UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



x		Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

		For the Quarterly Period Ended: ~~September~~June 30, ~~2017~~2018

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 ~~October 31, 2017,~~June 30, 2018, there were ~~316,641,799~~303,429,305 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS

Index

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A — Risk Factors Related to NRG Energy, Inc., in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017, and the following:

NRG's ability to achieve the expected benefits of its Transformation Plan;

NRG's ability to engage in successful sales and divestitures as well as mergers and acquisitions activity;

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;

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

General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;

Volatile power supply costs and demand for power;

Changes in law, including judicial decisions;

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 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 Energy, Inc. 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~~2017 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, ~~2016~~2017
2023 Term Loan Facility		The Company's $1.9 billion term loan facility due 2023, a component of the Senior Credit Facility
Adjusted EBITDA		Adjusted earnings before interest, taxes, depreciation and amortization
ARO		Asset Retirement Obligation
ASC		The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASU		Accounting Standards Updates ~~which reflect~~- updates to the ASC
Average realized prices		Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
BACT		Best Available Control Technology
Bankruptcy Code		Chapter 11 of Title 11 of the U.S. Bankruptcy Code
Bankruptcy Court		United States Bankruptcy Court for the Southern District of Texas, Houston Division
BETM		Boston Energy Trading and Marketing LLC
BTU		British Thermal Unit
Business Solutions		NRG's business solutions group, which includes demand response, commodity sales, energy efficiency and energy management services
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAISO		California Independent System Operator
CASPR		Competitive Auctions with Sponsored Resources
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~~Houston Electric, LLC
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
C&I		Commercial industrial and governmental/institutional
Cleco		Cleco Energy LLC
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
CWA		Clean Water Act
D.C. Circuit		U.S. Court of Appeals for the District of Columbia Circuit
DGPV Holdco 1		NRG DGPV Holdco 1 LLC
DGPV Holdco 2		NRG DGPV Holdco 2 LLC
DGPV Holdco 3		NRG DGPV Holdco 3 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



DNREC		Delaware Department of Natural Resources and Environmental Control
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
EPSA		The Electric Power Supply Association
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
~~ESCO~~		~~Energy Service Company~~
ESP		Electrostatic Precipitator
ESPP		NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
ESPS		Existing Source Performance Standards
Exchange Act		The Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGD		Flue gas desulfurization
Fresh Start		Reporting requirements as defined by ASC-852, Reorganizations
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~~$395 million outstanding unsecured senior notes consisting of ~~$366~~$208 million of 8.5% senior notes due 2021 and ~~$329~~$187 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 Mid-Atlantic		GenOn Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries, which include the coal generation units at two generating facilities under operating leases
GenOn Senior Notes		GenOn's $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $649 million of 9.5% senior notes due 2018, and $489 million of 9.875% senior notes due 2020
GenOn Settlement		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
GHG		Greenhouse Gas
GIP		Global Infrastructure Partners
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~~International Accounting Standards Board
IFRS		International Financial Reporting Standards
~~ILU~~IPA		Illinois ~~Union Insurance Company~~Power Agency
IPPNY		Independent Power Producers of New York
ISO		Independent System Operator, also referred to as RTOs
ISO-NE		ISO New England Inc.
ITC		Investment Tax Credit
kWh		Kilowatt-hour
LaGen		Louisiana Generating, ~~L.L.C.~~LLC
LIBOR		London Inter-Bank Offered Rate
LTIPs		Collectively, the NRG ~~Long-Term Incentive Plan, as amended,~~LTIP and the NRG GenOn ~~Long-Term Incentive Plan~~LTIP
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
MOPR		Minimum Offer Price Rule
MW		Megawatts
MWh		Saleable megawatt hour net of internal/parasitic load megawatt-hour
MWt		Megawatts Thermal Equivalent
NAAQS		National Ambient Air Quality Standards
NEPGA		New England Power Generators Association
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
NOV		Notice of Violation
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 ~~53.7%~~54.8% 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
NYMEX		New York Mercantile Exchange



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~~Pipeline		~~Pacific Gas~~Projects that range from identified lead to shortlisted with an offtake, and ~~Electric Company~~represents a lower level of execution certainty.
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~~PUHCA		~~Resource Adequacy Purchase Agreement~~Public Utility Holding Company Act of 2005
RCRA		Resource Conservation and Recovery Act of 1976
REMA		NRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interests in the Keystone and Conemaugh generating facilities, respectively
~~Repowering~~		Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility to achieve a substantial emissions reduction, increase facility capacity and improve system efficiency
Restructuring Support Agreement		Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017 and as amended on October 2, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC, ~~the~~and 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
RFO		Request for Offer
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability Must-Run
ROFO		Right of First Offer
ROFO Agreement		Second Amended and Restated Right of First Offer Agreement by and between ~~the Company~~NRG Energy, Inc. and NRG Yield, Inc.
RPM		Reliability Pricing Model
RPV Holdco		NRG RPV Holdco 1 LLC
RTO		Regional Transmission Organization
RTR		Renewable Technology Resource
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~~comprised 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 ~~September 30,~~December 31, 2017, ~~the Company’s $5.4~~NRG’s $4.8 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, and $870 million of 5.75% senior notes due 2028.
Services Agreement		NRG ~~provides~~provided GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn
~~Settlement Agreement~~SIFMA		~~A settlement agreement~~Securities Industry 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~~Financial Markets Association
SO₂		Sulfur Dioxide

~~SPP~~

South Central		~~Solar Power Partners~~
~~STP~~		NRG's South ~~Texas Project — nuclear generating facility located near Bay City, Texas in~~Central business, which ~~NRG~~ owns and operates a ~~44% interest~~3,555-MW portfolio of generation assets consisting of 225-MW Bayou Cove, 430-MW Big Cajun-I, 1,461-MW Big Cajun-II, 1,263-MW Cottonwood and 176-MW Sterlington, and serves a customer base of cooperatives, municipalities and regional utilities under load contracts.
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
VCP		Voluntary Clean-Up Program
VIE		Variable Interest Entity



~~Walnut Creek~~WECC		~~NRG Walnut Creek, LLC, the operating subsidiary of WCEP Holdings, LLC, which owns the Walnut Creek project~~Western Electricity Coordinating Council
WST		Washington-St. Tammany Electric Cooperative, Inc.
Yield Operating		NRG Yield Operating LLC

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
(In millions, except for per share amounts)	2017			2016			2017			2016			2018			2017			2018			2017
Operating Revenues
Total operating revenues	$	3,049		$	3,421		$	8,132		$	8,328		$	2,922		$	2,701		$	5,343		$	5,083
Operating Costs and Expenses
Cost of operations	2,156			2,440			5,852			5,711			2,051			1,841			3,609			3,704
Depreciation and amortization	272			298			789			826			227			260			462			517
Impairment losses	14			9			77			65			74			63			74			63
Selling, general and administrative	213			277			697			801			211			221			402			481
Reorganization	18			—			18			—
Development activity expenses	14			21			49			65
Reorganization costs													23			—			43			—
Development costs													16			18			29			35
Total operating costs and expenses	2,687			3,045			7,482			7,468			2,602			2,403			4,619			4,800
Other income - affiliate	14			48			104			144			—			39			—			87
Gain/(loss) on sale of assets	—			4			4			(79		)
Gain on sale of assets													14			2			16			4
Operating Income	376			428			758			925			334			339			740			374
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	27			16			29			13
Impairment loss on investment	—			(8		)	—			(147		)
Other income, net	15			7			33			29
Equity in earnings/(losses) of unconsolidated affiliates													18			(3		)	16			2
Other income/(expense), net													(20		)	14			(23		)	26
Loss on debt extinguishment, net	(1		)	(50		)	(3		)	(119		)	(1		)	—			(3		)	(2		)
Interest expense	(221		)	(237		)	(692		)	(718		)	(202		)	(247		)	(369		)	(471		)
Total other expense	(180		)	(272		)	(633		)	(942		)	(205		)	(236		)	(379		)	(445		)
Income/(Loss) from Continuing Operations Before Income Taxes	196			156			125			(17		)	129			103			361			(71		)
Income tax expense	6			28			5			75
Income tax expense/(benefit)													8			4			7			(1		)
Income/(Loss) from Continuing Operations	190			128			120			(92		)	121			99			354			(70		)
(Loss)/Income from discontinued operations, net of income tax	(27		)	265			(802		)	256
Loss from discontinued operations, net of income tax													(25		)	(741		)	(25		)	(775		)
Net Income/(Loss)	163			393			(682		)	164			96			(642		)	329			(845		)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests	(8		)	(9		)	(63		)	(49		)
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interests													24			(16		)	(22		)	(55		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	171			402			(619		)	213			$	72		$	(626	)	$	351		$	(790	)
Dividends for preferred shares	—			—			—			5
Gain on redemption of preferred shares	—			—			—			(78		)
Net Income/(Loss) Available for Common Stockholders	$	171		$	402		$	(619	)	$	286
Income/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders
Earnings/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	317			316			317			315			310			316			314			316
Income from continuing operations per weighted average common share — basic	$	0.63		$	0.43		$	0.58		$	0.10
(Loss)/Income from discontinued operations per weighted average common share — basic	$	(0.09	)	$	0.84		$	(2.53	)	$	0.81
Income/(Loss) per Weighted Average Common Share — Basic	$	0.54		$	1.27		$	(1.95	)	$	0.91
Income/(loss) from continuing operations per weighted average common share — basic													$	0.31		$	0.36		$	1.20		$	(0.05	)
Income/(loss) from discontinued operations per weighted average common share — basic													$	(0.08	)	$	(2.34	)	$	(0.08	)	$	(2.45	)
Earnings/(Loss) per Weighted Average Common Share — Basic													$	0.23		$	(1.98	)	$	1.12		$	(2.50	)
Weighted average number of common shares outstanding — diluted	322			317			317			316			314			316			318			316
Income from continuing operations per weighted average common share — diluted	$	0.61		$	0.43		$	0.58		$	0.10
(Loss)/Income from discontinued operations per weighted average common share — diluted	$	(0.08	)	$	0.84		$	(2.53	)	$	0.81
Income/(Loss) per Weighted Average Common Share — Diluted	$	0.53		$	1.27		$	(1.95	)	$	0.91
Income/(loss) from continuing operations per weighted average common share — diluted													$	0.31		$	0.36		$	1.18		$	(0.05	)
Income/(loss) from discontinued operations per weighted average common share — diluted													$	(0.08	)	$	(2.34	)	$	(0.08	)	$	(2.45	)
Earnings/(Loss) per Weighted Average Common Share — Diluted													$	0.23		$	(1.98	)	$	1.10		$	(2.50	)
Dividends Per Common Share	$	0.03		$	0.03		$	0.09		$	0.21		$	0.03		$	0.03		$	0.06		$	0.06

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
	(In millions)												(In millions)
Net income/(loss)	$	163		$	393		$	(682	)	$	164		$	96		$	(642	)	$	329		$	(845	)
Other comprehensive income/(loss), net of tax
Unrealized gain/(loss) on derivatives, net of income tax (benefit)/expense of $0, $(1), $1, and $1	7			27			6			(8		)
Unrealized gain/(loss) on derivatives, net of income tax expense of $0, $0, $0, and $1													5			(5		)	19			(1		)
Foreign currency translation adjustments, net of income tax expense of $0, $0, $0, and $0	2			3			10			6			(4		)	1			(6		)	8
Available-for-sale securities, net of income tax expense of $0, $0, $0, and $0	1			—			2			1			1			1			1			1
Defined benefit plans, net of income tax expense of $0, $0, $0, and $0	(1		)	31			26			32			(1		)	27			(2		)	27
Other comprehensive income	9			61			44			31			1			24			12			35
Comprehensive income/(loss)	172			454			(638		)	195			97			(618		)	341			(810		)
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interests	(5		)	(2		)	(61		)	(70		)
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest													26			(17		)	(12		)	(56		)
Comprehensive income/(loss) attributable to NRG Energy, Inc.	177			456			(577		)	265			71			(601		)	353			(754		)
Dividends for preferred shares	—			—			—			5
Gain on redemption of preferred shares	—			—			—			(78		)
Comprehensive income/(loss) available for common stockholders	$	177		$	456		$	(577	)	$	338		$	71		$	(601	)	$	353		$	(754	)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

~~(Unaudited)~~


	September 30, 2017			December 31, 2016			June 30, 2018			December 31, 2017
(In millions, except shares)							(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,223		$	938		$	980		$	991
Funds deposited by counterparties	31			2			71			37
Restricted cash	537			446			286			508
Accounts receivable, net	1,274			1,058			1,371			1,079
Inventory	630			721			485			532
Derivative instruments	475			1,067			851			626
Cash collateral posted in support of energy risk management activities	203			150
Cash collateral paid in support of energy risk management activities							224			171
Accounts receivable - affiliate							57			95
Current assets - held for sale	33			9			100			115
Prepayments and other current assets	354			404			328			261
Current assets - discontinued operations	—			1,919
Total current assets	4,760			6,714			4,753			4,415
Property, plant and equipment, net	15,332			15,369			12,774			13,908
Other Assets
Equity investments in affiliates	1,138			1,120			1,055			1,038
Notes receivable, less current portion	5			16			15			2
Goodwill	662			662			539			539
Intangible assets, net	1,838			1,973			1,860			1,746
Nuclear decommissioning trust fund	670			610			694			692
Derivative instruments	206			181			426			172
Deferred income taxes	205			225			126			134
Non-current assets held-for-sale	10			10			50			43
Other non-current assets	644			841			655			629
Non-current assets - discontinued operations	—			2,961
Total other assets	5,378			8,599			5,420			4,995
Total Assets	$	25,470		$	30,682		$	22,947		$	23,318
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1,247		$	516		$	952		$	688
Accounts payable	911			813			975			881
Accounts payable - affiliate							29			33
Derivative instruments	522			1,092			709			555
Cash collateral received in support of energy risk management activities	31			81			72			37
Current liabilities held-for-sale							74			72
Accrued expenses and other current liabilities	830			990			719			890
Accrued expenses and other current liabilities - affiliate	164			—			133			161
Current liabilities - discontinued operations	—			1,210
Total current liabilities	3,705			4,702			3,663			3,317
Other Liabilities
Long-term debt and capital leases	15,658			15,957			14,821			15,716
Nuclear decommissioning reserve	265			287			274			269
Nuclear decommissioning trust liability	397			339			410			415
Deferred income taxes	21			20			17			21
Derivative instruments	307			284			285			197
Out-of-market contracts, net	213			230			195			207
Non-current liabilities held-for-sale	13			11			12			8
Other non-current liabilities	1,116			1,176			1,130			1,122
Non-current liabilities - discontinued operations	—			3,184
Total non-current liabilities	17,990			21,488			17,144			17,955
Total Liabilities	21,695			26,190			20,807			21,272
Redeemable noncontrolling interest in subsidiaries	85			46			69			78
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4			4			4
Additional paid-in capital	8,369			8,358			8,481			8,376
Retained deficit	(4,713		)	(3,787		)
Less treasury stock, at cost — 101,580,045 and 102,140,814 shares, respectively	(2,386		)	(2,399		)
Accumulated deficit							(5,920		)	(6,268		)
Less treasury stock, at cost — 116,267,484 and 101,580,045 shares, at June 30, 2018 and December 31, 2017, respectively							(2,871		)	(2,386		)
Accumulated other comprehensive loss	(91		)	(135		)	(60		)	(72		)
Noncontrolling interest	2,507			2,405			2,437			2,314
Total Stockholders’ Equity	3,690			4,446			2,071			1,968
Total Liabilities and Stockholders’ Equity	$	25,470		$	30,682		$	22,947		$	23,318

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine months ended September 30,						Six months ended June 30,
(In millions)	2017			2016			2018			2017
Cash Flows from Operating Activities
Net (loss)/income	$	(682	)	$	164
(Loss)/Income from discontinued operations, net of income tax	(802		)	256
Net income/(loss)							$	329		$	(845	)
Loss from discontinued operations, net of income tax							(25		)	(775		)
Income/(loss) from continuing operations	120			(92		)	354			(70		)
Adjustments to reconcile net (loss)/income to net cash provided by operating activities:
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	24			44			27			26
Depreciation and amortization	789			826
Depreciation, amortization and accretion							485			517
Provision for bad debts	57			36			31			18
Amortization of nuclear fuel	37			39			24			24
Amortization of financing costs and debt discount/premiums	44			42			27			29
Adjustment for debt extinguishment	3			119			3			—
Amortization of intangibles and out-of-market contracts	79			131			48			51
Amortization of unearned equity compensation	27			23			26			16
Impairment losses	77			211			89			63
Changes in deferred income taxes and liability for uncertain tax benefits	26			29			4			8
Changes in nuclear decommissioning trust liability	20			24			41			2
Changes in derivative instruments	25			30			(211		)	7
Changes in collateral posted in support of risk management activities	(103		)	261
Proceeds from sale of emission allowances	21			11
(Gain)/loss on sale of assets	(22		)	70
Changes in collateral deposits in support of energy risk management activities							(18		)	(189		)
Gain on sale of emission allowances							(11		)	11
Gain on sale of assets							(16		)	(22		)
Loss on deconsolidation of business							22			—
Changes in other working capital	(380		)	(130		)	(401		)	(379		)
Cash provided by continuing operations	844			1,674			524			112
Cash (used)/provided by discontinued operations	(38		)	67
Cash used by discontinued operations							—			(38		)
Net Cash Provided by Operating Activities	806			1,741			524			74
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(36		)	(18		)	(284		)	(16		)
Capital expenditures	(760		)	(659		)	(691		)	(542		)
Decrease in notes receivable	11			2			4			8
Purchases of emission allowances	(47		)	(32		)	(22		)	(30		)
Proceeds from sale of emission allowances	105			47			34			59
Investments in nuclear decommissioning trust fund securities	(402		)	(378		)	(346		)	(279		)
Proceeds from the sale of nuclear decommissioning trust fund securities	382			354			303			277
Proceeds from renewable energy grants and state rebates	8			11			—			8
Proceeds from sale of assets, net of cash disposed of	36			84			18			35
Investments in unconsolidated affiliates	(31		)	(23		)
Deconsolidation of business							(160		)	—
Changes in investments in unconsolidated affiliates							(2		)	(30		)
Other	22			31			—			18
Cash used by continuing operations	(712		)	(581		)	(1,146		)	(492		)
Cash (used)/provided by discontinued operations	(53		)	326
Cash used by discontinued operations							—			(53		)
Net Cash Used by Investing Activities	(765		)	(255		)	(1,146		)	(545		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(28		)	(66		)	(19		)	(19		)
Payment for preferred shares	—			(226		)
Payment for treasury stock							(500		)	—
Net receipts from settlement of acquired derivatives that include financing elements	2			6			—			2
Proceeds from issuance of long-term debt	1,134			5,237			1,605			946
Payments for short and long-term debt	(712		)	(5,353		)	(848		)	(530		)
Receivable from affiliate	(125		)	—
Payments for debt extinguishment costs	—			(98		)
Contributions from, net of distributions to, noncontrolling interest in subsidiaries	65			(127		)
Proceeds from issuance of stock	—			1
Increase in notes receivable from affiliate							—			(125		)
Net contributions from noncontrolling interests in subsidiaries							222			14
Payment of debt issuance costs	(43		)	(70		)	(37		)	(36		)
Other - contingent consideration	(10		)	(10		)	—			(10		)
Cash provided/(used) by continuing operations	283			(706		)
Cash (used)/provided by discontinued operations	(224		)	119
Net Cash provided/(used) by Financing Activities	59			(587		)
Cash provided by continuing operations							423			242
Cash used by discontinued operations							—			(224		)
Net Cash Provided by Financing Activities							423			18
Effect of exchange rate changes on cash and cash equivalents	(10		)	(6		)	—			(8		)
Change in Cash from discontinued operations	(315		)	512			—			(315		)
Net Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	405			381
Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash							(199		)	(146		)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	1,386			1,322			1,536			1,386
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	1,791		$	1,703		$	1,337		$	1,240

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

General

NRG Energy, Inc., or NRG or the Company, is a ~~leading~~customer-driven integrated power company built on ~~the strength~~a portfolio of ~~a diverse competitive electric generation portfolio and~~ leading retail electricity ~~platform.~~brands and diverse generation assets. 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 30,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and Company:

directly sells energy ~~services,~~ and innovative, sustainable products and services to retail customers under the names “NRG”, ~~"Reliant"~~“Reliant” and other retail brand names owned by ~~NRG.~~NRG;

owns and operates approximately 30,000 MW of generation;

engages in the trading of wholesale energy, capacity and related products; and

transacts in and trades fuel and transportation services.

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~~2017 Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of ~~September~~June 30, ~~2017,~~2018, and the results of operations, comprehensive income/(loss) and cash flows for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016.~~2017.

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~~ determined that this disposal of GenOn and its subsidiaries is a discontinued ~~operation;~~operation and, accordingly, the financial information for all historical periods ~~have~~has been recast to reflect GenOn as a discontinued operation. ~~In connection with the disposal, NRG recorded a loss on deconsolidation of $208 million during the quarter ended June 30, 2017. See Note 3,~~ ~~Discontinued Operations, Dispositions and Acquisitions, for more information.~~

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

As announced on October 31, 2017, NRG and GenOn engaged in arms-length discussions to settle certain items related to the pre-petition Restructuring Support Agreement, including key topics such as: (i) timeline and transition; (ii) cooperation and co-development matters; (iii) post-employment and retiree health and welfare benefits and pension benefits; (iv) tax matters; and (v) intercompany balances. The agreements reached on these topics are expected to be incorporated into definitive documents for GenOn’s emergence from Chapter 11.

Forms of definitive documents were filed with the Bankruptcy Court by the GenOn Entities; however, such definitive documents are subject to ongoing review, revision, and further negotiation by the parties to the Restructuring Support Agreement, including NRG, who have various consent rights over the final form of the plan supplement documents, and may be amended, modified, supplemented, and revised in accordance with those ongoing negotiations.

~~Transformation Plan~~

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

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

~~Portfolio optimization~~ — Targeting up to $4.0 billion of asset sale net cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its 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:


	September 30, 2017		December 31, 2016		June 30, 2018		December 31, 2017
	(In millions)				(In millions)
Accounts receivable allowance for doubtful accounts	$	61	$	29	$	28	$	28
Property, plant and equipment accumulated depreciation	6,437		5,711		4,534		4,465
Intangible assets accumulated amortization	1,750		1,687		1,443		1,818
Out-of-market contracts accumulated amortization	352		457		370		358

Restricted Cash

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


	September 30, 2017		December 31, 2016		September 30, 2016		December 31, 2015		June 30, 2018		December 31, 2017		June 30, 2017		December 31, 2016
	(In millions)								(In millions)
Cash and cash equivalents	$	1,223	$	938	$	1,217	$	853	$	980	$	991	$	752	$	938
Funds deposited by counterparties	31		2		6		55		71		37		19		2
Restricted cash	537		446		480		414		286		508		469		446
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,791	$	1,386	$	1,703	$	1,322	$	1,337	$	1,536	$	1,240	$	1,386

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

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

Noncontrolling Interest

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


	(In millions)			(In millions)
Balance as of December 31, 2016	$	2,405
Contributions from noncontrolling interest	116
Non-cash adjustments to noncontrolling interest	98
Sale of assets to NRG Yield, Inc.	24
Comprehensive loss attributable to noncontrolling interest	(8		)
Balance as of December 31, 2017				$	2,314
Dividends paid to NRG Yield, Inc. public shareholders	(80		)	(61		)
Distributions to noncontrolling interest	(48		)	(34		)
Balance as of September 30, 2017	$	2,507
Comprehensive income attributable to noncontrolling interest				12
Non-cash adjustments to noncontrolling interest				8
Contributions from noncontrolling interest				295
Sale of assets to NRG Yield, Inc.				(8		)
Deconsolidation of Ivanpah^(a)				(89		)
Balance as of June 30, 2018				$	2,437

(a) See Note 9, Variable Interest Entities, or VIEs for further information regarding the deconsolidation of Ivanpah effective April 2018.

Redeemable Noncontrolling Interest

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


	(In millions)			(In millions)
Balance as of December 31, 2016	$	46
Balance as of December 31, 2017				$	78
Distributions to redeemable noncontrolling interest				(2		)
Contributions from redeemable noncontrolling interest	73			26
Non-cash adjustments to noncontrolling interest	21
Non-cash adjustments to redeemable noncontrolling interest				(9		)
Comprehensive loss attributable to redeemable noncontrolling interest	(53		)	(24		)
Distributions to redeemable noncontrolling interest	(2		)
Balance as of September 30, 2017	$	85
Balance as of June 30, 2018				$	69

Revenue Recognition

Revenue from Contracts with Customers

On January 1, 2018, the Company adopted the guidance in ASC 606 using the modified retrospective method applied to contracts which were not completed as of the adoption date. The Company recognized the cumulative effect of initially applying the new standard as a credit to the opening balance of accumulated deficit, resulting in a decrease of approximately $16 million. The adjustment primarily related to costs incurred to obtain a contract with customers and customer incentives. Following the adoption of the new standard, the Company’s revenue recognition of its contracts with customers remains materially consistent with its historical practice. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The Company's policies with respect to its various revenue streams are detailed below. In general, the Company applies the invoicing practical expedient to recognize revenue for the revenue streams detailed below, except in circumstances where the invoiced amount does not represent the value transferred to the customer.

Retail Revenues

Gross revenues for energy sales and services to retail customers are recognized as the Company transfers the promised goods and services to the customer. For the majority of its electricity contracts, the Company’s performance obligation with the customer is satisfied over time and performance obligations for its electricity products are recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct performance obligation in a contract for which the timing of the revenue recognized is different. Additionally, customer discounts and incentives reduce the contract consideration and are recognized over the term of the contract.

Energy sales and services that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.

As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable, and that vary based on the contract duration, customer type, inception date and other contract-specific factors. For the fixed price contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors such as weather and customer activity and therefore it is not practicable to estimate such amounts.

Energy Revenue

Both physical and financial transactions are entered into to optimize the financial performance of the Company's generating facilities. Electric energy revenue is recognized upon transmission to the customer over time, using the output method for measuring progress of satisfaction of performance obligations. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. The Company applies the invoicing practical expedient, where applicable, in recognizing energy revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815.

Capacity Revenue

Capacity revenues consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements. Capacity revenues are recognized over time, using the output method for measuring progress of satisfaction of performance obligations. The Company applies the invoicing practical expedient, where applicable, in recognizing capacity revenue. Under the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date.

Capacity revenue contracts mainly consist of:

Capacity auctions — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO. Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time performance, where NRG's actual revenues will be the combination of revenues based on the cleared auction MWs plus the net of any over- and under-performance of NRG's fleet. In addition, MISO has an annual auction, known as the Planning Resource Auction, or PRA. The Gulf Coast assets situated in the MISO market may participate in this auction. Estimated revenues for cleared auction MWs in the various capacity auctions are $578 million, $519 million, $410 million, $388 million and $168 million for fiscal years 2018, 2019, 2020, 2021 and 2022, respectively.

Resource adequacy and bilateral contracts — In California, there is a resource adequacy requirement that is primarily satisfied through bilateral contracts. Such bilateral contracts are typically short-term resource adequacy contracts. When bilateral contracting does not satisfy the resource adequacy need, such shortfalls can be addressed through procurement tools administered by the CAISO, including the capacity procurement mechanism or reliability must-run contracts. Demand payments from the current long-term contracts are tied to summer peak demand and provide a mechanism for recovering a portion of the costs associated with new or changed environmental laws or regulations. In Texas, capacity and contracted revenues are through bilateral contracts with load serving entities.

Long-term PPAs — Energy, capacity and where applicable, renewable attributes, from the majority of renewable energy assets and certain conventional energy plants is sold through long-term PPAs and tolling agreements to a single counterparty, which is often a utility or commercial customer. Many of these PPAs are accounted for as leases.

Renewable Energy Credits

As stated above, renewable energy credits are usually sold through long-term PPAs. Revenue from the sale of self-generated RECs is recognized when related energy is generated and simultaneously delivered even in cases where there is a certification lag as it has been deemed to be perfunctory.

In a bundled contract to sell energy, capacity and/or self-generated RECs, all performance obligations are deemed to be delivered at the same time and hence, timing of recognition of revenue for all performance obligations is the same and occurs over time. In such cases, it is often unnecessary to allocate transaction price to multiple performance obligations.

Sale of Emission Allowances

The Company records its inventory of emission allowances as part of intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. The Company records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations.

Disaggregated Revenues

The following table represents the Company’s disaggregation of revenue from contracts with customers for the three and six months ended June 30, 2018, along with the reportable segment for each category:



	Three months ended June 30, 2018
			Generation
(In millions)	Retail		Gulf Coast			East/West			Subtotal		Renewables		NRG Yield			Eliminations			Total
Energy revenue^(a)(b)	$	—	$	508		$	144		$	652	$	79	$	192		$	(250	)	$	673
Capacity revenue^(a)(b)	—		68			160			228		—		87			(2		)	313
Retail revenue
Mass customers	1,380		—			—			—		—		—			(1		)	1,379
Business solutions customers	437		—			—			—		—		—			—			437
Total retail revenue	1,817		—			—			—		—		—			(1		)	1,816
Mark-to-market for economic hedging activities^(c)	—		289			(15		)	274		5		—			(264		)	15
Contract amortization	—		4			—			4		—		(18		)	—			(14		)
Other revenue^(a)(b)	—		42			18			60		29		46			(16		)	119
Total operating revenue	1,817		911			307			1,218		113		307			(533		)	2,922
Less: Lease revenue	6		—			1			1		96		267			—			370
Less: Derivative revenue	—		898			(1		)	897		5		—			(264		)	638
Less: Contract amortization	—		4			—			4		—		(18		)	—			(14		)
Total revenue from contracts with customers	$	1,811	$	9		$	307		$	316	$	12	$	58		$	(269	)	$	1,928
(a) The following amounts of energy and capacity revenue relate to leases and are accounted for under ASC 840:
	Retail		Gulf Coast			East/West			Subtotal		Renewables		NRG Yield			Eliminations			Total
Energy revenue	$	—	$	—		$	—		$	—	$	90	$	182		$	—		$	272
Capacity revenue	—		—			—			—		—		85			—			85
Other revenue	6		—			1			1		6		—			—			13
(b) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.
	Retail		Gulf Coast			East/West			Subtotal		Renewables		NRG Yield			Eliminations			Total
Energy revenue	$	—	$	610		$	(30	)	$	580	$	—	$	—		$	—		$	580
Capacity revenue	—		—			39			39		—		—			—			39
Other revenue	—		(1		)	5			4		—		—			—			4
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.



	Six months ended June 30, 2018
				Generation
(In millions)	Retail			Gulf Coast			East/West			Subtotal			Renewables			NRG Yield			Eliminations			Total
Energy revenue^(a)(b)	$	—		$	879		$	362		$	1,241		$	156		$	306		$	(411	)	$	1,292
Capacity revenue^(a)(b)	—			135			300			435			—			169			(3		)	601
Retail revenue
Mass customers	2,551			—			—			—			—			—			(2		)	2,549
Business solutions customers	753			—			—			—			—			—			—			753
Total retail revenue	3,304			—			—			—			—			—			(2		)	3,302
Mark-to-market for economic hedging activities^(c)	(6		)	(275		)	(25		)	(300		)	(5		)	—			220			(91		)
Contract amortization	—			7			—			7			—			(35		)	—			(28		)
Other revenue^(a)(b)	—			128			34			162			48			92			(35		)	267
Total operating revenue	3,298			874			671			1,545			199			532			(231		)	5,343
Less: Lease revenue	12			—			2			2			160			448			—			622
Less: Derivative revenue	(6		)	710			79			789			(5		)	—			220			998
Less: Contract amortization	—			7			—			7			—			(35		)	—			(28		)
Total revenue from contracts with customers	$	3,292		$	157		$	590		$	747		$	44		$	119		$	(451	)	$	3,751
(a) The following amounts of energy and capacity revenue relate to leases and are accounted for under ASC 840:
	Retail			Gulf Coast			East/West			Subtotal			Renewables			NRG Yield			Eliminations			Total
Energy revenue	$	—		$	—		$	—		$	—		$	151		$	284		$	—		$	435
Capacity revenue	—			—			—			—			—			164			—			164
Other revenue	12			—			2			2			9			—			—			23
(b) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.
	Retail			Gulf Coast			East/West			Subtotal			Renewables			NRG Yield			Eliminations			Total
Energy revenue	$	—		$	981		$	31		$	1,012		$	—		$	—		$	—		$	1,012
Capacity revenue	—			—			65			65			—			—			—			65
Other revenue	—			4			8			12			—			—			—			12
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.

Contract Amortization

Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation and/or contracted volumes.

Lease Revenue

Certain of the Company’s revenues are obtained through PPAs or other contractual agreements. Many of these agreements are accounted for as operating leases under ASC 840 Leases. Certain of these leases have no minimum lease payments and all of the rent is recorded as contingent rent on an actual basis when the electricity is delivered. Judgment is required by management in determining the economic life of each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in determining whether a contract contains a lease and whether the lease is an operating lease or capital lease.

Contract Balances

The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of June 30, 2018:




(In millions)	June 30, 2018
Deferred customer acquisition costs	$	102
Accounts receivable, net - Contracts with customers	1,187
Accounts receivable, net - Leases	152
Accounts receivable, net - Derivative instruments	32
Total accounts receivable, net	$	1,371
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	445
Deferred revenues	73

The Company’s customer acquisition costs consist of broker fees, commission payments and other costs that represent incremental costs of obtaining the contract with customers for which the Company expects to recover. The Company amortizes these amounts over the estimated life of the customer contract. As a practical expedient, the Company expenses the incremental costs of obtaining a contract if the amortization period of the asset would have been one year or less.

When the Company receives consideration from the customer that is in excess of the amount due, such consideration is reclassified to deferred revenue, which represents a contract liability. Generally, the Company will recognize revenue from contract liabilities in the next period as the Company satisfies its performance obligations.

Recent Accounting Developments - Guidance Adopted in ~~2017~~

~~ASU 2016-18~~ ~~— In November 2016, the FASB issued ASU No. 2016-18,~~ ~~Statement of Cash Flows (Topic 230)~~, Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require an entity to include amounts generally described as restricted cash and restricted cash equivalents, including funds deposited by counterparties with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. The amendments of ASU No. 2016-18 are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted and the adoption of ASU No. 2016-18 will be applied retrospectively. The Company adopted the guidance in ASU No. 2016-18 during the second quarter of 2017. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in a decrease in cash flows from operations of $49 million and an increase in cash flows from investing of $66 million on the statement of cash flows for the nine months ended September 30, 2016.

~~ASU 2016-16~~ ~~— In October 2016, the FASB issued ASU No. 2016-16,~~ ~~Income Taxes (Topic 740)~~, Intra-Entity Transfers of Assets Other Than Inventory, or ASU No. 2016-16. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice and increased complexity within financial reporting. The amendments of ASU No. 2016-16 would require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company adopted the guidance in ASU No. 2016-16 effective January 1, 2017. In connection with the adoption of the standard, the Company recorded a reduction to non-current assets of $267 million with a corresponding reduction to cumulative retained deficit.

~~ASU 2016-15~~ ~~— In August 2016, the FASB issued ASU No. 2016-15,~~ ~~Statement of Cash Flows (Topic 230)~~, Classification of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The Company adopted the guidance in ASU No. 2016-15 effective January 1, 2017. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in an increase in cash flows from operations of $98 million and a decrease in cash flows from financing of $98 million on the statement of cash flows for the nine months ended September 30, 2016.

~~ASU 2016-09~~ ~~— In March 2016, the FASB issued ASU No. 2016-09,~~ ~~Compensation - Stock Compensation~~ (Topic 718), or ASU No. 2016-09. The amendments focused on simplification specifically with regard to share-based payment transactions, including income tax consequences, classification of awards as equity or liabilities and classification on the statement of cash flows. The Company adopted the guidance in ASU No. 2016-09 effective January 1, 2017 with no material adjustments recorded to the consolidated balance sheet.

~~Recent Accounting Developments - Guidance Not Yet Adopted~~

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

ASU 2017-07 — In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU No. 2017-07. Current GAAP does not indicate where the amount of net benefit cost should be presented in an entity’s income statement and does not require entities to disclose the amount of net benefit cost that is included in the income statement. The amendments of ASU No. 2017-07 require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and outside the subtotal of income from operations. Further, ASU No. 2017-07 prescribes that only the service cost component of net benefit costs is eligible for capitalization. The Company adopted the amendments of ASU No. 2017-07 ~~are~~ effective January 1, 2018. In connection with the adoption of the standard, the Company has applied the guidance retrospectively which resulted in an increase in cost of operations of $4 million and $8 million with a corresponding increase in other income, net on the statement of operations for the three and six months ended June 30, 2017, respectively.

ASU 2016-01 - In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) be generally measured at fair value with changes in fair value recognized in net income. Further, the amendments require that financial assets and financial liabilities be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset. The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, ~~including~~and interim periods ~~therein. Early adoption is permitted and must be applied on a retrospective basis, except for~~within those annual periods. The Company adopted the amendments ~~regarding the capitalization~~ of ~~the service cost component, which must be applied prospectively. The Company is currently assessing the impact that~~ASU No. 2016-01 effective January 1, 2018. In connection with the adoption of ~~ASU No. 2017-07 will have~~the standard, the Company has applied the guidance on ~~its~~a modified retrospective basis, which resulted in no material adjustments recorded to the consolidated results of operations, cash flows, and statement of financial position.

Recent Accounting Developments - Guidance Not Yet Adopted

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~~will adopt the standard effective January 1, 2019, ~~utilizing the required modified retrospective approach for the earliest period presented. The Company~~and 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~~ The Company is also monitoring recent changes to 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~~842 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 materialrelated impact on ~~its financial statements.~~the implementation process.

Note 3 — Acquisitions, Discontinued Operations ~~Dispositions~~ and ~~Acquisitions~~Dispositions

This footnote should be read in conjunction with the complete description under Note 3, Discontinued Operations, Acquisitions and Dispositions, to the Company's 2017 Form 10-K.

Acquisitions

XOOM Energy Acquisition — On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for approximately $219 million in cash, inclusive of approximately $54 million in payments for estimated working capital, which is subject to further adjustment. The acquisition increased NRG's retail portfolio by approximately 300,000 customers. The purchase price was provisionally allocated as follows: $2 million to cash, $8 million to restricted cash, $46 million to accounts receivable, $42 million to derivative assets, $169 million to customer relationships and contracts, $26 million to current and non-current assets, $25 million to accounts payable, $31 million to derivative liabilities, and $18 million to current and non-current liabilities.

Discontinued Operations

~~As described in Note 1,~~ ~~Basis of Presentation, on the Petition Date,~~On June 14, 2017, 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.~~operations.

Summarized results of discontinued operations were as follows:


	Three months ended September 30, 2017 ^(a)			Three months ended September 30, 2016				Nine months ended September 30, 2017 ^(a)			Nine months ended September 30, 2016			Three months ended June 30, 2018			Period from April 1, 2017 through June 14, 2017			Six months ended June 30, 2018			Period from January 1, 2017 through June 14, 2017
(In millions)
Operating revenues	$	—				$	532				$	646			$	1,509	$	—		$	265		$	—		$	646
Operating costs and expenses	—			(468		)		(700		)	(1,409		)	—			(327		)	—			(700		)
Gain on sale of assets	—			262				—			294
Other expenses	—			(43		)		(98		)	(127		)	—			(54		)	—			(98		)
(Loss)/Income from operations of discontinued components, before tax	—			283				(152		)	267
Loss from operations of discontinued components, before tax														—			(116		)	—			(152		)
Income tax expense	—			21				9			20			—			8			—			9
(Loss)/Incomes from operations of discontinued components	—			262				(161		)	247
Loss from operations of discontinued components														—			(124		)	—			(161		)
Interest income - affiliate	—			3				6			9			2			3			3			6
(Loss)/Income from operations of discontinued components, net of tax	—			265				(155		)	256
Loss from operations of discontinued components, net of tax														2			(121		)	3			(155		)
Pre-tax loss on deconsolidation	—			—				(208		)	—			—			(208		)	—			(208		)
Settlement consideration and services credit	—			—				(289		)	—			—			(289		)	—			(289		)
Pension and post-retirement liability assumption^(b)	(25		)	—				(144		)	—
Pension and post-retirement liability assumption														1			(119		)	1			(119		)
Advisory and consulting fees														(1		)	(4		)	(2		)	(4		)
Other	(2		)	—				(6		)	—			(27		)	—			(27		)	—
Loss on disposal of discontinued components, net of tax	(27		)	—				(647		)	—			(27		)	(620		)	(28		)	(620		)
(Loss)/Income from discontinued operations, net of tax	$	(27	)	$	265			$	(802	)	$	256
Loss from discontinued operations, net of tax														$	(25	)	$	(741	)	$	(25	)	$	(775	)

~~(a)~~GenOn Settlement

Effective July 16, 2018, NRG and GenOn consummated the GenOn Settlement which accelerated certain terms contemplated by the plan of reorganization, as further described below. As a result, the Company paid GenOn approximately $125 million, which included (i) the settlement consideration of $261 million, (ii) the transition services credit of $28 million and (iii) the return of $15 million of collateral posted to NRG; offset by the (i) $151 million in borrowings under the intercompany secured revolving credit facility, (ii) related accrued interest and fees of $12 million, (iii) remaining payments due under the transition services agreement of $10 million and (iv) certain other balances due to NRG totaling $6 million. As of June ~~14, 2017,~~30, 2018, the Company had reserved for all amounts deemed to be uncollectible.

In order to facilitate the consummation of the GenOn Settlement, among other items, NRG ~~no longer consolidates~~assigned to GenOn approximately $8 million of historical claims against REMA in exchange for ~~financial reporting purposes.~~

~~(b) See Note 1,~~ ~~Basis~~$4.2 million, which was credited as a reduction of ~~Presentation~~,the settlement payment. GenOn also indemnified NRG for ~~further discussion regarding the October 30, 2017 proposed changes~~any potential claims by REMA up to the ~~Restructuring Support Agreement. As part~~amount of ~~this,~~$10 million, and posted a letter of credit in that amount in favor of NRG ~~recorded~~as security for the ~~liability for GenOn’s post-employment~~indemnification. Other than those obligations which survive or are independent of the releases described herein, the GenOn Settlement provides NRG releases from GenOn and ~~retiree health~~each of its debtor and ~~welfare benefits, in an amount up to $25 million with a corresponding loss on discontinued operations during the third quarter of 2017.~~

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

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

Restructuring Support Agreement

~~As described in Note 1,~~ ~~Basis~~Prior to the filing of ~~Presentation~~,GenOn's bankruptcy case, NRG, GenOn and certain holders representing greater than 93% in aggregate principal amount of GenOn’s Senior Notes and certain holders representing greater than 93% in aggregate principal amount of GenOn Americas Generation’s Senior Notes entered into a Restructuring Support Agreement that ~~provides~~provided for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. ~~Completion~~In December 2017, the Bankruptcy Court approved the plan of reorganization, pursuant to an order of confirmation. Consummation of the ~~agreed upon terms is contingent upon~~plan of reorganization has not yet occurred and remains subject to the satisfaction or waiver of certain ~~milestones in the Restructuring Support Agreement.~~conditions precedent. Certain principal terms of the ~~Restructuring Support Agreement~~plan of reorganization are detailed below:


1)	~~Full~~The dismissal of certain prepetition litigation and full releases from GenOn and ~~GenOn Americas Generation~~each of its debtor and non-debtor subsidiaries 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.~~excluding REMA.

NRG ~~will provide~~provided settlement cash consideration to GenOn of $261.3 million, ~~which will be~~ paid in cash less ~~any~~ amounts owed to NRG under the intercompany secured revolving credit facility. As of ~~September~~June 30, ~~2017,~~2018, GenOn owed NRG approximately ~~$125~~$151 million under the intercompany secured revolving credit ~~facility.~~facility, plus interest and fees accrued thereon. See Note 14, Related Party Transactions, for further discussion of the intercompany secured revolving credit facility. The net liability for these amounts, along with the services credit described below, is recorded in accrued expenses and other current liabilities - affiliate as of June 30, 2018 and December 31, 2017.


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.~~

NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September 2017. GenOn’s pension liability as of ~~September~~June 30, ~~2017~~2018, was approximately ~~$106~~$90 million. NRG will also retain the liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million. These liabilities are recorded within other non-current liabilities as of June 30, 2018 and December 31, 2017.

5)4)

The shared services agreement between NRG and GenOn ~~will be amended such that (i)~~was terminated and replaced as of the plan confirmation date with a transition services agreement. Under the transition services agreement, NRG ~~will provide~~provided the shared services ~~to GenOn~~and other separation services 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~~subject to ~~GenOn at no charge for two months,~~certain credits 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.~~adjustments. See Note 14, Related Party Transactions, for further discussion of the ~~shared services agreement.~~Services Agreement.


6)5)	NRG ~~will provide~~provided a credit of $28 million to GenOn to apply against amounts owed under the ~~shared~~transition services ~~agreement upon emergence from bankruptcy. Any~~agreement. The unused ~~amount can be~~credit of approximately $18 million was paid in cash ~~at GenOn’s request.~~to GenOn. 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)6)

NRG and GenOn ~~have~~also agreed to cooperate in good faith to maximize the value of certain development projects. Pursuant to this, GenOn made a one-time payment in the amount of $15 million to NRG in December 2017 as compensation for a purchase option with respect to the Canal 3 project. During the second quarter of 2018, NRG sold Canal 3 to Stonepeak Kestrel Holdings II LLC, or Stonepeak Kestrel, in conjunction with GenOn's sale of Canal Units 1 and 2 to Stonepeak Kestrel Holdings LLC. NRG reimbursed GenOn for $13.5 million of the one-time payment upon the closing of the sale of Canal 3.

GenMA Settlement

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

~~Settlement Consideration~~

~~NRG has determined that the payment of~~reorganization also approved 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 expectsterms agreed to ~~pay this amount net of amounts due from GenOn under the intercompany secured revolving credit facility, which is further described in Note 14, Related Party Transactions~~.

~~Pension Liability~~

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

~~Services Agreement~~

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

~~Commercial Operations~~

~~For pre-disposal periods, NRG provided GenOn with services as described in Note 14,~~ ~~Related Party Transactions.~~ ~~Under intercompany agreements, NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn~~Mid-Atlantic, and certain of ~~its subsidiaries. Subject~~GenOn Mid-Atlantic’s stakeholders, or the GenMA Settlement, and directed the settlement parties to ~~applicable collateral thresholds, these arrangements may provide for~~cooperate in good faith to negotiate definitive documentation consistent with the ~~bilateral exchange~~GenMA Settlement term sheet in order to pursue consummation of the GenMA Settlement. The definitive documentation effectuating the GenMA Settlement was finalized and effective as of April 27, 2018. Certain terms of the compromise with respect to NRG and GenOn Mid-Atlantic are as follows:

Settlement of all pending litigation and objections to the Plan (including with respect to releases and feasibility);

NRG provided $37.5 million in letters of credit as new qualifying credit support ~~based upon market exposure~~to GenOn Mid-Atlantic; and ~~potential market movements.~~

NRG paid approximately $6 million as reimbursement of professional fees incurred by certain of GenOn Mid-Atlantic's stakeholders in connection with the GenMA Settlement.

Dispositions

On June 29, 2018, the Company completed the sale of Canal 3 to Stonepeak Kestrel for cash proceeds of approximately $16 million and recorded a gain of $17 million. Prior to the sale, Canal 3 entered into a financing arrangement and received cash proceeds of $167 million, of which $151 million was distributed to the Company. The ~~terms~~related debt is non-recourse to NRG and ~~conditions~~was transferred to Stonepeak Kestrel in connection with the sale of Canal 3.

In addition, the ~~agreements are generally consistent with industry practices and~~Company completed other ~~third party arrangements. For current and pre-disposal periods, revenue and expense associated with these transactions is recorded~~asset sales for $7 million of cash proceeds in ~~continuing operations.~~the first half of 2018.

~~GenOn Debt~~

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


1)	~~The intercompany secured revolving credit facility with NRG;~~


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


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


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


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


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

~~Transfer~~Transfers of Assets Under Common Control

On ~~November 1, 2017, NRG~~June 19, 2018, the Company completed the sale of ~~a 38 MW solar portfolio primarily comprised~~the substantially completed assets of ~~assets from SPP funds, in addition to other projects developed by NRG,~~the UPMC Thermal Project to NRG Yield, Inc. for cash consideration of ~~$71~~$84 million, ~~plus $3 million in~~subject to working capital adjustments.

On ~~August 1, 2017, NRG closed on~~March 30, 2018, as part of the ~~sale of its remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects,~~Transformation Plan, the Company sold to NRG Yield, Inc. ~~for total~~100% of NRG's interests in Buckthorn Renewables, LLC, which owns a 154-MW construction-stage utility-scale solar generation project, located in Texas. NRG Yield, Inc. paid cash consideration of ~~$44~~approximately $42 million, ~~including~~excluding working capital ~~adjustment~~adjustments, and assumed non-recourse debt of $3approximately $183 million. ~~The transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning~~Concurrently, an initial contribution of approximately $19 million was received from the third-party investor in ~~2027.~~

the underlying tax equity partnership, which is included in noncontrolling interest.

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

On September 1, 2016, the Company completed the sale of its remaining 51.05% interest in the CVSR project to NRG Yield, Inc. for total cash consideration of $78.5 million, plus an immaterial working capital adjustment. In addition, NRG Yield, Inc. assumed non-recourse project level debt of $496 million.

~~Acquisitions~~

~~SunEdison Utility-Scale Solar and Wind Acquisition~~

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

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

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

~~SunEdison Solar Distributed Generation Acquisition~~

On October 3, 2016, the Company acquired a 29 MW portfolio of mechanically-complete and construction-ready distributed generation solar assets from SunEdison for cash consideration of approximately $67 million excluding post-closing adjustments which reduced the purchase price by $5 million. Subsequent to the acquisition, the Company sold the majority of these assets into a tax-equity financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc., and expects to sell the remaining assets into a similar portfolio in 2017. The purchase price was allocated to $47 million in construction in progress and $15 million in intangible assets.

~~Dispositions~~

~~Disposition of Majority Interest in EVgo~~

On June 17, 2016, the Company completed the sale of a majority interest in its EVgo business to Vision Ridge Partners for total consideration of approximately $39 million, including $17 million in cash received, which is net of $2.5 million in working capital adjustments, $15 million contributed as capital to the EVgo business and $7 million of future contributions by Vision Ridge Partners, all of which were determined based on forecasted cash requirements to operate the business in future periods. In addition, the Company has future earnout potential of up to $70 million based on future profitability targets. NRG will retain its original financial obligation of $102.5 million under its agreement with the CPUC whereby EVgo will build at least 200 public fast charging Freedom Station sites and perform the associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California. As part of the sale, NRG has contracted with EVgo to continue to build the remaining required Freedom Stations and commercial and multi-family parking spaces for electric vehicle charging required under this obligation and will be directly reimbursed by NRG for the costs. As a result of the sale, the Company recorded a loss on sale of $83 million during the second quarter of 2016, which reflects the loss on the sale of the equity interest of $27 million and the accrual of NRG's remaining obligation under its agreement with the CPUC of $56 million. On February 22, 2017, the Company and CPUC entered into a second amendment to the agreement which extended the operating period commitment for the Freedom Stations to December 5, 2020. At September 30, 2017, the Company's remaining 35% interest in EVgo of $2 million was accounted for as an equity-method investment.

~~Rockford Disposition~~

On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford I and Rockford II generating stations, or Rockford, for cash consideration of $55 million, subject to adjustments for working capital and the results of the PJM 2019/2020 base residual auction. Rockford is a 450 MW natural gas facility located in Rockford, Illinois. The transaction triggered an indicator of impairment as the sales price was less than the carrying amount of the assets, and, as a result the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sales price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016 to reduce the carrying amount of the assets held for sale to the fair market value. At June 30, 2016, the Company had $2 million of current assets and $54 million of non-current assets classified as held for sale for Rockford on its balance sheet. On July 12, 2016, the Company completed the sale of Rockford for cash proceeds of $56 million, including $1 million in adjustments for the PJM base residual auction results. For further discussion on this impairment, refer to Note 7, ~~Impairments,~~ ~~to this Form 10-Q.~~

Note 4 — Fair Value of Financial Instruments

This footnote should be read in conjunction with the complete description under Note 4, Fair Value of Financial Instruments, to the Company's ~~2016~~2017 Form 10-K.

For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:


	As of September 30, 2017				As of December 31, 2016				As of June 30, 2018				As of December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)								(In millions)
Assets:
Notes receivable^(a)	$	22	$	21	$	34	$	34	$	21	$	18	$	16	$	15
Liabilities:
Long-term debt, including current portion^(b)	17,097		17,423		16,655		16,620		15,969		16,163		16,603		16,894

(a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.

(b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.

The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non-publicly traded long-term debt and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016:~~2017:

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



	As of June 30, 2018				As of December 31, 2017
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	9,586	$	6,577	$	8,934	$	7,960

Recurring Fair Value Measurements

Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.

The following tables present assets and liabilities measured and recorded at fair value on the Company's condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:

As of September 30, 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 $ —
$ —
$ 19
$ 19
Available-for-sale securities 5
—
—
5
Nuclear trust fund investments:
Cash and cash equivalents 31
—
—
31
U.S. government and federal agency obligations 43
1
—
44
Federal agency mortgage-backed securities —
74
—
74
Commercial mortgage-backed securities —
11
—
11
Corporate debt securities —
108
—
108
Equity securities 333
—
65
398
Foreign government fixed income securities —
4
—
4
Other trust fund investments:
U.S. government and federal agency obligations 1
—
—
1
Derivative assets:
Commodity contracts 132
409
98
639
Interest rate contracts —
42
—
42
Total assets $ 545
$ 649
$ 182
$ 1,376
Derivative liabilities:
Commodity contracts 201
404
146
751
Interest rate contracts —
78
—
78
Total liabilities $ 201
$ 482
$ 146
$ 829



	As of June 30, 2018
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other non-current assets)	$	22	$	3	$	—	$	19
Nuclear trust fund investments:
Cash and cash equivalents	25		25		—		—
U.S. government and federal agency obligations	42		42		—		—
Federal agency mortgage-backed securities	97		—		97		—
Commercial mortgage-backed securities	16		—		16		—
Corporate debt securities	101		—		101		—
Equity securities	342		342		—		—
Foreign government fixed income securities	6		—		6		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,169		188		481		500
Interest rate contracts	108		—		108		—
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	65
Total assets	$	1,994	$	601	$	809	$	519
Derivative liabilities:
Commodity contracts	971		236		388		347
Interest rate contracts	23		—		23		—
Total liabilities	$	994	$	236	$	411	$	347


	As of December 31, 2016								As of December 31, 2017
	Fair Value								Fair Value
(In millions)	Level 1		Level 2		Level 3		Total		Total		Level 1		Level 2		Level 3
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	17	$	17
Available-for-sale securities	10		—		—		10
Investments in securities (classified within other non-current assets)									$	22	$	3	$	—	$	19
Nuclear trust fund investments:
Cash and cash equivalents	25		—		—		25		47		45		2		—
U.S. government and federal agency obligations	72		1		—		73		43		42		1		—
Federal agency mortgage-backed securities	—		62		—		62		82		—		82		—
Commercial mortgage-backed securities	—		17		—		17		14		—		14		—
Corporate debt securities	—		84		—		84		99		—		99		—
Equity securities	292		—		54		346		334		334		—		—
Foreign government fixed income securities	—		3		—		3		5		—		5		—
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1		1		1		—		—
Derivative assets:
Commodity contracts	560		549		90		1,199		745		191		509		45
Interest rate contracts	—		49		—		49		53		—		53		—
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments									68
Total assets	$	960	$	765	$	161	$	1,886	$	1,513	$	616	$	765	$	64
Derivative liabilities:
Commodity contracts	494		636		158		1,288		693		257		359		77
Interest rate contracts	—		88		—		88		59		—		59		—
Total liabilities	$	494	$	724	$	158	$	1,376	$	752	$	257	$	418	$	77

There were no transfers during the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017 between Levels 1 and 2. The following tables reconcile, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017, 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, 2018								Six months ended June 30, 2018
(In millions)	Debt Securities		Derivatives^(a)			Total			Debt Securities		Derivatives^(a)			Total
Beginning balance	$	19	$	(22	)	$	(3	)	$	19	$	(32	)	$	(13	)
Contracts acquired in Xoom acquisition	—		12			12			—		12			12
Total losses — realized/unrealized:
Included in earnings	—		(21		)	(21		)	—		(19		)	(19		)
Purchases	—		(4		)	(4		)	—		(3		)	(3		)
Transfers into Level 3 ^(b)	—		193			193			—		197			197
Transfers out of Level 3 ^(b)	—		(5		)	(5		)	—		(2		)	(2		)
Ending balance as of June 30, 2018	$	19	$	153		$	172		$	19	$	153		$	172
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, 2018	—		20			20			—		17			17


(a)	Consists of derivative assets and liabilities, net.


(b)	Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.


	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)																				Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended September 30, 2017										Nine months ended September 30, 2017										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			Debt Securities		Derivatives^(a)			Total			Debt Securities		Derivatives^(a)			Total
Beginning balance	$	18	$	61	$	(11	)	$	68		$	17	$	54	$	(68	)	$	3		$	18	$	(56	)	$	(38	)	$	17	$	(68	)	$	(51	)
Total gains/(losses) — realized/unrealized:
Total gains — realized/unrealized:
Included in earnings	1		—		(28		)	(27		)	2		—		18			20			—		40			40			1		46			47
Included in nuclear decommissioning obligation	—		3		—			3			—		10		—			10			—		—			—			—		—			—
Purchases	—		1		(9		)	(8		)	—		1		—			1			—		5			5			—		9			9
Transfers into Level 3 ^(b)	—		—		(6		)	(6		)	—		—		(11		)	(11		)	—		3			3			—		(5		)	(5		)
Transfers out of Level 3 ^(b)	—		—		6			6			—		—		13			13			—		(3		)	(3		)	—		7			7
Ending balance as of September 30, 2017	$	19	$	65	$	(48	)	$	36		$	19	$	65	$	(48	)	$	36
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of September 30, 2017	$	—	$	��	$	(13	)	$	(13	)	$	—	$	—	$	(6	)	$	(6	)
Ending balance as of June 30, 2017																					$	18	$	(11	)	$	7		$	18	$	(11	)	$	7
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 September 30, 2016 Nine months ended September 30, 2016
(In millions) Debt Securities Trust Fund Investments
Derivatives^(a)
Total Debt Securities Trust Fund Investments
Derivatives^(a)
Total
Beginning balance $ 16
$ 51
$ 18
$ 85
$ 17
$ 54
$ (22 ) $ 49
Total (losses)/gains — realized/unrealized:
Included in earnings —
—
(5 ) (5 ) —
—
4
4
Included in OCI 1
—
—
1
—
—
—
—
Included in nuclear decommissioning obligations —
3
—
3
—
(1 ) —
(1 )
Purchases —
—
(25 ) (25 ) —
1
2
3
Transfers into Level 3 ^(b)
—
—
(13 ) (13 ) —
—
(6 ) (6 )
Transfers out of Level 3 ^(b)
—
—
3
3
—
—
—
—
Ending balance as of September 30, 2016 $ 17
$ 54
$ (22 ) $ 49
$ 17
$ 54
$ (22 ) $ 49
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of September 30, 2016 $ —
$ —
$ (4 ) $ (4 ) $ —
$ —
$ (11 ) $ (11 )


~~(a)~~	~~Consists of derivative assets and liabilities, net.~~


~~(b)~~	~~Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.~~

Derivative Fair Value Measurements

A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of ~~September~~June 30, ~~2017~~2018, contracts valued with prices provided by models and other valuation techniques make up ~~14%~~39% of the total derivative assets and ~~18%~~35% of the total derivative liabilities.

NRG's significant positions classified as Level 3 include physical and financial power executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power 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 ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016:~~2017:


	Significant Unobservable Inputs													Significant Unobservable Inputs
	September 30, 2017													June 30, 2018
	Fair Value						Input/Range							Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average		Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)													(In millions)
Power Contracts	$	47	$	101	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	88	$	24	$	481	$	330	Discounted Cash Flow	Forward Market Price (per MWh)	$	6		$	198	$	35
FTRs	51		45		Discounted Cash Flow	Auction Prices (per MWh)	(31		)	36		—		19		17		Discounted Cash Flow	Auction Prices (per MWh)	(48		)	47		—
	$	98	$	146										$	500	$	347


	Significant Unobservable Inputs													Significant Unobservable Inputs
	December 31, 2016													December 31, 2017
	Fair Value						Input/Range							Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average		Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)													(In millions)
Power Contracts	$	39	$	108	Discounted Cash Flow	Forward Market Price (per MWh)	$	11		$	104	$	31	$	34	$	65	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	142	$	33
FTRs	51		50		Discounted Cash Flow	Auction Prices (per MWh)	(22		)	17		—		11		12		Discounted Cash Flow	Auction Prices (per MWh)	(28		)	46		—
	$	90	$	158										$	45	$	77

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016:~~2017:



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 ~~September~~June 30, ~~2017~~2018, the credit reserve resulted in a $1$4 million ~~increase~~decrease in fair value which is composed of a $1 million loss in ~~operating revenue~~OCI and ~~cost of operations.~~a $3 million loss in interest expense. As of December 31, ~~2016,~~2017, the credit reserve resulted in ~~a $10 million decrease~~no change 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~~2017 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~~2017 Form 10-K. As of ~~September~~June 30, ~~2017~~2018, the Company's counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $~~134~~289 million with net exposure of ~~$129~~$112 million. NRG held collateral (cash and letters of credit) against those positions of $14246 million. Approximately ~~74%~~77% of the Company's exposure before collateral is expected to roll off by the end of ~~2018.~~2019. 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	9176	%
Financial institutions	924
Total as of ~~September~~June 30, ~~2017~~2018	100	%



	Net Exposure ^{(a) (b)}
Category by Counterparty Credit Quality	(% of Total)
Investment grade	7976	%
Non-Investment grade/Non-Rated	2124
Total as of ~~September~~June 30, ~~2017~~2018	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 $5049 million as of ~~September~~June 30, ~~2017.~~2018. 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 ~~September~~June 30, ~~2017,~~2018, aggregate credit risk exposure managed by NRG to these counterparties was approximately ~~$4.3~~$4.1 billion, including ~~$2.8~~$2.5 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~~The Company is exposed to retail credit risk through the Company's retail electricity providers, which serve ~~commercial, industrial and governmental/institutional~~C&I customers and the Mass market. Retail credit risk results in losses 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~~The Company manages retail credit risk through the use of established credit policies that include monitoring of the portfolio and the use of credit mitigation measures such as deposits or prepayment arrangements.

As of ~~September~~June 30, ~~2017~~2018, the ~~Company believes its~~Company's retail customer credit exposure to C&I and Mass customers 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~~2017 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~~the Nuclear Decommissioning Trust liability and are not included in net income or accumulated OCI, consistent with regulatory treatment.

The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.


	As of September 30, 2017							As of December 31, 2016							As of June 30, 2018							As of December 31, 2017
(In millions, except otherwise noted)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)
Cash and cash equivalents	$	31	$	—	$	—	—	$	25	$	—	$	—	—	$	25	$	—	$	—	—	$	47	$	—	$	—	—
U.S. government and federal agency obligations	44		2		—		10	73		1		—		11	42		1		—		14	43		1		—		11
Federal agency mortgage-backed securities	74		1		1		24	62		1		1		25	97		—		3		23	82		1		1		23
Commercial mortgage-backed securities	11		—		—		23	17		—		1		26	16		—		1		22	14		—		—		20
Corporate debt securities	108		2		1		11	84		1		2		11	101		1		2		10	99		2		1		11
Equity securities	398		260		—		—	346		214		—		—	407		272		—		—	402		272		—		—
Foreign government fixed income securities	4		—		—		9	3		—		—		9	6		—		—		8	5		—		—		9
Total	$	670	$	265	$	2		$	610	$	217	$	4		$	694	$	274	$	6		$	692	$	276	$	2

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.


	Nine months ended September 30,				Six months ended June 30,
	2017		2016		2018		2017
	(In millions)				(In millions)
Realized gains	$	8	$	7	$	7	$	3
Realized losses	6		3		6		3
Proceeds from sale of securities	382		354		$	303	$	277

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~~2017 Form 10-K.

Energy-Related Commodities

As of ~~September~~June 30, ~~2017~~2018, 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 ~~September~~June 30, ~~2017~~2018, ~~the Company~~NRG 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~~a portion of which are designated as cash flow hedges.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016~~2017. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.


		Total Volume							Total Volume
		September 30, 2017			December 31, 2016				June 30, 2018			December 31, 2017
Category	Units	(In millions)						Units	(In millions)
Emissions	Short Ton	(1		)	—			Short Ton	2			1
Coal	Short Ton	15			35			Short Ton	12			21
Natural Gas	MMBtu	(62		)	(53		)	MMBtu	(551		)	(17		)
Oil	Barrel	—			1
Power	MWh	19			7			MWh	16			14
Capacity	MW/Day	(1		)	(1		)	MW/Day	(1		)	(1		)
Interest	Dollars	$	3,806		$	3,429		Dollars	$	4,016		$	3,876
Equity	Shares	1			1			Shares	—			1

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

Fair Value of Derivative Instruments

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


	Fair Value								Fair Value
	Derivative Assets				Derivative Liabilities				Derivative Assets				Derivative Liabilities
	September 30, 2017		December 31, 2016		September 30, 2017		December 31, 2016		June 30, 2018		December 31, 2017		June 30, 2018		December 31, 2017
	(In millions)								(In millions)
Derivatives designated as cash flow hedges:
Derivatives Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	—	$	—	$	8	$	28	$	3	$	1	$	2	$	5
Interest rate contracts long-term	10		12		15		41		23		11		5		11
Total derivatives designated as cash flow hedges	10		12		23		69
Derivatives not designated as cash flow hedges:
Total Derivatives Designated as Cash Flow or Fair Value Hedges									26		12		7		16
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	5		—		19		7		16		9		5		15
Interest rate contracts long-term	27		37		36		12		66		32		11		28
Commodity contracts current	470		1,067		495		1,057		832		616		702		535
Commodity contracts long-term	169		132		256		231		337		129		269		158
Total derivatives not designated as cash flow hedges	671		1,236		806		1,307
Total derivatives	$	681	$	1,248	$	829	$	1,376
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges									1,251		786		987		736
Total Derivatives									$	1,277	$	798	$	994	$	752

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


	Gross Amounts Not Offset in the Statement of Financial Position												Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount			Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of September 30, 2017	(In millions)
As of June 30, 2018													(In millions)
Commodity contracts:
Derivative assets	$	639		$	(546	)	$	(5	)	$	88		$	1,169		$	(817	)	$	(50	)	$	302
Derivative liabilities	(751		)	546			83			(122		)	(971		)	817			98			(56		)
Total commodity contracts	(112		)	—			78			(34		)	198			—			48			246
Interest rate contracts:
Derivative assets	42			(2		)	—			40			108			(3		)	—			105
Derivative liabilities	(78		)	2			—			(76		)	(23		)	3			—			(20		)
Total interest rate contracts	(36		)	—			—			(36		)	85			—			—			85
Total derivative instruments	$	(148	)	$	—		$	78		$	(70	)	$	283		$	—		$	48		$	331


	Gross Amounts Not Offset in the Statement of Financial Position												Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount			Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of December 31, 2016	(In millions)
As of December 31, 2017													(In millions)
Commodity contracts:
Derivative assets	$	1,199		$	(1,021	)	$	(13	)	$	165		$	745		$	(578	)	$	(11	)	$	156
Derivative liabilities	(1,288		)	1,021			13			(254		)	(693		)	578			73			(42		)
Total commodity contracts	(89		)	—			—			(89		)	52			—			62			114
Interest rate contracts:
Derivative assets	49			(4		)	—			45			53			(3		)	—			50
Derivative liabilities	(88		)	4			—			(84		)	(59		)	3			—			(56		)
Total interest rate contracts	(39		)	—			—			(39		)	(6		)	—			—			(6		)
Total derivative instruments	$	(128	)	$	—		$	—		$	(128	)	$	46		$	—		$	62		$	108

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												Interest Rate Contracts
	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
	(In millions)												(In millions)
Accumulated OCI beginning balance	$	(67	)	$	(165	)	$	(66	)	$	(101	)	$	(31	)	$	(61	)	$	(54	)	$	(66	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	4			2			10			12			3			3			7			6
Mark-to-market of cash flow hedge accounting contracts	4			32			(3		)	(42		)	5			(9		)	24			(7		)
Accumulated OCI ending balance, net of $15, and $28 tax	$	(59	)	$	(131	)	$	(59	)	$	(131	)
Losses expected to be realized from OCI during the next 12 months, net of $4 tax	$	14					$	14
Accumulated OCI ending balance, net of $5, and $16 tax													$	(23	)	$	(67	)	$	(23	)	$	(67	)
Losses expected to be realized from OCI during the next 12 months, net of $1 tax													$	8					$	8

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

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

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

Impact of Derivative Instruments on the Statements of Operations

Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges ~~and ineffectiveness of hedge derivatives~~ are reflected in current period consolidated results of operations.

The following table summarizes the pre-tax effects of economic hedges that have not been designated as ~~cash flow hedges, ineffectiveness on~~ cash flow hedges and trading activity on the Company's statement of operations. The effect of energy commodity contracts is included within operating revenues and cost of operations and the effect of interest rate contracts is included in interest expense.


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Unrealized mark-to-market results	(In millions)												(In millions)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(6	)	$	(30	)	$	19		$	(75	)	$	(3	)	$	22		$	(1	)	$	25
Reversal of acquired gain positions related to economic hedges	(2		)	(7		)	(1		)	(11		)
Reversal of acquired (gain)/loss positions related to economic hedges													(1		)	1			(1		)	1
Net unrealized (losses)/gains on open positions related to economic hedges	(16		)	(50		)	(1		)	27			(67		)	36			127			15
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(24		)	(87		)	17			(59		)	(71		)	59			125			41
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(5		)	3			(24		)	13
Net unrealized (losses)/gains on open positions related to trading activity	—			(8		)	17			14
Total unrealized mark-to-market (losses)/gains for trading activity	(5		)	(5		)	(7		)	27
Reversal of previously recognized unrealized gains on settled positions related to trading activity													(3		)	(4		)	(6		)	(19		)
Net unrealized gains on open positions related to trading activity													8			16			19			17
Total unrealized mark-to-market gains/(losses) for trading activity													5			12			13			(2		)
Total unrealized (losses)/gains	$	(29	)	$	(92	)	$	10		$	(32	)	$	(66	)	$	71		$	138		$	39


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
	(In millions)												(In millions)
Unrealized gains/(losses) included in operating revenues	$	21		$	57		$	178		$	(333	)	$	20		$	53		$	(78	)	$	157
Unrealized (losses)/gains included in cost of operations	(50		)	(149		)	(168		)	301			(86		)	18			216			(118		)
Total impact to statement of operations — energy commodities	$	(29	)	$	(92	)	$	10		$	(32	)	$	(66	)	$	71		$	138		$	39
Total impact to statement of operations — interest rate contracts	$	11		$	9		$	(8	)	$	(9	)	$	13		$	(24	)	$	61		$	(19	)

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 ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, the $1 million unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases of coal, natural gas, and ERCOT power due to decreases in coal, natural gas, and ERCOT electricity prices, which was largely offset by an increase in value of forward sales of PJM power and New York capacity due to decreases in PJM electricity and New York capacity prices.

~~For the nine months ended September 30, 2016, the $27~~$127 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of ERCOT heat rate and ERCOT electricity contracts due to ERCOT heat rate expansion and increases in ERCOT power prices.

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 ~~increases~~decreases in natural gas and coal 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~~require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of ~~September~~June 30, ~~2017,~~2018, was ~~$27~~$31 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of ~~September~~June 30, ~~2017,~~2018, was ~~$34~~$3 million. The Company is also a party to certain marginable agreements ~~where NRG~~under which it has a net liability position, but the counterparty has not called for the collateral due, which was approximately $174 million as of ~~September~~June 30, ~~2017~~2018.

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

Note 7 — Impairments

2018 Impairment Losses

Keystone and Conemaugh — On June 29, 2018, the Company entered into an agreement to sell its approximately 3.7% interests in the Keystone and Conemaugh generating stations. NRG recorded impairment losses of $14 million for Keystone and $14 million for Conemaugh to adjust the carrying amount of the assets to fair value based on the contractual sale price. The transaction is expected to close in the third quarter of 2018.

Dunkirk — During the second quarter of 2018, NRG ceased its development of the project to add gas capability at the Dunkirk generating station. The project was put on hold in 2015 pending the resolution of a lawsuit filed by Entergy Corporation against the NYPSC which challenged the legality of the Dunkirk contract. The lawsuit was later dropped and development continued, but the delay imposed a new requirement on Dunkirk to enter into the NYISO interconnection process. The NYISO studies have shown that it would cause the Company to incur a material increase in costs. In addition, the interconnection upgrades that the NYISO has identified may not be ready until December 2023, which represents a significant delay the project schedule. This caused the Company to record an impairment loss of $46 million, reducing the carrying amount of the related assets to $0.

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,~~Subsequent to the ~~Company gave notice to~~MIPA termination, BTEC ~~New Albany, LLC that it owes~~filed claims against NRG Texas Power LLC ~~approximately $48 million under~~with respect to the ~~terminated~~termination of the MIPA ~~consisting of $38 million~~and NRG filed counterclaims against BTEC as further described in ~~purchaser incurred costs~~Note 15, Commitments and ~~$10 million~~Contingencies. On June 7, 2018, the parties resolved all claims and counterclaims in ~~liquidated damages.~~the lawsuit.

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

~~2016 Impairment Losses~~

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

~~Other Impairments —~~ During the second quarter of 2016, the Company recorded impairment losses for intangible assets of $8 million in connection with the Company's strategic change in its residential solar business as well as $10 million of deferred marketing expenses. In addition, the Company also recorded an impairment loss of $17 million to record certain previously purchased solar panels at fair market value. During the third quarter of 2016, the Company recorded an additional $9 million in impairment losses related to investments and $8 million in other impairments.

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

Note 8 — Debt and Capital Leases

This footnote should be read in conjunction with the complete description under Note 12, Debt and Capital Leases, to the Company's ~~2016~~2017 Form 10-K. Long-term debt and capital leases consisted of the following:


(In millions, except rates)	September 30, 2017			December 31, 2016			September 30, 2017 interest rate % ^(a)	June 30, 2018			December 31, 2017			June 30, 2018 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
Senior Notes, due 2022								$	977		$	992		6.250
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
Senior Notes, due 2028								841			870			5.750
Convertible Senior Notes, due 2048								575			—			2.750
Revolving loan facility, due 2018 and 2021								26			—			L+1.75
Term loan facility, due 2023	1,876			1,891			L+2.25	1,862			1,872			L+1.75
Tax-exempt bonds	465			455			4.125 - 6.00	465			465			4.125 - 6.00
Subtotal NRG recourse debt	7,790			7,795
Subtotal recourse debt								7,729			7,182
Non-recourse debt:
NRG Yield, Inc. Convertible Senior Notes, due 2019								345			345			3.500
NRG Yield, Inc. Convertible Senior Notes, due 2020								288			288			3.250
NRG Yield Operating LLC Senior Notes, due 2024	500			500			5.375	500			500			5.375
NRG Yield Operating LLC Senior Notes, due 2026	350			350			5.000	350			350			5.000
NRG Yield, Inc. Convertible Senior Notes, due 2019	345			345			3.500
NRG Yield, Inc. Convertible Senior Notes, due 2020	288			288			3.250
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2023^(b)								—			55			L+1.75
El Segundo Energy Center, due 2023	400			443			L+1.75 - L+2.375	369			400			L+1.75 - L+2.375
Marsh Landing, due 2017 and 2023	334			370			L+1.750 - L+1.875
Marsh Landing, due 2023								305			318			L+2.125
Alta Wind I - V lease financing arrangements, due 2034 and 2035	940			965			5.696 - 7.015	901			926			5.696 - 7.015
Walnut Creek, term loans due 2023	279			310			L+1.625	254			267			L+1.625
Utah Portfolio, due 2022	284			287			L+2.625	273			278			various
Tapestry, due 2021	165			172			L+1.625	155			162			L+1.625
CVSR, due 2037	746			771			2.339 - 3.775	731			746			2.339 - 3.775
CVSR HoldCo, due 2037	194			199			4.680	188			194			4.680
Alpine, due 2022	138			145			L+1.750	133			135			L+1.750
Energy Center Minneapolis, due 2017 and 2025	82			96			5.95 - 7.25
Energy Center Minneapolis, due 2031	125			125			3.55
Energy Center Minneapolis, due 2031, 2033, 2035 and 2037								328			208			various
Viento, due 2023	169			178			L+3.00	154			163			L+3.00
Buckthorn Solar, due 2018 and 2025								132			169			L+1.750
NRG Yield - other	562			540			various	564			579			various
Subtotal NRG Yield debt (non-recourse to NRG)	5,901			6,084
Ivanpah, due 2033 and 2038	1,097			1,113			2.285 - 4.256
Carlsbad Energy Project	407			—			4.120
Subtotal NRG Yield debt (non-recourse to NRG) ^(c)								5,970			6,083
Ivanpah, due 2033 and 2038 ^(e)								—			1,073			2.285 - 4.256
Carlsbad Energy Project ^(c)								513			427			L+1.625 - 4.120
Agua Caliente, due 2037	833			849			2.395 - 3.633	812			818			2.395 - 3.633
Agua Caliente Borrower 1, due 2038	89			—			5.430	86			89			5.430
Cedro Hill, due 2025	153			163			L+1.75
Cedro Hill, due 2025 ^(c)								144			151			L+1.75
Midwest Generation, due 2019	173			231			4.390	108			152			4.390
NRG Other Renewables ^(c)								623			478			various
NRG Other	689			468			various	107			180			various
Subtotal other NRG non-recourse debt	3,441			2,824				2,393			3,368
Subtotal all non-recourse debt	9,342			8,908				8,363			9,451
Subtotal long-term debt (including current maturities)	17,132			16,703				16,092			16,633
Capital leases	6			6			various	3			5			various
Subtotal long-term debt and capital leases (including current maturities)	17,138			16,709				16,095			16,638
Less current maturities	(1,247		)	(516		)
Less current maturities^(d)								(952		)	(688		)
Less debt issuance costs	(198		)	(188		)		(199		)	(204		)
Discounts	(35		)	(48		)		(123		)	(30		)
Total long-term debt and capital leases	$	15,658		$	15,957			$	14,821		$	15,716

(a) As of ~~September~~June 30, ~~2017,~~2018, L+ equals 33-month LIBOR plus x%, except for Carlsbad, the Buckthorn Solar and Utah Solar Portfolio where L+ equals 1 month LIBOR plus x%, and Viento where L+ equals 6-month LIBOR plus x%.

(b) Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement.

(d) The NRG Yield, Inc. Convertible Senior Notes, due 2019, become due in February 2019 and are recorded in current maturities as of June 30, 2018.

(e) The Company deconsolidated Ivanpah during the ~~Utah Portfolio term loans.~~second quarter of 2018.

Recourse Debt

2023 Term Loan Facility

On ~~January 24, 2017,~~March 21, 2018, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus ~~2.25%. The~~1.75% and reducing the LIBOR floor ~~remains 0.75%~~to 0.00%.

~~Revolving Credit Facility~~

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

Senior Notes

~~2017~~

Issuance of 2048 Convertible Senior ~~Note Redemptions~~Notes

~~On October 16, 2017,~~During the ~~Company redeemed $398~~second quarter of 2018, NRG issued $575 million in aggregate principal amount of ~~its 7.625%~~2.75% Convertible Senior Notes due ~~2018~~2048, or the Convertible Notes. The Convertible Notes are convertible, under certain circumstances, into the Company's common stock, cash or a combination thereof (at NRG's option) at an initial conversion price of $47.74 per common share, which is equivalent to an initial conversion rate of approximately 20.9479 shares of common stock per $1,000 principal amount of Convertible Notes. Interest on the Convertible Notes is payable semi-annually in arrears on June 1 and ~~$206~~December 1 of each year, commencing on December 1, 2018. The Convertible Notes mature on June 1, 2048, unless earlier repurchased, redeemed or converted in accordance with their terms. The Convertible Notes are guaranteed by certain NRG subsidiaries. Prior to the close of business on the business day immediately preceding December 1, 2024, the Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter during specified periods as follows:

•from December 1, 2024 until the close of business on the second scheduled trading day immediately before June 1, 2025; and

•from December 1, 2047 until the close of business on the second scheduled trading day immediately before the maturity date.

The Convertible Notes are accounted for in accordance with ASC 470-20, Debt with Conversion and Other Options. Under ASC 470-20, issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are required to separately account for the liability (debt) and equity (conversion option) components. The carrying amount of the liability component at issuance date of $472 million was calculated by estimating the fair value of ~~its 7.875% Senior Notes due 2021 for $630~~similar liabilities without a conversion feature. The residual principal amount of the notes of $103 million was allocated to the equity component with offset to debt discount. The debt discount will be amortized to interest expense using the effective interest method over seven years which ~~included $14~~is determined to be the expected life of the Convertible Notes.

The Company incurred approximately $12 million in ~~accrued interest.~~transaction costs in connection with the issuance of the notes. These costs were allocated to the liability and equity components in proportion to the allocation of proceeds. Transaction costs of $9.5 million, allocated to the liability component, were recognized as deferred financing costs and are amortized over the seven years. Transaction costs of $2 million, allocated to the equity component, were recognized as a reduction of additional paid-in capital.

~~2016~~ Senior Note Repurchases

~~During~~In connection with the ~~nine months ended September 30, 2016,~~Transformation Plan, the Company ~~repurchased $2.6 billion in aggregate principal~~has committed to reduce its debt balance by an additional $640 million to achieve a target net debt to adjusted EBITDA credit ratio of ~~its Senior Notes in the~~3.0/1. The following open market ~~for $2.7 billion, which included accrued interest of $67 million.~~ senior note repurchases were completed to assist in achieving this target.

In connection with the repurchases during the six months ended June 30, 2018, a ~~$94~~$1 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of ~~$15~~$1 million.

~~Issuance~~



	Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage
In millions, except rates
5.750% senior notes due 2028	$	29	$	30	99.24	%
6.250% senior notes due 2022	14		15		103.25	%
Total at June 30, 2018	$	43	$	45
6.250% senior notes due 2022	6		6		103.25	%
5.750% senior notes due 2028	20		21		99.13	%
6.625% senior notes due 2027	20		21		103.06	%
Total at August 2, 2018	$	89	$	93

(a) Includes payment for accrued interest of ~~2026 Senior Notes~~$1 million.

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~~are parties to a senior secured revolving credit facility, which can be used for cash and for the issuance of letters of credit. On April 30, 2018, NRG Yield LLC and NRG Yield Operating LLC refinanced the revolving credit facility, which extended the maturity of the facility to April 28, 2023, and decreased the overall cost of borrowing from L+ 2.50% to L+1.75%. At ~~September~~June 30, ~~2017,~~2018, there was ~~$68~~$67 million of letters of credit issued under the revolving credit facility and no ~~borrowing~~ outstanding borrowings on the revolver.

Project Financings

Thermal Financing

On June 19, 2018, NRG Energy Center Minneapolis, a subsidiary of NRG Yield LLC, entered into an amended and restated Thermal note purchase and private shelf agreement whereas it authorized the issuance of the Series E Notes, Series F Notes, Series G Notes, and Series H Notes, as further described in the table below:



	Amount			Interest Rate
In millions, except rates
Energy Center Minneapolis Series E Notes, due 2033	$	70		4.80	%
Energy Center Minneapolis Series F Notes, due 2033	10			4.60	%
Energy Center Minneapolis Series G Notes, due 2035	83			5.90	%
Energy Center Minneapolis Series H Notes, due 2037	40			4.83	%
Total proceeds	$	203
Repayment of Energy Center Minneapolis Series C Notes, due 2025	(83		)	5.95	%
Net borrowings	$	120

The Series G Notes were used to refinance the Series C Notes due 2025. The amended and restated Thermal note purchase and private shelf agreement also established a private shelf facility for the future issuance of notes in the amount of $40 million.

Rosamond Financing

On June 4, 2018, Rosamond Solar Portfolio, LLC entered into a financing agreement with financial institutions for a $118 million construction loan, which will convert to a term loan upon completion of project construction and a $175 million investment tax credit, or ITC, bridge loan, both of which have an interest rate of LIBOR plus 1.75%, as well as a letter of credit facility with availability of up to $33 million. The ITC bridge loan is expected to be repaid with proceeds from a tax equity arrangement by April 30, 2019. The term loan matures on April 30, 2034. As of June 30, 2018, $83 million and $5 million had been borrowed under the construction loan and the ITC bridge loan, respectively.

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, Acquisitions, Discontinued Operations ~~Dispositions~~ and ~~Acquisitions~~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 September 30, 2017, all $407 million of these notes were outstanding.~~

~~Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into~~2038, and 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~~project as well as a letter of credit facility with an aggregate ~~principle~~principal amount not to exceed $83 million, and a working capital loan facility with an aggregate ~~principle~~principal amount not to exceed $4 million. As of June 30, 2018, $513 million was outstanding under both the note and the construction loan.

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.

Utility-Scale Solar Portfolio—Through its consolidated subsidiary, NRG Yield, Inc., the Company has equity interests in Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC, which are accounted for as equity method investments as the Company does not have a controlling financial interest. The assets have 20-year PPAs with PacifiCorp. NRG's maximum exposure to loss is limited to its equity investment, which was $338 million as of June 30, 2018.

GenConn Energy LLC — Through its consolidated subsidiary, NRG Yield, ~~Operating LLC,~~Inc., the Company owns a 50% interest in GCE Holding LLC, the owner of GenConn, which owns and operates two 190 MW-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 $~~102~~100 million as of ~~September~~June 30, ~~2017~~2018.

Ivanpah Master Holdings LLC — Through its consolidated subsidiary, NRG Solar Ivanpah LLC, the Company owns a 54.6% interest in Ivanpah Master Holdings LLC, or Ivanpah, the owner of three solar electric generating projects located in the Mojave Desert with a total capacity of 392 MW. The projects were funded in large part by loans guaranteed by the U.S. DOE and equity from the projects' partners. During the first quarter of 2018, all interested parties sought a restructuring of Ivanpah's debt in order to avoid a potential event of default with respect to the loans in connection with several recent events, including the planned sale of NRG's renewables platform. Ensuing negotiations culminated in a settlement during the second quarter of 2018 between the parties which resulted in certain transactions, including the release of reserves totaling $95 million to fund equity distributions to the partners, which reduced the equity at risk, and the prepayment of certain of the debt balance outstanding, and the amendment of certain of Ivanpah's governing documents. The equity distributions and prepayment of debt were funded by the agreed upon release of reserve funds. These events were considered to be a reconsideration event in accordance with ASC 810, Consolidations. As a result, NRG determined that it is not the primary beneficiary and deconsolidated Ivanpah. NRG recognized a loss of $22 million on the deconsolidation and subsequent recognition of Ivanpah as an equity method investment during the six months ended June 30, 2018. The deconsolidation of Ivanpah reduced the Company's assets by approximately $1.3 billion, which was primarily property, plant and equipment, and reduced the Company's liabilities by $1.2 billion, which was primarily long-term debt. NRG's maximum exposure to loss is limited to its equity investment, which was $57 million as of June 30, 2018.

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~~2017 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to ~~$100~~$83 million as of ~~September~~June 30, ~~2017,~~2018, which would be required to be funded if the arrangement were to be dissolved.

The summarized financial information for the Company's consolidated VIEs consisted of the following:


(In millions)	September 30, 2017		December 31, 2016		June 30, 2018		December 31, 2017
Current assets	$	74	$	87	$	191	$	118
Net property, plant and equipment	1,466		1,534		2,709		2,337
Other long-term assets	1,026		954		660		658
Total assets	2,566		2,575		3,560		3,113
Current liabilities	69		59		119		96
Long-term debt	420		442		814		661
Other long-term liabilities	187		183		211		209
Total liabilities	676		684		1,144		966
Noncontrolling interests	578		529
Net assets less noncontrolling interests	$	1,312	$	1,362
Redeemable noncontrolling interest					69		78
Noncontrolling interest					660		507
Net assets less noncontrolling interest					$	1,687	$	1,562

Note 10 — Changes in Capital Structure

As of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016~~2017, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:


	Issued	Treasury		Outstanding	Issued	Treasury		Outstanding
Balance as of December 31, 2016	417,583,825	(102,140,814	)	315,443,011
Balance as of December 31, 2017					418,323,134	(101,580,045	)	316,743,089
Shares issued under LTIPs	634,738	—		634,738	1,373,655	—		1,373,655
Shares issued under ESPP	—	560,769		560,769	—	175,862		175,862
Balance as of September 30, 2017	418,218,563	(101,580,045	)	316,638,518
Shares repurchased					—	(14,863,301	)	(14,863,301	)
Balance as of June 30, 2018					419,696,789	(116,267,484	)	303,429,305

~~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

In January 2018, 175,862 shares of common stock were issued to employee accounts from treasury stock for the offering period of July 1, 2017, to December 31, 2017. In January 2018, NRG suspended the ESPP.

Share Repurchases

In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock, with the first $500 million program beginning as soon as permitted. The following repurchases have been made during the six months ended June 30, 2018.



	Total number of shares purchased	Average price paid per share ^(a)		Amounts paid for shares purchased (in millions) ^(a)
Board Authorized Share Repurchases
First Quarter 2018	3,114,748			$	93
Second Quarter 2018 ^(b)	11,748,553			407
Total Board Authorized Share Repurchases as of June 30, 2018	14,863,301			$	500
July 2018	860,880			—
Total Board Authorized Share Repurchases as of August 2, 2018	15,724,181	$	31.80	$	500

(a) The average price paid per share and amounts paid for shares purchased exclude the commissions of $0.01 per share paid in connection with the share repurchase.

(b) The share repurchases for the second quarter include 9,969,023 of the shares repurchased through the ASR Agreement, as described below.

Accelerated Share Repurchase

On ~~April 27, 2017, NRG stockholders approved~~May 24, 2018, the Company executed an ~~increase~~accelerated share repurchase agreement, or ASR Agreement, with a financial institution to repurchase a total of ~~3,000,000~~$354 million of outstanding common stock based on a volume weighted average price. The Company received initial shares ~~available~~of 9,969,023, which were recorded in treasury stock at fair value based on the closing price of $343 million, with the remaining $11 million recorded in additional paid in capital, representing the value of the forward contract to purchase additional shares. In July 2018, the financial institution delivered the remaining shares pursuant to the ASR Agreement and the Company received an additional 860,880 shares. The average price paid for ~~issuance~~all of the shares delivered under the ~~ESPP. As~~ASR Agreement was $32.69 per share. Upon receipt of ~~September 30, 2017, there were 3,107,050~~the additional shares, ofthe Company transferred the $11 million from additional paid in capital to treasury ~~stock available for issuance under the ESPP.~~stock.

~~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 ~~nine~~six months ended ~~September~~June 30, ~~2017:~~2018:

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

$ 0.03



	Second Quarter 2018		First Quarter 2018
Dividends per Common Share	$	0.03	$	0.03

On ~~October~~July 18, ~~2017,~~2018, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable ~~November~~August 15, ~~2017,~~2018, to stockholders of record as of ~~November~~August 1, ~~2017,~~2018, representing $0.12 per share on an annualized basis.

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.

Note 11 — Earnings/(Loss) Per Share

Basic earnings/(loss) per common share is computed by dividing net income/(loss) less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings/(loss) per share is computed in a manner consistent with that of basic income/(loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period. ~~During the second quarter of 2016, the Company repurchased 100% of the outstanding shares of its 2.822% preferred stock.~~ The reconciliation of NRG's basic and diluted ~~earnings/(loss)~~loss per share is shown in the following table:

Three months ended September 30, Nine months ended September 30,
(In millions, except per share data) 2017 2016 2017 2016
Basic and diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Net income/(loss) attributable to NRG Energy, Inc. $ 171
$ 402
$ (619 ) $ 213
Dividends for preferred shares —
—
—
5
Gain on redemption of 2.822% redeemable perpetual preferred stock —
—
—
(78 )
Income/(loss) available for common stockholders $ 171

$ 402

$ (619 )
$ 286
Weighted average number of common shares outstanding - basic 317
316

317
315
Income/(loss) per weighted average common share — basic $ 0.54
$ 1.27
$ (1.95 ) $ 0.91
Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding - diluted 317
316
317
315
Incremental shares attributable to the issuance of equity compensation (treasury stock method) 5
1
—
1
Total dilutive shares 322
317
317
316
Income/(loss) per weighted average common share — diluted $ 0.53
$ 1.27
$ (1.95 ) $ 0.91



	Three months ended June 30,					Six months ended June 30,
In millions, except per share data	2018		2017			2018		2017
Basic income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Net income/(loss) attributable to NRG Energy, Inc.	$	72	$	(626	)	$	351	$	(790	)
Weighted average number of common shares outstanding - basic	310		316			314		316
Earnings/(loss) per weighted average common share — basic	$	0.23	$	(1.98	)	$	1.12	$	(2.50	)
Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding - diluted	310		316			314		316
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	4		—			4		—
Total dilutive shares	314		316			318		316
Earnings/(loss) per weighted average common share — diluted	$	0.23	$	(1.98	)	$	1.10	$	(2.50	)

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 ~~earnings/(loss)~~loss per share:


	Three months ended September 30,		Nine months ended September 30,		Three months ended June 30,		Six months ended June 30,
(In millions of shares)	2017	2016	2017	2016
In millions of shares					2018	2017	2018	2017
Equity compensation plans	1	2	6	3	—	6	1	6
Total	1	2	6	3	—	6	1	6

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 nine months ended September 30, 2016 has been recast to reflect the current segment structure.~~

~~On September 1, 2016, NRG Yield acquired the remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, from the Company. On March 27,~~During 2017, NRG Yield acquired several projects totaling 555 MW from NRG. On March 30, 2018, the Company sold to NRG ~~a 16% interest in the Agua Caliente solar project, and~~Yield, Inc. 100% of NRG's interests in ~~seven~~Buckthorn Renewables, LLC, which owns a 154 MW construction-stage utility-scale solar ~~projects~~generation project, located in ~~Utah. On August 1, 2017, NRG Yield acquired the remaining 25% interest in NRG Wind TE Holdco from the Company. All three~~Texas. These acquisitions were treated as a transfer of entities under common control and accordingly, all historical periods have been recast to reflect the ~~acquisition~~acquisitions as if they had occurred at the beginning of the financial statement period.

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

NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and capital for allocation, as well as net income/(loss).

Generation^(a)

Retail ^(a)

Renewables^(a)
NRG Yield
Corporate^(a)
Eliminations Total
Three months ended September 30, 2017 (In millions)
Operating revenues^(a)
$ 1,224
$ 1,937
$ 144
$ 265
$ 2
$ (523 ) $ 3,049
Depreciation and amortization 96
29
51
88
8
—
272
Impairment losses 1
—
13
—
—
—
14
Equity in (losses)/earnings of unconsolidated affiliates 12
—
(3 ) 28
—
(10 ) 27
Loss on debt extinguishment, net —
—
—
—
(1 ) —
(1 )
Income/(loss) from continuing operations before income taxes 258
69
(7 ) 49
(161 ) (12 ) 196
Income/(loss) from continuing operations 258
69
(4 ) 41
(162 ) (12 ) 190
Loss from discontinued operations, net of tax —
—
—
—
(27 ) —
(27 )
Net Income/(loss) 258
69

(4 ) 41
(189 ) (12 ) 163
Net Income/(loss) attributable to NRG Energy, Inc. $ 258
—
$ 69
$ 9
$ 35

$ (220 ) $ 20
$ 171
Total assets as of September 30, 2017 $ 8,585
$ 2,445
$ 5,357
$ 8,442
$ 11,090
$ (10,449 ) $ 25,470



	Retail^(a)			Generation^(a)		Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total
Three months ended June 30, 2018	(In millions)
Operating revenues^(a)	$	1,817		$	1,218	$	113		$	307	$	7		$	(540	)	$	2,922
Depreciation and amortization	31			66		40			82		8			—			227
Impairment losses	—			74		—			—		—			—			74
Reorganization costs	1			3		3			—		16			—			23
Equity in earnings/(losses) of unconsolidated affiliates	—			—		5			29		—			(16		)	18
(Loss)/income from continuing operations before income taxes	(84		)	273		(17		)	103		(134		)	(12		)	129
(Loss)/income from continuing operations	(84		)	272		(12		)	96		(139		)	(12		)	121
Loss from discontinued operations, net of tax	—			—		—			—		(25		)	—			(25		)
Net (Loss)/Income	(84		)	272		(12		)	96		(164		)	(12		)	96
(Loss)/Income attributable to NRG Energy, Inc.	$	(88	)	$	272	$	(35	)	$	73	$	(244	)	$	94		$	72
Total assets as of June 30, 2018	$	7,217		$	4,306	$	4,117		$	8,448	$	9,675		$	(10,816	)	$	22,947

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



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	2	$	546	$	9	$	—	$	(17	)	$	—	$	540


	Generation^(a)		Retail^(a)			Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total			Retail^(a)		Generation^(a)			Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total
Three months ended September 30, 2016	(In millions)
Three months ended June 30, 2017																				(In millions)
Operating revenues^(a)	$	1,536	$	2,012		$	139		$	272	$	24		$	(562	)	$	3,421		$	1,603	$	882		$	119		$	288	$	3		$	(194	)	$	2,701
Depreciation and amortization	134		26			48			75		15			—			298			29		95			49			79		8			—			260
Impairment losses	9		—			—			—		—			—			9			—		41			22			—		—			—			63
Equity in earnings/(losses) of unconsolidated affiliates	6		—			(10		)	16		5			(1		)	16
Gain on sale of assets			—			—			—		4			—			4
Loss on debt extinguishment, net	—		—			—			—		(50		)	—			(50		)
Equity in (losses)/earnings of unconsolidated affiliates																				—		(15		)	(2		)	16		3			(5		)	(3		)
Income/(loss) from continuing operations before income taxes	370		(78		)	(1		)	63		(202		)	4			156			330		(89		)	(51		)	52		(134		)	(5		)	103
Income/(loss) from continuing operations	372		(78		)	2			50		(222		)	4			128			341		(90		)	(46		)	44		(145		)	(5		)	99
Income from discontinued operations, net of tax	—		—			—			—		265			—			265
Loss from discontinued operations, net of tax																				—		—			—			—		(741		)	—			(741		)
Net Income/(Loss)	372		(78		)	2			50		43			4			393			341		(90		)	(46		)	44		(886		)	(5		)	(642		)
Net Income/(Loss) attributable to NRG Energy, Inc.	$	372	$	(78	)	$	(9	)	$	55	$	19		$	43		$	402		$	341	$	(90	)	$	(21	)	$	38	$	(919	)	$	25		$	(626	)

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



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	1	$	171	$	3	$	—	$	19	$	—	$	194



	Retail^(a)		Generation^(a)			Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total
Six months ended June 30, 2018	(In millions)
Operating revenues^(a)	$	3,298	$	1,545		$	199		$	532	$	9		$	(240	)	$	5,343
Depreciation and amortization	59		133			90			163		17			—			462
Impairment losses	—		74			—			—		—			—			74
Reorganization costs	4		7			3			—		29			—			43
Equity in earnings/(losses) of unconsolidated affiliates	—		2			5			33		(1		)	(23		)	16
Income/(Loss) from continuing operations before income taxes	861		(264		)	(56		)	102		(260		)	(22		)	361
Income/(Loss) from continuing operations	861		(265		)	(45		)	96		(271		)	(22		)	354
Income from discontinued operations, net of tax	—		—			—			—		(25		)	—			(25		)
Net Income/(Loss)	861		(265		)	(45		)	96		(296		)	(22		)	329
Net Income/(Loss) attributable to NRG Energy, Inc.	$	851	$	(265	)	$	(33	)	$	94	$	(392	)	$	96		$	351



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	3	$	239	$	17	$	—	$	(19	)	$	—	$	240



	Retail ^(a)		Generation^(a)			Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total
Six months ended June 30, 2017
Operating revenues^(a)	$	2,938	$	1,848		$	213		$	509	$	11		$	(436	)	$	5,083
Depreciation and amortization	57		192			96			156		16			—			517
Impairment losses	—		41			22			—		—			—			63
Equity in (losses)/earnings of unconsolidated affiliates	—		(28		)	(3		)	35		7			(9		)	2
Income/(loss) from continuing operations before income taxes	303		(52		)	(87		)	49		(275		)	(9		)	(71		)
Income/(loss) from continuing operations	311		(54		)	(77		)	42		(283		)	(9		)	(70		)
Loss from discontinued operations, net of tax	—		—			—			—		(775		)	—			(775		)
Net Income/(loss)	311		(54		)	(77		)	42		(1,058		)	(9		)	(845		)
Net Income/(loss) attributable to NRG Energy, Inc.	$	311	$	(54	)	$	(24	)	$	50	$	(1,091	)	$	18		$	(790	)



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

Generation^(a)

Retail ^(a)

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

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

Generation^(a)

Retail^(a)

Renewables^(a)

NRG Yield^(a)

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

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

Note 13 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:


	Three months ended September 30,						Nine months ended September 30,						Three months ended June 30,						Six months ended June 30,
(In millions except otherwise noted)	2017			2016			2017			2016
In millions, except rates													2018			2017			2018			2017
Income/(Loss) before income taxes	$	196		$	156		$	125		$	(17	)	$	129		$	103		$	361		$	(71	)
Income tax expense from continuing operations	6			28			5			75
Income tax expense/(benefit) from continuing operations													8			4			7			(1		)
Effective tax rate	3.1		%	17.9		%	4.0		%	(441.2		)%	6.2		%	3.9		%	1.9		%	1.4		%

For the three ~~months~~ and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018, NRG's overall effective tax rate was different than the statutory rate of ~~35%~~21% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs from various wind facilities partially offset by the inclusion of consolidated partnerships and the current state tax expense.

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 ~~three~~six months ended ~~September~~June 30, ~~2016,~~2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax ~~benefit~~expense for the change in valuation allowance and current state tax expense, partially offset by ~~amortization~~the generation of ~~indefinite lived assets, inclusion of consolidated partnerships~~PTCs and ~~state tax expense.~~

~~For the nine months ended~~ ~~September 30, 2016~~, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the amortization of indefinite lived assets, the inclusion of consolidated partnerships, state tax expenseITCs from various wind and ~~the expense for the change in valuation allowance.~~solar facilities, respectively.

Uncertain Tax Benefits

As of ~~September~~June 30, ~~2017,~~2018, NRG has recorded a non-current tax liability of ~~$40~~$39 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of ~~September~~June 30, ~~2017,~~2018, NRG had cumulative interest and penalties related to these uncertain tax benefits of $45 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~~no longer 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 and Transition 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, Acquisitions, Discontinued Operations ~~Dispositions~~ and ~~Acquisitions~~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~~million.

In December 2017, in conjunction with the ~~pendency~~confirmation 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,~~plan of reorganization, the Services Agreement was terminated and replaced by the transition services agreement. Under the transition services agreement, NRG ~~will provide~~provided the shared services ~~for two months at no charge; after which GenOn has an additional two, one-month options to provide~~and other separation services at an annualized ~~fee~~rate of $84 ~~million.~~million, subject to certain credits and adjustments. GenOn provided notice to NRG ~~charges these fees on a monthly basis, less~~of its intent to terminate the transition services agreement effective August 15, 2018 and in connection with the settlement agreement described in Note 3, Acquisitions, Discontinued Operations and Dispositions, all amounts ~~incurred directly by GenOn.~~owed and payable to NRG were settled against the $28 million credit provided for in the Restructuring Support Agreement. NRG may provide additional separation services that are necessary for or reasonably related to the operation of GenOn's business after such date, subject to NRG's prior written consent, not to be unreasonably withheld. For the three and ~~nine~~six months ended ~~September~~June 30, 2018, NRG recorded approximately $21 million and $42 million, respectively, under the transition services agreement against selling, general and administrative expenses post-Chapter 11 Filing. For the three and six months ended June 30, 2017, NRG recorded other income - affiliate related to these services of ~~$14~~$39 million and ~~$104~~$87 million, respectively. ~~For the three and nine months ended September 30, 2016, NRG recorded other income - affiliate related to these services of $48 million and $144 million, respectively.~~

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

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

Credit Agreement with GenOn

NRG and GenOn are party to a secured intercompany revolving credit agreement. The intercompany revolving credit agreement provided for a $500 million revolving credit facility, all of which was available for revolving loans and letters of credit. At ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016, $103~~2017, $45 million and ~~$272~~$92 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of ~~September~~June 30, 2018 and December 31, 2017, there were $151 million and $125 million, respectively, of loans outstanding under the ~~intercompany secured revolving credit facility. As of December 31, 2016, no loans were outstanding under this~~ intercompany secured revolving credit facility. In addition, the intercompany secured revolving credit facility contains customary covenants and events of default. As of ~~September~~June 30, ~~2017,~~2018, 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,~~As the Restructuring Support Agreement provided that the borrowings be repaid to NRG ~~agreed~~at or prior 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 repayemergence, NRG ~~for all revolving loans outstanding, with such amount to be netted against the settlement payment owed from NRG to GenOn. Accordingly, the~~recorded its affiliate receivable ~~is recorded~~for the amount outstanding net within accrued expenses and other current liabilities - affiliate on the consolidated balance sheet as of ~~September~~June 30, ~~2017.~~2018. Interest ~~continues~~continued to accrue during the pendency of the Chapter 11 Cases until July 2018, when all borrowings and ~~borrowings remain secured obligations.~~

related interest were settled against amounts owed by the Company to GenOn as further discussed in Note 3 , Acquisitions, Discontinued Operations and Dispositions, in connection with the settlement between NRG and GenOn.

Commercial Operations Agreement

NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. As of ~~September~~June 30, ~~2017,~~2018, 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. Additionally, as of June 30, 2018 and December 31, 2017, the Company had $24 million and $32 million, respectively, of cash collateral posted in support of energy risk management activities by GenOn.

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~~2017 Form 10-K.

Commitments

First Lien Structure—

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets that have project-level financing, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of ~~September~~June 30, ~~2017,~~2018, hedges under the first ~~liens~~lien were ~~out-of-the-money~~in-the-money for NRG on a counterparty aggregate basis.

~~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~~March 27, 2018, ComEd filed a ~~subpoena from the NYAG which generally sought information and business records~~Motion to Compel Payments of Claims seeking $61 million related to ~~Energy Plus Holdings' sales, marketing~~asbestos liabilities. On April 25, 2018, NRG filed an Omnibus Objection to All Remaining Claims of ComEd 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. On August 28, 2017, the parties entered into an Assurance of Discontinuance resolving this matter.Exelon.

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.regulations. 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.~~litigation. Midwest Generation ~~filed a motion~~moved 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.~~counts. 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.~~claims. 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~~On May 10, 2018, the district court approved the Consent Decree settling this litigation and dismissed the case. Pursuant to the Consent Decree, Midwest Generation has paid $500,000 to each of the ~~environmental groups that had intervened in~~State of Illinois and 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~~Federal Government and has agreed to ~~have a material impact on the Company’s consolidated financial position, results of operations or cash flows.~~make and maintain certain operational improvements.

Telephone Consumer Protection Act Purported Class Actions — Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC — one in California and two in New Jersey. The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages and equitable relief. On June 22, 2017, plaintiffs in the California case filed a motion for leave to file a second amended complaint to substitute new plaintiffs. ~~Defendants’~~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~~defendants filed an answer to the second amended complaint. On August 31, 2017, the court in the California case agreed that the litigation should be stayed pending final court approval of the New Jersey settlement. On July 12, 2017, the parties in one of the New Jersey ~~action~~actions reached an agreement in principle to resolve the class allegations which was confirmed by a term sheet signed by the parties on July 28, 2017. On September 27, 2017, plaintiffs in one of the New Jersey ~~case~~cases filed their motion for preliminary approval of the class ~~settlement.~~settlement which was approved by the court on November 17, 2017. On May 14, 2018, the court entered a final order approving the class action settlement and dismissing the lawsuit, thereby ending the New Jersey lawsuits. On July 2, 2018, the court in the California case entered an order dismissing the lawsuit.

California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation. In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR. At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not. As such, the plaintiffs brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions. Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed ~~demurrers~~objections in response to the plaintiffs' complaint. The ~~demurrers~~objections 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~~objections to the amended complaints. On November 18, 2016, the court sustained the ~~demurrers~~objections 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~~objections without leave to amend. On July 14, 2017, CDWR filed a notice of appeal. On January 10, 2018, CDWR filed its appellate brief. Defendants filed their opposition brief on April 10, 2018. On May 30, 2018, CDWR filed their reply brief.

Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the current and former members of its board of directors individually, and other parties in California Superior Court in Kern County, CA. Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On ~~October 26, 2017,~~July 30, 2018, the ~~court approved the parties' stipulation which provides the plaintiffs' opposition is due on December 6, 2017 and defendants' reply is due on February 8, 2018.~~

~~Ahmed v. NRG Energy, Inc. and the NRG Yield Board of Directors~~ ~~— On September 15, 2016,~~ plaintiffs filed a putative class action lawsuit against NRG Energy, Inc., the directors of NRG Yield, Inc., and other parties in the Delaware Chancery Court. The complaint alleges that the defendants breached their respective fiduciary duties with regardan opposition 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~~defendants’ motion to ~~dismiss~~quash service of the ~~lawsuit on December 21, 2016. Plaintiffs filed their objection~~summons and an opposition to the motion to dismiss on February 15, 2017. The defendants' reply was filed on March 24, 2017. The court heard oral argument on defendants' motion to dismiss on June 20, 2017. On September 7, 2017, the court requested additional briefing which the parties provided on September 21, 2017.defendants’ demurrer.

Griffoul v. NRG Residential Solar Solutions — On February 28, 2017, plaintiffs, consisting of New Jersey residential solar customers, filed a purported class action lawsuit in New Jersey state court. Plaintiffs allege violations of the New Jersey Consumer Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar contracts. The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits. On June 6, 2017, the defendants filed a motion to compel arbitration or dismiss the lawsuit. Plaintiffs filed their opposition on June 29, 2017. On July 14, 2017, the court denied NRG's motion to compel arbitration or dismiss the case. On July 25, 2017, NRG filed a motion for reconsideration of the appeal, which ~~the court~~was denied. On August 22, 2017, NRG filed a notice of appeal. ~~NRG’s appellate brief was~~After oral argument on April 24, 2018, the Appellate Division reversed the lower court on May 4, 2018, and ordered that the plaintiff must arbitrate their claims against NRG. On May 23, 2018, the plaintiff filed ~~on October 25, 2017. Plaintiffs’ opposition is due on November 16, 2017.~~a petition for certification with the Supreme Court of New Jersey seeking to overturn the Appellate Division ruling. The petition and objection are fully briefed.

Rice v. NRG — On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court for the Western District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc. Plaintiffs generally claim personal injury, trespass, nuisance and property damage related to the disposal of coal ash from GenOn's Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property. Plaintiffs filed an amended complaint on August 14, 2017. On October 20, 2017, NRG filed its ~~answer~~answers and affirmative defenses. On July 6, 2018, NRG filed a motion for summary judgment. Plaintiffs filed their opposition to the motion for summary judgment on July 29, 2018.

Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen — On June 28, 2017, plaintiffs Washington-St. Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against Louisiana Generating, L.L.C., or LaGen, in the United States District Court for the Middle District of Louisiana. The plaintiffs claim breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology. Plaintiffs seek damages for the alleged improper charges and a declaration as to which charges are proper under the contract. On September 14, 2017, the court issued a scheduling order setting this case for trial on October 21, 2019. LaGen filed ~~a motion for a more definite statement~~its answer and affirmative defenses on ~~September 18,~~November 17, 2017.

GenOn Chapter 11 Cases — On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under the Restructuring Support Agreement to which the GenOn Entities, NRG and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them ~~has agreed to support~~supported the Bankruptcy ~~Court~~Court's 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,~~consummated, 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, Acquisitions, Discontinued Operations ~~Dispositions~~ and ~~Acquisitions~~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~~On July 13, 2018, NRG and GenOn executed a term sheet that resolves and releases the GenOn ~~Entities' plan of reorganization is approved by the Bankruptcy Court.~~Noteholder litigation.

Morgantown v. GenOn Mid-Atlantic — On June 8, 2017, Morgantown and Dickerson Owner Lessors filed a lawsuit against GenOn Mid-Atlantic, LLC, NRG North America LLC, GenOn Americas Generation, LLC, NRG Americas, Inc., GenOn Energy Holdings, Inc., GenOn Energy, Inc., and NRG Energy, Inc. in New York State Supreme Court. The plaintiffs allege that they were overcharged by defendants for certain services outlined in a Services Agreement and that defendants caused a Qualified Credit Support portion of a Participation Agreement, or QCS Agreement, to be violated by causing the transfer of certain money outside the allowable confines set forth in the QCS Agreement. In addition, plaintiffs claim that the transfers were unfairly executed and done so in an effort to defraud plaintiffs and hinder their ability to continue to do business. As such, plaintiffs seek, among other things, the return of certain transferred funds and service charges paid and to bar defendants from executing additional transfers on plaintiffs’ behalf. ~~A claims estimation ruling on this matter by~~On November 7, 2017, the Bankruptcy Court ~~could occur as early as November 7, 2017.~~issued an order estimating the claims to be valued at $0. On December 14, 2017, a settlement agreement was executed between GenOn and NRG. On April 27, 2018, the parties executed a mutual release which in conjunction with the settlement agreement resolved this lawsuit.

BTEC v. NRG Texas Power — On July 18, 2017, BTEC New Albany LLC, or BTEC, filed a lawsuit against NRG Texas Power LLC, or NRG Texas Power, in the Harris County District Court in Texas. On January 15, 2013, the parties entered into a Membership Interest and Purchase Agreement, or MIPA, whereby BTEC agreed to dismantle, transport and rebuild an electric power generation facility at the former P.H. Robinson Electric Generating Station in Bacliff, Texas. The MIPA required BTEC to meet a Guaranteed Commercial Completion Date of May 31, 2016. ~~But even a year later,~~Because BTEC had not satisfied all of the contractually-required acceptance ~~criteria. As a result and given that~~criteria by the MIPA expiration date, ~~passed on May 31, 2017,~~ NRG elected to terminate the contract in June 2017. BTEC ~~claims~~claimed that NRG Texas Power breached the MIPA by improperly terminating it, and ~~seeks~~sought a declaratory judgment as to the rights and obligations of the ~~parties. In addition, BTEC seeks~~parties as well as damages, interest and attorney’s fees. ~~On August 14, 2017, NRG Texas Power served its answer to the lawsuit.~~ On September 7, 2017, NRG Texas Power filed a counterclaim seeking damages in excess of $48 million. On June 7, 2018, the parties resolved all claims and counterclaims in the lawsuit and a dismissal order was subsequently entered by the court on July 12, 2018.

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~~sought to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings. In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants. In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit, or the Fifth Circuit. In March 2012, the Fifth Circuit reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. On December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29, 2015, MC Asset Recovery filed a notice to appeal this judgment with the Fifth Circuit. On June 1, 2017, the Fifth Circuit affirmed the District Court's judgment. On June 12, 2017, MC Asset Recovery petitioned the Fifth Circuit for rehearing. The petition for rehearing was denied and a court order and judgment affirming the District Court's judgments was entered on July 17, 2017. On ~~January~~October 17, 2018, the bankruptcy court ~~will~~is scheduled to hear a Motion for a Final Decree into close the Mirant ~~bankruptcy.~~bankruptcy case.

Natural Gas Litigation — GenOn ishas been a party to several lawsuits, certain of which are class action lawsuits, in state and federal courts, of which four remain pending involving plaintiffs 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,~~certification, which the plaintiffs appealed to. The plaintiffs petitioned the Ninth Circuit for interlocutory ~~review of the court’s order denying class certification.~~review. On ~~June 13, 2017,~~July 12, 2018, the Ninth Circuit ~~granted~~heard oral arguments and the case is under submission pending a decision.

On February 26, 2018, GenOn filed objections to the proofs of claim filed in the Chapter 11 Cases by all of the plaintiffs in each of the four cases. GenOn filed that same day a motion asking the Bankruptcy Court to estimate all of the proofs of claim at zero dollars, to which the plaintiffs objected. The Bankruptcy Court denied the plaintiffs' ~~petition~~objection, ruling that it had the authority to consider GenOn's objections to the proofs of claim and to estimate the claims, but has certified its decision for ~~interlocutory review.~~review by either the Fifth Circuit Court of Appeals or the District Court.

In ~~May 2016~~June 2018, GenOn reached a settlement with plaintiffs in ~~one~~three of the ~~Kansas cases,~~four remaining suits, which leaves only the ~~U.S. District Court for the District of Nevada granted the defendants' motion for summary judgment. Subsequently~~one purported class action involving plaintiffs in ~~December 2016, the plaintiffs filed~~Wisconsin. CenterPoint Energy Services is a ~~notice of appeal with the Ninth Circuit. The appeal has been fully briefed by the parties.~~defendant in that case, and GenOn has agreed to indemnify CenterPoint against certain losses relating to ~~these lawsuits.~~the lawsuit. The Nevada District Judge granted summary judgment in favor of CenterPoint in that lawsuit and the plaintiffs appealed that decision to the Ninth Circuit. The appeal was argued on February 16, 2018, and the case is under submission pending a decision.

Mirant Chapter 11 Proceedings — In ~~September 2012,~~July 2003, and various dates thereafter, the ~~State~~Mirant Debtors filed voluntary petitions in the U.S. Bankruptcy Court for the Northern District of ~~Nevada Supreme Court, which~~Texas, Fort Worth Division, for relief under Chapter 11 of the Bankruptcy Code. GenOn Energy Holdings and most of the other Mirant Debtors emerged from bankruptcy on January 3, 2006, when the plan of reorganization that was ~~handling~~approved in conjunction with Mirant Corporation's emergence from bankruptcy protection, or the Mirant Plan, became effective. The remaining ~~case, affirmed dismissal~~Mirant Debtors emerged from bankruptcy on various dates in 2007. Approximately 461,000 of the shares of GenOn Energy Holdings common stock to be distributed under the Mirant Plan have not yet been distributed and have been reserved for distribution with respect to claims disputed by the ~~Eighth Judicial District Court~~Mirant Debtors that have not been resolved. Upon the Mirant/RRI Merger, those reserved shares converted into a reserve for ~~Clark County, Nevada~~approximately 1.3 million shares of ~~all plaintiffs'~~GenOn common stock. Upon the NRG Merger, those reserved shares converted into a reserve for approximately 159,000 shares of NRG common stock. Under the terms of the Mirant Plan, upon the resolution of such a disputed claim, the claimant will receive the same pro rata distributions of common stock, cash, or both as previously allowed claims, ~~against GenOn. In February 2013,~~regardless of the ~~plaintiffs~~price at which the common stock is trading at the time the claim is resolved. If the aggregate amount of any such payouts results in the ~~Nevada case filed~~number of reserved shares being insufficient, additional shares of common stock may be issued to address the shortfall. The bankruptcy court is scheduled to hear a ~~petition~~Motion for a ~~writ of certiorari to~~Final Decree in 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.~~Mirant bankruptcy on October 17, 2018.

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.

Natixis v. GenOn Mid-Atlantic—On February 16, 2018, Natixis Funding Corp. and Natixis, New York Branch filed a complaint in the Supreme Court of the State of New York against GenOn Mid-Atlantic, the owner lessors under GenOn Mid-Atlantic’s operating leases of the Dickerson and Morgantown coal generation units, and the lease indenture trustee under those leases. The plaintiffs’ allegations against GenOn Mid-Atlantic relate to a payment agreement between GenOn Mid-Atlantic and Natixis Funding Corp. to procure credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson. The plaintiffs seek approximately $34 million in damages arising from GenOn Mid-Atlantic’s purported breach of certain warranties in the payment agreement. On April 2, 2018, GenOn Mid-Atlantic removed the allegations against it to the U.S. District Court for the Southern District of New York. On April 11, 2018, the U.S. District Court for the Southern District of New York entered a briefing schedule on a forthcoming motion to remand by Natixis Funding Corp. and a forthcoming motion to transfer by GenOn Mid-Atlantic. On April 26, 2018, Natixis Funding Corp. filed its motion to remand. On May 31, 2018, GenOn Mid-Atlantic opposed the motion to remand and filed a cross-motion to transfer. The parties completed briefing on the motions to remand and transfer on July 9, 2018, and the U.S. District Court for the Southern District of New York held an oral argument on July 18, 2018 and continued the motions to a subsequent conference scheduled for September 26, 2018.

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~~2017 Form 10-K. Environmental regulatory matters are discussed within Note 17, Environmental Matters, to this Form 10-Q.

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

Department of Energy Consideration of 202(c) and Defense Production Act —On March 29, 2018, FirstEnergy Solutions requested that the Department of Energy provide price supports for its coal and nuclear units by having the DOE issue an emergency must-run order under Section 202(c) of the Federal Power Act. A number of parties have filed comments with the DOE, including PJM, challenging the assertion that the FirstEnergy Solutions’ units are necessary for grid reliability. The DOE has not yet formally responded. On June 1, 2018, the White House announced that President Trump has directed Secretary of Energy Rick Perry to "prepare immediate steps to stop the loss" of coal and nuclear resources. No formal timeline for action on either proposal has been set by the Administration.

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.~~ Briefing is ~~underway.~~complete. On May 29, 2018, the United States filed an amicus brief at the invitation of the Seventh Circuit arguing that the ZEC program is not preempted.

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'~~Defendants' motions to dismiss were granted. On August 24, 2017, NRG, along with other plaintiff companies, filed a notice of appeal to the U.S. Court of Appeals for the Second Circuit. ~~On September 9, 2017, the Court of Appeals issued a briefing schedule.~~ Briefing is ~~underway.~~complete. On May 29, 2018, the United States filed an amicus brief at the invitation of the Seventh Circuit arguing that the ZEC program is not preempted.

Department of Energy's Proposed Grid Resiliency Pricing Rule and Subsequent FERC Proceeding — — On September 29, 2017, the Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC to take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 2, 2017, FERC issued a notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to address. On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner compatible with robust competitive markets. On January 8, 2018, FERC terminated the proposed rulemaking and opened a new proceeding asking each ISO/RTO to address specific questions focused on grid resilience. On March 9, 2018, the ISOs/RTOs filed comments to the questions posed by FERC. The Company responded on May 9, 2018 and is currently awaiting a decision from FERC.

East/West

Montgomery County Station Power Tax—On December 20, 2013, NRG received a letter from Montgomery County, Maryland requesting payment of an energy tax for the consumption of station power at the Dickerson Facility over the previous three years. Montgomery County seeks payment in the amount of $22 million, which includes tax, interest and penalties. NRG disputed the applicability of the tax. On December 11, 2015, the Maryland Tax Court reversed Montgomery County's assessment. Montgomery County filed an appeal, and on February 2, 2017, the Montgomery County Circuit Court affirmed the decision of the tax court. On February 17, 2017, Montgomery County filed an appeal to the Court of Special Appeals of Maryland. On April 24, 2018, the Court of Special Appeals of Maryland affirmed the lower court's decision and on May 29, 2018, Montgomery County petitioned the Court of Appeals of Maryland to issue a writ of certiorari to review that decision. NRG filed an answer opposing the petition on June 18, 2018. The petition is currently pending before the Court of Appeals of Maryland.

Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months, which was granted on November 3, 2017. On May 31, 2018, the CEC extended the suspension period at NRG's request to July 1, 2019. The supplemental extension period should allow sufficient time to determine whether alternate procurement efforts undertaken by SCE supersede the need for the Puente Power Project.

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~~2017 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, or FGD, 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. On September 18, 2017, the EPA promulgated a final rule that (i) postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking and (ii) withdrew the April 2017 administrative stay. The 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. ~~On September 13,~~In 2017, the EPA ~~granted~~agreed to reconsider the ~~petition for reconsideration~~rule. On July 30, 2018, the EPA promulgated a rule that amends the ~~Utility Solid Waste Activities Group filed in May 2017. The Company has evaluated the impact~~existing ash rule by extending some of the ~~new rule on~~deadlines and providing more flexibility for compliance. The EPA has stated that it intends to further revise the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of September 30, 2017.rule.

~~East Region~~East/West

~~Burton Island Old Ash Landfill~~New Source Review — The EPA and various states have been investigating compliance of electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review,” or NSR. In ~~January 2006, NRG's Indian River Power LLC was notified~~2007, Midwest Generation received an NOV from the EPA alleging that ~~it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located~~past work at Crawford, Fisk, Joliet, Powerton, Waukegan and Will County generating stations violated NSR and other regulations. These alleged violations are the subject of litigation described in Note 15, Commitments and Contingencies. Additionally, in April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at oil-fired combustion turbines 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 waterTorrington Terminal, Franklin, Branford 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.Middletown generating stations violated regulations regarding NSR.

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 ~~September~~June 30, ~~2017~~2018, the Company had outstanding $5.4 billion of Senior Notes due from ~~2018~~2022 to ~~2027,~~2048, 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 ~~September~~June 30, ~~2017~~2018:



Ace Energy, Inc.	New Genco GP, LLC	NRG ~~Norwalk Harbor Operations~~Northeast Affiliate Services Inc.
Allied Home Warranty GP LLC	Norwalk Power LLC	NRG ~~Operating Services,~~Norwalk Harbor Operations Inc.
Allied Warranty LLC	NRG Advisory Services LLC	NRG ~~Oswego Harbor Power Operations~~Operating Services, Inc.
Arthur Kill Power LLC	NRG Affiliate Services Inc.	NRG ~~PacGen~~Oswego Harbor Power Operations Inc.
Astoria Gas Turbine Power LLC	NRG Arthur Kill Operations Inc.	NRG ~~Portable Power LLC~~PacGen Inc.
Bayou Cove Peaking Power, LLC	NRG Astoria Gas Turbine Operations Inc.	NRG Portable Power ~~Marketing~~ LLC
BidURenergy, Inc.	NRG Bayou Cove LLC	NRG ~~Reliability Solutions~~Power Marketing LLC
Cabrillo Power I LLC	NRG Business Services LLC	NRG ~~Renter's Protection~~Reliability Solutions LLC
Cabrillo Power II LLC	NRG Cabrillo Power Operations Inc.	NRG ~~Retail~~Renter's Protection LLC
Carbon Management Solutions LLC	NRG California Peaker Operations LLC	NRG Retail ~~Northeast~~ LLC
Cirro Group, Inc.	NRG Cedar Bayou Development Company, LLC	NRG ~~Rockford Acquisition~~Retail Northeast LLC
Cirro Energy Services, Inc.	NRG Connected Home LLC	NRG ~~Saguaro Operations Inc.~~Rockford Acquisition LLC
Conemaugh Power LLC	NRG Connecticut Affiliate Services Inc.	NRG ~~Security LLC~~Saguaro Operations Inc.
Connecticut Jet Power LLC	NRG Construction LLC	NRG ~~Services Corporation~~Security LLC
Cottonwood Development LLC	NRG Curtailment Solutions, Inc	NRG ~~SimplySmart Solutions LLC~~Services Corporation
Cottonwood Energy Company LP	NRG Development Company Inc.	NRG ~~South Central Affiliate Services Inc.~~SimplySmart Solutions LLC
Cottonwood Generating Partners I LLC	NRG Devon Operations Inc.	NRG South Central ~~Generating LLC~~Affiliate Services Inc.
Cottonwood Generating Partners II LLC	NRG Dispatch Services LLC	NRG South Central ~~Operations Inc.~~Generating LLC
Cottonwood Generating Partners III LLC	NRG Distributed Energy Resources Holdings LLC	NRG South ~~Texas LP~~Central Operations Inc.
Cottonwood Technology Partners LP	NRG Distributed Generation PR LLC	NRG ~~SPV #1 LLC~~South Texas LP
Devon ~~Power��~~Power LLC	NRG Dunkirk Operations Inc.	NRG Texas C&I Supply LLC
Dunkirk Power LLC	NRG El Segundo Operations Inc.	NRG Texas Gregory LLC
Eastern Sierra Energy Company LLC	NRG Energy Efficiency-L LLC	NRG Texas Holding Inc.
El Segundo Power, LLC	NRG Energy Labor Services LLC	NRG Texas LLC
El Segundo Power II LLC	NRG ECOKAP Holdings LLC	NRG Texas Power LLC
Energy Alternatives Wholesale, LLC	NRG Energy Services Group LLC	NRG Warranty Services LLC
Energy Choice Solutions LLC	NRG Energy Services International Inc.	NRG West Coast LLC
Energy Plus Holdings LLC	NRG Energy Services LLC	NRG Western Affiliate Services Inc.
Energy Plus Natural Gas LLC	NRG Generation Holdings, Inc.	O'Brien Cogeneration, Inc. II
Energy Protection Insurance Company	NRG Greenco LLC	ONSITE Energy, Inc.
Everything Energy LLC	NRG Home & Business Solutions LLC	Oswego Harbor Power LLC
Forward Home Security, LLC	NRG Home Services LLC	Reliant Energy Northeast LLC
GCP Funding Company, LLC	NRG Home Solutions LLC	Reliant Energy Power Supply, LLC
Green Mountain Energy Company	NRG Home Solutions Product LLC	Reliant Energy Retail Holdings, LLC
Gregory Partners, LLC	NRG Homer City Services LLC	Reliant Energy Retail Services, LLC
Gregory Power Partners LLC	NRG Huntley Operations Inc.	RERH Holdings, LLC
Huntley Power LLC	NRG HQ DG LLC	Saguaro Power LLC
Independence Energy Alliance LLC	NRG Identity Protect LLC	Somerset Operations Inc.
Independence Energy Group LLC	NRG Ilion Limited Partnership	Somerset Power LLC
Independence Energy Natural Gas LLC	NRG Ilion LP LLC	Texas Genco GP, LLC
Indian River Operations Inc.	NRG International LLC	Texas Genco Holdings, Inc.
Indian River Power LLC	NRG Maintenance Services LLC	Texas Genco LP, LLC
Keystone Power LLC	NRG Mextrans Inc.	Texas Genco Services, LP
~~Langford Wind Power,~~Louisiana Generating LLC	NRG MidAtlantic Affiliate Services Inc.	US Retailers LLC
~~Louisiana Generating~~Meriden Gas Turbines LLC	NRG Middletown Operations Inc.	Vienna Operations Inc.
~~Meriden Gas Turbines~~Middletown Power LLC	NRG Montville Operations Inc.	Vienna Power LLC
~~Middletown~~Montville Power LLC	NRG New Roads Holdings LLC	WCP (Generation) Holdings LLC
~~Montville Power LLC~~NEO Corporation	NRG North Central Operations Inc.	West Coast Power LLC
~~NEO Corporation~~	~~NRG Northeast Affiliate Services 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 ~~September~~June 30, ~~2017~~2018

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)															(In millions)
Operating Revenues
Total operating revenues	$	2,160		$	1,021		$	—		$	(132	)	$	3,049		$	2,276		$	659		$	—		$	(13	)	$	2,922
Operating Costs and Expenses
Cost of operations	1,588			682			15			(129		)	2,156			1,778			282			(4		)	(5		)	2,051
Depreciation and amortization	104			160			8			—			272			76			143			8			—			227
Impairment losses	—			14			—			—			14			—			74			—			—			74
Selling, general and administrative	97			29			88			(1		)	213			110			34			77			(10		)	211
Reorganization	—			—			18			—			18
Development activity expenses	—			9			5						14
Reorganization costs																1			—			22			—			23
Development costs																—			13			3			—			16
Total operating costs and expenses	1,789			894			134			(130		)	2,687			1,965			546			106			(15		)	2,602
Other income - affiliate	—			—			14			—			14
Gain on sale of assets																—			14			—			—			14
Operating Income/(Loss)	371			127			(120		)	(2		)	376			311			127			(106		)	2			334
Other Income/(Expense)
Equity in losses of consolidated subsidiaries	(41		)	(9		)	(134		)	184			—
Equity in (losses)/earnings of unconsolidated affiliates	—			(606		)	666			(33		)	27
Other income	7			3			5			—			15
Loss on debt extinguishment	—			(1		)	—			—			(1		)
Equity in earnings of consolidated subsidiaries																7			—			355			(362		)	—
Equity in earnings of unconsolidated affiliates																—			18			—			—			18
Other income/(expense), net																4			(26		)	2			—			(20		)
Loss on debt extinguishment, net																—			—			(1		)	—			(1		)
Interest expense	(4		)	(103		)	(114		)	—			(221		)	(4		)	(92		)	(106		)	—			(202		)
Total other (expense)/income	(38		)	(716		)	423			151			(180		)
Income/(Loss) from Continuing Operations Before Income Taxes	333			(589		)	303			149			196
Total other income/(expense)																7			(100		)	250			(362		)	(205		)
Income Before Income Taxes																318			27			144			(360		)	129
Income tax expense/(benefit)	113			(209		)	102			—			6			108			(68		)	(32		)	—			8
Income/(Loss) from Continuing Operations	220			(380		)	201			149			190
Loss from Discontinued Operations, net of income tax	—			(27		)	—			—			(27		)
Net Income/(Loss)	220			(407		)	201			149			163
Income from Continuing Operations																210			95			176			(360		)	121
Loss from discontinued operations, net of income tax																—			—			(25		)	—			(25		)
Net Income																210			95			151			(360		)	96
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—			(3		)	30			(35		)	(8		)	—			(57		)	79			2			24
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	220		$	(404	)	$	171		$	184		$	171
Net Income Attributable to NRG Energy, Inc.																$	210		$	152		$	72		$	(362	)	$	72


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)															(In millions)
Operating Revenues
Total operating revenues	$	5,517		$	2,872		$	—		$	(257	)	$	8,132		$	4,120		$	1,249		$	—		$	(26	)	$	5,343
Operating Costs and Expenses
Cost of operations	4,156			1,904			46			(254		)	5,852			3,004			613			9			(17		)	3,609
Depreciation and amortization	307			458			24			—			789			149			297			16			—			462
Impairment losses	42			35			—			—			77			—			74			—			—			74
Selling, general and administrative	281			115			304			(3		)	697			213			60			139			(10		)	402
Reorganization	—			—			18			—			18
Development activity expenses	—			34			15			—			49
Reorganization costs																3			—			40			—			43
Development costs																—			23			7			(1		)	29
Total operating costs and expenses	4,786			2,546			407			(257		)	7,482			3,369			1,067			211			(28		)	4,619
Other income - affiliate	—			—			104			—			104
Gain on sale of assets	4			—			—			—			4			3			13			—			—			16
Operating Income/(Loss)	735			326			(303		)	—			758			754			195			(211		)	2			740
Other Income/(Expense)
Equity in losses of consolidated subsidiaries	(61		)	(66		)	(182		)	309			—
Equity in earnings of consolidated subsidiaries																9			—			685			(694		)	—
Equity in earnings/(losses) of unconsolidated affiliates	—			101			(3		)	(69		)	29			—			17			(1		)	—			16
Other income	8			15			10			—			33
Loss on debt extinguishment	—			(3		)	—			—			(3		)
Other income/(expense), net																8			(36		)	5			—			(23		)
Loss on debt extinguishment, net																—			—			(3		)	—			(3		)
Interest expense	(11		)	(328		)	(353		)	—			(692		)	(7		)	(164		)	(198		)	—			(369		)
Total other expense	(64		)	(281		)	(528		)	240			(633		)
Income/(Loss) from Continuing Operations Before Income Taxes	671			45			(831		)	240			125
Total other income/(expense)																10			(183		)	488			(694		)	(379		)
Income Before Income Taxes																764			12			277			(692		)	361
Income tax expense/(benefit)	244			28			(267		)	—			5			221			(20		)	(194		)	—			7
Income/(Loss) from Continuing Operations	427			17			(564		)	240			120
Loss from Discontinued Operations, net of income tax	—			(802		)	—			—			(802		)
Net Income/(Loss)	427			(785		)	(564		)	240			(682		)
Income from Continuing Operations																543			32			471			(692		)	354
Loss from discontinued operations, net of income tax																—			—			(25		)	—			(25		)
Net Income																543			32			446			(692		)	329
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—			(49		)	55			(69		)	(63		)	—			(119		)	95			2			(22		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	427		$	(736	)	$	(619	)	$	309		$	(619	)
Net Income Attributable to NRG Energy, Inc.																$	543		$	151		$	351		$	(694	)	$	351


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE ~~INCOME/(LOSS)~~INCOME

For the three months ended ~~September~~June 30, ~~2017~~2018

(Unaudited)

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

Eliminations^(a)
Consolidated
(In millions)
Net Income/(Loss) $ 220
$ (407 ) $ 201
$ 149
$ 163
Other Comprehensive Income/(Loss), net of tax
Unrealized gain on derivatives, net —
7
7
(7 ) 7
Foreign currency translation adjustments, net 2
2
2
(4 ) 2
Available-for-sale securities, net —
—
1
—
1
Defined benefit plans, net —
—
(2 ) 1
(1 )
Other comprehensive income 2
9
8
(10 ) 9
Comprehensive Income/(Loss) 222
(398 ) 209
139
172
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest —
—
30
(35 ) (5 )
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. $ 222
$ (398 ) $ 179
$ 174
$ 177



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income	$	210		$	95		$	151		$	(360	)	$	96
Other Comprehensive Income, net of tax
Unrealized gain on derivatives, net	—			4			6			(5		)	5
Foreign currency translation adjustments, net	(4		)	(4		)	(5		)	9			(4		)
Available-for-sale securities, net	—			—			1			—			1
Defined benefit plans, net	—			—			(1		)	—			(1		)
Other comprehensive (loss)/income	(4		)	—			1			4			1
Comprehensive Income	206			95			152			(356		)	97
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(57		)	81			2			26
Comprehensive Income Attributable to NRG Energy, Inc.	$	206		$	152		$	71		$	(358	)	$	71


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE ~~INCOME/(LOSS)~~INCOME

For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018

(Unaudited)

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


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING BALANCE SHEETS~~

~~September 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 $ (20 ) $ 350
$ 893
$ —
$ 1,223
Funds deposited by counterparties 29
2
—
—
31
Restricted cash 14
523
—
—
537
Accounts receivable - trade, net 876
395
3
—
1,274
Accounts receivable - affiliate 222
191
(22 ) (337 ) 54
Inventory 406
224
—
—
630
Derivative instruments 438
106
5
(74 ) 475
Cash collateral posted in support of energy risk management activities 190
13
—
—
203
Prepayments and other current assets 108
147
45
—
300
Current assets - held for sale —
33
—
—
33
Total current assets 2,263
1,984
924

(411 ) 4,760
Net property, plant and equipment 3,980
11,142
236
(26 ) 15,332
Other Assets
Investment in subsidiaries 1,098
1,004
9,409
(11,511 ) —
Equity investments in affiliates —
1,135
3
—
1,138
Notes receivable, less current portion —
5
—
—
5
Goodwill 359
303
—
—
662
Intangible assets, net 520
1,321
—
(3 ) 1,838
Nuclear decommissioning trust fund 670
—
—
—
670
Derivative instruments 187
38
27
(46 ) 206
Deferred income tax (5 ) (148 ) 358
—
205
Non-current assets held-for-sale —
10
—
—
10
Other non-current assets 63
520
61
—
644
Total other assets 2,892
4,188
9,858
(11,560 ) 5,378
Total Assets $ 9,135
$ 17,314
$ 11,018
$ (11,997 ) $ 25,470
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases $ —
$ 623
$ 624
$ —
$ 1,247
Accounts payable 599
285
31
—
915
Accounts payable — affiliate 528
(340 ) 146
(338 ) (4 )
Derivative instruments 418
178
—
(74 ) 522
Cash collateral received in support of energy risk management activities 29
2
—
—
31
Accrued expenses and other current liabilities 301
57
472
—
830
Accrued expenses and other current liabilities-affiliate —
164
—
—
164
Total current liabilities 1,875
969
1,273
(412 ) 3,705
Other Liabilities
Long-term debt and capital leases 244
8,644
6,770
—
15,658
Nuclear decommissioning reserve 265
—
—
—
265
Nuclear decommissioning trust liability 397
—
—
—
397
Deferred income taxes 428
—
(407 ) —
21
Derivative instruments 194
159
—
(46 ) 307
Out-of-market contracts, net 69
144
—
—
213
Non-current liabilities held-for-sale —
13
—
—
13
Other non-current liabilities 377
315
424
—
1,116
Total non-current liabilities 1,974
9,275
6,787
(46 ) 17,990
Total liabilities 3,849
10,244
8,060
(458 ) 21,695
Redeemable noncontrolling interest in subsidiaries —
85
—
—
85
Stockholders’ Equity 5,286
6,985
2,958
(11,539 ) 3,690
Total Liabilities and Stockholders’ Equity $ 9,135
$ 17,314
$ 11,018
$ (11,997 ) $ 25,470


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS~~

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

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

Eliminations^(a)
Consolidated
(In millions)
Cash Flows from Operating Activities
Net income/(loss) $ 427
$ (785 ) $ (564 ) $ 240
$ (682 )
Loss from discontinued operations —
(802 ) —
—
(802 )
Net income/(loss) from continuing operations 427
17
(564 ) 240
120
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions from unconsolidated affiliates —
60
—
(7 ) 53
Equity in losses/(earnings) of unconsolidated affiliates —
(101 ) 3
69
(29 )
Depreciation and amortization 307
458
24
—
789
Provision for bad debts 40
2
15
—
57
Amortization of nuclear fuel 37
—
—
—
37
Amortization of financing costs and debt discount/premiums —
31
13
—
44
Adjustment for debt extinguishment —
3
—
—
3
Amortization of intangibles and out-of-market contracts 20
59
—
—
79
Amortization of unearned equity compensation —
—
27
—
27
Impairment losses 42
35
—
—
77
Changes in deferred income taxes and liability for uncertain tax benefits 244
28
(246 ) —
26
Changes in nuclear decommissioning trust liability 20
—
—

—
20
Changes in derivative instruments (11 ) 32
12
(8 ) 25
Changes in collateral deposits supporting energy risk management activities (126 ) 23
—
—
(103 )
Proceeds from sale of emission allowances 21
—
—
—
21
Gain on sale of assets (22 ) —
—
—
(22 )
Cash (used)/provided by changes in other working capital (958 ) (523 ) 1,395
(294 ) (380 )
Cash provided by continuing operations 41
124
679
—
844
Cash used by discontinued operations —
(38 ) —
—
(38 )
Net Cash Provided by Operating Activities 41
86
679
—
806
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc. —
—
69
(69 ) —
Acquisition of Drop Down Assets, net of cash acquired —
(176 ) —
176
—
Intercompany dividends —
—
129
(129 ) —
Acquisition of business, net of cash acquired —
(36 ) —
—
(36 )
Capital expenditures (135 ) (606 ) (19 ) —
(760 )
Decrease in notes receivable —
11
—
—
11
Purchases of emission allowances (47 ) —
—
—
(47 )
Proceeds from sale of emission allowances 105
—
—
—
105
Investments in nuclear decommissioning trust fund securities (402 ) —
—
—
(402 )
Proceeds from sales of nuclear decommissioning trust fund securities 382
—
—
—
382
Proceeds from renewable energy grants and state rebates 8
—

—
—
8
Proceeds from sale of assets, net of cash disposed of 36
—
—
—
36
Investments in unconsolidated affiliates —
(31 ) —
—
(31 )
Other 22
—
—
—
22
Cash (used)/provided by continuing operations (31 ) (838 ) 179
(22 ) (712 )
Cash used by discontinued operations —
(53 ) —
—
(53 )
Net Cash (Used)/Provided by Investing Activities (31 ) (891 ) 179
(22 ) (765 )
Cash Flows from Financing Activities

Dividends from NRG Yield, Inc. —
(69 ) —
69
—
Payments from/(for) intercompany loans 9
417
(426 ) —
—
Acquisition of Drop Down Assets, net of cash acquired —
—
176
(176 ) —
Intercompany dividends —
(129 ) —
129
—
Payment of dividends to common and preferred stockholders —
—
(28 ) —
(28 )
Net receipts from settlement of acquired derivatives that include financing elements —
2
—
—
2
Proceeds from issuance of long-term debt —
920
214
—
1,134
Payments for short and long-term debt —
(493 ) (219 ) —
(712 )
Receivable from affiliate —
(125 ) —
—
(125 )
Contributions from, net of distributions to, noncontrolling interest in subsidiaries —
65
—
—
65
Payment of debt issuance costs —
(38 ) (5 ) —
(43 )
Other - contingent consideration —
(10 ) —
—
(10 )
Cash provided/(used) by continuing operations 9
540
(288 ) 22
283
Cash used by discontinued operations —
(224 ) —
—
(224 )
Net Cash Provided/(Used) by Financing Activities 9
316
(288 ) 22
59
Change in cash from discontinued operations —
(315 ) —
—
(315 )
Effect of exchange rate changes on cash and cash equivalents —
(10 ) —
—
(10 )
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties 19
(184 ) 570
—
405
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period 4
1,059
323
—
1,386
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period $ 23

$ 875

$ 893

$ —
$ 1,791

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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~For the three months ended September 30, 2016~~

~~(Unaudited)~~

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

Eliminations^(a)
Consolidated
(In millions)
Operating Revenues
Total operating revenues $ 2,424
$ 1,090
$ —
$ (93 ) $ 3,421
Operating Costs and Expenses
Cost of operations 1,719
804
10
(93 ) 2,440
Depreciation and amortization 147
144
7
—
298
Impairment losses 8
1
—
—
9
Selling, general and administrative 115
50
112
—
277
Development activity expenses —
10
11
—
21
Total operating costs and expenses 1,989
1,009
140
(93 ) 3,045
Other income - affiliate —
—
48
—
48
Gain on sale of assets —
—
4
—
4
Operating Income/(Loss) 435
81
(88 ) —
428
Other Income/(Expense)

Equity in (losses)/earnings of consolidated subsidiaries (114 ) (10 ) 562
(438 ) —
Equity in earnings/(losses) of unconsolidated affiliates 2
75
(12 ) (49 ) 16
Loss on investment —
(8 ) —
—
(8 )
Other income/(loss), net 1
6
��
—
7
Loss on debt extinguishment —
—
(50 ) —
(50 )
Interest expense (4 ) (104 ) (129 ) —
(237 )
Total other expense (115 ) (41 ) 371
(487 ) (272 )
Income from Continuing Operations Before Income Taxes 320
40
283
(487 ) 156
Income tax expense/(benefit) 134
45
(151 ) —
28
Income from Continuing Operations 186
(5 ) 434
(487 ) 128
Income from Discontinued Operations, net of income tax —
263
2
—
265
Net Income 186
258
436
(487 ) 393
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest —
6
34
(49 ) (9 )
Net Income Attributable to NRG Energy, Inc. $ 186
$ 252
$ 402
$ (438 ) $ 402


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

~~For the nine months ended September 30, 2016~~

~~(Unaudited)~~

Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc.
(Note Issuer)
Eliminations^(a)
Consolidated
(In millions)
Operating Revenues
Total operating revenues $ 6,079
$ 2,400
$ —
$ (151 ) $ 8,328
Operating Costs and Expenses
Cost of operations 4,278
1,558
29
(154 ) 5,711
Depreciation and amortization 372
435
19
—
826
Impairment losses 8
57
—
—
65
Selling, general and administrative 306
144
351
—
801
Development activity expenses —
42
23
—
65
Total operating costs and expenses 4,964
2,236
422
(154 ) 7,468
Other income - affiliate —
—
144
—
144
Loss on sale of assets —
—
(79 ) —
(79 )
Operating Income/(Loss) 1,115
164
(357 ) 3
925
Other Income/(Expense)

Equity in (losses)/earnings of consolidated subsidiaries (195 ) (80 ) 904
(629 ) —
Equity in earnings/(losses) of unconsolidated affiliates 5
114
(2 ) (104 ) 13
Impairment loss on investment —
(147 ) —
—
(147 )
Other income, net 3
25
2
(1 ) 29
Loss on debt extinguishment —
(4 ) (115 ) —
(119 )
Interest expense (11 ) (312 ) (395 )

(718 )
Total other (expense)/income (198 ) (404 ) 394
(734 ) (942 )
Income/(Loss) Before Income Taxes 917
(240 ) 37
(731 ) (17 )
Income tax expense/(benefit) 362
(49 ) (238 ) —
75
Income/(Loss) from Continuing Operations 555
(191 ) 275
(731 ) (92 )
Income from Discontinued Operations, net of income tax —
248
8
—
256
Net Income 555
57
283
(731 ) 164
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest —
(17 ) 70
(102 ) (49 )
Net Income Attributable to NRG Energy, Inc. $ 555
$ 74
$ 213
$ (629 ) $ 213



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income	$	543		$	32		$	446		$	(692	)	$	329
Other Comprehensive (Loss)/Income, net of tax
Unrealized gain on derivatives, net	—			20			21			(22		)	19
Foreign currency translation adjustments, net	(6		)	(6		)	(8		)	14			(6		)
Available-for-sale securities, net	—			—			1			—			1
Defined benefit plans, net	—			—			(2		)	—			(2		)
Other comprehensive (loss)/income	(6		)	14			12			(8		)	12
Comprehensive Income	537			46			458			(700		)	341
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(119		)	105			2			(12		)
Comprehensive Income Attributable to NRG Energy, Inc.	$	537		$	165		$	353		$	(702	)	$	353


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

NRG ENERGY, INC. AND SUBSIDIARIES

~~CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)~~

~~For the three months ended September 30, 2016~~

~~(Unaudited)~~

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

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


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)~~

~~For the nine months ended September 30, 2016~~

~~(Unaudited)~~

Guarantor Subsidiaries Non-Guarantor Subsidiaries NRG Energy, Inc.
(Note Issuer)
Eliminations^(a)
Consolidated
(In millions)
Net Income $ 555
$ 57
$ 283
$ (731 ) $ 164
Other Comprehensive Income/(Loss), net of tax
Unrealized (loss)/gain on derivatives, net —
(15 ) 46
(39 ) (8 )
Foreign currency translation adjustments, net 4
4
6
(8 ) 6
Available-for-sale securities, net —
—
1
—
1
Defined benefit plans, net 55
—
(43 ) 20
32
Other comprehensive income/(loss) 59
(11 ) 10
(27 ) 31
Comprehensive Income 614
46
293
(758 ) 195
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest —
(38 ) 70
(102 ) (70 )
Comprehensive Income Attributable to NRG Energy, Inc. 614
84
223
(656 ) 265
Dividends for preferred shares —
—
5
—
5
Gain on redemption of preferred shares —
—
(78 ) —
(78 )
Comprehensive Income Available for Common Stockholders $ 614
$ 84
$ 296
$ (656 ) $ 338


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

CONDENSED CONSOLIDATING BALANCE SHEETS

~~December 31, 2016~~June 30, 2018

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations ^(a)			Consolidated		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)														(In millions)
Current Assets
Cash and cash equivalents	$	(9	)	$	624		$	323		$	—		$	938	$	71	$	395		$	514		$	—		$	980
Funds deposited by counterparties	2			—			—			—			2		71		—			—			—			71
Restricted cash	11			435			—			—			446		9		277			—			—			286
Accounts receivable - trade, net	734			321			3			—			1,058
Accounts receivable - affiliate	307			(254		)	200			(139		)	114
Accounts receivable, net															1,094		274			3			—			1,371
Inventory	482			239			—			—			721		309		176			—			—			485
Derivative instruments	962			196			1			(92		)	1,067		837		36			15			(37		)	851
Cash collateral posted in support of energy risk management activities	116			34			—			—			150
Current assets held-for-sale	—			9			—			—			9
Cash collateral paid in support of energy risk management activities															209		15			—			—			224
Accounts receivable - affiliate															1,189		123			141			(1,396		)	57
Current assets - held for sale															—		100			—			—			100
Prepayments and other current assets	76			152			62			—			290		173		122			35			(2		)	328
Current assets - discontinued operations	—			1,919			—			—			1,919
Total current assets	2,681			3,675			589			(231		)	6,714		3,962		1,518			708			(1,435		)	4,753
Net Property, Plant and Equipment	4,219			10,926			251			(27		)	15,369
Property, plant and equipment, net															2,402		10,164			231			(23		)	12,774
Other Assets
Investment in subsidiaries	1,090			1,054			10,128			(12,272		)	—		486		—			8,111			(8,597		)	—
Equity investments in affiliates	(13		)	1,128			5			—			1,120		—		1,055			—			—			1,055
Notes receivable, less current portion	—			16			—			—			16		—		15			—			—			15
Goodwill	359			303			—			—			662		360		179			—			—			539
Intangible assets, net	592			1,384			—			(3		)	1,973		415		1,448			—			(3		)	1,860
Nuclear decommissioning trust fund	610			—			—			—			610		694		—			—			—			694
Derivative instruments	144			44			36			(43		)	181		329		61			38			(2		)	426
Deferred income taxes	3			—			222			—			225
Non-current assets held for sale	—			10			—			—			10
Deferred income tax															156		34			(64		)	—			126
Non-current assets held-for-sale															—		50			—			—			50
Other non-current assets	67			446			328			—			841		81		454			120			—			655
Non-current assets - discontinued operations	—			2,961			—			—			2,961
Total other assets	2,852			7,346			10,719			(12,318		)	8,599		2,521		3,296			8,205			(8,602		)	5,420
Total Assets	$	9,752		$	21,947		$	11,559		$	(12,576	)	$	30,682	$	8,885	$	14,978		$	9,144		$	(10,060	)	$	22,947
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	498		$	18		$	—		$	516	$	—	$	862		$	92		$	(2	)	$	952
Accounts payable	501			247			34			—			782		699		230			46			—			975
Accounts payable — affiliate	744			(452		)	(122		)	(139		)	31		1,901		(207		)	(269		)	(1,396		)	29
Derivative instruments	947			237			—			(92		)	1,092		695		51			—			(37		)	709
Cash collateral received in support of energy risk management activities	81			—			—			—			81		72		—			—			—			72
Current liabilities held-for-sale															—		74			—			—			74
Accrued expenses and other current liabilities	316			209			465			—			990		270		123			326			—			719
Current liabilities - discontinued operations	—			1,210			—			—			1,210
Accrued expenses and other current liabilities-affiliate															—		—			133			—			133
Total current liabilities	2,589			1,949			395			(231		)	4,702		3,637		1,133			328			(1,435		)	3,663
Other Liabilities
Long-term debt and capital leases	244			8,252			7,461			—			15,957		245		7,428			7,148			—			14,821
Nuclear decommissioning reserve	287			—			—			—			287		274		—			—			—			274
Nuclear decommissioning trust liability	339			—			—			—			339		410		—			—			—			410
Deferred income taxes	186			125			(291		)	—			20		112		64			(159		)	—			17
Derivative instruments	157			170			—			(43		)	284		237		50			—			(2		)	285
Out-of-market contracts, net	80			150			—			—			230		58		137			—			—			195
Non-current liabilities held-for-sale	—			11			—			—			11		—		12			—			—			12
Other non-current liabilities	396			456			324			—			1,176		410		311			409			—			1,130
Non-current liabilities - discontinued operations	—			3,184			—			—			3,184
Total non-current liabilities	1,689			12,348			7,494			(43		)	21,488		1,746		8,002			7,398			(2		)	17,144
Total Liabilities	4,278			14,297			7,889			(274		)	26,190
Total liabilities															5,383		9,135			7,726			(1,437		)	20,807
Redeemable noncontrolling interest in subsidiaries	—			46			—			—			46		—		69			—			—			69
Stockholders’ Equity	5,474			7,604			3,670			(12,302		)	4,446		3,502		5,774			1,418			(8,623		)	2,071
Total Liabilities and Stockholders’ Equity	$	9,752		$	21,947		$	11,559		$	(12,576	)	$	30,682	$	8,885	$	14,978		$	9,144		$	(10,060	)	$	22,947


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

NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED

~~CONDENSED~~ CONSOLIDATING STATEMENTS OF CASH FLOWS

For the ~~nine~~six months ended ~~September~~June 30, ~~2016~~ 2018

(Unaudited)

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

Eliminations^(a)
Consolidated
(In millions)
Cash Flows from Operating Activities
Net Income $ 555
$ 57
$ 283
$ (731 ) $ 164
Less: Income from discontinued operations —
248
8
—
256
Net income/(loss) from continuing operations 555
(191 ) 275
(731 ) (92 )
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions from unconsolidated affiliates —
65
—
(8 ) 57
Equity in (earnings)/losses of unconsolidated affiliates (5 ) (20 ) 2
10
(13 )
Depreciation and amortization 372
435
19
—
826
Provision for bad debts 31
5
—
—
36
Amortization of nuclear fuel 39
—
—
—
39
Amortization of financing costs and debt discount/premiums —
25
17
—
42
Adjustment for debt extinguishment —
102
17
—
119
Amortization of intangibles and out-of-market contracts 32
99
—
—
131
Amortization of unearned equity compensation —
—
23
—
23
Impairment losses 8
203
—
—
211
Changes in deferred income taxes and liability for uncertain tax benefits (134 ) (90 ) 253
—
29
Changes in nuclear decommissioning trust liability 24
—
—
—
24
Changes in derivative instruments (173 ) 206
(3 ) —
30
Changes in collateral posted supporting energy risk management activities 268
(7 ) —
—
261
Proceeds from sale of emission allowances 11
—
—
—
11
Loss on sale of assets —
—
70
—
70
Cash (used)/provided by changes in other working capital (827 ) 168
(200 ) 729
(130 )
Net cash provided by continuing operations 201
1,000

473

—
1,674
Cash provided by discontinued operations —
67
—
—
67
Net Cash Provided by Operating Activities 201
1,067
473
—
1,741
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc. —
—
59
(59 ) —
Acquisition of September 2016 Drop Down assets, net of cash acquired —
(77 ) —
77
—
Intercompany dividends —
—
12
(12 ) —
Acquisition of businesses, net of cash acquired —
(18 ) —
—
(18 )
Capital expenditures (145 ) (474 ) (40 ) —
(659 )
Increase in notes receivable —
2
—
—
2
Purchases of emission allowances (32 ) —
—
—
(32 )
Proceeds from sale of emission allowances 47
—
—
—
47
Investments in nuclear decommissioning trust fund securities (378 ) —
—
—
(378 )
Proceeds from sales of nuclear decommissioning trust fund securities 354
—
—
—
354
Proceeds from renewable energy grants and state rebates —
11
—
—
11
Proceeds from sale of assets, net of cash disposed of —
67
17
—
84
Investments in unconsolidated affiliates 2
(25 ) —
—
(23 )
Other 27
(4 ) 8
—
31
Net cash (used)/provided by continuing operations (125 ) (518 ) 56

6
(581 )
Cash provided by discontinued operations —
326
—
—
326
Net Cash (Used)/Provided by Investing Activities (125 ) (192 ) 56
6
(255 )
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc. —
(59 ) —
59
—
Payments (for)/from intercompany loans (2 ) (134 ) 136
—
—
Acquisition of September 2016 Drop Down assets, net of cash acquired —
—
77
(77 ) —
Intercompany dividends (52 ) 40
—
12
—
Payment of dividends to common and preferred stockholders —
—
(66 ) —
(66 )
Payment for preferred shares —
—
(226 ) —
(226 )
Net receipts for settlement of acquired derivatives that include financing elements —
6
—
—
6
Proceeds from issuance of long-term debt —
1,097
4,140
—
5,237
Payments for short and long-term debt (2 ) (811 ) (4,540 ) —
(5,353 )
Payments for debt extinguishment costs —
(98 ) —
—
(98 )
Distributions from, net of contributions to, noncontrolling interest in subsidiaries —
(127 ) —
—
(127 )
Proceeds from issuance of common stock —
—
1
—
1
Payment of debt issuance costs —
(17 ) (53 ) —
(70 )
Other (3 ) (7 ) —
—
(10 )
Net cash used by continuing operations (59 ) (110 ) (531 ) (6 ) (706 )
Cash provided by discontinued operations —
119
—
—
119
Net Cash (Used)/Provided by Financing Activities (59 ) 9
(531 ) (6 ) (587 )
Change in cash from discontinued operations —
512
—
—
512
Effect of exchange rate changes on cash and cash equivalents —
(6 ) —
—
(6 )
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties 17
366
(2 ) —
381
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at Beginning of Period —
629
693
—
1,322
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by Counterparties at End of Period $ 17
$ 995
$ 691
$ —
$ 1,703



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Cash Flows from Operating Activities
Net income	$	543		$	32		$	446		$	(692	)	$	329
Loss from discontinued operations	—			—			(25		)	—			(25		)
Net income from continuing operations	543			32			471			(692		)	354
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Distributions from unconsolidated affiliates	—			50			—			(7		)	43
Equity in (earnings)/losses of unconsolidated affiliates	—			(17		)	1			—			(16		)
Depreciation, amortization and accretion	162			307			16			—			485
Provision for bad debts	31			—			—			—			31
Amortization of nuclear fuel	24			—			—			—			24
Amortization of financing costs and debt discount/premiums	—			18			9			—			27
Adjustment for debt extinguishment	—			—			3			—			3
Amortization of intangibles and out-of-market contracts	9			39			—			—			48
Amortization of unearned equity compensation	—			—			26			—			26
Impairment losses	—			89			—			—			89
Changes in deferred income taxes and liability for uncertain tax benefits	221			(41		)	(176		)	—			4
Changes in nuclear decommissioning trust liability	41			—			—			—			41
Changes in derivative instruments	(154		)	(43		)	8			(22		)	(211		)
Changes in collateral deposits in support of energy risk management activities	(4		)	(14		)	—			—			(18		)
Gain on sale of emission allowances	(11		)	—			—			—			(11		)
Gain on sale of assets	(3		)	(13		)	—			—			(16		)
Loss on deconsolidation of business	—			22			—			—			22
Changes in other working capital	(298		)	41			(865		)	721			(401		)
Net Cash Provided/(Used) by Operating Activities	561			470			(507		)	—			524
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			52			(52		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(126		)	—			126			—
Acquisition of business, net of cash acquired	(2		)	(282		)	—			—			(284		)
Capital expenditures	(105		)	(556		)	(30		)	—			(691		)
Decrease in notes receivable	—			4			—			—			4
Purchases of emission allowances	(22		)	—			—			—			(22		)
Proceeds from sale of emission allowances	34			—			—			—			34
Investments in nuclear decommissioning trust fund securities	(346		)	—			—			—			(346		)
Proceeds from the sale of nuclear decommissioning trust fund securities	303			—			—			—			303
Proceeds from sale of assets, net of cash disposed of	10			8			—			—			18
Deconsolidation of business	—			(160		)	—			—			(160		)
Change in investments in unconsolidated affiliates	—			(2		)	—			—			(2		)
Net Cash (Used)/Provided by Investing Activities	(128		)	(1,114		)	22			74			(1,146		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(52		)	—			52			—
Payment (for)/from intercompany loans	(323		)	108			215			—			—
Acquisition of Drop Down Assets, net of cash acquired	—			—			126			(126		)	—
Payment of dividends to common and preferred stockholders	—			—			(19		)	—			(19		)
Payment for treasury stock	—			—			(500		)	—			(500		)
Proceeds from issuance of long-term debt	—			774			831			—			1,605
Payments for short and long-term debt	—			(564		)	(284		)	—			(848		)
Contributions from, net of distributions to noncontrolling interests in subsidiaries	—			222			—			—			222
Payment of debt issuance costs	—			(24		)	(13		)	—			(37		)
Net Cash (Used)/Provided by Financing Activities	(323		)	464			356			(74		)	423
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	110			(180		)	(129		)	—			(199		)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	41			852			643			—			1,536
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	151		$	672		$	514		$	—		$	1,337


(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, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	2,060		$	664		$	—		$	(23	)	$	2,701
Operating Costs and Expenses
Cost of operations	1,530			312			20			(21		)	1,841
Depreciation and amortization	99			153			8			—			260
Impairment losses	42			21			—			—			63
Selling, general and administrative	96			29			97			(1		)	221
Development costs	—			13			5			—			18
Total operating costs and expenses	1,767			528			130			(22		)	2,403
Other income - affiliate	—			—			39			—			39
Gain on sale of assets	2			—			—			—			2
Operating Income/(Loss)	295			136			(91		)	(1		)	339
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	8			—			(149		)	141			—
Equity in losses of unconsolidated affiliates	—			(2		)	(1		)	—			(3		)
Other income, net	—			41			7			(34		)	14
Interest expense	(4		)	(121		)	(122		)	—			(247		)
Total other income/(expense)	4			(82		)	(265		)	107			(236		)
Income/(Loss) from Continuing Operations Before Income Taxes	299			54			(356		)	106			103
Income tax expense/(benefit)	113			267			(376		)	—			4
Income/(Loss) from Continuing Operations	186			(213		)	20			106			99
Loss from discontinued operations, net of income tax	—			(123		)	(618		)	—			(741		)
Net Income/(Loss)	186			(336		)	(598		)	106			(642		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(9		)	28			(35		)	(16		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	186		$	(327	)	$	(626	)	$	141		$	(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	$	3,878		$	1,241		$	—		$	(36	)	$	5,083
Operating Costs and Expenses
Cost of operations	3,050			651			39			(36		)	3,704
Depreciation and amortization	198			303			16			—			517
Impairment losses	42			21			—			—			63
Selling, general and administrative	205			64			213			(1		)	481
Development costs	—			25			10			—			35
Total operating costs and expenses	3,495			1,064			278			(37		)	4,800
Other income - affiliate	—			—			87			—			87
Gain on sale of assets	4			—			—			—			4
Operating Income/(Loss)	387			177			(191		)	1			374
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	13			—			(100		)	87			—
Equity in earnings/(losses) of unconsolidated affiliates	—			4			(2		)	—			2
Other income, net	1			47			13			(35		)	26
Loss on debt extinguishment, net	—			(2		)	—			—			(2		)
Interest expense	(7		)	(225		)	(239		)	—			(471		)
Total other income/(expense)	7			(176		)	(328		)	52			(445		)
Income/(Loss) from Continuing Operations Before Income Taxes	394			1			(519		)	53			(71		)
Income tax expense/(benefit)	131			237			(369		)	—			(1		)
Income/(Loss) from Continuing Operations	263			(236		)	(150		)	53			(70		)
Loss from discontinued operations, net of income tax	—			(160		)	(615		)	—			(775		)
Net Income/(Loss)	263			(396		)	(765		)	53			(845		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(46		)	25			(34		)	(55		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	263		$	(350	)	$	(790	)	$	87		$	(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)	$	186	$	(336	)	$	(598	)	$	106		$	(642	)
Other Comprehensive Income, 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	—		23			25			(24		)	24
Comprehensive Income/(Loss)	186		(313		)	(573		)	82			(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.	$	186	$	(303	)	$	(601	)	$	117		$	(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)	$	263	$	(396	)	$	(765	)	$	53		$	(845	)
Other Comprehensive Income, net of tax
Unrealized loss 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)	268		(363		)	(730		)	15			(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.	$	268	$	(316	)	$	(755	)	$	49		$	(754	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2017



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	—	$	348		$	643		$	—		$	991
Funds deposited by counterparties	37		—			—			—			37
Restricted cash	4		504			—			—			508
Accounts receivable, net	912		163			4			—			1,079
Inventory	338		194			—			—			532
Derivative instruments	646		29			9			(58		)	626
Cash collateral paid in support of energy risk management activities	170		1			—			—			171
Accounts receivable - affiliate	685		133			(129		)	(594		)	95
Current assets held-for-sale	8		107			—			—			115
Prepayments and other current assets	122		112			27			—			261
Total current assets	2,922		1,591			554			(652		)	4,415
Property, plant and equipment, net	2,507		11,188			238			(25		)	13,908
Other Assets
Investment in subsidiaries	266		—			7,581			(7,847		)	—
Equity investments in affiliates	—		1,036			2			—			1,038
Note receivable, less current portion	—		2			38			(38		)	2
Goodwill	360		179			—			—			539
Intangible assets, net	454		1,295			—			(3		)	1,746
Nuclear decommissioning trust fund	692		—			—			—			692
Derivative instruments	126		15			31			—			172
Deferred income taxes	377		(7		)	(236		)	—			134
Non-current assets held for sale	—		43			—			—			43
Other non-current assets	50		459			120			—			629
Total other assets	2,325		3,022			7,536			(7,888		)	4,995
Total Assets	$	7,754	$	15,801		$	8,328		$	(8,565	)	$	23,318
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	667		$	59		$	(38	)	$	688
Accounts payable	610		216			55			—			881
Accounts payable — affiliate	742		(297		)	181			(593		)	33
Derivative instruments	556		57			—			(58		)	555
Cash collateral received in support of energy risk management activities	37		—			—			—			37
Current liabilities held-for-sale	—		72			—			—			72
Accrued expenses and other current liabilities	303		162			425			—			890
Accrued expenses and other current liabilities - affiliate	—		—			161			—			161
Total current liabilities	2,248		877			881			(689		)	3,317
Other Liabilities
Long-term debt and capital leases	244		8,733			6,739			—			15,716
Nuclear decommissioning reserve	269		—			—			—			269
Nuclear decommissioning trust liability	415		—			—			—			415
Deferred income taxes	112		64			(155		)	—			21
Derivative instruments	136		61			—			—			197
Out-of-market contracts, net	66		141			—			—			207
Non-current liabilities held-for-sale	—		8			—			—			8
Other non-current liabilities	410		321			391			—			1,122
Total non-current liabilities	1,652		9,328			6,975			—			17,955
Total Liabilities	3,900		10,205			7,856			(689		)	21,272
Redeemable noncontrolling interest in subsidiaries	—		78			—			—			78
Stockholders’ Equity	3,854		5,518			472			(7,876		)	1,968
Total Liabilities and Stockholders’ Equity	$	7,754	$	15,801		$	8,328		$	(8,565	)	$	23,318


(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)	$	263		$	(396	)	$	(765	)	$	53		$	(845	)
Loss from discontinued operations	—			(160		)	(615		)	—			(775		)
Net income/(loss) from continuing operations	263			(236		)	(150		)	53			(70		)
Adjustments to reconcile net income/(loss) to net cash provided/(used) by operating activities:
Distributions from unconsolidated affiliates	—			32			—			(4		)	28
Equity in (earnings)/losses of unconsolidated affiliates	—			(4		)	2			—			(2		)
Depreciation, amortization and accretion	198			303			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 in support of energy risk management activities	(203		)	11			3			—			(189		)
Proceeds from sale of emission allowances	11			—			—			—			11
Gain on sale of assets	(22		)	—			—			—			(22		)
Changes in other working capital	(329		)	(539		)	538			(49		)	(379		)
Net cash provided/(used) by continuing operations	158			(127		)	81			—			112
Cash used by discontinued operations	—			(38		)	—			—			(38		)
Net Cash Provided/(Used) by Operating Activities	158			(165		)	81			—			74
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			45			(45		)	—
Intercompany dividends	—			—			129			(129		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(131		)	—			131			—
Acquisition of businesses, 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 the sale 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
Change in investments in unconsolidated affiliates	—			(30		)	—			—			(30		)
Other	18			—			—			—			18
Net 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	—			(129		)	—			129			—
Acquisition of Drop Down Assets, net of cash acquired	—			—			131			(131		)	—
Intercompany dividends	(122		)	369			(247		)	—			—
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		)
Increase in notes receivable from affiliate	—			(125		)	—			—			(125		)
Distributions to, net of contributions from, noncontrolling interests in subsidiaries	—			14			—			—			14
Payments of debt issuance costs	—			(32		)	(4		)	—			(36		)
Other - contingent consideration	—			(10		)	—			—			(10		)
Net 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
Effect of exchange rate changes on cash and cash equivalents	—			(8		)	—			—			(8		)
Change in cash from discontinued operations	—			(315		)	—			—			(315		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	34			(271		)	91			—			(146		)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	13			1,050			323			—			1,386
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	47		$	779		$	414		$	—		$	1,240


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

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017. Also refer to NRG's ~~2016~~2017 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

owns and operates approximately 30,000 MW of generation;

engages in the trading of wholesale energy, capacity and related products; and

transacts in and trades fuel and transportation services.

NRG was incorporated as a Delaware corporation on May 29, 1992.

The following table summarizes NRG's global generation portfolio as of ~~September~~June 30, ~~2017,~~2018, by operating segment:


	Global Generation Portfolio^(a)(b)									Global Generation Portfolio^(a)
	(In MW)									(In MW)
	Generation									Generation
Generation Type	Gulf Coast	East/West ^(c)	Renewables^(d)		NRG Yield^(e)		Other^(f)	Total Global		Gulf Coast^(f)(i)	East/West^(b)	Renewables^(c)(g)(j)(k)		NRG Yield^(d)(j)		Other^(e)(j)	Total Global
Natural gas^(g)(f)	7,464	4,939	—		1,878		—	14,281		7,464	4,878	—		1,888		—	14,230
Coal	5,114	3,869	—		—		—	8,983		5,114	3,871	—		—		—	8,985
Oil	—	3,642	—		190		—	3,832		—	3,641	—		190		—	3,831
Nuclear	1,136	—	—		—		—	1,136		1,136	—	—		—		—	1,136
Wind(g)	—	—	743		2,206		—	2,949		—	—	739		2,200		—	2,939
Utility Scale Solar	—	—	742		921		—	1,663		—	—	342		921		—	1,263
Distributed Solar	—	—	175		14		114	303		—	—	189		52		114	355
Total generation capacity^(g)(h)	13,714	12,450	1,660		5,209		114	33,147		13,714	12,390	1,270		5,251		114	32,739
Capacity attributable to noncontrolling interest^(h)	—	—	(684	)	(2,342	)	—	(3,026	)	—	—	(580	)	(2,358	)	—	(2,938	)
Total net generation capacity	13,714	12,450	976		2,867		114	30,121		13,714	12,390	690		2,893		114	29,801

(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.


(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,~~Includes International and BETM.


(c)	Includes Distributed Solar capacity from assets held by DGPV Holdco 1, DGPV Holdco 2, and DGPV Holdco 3.


(d)	Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which ~~represented 16,423~~is part of the NRG Yield operating segment.


(e)	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.


(f)	Natural gas generation does not include 371 MW ~~of global generation at December 31, 2016,~~related to Greens Bayou 5 which was ~~deconsolidated from NRG on June 14, 2017.~~retired in January 2018.

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

~~(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.


(g)	During the first quarter of 2018, NRG sold 10 MW to third parties related to the Minnesota wind assets.


(h)	NRG Yield's total generation capacity includes 6 ~~MWs~~MW for noncontrolling interest for Spring Canyon II and III. NRG Yield's total generation capacity net of this noncontrolling interest was ~~5,203 MWs.~~5,247 MW.


(i)	Includes the South Central business, which owns and operates a 3,555 MW portfolio of generation assets in Gulf Coast, and which the Company expects to sell as announced on February 6, 2018. NRG will lease back the 1,263 MW Cottonwood facility.


(j)	Includes net MW for NRG Yield, Inc. of 2,893 MW and the Renewables operating and development platform of 467 MW, which the Company expects to sell as announced on February 6, 2018.

~~GenOn~~

~~On June 14, 2017, GenOn, GenOn Americas Generation and certain~~(k) Does not include net MW for Ivanpah 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~~196 MW due to deconsolidation in the ~~United States Bankruptcy Court for the Southern District~~second quarter 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.2018.

Strategy

NRG's strategy is to maximize stockholder value through the safe production and sale of reliable power to its customers in the markets served by the Company, while positioning the Company to provide fully integrated solutions to the end-use energy consumer. This strategy is intended to enable the Company to create and maintain growth at reasonable margins while de-risking the Company in terms of reduced and mitigated exposure to cyclical commodity price risk. At the same time, the Company's relentless commitment to safety for its employees, customers and partners continues unabated.

To effectuate the Company’s strategy, NRG is focused on: (i) excellence in operating performance of its existing assets including repowering its power generation assets at premium sites and optimal hedging of generation assets and retail load operations; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) deploying innovative and renewable energy solutions for consumers within its retail businesses; and (iv) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management, including reducing consolidated debt and pursuing selective acquisitions, joint ventures, divestitures and investments.

Transformation Plan

~~On July 12, 2017,~~ NRG ~~announced~~is in the process of executing its Transformation Plan, which is designed to significantly strengthen earnings and cost competitiveness, lower risk and volatility, and create significant shareholder value. The Company expects to fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018. The three-part, three-year plan is comprised of the following ~~targets:~~targets, and the Company's achievements towards such targets are as follows:

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

Portfolio optimization — Targeting up to ~~$4.0~~$3.2 billion of asset sale ~~net~~ cash proceeds, including divestitures of 6 ~~GWs~~GW of conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG Yield, Inc. and its renewables platform.

In 2017, NRG executed asset sales of 322 MW for aggregate cash of $150 million, which includes sales to NRG Yield, Inc. and the sale of Minnesota wind projects to third parties.

On February 6, 2018, NRG announced agreements to sell (i) NRG's full ownership interest in NRG Yield, Inc. and NRG's renewables platform, a 3,440 MW portfolio, for cash of $1.375 billion, subject to certain adjustments; and (ii) NRG's South Central business, a 3,555 MW portfolio of generation assets, for cash of $1.0 billion, subject to certain adjustments. The transactions are subject to certain closing conditions and are expected to close in the second half of 2018.

On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of the membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, a 527-MW natural gas-fired project in Carlsbad, CA, pursuant to the ROFO Agreement. The purchase price for the transaction is $365 million in cash consideration, subject to customary working capital and other adjustments.

On March 30, 2018, the Company completed the sale of 100% of its ownership interest in Buckthorn Solar to NRG Yield, Inc. for cash consideration of approximately $42 million.

During the first half of 2018, the Company completed the sale of various other assets for approximately $7 million.

On June 19, 2018, the Company completed the sale of the substantially completed assets of the UPMC Thermal Project to NRG Yield, Inc. for cash consideration of $84 million, subject to working capital adjustments.

On August 1, 2018, the Company completed the sale of 100% of its ownership interests in BETM to a third party for $70 million, subject to working capital adjustments. The sale also resulted in the release and return of approximately $119 million of letters of credit, $30 million of parent guarantees, and $4 million of net cash collateral to NRG.

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 achievingachieve its targeted 3.0x net debt / Adjusted EBITDA ~~corporate~~ credit ratio.

Expected reduction in non-recourse debt related to the sale of NRG's ownership in NRG Yield, Inc. and the NRG renewables platform and the sales of Carlsbad Energy Center and Buckthorn Solar.

Year to date open market repurchases of $93 million, representing principal reduction of Senior Notes of $89 million.

~~The Company expects~~Working Capital and Costs to ~~fully implement the Transformation Plan by the end of 2020 with significant completion by the end of 2018.~~ Achieve —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.

Since the inception of the Transformation Plan, NRG has realized $298 million of non-recurring working capital improvements and $113 million of one-time costs to achieve.

Regulatory Matters

The Company’s regulatory matters are described in the Company’s ~~2016~~2017 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~~Federal Energy Regulation

~~Minimum Offer Price~~Department of Energy's Proposed Grid Resiliency Pricing Rule ~~Exemption Appeal~~and Subsequent FERC Proceeding — —On ~~July 7,~~September 29, 2017, the ~~D.C. Circuit vacated~~Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC ~~order from 2013 related~~ to ~~an exemption~~take action to reform the ~~Minimum Offer Price Rule, or MOPR,~~ISO/RTO markets to value certain reliability and ~~remanded the issue back~~resiliency attributes of electric generation resources. On October 2, 2017, FERC issued a notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to ~~FERC.~~address. On October 23, 2017, ~~PJM re-filed its initial 2012 MOPR. FERC's ruling~~NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner compatible with robust competitive markets. On January 8, 2018, FERC terminated the proposed rulemaking and opened a new proceeding asking each ISO/RTO to address specific questions focused on ~~PJM's renewed proposal could affect how generators participate~~grid resilience. On March 9, 2018, the ISOs/RTOs filed comments to the questions posed by FERC. The Company responded on May 9, 2018 and is currently awaiting a decision from FERC.

State Energy Regulation

State Out-Of-Market Subsidy Proposals — On April 12, 2018, the New Jersey State Legislature passed a bill to provide out-of-market subsidies to the state’s nuclear plants. The bill has not yet been signed by the New Jersey Governor. In addition, Certain other states in the ~~PJM Base Residual Auction.~~areas of the country in which NRG operates, including 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 efforts to provide out-of-market subsidies, and intends to continue opposing them in the future.

~~2020/2021~~Regional Regulatory Developments

NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 16, Regulatory Matters, to the Consolidated Financial Statements.

Gulf Coast

MISO

Revisions to MISO Capacity Construct — On February 28, 2018, FERC issued two orders on MISO’s capacity market design, which together, re-affirm MISO’s existing capacity market structure. FERC also held that, even though there was a period of time between where MISO’s capacity market structure may not have just and reasonable, FERC exercised its remedial authority not to rerun past auctions. On March 30, 2018, the Company filed a motion for rehearing with FERC. The eventual outcome of this proceeding will affect capacity prices in MISO and the incentive for generators in MISO to sell capacity into neighboring markets.

East/West

PJM

2021/2022 PJM Auction Results — On May 23, ~~2017,~~2018, PJM announced the results of its ~~2020/2021~~2021/2022 base residual auction. NRG, excluding GenOn, cleared approximately ~~3,992~~4,740 MW of Capacity Performance product. NRG’s expected capacity revenues, excluding GenOn, from the base residual auction for the ~~2020/2021~~2021/2022 delivery year are approximately ~~$268~~$328 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~~2021/2022 base residual auction ~~result:~~results from May 23, 2018:


	Capacity Performance Product		Capacity Performance Product
Zone	Cleared Capacity (MW)^(a)	Price ($/MW-day)	Cleared Capacity (MW)^(a)	Price ($/MW-day)
COMED	3,315	$188.12	3,995	$	195.55
EMAAC	519	$187.87
DPL			552	$	165.73
MAAC	158	$86.04	121	$	140.00
PEPCO			72	$	140.00
Total	3,992		4,740

~~(a) Includes imports.~~


(a)	Does not include capacity sold by NRG Curtailment Specialists.

Capacity Market Reforms Filing —On April 9, 2018, PJM filed with FERC two capacity market reform proposals in one filing attempting to address market impacts created by out-of-market subsidies.PJM proposed a capacity re-pricing proposal as its preferred option to accommodate state subsidies in the wholesale market. In the alternative, PJM proposes extending its MOPR to existing resources, along with other changes. On June 29, 2018, FERC issued an order rejecting both of the PJM proposals. Instead, FERC found the existing PJM tariff unjust and unreasonable, and initiated a new proceeding to develop a just and reasonable outcome. Among other things, FERC directed PJM to adopt a minimum price rule that would apply to all subsidized resources, including nuclear and renewable resources. Additionally, FERC directed PJM to consider whether to allow state regulators to remove equal amounts of subsidized generation and load from the capacity market. FERC established a briefing schedule and committed to issuing a final order in early 2019 for implementation for next year’s BRA.

PJM Seasonal Capacity Proceeding — On November 17, 2016, PJM proposed to allow winter- and summer-peaking capacity resources to “aggregate” their seasonal capacity into an annual capacity product eligible to participate as Capacity Performance resources. NRG filed comments specifically supporting PJM’s proposal to modify the aggregation rules to allow seasonal capacity resources to aggregate across LDAs and to allow aggregations through RPM auctions, but opposing the move to seasonal capacity. On January 23, 2017, PJM amended its proposal to address questions from FERC. On March 21, 2017, FERC issued a decision accepting PJM's seasonal capacity aggregation filing pursuant to FERC staff's delegated authority, since FERC did not have a quorum at the time. On February 23, 2018, FERC re-affirmed its prior order. On February 23, 2018, FERC accepted PJM's filing and dismissed the requests for clarification. The outcome of this proceeding could have a material impact on future PJM capacity prices.

Complaints Related to Extension of Base Capacity — In 2015, FERC approved changes to PJM’s capacity market, which included moving from the Base Capacity product to the higher performance Capacity Performance product over the course of a five year transition. Under this transition, as of the May 2017 BRA, the Base Capacity product will no longer be available. Several parties have filed complaints at FERC seeking to maintain the RPM Base Capacity product for at least one more delivery year or until such time as PJM develops a model for seasonal resources to participate. On February 23, 2018, FERC issued an Order scheduling a technical conference and established a refund effective date of December 23, 2016 and January 5, 2017 for the complaints. Multiple parties filed for rehearing. FERC held a technical conference on April 24, 2018 and received post-technical conference comments on July 13, 2018. The outcome of this proceeding could have a material impact on future PJM capacity prices.

New England

~~2020/2021~~ ISO-NE ~~Auction Results~~Retention of Mystic Units — ~~— On February 6, 2017,~~ISO-NE recently announced that it had denied delist bids submitted by two of the three Mystic generating units attached to the DistriGas LNG terminal outside of Boston, citing local reliability concerns. Subsequently, ISO-NE announced its intent to retain the ~~results~~Mystic units in future auctions through an out-of-market payment, citing “fuel security” concerns. On May 1, 2018, ISO-NE filed with FERC to allow it to retain the Mystic units. On July 2, 2018, FERC issued an order denying ISO-NE's request for a waiver and initiated a new proceeding to examine whether ISO-NE's capacity market rules were just and reasonable. Among other things, FERC found that ISO-NE should file a short-term fuel security agreement as part of its ~~2020/2021 forward~~tariff and then redesign its capacity ~~auction. NRG cleared 2,641 MW at $5.297 KW per month providing expected annual~~market to allow units retained for fuel security to set price in the capacity ~~revenues~~market. Additional briefing is due 90 days after issuance 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 $7.03 KW per month for the 2020/2021 deliverability year, are excluded from these results.~~order.

~~Peak Energy Rent Adjustment Complaint~~Competitive Auctions with Sponsored Resources Proposal (CASPR) — 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 8, 2018, ISO-NE filed the CASPR proposal which attempts to accommodate state sponsored resources while maintaining competitive market pricing. On January 29, 2018, NRG protested certain aspects of the proposal and also supported ISO-NE’s beginning attempts to address state sponsored resources entering the capacity market. On March 9, ~~2017,~~2018, FERC ~~granted NEPGA’s complaint requiring~~accepted ISO-NE's proposal. On April 9, 2018, NRG joined another generator in filing a ~~change to the methodology used to calculate the PER strike price. FERC also directed the parties to determine any refunds~~request for ~~PER paid between September 30, 2016 and May 31, 2018. On July 26, 2017, NEPGA filed settlement documents at FERC, which NRG supported.~~rehearing. The ~~settlement~~rehearing is pending at FERC. The outcome of this ~~matter~~proceeding will ~~determine~~potentially affect future capacity market prices.

Renewable Technology Resource (RTR) Exemption —In 2014, FERC approved a package of revisions that included a renewables exemption called the ~~amount~~RTR Exemption. After FERC denied rehearing, the case was appealed to the D.C. Circuit. After a voluntary remand motion, the Court remanded the case back to FERC. In 2016, FERC issued an order reaffirming its decision. In 2017, a group of ~~refunds that~~generators, including NRG, filed a petition for review with the ~~NRG fleet may receive as~~D.C. Circuit. On July 31, 2018, the Court upheld FERC's decision.

Northern Pass Siting Application — On February 1, 2018, the New Hampshire Site Evaluation Committee denied the application for Northern Pass Transmission to cross the state with a ~~result~~160-mile transmission line from Quebec into southern New Hampshire. The Northern Pass transmission line project had previously been awarded a contract by the State of ~~negotiating~~Massachusetts, which is now in doubt. The addition of 1,000 MW of additional Canadian hydropower associated with Northern Pass would have affected energy and capacity prices. On February 28, 2018, Northern Pass Transmission filed a motion for rehearing. On March 13, 2018, the ~~PER strike price methodology.~~New Hampshire Site Evaluation Committee suspended the request for rehearing pending a written decision on the project's full application.

New York

Independent Power Producers of New York (IPPNY) Complaint — On January 9, 2017, EPSA requested FERC to promptly direct the NYISO to file tariff provisions to address pending market concerns related to out-of-market payments to existing generation in the NYISO. This request was prompted by the ZEC program initiated by the NYSPSC. This request follows IPPNY’s complaint at FERC against the NYISO on May 10, 2013, as amended on March 25, 2014. On April 5, 2018, EPSA filed a motion for renewed request for expedited action on the MOPR. The generators asked FERC to direct the NYISO to require that capacity from existing generation resources that would have exited the market but for out-of-market payments be mitigated. Failure to implement buyer-side mitigation measures could result in uneconomic entry, which artificially decreases capacity prices below competitive market levels.

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~~Docket 12-M-0476 et al.al. Among other things, the Reset Order placed a price cap on energy supply offers and required many retail providers to seek affirmative consent from certain retail customers. Various parties have challenged the NYPSC’s ~~ability~~authority to regulate ~~rates~~prices charged by competitive suppliers in New York state court. On March 29, 2018, the New York State Court of Appeals granted a motion by the Retail Energy Supply Association and National Energy Marketers Association for leave to appeal an earlier adverse Appellate Division ruling. In conjunction with the court challenges, the NYPSC ~~is scheduled to commence~~noticed both an evidentiary ~~proceeding on~~and a collaborative track to address the functioning of the competitive retail ~~markets~~markets. An administrative hearing on ~~November 29, 2017.~~the evidentiary track concluded on December 12, 2017 after 10 days of testimony and is now in the post-hearing brief phase. The outcome of ~~this~~the evidentiary and collaborative ~~process,~~processes, combined with the outcome of the appeal of the ~~Appellate Division order,~~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 October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six ~~months. A hearing~~months, which was granted on ~~the motion was held on October~~November 3, 2017. On May 31, ~~2017, after which~~2018, the CEC ~~took~~extended the ~~matter under submission subject~~suspension period at NRG's request to ~~a written decision~~July 1, 2019. The supplemental extension period should allow sufficient time to ~~be issued at an unspecified later date. If~~determine whether alternate procurement efforts undertaken by SCE supersede the ~~CEC Commissioners accept the recommendation, and formally deny a permit~~need for the Puente Power ~~Project, then the project will not move forward.~~Project.

~~Nuclear Operations~~

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

Environmental Matters

NRG is subject to ~~a wide range of~~numerous 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~~Federal and state environmental 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 specieshistorically 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.~~become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on ~~the~~our operations, ~~of the Company's facilities,~~ which could ~~have a material effect on~~affect the Company's operations. Complying with environmental laws often involves significant capital and operating ~~expenses.~~expenses, as well as occasionally curtailing operations. 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~~that may affect the Company ~~and its facilities have been recently promulgated~~are under review by the EPA, ~~but are being reconsidered,~~ including ~~ESPS/NSPS~~ESPS for GHGs, ash disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. NRG ~~is evaluating~~will evaluate the ~~potential outcomes and any resulting impacts~~impact of ~~recently promulgated~~these regulations ~~that the EPA is now reconsidering and~~as they are revised but cannot fully predict ~~such impacts~~the impact of each until ~~administrative reconsiderations and~~anticipated 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~~2017 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.PM2.5. 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~~air regulations 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.~~economic.

~~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. On October 16, 2017, the EPA proposed a rule to repeal the CPP. Accordingly, the Company believes the CPP is not likely to survive.

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. In 2017, the EPA agreed to reconsider the rule. On ~~September 13,~~July 30, 2018, the EPA promulgated a rule that amends the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. The EPA has stated that it intends to further revise the rule.

Water

Clean Water Act —The Company is required under the CWA to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations have become more stringent and imposed new requirements.

Once Through Cooling Regulation — In August 2014, EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are renewed.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, or FGD, fly ash, bottom ash, and flue gas mercury control. In April 2017, the EPA granted two petitions to reconsider the ~~petition~~rule and also administratively stayed some of the deadlines. On September 18, 2017, the EPA promulgated a final rule that (i) postpones the compliance dates to preserve the status quo for ~~reconsideration that~~FGD wastewater and bottom ash transport water by two years to November 2020 until the ~~Utility Solid Waste Activities Group filed in May 2017.~~EPA completes its next rulemaking and (ii) withdrew the April 2017 administrative stay. The legal challenges have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company has ~~evaluated the impact~~largely eliminated its estimate of the ~~new rule on the Company's consolidated financial position, results of operations, or cash flows and has accrued its~~ environmental ~~and asset retirement obligations under the rule based on current estimates as of September 30, 2017.~~

~~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, hadcapital expenditures that would have been required to ~~enter into contracts setting out~~comply with permits incorporating the ~~obligations of~~revised guidelines. The Company will revisit these estimates after 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, STPNOCrule 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.revised.

Regional Environmental Developments

~~Gulf Coast Region~~

Texas Regional Haze — On October 17, 2017, the EPA promulgated a final rule creating a Texas-only SO₂cap-and-trade program to address regional haze. The program is scheduled to begin on January 1, 2019. Several of the Company's units in Texas will be affected by this rule.

~~East Region~~

~~Massachusetts Global Warming Solutions Act Proposed Regulation~~ - In May 2016, the Massachusetts Supreme Judicial Court held that the Massachusetts DEP had not complied with the 2008 Global Warming Solutions Act, which requires establishing limits for sources of GHGs. The Court held that participation in RGGI was not sufficient. In August 2017, the Massachusetts DEP finalized a regulation that, if it survives legal challenges, would limit GHG emissions, and may limit operations, from electric generating facilities located in Massachusetts. The final regulationrule has been challenged by several environmental groups in ~~The Commonwealth~~the Fifth Circuit of ~~Massachusetts Superior~~the U.S. Court of ~~Suffolk County.~~Appeals, which litigation has been stayed pending resolution of administrative petitions for reconsideration.

Significant Events

The following significant events have occurred during ~~2017,~~2018, 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~~As described above, the Company has continued to execute on its Transformation Plan.

XOOM Energy Acquisition

On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for approximately $219 million in cash, inclusive of approximately $54 million in payments for estimated working capital, which is subject to further adjustment. The ~~three-part, three-year plan is comprised of targets~~acquisition increased NRG's retail portfolio by approximately 300,000 customers in the ~~areas of operational and cost excellence, portfolio optimization, and capital structure and allocation enhancement.~~aggregate by June 30, 2018.

~~GenOn Chapter 11 Bankruptcy Filing~~Ivanpah Deconsolidation

OnDuring the ~~Petition Date,~~second quarter of 2018, the ~~GenOn Entities filed voluntary petitions for relief under Chapter 11~~Company, recognized a loss of ~~the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings and beginning~~$22 million on the ~~Petition Date, NRG no longer consolidates GenOn for financial reporting purposes,~~deconsolidation and subsequent recognition of its 54.6% interest in Ivanpah as an equity method investment, as discussed in more detail in Note 1,9, ~~Basis of Presentation~~Variable Interest Entities, or VIEs~~, Note 3,~~ ~~Discontinued Operations, Dispositions and Acquisitions~~ ~~and Note 14,~~ ~~Related Party Transactionsof this Form 10-Q.~~.

~~Transfers of Assets Under Common Control~~

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

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

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

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

Financing Activities

On March 21, 2018, the Company repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 1.75% and reducing the LIBOR floor to 0.00%. As a result of the repricing, the Company expects approximately $47 million in interest savings over the remaining life of the loan.

On May ~~26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for~~24, 2018, the ~~issuance~~Company issued $575 million in aggregate principal amount at par of ~~up to $407 million of~~2.75% convertible senior ~~secured~~ notes ~~that bear interest at a rate of 4.12%, and mature on October 31, 2038,~~due 2048, as discussed in more detail in Note 8, Debt and Capital Leases.

On June ~~12, 2017, NRG repaid $125~~19, 2018, the Company entered into an amended and restated Thermal note purchase and private shelf agreement whereas it authorized the issuance of the Series E Notes, Series F Notes, Series G Notes, and Series H Notes, as discussed in more detail in Note 8, Debt and Capital Leases.

During the six months ended June 30, 2018, the Company repurchased $43 million onin aggregate principal of its Senior Notes in the ~~Revolving Credit Facility. As~~open market for $45 million, including accrued interest as discussed in more detail in Note 8, Debt and Capital Leases. In July 2018, the Company repurchased an additional $46 million in aggregate principal of ~~September 30, 2017, there were no cash borrowings outstanding on~~its Senior Notes in the ~~revolver.~~open market for $48 million including accrued interest.

On ~~October 16, 2017, NRG redeemed all of~~August 1, 2018, the Company announced that it gave the required notice under the indenture governing its ~~outstanding 7.625%~~6.25% Senior Notes due ~~2018 and all~~2022, or the 2022 Notes, to redeem for cash $486 million aggregate principal amount of its 2022 Notes, or the Partial Redemption, on August 31, 2018, or the Redemption Date. The redemption price for the 2022 Notes will be 103.125% of the principal amount of the 2022 Notes, plus accrued and unpaid interest to the Redemption Date. The Partial Redemption, combined with recently completed open market repurchases of approximately $89 million of the Company's outstanding ~~7.875% Senior Notes due 2021 for $630~~indebtedness, will result in the retirement of outstanding indebtedness equal to approximately $575 million which ~~included $14 million in accrued interest.~~is the aggregate principal amount of the Company's 2.75% convertible senior notes due 2048 issued on May 24, 2018.

~~Operational Matters~~

~~Extreme Weather Events~~Share Repurchases

In ~~late August 2017, Hurricane Harvey made landfall on~~February 2018, the ~~Texas coast.~~Company's board of directors authorized the Company to repurchase $1 billion of its common stock, with the first $500 million program beginning as soon as permitted. In March 2018, the Company repurchased 3,114,748 shares of NRG common stock for approximately $93 million. During the ~~third~~second quarter of ~~2017,~~2018, the ~~Company’s Retail business~~Company repurchased 11,748,553 shares of NRG common stock for approximately $407 million, including shares repurchased under the ASR Agreement. In July 2018, the Company received an additional 860,880 shares in connection with the settlement of the ASR Agreement, completing the $500 million of share repurchases. The average cost per share for the total $500 million of shares repurchased was ~~impacted by Hurricane Harvey by approximately $20 million.~~$31.80.

In addition, during August 2017, NRG's Cottonwood generating station was damaged when the Sabine River Authority opened the floodgates of the Toledo Bend reservoir, which resulted in downstream flooding of the Sabine River. The generating station was returned to service during the fourth quarter of 2017. NRG is continuing to work with insurers on potential property insurance recovery and does not anticipate recovery from business interruption insurance due to the short period of the outage. The Company estimates the impact of the Cottonwood damage and Hurricane Harvey on Gulf Coast Generation to be approximately $20 million.

~~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

~~In addition to below, the~~The Company’s trends are described in the Company’s ~~2016~~2017 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,.and below.

ERCOT ~~Retirements~~Pricing — ~~A number of announced retirement notices of coal generating facilities in Texas could lower reserve margins in ERCOT. This trend of retirement notices could~~ERCOT forward prices for July and August 2018 are significantly higher than where previous summers have ~~an effect~~settled. These elevated pricing levels mean that deviations from expected demand and/or generation availability may have a material impact on the Company’s ~~results of operations and future business performance, particularly in the ERCOT market.~~actual results.

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 September 30,									Nine months ended September 30,									Three months ended June 30,									Six months ended June 30,
(In millions except otherwise noted)	2017			2016			Change			2017			2016			Change			2018			2017			Change			2018			2017			Change
Operating Revenues
Energy revenue^(a)	$	665		$	933		$	(268	)	$	1,908		$	2,478		$	(570	)	$	673		$	656		$	17		$	1,292		$	1,243		$	49
Capacity revenue ^(a)	335			303			32			894			937			(43		)	313			297			16			601			559			42
Retail revenue	1,934			2,015			(81		)	4,880			4,931			(51		)	1,816			1,605			211			3,302			2,946			356
Mark-to-market for economic hedging activities	26			62			(36		)	185			(360		)	545			15			41			(26		)	(91		)	159			(250		)
Contract amortization	(12		)	(12		)	—			(41		)	(41		)	—			(14		)	(14		)	—			(28		)	(29		)	1
Other revenues ^(b)	101			120			(19		)	306			383			(77		)	119			116			3			267			205			62
Total operating revenues	3,049			3,421			(372		)	8,132			8,328			(196		)	2,922			2,701			221			5,343			5,083			260
Operating Costs and Expenses
Cost of sales ^(c)	1,679			1,847			168			4,362			4,526			164			1,515			1,422			(93		)	2,908			2,683			(225		)
Mark-to-market for economic hedging activities	50			149			99			168			(301		)	(469		)	86			(18		)	(104		)	(216		)	118			334
Contract and emissions credit amortization ^(c)	8			11			3			24			34			10			7			8			1			13			16			3
Operations and maintenance	326			354			28			1,038			1,196			158			360			340			(20		)	730			712			(18		)
Other cost of operations	93			79			(14		)	260			256			(4		)	83			89			6			174			175			1
Total cost of operations	2,156			2,440			284			5,852			5,711			141			2,051			1,841			(210		)	3,609			3,704			(95		)
Depreciation and amortization	272			298			26			789			826			37			227			260			33			462			517			55
Impairment losses	14			9			(5		)	77			65			(12		)	74			63			(11		)	74			63			(11		)
Selling, general and administrative	213			277			64			697			801			104			211			221			10			402			481			79
Reorganization	18			—			(18		)	18			—			(18		)
Reorganization costs																			23			—			(23		)	43			—			(43		)
Development costs	14			21			7			49			65			16			16			18			2			29			35			6
Total operating costs and expenses	2,687			3,045			358			7,482			7,468			(14		)	2,602			2,403			(199		)	4,619			4,800			181
Other income - affiliate	14			48			(34		)	104			144			(40		)	—			39			(39		)	—			87			(87		)
Gain/(loss) on sale of assets	—			4			(4		)	4			(79		)	83
Gain on sale of assets																			14			2			12			16			4			12
Operating Income	376			428			(52		)	758			925			(167		)	334			339			(5		)	740			374			366
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	27			16			11			29			13			16
Impairment loss on investment	—			(8		)	8			—			(147		)	147
Other income, net	15			7			8			33			29			4
Equity in earnings/(losses) of unconsolidated affiliates																			18			(3		)	21			16			2			14
Other (losses)/income, net																			(20		)	14			(34		)	(23		)	26			(49		)
Loss on debt extinguishment, net	(1		)	(50		)	49			(3		)	(119		)	116			(1		)	—			(1		)	(3		)	(2		)	(1		)
Interest expense	(221		)	(237		)	16			(692		)	(718		)	26			(202		)	(247		)	45			(369		)	(471		)	102
Total other expense	(180		)	(272		)	92			(633		)	(942		)	309			(205		)	(236		)	31			(379		)	(445		)	66
Income/(Loss) from Continuing Operations before Income Taxes	196			156			40			125			(17		)	142			129			103			26			361			(71		)	432
Income tax expense	6			28			(22		)	5			75			(70		)
Income tax expense/(benefit)																			8			4			4			7			(1		)	8
Income/(Loss) from Continuing Operations	190			128			62			120			(92		)	212			121			99			22			354			(70		)	424
(Loss)/Income from discontinued operations, net of income tax	(27		)	265			(292		)	(802		)	256			(1,058		)
Loss from discontinued operations, net of income tax																			(25		)	(741		)	716			(25		)	(775		)	750
Net Income/(Loss)	163			393			(230		)	(682		)	164			(846		)	96			(642		)	738			329			(845		)	1,174
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest	(8		)	(9		)	1			(63		)	(49		)	(14		)
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest																			24			(16		)	40			(22		)	(55		)	33
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	171		$	402		$	(231	)	$	(619	)	$	213		$	(832	)	$	72		$	(626	)	$	698		$	351		$	(790	)	$	1,141
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	3.00		$	2.81		7		%	$	3.17		$	2.29		38		%	$	2.80		$	3.18		(12		)%	$	2.90		$	3.25		(11		)%

(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 ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended ~~September~~June 30, ~~2017~~2018 and ~~2016.~~2017. The average on-peak power prices ~~have generally~~for ERCOT - Houston and COMED (PJM) decreased primarily due to the ~~increase~~change in ~~natural gas prices~~congestion pattern for the three months ended ~~September~~June 30, ~~2017~~2018, as compared to the same period in ~~2016.~~2017.


	Average on Peak Power Price ($/MWh)						Average on Peak Power Price ($/MWh)
	Three months ended September 30,						Three months ended June 30,
Region	2017		2016		Change %		2018		2017		Change %
Gulf Coast ^(a)
ERCOT - Houston ^(b)	$	33.09	$	33.12	—	%	$	34.82	$	46.03	(24	)%
ERCOT - North^(b)	29.35		30.47		(4	)%	34.89		27.80		26	%
MISO - Louisiana Hub^(c)	39.56		39.83		(1	)%	44.20		42.77		3	%
East/West
NY J/NYC^(c)	37.42		42.50		(12	)%	36.41		39.35		(7	)%
NEPOOL^(c)	31.94		42.33		(25	)%	36.28		33.57		8	%
PEPCO (PJM)^(c)	38.81		42.57		(9	)%
COMED (PJM)^(c)							31.88		33.40		(5	)%
PJM West Hub^(c)	35.10		38.84		(10	)%	39.73		32.79		21	%
CAISO - NP15^(c)	46.69		38.13		22	%	27.37		28.29		(3	)%
CAISO - SP15^(c)	46.54		40.24		16	%	27.75		30.72		(10	)%

(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 ~~September~~June 30, ~~2017~~2018 and ~~2016,~~2017, which reflects the impact of settled hedges.


	Average Realized Power Price ($/MWh)						Average Realized Power Price ($/MWh)
	Three months ended September 30,						Three months ended June 30,
Region	2017		2016		Change %		2018		2017		Change %
Gulf Coast	$	34.69	$	39.68	(13	)%	$	36.33	$	34.68	5	%
East/West(a)	38.19		40.44		(6	)%	35.63		36.67		(3	)%

(a) does not include BETM energy revenue of $15 million and $14 million for 2018 and 2017, respectively.

Though the average on peak power prices have ~~decreased on average by 5%,~~remained relatively flat, average realized prices by region for the Company have generally fluctuated at ~~a slower rate~~different rates 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 ~~September~~June 30, ~~2017~~2018 and ~~2016:~~2017:


	Three months ended September 30, 2017																								Three months ended June 30, 2018
	Generation																											Generation
(In millions)	Gulf Coast			East/West^(a)			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total			Retail			Gulf Coast			East/West^(a)			Subtotal			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	540		$	243		$	783		$	—		$	119		$	146		$	(383	)	$	665		$	—		$	508		$	144		$	652		$	79		$	192		$	(250	)	$	673
Capacity revenue	74			172			246			—			1			92			(4		)	335			—			68			160			228			—			87			(2		)	313
Retail revenue	—			—			—			1,936			—			—			(2		)	1,934			1,817			—			—			—			—			—			(1		)	1,816
Mark-to-market for economic hedging activities	133			—			133			—			5			—			(112		)	26			—			289			(15		)	274			5			—			(264		)	15
Contract amortization	5			—			5			1			(1		)	(18		)	1			(12		)	—			4			—			4			—			(18		)	—			(14		)
Other revenue ^(b)	41			16			57			—			20			44			(20		)	101			—			42			18			60			29			46			(16		)	119
Operating revenue	793			431			1,224			1,937			144			264			(520		)	3,049			1,817			911			307			1,218			113			307			(533		)	2,922
Cost of fuel	(292		)	(123		)	(415		)	(1		)	(1		)	(6		)	17			(406		)	(4		)	(260		)	(70		)	(330		)	—			(9		)	(25		)	(368		)
Other cost of sales^(c)	(102		)	(79		)	(181		)	(1,457		)	(3		)	(9		)	377			(1,273		)	(1,315		)	(81		)	(21		)	(102		)	(2		)	(8		)	280			(1,147		)
Mark-to-market for economic hedging activities	2			10			12			(174		)	—			—			112			(50		)	(346		)	(4		)	—			(4		)	—			—			264			(86		)
Contract and emission credit amortization	(7		)	(1		)	(8		)	—			—			—			—			(8		)	—			(7		)	—			(7		)	—			—			—			(7		)
Gross margin	$	394		$	238		$	632		$	305		$	140		$	249		$	(14	)	$	1,312		$	152		$	559		$	216		$	775		$	111		$	290		$	(14	)	$	1,314
Less: Mark-to-market for economic hedging activities, net	135			10			145			(174		)	5			—			—			(24		)	(346		)	285			(15		)	270			5			—			—			(71		)
Less: Contract and emission credit amortization, net	(2		)	(1		)	(3		)	1			(1		)	(18		)	1			(20		)	—			(3		)	—			(3		)	—			(18		)	—			(21		)
Economic gross margin	$	261		$	229		$	490		$	478		$	136		$	267		$	(15	)	$	1,356		$	498		$	277		$	231		$	508		$	106		$	308		$	(14	)	$	1,406
Business Metrics
MWh sold (thousands)^(d)(e)	15,568			6,363									928			1,544												13,982			3,616						1,211			2,308
MWh generated (thousands)^(f)	14,185			4,106									928			2,261												12,959			2,903						1,211			2,675
(a) Includes International, BETM and Generation eliminations
(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
(b) Renewables other revenue includes $13 million of intercompany revenue to NRG Yield.																									(b) Renewables other revenue includes $13 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits																																																	(d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 9 thousand or MWt of 463 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 44 thousand or MWt of 463 thousand for thermal generated by NRG Yield.
(e) Does not include thermal MWh of 9 thousand or MWt of 462 thousand for thermal sold by NRG Yield.																									(e) Does not include thermal MWh of 9 thousand or MWt of 462 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 28 thousand or MWt of 462 thousand for thermal generated by NRG Yield.																									(f) Does not include thermal MWh of 28 thousand or MWt of 462 thousand for thermal generated by NRG Yield.


	Three months ended September 30, 2016																								Three months ended June 30, 2017
	Generation																											Generation
(In millions)	Gulf Coast			East/West^(a)			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total			Retail			Gulf Coast			East/West^(a)			Subtotal			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	650		$	362		$	1,012		$	—		$	127		$	158		$	(364	)	$	933		$	—		$	484		$	184		$	668		$	105		$	177		$	(294	)	$	656
Capacity revenue	72			148			220			—			—			86			(3		)	303			—			68			144			212			—			85			—			297
Retail revenue	—			—			—			2,009			—			—			6			2,015			1,605			—			—			—			—			—			—			1,605
Mark-to-market for economic hedging activities	179			57			236			2			1			—			(177		)	62			(2		)	(90		)	13			(77		)	(3		)	—			123			41
Contract amortization	4			—			4			1			(1		)	(17		)	1			(12		)	—			3			—			3			—			(17		)	—			(14		)
Other revenue ^(b)	51			13			64			—			12			45			(1		)	120			—			55			21			76			17			43			(20		)	116
Operating revenue	956			580			1,536			2,012			139			272			(538		)	3,421			1,603			520			362			882			119			288			(191		)	2,701
Cost of fuel	(317		)	(190		)	(507		)	(1		)	(2		)	(7		)	18			(499		)	(2		)	(284		)	(82		)	(366		)	(1		)	(7		)	5			(371		)
Other cost of sales^(c)	(114		)	(83		)	(197		)	(1,484		)	(1		)	(11		)	345			(1,348		)	(1,211		)	(79		)	(52		)	(131		)	(2		)	(7		)	300			(1,051		)
Mark-to-market for economic hedging activities	27			7			34			(360		)	—			—			177			(149		)	158			(15		)	(2		)	(17		)	—			—			(123		)	18
Contract and emission credit amortization	(9		)	—			(9		)	(2		)	—			—			—			(11		)	—			(7		)	(1		)	(8		)	—			—						(8		)
Gross margin	$	543		$	314		$	857		$	165		$	136		$	254		$	2		$	1,414		$	548		$	135		$	225		$	360		$	116		$	274		$	(9	)	$	1,289
Less: Mark-to-market for economic hedging activities, net	206			64			270			(358		)	1			—			—			(87		)	156			(105		)	11			(94		)	(3		)	—			—			59
Less: Contract and emission credit amortization, net	(5		)	—			(5		)	(1		)	(1		)	(17		)	1			(23		)	—			(4		)	(1		)	(5		)	—			(17		)	—			(22		)
Economic gross margin	$	342		$	250		$	592		$	524		$	136		$	271		$	1		$	1,524		$	392		$	244		$	215		$	459		$	119		$	291		$	(9	)	$	1,252
Business Metrics
MWh sold (thousands)^(d)(e)	16,380			8,951									977			1,744												13,958			4,598						1,059			2,112
MWh generated (thousands)^(f)	14,927			6,426									977			2,372												13,101			3,079						1,059			2,425
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $5 million of intercompany revenue to NRG Yield.
(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.																									(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits																																																	(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 12 thousand or MWt of 496 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 125 thousand or MWt of 496 thousand for thermal generated by NRG Yield.
(e) Does not include thermal MWh of 9 thousand or MWt of 418 thousand for thermal sold by NRG Yield.																									(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.																									(f) Does not include thermal MWh of 20 thousand or MWt of 418 thousand for thermal generated by NRG Yield.

The table below represents the weather metrics for the three months ended ~~September~~June 30, ~~2017~~2018 and ~~2016:~~2017:


	Three months ended September 30,		Three months ended June 30,
Weather Metrics	Gulf Coast	East/West	Gulf Coast	East/West
2017
2018
CDDs ^(a)	1,528	770	1,067	265
HDDs ^(a)	1	34	108	425
2016
2017
CDDs	1,655	806	921	281
HDDs	—	23	41	380
10 year average
10-year average
CDDs	1,617	705	970	259
HDDs	6	40	67	429

(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.

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)	2018			2017
Retail revenue	$	1,689		$	1,515
Supply management revenue	42			52
Capacity revenue	86			38
Customer mark-to-market	—			(2		)
Operating revenue^(a)	1,817			1,603
Cost of sales ^(b)	(1,319		)	(1,213		)
Mark-to-market for economic hedging activities	(346		)	158
Gross Margin	$	152		$	548
Less: Mark-to-market for economic hedging activities, net	(346		)	156
Economic Gross Margin	$	498		$	392

Business Metrics
Mass electricity sales volume — GWh - Gulf Coast	9,802			9,234
Mass electricity sales volume — GWh - All other regions	1,592			1,357
C&I electricity sales volume — GWh - All regions	5,403			5,308
Natural gas sales volumes (MDth)	1,244			438
Average Retail Mass customer count (in thousands)	2,973			2,859
Ending Retail Mass customer count (in thousands) ^(c)	3,173			2,887


(a)	Includes intercompany sales of $1 million and $1 million in 2018 and 2017, respectively, representing sales from Retail to the Gulf Coast region.


(b)	Includes intercompany purchases of $251 million and $293 million in 2018 and 2017, respectively.


(c)	The acquisition of XOOM Energy, LLC increased NRG's retail portfolio by approximately 300,000 customers in the aggregate by June 30, 2018.

Retail gross margin decreased $396 million and economic gross margin increased $106 million for the three months ended June 30, 2018, compared to the same period in 2017, due to:



	(In millions)
Higher gross margin due to higher revenue of $63 million or approximately $3.25 per MWh, driven by customer product, term and mix, offset by higher supply costs of $25 million or approximately $1.25 per MWh, driven by an increase in power prices	$	38
Higher gross margin from the Business Solutions unit reflecting the early settlement of capacity obligations for 2018	34
Higher gross margin due to an increase in load of 790,000 MWh driven by warmer weather conditions in 2018 as compared to 2017	27
Higher gross margin due to higher volumes driven by higher average customer counts primarily driven by the XOOM acquisition in June 2018	7
Increase in economic gross margin	$	106
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(502		)
Decrease in gross margin	$	(396	)

Generation gross margin and economic gross margin

Generation gross margin ~~decreased $225~~increased $415 million and economic gross margin ~~decreased $102~~increased $49 million, both of which include intercompany sales, during the three months ended ~~September~~June 30, ~~2017,~~2018, compared to the same period in ~~2016:~~2017.

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

~~Gulf Coast Region~~

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

~~East/West~~

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

~~Retail gross margin and economic gross margin~~

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

Three months ended September 30,
(In millions except otherwise noted) 2017 2016
Retail revenue $ 1,845
$ 1,911
Supply management revenue 63
53
Capacity revenue 28
45
Customer mark-to-market —
2
Contract amortization 1
1
Operating revenue^(a)
1,937
2,012
Cost of sales ^(b)
(1,458 ) (1,485 )
Mark-to-market for economic hedging activities (174 ) (360 )
Contract amortization —
(2 )
Gross Margin $ 305
$ 165
Less: Mark-to-market for economic hedging activities, net (174 ) (358 )
Less: Contract and emission credit amortization, net 1
(1 )
Economic Gross Margin $ 478
$ 524

Business Metrics
Mass electricity sales volume - GWh - Gulf Coast 11,935
11,996
Mass electricity sales volume - GWh - All other regions 1,724
1,986
C&I electricity sales volume — GWh - All regions 5,087
5,146
Natural gas sales volumes (MDth) 241
172
Average Retail Mass customer count (in thousands)
2,884
2,786
Ending Retail Mass customer count (in thousands) 2,880
2,797


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


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

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

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

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

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

Three months ended September 30, 2017
Generation
Gulf Coast East/West Retail Renewables
Eliminations^(a)
Total
(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges $ 121
$ 5
$ —
$ 1
$ (68 ) $ 59
Net unrealized gains/(losses) on open positions related to economic hedges 12
(5 ) —
4
(44 ) (33 )
Total mark-to-market gains/(losses) in operating revenues $ 133
$ —
$ —
$ 5
$ (112 ) $ 26
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges $ (5 ) $ (1 ) $ (127 ) $ —
$ 68
$ (65 )
Reversal of acquired gain positions related to economic hedges —
—
(2 ) —
—
(2 )
Net unrealized gains/(losses) on open positions related to economic hedges 7
11
(45 ) —
44
17
Total mark-to-market gains/(losses) in operating costs and expenses $ 2
$ 10
$ (174 ) $ —
$ 112
$ (50 )


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

Three months ended September 30, 2016
Generation
Gulf Coast East/West Retail Renewables
Eliminations^(a)
Total
(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges $ 8
$ (1 ) $ —
$ —
$ (77 ) $ (70 )
Net unrealized gains/(losses) on open positions related to economic hedges 171
58
2
1
(100 ) 132
Total mark-to-market gains/(losses) in operating revenues $ 179
$ 57
$ 2
$ 1
$ (177 ) $ 62
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges $ 7
$ 2
$ (46 ) $ —
$ 77
$ 40
Reversal of acquired gain positions related to economic hedges —
(5 ) (2 ) —
—
(7 )
Net unrealized gains/(losses) on open positions related to economic hedges 20
10
(312 ) —
100
(182 )
Total mark-to-market gains/(losses) in operating costs and expenses $ 27
$ 7
$ (360 ) $ —
$ 177
$ (149 )


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

Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.

~~The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.~~

For the three months ended September 30, 2017, the $26 million gain in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, partially offset by a decrease in value of open positions as a result of an increase in natural gas prices. The $50 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in value of open positions as a result of an increase in coal prices.

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

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 30, 2017 and 2016. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.

Three months ended September 30,
(In millions) 2017 2016
Trading (losses)/gains
Realized $ (10 ) $ 20
Unrealized (5 ) (5 )
Total trading (losses)/gains $ (15 ) $ 15

~~Operations and Maintenance Expense~~

Generation Retail Renewables NRG Yield Corporate Eliminations Total
Gulf Coast
East/West^(a)

(In millions)
Three months ended September 30, 2017 $ 120
$ 85
$ 56
$ 28
$ 46
$ 3
$ (12 ) $ 326
Three months ended September 30, 2016 139
97
58
19
41
7
(7 ) 354


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

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

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

~~Selling, General and Administrative~~

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

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

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

~~Reorganization~~

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

~~Loss on Debt Extinguishment~~

A loss on debt extinguishment of $50 million was recorded for the three months ended September 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.

~~Interest Expense~~

~~NRG's interest expense decreased by $16 million for the three months ended September 30, 2017, compared to the same period in 2016 due to the following:~~

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

~~Income Tax Expense~~

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

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

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

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

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

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

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

~~Electricity Prices~~

The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the nine months ended September 30, 2017, and 2016. Average on-peak power prices increased primarily due to the increase in natural gas prices for the nine months ended September 30, 2017 as compared to the same period in 2016.

Average on Peak Power Price ($/MWh)
Nine months ended September 30,
Region 2017
2016 Change %
Gulf Coast ^(a)

ERCOT - Houston ^(b)
$ 35.61
$ 25.97
37 %
ERCOT - North^(b)
26.64
24.14
10 %
MISO - Louisiana Hub^(c)
42.33
33.47
26 %
East/West
    NY J/NYC^(c)
37.46
35.04
7 %
    NEPOOL^(c)
33.11
33.80
(2 )%
    PEPCO (PJM)^(c)
35.65
38.15
(7 )%
    PJM West Hub^(c)
33.30
33.95
(2 )%
CAISO - NP15^(c)
33.82
29.38
15 %
CAISO - SP15^(c)
33.42
30.22
11 %

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

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

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

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

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

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

~~Gross Margin~~

~~Economic Gross Margin~~

~~Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.~~

~~The below tables present the composition and reconciliation of gross margin and economic gross margin for the nine months ended September 30, 2017 and 2016:~~

Nine months ended September 30, 2017
Generation
(In millions) Gulf Coast
East/West^(a)
Subtotal Retail Renewables NRG Yield Corporate/Eliminations Total
Energy revenue $ 1,408
$ 651
$ 2,059
$ —
$ 298
$ 436
$ (885 ) $ 1,908
Capacity revenue 207
438
645
—
1
256
(8 ) 894
Retail revenue —
—
—
4,875
—
—
5
4,880
Mark-to-market for economic hedging activities 174
4
178
—
8
—
(1 ) 185
Contract amortization 11
—
11
—
(1 ) (52 ) 1
(41 )
Other revenue ^(b)
143
36
179
—
58
127
(58 ) 306
Operating revenue 1,943
1,129
3,072
4,875
364
767
(946 ) 8,132
Cost of fuel (790 ) (293 ) (1,083 ) (8 ) (3 ) (24 ) 48
(1,070 )
Other cost of sales^(c)
(259 ) (203 ) (462 ) (3,661 ) (8 ) (21 ) 860
(3,292 )
Mark-to-market for economic hedging activities (22 ) 7
(15 ) (154 ) —

1
(168 )
Contract and emission credit amortization (21 ) (3 ) (24 ) —
—
—
(24 )
Gross margin $ 851
$ 637
$ 1,488
$ 1,052
$ 353
$ 722
$ (37 ) $ 3,578
Less: Mark-to-market for economic hedging activities, net 152
11
163
(154 ) 8
—
—
17
Less: Contract and emission credit amortization, net (10 ) (3 ) (13 ) —
(1 ) (52 ) 1
(65 )
Economic gross margin $ 709
$ 629
$ 1,338
$ 1,206
$ 346
$ 774
$ (38 ) $ 3,626
Business Metrics
MWh sold (thousands)^(d)(e)
40,908
16,140
2,940
5,295

MWh generated (thousands)^(f)
37,975
10,202
2,940
6,467

(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $21 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 27 thousand or MWt of 1,450 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 80 thousand or MWt of 1,450 thousand for thermal generated by NRG Yield.

Nine months ended September 30, 2016
Generation
(In millions) Gulf Coast
East/West^(a)
Subtotal Retail Renewables NRG Yield Corporate/Eliminations Total
Energy revenue $ 1,598
$ 896
$ 2,494
$ —
$ 303
$ 459
$ (778 ) $ 2,478
Capacity revenue 222
468
690
—
—
256
(9 ) 937
Retail revenue —
—
—
4,918
—
—
13
4,931
Mark-to-market for economic hedging activities (270 ) (9 ) (279 ) —
—
—
(81 ) (360 )
Contract amortization 11
—
11
—
(1 ) (51 ) —
(41 )
Other revenue ^(b)
182
75
257
—
34
125
(33 ) 383
Operating revenue 1,743
1,430
3,173
4,918
336
789
(888 ) 8,328
Cost of fuel (718 ) (371 ) (1,089 ) (5 ) (3 ) (25 ) 114
(1,008 )
Other cost of sales^(c)
(309 ) (245 ) (554 ) (3,628 ) (9 ) (23 ) 696
(3,518 )
Mark-to-market for economic hedging activities 62
8
70
150
—
—
81
301
Contract and emission credit amortization (22 ) (4 ) (26 ) (5 ) —
(6 ) 3
(34 )
Gross margin $ 756
$ 818
$ 1,574
$ 1,430
$ 324
$ 735
$ 6
$ 4,069
Less: Mark-to-market for economic hedging activities, net (208 ) (1 ) (209 ) 150
—
—
—
(59 )
Less: Contract and emission credit amortization, net (11 ) (4 ) (15 ) (5 ) (1 ) (57 ) 3
(75 )
Economic gross margin $ 975
$ 823
$ 1,798
$ 1,285
$ 325
$ 792
$ 3
$ 4,203
Business Metrics
MWh sold (thousands)^(d)(e)
40,433
21,141
2,968
5,563

MWh generated (thousands)^(f)
36,427
13,732
2,968
6,828

(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $13 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 61 thousand or MWt of 1,497 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 248 thousand or MWt of 1,497 thousand for thermal generated by NRG Yield.

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

Nine months ended September 30,
Weather Metrics Gulf Coast East/West
2017
CDDs ^(a)
2,653
1,071

HDDs ^(a)
674
2,041

2016
CDDs 2,605
1,098

HDDs 984
2,046

10 year average
CDDs 2,656
976

HDDs 1,167
2,277

~~(a)~~

~~Generation gross margin and economic gross margin~~

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

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

Gulf Coast Region

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



	(In millions)
Higher gross margin due to a 5% increase in average realized prices in South Central and a 6% increase in average realized prices in Texas	$	45
Higher capacity margins due to an increase in load demand in the South Central business	10
Lower energy margin due to a 14% increase in supply cost on load contracts	(9		)
Lower capacity revenue due to the cancellation of the Greens Bayou RMR agreement in 2017	(6		)
Lower gross margin from commercial optimization activities	(5		)
Other	(2		)
Increase in economic gross margin	$	33
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	391
Increase in gross margin	$	424

East/West

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



	(In millions)
Higher gross margin due to a 80% increase in New England cleared capacity pricing	$	16
Higher gross margin due to a 26% increase in PJM cleared capacity pricing which relates to the first full period of capacity performance product pricing	15
Lower gross margin due to a 29% decrease in capacity pricing in New York of $15 million and decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration in July 2017 of $4 million	(19		)
Lower gross margin due to a 6% decrease in generation volumes due to timing of planned and unplanned outages at Midwest Generation, offset by favorable fuel costs	(8		)
Higher gross margin due to insurance proceeds from outages of $14 million in 2018, compared to business interruption proceeds of $8 million in 2017	6
Other	6
Increase in economic gross margin	$	16
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(26		)
Increase in contract and emission credit amortization	1
Decrease in gross margin	$	(9	)

~~Retail gross margin and economic gross margin~~

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

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

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


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


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


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

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

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

Renewables gross margin and economic gross margin

Renewables gross margin ~~increased $29~~decreased $5 million and economic gross margin ~~increased $21~~decreased $13 million for the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2018, compared to the same period in ~~2016, primarily~~2017. This was driven by ~~new~~the deconsolidation of Ivanpah in May 2018, partially offset by additional distributed ~~generation~~ solar projects ~~placed~~reaching commercial operations in ~~service, increased margin in operations~~late 2017 and ~~maintenance agreements and receipt of insurance proceeds offsetting lower volume at the Ivanpah solar plant.~~early 2018.

NRG Yield gross margin and economic gross margin

NRG Yield gross margin ~~decreased $13~~increased $16 million and economic gross margin ~~decreased by $19~~increased $17 million ~~during~~for the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2018, compared to the same period in ~~2016,~~2017. The increase is due to a ~~4% decrease~~9% increase in volume generated atby wind projects, primarily ~~in connection with lower wind resources at~~ the Alta Wind projects and ~~NRG Wind TE Holdco projects,~~Wildorado from increased wind resources, as well as ~~5% decrease~~a 2% increase in solar generation, primarily at CVSR ~~in connection with lower~~due to higher insolation.

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow ~~hedges and ineffectiveness on cash flow~~ hedges. Total net mark-to-market results ~~increased~~decreased by ~~$76~~$130 million during the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2018, compared to the same period in ~~2016.~~2017.

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, 2018
				Generation
	Retail			Gulf Coast			East/West			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	$	—		$	(52	)	$	(8	)	$	—	$	28		$	(32	)
Net unrealized gains/(losses) on open positions related to economic hedges	—			341			(7		)	5		(292		)	47
Total mark-to-market gains/(losses) in operating revenues	$	—		$	289		$	(15	)	$	5	$	(264	)	$	15
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	62		$	(2	)	$	(3	)	$	—	$	(28	)	$	29
Reversal of acquired gain positions related to economic hedges	(1		)	—			—			—		—			(1		)
Net unrealized (losses)/gains on open positions related to economic hedges	(407		)	(2		)	3			—		292			(114		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(346	)	$	(4	)	$	—		$	—	$	264		$	(86	)


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


	Nine months ended September 30, 2017																	Three months ended June 30, 2017
	Generation																				Generation
	Gulf Coast			East/West			Retail			Renewables		Eliminations^(a)			Total			Retail			Gulf Coast			East/West			Renewables			Eliminations^(a)			Total
	(In millions)																	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges																		$	(1	)	$	(7	)	$	(11	)	$	—		$	50		$	31
Net unrealized (losses)/gains on open positions related to economic hedges																		(1		)	(83		)	24			(3		)	73			10
Total mark-to-market (losses)/gains in operating revenues																		$	(2	)	$	(90	)	$	13		$	(3	)	$	123		$	41
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	113		$	(32	)	$	(1	)	$	1	$	21		$	102		$	45		$	(4	)	$	—		$	—		$	(50	)	$	(9	)
Net unrealized gains/(losses) on open positions related to economic hedges	61			36			1			7		(22		)	83
Total mark-to-market gains/(losses) in operating revenues	$	174		$	4		$	—		$	8	$	(1	)	$	185
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(12	)	$	1		$	(51	)	$	—	$	(21	)	$	(83	)
Reversal of acquired gain positions related to economic hedges	—			—			(1		)	—		—			(1		)
Net unrealized (losses)/gains on open positions related to economic hedges	(10		)	6			(102		)	—		22			(84		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(22	)	$	7		$	(154	)	$	—	$	1		$	(168	)
Reversal of acquired loss positions related to economic hedges																		1			—			—			—			—			1
Net unrealized gains/(losses)on open positions related to economic hedges																		112			(11		)	(2		)	—			(73		)	26
Total mark-to-market gains/(losses) in operating costs and expenses																		$	158		$	(15	)	$	(2	)	$	—		$	(123	)	$	18


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

Nine months ended September 30, 2016
Generation
Gulf Coast East/West Retail Renewables
Eliminations^(a)
Total
(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized gains on settled positions related to economic hedges $ (260 ) $ (68 ) $ (1 ) $ —
$ —
$ (329 )
Net unrealized (losses)/gains on open positions related to economic hedges (10 ) 59
1
—
(81 ) (31 )
Total mark-to-market losses in operating revenues $ (270 ) $ (9 ) $ —
$ —
$ (81 ) $ (360 )
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges $ 26
$ 10
$ 218
$ —
$ —
$ 254
Reversal of acquired gain positions related to economic hedges —
(10 ) (1 ) —
—
(11 )
Net unrealized gains/(losses) on open positions related to economic hedges 36
8
(67 ) —
81
58
Total mark-to-market gains in operating costs and expenses $ 62
$ 8
$ 150
$ —
$ 81
$ 301


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

~~The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.~~

For the ~~nine~~three months ended ~~September~~June 30, 2018, the $15 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of ERCOT heat rate contraction and decreases in ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The $86 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in value of open positions as a result of ERCOT heat rate contraction and decreases in ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.

For the three months ended June 30, 2017, the ~~$185~~$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, ~~and natural gas prices. The $168 million loss in operating costs and expenses from economic hedge positions was driven primarily~~partially offset by ~~the~~a decrease in value of open positions as a result of ~~decreases in coal, natural gas, and~~ ERCOT ~~power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.~~

For the nine months ended September 30, 2016, the $360 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period.heat rate expansion. The ~~$301~~$18 million gain in operating costs and expenses from economic hedge positions was driven primarily by ~~the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as the~~an increase in value of open positions as a result of ~~increases~~ERCOT heat rate expansion, partially offset by a decrease in ~~natural gas prices.~~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.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2018 and ~~2016.~~2017. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.


	Nine months ended September 30,					Three months ended June 30,
(In millions)	2017			2016		2018		2017
Trading gains/(losses)
Trading gains
Realized	$	18		$	67	$	25	$	14
Unrealized	(7		)	27		5		12
Total trading gains	$	11		$	94	$	30	$	26

Operations and Maintenance Expense

Generation Retail Renewables NRG Yield Corporate Eliminations Total
Gulf Coast
East/West^(a)

(In millions)
Nine months ended September 30, 2017 $ 370
$ 284
$ 170
$ 91
$ 143
$ 12
$ (32 ) $ 1,038
Nine months ended September 30, 2016 419
374
178
93
134
19
(21 ) 1,196



	Retail		Generation				Renewables		NRG Yield		Corporate		Eliminations			Total
	Retail		Gulf Coast		East/West^(a)		Renewables		NRG Yield		Corporate		Eliminations			Total
			(In millions)
Three months ended June 30, 2018	$	49	$	156	$	99	$	25	$	42	$	1	$	(12	)	$	360
Three months ended June 30, 2017	$	57	$	105	$	105	$	34	$	46	$	5	$	(12	)	$	340


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

(a) Includes International, BETM and generation eliminations of $2 million in 2018 and $1 million in 2017.

Operations and maintenance expense ~~decreased~~increased by ~~$158~~$20 million for the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2018, compared to the same period in ~~2016,~~2017, due to the following:

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



	(In millions)
2017 proceeds and 2018 payments in settlement of certain legal matters	$	33
Increase in operations and maintenance due to the gain on sale of the Jewett Mine dragline in 2017	18
Increased deactivation costs primarily at Dunkirk	7
Increase in major maintenance primarily due to outages at W.A. Parish and Big Cajun II	6
Decrease in NRG Yield operations and maintenance expense due to lower costs related to forced outages at Walnut Creek in 2018 compared to 2017, as well as lower losses on disposal of assets at Walnut Creek and El Segundo	(5		)
Decrease in East/West operations and maintenance expense due to major maintenance at Sunrise in 2017	(5		)
Decrease in Renewables operations and maintenance expense primarily from the deconsolidation of Ivanpah	(9		)
Decrease in operations and maintenance expense due to cost efficiencies as a result of the Transformation Plan	(25		)
	$	20

Depreciation and amortization

Depreciation and amortization decreased by $33 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017, driven primarily by the impairment of property, plant and equipment in prior years as well as the deconsolidation of Ivanpah in May 2018.

Impairment Losses

For the three months ended June 30, 2018, the Company recorded impairment losses of $74 million related to the impairment of the Keystone and Conemaugh generating stations, as well and the impairment of the Dunkirk project, as described in Note 7, Impairments.

Selling, General and Administrative

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

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



	Retail		Generation		Renewables		NRG Yield		Corporate		Total
			(In millions)
Three months ended June 30, 2018	$	126	$	55	$	12	$	7	$	11	$	211
Three months ended June 30, 2017	106		52		14		7		42		221

Selling, general and administrative expenses decreased by ~~$104~~$10 million for the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2018, compared to the same period in ~~2016. The decrease in year over year expenses is~~2017, due ~~primarily~~ to ~~a reduction in personnel costs and selling and marketing activities as~~ the ~~Company continues to focus on cost management.~~following:

~~Reorganization~~



	(In millions)
Decrease in general and administrative expense from cost initiatives for the Transformation Plan	$	(36	)
Prior year fees associated with advisors engaged to assist the Company in its strategic review in 2017	(6		)
Increase in bad debt expense primarily from increased usage due to weather	6
Increase in expense for estimated legal settlements	10
Increase in selling and marketing expense associated with costs incurred for margin enhancement initiatives	16
	$	(10	)

Reorganization ~~expenses~~Costs

Reorganization costs of ~~$18~~$23 million, primarily related to employee costs, were incurred ~~during the third quarter~~as part of ~~2017 related to~~ the Transformation ~~Plan announced on July 12, 2017.~~Plan.

~~Loss~~Other Income - Affiliate

Other income - affiliate represents the services fees charged to GenOn for shared services under the Services Agreement through June 14, 2017, the date of deconsolidation.

Gain on Sale of Assets

~~During the nine months ended September 30, 2016, the Company sold a majority interest in its EVgo business to Vision Ridge Partners, as described in Note 3,~~ ~~Discontinued Operations, Dispositions and Acquisitions, of this Form 10-Q, which resulted in a loss~~Gain on sale of ~~$79 million .~~

~~Impairment Losses on Investments~~

~~For~~assets for the ~~nine~~three months ended ~~September~~June 30, ~~2016,~~2018, consists primarily of the ~~Company~~gain on the sale of Canal 3, while the gain on sale of assets for the three months ended June 30, 2017, represents a gain on the sale of land.

Equity in Earnings/(Losses) of Unconsolidated Affiliates

Equity in earnings of consolidated affiliates increased by $21 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017, which was primarily driven by the equity in earnings recorded ~~other-than-temporary impairment~~in 2018 for Ivanpah after deconsolidation, as well as by prior year losses ~~of $147 million, which is primarily due to its 50% interest in~~from Petra Nova Parish Holdings, offset by the prior period HLBV income allocated to the Company’s interests in the Utah Portfolio.

Other (Losses)/Income, Net

Other losses for the three months ended June 30, 2018, primarily relate to the loss on deconsolidation of Ivanpah of $22 million. Other income for the three months ended June 30, 2017, primarily relates to dividends received from cost method investments as ~~further described in Note 7,~~ ~~Impairments,~~ ~~of this Form 10-Q.~~well as income from pension and postretirement investments.

~~Loss on Debt Extinguishment~~

A loss on debt extinguishment of $119 million was recorded for the nine months ended September 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.

Interest Expense

NRG's interest expense decreased by ~~$26~~$46 million for the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2018, compared to the same period in ~~2016~~2017 due to the following:

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



	(In millions)
Decrease in derivative interest expense from changes in the fair value of interest rate swaps driven by increased interest rates in 2018	$	(35	)
Decrease in interest expense related to repurchases of Senior Notes	(9		)
Decrease in interest expense related to Ivanpah deconsolidation	(6		)
Other	4
	$	(46	)

Income Tax Expense

For the ~~nine~~three months ended ~~September~~June 30, ~~2017,~~2018, NRG recorded an income tax expense of $5$8 million on a pre-tax income of ~~$125~~$129 million. For the same period in ~~2016,~~2017, NRG recorded an income tax expense of ~~$75~~$4 million on a pre-tax ~~loss~~income of ~~$17~~$103 million. The effective tax rate was ~~4.0%~~6.2% and ~~(441.2)%~~3.9% for the ~~nine~~three months ended ~~September~~June 30, 2018 and 2017, ~~and 2016,~~ respectively.

For the ~~nine~~three months ended ~~September~~June 30, 2018, NRG's overall effective tax rate was different than the statutory rate of 21% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs from various wind facilities partially offset by the inclusion of consolidated partnerships and the current state tax expense.

For the nine months ended September 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due the amortization of indefinite lived assets, the inclusion of consolidated partnerships, state tax expense and the expense for the change in valuation allowance.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

For the ~~nine~~three months ended ~~September~~June 30, ~~2017~~2018 and ~~2016,~~2017, 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)~~

Management’s discussion of the results of operations for the six months ended June 30, 2018 and 2017

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, 2018 and 2017. The average on-peak power prices have generally increased primarily due to increased heat rates for the six months ended June 30, 2018, as compared to the same period in 2017.



	Average on Peak Power Price ($/MWh)
	Six months ended June 30,
Region	2018		2017		Change %
Gulf Coast ^(a)
ERCOT - Houston ^(b)	$	33.98	$	36.86	(8	)%
ERCOT - North^(b)	33.28		25.28		32	%
MISO - Louisiana Hub^(c)	45.22		43.71		3	%
East/West
NY J/NYC^(c)	49.19		37.48		31	%
NEPOOL^(c)	51.07		33.69		52	%
COMED (PJM)^(c)	32.54		31.89		2	%
PJM West Hub^(c)	43.58		32.40		35	%
CAISO - NP15^(c)	30.05		27.38		10	%
CAISO - SP15^(c)	31.60		26.87		18	%

(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, 2018 and 2017, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Six months ended June 30,
Region	2018		2017		Change %
Gulf Coast	$	34.85	$	34.25	2	%
East/West^(a)	40.69		40.20		1	%

(a) does not include BETM energy revenue of $32 million and $15 million for 2018 and 2017, respectively.

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 different rates 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, 2018 and 2017:



	Six months ended June 30, 2018
				Generation
(In millions)	Retail			Gulf Coast			East/West^(a)			Subtotal			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	—		$	879		$	362		$	1,241		$	156		$	306		$	(411	)	$	1,292
Capacity revenue	—			135			300			435			—			169			(3		)	601
Retail revenue	3,304			—			—			—			—			—			(2		)	3,302
Mark-to-market for economic hedging activities	(6		)	(275		)	(25		)	(300		)	(5		)	—			220			(91		)
Contract amortization	—			7			—			7			—			(35		)	—			(28		)
Other revenue ^(b)	—			128			34			162			48			92			(35		)	267
Operating revenue	3,298			874			671			1,545			199			532			(231		)	5,343
Cost of fuel	(12		)	(454		)	(152		)	(606		)	(1		)	(23		)	(88		)	(730		)
Other cost of sales^(c)	(2,415		)	(164		)	(90		)	(254		)	(4		)	(14		)	509			(2,178		)
Mark-to-market for economic hedging activities	446			(7		)	(3		)	(10		)	—			—			(220		)	216
Contract and emission credit amortization	—			(12		)	(1		)	(13		)	—			—			—			(13		)
Gross margin	$	1,317		$	237		$	425		$	662		$	194		$	495		$	(30	)	$	2,638
Less: Mark-to-market for economic hedging activities, net	440			(282		)	(28		)	(310		)	(5		)	—			—			125
Less: Contract and emission credit amortization, net	—			(5		)	(1		)	(6		)	—			(35		)	—			(41		)
Economic gross margin	$	877		$	524		$	454		$	978		$	199		$	530		$	(30	)	$	2,554
Business Metrics
MWh sold (thousands)^(d)(e)				25,220			8,110						2,227			3,924
MWh generated (thousands)^(f)				23,146			5,463						2,227			4,729
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $26 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 18 thousand or MWt of 1,079 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 47 thousand or MWt of 987 thousand for thermal generated by NRG Yield.



	Six months ended June 30, 2017
				Generation
(In millions)	Retail			Gulf Coast			East/West^(a)			Subtotal			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	—		$	868		$	408		$	1,276		$	174		$	294		$	(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	(1		)	6			—			6			—			(34		)	—			(29		)
Other revenue ^(b)	—			102			20			122			36			85			(38		)	205
Operating revenue	2,938			1,150			698			1,848			213			509			(425		)	5,083
Cost of fuel	(7		)	(498		)	(170		)	(668		)	(2		)	(18		)	31			(664		)
Other cost of sales^(c)	(2,204		)	(157		)	(124		)	(281		)	(5		)	(12		)	483			(2,019		)
Mark-to-market for economic hedging activities	20			(24		)	(3		)	(27		)	—			—			(111		)	(118		)
Contract and emission credit amortization	—			(14		)	(2		)	(16		)	—			—			—			(16		)
Gross margin	$	747		$	457		$	399		$	856		$	206		$	479		$	(22	)	$	2,266
Less: Mark-to-market for economic hedging activities, net	20			17			1			18			3			—			—			41
Less: Contract and emission credit amortization, net	(1		)	(8		)	(2		)	(10		)	—			(34		)	—			(45		)
Economic gross margin	$	728		$	448		$	400		$	848		$	203		$	513		$	(22	)	$	2,270
Business Metrics
MWh sold (thousands)^(d)(e)				25,340			9,776						1,974			3,789
MWh generated (thousands)^(f)				23,790			6,096						1,974			4,244
(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 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.

The table below represents the weather metrics for the six months ended June 30, 2018 and 2017:



	Six months ended June 30,
Weather Metrics	Gulf Coast	East/West
2018
CDDs ^(a)	1,200	283
HDDs ^(a)	1,142	2,152
2017
CDDs	1,125	301
HDDs	673	2,008
10-year average
CDDs	1,062	276
HDDs	1,103	2,206

(a)

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)	2018			2017
Retail revenue	$	3,135		$	2,813
Supply management revenue	75			84
Capacity revenue	94			42
Customer mark-to-market	(6		)	—
Contract amortization	—			(1		)
Other	—			—
Operating revenue^(a)	3,298			2,938
Cost of sales ^(b)	(2,427		)	(2,211		)
Mark-to-market for economic hedging activities	446			20
Gross Margin	$	1,317		$	747
Less: Mark-to-market for economic hedging activities, net	440			20
Less: Contract amortization, net	—			(1		)
Economic Gross Margin	$	877		$	728

Business Metrics
Mass electricity sales volume — GWh - Gulf Coast	17,745			16,218
Mass electricity sales volume — GWh - All other regions	3,310			2,998
C&I electricity sales volume — GWh - All regions	10,430			10,141
Natural gas sales volumes (MDth)	3,419			1,700
Average Retail Mass customer count (in thousands)	2,926			2,843
Ending Retail Mass customer count (in thousands) ^(c)	3,173			2,887


(a)	Includes intercompany sales of $2 million and $2 million in 2018 and 2017, respectively, representing sales from Retail to the Gulf Coast region.


(b)	Includes intercompany purchases of $415 million and $502 million in 2018 and 2017, respectively.


(c)	The acquisition of XOOM Energy, LLC increased NRG's retail portfolio by approximately 300,000 customers in the aggregate by June 30, 2018.

Retail gross margin increased $570 million and economic gross margin increased $149 million for the six months ended June 30, 2018, compared to the same period in 2017, due to:



	(In millions)
Higher gross margin due to higher revenue of $101 million or approximately $3.00 per MWh, driven by customer product, term and mix offset by higher supply costs of $40 million or approximately $1.25 per MWh, driven primarily by an increase in power prices	$	61
Higher gross margin from the Business Solutions unit reflecting the early settlement of capacity obligations for 2018	34
Higher gross margin due to an increase in load of 1,495,000 MWh driven by more favorable weather conditions in 2018 as compared to 2017	46
Higher gross margin due to higher volumes driven by higher average customer counts primarily driven by the XOOM acquisition in June 2018	8
Increase in economic gross margin	$	149
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	420
Increase in contract amortization	1
Increase in gross margin	$	570

Generation gross margin and economic gross margin

Generation gross margin decreased $194 million and economic gross margin increased $130 million, both of which include intercompany sales, during the six months ended June 30, 2018, compared to the same period in 2017.

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

Gulf Coast Region



	(In millions)
Higher gross margin due to a 10% increase in average realized prices in South Central and a 2% increase in average realized prices in Texas	$	65
Higher gross margin from sales of NOx emission credits	35
Higher capacity margins due to an 15% increase in load demand in the South Central business	29
Lower energy margin due to a 14% increase in supply cost on load contracts	(36		)
Lower capacity revenue due to the cancellation of the Greens Bayou RMR agreement in 2017	(14		)
Other	(3		)
Increase in economic gross margin	$	76
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(299		)
Increase in contract and emission credit amortization	3
Decrease in gross margin	$	(220	)

East/West



	(In millions)
Higher gross margin due to a 88% increase in New England cleared capacity pricing	$	34
Higher gross margin due to a 23% increase in PJM cleared capacity pricing which relates to the first full period of capacity performance product pricing	29
Higher gross margin from commercial optimization activities	15
Higher gross margin by BETM due to higher gains in congestion strategies	14
Higher gross margin due to a net overall increase in capacity volumes sold in New York	11
Lower gross margin due to a 31% decrease in capacity pricing in New York of $30 million and decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration in July 2017 of $9 million	(39		)
Lower gross margin due to lower load contracted prices coupled with lower contracted volumes	(13		)
Lower gross margin due to a 10% decrease in generation volumes due to timing of planned and unplanned outages at Midwest Generation and Arthur Kill, offset by favorable fuel costs	(10		)
Higher gross margin due to insurance proceeds from outages of $14 million in 2018, compared to business interruption proceeds of $8 million in 2017	6
Other	7
Increase in economic gross margin	$	54
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(29		)
Increase in contract and emission credit amortization	1
Increase in gross margin	$	26

Renewables gross margin and economic gross margin

Renewables gross margin decreased $12 million and economic gross margin decreased $4 million for the six months ended June 30, 2018, compared to the same period in 2017. This was driven by the deconsolidation of Ivanpah in May 2018, offset in part by additional distributed solar projects reaching commercial operations in late 2017 and early 2018.

NRG Yield gross margin and economic gross margin

NRG Yield gross margin increased $16 million and economic gross margin increased $17 million for the six months ended June 30, 2018, compared to the same period in 2017. The increase is due primarily to a 3% increase in volume generated by wind projects, primarily in connection with higher wind resource at the Alta Wind projects, as well as a 5% increase in solar generation, primarily at CVSR in connection with higher insolation and higher plant availability at Walnut Creek and El Segundo.

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. Total net mark-to-market results increased by $84 million during the six months ended June 30, 2018, compared to the same period in 2017.

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, 2018
				Generation
	Retail			Gulf Coast			East/West			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	$	(1	)	$	(86	)	$	(8	)	$	—		$	31		$	(64	)
Net unrealized (losses)/gains on open positions related to economic hedges	(5		)	(189		)	(17		)	(5		)	189			(27		)
Total mark-to-market (losses)/gains in operating revenues	$	(6	)	$	(275	)	$	(25	)	$	(5	)	$	220		$	(91	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	104		$	(3	)	$	(7	)	$	—		$	(31	)	$	63
Reversal of acquired gain positions related to economic hedges	(1		)	—			—			—			—			(1		)
Net unrealized gains/(losses) on open positions related to economic hedges	343			(4		)	4			—			(189		)	154
Total mark-to-market gains/(losses) in operating costs and expenses	$	446		$	(7	)	$	(3	)	$	—		$	(220	)	$	216


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



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


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

For the six months ended June 30, 2018, the $91 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 the value of open positions as a result of ERCOT heat rate expansion and increases in ERCOT electricity prices. The $216 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 and increases in ERCOT electricity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period.

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.

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, 2018 and 2017. 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)	2018		2017
Trading gains/(losses)
Realized	$	40	$	28
Unrealized	13		(2		)
Total trading gains	$	53	$	26

Operations and Maintenance Expense



	Retail		Generation				Renewables		NRG Yield		Corporate		Eliminations			Total
	Retail		Gulf Coast		East/West^(a)		Renewables		NRG Yield		Corporate		Eliminations			Total
	(In millions)
Six months ended June 30, 2018	$	96	$	307	$	204	$	53	$	94	$	2	$	(26	)	$	730
Six months ended June 30, 2017	$	114	$	250	$	200	$	63	$	98	$	9	$	(22	)	$	712

(a) Includes International, BETM and generation eliminations of $3 million in 2018 and $2 million in 2017.

Operations and maintenance expense increased by $18 million for the six months ended June 30, 2018, compared to the same period in 2017, due to the following:



	(In millions)
2017 proceeds and 2018 payments in settlement of certain legal matters	$	33
Increase in operations and maintenance due to the gain on sale of the Jewett Mine dragline in 2017	18
Increase in major maintenance primarily due to outages at W.A. Parish and Big Cajun II	32
Increased deactivation costs primarily at Dunkirk	10
Decrease in operations and maintenance expense due to cost efficiencies as a result of the Transformation Plan^(a)	(60		)
Decrease in Renewables operations and maintenance expense primarily from the deconsolidation of Ivanpah	(10		)
Decrease in NRG Yield operations and maintenance expense due to lower costs related to forced outages at Walnut Creek in 2018 compared to 2017, as well as lower losses on disposal of assets at Walnut Creek and El Segundo	(5		)
	$	18

(a) Approximately $36 million of additional cost savings were achieved in the six months ended June 30, 2017, as compared to the six months ended June 30, 2016, as the savings became permanent through the Transformation Plan.

Depreciation and amortization

Depreciation and amortization decreased by $55 million for the six months ended June 30, 2018, compared to the same period in 2017, driven primarily by the impairment of property, plant and equipment in prior years as well as the deconsolidation of Ivanpah in May 2018.

Impairment Losses

For the six months ended June 30, 2018, the Company recorded impairment losses of $74 million related to the impairment of the Keystone Conemaugh generating stations, as well as the impairment of the Dunkirk project as described in Note 7, Impairments.

Selling, General and Administrative

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



	Retail		Generation		Renewables		NRG Yield		Corporate		Total
			(In millions)
Six months ended June 30, 2018	$	241	$	106	$	22	$	13	$	20	$	402
Six months ended June 30, 2017	225		111		27		12		106		481

Selling, general and administrative expenses decreased by $79 million for the six months ended June 30, 2018, compared to the same period in 2017.



	(In millions)
Decrease in general and administrative expense from cost initiatives for the Transformation Plan^(a)	$	(104	)
Prior year fees associated with advisors engaged to assist the Company in its strategic review in 2017	(20		)
Prior year fees for advisors and other consultants engaged to assist the Company with GenOn's ability to continue as a going concern	(11		)
Increase in bad debt expense primarily from increased usage due to weather	14
Increase in expense for estimated legal settlements	10
Increase in selling and marketing expense associated with costs incurred for margin enhancement initiatives	32
	$	(79	)

(a) Approximately $22 million of additional cost savings were achieved in the six months ended June 30, 2017, as compared to the six months ended June 30, 2016, as the savings became permanent through the Transformation Plan.

Reorganization Costs

Reorganization costs of $43 million, primarily related to employee costs, were incurred as part of the Transformation Plan during the six months ended June 30, 2018.

Other Income - Affiliate

Other income - affiliate represents the services fees charged to GenOn for shared services under the Services Agreement through June 14, 2017, the date of deconsolidation.

Gain on Sale of Assets

Gain on sale of assets for the six months ended June 30, 2018, consists primarily of the gain on the sale of Canal 3, while the gain on sale of assets for the six months ended June 30, 2017, represents a gain on the sale of land.

Equity in (Losses)/Earnings of Unconsolidated Affiliates

Equity in earnings of consolidated affiliates increased by $14 million for the six months ended June 30, 2018, compared to the six months ended June 30, 2017, which was primarily driven by the equity in earnings recorded in 2018 for Ivanpah after deconsolidation, as well as by prior year losses from Petra Nova Parish Holdings, offset by the prior period HLBV income allocated to the Company’s interests in the Utah Portfolio.

Other (Losses)/Income, Net

Other losses for the six months ended June 30, 2018, primarily relate to the loss on deconsolidation of Ivanpah of $22 million. Other income for the six months ended June 30, 2017, primarily relates to primarily relates to dividends received from ~~Discontinued Operations, Net of~~ cost method investments as well as income from pension and postretirement investments.

Interest Expense

NRG's interest expense decreased by $102 million for the six months ended June 30, 2018, compared to the same period in 2017 due to the following:



	(In millions)
Decrease in derivative interest expense from changes in the fair value of interest rate swaps driven by increased interest rates in 2018	$	(75	)
Decrease in interest expense related to repurchases of Senior Notes	(20		)
Decrease in interest expense related to Ivanpah deconsolidation	(6		)
Other	(1		)
	$	(102	)

Income Tax ~~(Benefit)/~~Expense

For the ~~nine~~six months ended ~~September~~June 30, 2018, NRG recorded an income tax expense of $7 million on pre-tax income of $361 million. For the same period in 2017, NRG recorded ~~loss from discontinued operations, net of~~an income tax ~~(benefit)/expense~~benefit of ~~$802~~$1 million on a pre-tax loss of $71 million.

The effective tax rate was 1.9% and 1.4% for the six months ended June 30, 2018 and 2017, respectively.

For the ~~nine~~six months ended ~~September~~June 30, ~~2016,~~2018, NRG's overall effective tax rate was different than the statutory rate of 21% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs from various wind facilities partially offset by the inclusion of consolidated partnerships and the 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.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

For the six months ended June 30, 2018 and 2017, 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 ~~recorded income from discontinued operations,~~Yield, Inc.'s share of net ~~of income tax (benefit)/expense of $256 million.~~income.

Liquidity and Capital Resources

Liquidity Position

As of ~~September~~June 30, ~~2017~~2018 and December 31, ~~2016~~2017, NRG's liquidity, excluding collateral received, was approximately ~~$3.4~~$2.5 billion and $~~2.4~~3.2 billion, respectively, comprised of the following:


(In millions)	September 30, 2017		December 31, 2016		June 30, 2018		December 31, 2017
Cash and cash equivalents:
NRG excluding NRG Yield	$	1,044	$	621	$	850	$	843
NRG Yield and subsidiaries	179		317		130		148
Restricted cash - operating	124		56		43		71
Restricted cash - reserves^(a)	413		390		243		437
Total	1,760		1,384		1,266		1,499
Total credit facility availability	1,604		989		1,222		1,711
Total liquidity, excluding collateral received	$	3,364	$	2,373	$	2,488	$	3,210

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

For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018, total liquidity, excluding collateral funds deposited by counterparties, ~~increased~~decreased by ~~$1 billion.~~$722 million. Changes in cash and cash ~~equivalents~~equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at ~~September~~June 30, ~~2017~~2018, 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 September 30, 2017:~~



	~~S&P~~	~~Moody's~~
~~NRG Energy, Inc.~~	~~BB- Stable~~	~~Ba3 Stable~~
~~7.625% Senior Notes, due 2018~~	~~BB-~~	B1
~~7.875% Senior Notes, due 2021~~	~~BB-~~	B1
~~6.25% Senior Notes, due 2022~~	~~BB-~~	B1
~~6.625% Senior Notes, due 2023~~	~~BB-~~	B1
~~6.25% Senior Notes, due 2024~~	~~BB-~~	B1
~~7.25% Senior Notes, due 2026~~	~~BB-~~	B1
~~6.625% Senior Notes, due 2027~~	~~BB-~~	B1
~~Term Loan Facility, due 2023~~	~~BB+~~	~~Baa3~~
~~NRG Yield, Inc.~~	BB	~~Ba2~~
~~5.375% NRG Yield Operating LLC Senior Notes, due 2024~~	BB	~~Ba2~~
~~5.00% NRG Yield Operating LLC Senior Notes, due 2026~~	BB	~~Ba2~~

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

Sources of Liquidity

The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from ~~new and existing financing arrangements, existing~~ cash on hand, cash flows from operations, ~~and~~ cash proceeds from future sales of assets, including sales to NRG Yield, Inc. Asand under the Transformation Plan, and financing arrangements, 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~~2017 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~~Sale of Ownership in NRG Yield, Inc. and Renewables Platform

On ~~May 26, 2017, Carlsbad Energy Holdings, LLC~~February 6, 2018, NRG and Global Infrastructure Partners, or GIP, entered into a ~~note payable~~purchase and sale agreement for GIP to purchase NRG's ownership in NRG Yield, Inc. and NRG's renewables platform for cash of $1.375 billion, subject to certain adjustments. The purchase and sale agreement includes the sale of all of NRG's ownership in NRG Yield, Inc., NRG's renewable energy development and operations platforms and NRG's renewable energy non-ROFO backlog and pipeline.

In connection with ~~financial institutions for~~ the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038. As of September 30, 2017, all $407 million of these notes were outstanding.

~~Also on May 26, 2017, Carlsbad Energy Holdings, LLC~~transaction, the Company entered into a ~~credit agreement, or the Carlsbad Financing~~Consent and Indemnity Agreement with NRG Yield, Inc. and GIP setting forth key terms and conditions of NRG Yield, Inc.'s consent to the ~~issuing banks,~~transaction. As part of the Consent and Indemnity Agreement, NRG has agreed to indemnify GIP and NRG Yield, Inc. and its project companies for any increase in property taxes at the California-based solar projects resulting from the transaction.

The transaction is subject to certain closing conditions, approvals and consents. As of July 31, 2018, all regulatory approvals have been received, however certain significant consents and waivers remain pending, and the Company expects the transaction to close in the second half of 2018. Upon the closing of the transaction, NRG’s interest in the Ivanpah asset will no longer be part of the NRG Yield ROFO assets.

Sale of South Central Business

On February 6, 2018, NRG and Cleco Energy LLC, or Cleco, entered into a ~~$194 million construction loan, that~~purchase and sale agreement for Cleco to purchase NRG's South Central business for cash of $1.0 billion, subject to certain adjustments. The transaction is expected to close in the second half of 2018 and is subject to certain closing conditions, approvals and consents. The South Central business owns and operates a 3,555 MW portfolio of generation assets in the Gulf Coast region. Upon the closing of the transaction, NRG will ~~convert~~enter into a sale leaseback agreement for the Cottonwood plant through May 2025.

Sale of BETM

On August 1, 2018, the Company completed the sale of 100% of its ownership interests in BETM to a ~~term loan upon completion~~third party for $70 million, subject to working capital adjustments. The sale also resulted in the release and return of ~~the project. The Carlsbad Financing Agreement also includes a~~approximately $119 million of letters of credit, ~~facility not~~$30 million of parent guarantees, and $4 million of net cash collateral to ~~exceed aggregate amount~~NRG.

Sales of ~~$83~~Assets to NRG Yield, Inc.

On June 19, 2018, the Company completed the sale of the substantially completed assets of the UPMC Thermal Project for cash consideration of $84 million, ~~and a~~subject to working capital ~~loan facility with an aggregate principle amount not to exceed $4 million.~~

~~ROFO Agreement Expansion and Offer~~adjustments.

On ~~February 24, 2017,~~March 30, 2018, as part of the Transformation Plan, the Company ~~amended and restated~~completed the ~~ROFO Agreement to expand the ROFO assets pipeline with the addition~~sale of ~~234 net MW of utility-scale solar projects. These assets include Buckthorn Solar, a 154 net MW facility located in Texas, and the Hawaii Solar projects, which have a combined capacity of 80 net MW.~~

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

~~Sale of Assets to NRG Yield, Inc.~~

~~On November 1, 2017, NRG completed the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds, in addition to other projects developed by NRG,~~ to NRG Yield, Inc. for cash consideration of ~~$71 million, plus $3 million in working capital adjustments.~~approximately $42 million.

On ~~August 1, 2017, NRG closed on its sale of~~February 6, 2018, the ~~remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind projects, to~~Company entered into an agreement with NRG Yield, Inc. ~~for total cash consideration~~to sell 100% of ~~$44 million. The transaction also includes potential additional payments to NRG dependent on actual energy prices for merchant periods beginning in 2027.~~

~~On May 23, 2017, NRG offered NRG Yield, Inc.~~ the ~~opportunity to form a new distributed solar investment partnership enabling up to $50 million in investment by NRG Yield, Inc. In addition, on July 31, 2017, NRG offered NRG Yield, Inc. equity~~membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, 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~~527-MW natural gas fired project in ~~addition~~Carlsbad, CA, pursuant to ~~other projects developed since the acquisition of SPP. These equity interests are not part of~~ the ROFO Agreement. ~~Both~~The purchase price for the ~~distributed solar investment partnership and the distributed and small utility-scale solar acquisitions are~~transaction is $365 million in cash consideration, subject to ~~negotiation~~customary working capital and ~~approval by NRG Yield, Inc.'s independent directors. As~~other adjustments. The transaction is expected to close during the fourth quarter of ~~September 30, 2017, NRG Yield, Inc has invested $41 million in distributed solar investment partnerships with NRG.~~2018.

Sale of Canal 3

On ~~March 27, 2017,~~June 29, 2018, the Company ~~sold (i) a 16% interest in~~completed the ~~Agua Caliente solar project, representing ownership~~sale of Canal 3 to Stonepeak Kestrel for cash proceeds of approximately ~~46 net MW~~$16 million and recorded a gain of ~~capacity~~$17 million. Prior to the sale, Canal 3 entered into a financing arrangement and ~~(ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW~~received cash proceeds of ~~capacity~~$167 million, of which ~~have reached commercial operations~~$151 million was distributed to the Company. The related debt is non-recourse to NRG ~~Yield, Inc. NRG Yield Inc. paid cash consideration~~and was transferred to Stonepeak Kestrel in connection with the sale of ~~$130 million, plus $1 million in working capital adjustments, and assumed non-recourse project debt~~Canal 3.

Other Asset Sales

During the first half of 2018, the Company completed the sale of various other assets for approximately ~~$328~~$7 million.

2023 Term Loan Facility

On ~~January 24, 2017,~~March 21, 2018, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus ~~2.25%,~~1.75% and reducing the LIBOR floor ~~remains 0.75%~~to 0.00%. As a result of the repricing, the Company expects ~~interest savings of~~ approximately ~~$9 million in 2017 and approximately $60~~$47 million in interest savings over the remaining life of the loan.

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

On April 30, 2018, NRG Yield LLC and NRG Yield Operating LLC refinanced the revolving credit facility, which extended the maturity of the facility to April 28, 2023, and decreased the overall cost of borrowing from L+ 2.50% to L+1.75%.

2048 Convertible Senior Notes Issuance

On May 24, 2018, the Company issued $575 million in aggregate principal amount at par of 2.75% convertible senior notes due 2048.

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired ~~through~~in the GenOn and EME (including Midwest Generation), acquisitions, 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.~~exposure. 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.~~Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of ~~September~~June 30, ~~2017~~2018, all hedges under the first liens were ~~out-of-the-money~~in-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of ~~September~~June 30, ~~2017~~2018:


Equivalent Net Sales Secured by First Lien Structure ^(a)	2017		2018		2019		2020		2021		2018	2019	2020	2021	2022	2023
In MW	1,458		1,093		—		—		—		264	908	916	765	828	860
As a percentage of total net coal and nuclear capacity ^(b)	27	%	20	%	—	%	—	%	—	%	6%	19%	20%	16%	18%	18%


(a)	Equivalent ~~net sales~~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~~(including 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, share repurchases, return of capital and dividend payments to ~~stockholders.~~

~~Senior Note Redemptions~~

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

~~Restructuring Support Agreement~~

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

~~Revolving Credit Facility~~

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

Commercial Operations

~~NRG's~~The Company's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of ~~September~~June 30, ~~2017~~2018, commercial operations had total cash collateral outstanding of ~~$274~~$234 million and ~~$606~~$953 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of ~~September~~June 30, ~~2017~~2018, total collateral held from counterparties was ~~$31~~$76 million in cash and ~~$17~~$198 million inof 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~~the Company'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 ~~nine~~six months ended ~~September~~June 30, ~~2017~~,2018, and the ~~currently~~ estimated capital expenditure and growth investments forecast for the remainder of ~~2017~~. 2018.

Maintenance Environmental Growth Investments Total
(In millions)
Generation
Gulf Coast $ 73
$ 1
$ 3
$ 77
East/West 17
24
240
281
Retail 22
—
33
55
Renewables 3
—
309
312
NRG Yield 21
—
2
23
Corporate
11
—
1
12
Total cash capital expenditures for the nine months ended September 30, 2017 147
25
588
760
     Funding from third party equity partners, cash grants and debt financing, net of fees —
—
(815 ) (815 )
     Other investments ^(a)
—
—
95
95
Total capital expenditures and investments, net of financings 147
25
(132 ) 40

Estimated capital expenditures for the remainder of 2017 76
10
430
516
     Funding from third party equity partners, cash grants and debt financing, net of fees —
—
(211 ) (211 )
NRG estimated capital expenditures for the remainder of 2017, net of financings $ 76
$ 10
$ 219
$ 305


~~(a)~~	~~Other investments include restricted cash activity.~~



	Maintenance		Environmental		Growth Investments ^(b)			Total
	(In millions)
Retail	$	12	$	—	$	22		$	34
Generation
Gulf Coast	70		—		—			70
East/West ^(a)	15		—		208			223
Renewables	2		—		286			288
NRG Yield	17		—		28			45
Corporate	6		—		25			31
Total cash capital expenditures for the six months ended June 30, 2018	122		—		569			691
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(618		)	(618		)
Other investments ^(c)	—		—		286			286
Total capital expenditures and investments, net of financings	122		—		237			359

Estimated capital expenditures for the remainder of 2018	99		3		231			333
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(73		)	(73		)
Other investments ^(c)	—		—		10			10
NRG estimated capital expenditures for the remainder of 2018, net of financings ^(d)	$	99	$	3	$	168		$	270

(a) Includes International and BETM

~~Environmental~~(b) Total cash capital expenditures ~~— For~~ include $25 million of cost-to-achieve spend associated with the ~~nine months ended September 30, 2017, the Company's environmental~~Transformation Plan

(d) Maintenance capital expenditures ~~included DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion~~includes approximately $66 million for assets to ~~satisfy CPS.~~

be sold

Growth Investments capital expenditures —

For the ~~nine~~six months ended ~~September~~June 30, ~~2017~~,2018, the Company's growth investment capital expenditures included ~~$245~~$266 million for ~~solar~~renewable projects, ~~$241~~$208 million for repowering projects ~~$65 million for wind projects~~ and ~~$37~~$95 million for the Company's other growth projects.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from ~~2017~~2018 through ~~2021~~2022 required to comply with environmental laws will be approximately ~~$60~~$76 million, which includes ~~$16~~$14 million for Midwest Generation. ~~The increase from last quarter is driven primarily by the addition of the anticipated costs of adding NOx control equipment at certain of the Company's units in Connecticut.~~

Common Stock Dividends

The following table lists the dividends paid during the ~~nine~~six months ended ~~September~~June 30, ~~2017:~~2018:

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



	Second Quarter 2018		First Quarter 2018
Dividends per Common Share	$	0.03	$	0.03

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws ~~regulations~~ and ~~other contractual obligations.~~regulations. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.

~~Fuel Repowerings~~Share Repurchases

~~The table below lists~~In February 2018, the Company's ~~currently projected repowering and conversion projects. With respect~~board of directors authorized the Company to ~~facilities that are currently operating,~~repurchase $1 billion of its common stock, with the ~~timing~~first $500 million program beginning as soon as permitted. In March 2018, the Company repurchased 3,114,748 shares of NRG common stock for approximately $93 million. During the second quarter of 2018, the Company repurchased 11,748,553 shares of NRG common stock for approximately $407 million, including shares repurchased under the ASR Agreement. In July 2018, the Company received an additional 860,880 shares in connection with the settlement of the ~~projects listed below could adversely impact~~ASR Agreement, completing the ~~Company's operating revenues, gross margin and other operating costs during~~$500 million of share repurchases. The average cost per share for the ~~period prior~~total $500 million of shares repurchased was $31.80.

Senior Note Repurchases

In connection with the Transformation Plan, the Company has committed to ~~the targeted COD.~~reduce its debt balance by an additional $640 million to achieve a target net debt to adjusted EBITDA credit ratio of 3.0/1. The following open market senior note repurchases were completed to assist in achieving this target.



~~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~~



	Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage
In millions, except rates
5.750% senior notes due 2028	$	29	$	30	99.24	%
6.250% senior notes due 2022	14		15		103.25	%
Total at June 30, 2018	$	43	$	45
6.250% senior notes due 2022	$	6	$	6	103.25	%
5.750% senior notes due 2028	20		21		99.13	%
6.625% senior notes due 2027	20		21		103.06	%
Total at August 2, 2018	$	89	$	93

(a) Includes payment for accrued interest.

~~(a) See~~As discussed in more detail in "Significant Events" in this ~~Regulatory Matters~~ ~~in the~~ Management's Discussion and Analysis of Financial Condition and Results of Operations, on August 1, 2018, the Company announced that it gave the required notice under the indenture governing its 6.25% Senior Notes due 2022 to ~~this Form 10-Q~~redeem for ~~recent developments~~cash $486 million aggregate principal amount of its 2022 Notes on August 31, 2018.

XOOM Energy Acquisition

On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for approximately $219 million in cash, inclusive of approximately $54 million in payments for estimated working capital, which is subject to further adjustment. The acquisition increased NRG's retail portfolio by approximately 300,000 customers in the aggregate by June 30, 2018.

Repowerings

Carlsbad — The Company is currently overseeing construction of the Carlsbad project, which when completed will consist of approximately 527 MWs of net generation capacity. On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell the Carlsbad project pursuant to the ROFO Agreement. The transaction is expected to close during the fourth quarter of 2018.

(bPower Project. On ~~June~~October 16, 2017, NRG ~~Texas Power LLC provided notice~~filed a motion to ~~BTEC New Albany, LLC that it~~suspend the permitting proceeding for at least six months, which 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,granted on November 3, 2017. On ~~July 14, 2017,~~April 20, 2018, NRG filed a motion requesting an additional extension of the ~~Company gave notice~~suspension period to ~~BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately $48 million under~~coincide with the ~~terminated MIPA, consisting~~CPUC’s final decision on SCE’s application seeking approval of ~~$38 million in purchaser incurred costs and $10 million in liquidated damages.~~

resources procured through its Moorpark RFO, or until June 30, 2019, whichever is sooner.

Cash Flow Discussion

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

Nine months ended September 30,
2017 2016 Change
(In millions)
Net cash used by operating activities $ 806
$ 1,741
$ (935 )
Net cash used by investing activities (765 ) (255 ) (510 )
Net cash provided by financing activities 59
(587 ) 646



	Six months ended June 30,
	2018			2017			Change
	(In millions)
Net cash provided/(used) by operating activities	$	524		$	74		$	450
Net cash used by investing activities	(1,146		)	(545		)	(601		)
Net cash used by financing activities	423			18			405

Net Cash ~~Used~~Provided By Operating Activities

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

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



	(In millions)
Increase in operating income adjusted for non-cash items	$	262
Changes in cash collateral in support of risk management activities due to changes in commodity prices	171
Other changes in working capital	(21		)
Change in cash from discontinued operations	38
	$	450

Net Cash Used By Investing Activities

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

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



	(In millions)
Increase in cash paid for acquisitions in 2018 compared to 2017, primarily from the XOOM acquisition	$	(268	)
Increase in capital expenditures for growth investments for solar and repowering projects	(149		)
Beginning balance of cash removed due to the deconsolidation of Ivanpah in 2018	(160		)
Decrease in proceeds from the sale of investments in 2017 compared to 2018	(17		)
Decrease in insurance proceeds for property damage	(18		)
Decrease in sales of emissions, net of purchases	(17		)
Change in cash from discontinued operations	53
Other	(25		)
	$	(601	)

Net Cash Provided By Financing Activities

Changes to net cash provided by 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 $ 538
Increase due to purchase of preferred stock in 2016 226
Increase in cash contributions, net of distributions from non-controlling interest in 2017 192
Decrease in debt extinguishment cost 98
Decrease in payment of dividends, primarily related to reduction of NRG dividend rate in the first quarter of 2016 38
Decrease in deferred debt issuance cost 27
Decrease in financing element related to acquired derivatives (5 )
Payment for affiliate receivable (125 )
Cash used by discontinued operations (343 )
$ 646



	(In millions)
Repurchases of common stock in 2018, from open market repurchases and the ASR Agreement	$	(500	)
Increase in payments for short and long-term debt	(318		)
Increase in proceeds from the issuance of long-term debt, primarily for the Convertible Notes	659
Change in cash from discontinued operations including long-term deposits in 2017	349
Increase in cash contributions, net of distributions from non-controlling interests in 2018, primarily related to tax equity financings	208
Other	7
	$	405

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

For the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2018, the Company had a total domestic pre-tax book income of ~~$112~~$361 million and an immaterial foreign pre-tax book ~~income of $13 million.~~income. As of December 31, ~~2016,~~2017, the Company had cumulative domestic Federal NOL carryforwards of ~~$3.4~~$2.8 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~~$2.2 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of ~~$196~~$224 million, which do not have an expiration date. Contingent upon GenOn's emergence from bankruptcy, the Company will recognize an estimated ~~$7.8~~$9.7 billion worthless stock deduction for tax purposes. ~~The NOL balances of $1.2 billion will remain with the GenOn group of companies upon emergence from bankruptcy.~~

In addition to these amounts, the Company has ~~$36~~$39 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 ~~$25~~$20 million in ~~2017.~~2018.

The Company has recorded a non-current tax liability of ~~$40~~$39 million until final resolution with the related taxing authority. The ~~$40~~$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~~no longer 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~~before 2010.

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.

Retained or Contingent Interests

NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of ~~September~~June 30, ~~2017~~2018, 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 ~~$616 million~~$1.2 billion as of ~~September~~June 30, ~~2017~~2018. 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~~2017 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~~2017 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 ~~nine~~six months ended ~~September~~June 30, ~~2017~~2018.

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~~2017 Form 10‑K.

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at ~~September~~June 30, ~~2017~~2018, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at ~~September~~June 30, ~~2017~~2018.

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



Derivative Activity Gains	(In millions)
Fair Value of Contracts as of December 31, 2017	$	46
Contracts realized or otherwise settled during the period	9
Contracts acquired during the period	11
Changes in fair value	217
Fair Value of Contracts as of June 30, 2018	$	283


	Fair Value of Contracts as of September 30, 2017															Fair Value of Contracts as of June 30, 2018
	Maturity															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			1 Year or Less			Greater than 1 Year to 3 Years			Greater than 3 Years to 5 Years			Greater than 5 Years			Total Fair Value
	(In millions)															(In millions)
Level 1	$	(34	)	$	(30	)	$	(5	)	$	—		$	(69	)	$	(9	)	$	(30	)	$	(8	)	$	(1	)	$	(48	)
Level 2	11			(28		)	(14		)	—			(31		)	10			137			16			15			178
Level 3	(24		)	(11		)	(5		)	(8		)	(48		)	141			32			(6		)	(14		)	153
Total	$	(47	)	$	(69	)	$	(24	)	$	(8	)	$	(148	)	$	142		$	139		$	2		$	—		$	283

The Company has elected to present derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3 - Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of ~~September~~June 30, ~~2017,~~2018, NRG's net derivative ~~liability~~asset was ~~$148~~$283 million, ~~a decrease~~an increase to total fair value of ~~$20~~$237 million as compared to December 31, ~~2016.~~2017. This ~~decrease~~increase was driven by ~~losses~~gains in fair value, ~~largely offset by~~acquired contracts, and 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~~a decrease of approximately ~~$39~~$191 million in the net value of derivatives as of ~~September~~June 30, ~~2017.~~2018. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in ~~a decrease~~an increase of approximately ~~$62~~$183 million in the net value of derivatives as of ~~September~~June 30, ~~2017.~~2018.

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’s~~Company's annual budget is utilized to determine the cash flows associated with the ~~Company’s~~Company's long-lived assets, which incorporates various assumptions, including the ~~Company’s~~Company's long-term view of natural gas prices and its impact on merchant power prices and fuel costs. The ~~Company’s~~Company's annual budget process is finalized and approved by the Board of Directors in the fourth quarter. It is reasonably possible that the updated ~~long term~~long-term cash flows will not support the carrying value of certain assets, and the Company will be required to test such assets for impairment. This could also have a negative impact on the fair value of the reporting units that have goodwill balances. This decrease in power prices could also result in an adverse change in the manner that long-lived assets are used, or result in the Company selling an asset before the end of its previously estimated useful life, at a price that is lower than its carrying amount. ~~During the preparation of the budget, the Company noted that management’s view of long term merchant power prices has decreased, and accordingly,~~Accordingly, if these decreases continue, it is ~~reasonably~~ possible that ~~certain of~~ the Company's goodwill ~~and/~~or long-lived assets will be ~~significantly impaired during the fourth quarter of 2017.~~

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~~2017 Form 10-K.

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities and correlations between various commodities, such as natural gas, electricity, coal, oil and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of its energy assets and liabilities, which includes generation assets, load obligations and bilateral physical and financial transactions.

The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions, calculated using the VaR model for the three and ~~nine~~six months ~~ended~~ending ~~September~~June 30, ~~2017~~2018 and ~~2016~~2017:


(In millions)	2017		2016		2018		2017
VaR as of September 30,	$	40	$	40
Three months ended September 30,
VaR as of June 30,					$	54	$	49
Three months ended June 30,
Average	$	30	$	59	$	59	$	59
Maximum	40		72		68		66
Minimum	25		40		52		49
Nine months ended September 30,
Six months ended June 30,
Average	$	27	$	58	59		$	56
Maximum	40		72		69		66
Minimum	20		40		48		41

In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of ~~September~~June 30, ~~2017~~2018, for the entire term of these instruments entered into for both asset management and trading was ~~$17~~$25 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~~2017 Form 10-K for more information on the Company's interest rate swaps.

If all of the above swaps had been discontinued on ~~September~~June 30, ~~2017~~2018, the Company would have owed the counterparties $4379 million. Based on the credit ratings of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of ~~September~~June 30, ~~2017~~2018, a 1% change in variable interest rates would result in a $~~13.8~~14.3 million change in interest expense on a rolling ~~twelve month~~twelve-month basis.

As of ~~September~~June 30, ~~2017~~2018, the fair value and related carrying value of the Company's debt was ~~$17.4~~$16.2 billion and ~~$17.1~~$16.0 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 ~~$984~~$981 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 $~~164~~61 million as of ~~September~~June 30, ~~2017~~2018, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $~~149~~44 million as of ~~September~~June 30, ~~2017~~2018. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of ~~September~~June 30, ~~2017~~2018.

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~~NRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the ~~third~~ quarter ~~of 2017~~ended June 30, 2018 that materially affected, or are reasonably likely to materially affect, ~~NRG’s~~NRG's internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through ~~September~~June 30, ~~2017~~2018, 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~~2017 Form ~~10-K, and Part II, Item 1A of the Company's Form 10-Q for the quarter ended June 30, 2017.~~10-K. There have been no material changes in the Company's risk factors since those reported in its ~~2016~~2017 Form 10‑~~K and its Form 10-Q for the quarter ended June 30, 2017.~~K.

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

~~None.~~In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock, with the first $500 million program beginning as soon as permitted. The authorization did not specify an expiration date.

The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act), of NRG's common stock during the quarter ended June 30, 2018.



For the three months ended June 30, 2018	Total Number of Shares Purchased	Average Price Paid per Share^(a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs^(b)
Month #1
(April 1, 2018 to April 30, 2018)	1,779,530	$	29.98	1,779,530	$	853,952,158
Month #2
(May 1, 2018 to May 31, 2018)	9,969,023	$	32.69	9,969,023	$	499,950,111
Month #3
(June 1, 2018 to June 30, 2018)	—	$	—	—	$	499,950,111
Total at June 30, 2018	11,748,553			11,748,553

(a) The average price paid per share excludes commissions of $0.01 per share paid in connection with the April share repurchases.

(b) Includes commissions of $0.01 per share paid in connection with the April share repurchases.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

See Note 3, Discontinued Operations ~~Dispositions~~ and ~~Acquisitions~~Dispositions, to the Condensed Consolidated Financial Statements of ~~this~~the Company's 2017 Form ~~10-Q,~~10-K, for a description of events of default by GenOn and GenOn Americas Generation under the GenOn Senior Notes and the GenOn Americas Generation Senior Notes.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

ITEM 6 — EXHIBITS



Number	Description	Method of Filing
4.1	Indenture, dated May 24, 2018, among NRG Energy, Inc., the guarantors named therein and Delaware Trust Company, as trustee.	Incorporated herein by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on May 25, 2018.
4.2	Form of 2.75% Convertible Senior Notes due 2048.	Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed on May 25, 2018.
10.1	~~Amended and Restated Backstop Commitment Letter,~~Third Amendment Agreement, dated as of ~~October 2, 2017,~~May 7, 2018, by and among ~~GenOn~~NRG Energy, Inc., ~~GenOn Americas Generation, LLC,~~its subsidiaries parties thereto, the ~~guarantors party~~lenders from time to time parties thereto and ~~backstop parties thereto.~~Citicorp North America, Inc., as administrative agent and collateral agent.	Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on ~~October 6, 2017.~~May 7, 2018.
10.2	~~First Amendment, dated as of October 2, 2017, to the Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC,~~ NRG Energy, Inc. Amended and ~~the consenting noteholders party thereto.~~Restated Executive Change-in-Control and General Severance Plan for Tier IA and Tier IIA Executives (Amended and Restated Effective April 1, 2018).	~~Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on October 6, 2017.~~
~~10.3~~	Consent Agreement, dated as of October 30, 2017, by and among GenOn Energy, Inc, GenOn Americas Generation LLC, and certain of their directly and indirectly owned subsidiaries listed on the signature pages thereto, and the Required Consenting Noteholders.	~~Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on November 1, 2017.~~Filed herewith.
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.

SIGNATURES

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



	NRG ENERGY, INC. (Registrant)

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


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


	/s/ DAVID CALLEN
	David Callen
Date: ~~November~~August 2, ~~2017~~2018	Chief Accounting Officer (Principal Accounting Officer)

~~107~~110



CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	5
PART I — FINANCIAL INFORMATION	10
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	10
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	6567
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	~~102~~105
ITEM 4 — CONTROLS AND PROCEDURES	~~104~~107
PART II — OTHER INFORMATION	~~105~~108
ITEM 1 — LEGAL PROCEEDINGS	~~105~~108
ITEM 1A — RISK FACTORS	~~105~~108
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	~~105~~108
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	~~105~~108
ITEM 4 — MINE SAFETY DISCLOSURES	~~105~~108
ITEM 5 — OTHER INFORMATION	~~105~~108
ITEM 6 — EXHIBITS	~~106~~109
SIGNATURES	~~107~~110



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



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



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



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



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



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



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



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



	Maintenance		Environmental		Growth Investments			Total
	(In millions)
Generation
Gulf Coast	$	73	$	1	$	3		$	77
East/West	17		24		240			281
Retail	22		—		33			55
Renewables	3		—		309			312
NRG Yield	21		—		2			23
Corporate	11		—		1			12
Total cash capital expenditures for the nine months ended September 30, 2017	147		25		588			760
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(815		)	(815		)
Other investments ^(a)	—		—		95			95
Total capital expenditures and investments, net of financings	147		25		(132		)	40

Estimated capital expenditures for the remainder of 2017	76		10		430			516
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(211		)	(211		)
NRG estimated capital expenditures for the remainder of 2017, net of financings	$	76	$	10	$	219		$	305



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



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