UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

		For the Quarterly Period Ended: ~~June~~September 30, 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 ~~June~~September 30, 2018, there were ~~303,429,305~~289,930,024 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, 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 obtain and maintain retail market share;

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 changes in market rules, rates, tariffs and environmental laws;

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~~complete the sale of certain assets to ~~NRG Yield,~~Clearway Energy, 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:



2017 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 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 - updates to the ASC
Average realized prices		Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
BACT		Best Available Control Technology
Bankruptcy Code		Chapter 11 of Title 11 the U.S. Bankruptcy Code
Bankruptcy Court		United States Bankruptcy Court for the Southern District of Texas, Houston Division
BETM		Boston Energy Trading and Marketing LLC
BTU		British Thermal Unit
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
Carlsbad		Collectively, Carlsbad Energy Holdings LLC and Carlsbad Energy Center LLC
CASPR		Competitive Auctions with Sponsored Resources
CDD		Cooling Degree Day
CDWR		California Department of Water Resources
CEC		California Energy Commission
CenterPoint		CenterPoint Energy 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.
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



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
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 $395 million outstanding unsecured senior notes consisting of $208 million of 8.5% senior notes due 2021 and $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		International Accounting Standards Board
IFRS		International Financial Reporting Standards
IPA		Illinois 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, LLC
LIBOR		London Inter-Bank Offered Rate
LTIPs		Collectively, the NRG LTIP and the NRG GenOn 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., which changed it's name to Clearway Energy, Inc. following the ~~owner of 54.8% of the economic interests~~sale by NRG of NRG Yield ~~LLC with a controlling interest,~~ and ~~issuer of publicly held shares of Class A and Class C common stock~~the Renewables Platform to GIP
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
Pipeline		Projects that range from identified lead to shortlisted with an offtake and ~~represents~~represent a lower level of execution certainty.
PJM		PJM Interconnection, LLC



PML		NRG Power Marketing LLC
PPA		Power Purchase Agreement
PSD		Prevention of Significant Deterioration
PTC		Production Tax Credit
PUCT		Public Utility Commission of Texas
PUHCA		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
Renewables		Consists of the following projects retained by NRG: Agua, Ivanpah, Guam, NFL stadiums
Renewables Platform		The renewable operating and development platform sold to GIP with NRG's interest in NRG Yield.
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, 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~~$2.4 billion revolving credit facility, a component of the Senior Credit Facility. The revolving credit facility consists of ~~$289~~$169 million of Tranche A Revolving Credit Facility, due ~~2018,~~2021, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021
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 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
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, comprised of the Revolving Credit Facility and the 2023 Term Loan Facility
Senior Notes		As of December 31, 2017, NRG’s $4.8 billion outstanding unsecured senior notes consisting of $992 million of 6.25% senior notes due 2022, $733 million of 6.25% senior notes due 2024, $1.0 billion of 7.25% senior notes due 2026, $1.25 billion of 6.625% senior notes due 2027, and $870 million of 5.75% senior notes due 2028.
Services Agreement		NRG 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~~GenOn.
SIFMA		Securities Industry and Financial Markets Association
SO₂		Sulfur Dioxide



South Central		NRG's South Central business, which owns and operates a 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
SREC		Solar renewable energy credit



TCPA		Telephone Consumer Protection Act
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~~level.
VaR		Value at Risk
VCP		Voluntary Clean-Up Program
VIE		Variable Interest Entity
WECC		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 June 30,						Six months ended June 30,						Three months ended September 30,								Nine months ended September 30,
(In millions, except for per share amounts)	2018			2017			2018			2017			2018				2017				2018			2017
Operating Revenues
Total operating revenues	$	2,922		$	2,701		$	5,343		$	5,083		$	3,061			$	2,740			$	7,795		$	7,246
Operating Costs and Expenses
Cost of operations	2,051			1,841			3,609			3,704			2,307				2,072				5,730			5,589
Depreciation and amortization	227			260			462			517			112				163				370			490
Impairment losses	74			63			74			63			—				—				74			60
Selling, general and administrative	211			221			402			481			212				190				591			634
Reorganization costs	23			—			43			—			27				12				70			18
Development costs	16			18			29			35			1				6				9			18
Total operating costs and expenses	2,602			2,403			4,619			4,800			2,659				2,443				6,844			6,809
Other income - affiliate	—			39			—			87			—				—				—			87
Gain on sale of assets	14			2			16			4			14				—				30			4
Operating Income	334			339			740			374			416				297				981			528
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	18			(3		)	16			2			20				9				26			(20		)
Other income/(expense), net	(20		)	14			(23		)	26			17				19			—	(4		)	43
Loss on debt extinguishment, net	(1		)	—			(3		)	(2		)	(19		)		—				(22		)	—
Interest expense	(202		)	(247		)	(369		)	(471		)	(121		)		(139		)		(361		)	(432		)
Total other expense	(205		)	(236		)	(379		)	(445		)	(103		)		(111		)		(361		)	(409		)
Income/(Loss) from Continuing Operations Before Income Taxes	129			103			361			(71		)
Income tax expense/(benefit)	8			4			7			(1		)
Income/(Loss) from Continuing Operations	121			99			354			(70		)
Income from Continuing Operations Before Income Taxes													313				186				620			119
Income tax expense													7			—	1				19			3
Income from Continuing Operations													306				185				601			116
Loss from discontinued operations, net of income tax	(25		)	(741		)	(25		)	(775		)	(354		)		(22		)		(320		)	(798		)
Net Income/(Loss)	96			(642		)	329			(845		)
Net (Loss)/Income													(48		)		163				281			(682		)
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interests	24			(16		)	(22		)	(55		)	24				(8		)		1			(63		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	72		$	(626	)	$	351		$	(790	)
Earnings/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders
Net (Loss)/Income Attributable to NRG Energy, Inc. common stockholders													$	(72	)		$	171			$	280		$	(619	)
(Loss)/Earnings per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	310			316			314			316			299				317				309			317
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	)
Income from continuing operations per weighted average common share — basic													$	0.94			$	0.61			$	1.94		$	0.56
Loss from discontinued operations per weighted average common share — basic													$	(1.18	)		$	(0.07	)		$	(1.03	)	$	(2.51	)
(Loss)/Earnings per Weighted Average Common Share — Basic													$	(0.24	)		$	0.54			$	0.91		$	(1.95	)
Weighted average number of common shares outstanding — diluted	314			316			318			316			299				322				313			317
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	)
Income from continuing operations per weighted average common share — diluted													$	0.94			$	0.60			$	1.91		$	0.56
Loss from discontinued operations per weighted average common share — diluted													$	(1.18	)		$	(0.07	)		$	(1.02	)	$	(2.51	)
(Loss)/Earnings per Weighted Average Common Share — Diluted													$	(0.24	)		$	0.53			$	0.89		$	(1.95	)
Dividends Per Common Share	$	0.03		$	0.03		$	0.06		$	0.06		$	0.03			$	0.03			$	0.09		$	0.09

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

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

(Unaudited)

Three months ended June 30,
Six months ended June 30,

2018
2017
2018
2017

(In millions)
Net income/(loss) $ 96

$ (642 )
$ 329

$ (845 )
Other comprehensive income/(loss), net of tax

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 (4 )
1

(6 )
8
Available-for-sale securities, net of income tax expense of $0, $0, $0, and $0 1

1

1

1
Defined benefit plans, net of income tax expense of $0, $0, $0, and $0 (1 )
27

(2 )
27
Other comprehensive income 1

24

12

35
Comprehensive income/(loss) 97

(618 )
341

(810 )
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest 26

(17 )
(12 )
(56 )
Comprehensive income/(loss) attributable to NRG Energy, Inc. 71

(601 )
353

(754 )
Comprehensive income/(loss) available for common stockholders $ 71

$ (601 )
$ 353

$ (754 )



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(In millions)
Net (loss)/income	$	(48	)	$	163		$	281		$	(682	)
Other comprehensive income/(loss), net of tax
Unrealized gain on derivatives, net of income tax expense of $0, $0, $1, and $0	4			7			24			7
Foreign currency translation adjustments, net of income tax expense of $0, $0, $0, and $0	(2		)	2			(8		)	9
Available-for-sale securities, net of income tax expense of $0, $0, $0, and $0	—			1			1			2
Defined benefit plans, net of income tax expense of $0, $0, $0, and $0	(1		)	(1		)	(3		)	25
Other comprehensive income	1			9			14			43
Comprehensive (loss)/income	(47		)	172			295			(639		)
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	26			(5		)	15			(61		)
Comprehensive (loss)/income attributable to NRG Energy, Inc. common stockholders	$	(73	)	$	177		$	280		$	(578	)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30, 2018			December 31, 2017			September 30, 2018			December 31, 2017^(a)
(In millions, except shares)	(Unaudited)						(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	980		$	991		$	1,359		$	767
Funds deposited by counterparties	71			37			30			37
Restricted cash	286			508			28			279
Accounts receivable, net	1,371			1,079			1,297			960
Inventory	485			532			408			486
Derivative instruments	851			626			683			624
Cash collateral paid in support of energy risk management activities	224			171			209			171
Accounts receivable - affiliate	57			95			19			186
Prepayments and other current assets							248			179
Current assets - held for sale	100			115			—			116
Prepayments and other current assets	328			261
Current assets - discontinued operations							4			705
Total current assets	4,753			4,415			4,285			4,510
Property, plant and equipment, net	12,774			13,908			3,599			6,435
Other Assets
Equity investments in affiliates	1,055			1,038			452			182
Notes receivable, less current portion	15			2			10			2
Goodwill	539			539			539			539
Intangible assets, net	1,860			1,746			602			507
Nuclear decommissioning trust fund	694			692			719			692
Derivative instruments	426			172			392			159
Deferred income taxes	126			134			11			6
Other non-current assets							281			294
Non-current assets held-for-sale	50			43			—			43
Other non-current assets	655			629
Non-current assets - discontinued operations							560			10,181
Total other assets	5,420			4,995			3,566			12,605
Total Assets	$	22,947		$	23,318		$	11,450		$	23,550
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	952		$	688		$	593		$	204
Accounts payable	975			881			824			711
Accounts payable - affiliate	29			33			14			57
Derivative instruments	709			555			550			537
Cash collateral received in support of energy risk management activities	72			37			30			37
Current liabilities held-for-sale	74			72
Accrued expenses and other current liabilities	719			890			659			769
Accrued expenses and other current liabilities - affiliate	133			161			1			161
Current liabilities - held-for-sale							—			72
Current liabilities - discontinued operations							52			864
Total current liabilities	3,663			3,317			2,723			3,412
Other Liabilities
Non-Current Liabilities
Long-term debt and capital leases	14,821			15,716			6,658			9,180
Nuclear decommissioning reserve	274			269			278			269
Nuclear decommissioning trust liability	410			415			432			415
Deferred income taxes	17			21			18			21
Derivative instruments	285			197			357			143
Out-of-market contracts, net	195			207			177			195
Non-current liabilities held-for-sale	12			8
Other non-current liabilities	1,130			1,122			1,177			1,002
Non-current liabilities - held-for-sale							—			8
Non-current liabilities - discontinued operations							547			6,859
Total non-current liabilities	17,144			17,955			9,644			18,092
Total Liabilities	20,807			21,272			12,367			21,504
Redeemable noncontrolling interest in subsidiaries	69			78			19			78
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4			4			4
Additional paid-in capital	8,481			8,376			8,453			8,377
Accumulated deficit	(5,920		)	(6,268		)	(6,001		)	(6,269		)
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		)
Less treasury stock, at cost - 129,948,876 and 101,580,045 shares, at September 30, 2018 and December 31, 2017, respectively							(3,334		)	(2,386		)
Accumulated other comprehensive loss	(60		)	(72		)	(58		)	(72		)
Noncontrolling interest	2,437			2,314			—			2,314
Total Stockholders’ Equity	2,071			1,968			(936		)	1,968
Total Liabilities and Stockholders’ Equity	$	22,947		$	23,318		$	11,450		$	23,550

(a) Retrospectively adjusted as discussed in Note 1, Basis of Presentation.

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six months ended June 30,						Nine months ended September 30,
(In millions)	2018			2017			2018				2017
Cash Flows from Operating Activities
Net income/(loss)	$	329		$	(845	)	$	281			$	(682	)
Loss from discontinued operations, net of income tax	(25		)	(775		)	(320		)		(798		)
Income/(loss) from continuing operations	354			(70		)
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Income from continuing operations							601				116
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	27			26			10				—
Depreciation, amortization and accretion	485			517			403				490
Provision for bad debts	31			18			57				57
Amortization of nuclear fuel	24			24			38				37
Amortization of financing costs and debt discount/premiums	27			29			21				15
Adjustment for debt extinguishment	3			—			22				3
Amortization of intangibles and out-of-market contracts	48			51			21				79
Amortization of unearned equity compensation	26			16			36				27
Impairment losses	89			63			89				60
Changes in deferred income taxes and liability for uncertain tax benefits	4			8			(6		)		(1		)
Changes in nuclear decommissioning trust liability	41			2			50				20
Changes in derivative instruments	(211		)	7			(17		)		36
Changes in collateral deposits in support of energy risk management activities	(18		)	(189		)	(30		)		(103		)
Gain on sale of emission allowances	(11		)	11			(20		)		21
Gain on sale of assets	(16		)	(22		)	(30		)		(4		)
GenOn settlement in July 2018							(125		)		—
Loss on deconsolidation of business	22			—			13				—
Changes in other working capital	(401		)	(379		)	(375		)		(295		)
Cash provided by continuing operations	524			112			758				558
Cash used by discontinued operations	—			(38		)
Cash provided by discontinued operations							324				178
Net Cash Provided by Operating Activities	524			74			1,082				736
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(284		)	(16		)	(209		)		(12		)
Capital expenditures	(691		)	(542		)	(345		)		(172		)
Decrease in notes receivable	4			8
Purchases of emission allowances	(22		)	(30		)	(30		)		(47		)
Proceeds from sale of emission allowances	34			59			54			—	104
Investments in nuclear decommissioning trust fund securities	(346		)	(279		)	(449		)		(402		)
Proceeds from the sale of nuclear decommissioning trust fund securities	303			277			398				382
Proceeds from renewable energy grants and state rebates	—			8
Proceeds from sale of assets, net of cash disposed of	18			35
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees							1,555				309
Deconsolidation of business	(160		)	—			(268		)		—
Changes in investments in unconsolidated affiliates	(2		)	(30		)	(62		)		24
Other	—			18			—				30
Cash used by continuing operations	(1,146		)	(492		)
Cash provided by continuing operations							644				216
Cash used by discontinued operations	—			(53		)	(703		)		(638		)
Net Cash Used by Investing Activities	(1,146		)	(545		)
Net Cash (Used) by Investing Activities							(59		)		(422		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(19		)	(19		)
Payment of dividends to common stockholders							(28		)		(28		)
Payment for treasury stock	(500		)	—			(1,000		)		—
Net receipts from settlement of acquired derivatives that include financing elements	—			2
Proceeds from issuance of long-term debt	1,605			946			995				308
Payments for short and long-term debt	(848		)	(530		)	(970		)		(343		)
Increase in notes receivable from affiliate	—			(125		)
Net contributions from noncontrolling interests in subsidiaries	222			14
Receivable from affiliate							(26		)		(125		)
Net distributions to noncontrolling interests from subsidiaries							(17		)		(18		)
Payment of debt issuance costs	(37		)	(36		)	(19		)		(39		)
Other - contingent consideration	—			(10		)
Cash provided by continuing operations	423			242
Cash used by discontinued operations	—			(224		)
Net Cash Provided by Financing Activities	423			18
Other							(4		)		(8		)
Cash used by continuing operations							(1,069		)		(253		)
Cash provided by discontinued operations							403				39
Net Cash Used by Financing Activities							(666		)		(214		)
Effect of exchange rate changes on cash and cash equivalents	—			(8		)	1				(10		)
Change in Cash from discontinued operations	—			(315		)	24				(421		)
Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(199		)	(146		)
Net Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash							334				511
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	1,536			1,386			1,083				860
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	1,337		$	1,240		$	1,417			$	1,371

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 customer-driven integrated power company built on a portfolio of ~~leading~~dynamic retail electricity brands and diverse generation assets. NRG is continuously focused on serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels. The Company:

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

owns ~~and operates~~ approximately ~~30,000~~26,000 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 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 ~~June~~September 30, 2018, and the results of operations, comprehensive income/(loss) and cash flows for the three and ~~six~~nine months ended ~~June~~September 30, 2018 and 2017.

Discontinued Operations

On August 31, 2018, as described in Note 3, Acquisitions, Discontinued Operations and Dispositions, NRG deconsolidated NRG Yield, Inc. and its Renewables Platform for financial reporting purposes. The financial information for all historical periods has been recast to reflect the presentation of these entities, as well as the Carlsbad project, as discontinued operations. As a result of the sale of NRG Yield, the Company no longer controls the Agua Caliente project. Due to this change in control, the Company has also deconsolidated the Agua Caliente project from its financial results and has accounted for the project as an equity method investment.

GenOn Chapter 11 Cases

On June 14, 2017, 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, 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 determined that this disposal of GenOn and its subsidiaries is a discontinued operation and, accordingly, the financial information for all historical periods has been recast to reflect GenOn as a discontinued operation.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Reclassifications

Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.

Note 2 — Summary of Significant Accounting Policies

Other Balance Sheet Information

The following table presents the allowance for doubtful accounts included in accounts receivable, net; accumulated depreciation included in property, plant and equipment, net; accumulated amortization included in intangible assets, net and accumulated amortization included in out-of-market contracts, net:


	June 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
	(In millions)				(In millions)
Accounts receivable allowance for doubtful accounts	$	28	$	28	$	37	$	28
Property, plant and equipment accumulated depreciation	4,534		4,465		2,652		3,013
Intangible assets accumulated amortization	1,443		1,818		1,194		1,572
Out-of-market contracts accumulated amortization	370		358		372		354

Restricted Cash

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


	June 30, 2018		December 31, 2017		June 30, 2017		December 31, 2016		September 30, 2018		December 31, 2017		September 30, 2017		December 31, 2016
	(In millions)								(In millions)
Cash and cash equivalents	$	980	$	991	$	752	$	938	$	1,359	$	767	$	1,022	$	591
Funds deposited by counterparties	71		37		19		2		30		37		31		2
Restricted cash	286		508		469		446		28		279		318		267
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,337	$	1,536	$	1,240	$	1,386	$	1,417	$	1,083	$	1,371	$	860

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.

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.

Pension and Post Retirement Benefit Plan Amendments

In the fourth quarter of 2018, the Company will recognize a loss of $17 million related to curtailment of certain of the Company's pension plan. The Company also amended the post retirement benefit plan and, as a result of the subsequent plan remeasurement, will recognize a gain of $2 million.

Noncontrolling Interest

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


	(In millions)			(In millions)
Balance as of December 31, 2017	$	2,314		$	2,314
Dividends paid to NRG Yield, Inc. public shareholders	(61		)	(61		)
Distributions to noncontrolling interest	(34		)	(43		)
Comprehensive income attributable to noncontrolling interest	12
Net income attributable to noncontrolling interest - continuing operations				5
Net income attributable to noncontrolling interest - discontinued operations				21
Other comprehensive income attributable to noncontrolling interest - discontinued operations				14
Non-cash adjustments to noncontrolling interest	8			10
Contributions from noncontrolling interest	295			296
Sale of assets to NRG Yield, Inc.	(8		)	(8		)
Deconsolidation of Ivanpah^(a)	(89		)	(89		)
Balance as of June 30, 2018	$	2,437
Deconsolidation of Agua Caliente^(b)				(279		)
Deconsolidation of NRG Yield and the Renewables Platform^(b)				(2,180		)
Balance as of September 30, 2018				$	—

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

(b) See Note 3, Acquisitions, Discontinued Operations and Dispositions for further information regarding the sale of NRG Yield and the Renewables Platform and the deconsolidation of Agua Caliente.

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, 2017	$	78		$	78
Distributions to redeemable noncontrolling interest	(2		)	(3		)
Contributions from redeemable noncontrolling interest	26			26
Non-cash adjustments to redeemable noncontrolling interest	(9		)	(9		)
Comprehensive loss attributable to redeemable noncontrolling interest	(24		)
Balance as of June 30, 2018	$	69
Net income attributable to redeemable noncontrolling interest - continuing operations				1
Net income attributable to redeemable noncontrolling interest - discontinued operations				(26		)
Deconsolidation of NRG Yield and the Renewables Platform^(a)				(48		)
Balance as of September 30, 2018				$	19

(a) See Note 3, Acquisitions, Discontinued Operations and Dispositions for further information regarding the sale of NRG Yield and the Renewables Platform.

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~~that 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 and demand response 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 future revenues for cleared auction MWs in the various capacity auctions are ~~$578~~$152 million, ~~$519~~$610 million, ~~$410~~$459 million, ~~$388~~$528 million and ~~$168~~$244 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 expected 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~~nine months ended ~~June~~September 30, 2018, along with the reportable segment for each category:


	Three months ended June 30, 2018																					Three months ended September 30, 2018
			Generation																					Generation
(In millions)	Retail		Gulf Coast			East/West			Subtotal		Renewables		NRG Yield			Eliminations			Total			Retail		Gulf Coast			East/West/Other			Subtotal		Corporate/Eliminations			Total
Energy revenue^(b)(a)	$	—	$	508		$	144		$	652	$	79	$	192		$	(250	)	$	673		$	—	$	680		$	278		$	958	$	(479	)	$	479
Capacity revenue^(b)(a)	—		68			160			228		—		87			(2		)	313			—		66			187			253		1			254
Retail revenue
Mass customers	1,380		—			—			—		—		—			(1		)	1,379			1,768		—			—			—		(2		)	1,766
Business solutions customers	437		—			—			—		—		—			—			437
Business Solutions customers																						434		—			—			—		—			434
Total retail revenue	1,817		—			—			—		—		—			(1		)	1,816			2,202		—			—			—		(2		)	2,200
Mark-to-market for economic hedging activities^(c)(b)	—		289			(15		)	274		5		—			(264		)	15			1		268			27			295		(241		)	55
Contract amortization	—		4			—			4		—		(18		)	—			(14		)	—		5			—			5		—			5
Other revenue^(b)(c)	—		42			18			60		29		46			(16		)	119			—		36			32			68		—			68
Total operating revenue	1,817		911			307			1,218		113		307			(533		)	2,922			2,203		1,055			524			1,579		(721		)	3,061
Less: Lease revenue	6		—			1			1		96		267			—			370			3		—			3			3		—			6
Less: Derivative revenue	—		898			(1		)	897		5		—			(264		)	638			1		1,160			55			1,215		(241		)	975
Less: Contract amortization	—		4			—			4		—		(18		)	—			(14		)	—		5			—			5		—			5
Total revenue from contracts with customers	$	1,811	$	9		$	307		$	316	$	12	$	58		$	(269	)	$	1,928		$	2,199	$	(110	)	$	466		$	356	$	(480	)	$	2,075
(a) The following amounts of energy and capacity revenue relate to leases and are accounted for under ASC 840:
(a) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.																						(a) 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			Retail		Gulf Coast			East/West/Other			Subtotal		Corporate/Eliminations			Total
Energy revenue	$	—	$	—		$	—		$	—	$	90	$	182		$	—		$	272		$	—	$	896		$	(25	)	$	871	$	—		$	871
Capacity revenue	—		—			—			—		—		85			—			85			—		—			45			45		—			45
Other revenue	6		—			1			1		6		—			—			13			—		(4		)	8			4		—			4
(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.

(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.


	Six months ended June 30, 2018																								Nine months ended September 30, 2018
				Generation																								Generation
(In millions)	Retail			Gulf Coast			East/West			Subtotal			Renewables			NRG Yield			Eliminations			Total			Retail			Gulf Coast				East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue^(b)(a)	$	—		$	879		$	362		$	1,241		$	156		$	306		$	(411	)	$	1,292		$	—		$	1,558			$	735		$	2,293		$	(890	)	$	1,403
Capacity revenue^(b)(a)	—			135			300			435			—			169			(3		)	601			—			201			—	487		—	688			—			688
Retail revenue
Mass customers	2,551			—			—			—			—			—			(2		)	2,549			4,321			—				—			—			(4		)	4,317
Business solutions customers	753			—			—			—			—			—			—			753
Business Solutions customers																									1,181			—				—			—			—			1,181
Total retail revenue	3,304			—			—			—			—			—			(2		)	3,302			5,502			—				—			—			(4		)	5,498
Mark-to-market for economic hedging activities^(c)(b)	(6		)	(275		)	(25		)	(300		)	(5		)	—			220			(91		)	(5		)	(7		)		2			(5		)	(21		)	(31		)
Contract amortization	—			7			—			7			—			(35		)	—			(28		)	—			12				—			12			—			12
Other revenue^(b)(c)	—			128			34			162			48			92			(35		)	267			—			164				64			228			(3		)	225
Total operating revenue	3,298			874			671			1,545			199			532			(231		)	5,343			5,497			1,928				1,288			3,216			(918		)	7,795
Less: Lease revenue	12			—			2			2			160			448			—			622			10			—				6			6			—			16
Less: Derivative revenue	(6		)	710			79			789			(5		)	—			220			998			(5		)	1,871				135			2,006			—			2,001
Less: Contract amortization	—			7			—			7			—			(35		)	—			(28		)	—			12				—			12			—			12
Total revenue from contracts with customers	$	3,292		$	157		$	590		$	747		$	44		$	119		$	(451	)	$	3,751		$	5,492		$	45			$	1,147		$	1,192		$	(918	)	$	5,766
(a) The following amounts of energy and capacity revenue relate to leases and are accounted for under ASC 840:
(a) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.																									(a) 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			Retail			Gulf Coast				East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	—		$	—		$	—		$	151		$	284		$	—		$	435		$	—		$	1,877			$	7		$	1,884		$	—		$	1,884
Capacity revenue	—			—			—			—			—			164			—			164			—			—				110			110			—			110
Other revenue	12			—			2			2			9			—			—			23			—			1				16			17			—			17
(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.

(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.

(c) Included in other revenue is lease revenue of $10 million and $6 million for Retail and East/West/Other, respectively.

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~~Discontinued Operations

~~Certain~~On August 31, 2018, as described in Note 3, Acquisitions, Discontinued Operations and Dispositions, NRG deconsolidated NRG Yield, Inc. and its Renewables Platform for financial reporting purposes. The financial information for all historical periods has been recast to reflect the presentation of these entities, as well as the Carlsbad project, as discontinued operations. As a result of the ~~Company’s revenues are obtained through PPAs or other contractual agreements. Many~~sale of ~~these agreements are~~NRG Yield, the Company no longer controls the Agua Caliente project. Due to this change in control, the Company has also deconsolidated the Agua Caliente project from its financial results and has accounted for the project as ~~operating leases~~an equity method investment.

GenOn Chapter 11 Cases

On June 14, 2017, 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 ~~ASC 840 Leases. Certain of these leases have no minimum lease payments and all~~Chapter 11, or the Chapter 11 Cases, of the ~~rent~~U.S. 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 determined that this disposal of GenOn and its subsidiaries is ~~recorded~~a discontinued operation and, accordingly, the financial information for all historical periods has been recast to reflect GenOn as a discontinued operation.

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 ~~rent on an actual basis when~~assets and liabilities at the ~~electricity is delivered. Judgment is required by management in determining~~date of the ~~economic life~~financial statements, and the reported amounts of ~~each generating facility, in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent~~revenues and ~~other factors in determining whether a contract contains a lease and whether~~expenses during the ~~lease is an operating lease or capital lease.~~

reporting period. Actual results could differ from these estimates.

~~Contract Balances~~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



	September 30, 2018		December 31, 2017
	(In millions)
Accounts receivable allowance for doubtful accounts	$	37	$	28
Property, plant and equipment accumulated depreciation	2,652		3,013
Intangible assets accumulated amortization	1,194		1,572
Out-of-market contracts accumulated amortization	372		354

Restricted Cash



	September 30, 2018		December 31, 2017		September 30, 2017		December 31, 2016
	(In millions)
Cash and cash equivalents	$	1,359	$	767	$	1,022	$	591
Funds deposited by counterparties	30		37		31		2
Restricted cash	28		279		318		267
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,417	$	1,083	$	1,371	$	860

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.

Pension and Post Retirement Benefit Plan Amendments

Noncontrolling Interest

The following table reflects the ~~contract assets and liabilities included~~changes in ~~the Company’s balance sheet as of June 30, 2018:~~NRG's noncontrolling interest balance:

(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 2018~~



	(In millions)
Balance as of December 31, 2017	$	2,314
Dividends paid to NRG Yield, Inc. public shareholders	(61		)
Distributions to noncontrolling interest	(43		)
Net income attributable to noncontrolling interest - continuing operations	5
Net income attributable to noncontrolling interest - discontinued operations	21
Other comprehensive income attributable to noncontrolling interest - discontinued operations	14
Non-cash adjustments to noncontrolling interest	10
Contributions from noncontrolling interest	296
Sale of assets to NRG Yield, Inc.	(8		)
Deconsolidation of Ivanpah^(a)	(89		)
Deconsolidation of Agua Caliente^(b)	(279		)
Deconsolidation of NRG Yield and the Renewables Platform^(b)	(2,180		)
Balance as of September 30, 2018	$	—

~~ASU 2017-07~~(a) See Note 9, Variable Interest Entities, or VIEs ~~— In March 2017,~~for further information regarding the ~~FASB issued ASU No. 2017-07,~~ ~~Compensation - Retirement Benefits (Topic 715), Improving the Presentation~~deconsolidation 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. 2017-07Ivanpah effective ~~January 1,~~April 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, and interim periods within those annual periods. The Company adopted the amendments of ASU No. 2016-01 effective January 1, 2018. In connection with the adoption of the standard, the Company has applied the guidance on 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 will adopt the standard effective January 1, 2019, 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. The Company is also monitoring recent changes to Topic 842 and the related impact on the implementation process.

(b) See Note 3, — Acquisitions, Discontinued Operations and Dispositions for further information regarding the sale of NRG Yield and the Renewables Platform and the deconsolidation of Agua Caliente.

Redeemable Noncontrolling Interest

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



	(In millions)
Balance as of December 31, 2017	$	78
Distributions to redeemable noncontrolling interest	(3		)
Contributions from redeemable noncontrolling interest	26
Non-cash adjustments to redeemable noncontrolling interest	(9		)
Net income attributable to redeemable noncontrolling interest - continuing operations	1
Net income attributable to redeemable noncontrolling interest - discontinued operations	(26		)
Deconsolidation of NRG Yield and the Renewables Platform^(a)	(48		)
Balance as of September 30, 2018	$	19

~~This footnote should be read in conjunction with the complete description under~~(a) See Note 3, Acquisitions, Discontinued Operations ~~Acquisitions~~ and Dispositions~~, to~~ for further information regarding the ~~Company's 2017 Form 10-K.~~sale of NRG Yield and the Renewables Platform.

~~Acquisitions~~Revenue Recognition

~~XOOM Energy Acquisition —~~ Revenue from Contracts with Customers

On ~~June~~January 1, 2018, the Company adopted the guidance in ASC 606 using the modified retrospective method applied to contracts that were not completed as of the ~~acquisition~~adoption date. The Company recognized the cumulative effect of ~~XOOM Energy, LLC, an electricity and natural gas retailer operating~~initially applying the new standard as a credit to the opening balance of accumulated deficit, resulting in ~~19 states, Washington, D.C. and Canada for approximately $219 million in cash, inclusive~~a decrease of approximately ~~$54 million~~$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 ~~payments~~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

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 ~~working capital,~~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.

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 ~~subject~~equal to ~~further adjustment.~~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 and demand response 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 ~~acquisition increased~~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 ~~retail portfolio~~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 future revenues for cleared auction MWs in the various capacity auctions are $152 million, $610 million, $459 million, $528 million and $244 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 ~~approximately 300,000 customers.~~ 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.

Renewable Energy Credits

Sale of Emission Allowances

The ~~purchase price was provisionally allocated~~Company records its inventory of emission allowances as ~~follows: $2~~part of intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of expected 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 nine months ended September 30, 2018, along with the reportable segment for each category:



	Three months ended September 30, 2018
			Generation
(In millions)	Retail		Gulf Coast			East/West/Other			Subtotal		Corporate/Eliminations			Total
Energy revenue^(a)	$	—	$	680		$	278		$	958	$	(479	)	$	479
Capacity revenue^(a)	—		66			187			253		1			254
Retail revenue
Mass customers	1,768		—			—			—		(2		)	1,766
Business Solutions customers	434		—			—			—		—			434
Total retail revenue	2,202		—			—			—		(2		)	2,200
Mark-to-market for economic hedging activities^(b)	1		268			27			295		(241		)	55
Contract amortization	—		5			—			5		—			5
Other revenue^(a)(c)	—		36			32			68		—			68
Total operating revenue	2,203		1,055			524			1,579		(721		)	3,061
Less: Lease revenue	3		—			3			3		—			6
Less: Derivative revenue	1		1,160			55			1,215		(241		)	975
Less: Contract amortization	—		5			—			5		—			5
Total revenue from contracts with customers	$	2,199	$	(110	)	$	466		$	356	$	(480	)	$	2,075
(a) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.
	Retail		Gulf Coast			East/West/Other			Subtotal		Corporate/Eliminations			Total
Energy revenue	$	—	$	896		$	(25	)	$	871	$	—		$	871
Capacity revenue	—		—			45			45		—			45
Other revenue	—		(4		)	8			4		—			4

(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.



	Nine months ended September 30, 2018
				Generation
(In millions)	Retail			Gulf Coast				East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue^(a)	$	—		$	1,558			$	735		$	2,293		$	(890	)	$	1,403
Capacity revenue^(a)	—			201			—	487		—	688			—			688
Retail revenue
Mass customers	4,321			—				—			—			(4		)	4,317
Business Solutions customers	1,181			—				—			—			—			1,181
Total retail revenue	5,502			—				—			—			(4		)	5,498
Mark-to-market for economic hedging activities^(b)	(5		)	(7		)		2			(5		)	(21		)	(31		)
Contract amortization	—			12				—			12			—			12
Other revenue^(c)	—			164				64			228			(3		)	225
Total operating revenue	5,497			1,928				1,288			3,216			(918		)	7,795
Less: Lease revenue	10			—				6			6			—			16
Less: Derivative revenue	(5		)	1,871				135			2,006			—			2,001
Less: Contract amortization	—			12				—			12			—			12
Total revenue from contracts with customers	$	5,492		$	45			$	1,147		$	1,192		$	(918	)	$	5,766
(a) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.
	Retail			Gulf Coast				East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	1,877			$	7		$	1,884		$	—		$	1,884
Capacity revenue	—			—				110			110			—			110
Other revenue	—			1				16			17			—			17

(b) Revenue relates entirely to ~~cash, $8~~unrealized gains and losses on derivative instruments accounted for under ASC 815.

(c) Included in other revenue is lease revenue of $10 million and $6 million for Retail and East/West/Other, respectively.

Contract Amortization

Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to ~~restricted cash, $46 million~~the sale of electric capacity and energy in future periods for which the fair value has been determined to ~~accounts receivable, $42 million~~be significantly less (more) than market are amortized 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.revenue over the term of each underlying contract based on actual generation and/or contracted volumes.

Discontinued Operations

GenOn Chapter 11 Cases

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



	September 30, 2018		December 31, 2017
	(In millions)
Accounts receivable allowance for doubtful accounts	$	37	$	28
Property, plant and equipment accumulated depreciation	2,652		3,013
Intangible assets accumulated amortization	1,194		1,572
Out-of-market contracts accumulated amortization	372		354

Restricted Cash



	September 30, 2018		December 31, 2017		September 30, 2017		December 31, 2016
	(In millions)
Cash and cash equivalents	$	1,359	$	767	$	1,022	$	591
Funds deposited by counterparties	30		37		31		2
Restricted cash	28		279		318		267
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,417	$	1,083	$	1,371	$	860

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.

Pension and Post Retirement Benefit Plan Amendments

Noncontrolling Interest

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



	(In millions)
Balance as of December 31, 2017	$	2,314
Dividends paid to NRG Yield, Inc. public shareholders	(61		)
Distributions to noncontrolling interest	(43		)
Net income attributable to noncontrolling interest - continuing operations	5
Net income attributable to noncontrolling interest - discontinued operations	21
Other comprehensive income attributable to noncontrolling interest - discontinued operations	14
Non-cash adjustments to noncontrolling interest	10
Contributions from noncontrolling interest	296
Sale of assets to NRG Yield, Inc.	(8		)
Deconsolidation of Ivanpah^(a)	(89		)
Deconsolidation of Agua Caliente^(b)	(279		)
Deconsolidation of NRG Yield and the Renewables Platform^(b)	(2,180		)
Balance as of September 30, 2018	$	—

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

(b) See Note 3, Acquisitions, Discontinued Operations and Dispositions for further information regarding the sale of NRG Yield and the Renewables Platform and the deconsolidation of Agua Caliente.

Redeemable Noncontrolling Interest

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



	(In millions)
Balance as of December 31, 2017	$	78
Distributions to redeemable noncontrolling interest	(3		)
Contributions from redeemable noncontrolling interest	26
Non-cash adjustments to redeemable noncontrolling interest	(9		)
Net income attributable to redeemable noncontrolling interest - continuing operations	1
Net income attributable to redeemable noncontrolling interest - discontinued operations	(26		)
Deconsolidation of NRG Yield and the Renewables Platform^(a)	(48		)
Balance as of September 30, 2018	$	19

(a) See Note 3, Acquisitions, Discontinued Operations and Dispositions for further information regarding the sale of NRG Yield and the Renewables Platform.

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 that 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

Energy Revenue

Capacity Revenue

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 future revenues for cleared auction MWs in the various capacity auctions are $152 million, $610 million, $459 million, $528 million and $244 million for fiscal years 2018, 2019, 2020, 2021 and 2022, respectively.

Renewable Energy Credits

Sale of Emission Allowances

Disaggregated Revenues



	Three months ended September 30, 2018
			Generation
(In millions)	Retail		Gulf Coast			East/West/Other			Subtotal		Corporate/Eliminations			Total
Energy revenue^(a)	$	—	$	680		$	278		$	958	$	(479	)	$	479
Capacity revenue^(a)	—		66			187			253		1			254
Retail revenue
Mass customers	1,768		—			—			—		(2		)	1,766
Business Solutions customers	434		—			—			—		—			434
Total retail revenue	2,202		—			—			—		(2		)	2,200
Mark-to-market for economic hedging activities^(b)	1		268			27			295		(241		)	55
Contract amortization	—		5			—			5		—			5
Other revenue^(a)(c)	—		36			32			68		—			68
Total operating revenue	2,203		1,055			524			1,579		(721		)	3,061
Less: Lease revenue	3		—			3			3		—			6
Less: Derivative revenue	1		1,160			55			1,215		(241		)	975
Less: Contract amortization	—		5			—			5		—			5
Total revenue from contracts with customers	$	2,199	$	(110	)	$	466		$	356	$	(480	)	$	2,075
(a) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.
	Retail		Gulf Coast			East/West/Other			Subtotal		Corporate/Eliminations			Total
Energy revenue	$	—	$	896		$	(25	)	$	871	$	—		$	871
Capacity revenue	—		—			45			45		—			45
Other revenue	—		(4		)	8			4		—			4

(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.



	Nine months ended September 30, 2018
				Generation
(In millions)	Retail			Gulf Coast				East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue^(a)	$	—		$	1,558			$	735		$	2,293		$	(890	)	$	1,403
Capacity revenue^(a)	—			201			—	487		—	688			—			688
Retail revenue
Mass customers	4,321			—				—			—			(4		)	4,317
Business Solutions customers	1,181			—				—			—			—			1,181
Total retail revenue	5,502			—				—			—			(4		)	5,498
Mark-to-market for economic hedging activities^(b)	(5		)	(7		)		2			(5		)	(21		)	(31		)
Contract amortization	—			12				—			12			—			12
Other revenue^(c)	—			164				64			228			(3		)	225
Total operating revenue	5,497			1,928				1,288			3,216			(918		)	7,795
Less: Lease revenue	10			—				6			6			—			16
Less: Derivative revenue	(5		)	1,871				135			2,006			—			2,001
Less: Contract amortization	—			12				—			12			—			12
Total revenue from contracts with customers	$	5,492		$	45			$	1,147		$	1,192		$	(918	)	$	5,766
(a) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.
	Retail			Gulf Coast				East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	1,877			$	7		$	1,884		$	—		$	1,884
Capacity revenue	—			—				110			110			—			110
Other revenue	—			1				16			17			—			17

(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.

(c) Included in other revenue is lease revenue of $10 million and $6 million for Retail and East/West/Other, respectively.

Contract Amortization

Lease Revenue

Certain of the Company’s revenues are obtained through leases of rooftop residential solar systems, which are accounted for as operating leases in accordance with ASC 840, Leases. Pursuant to the lease agreements, the customers’ monthly payments are pre-determined fixed monthly amounts and may include an annual fixed percentage escalation to reflect the impact of utility rate increases over the lease term, which is 20 years. The Company records operating lease revenue on a straight-line basis over the life of the lease term. Certain customers made initial down payments that are being amortized over the life of the lease. The difference between the payments received and the revenue recognized is recorded as deferred revenue.

Contract Balances

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




(In millions)	September 30, 2018
Deferred customer acquisition costs	$	104

Accounts receivable, net - Contracts with customers	1,265
Accounts receivable, net - Derivative instruments	32
Total accounts receivable, net	$	1,297

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	385
Deferred revenues	60

Recent Accounting Developments - Guidance Adopted in 2018

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 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 $13 million with a corresponding increase in other income, net on the statement of operations for the three and nine months ended September 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, and interim periods within those annual periods. The Company adopted the amendments of ASU No. 2016-01 effective January 1, 2018. In connection with the adoption of the standard, the Company has applied the guidance on 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 2018-15 - In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other- Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, or ASU No. 2018-15. The amendments of ASU No. 2018-15 addresses customer’s accounting for implementation costs incurred in a cloud computing arrangement that is a service contract and also adds certain disclosure requirements related to implementation costs incurred for internal-use software and cloud computing arrangements. The amendment aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). ASU No. 2018-15 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. The amendments in ASU No. 2018-15 can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company is evaluating the impact of adopting this guidance on the consolidated financial statements and disclosures.

ASU 2018-14 - In August 2018, the FASB issued ASU No. 2018-14, Compensation - Retirement benefits (Topic 715-20): Disclosure Framework - Changes to Disclosure Requirements for Defined Benefit Plans, or ASU No. 2018-14. The guidance in ASU No. 2018-14 adds, removes and clarifies disclosure requirements related to defined benefit pension and other postretirement plans. The amendments in ASU No. 2018-14 eliminate the requirement to disclose the amounts in accumulated other comprehensive income expected to be recognized as part of net periodic benefit cost over the next year. The guidance also removes the disclosure requirements for the effects of a one-percentage-point change on the assumed health care costs and the effect of this change in rates on service cost, interest cost and the benefit obligation for postretirement health care benefits. ASU No. 2018-14 is effective for fiscal years ending after December 15, 2020 and must be applied on a retrospective basis. As the amendment contemplates changes in disclosures only, it will have no material impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2018-13 - In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirement for Fair value Measurement), or ASU No. 2018-13. The guidance in ASU No. 2018-13 eliminates such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy. The amendments in ASU No. 2018-13 add new disclosure requirements for Level 3 measurements. ASU No. 2018-13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted for any eliminated or modified disclosures. Certain disclosures in ASU No. 2018-13 are required to be applied on a retrospective basis and others on a prospective basis. As the amendment contemplates changes in disclosures only, it will have no material impact on the Company's results of operations, cash flows, or statement of financial position.

ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company will adopt the standard effective January 1, 2019, 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. The Company is also monitoring recent changes to Topic 842 and the related impact on the implementation process.

Note 3 — Acquisitions, Discontinued Operations and 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, $45 million to accounts receivable, $42 million to derivative assets, $170 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.

Small Book Acquisitions — Through the end of October 2018, the Company has agreed to acquire several books of customers totaling approximately 115,000 customers, along with brand names, for $44 million.

Discontinued Operations

Sale of Ownership in NRG Yield, Inc. and Renewables Platform

On August 31, 2018, the Company completed the sale of its interests in NRG Yield, Inc. and its Renewables Platform to GIP, for total cash consideration of $1.348 billion. The Company has concluded that the divested businesses meet the criteria for discontinued operations, as the dispositions represent a strategic shift in the markets in which NRG operates. As such, all prior period results for the transaction have been reclassified as discontinued operations. In connection with the transaction, NRG entered into a transition services agreement to provide certain corporate services to the divested businesses.

As a result of the sale of NRG Yield, Inc., the Company's indirect ownership interest in the Agua Caliente solar project was reduced from 51% to 35%. As such, the Company no longer controls the project; and accordingly, no longer consolidates the project for financial reporting purposes. The Company recorded its ownership interest as an equity method investment upon deconsolidation resulting in a gain of $8 million.

As part of the agreement to sell NRG Yield and the Renewables Platform, the Company agreed to indemnify NRG Yield for any increase in property taxes for certain solar properties. The indemnity term will expire at various dates between 2029 and 2039. NRG has determined that the payment of this indemnity is probable and has recorded the estimated present value of the obligation as of the closing date of the transaction of $153 million to other non-current liabilities with a corresponding loss from discontinued operations. In addition to the California property tax indemnity, there were additional commitments and advisory fees totaling approximately $50 million. The Company will also retain all costs associated with the development and ownership of the Patriot Wind project until its sale to a third party pursuant to a sale agreement.

Carlsbad

On February 6, 2018, NRG entered into an agreement with NRG Yield to sell 100% of the membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, for $365 million of cash consideration. Though construction is not yet complete, the primary condition to close the Carlsbad transaction was the completion of the sale of NRG Yield and the Renewables Platform.As the sale of NRG Yield and the Renewables Platform has closed, the Company has concluded that the Carlsbad project meets the criteria for discontinued operations and accordingly, the financial information for all current and historical periods has been recast to reflect Carlsbad as a discontinued operation. The Company will continue to consolidate Carlsbad until the transaction is closed, which is currently anticipated for the first quarter of 2019. After the transaction closes, Carlsbad will continue to have a ground lease and easement agreement with NRG. The agreement has an initial term ending in 2039 with two ten year extensions. As a result of the transaction, additional commitments related to the project totaled $23 million.

Summarized results of discontinued operations were as follows:



	Three months ended September 30, 2018			Three months ended September 30, 2017			Nine months ended September 30, 2018			Nine months ended September 30, 2017
(In millions)	Three months ended September 30, 2018			Three months ended September 30, 2017			Nine months ended September 30, 2018			Nine months ended September 30, 2017
Operating revenues	$	280		$	315		$	925		$	906
Operating costs and expenses	(212		)	(242		)	(682		)	(690		)
Other expenses	(44		)	(64		)	(165		)	(210		)
Gain/(loss) from operations of discontinued components, before tax	24			9			78			6
Income tax expense	9			4			4			2
Gain/(loss) from discontinued operations, net of tax	15			5			74			4
Loss on deconsolidation, net of tax	(139		)	—			(139		)	—
California property tax indemnification	(153		)	—			(153		)	—
Other Commitments, Indemnification and Fees	(77		)	—			(77		)	—
Loss on disposal of discontinued operations, net of tax	(369		)	—			(369		)	—
Gain/(Loss) from discontinued operations, net of tax	$	(354	)	$	5		$	(295	)	$	4

The following table summarizes the major classes of assets and liabilities classified as discontinued operations as follows:



(In millions)	September 30, 2018 ^(a)		December 31, 2017 ^(b)
Cash and cash equivalents	$	—	$	224
Restricted Cash	—		229
Accounts receivable, net	—		119
Other current assets	4		133
Current assets - discontinued operations	4		705
Property, plant and equipment, net	547		7,473
Equity investments in affiliates	—		856
Intangible assets, net	8		1,240
Other non-current assets	5		612
Non-current assets - discontinued operations	560		10,181
Current portion of long term debt and capital leases	14		484
Accounts payable	37		169
Other current liabilities	1		211
Current liabilities - discontinued operations	52		864
Long-term debt and capital leases	545		6,673
Other non-current liabilities	2		186
Non-current liabilities - discontinued operations	$	547	$	6,859

(a) Represents the Carlsbad project.

(b) Represents the discontinued operations of NRG Yield, NRG's Renewable Platform and the Carlsbad project.

Sale of Assets to NRG Yield, Inc. Prior to Discontinued Operations

On June 19, 2018, the Company completed the UPMC Thermal Project and received cash consideration from NRG Yield of $84 million.

On March 30, 2018, as part of the Transformation Plan, the Company sold to NRG Yield, Inc. 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 approximately $42 million, excluding working capital adjustments, and assumed non-recourse debt of approximately $183 million.

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.

GenOn

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.

Summarized results of discontinued operations were as follows:


	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			Three months ended September 30, 2018			Three months ended September 30, 2017			Nine months ended September 30, 2018			Nine months ended September 30, 2017
(In millions)
Operating revenues	$	—				$	265				$	—			$	646	$	—		$	—		$	—		$	646
Operating costs and expenses	—			(327		)		—			(700		)	—			—			—			(700		)
Other expenses	—			(54		)		—			(98		)	—			—			—			(98		)
Loss from operations of discontinued components, before tax	—			(116		)		—			(152		)	—			—			—			(152		)
Income tax expense	—			8				—			9			—			—			—			9
Loss from operations of discontinued components	—			(124		)		—			(161		)
Loss from discontinued operations														—			—			—			(161		)
Interest income - affiliate	2			3				3			6			—			—			3			6
Loss from operations of discontinued components, net of tax	2			(121		)		3			(155		)
Loss from discontinued operations, net of tax														—			—			3			(155		)
Pre-tax loss on deconsolidation	—			(208		)		—			(208		)	—			—			—			(208		)
Settlement consideration and services credit	—			(289		)		—			(289		)	—			—			1			(289		)
Pension and post-retirement liability assumption	1			(119		)		1			(119		)	—			(25		)	(2		)	(144		)
Advisory and consulting fees	(1		)	(4		)		(2		)	(4		)
Other	(27		)	—				(27		)	—			—			(2		)	(27		)	(6		)
Loss on disposal of discontinued components, net of tax	(27		)	(620		)		(28		)	(620		)
Loss on disposal of discontinued operations, net of tax														—			(27		)	(28		)	(647		)
Loss from discontinued operations, net of tax	$	(25	)	$	(741	)		$	(25	)	$	(775	)	$	—		$	(27	)	$	(25	)	$	(802	)

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 30, 2018, the~~The Company ~~had~~has reserved for all amounts deemed to be uncollectible.

In order to facilitate the consummation of the GenOn Settlement, among other items, NRG assigned to GenOn approximately $8 million of historical claims against REMA in exchange for $4.2 million, which was credited as a reduction of the settlement payment. GenOn also indemnified NRG for any potential claims by REMA up to the amount of $10 million, and posted a letter of credit in that amount in favor of NRG as security for the indemnification. That letter of credit was subsequently released upon REMA's election to participate in the releases under GenOn's chapter 11 plan in favor of NRG. Other than those obligations which survive or are independent of the releases described herein, the GenOn Settlement ~~provides~~and the GenOn chapter 11 plan provide NRG releases from GenOn and each of its debtor and non-debtor subsidiaries. On October 16, 2018, REMA and its subsidiaries ~~excluding REMA.~~filed voluntary petitions for chapter 11 relief and a prepackaged plan of reorganization in the United States Bankruptcy Court for the Southern District of Texas. The REMA debtors' plan of reorganization has been formally accepted by REMA's voting creditors and is consistent with the releases NRG receives under the GenOn Settlement and the GenOn plan.

Restructuring Support Agreement

Prior to the filing of 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 provided for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization. In December 2017, the Bankruptcy Court approved the plan of reorganization, pursuant to an order of confirmation. Consummation of the plan of reorganization has not yet occurred and remains subject to the satisfaction or waiver of certain conditions precedent. Certain principal terms of the plan of reorganization are detailed below:


1)	The dismissal of certain prepetition litigation and full releases from GenOn and each of its debtor and non-debtor subsidiaries in favor of NRG, excluding REMA.

NRG provided settlement cash consideration to GenOn of $261.3 million, paid in cash less amounts owed to NRG under the intercompany secured revolving credit facility. ~~As of June 30, 2018, GenOn owed NRG approximately $151 million under the intercompany secured revolving credit 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~~September 30, 2018 and December 31, 2017.

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 ~~June~~September 30, 2018, was approximately ~~$90~~$76 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~~September 30, 2018 and December 31, 2017.

The shared services agreement between NRG and GenOn was terminated and replaced as of the plan confirmation date with a transition services agreement. Under the transition services agreement, NRG provided the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments. See Note 14, Related Party Transactions, for further discussion of the Services Agreement.


5)	NRG provided a credit of $28 million to GenOn to apply against amounts owed under the transition services agreement. The unused credit of approximately $18 million was paid in cash to GenOn. The credit was intended to reimburse GenOn for its payment of financing costs.

NRG and GenOn 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

The Bankruptcy Court order confirming the plan of reorganization also approved the settlement terms agreed to among the GenOn Entities, NRG, the Consenting Holders, GenOn Mid-Atlantic, and certain of GenOn Mid-Atlantic’s stakeholders, or the GenMA Settlement, and directed the settlement parties to cooperate in good faith to negotiate definitive documentation consistent with the 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 to GenOn Mid-Atlantic; and

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 November 1, 2018, the Company offered to Clearway Energy, Inc. its ownership interest in Agua Caliente Borrower 1, LLC, for approximately $120 million, which owns a 35% interest in Agua Caliente, a 290 MW utility-scale solar project located in Dateland, Arizona. The transaction is anticipated to close in the first quarter of 2019.

On August 1, 2018, the Company completed the sale of 100% of its ownership interests in BETM to Diamond Energy Trading and Marketing, LLC for $71 million, net of working capital adjustments, which resulted in a gain of $15 million on the sale. The sale also resulted in the release and return of approximately $119 million of letters of credit, $32 million of parent guarantees, and $4 million of net cash collateral to NRG.

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 related debt iswas non-recourse to NRG and was transferred to Stonepeak Kestrel in connection with the sale of Canal 3.

In addition, the Company completed other asset sales for $7$12 million of cash proceeds induring the ~~first half of~~nine months ended September 30, 2018.

~~Transfers of Assets Under Common Control~~

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 March 30, 2018, as part of the Transformation Plan, the Company sold to NRG Yield, Inc. 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 approximately $42 million, excluding working capital adjustments, and assumed non-recourse debt of approximately $183 million. Concurrently, an initial contribution of approximately $19 million was received from the third-party investor in the underlying tax equity partnership, which is included in noncontrolling interest.

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 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 June 30, 2018				As of December 31, 2017				As of September 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)	$	21	$	18	$	16	$	15	$	11	$	8	$	2	$	2
Liabilities:
Long-term debt, including current portion^(b)	15,969		16,163		16,603		16,894		7,331		7,653		9,482		9,739

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

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

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

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



	As of September 30, 2018				As of December 31, 2017
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	7,385	$	268	$	7,432	$	2,307

Recurring Fair Value Measurements

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

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


	As of June 30, 2018								As of September 30, 2018
	Fair Value								Fair Value
(In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Investments in securities (classified within other non-current assets)	$	22	$	3	$	—	$	19	$	21	$	2	$	—	$	19
Nuclear trust fund investments:
Cash and cash equivalents	25		25		—		—		21		21		—		—
U.S. government and federal agency obligations	42		42		—		—		41		41		—		—
Federal agency mortgage-backed securities	97		—		97		—		88		—		88		—
Commercial mortgage-backed securities	16		—		16		—		19		—		19		—
Corporate debt securities	101		—		101		—		112		—		112		—
Equity securities	342		342		—		—		368		368		—		—
Foreign government fixed income securities	6		—		6		—		4		—		4		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—		1		1		—		—
Derivative assets:
Commodity contracts	1,169		188		481		500		1,022		210		743		69
Interest rate contracts	108		—		108		—		53		—		53		—
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	65								66
Total assets	$	1,994	$	601	$	809	$	519	$	1,816	$	643	$	1,019	$	88
Derivative liabilities:
Commodity contracts	971		236		388		347		905		271		552		82
Interest rate contracts	23		—		23		—		2		—		2		—
Total liabilities	$	994	$	236	$	411	$	347	$	907	$	271	$	554	$	82


	As of December 31, 2017								As of December 31, 2017
	Fair Value								Fair Value
(In millions)	Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3
Investments in securities (classified within other non-current assets)	$	22	$	3	$	—	$	19	$	22	$	3	$	—	$	19
Nuclear trust fund investments:
Cash and cash equivalents	47		45		2		—		47		45		2		—
U.S. government and federal agency obligations	43		42		1		—		43		42		1		—
Federal agency mortgage-backed securities	82		—		82		—		82		—		82		—
Commercial mortgage-backed securities	14		—		14		—		14		—		14		—
Corporate debt securities	99		—		99		—		99		—		99		—
Equity securities	334		334		—		—		334		334		—		—
Foreign government fixed income securities	5		—		5		—		5		—		5		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—		1		1		—		—
Derivative assets:
Commodity contracts	745		191		509		45		744		191		509		44
Interest rate contracts	53		—		53		—		39		—		39		—
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	68								68
Total assets	$	1,513	$	616	$	765	$	64	$	1,498	$	616	$	751	$	63
Derivative liabilities:
Commodity contracts	693		257		359		77		674		257		358		59
Interest rate contracts	59		—		59		—		6		—		6		—
Total liabilities	$	752	$	257	$	418	$	77	$	680	$	257	$	364	$	59

There were no transfers during the three and ~~six~~nine months ended ~~June~~September 30, 2018 and 2017 between Levels 1 and 2. The following tables reconcile, for the three and ~~six~~nine months ended ~~June~~September 30, 2018 and 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)																Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended June 30, 2018								Six months ended June 30, 2018								Three months ended September 30, 2018								Nine months ended September 30, 2018
(In millions)	Debt Securities		Derivatives^(a)			Total			Debt Securities		Derivatives^(a)			Total			Debt Securities		Derivatives^(a)			Total			Debt Securities		Derivatives^(a)			Total
Beginning balance	$	19	$	(22	)	$	(3	)	$	19	$	(32	)	$	(13	)	$	19	$	174		$	193		$	19	$	(15	)	$	4
Contracts acquired in Xoom acquisition	—		12			12			—		12			12			—		—			—			—		12			12
Total losses — realized/unrealized:
Included in earnings	—		(21		)	(21		)	—		(19		)	(19		)
Total losses — realized/unrealized included in earnings																	—		—			—			—		(15		)	(15		)
Purchases	—		(4		)	(4		)	—		(3		)	(3		)	—		12			12			—		9			9
Transfers into Level 3 ^(b)	—		193			193			—		197			197			—		(201		)	(201		)	—		(4		)	(4		)
Transfers out of Level 3 ^(b)	—		(5		)	(5		)	—		(2		)	(2		)	—		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
Ending balance as of September 30, 2018																	$	19	$	(13	)	$	6		$	19	$	(13	)	$	6
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, 2018																	—		(3		)	(3		)	—		(18		)	(18		)


(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 June 30, 2017								Six months ended June 30, 2017								Three months ended September 30, 2017								Nine months ended September 30, 2017
(In millions)	Debt Securities		Derivatives^(a)			Total			Debt Securities		Derivatives^(a)			Total			Debt Securities		Derivatives^(a)			Total			Debt Securities		Derivatives^(a)			Total
Beginning balance	$	18	$	(56	)	$	(38	)	$	17	$	(68	)	$	(51	)	$	18	$	(9	)	$	9		$	17	$	(64	)	$	(47	)
Total gains — realized/unrealized:
Included in earnings	—		40			40			1		46			47
Included in nuclear decommissioning obligation	—		—			—			—		—			—
Total gains/(losses) — realized/unrealized included in earnings																	1		(32		)	(31		)	2		12			14
Purchases	—		5			5			—		9			9			—		(9		)	(9		)	—		—			—
Transfers into Level 3 ^(b)	—		3			3			—		(5		)	(5		)	—		(7		)	(7		)	—		(11		)	(11		)
Transfers out of Level 3 ^(b)	—		(3		)	(3		)	—		7			7			—		7			7			—		13			13
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
Ending balance as of September 30, 2017																	$	19	$	(50	)	$	(31	)	$	19	$	(50	)	$	(31	)
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																	—		(16		)	(16		)	—		(12		)	(12		)


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


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

Derivative Fair Value Measurements

A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of ~~June~~September 30, 2018, contracts valued with prices provided by models and other valuation techniques make up ~~39%~~6% of the total derivative assets and ~~35%~~9% 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 ~~June~~September 30, 2018 and December 31, 2017:


	Significant Unobservable Inputs													Significant Unobservable Inputs
	June 30, 2018													September 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	$	481	$	330	Discounted Cash Flow	Forward Market Price (per MWh)	$	6		$	198	$	35	$	44	$	68	Discounted Cash Flow	Forward Market Price (per MWh)	$	2		$	197	$	23
FTRs	19		17		Discounted Cash Flow	Auction Prices (per MWh)	(48		)	47		—		25		14		Discounted Cash Flow	Auction Prices (per MWh)	(90		)	86		—
	$	500	$	347										$	69	$	82


	Significant Unobservable Inputs													Significant Unobservable Inputs
	December 31, 2017													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	$	34	$	65	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	142	$	33	$	33	$	47	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	142	$	24
FTRs	11		12		Discounted Cash Flow	Auction Prices (per MWh)	(28		)	46		—		11		12		Discounted Cash Flow	Auction Prices (per MWh)	(28		)	46		—
	$	45	$	77										$	44	$	59

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of ~~June~~September 30, 2018 and December 31, 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 ~~June~~September 30, 2018, ~~the credit reserve resulted in a $4 million decrease in fair value which is composed of a $1 million loss in OCI~~ and ~~a $3 million loss in interest expense. As of~~ December 31, 2017, the credit reserve ~~resulted~~did not result in noa significant 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 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 2017 Form 10-K. As of ~~June~~September 30, 2018, the Company's counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $~~289~~290 million with net exposure of ~~$112~~$251 million. NRG held collateral (cash and letters of credit) against those positions of $~~246~~48 million. Approximately ~~77%~~76% of the Company's exposure before collateral is expected to roll off by the end of 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	7683	%
Financial institutions	2417
Total as of ~~June~~September 30, 2018	100	%



	Net Exposure ^{(a) (b)}
Category by Counterparty Credit Quality	(% of Total)
Investment grade	7659	%
Non-Investment grade/Non-Rated	2441
Total as of ~~June~~September 30, 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 $4960 million as of ~~June~~September 30, 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 ~~June~~September 30, 2018, aggregate credit risk exposure managed by NRG to these counterparties was approximately ~~$4.1~~$1.5 billion, ~~including $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

The Company is exposed to retail credit risk through the Company's retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. 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 ~~June~~September 30, 2018, the 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 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 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 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)
Cash and cash equivalents $ 25
$ —
$ —
—
$ 47
$ —
$ —
—
U.S. government and federal agency obligations 42
1
—
14
43
1
—
11
Federal agency mortgage-backed securities 97
—
3
23
82
1
1
23
Commercial mortgage-backed securities 16
—
1
22
14
—
—
20
Corporate debt securities 101
1
2
10
99
2
1
11
Equity securities 407
272
—
—
402
272
—
—
Foreign government fixed income securities 6
—
—
8
5
—
—
9
Total $ 694
$ 274
$ 6
$ 692
$ 276
$ 2



	As of September 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)
Cash and cash equivalents	$	21	$	—	$	—	—	$	47	$	—	$	—	—
U.S. government and federal agency obligations	41		1		1		12	43		1		—		11
Federal agency mortgage-backed securities	88		—		3		23	82		1		1		23
Commercial mortgage-backed securities	19		—		1		22	14		—		—		20
Corporate debt securities	112		1		2		10	99		2		1		11
Equity securities	434		296		—		—	402		272		—		—
Foreign government fixed income securities	4		—		—		9	5		—		—		9
Total	$	719	$	298	$	7		$	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.


	Six months ended June 30,				Nine months ended September 30,
	2018		2017		2018		2017
	(In millions)				(In millions)
Realized gains	$	7	$	3	$	8	$	8
Realized losses	6		3		8		6
Proceeds from sale of securities	$	303	$	277	$	398	$	382

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 2017 Form 10-K.

Energy-Related Commodities

As of ~~June~~September 30, 2018, NRG had energy-related derivative instruments extending through ~~2031.~~2030. The Company marks these derivatives to market through the statement of operations.

Interest Rate Swaps

NRG is exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of ~~June~~September 30, 2018, NRG had interest rate derivative instruments on recourse debt extending through 2021, which are not designated as cash flow hedges. The Company had an interest rate ~~swaps~~swap on non-recourse debt extending through ~~2041, a portion of~~2032, which ~~are~~is not designated as a cash flow ~~hedges.~~hedge.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of ~~June~~September 30, 2018 and December 31, 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
		June 30, 2018			December 31, 2017				September 30, 2018			December 31, 2017
Category	Units	(In millions)						Units	(In millions)
Emissions	Short Ton	2			1			Short Ton	3			1
Renewable Energy Certificates								Certificates	1			—
Coal	Short Ton	12			21			Short Ton	8			21
Natural Gas	MMBtu	(551		)	(17		)	MMBtu	(439		)	(20		)
Power	MWh	16			14			MWh	8			23
Capacity	MW/Day	(1		)	(1		)	MW/Day	(1		)	(1		)
Interest	Dollars	$	4,016		$	3,876		Dollars	$	1,058		$	1,060
Equity	Shares	—			1			Shares	—			1

The increase in the natural gas position was primarily the result of additional 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
Derivative Assets Derivative Liabilities
June 30, 2018 December 31, 2017 June 30, 2018 December 31, 2017
(In millions)
Derivatives Designated as Cash Flow or Fair Value Hedges:

Interest rate contracts current $ 3
$ 1
$ 2

$ 5
Interest rate contracts long-term 23
11
5

11
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 16
9
5

15
Interest rate contracts long-term 66
32
11

28
Commodity contracts current 832
616
702

535
Commodity contracts long-term 337
129
269

158
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges 1,251
786
987

736
Total Derivatives $ 1,277

$ 798
$ 994

$ 752



	Fair Value
	Derivative Assets		Derivative Liabilities
	September 30, 2018	December 31, 2017	September 30, 2018	December 31, 2017
	(In millions)
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	17	8	—	1
Interest rate contracts long-term	36	31	2	5
Commodity contracts current	666	616	550	536
Commodity contracts long-term	356	128	355	138
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	1,075	783	907	680

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 June 30, 2018	(In millions)
As of September 30, 2018													(In millions)
Commodity contracts:
Derivative assets	$	1,169		$	(817	)	$	(50	)	$	302		$	1,022		$	(765	)	$	(18	)	$	239
Derivative liabilities	(971		)	817			98			(56		)	(905		)	765			30			(110		)
Total commodity contracts	198			—			48			246			117			—			12			129
Interest rate contracts:
Derivative assets	108			(3		)	—			105			53			—			—			53
Derivative liabilities	(23		)	3			—			(20		)	(2		)	—			—			(2		)
Total interest rate contracts	85			—			—			85			51			—			—			51
Total derivative instruments	$	283		$	—		$	48		$	331		$	168		$	—		$	12		$	180


	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, 2017	(In millions)												(In millions)
Commodity contracts:
Derivative assets	$	745		$	(578	)	$	(11	)	$	156		$	744		$	(578	)	$	(11	)	$	155
Derivative liabilities	(693		)	578			73			(42		)	(674		)	578			72			(24		)
Total commodity contracts	52			—			62			114			70			—			61			131
Interest rate contracts:
Derivative assets	53			(3		)	—			50			39			—			—			39
Derivative liabilities	(59		)	3			—			(56		)	(6		)	—			—			(6		)
Total interest rate contracts	(6		)	—			—			(6		)	33			—			—			33
Total derivative instruments	$	46		$	—		$	62		$	108		$	103		$	—		$	61		$	164

Accumulated Other Comprehensive Loss

The following table summarizes the effects of ASC 815 on the Company's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:


	Interest Rate Contracts												Interest Rate Contracts
	Three months ended June 30,						Six months ended June 30,						Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017			2018			2017			2018			2017
	(In millions)												(In millions)
Accumulated OCI beginning balance	$	(31	)	$	(61	)	$	(54	)	$	(66	)	$	(23	)	$	(67	)	$	(54	)	$	(66	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	3			3			7			6			1			4			8			10
Mark-to-market of cash flow hedge accounting contracts	5			(9		)	24			(7		)	(3		)	4			21			(3		)
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
Sale of NRG Yield and the Renewables Platform													25			—			25			—
Accumulated OCI ending balance, net of $0, and $15 tax													$	—		$	(59	)	$	—		$	(59	)

Amounts reclassified from accumulated OCI into income are recorded ~~to interest expense for interest rate contracts.~~in discontinued operations.

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~~marked these derivatives to market through the income ~~statement.~~

statement until the assets were sold.

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 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 and trading activity on the Company's statement of operations. The effect of energy commodity contracts is included within operating revenues and cost of operations and the effect of interest rate contracts is included in interest expense.


	Three months ended June 30,						Six months ended June 30,						Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017			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	$	(3	)	$	22		$	(1	)	$	25		$	(84	)	$	(7	)	$	(85	)	$	18
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	(67		)	36			127			15
Reversal of acquired gain positions related to economic hedges													(10		)	(2		)	(11		)	(1		)
Net unrealized gains/(losses) on open positions related to economic hedges													25			(19		)	158			(8		)
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(71		)	59			125			41			(69		)	(28		)	62			9
Reversal of previously recognized unrealized gains on settled positions related to trading activity	(3		)	(4		)	(6		)	(19		)	(4		)	(5		)	(10		)	(24		)
Net unrealized gains on open positions related to trading activity	8			16			19			17			8			—			27			17
Total unrealized mark-to-market gains/(losses) for trading activity	5			12			13			(2		)	4			(5		)	17			(7		)
Total unrealized (losses)/gains	$	(66	)	$	71		$	138		$	39		$	(65	)	$	(33	)	$	79		$	2


	Three months ended June 30,						Six months ended June 30,						Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017			2018			2017			2018			2017
	(In millions)												(In millions)
Unrealized gains/(losses) included in operating revenues	$	20		$	53		$	(78	)	$	157		$	59		$	17		$	(14	)	$	170
Unrealized (losses)/gains included in cost of operations	(86		)	18			216			(118		)	(124		)	(50		)	93			(168		)
Total impact to statement of operations — energy commodities	$	(66	)	$	71		$	138		$	39		$	(65	)	$	(33	)	$	79		$	2
Total impact to statement of operations — interest rate contracts	$	13		$	(24	)	$	61		$	(19	)	$	2		$	3		$	17		$	(4	)

The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in operating revenue or cost of operations during the same period.

For the ~~six~~nine months ended ~~June~~September 30, 2018, the ~~$127~~$158 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~~nine months ended ~~June~~September 30, 2017, the ~~$15~~$8 million unrealized ~~gain~~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 ~~electricity~~power and New York capacity due to decreases in PJM electricity and New York capacity ~~prices, which was offset by a decrease in value of forward purchases of natural gas and coal due to decreases in natural gas and coal~~ prices.

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 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 ~~June~~September 30, 2018, was ~~$31~~$25 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of ~~June~~September 30, 2018, was $3$17 million. The Company is also a party to certain marginable agreements under which it has a net liability position, but the counterparty has not called for the collateral due, which was approximately $46 million as of ~~June~~September 30, 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~~closed on September 5, 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 study process. The NYISO studies have ~~shown~~concluded that itextensive electric system upgrades would be necessary for the station to return to service. This 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~~cost and delay the project ~~schedule. This caused~~schedule that would render the project impractical. Consequently, the Company ~~to record~~has recorded 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. Subsequent to the MIPA termination, BTEC filed claims against NRG Texas Power LLC with respect to the termination of the MIPA and NRG filed counterclaims against BTEC as further described in Note 15, Commitments and Contingencies. On June 7, 2018, the parties resolved all claims and counterclaims in the lawsuit.

Other Impairments — ~~During the second quarter~~As of September 30, 2017, the Company recorded impairment losses of approximately ~~$22~~$19 million in connection with the ~~Company's~~renewable assets that were not divested as part of the sale of NRG Yield and the Renewables ~~business.~~Platform.

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 2017 Form 10-K. Long-term debt and capital leases consisted of the following:

(In millions, except rates) June 30, 2018 December 31, 2017
June 30, 2018 interest rate % ^(a)

Recourse debt:
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 1,862
1,872
L+1.75
Tax-exempt bonds 465
465
4.125 - 6.00
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
NRG Yield Operating LLC Senior Notes, due 2026 350
350
5.000
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2023^(b)
—
55
L+1.75
El Segundo Energy Center, due 2023 369
400
L+1.75 - L+2.375
Marsh Landing, due 2023 305
318
L+2.125
Alta Wind I - V lease financing arrangements, due 2034 and 2035 901
926
5.696 - 7.015
Walnut Creek, term loans due 2023 254
267
L+1.625
Utah Portfolio, due 2022 273
278
various
Tapestry, due 2021 155
162
L+1.625
CVSR, due 2037 731
746
2.339 - 3.775
CVSR HoldCo, due 2037 188
194
4.680
Alpine, due 2022 133
135
L+1.750
Energy Center Minneapolis, due 2031, 2033, 2035 and 2037 328
208
various
Viento, due 2023 154
163
L+3.00
Buckthorn Solar, due 2018 and 2025 132
169
L+1.750
NRG Yield - other 564
579
various
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 812
818
2.395 - 3.633
Agua Caliente Borrower 1, due 2038 86
89
5.430
Cedro Hill, due 2025 ^(c)
144
151
L+1.75
Midwest Generation, due 2019 108
152
4.390
NRG Other Renewables ^(c)
623
478
various
NRG Other 107
180
various
Subtotal other NRG non-recourse debt 2,393
3,368

Subtotal all non-recourse debt 8,363
9,451

Subtotal long-term debt (including current maturities) 16,092

16,633

Capital leases 3
5
various
Subtotal long-term debt and capital leases (including current maturities) 16,095

16,638

Less current maturities^(d)
(952 )
(688 )
Less debt issuance costs (199 ) (204 )
Discounts (123 ) (30 )
Total long-term debt and capital leases $ 14,821

$ 15,716



(In millions, except rates)	September 30, 2018			December 31, 2017			September 30, 2018 interest rate %^(a)

Recourse debt:
Senior Notes, due 2022	$	485		$	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	1,230			1,250			6.625
Senior Notes, due 2028	821			870			5.750
Convertible Senior Notes, due 2048	575			—			2.750
Term loan facility, due 2023	1,857			1,872			L+1.75
Tax-exempt bonds	466			465			4.125 - 6.00
Subtotal recourse debt	7,167			7,182
Non-recourse debt:
Ivanpah, due 2033 and 2038^(b)	—			1,073			2.285 - 4.256
Agua Caliente, due 2037^(c)	—			818			2.395 - 3.633
Agua Caliente Borrower 1, due 2038	86			89			5.430
Midwest Generation, due 2019	78			152			4.390
Other	105			180			various
Subtotal all non-recourse debt	269			2,312
Subtotal long-term debt (including current maturities)	7,436			9,494
Capital leases	2			5			various
Subtotal long-term debt and capital leases (including current maturities)	7,438			9,499
Less current maturities	(593		)	(204		)
Less debt issuance costs	(82		)	(103		)
Discounts	(105		)	(12		)
Total long-term debt and capital leases	$	6,658		$	9,180

(a) As of ~~June~~September 30, 2018, L+ equals 3-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%~~1.75%.

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

~~(c) Debt associated with the asset sales announced in February 2018.~~

~~(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 second quarter of 2018.

Recourse Debt

2023 Term Loan Facility

On March 21, 2018, NRG 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%.

In accordance with the terms of the Credit Agreement, on October 5, 2018, the Company initiated an asset sale offer to purchase a portion of its Term Loan following the sale of NRG Yield and the Renewables Platform. The offer expired on November 5, 2018, and $260 million of Term Loan holders accepted the offer. As a result, the Company prepaid $155 million of Term Loans as part of its de-leveraging plan, as well as established an incremental first lien secured loan term facility under the Senior Credit Facility in the aggregate principal amount of $105 million on the same terms and conditions to stay within its debt reduction target.

Senior Notes

Issuance of 2048 Convertible Senior Notes

During the second quarter of 2018, NRG issued $575 million in aggregate principal amount of 2.75% Convertible Senior Notes due 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 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 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 is determined to be the expected life of the Convertible Notes.

The Company incurred approximately $12 million in 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~~$10 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.

Senior Note Repurchases

In ~~connection~~order to remain leverage neutral with the ~~Transformation Plan,~~issuance of the Convertible Notes, during the second and third quarter, the Company ~~has committed to 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~~completed open market senior note repurchases ~~were completed to assist~~and partially redeemed the 6.250% notes due 2022, as detailed in ~~achieving this target.~~

~~In connection with~~ the ~~repurchases during~~table below. During the ~~six~~nine months ended ~~June~~September 30, 2018, a $1$22 million loss on debt extinguishment was recorded for these repurchases, which included the write-off of previously deferred financing costs of $1$6 million.


	Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage		Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage
In millions, except rates
5.750% senior notes due 2028	$	29	$	30	99.24	%	$	29	$	30	99.24	%
6.250% senior notes due 2022	14		15		103.25	%	14		15		103.25	%
Total at June 30, 2018	$	43	$	45			$	43	$	45
6.250% senior notes due 2022	6		6		103.25	%
6.250% senior notes due 2022^(b)							492		512		103.13	%
5.750% senior notes due 2028	20		21		99.13	%	20		20		99.13	%
6.625% senior notes due 2027	20		21		103.06	%	20		21		103.06	%
Total at August 2, 2018	$	89	$	93
Total at September 30, 2018							$	575	$	598

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

~~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, are parties to a senior secured revolving credit facility, which can be used for cash and for the issuance~~$7 million as of ~~letters of credit. On April~~September 30, 2018 ~~NRG Yield LLC and NRG Yield Operating LLC refinanced~~

(b) Includes partial redemption of $486 million during the ~~revolving credit facility, which extended the maturity~~third quarter of ~~the facility to April 28, 2023, and decreased the overall cost of borrowing from L+ 2.50% to L+1.75%. At June 30,~~ 2018 ~~there was $67 million of letters of credit issued under the revolving credit facility and no outstanding borrowings on the revolver.~~

~~Project Financings~~

~~Thermal Financing~~

On ~~June 19,~~October 9, 2018, ~~NRG Energy Center Minneapolis, a subsidiary~~the Company redeemed all 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 describedits outstanding 6.250% senior notes due 2022 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 and Dispositions~~, on March 27, 2017, NRG Yield, Inc. acquired Agua Caliente Borrower 2 LLC from NRG. The debt is joint and several with respect to Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC and is secured by the equity interests of each borrower in the Agua Caliente solar facility.

~~Carlsbad Project Financing~~

On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038, and a credit agreement for a $194 million construction loan, that will convert to a term loan upon completion of the project as well as a letter of credit facility with an aggregate principal amount ~~not to exceed $83~~of $485 million. The Company has completed its targeted $640 million ~~and a working capital loan facility with an aggregate principal amount not to exceed $4 million. As of June 30, 2018, $513 million was outstanding under both the note~~debt reduction, through this redemption and the ~~construction loan.~~$155 million Term Loan repurchase, and is on track to achieve a target net debt to adjusted EBITDA ratio of 3.0/1 for 2018.

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, Inc., the Company owns a~~ ~~50%~~ ~~interest in GCE Holding LLC, the owner of GenConn, which owns and operates~~ ~~two190-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~~ ~~$100 million~~ ~~as of~~ ~~June 30, 2018~~.

~~Ivanpah Master Holdings LLC~~ — Through its consolidated subsidiary, NRG Solar Ivanpah LLC, ~~the Company~~NRG 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. NRG considers this investment a VIEs under ASC 810, Consolidation, and NRG is not considered the primary beneficiary. The Company accounts for its interest under the equity method of accounting.

The Ivanpah solar electric generating 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.~~events. 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.~~Consolidation. 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~~nine months ended ~~June~~September 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 $5745 million as of ~~June~~September 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 2017 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $83 million as of June 30, 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)	June 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
Current assets	$	191	$	118	$	6	$	6
Net property, plant and equipment	2,709		2,337		76		80
Other long-term assets	660		658		31		36
Total assets	3,560		3,113		113		122
Current liabilities	119		96		2		3
Long-term debt	814		661		29		30
Other long-term liabilities	211		209		8		7
Total liabilities	1,144		966		39		40
Redeemable noncontrolling interest	69		78		19		19
Noncontrolling interest	660		507
Net assets less noncontrolling interest	$	1,687	$	1,562
Net assets less noncontrolling interests					$	55	$	63

Note 10 — Changes in Capital Structure

As of ~~June~~September 30, 2018 and December 31, 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, 2017	418,323,134	(101,580,045	)	316,743,089		418,323,134	(101,580,045	)	316,743,089
Shares issued under LTIPs	1,373,655	—		1,373,655		1,555,766	—		1,555,766
Shares issued under ESPP	—	175,862		175,862		—	175,862		175,862
Shares repurchased	—	(14,863,301	)	(14,863,301	)	—	(28,544,693	)	(28,544,693	)
Balance as of June 30, 2018	419,696,789	(116,267,484	)	303,429,305
Balance as of September 30, 2018						419,878,900	(129,948,876	)	289,930,024

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. As of September 30, 2018, the Company has completed the $1 billion common stock ~~with the first $500 million program beginning as soon as permitted.~~repurchase program. The following repurchases have been made during the ~~six~~nine months ended ~~June~~September 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



	Total number of shares purchased	Average price paid per share	Amounts paid for shares purchased (in millions)
Board Authorized Share Repurchases
First Quarter 2018 ^(a)	3,114,748		$	93
Second Quarter 2018 ^{(a) (b)}	11,748,553		407
Third Quarter 2018 ^(b)	13,681,392		500
Total Board Authorized Share Repurchases as of September 30, 2018	28,544,693	(c)	$	1,000

(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 open market share repurchase.

(b) The share repurchases for the second and the third quarter include 9,969,023 and 13,681,392 respectively of the shares repurchased through the ASR ~~Agreement,~~Agreements, as described below.

(c) The total number of shares repurchased under the $1 billion share repurchase program and the average price paid per share will be determined upon final settlement of the September ASR in which the financial institution may deliver additional shares to the Company.

Accelerated Share Repurchase

On May 24, 2018, the Company executed an accelerated share repurchase agreement, or ASR Agreement, with a financial institution to repurchase a total of $354 million of outstanding common stock based on a volume weighted average price. The Company received initial shares 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 all of the shares delivered under the ASR Agreement was $32.69 per share. Upon receipt of the additional shares, the Company transferred the $11 million from additional paid in capital to treasury stock.

On September 5, 2018, the Company executed an additional ASR Agreement with a financial institution, to complete the remaining portion of the $1 billion stock repurchase program authorized by the Company's board of directors by repurchasing a total of $500 million of outstanding common stock based on a volume weighted average price less an agreed upon discount. The Company received initial shares of 12,820,512, which were recorded in treasury stock at fair value based on the closing price on the day of the transaction of $452 million, with the remaining $48 million recorded in additional paid in capital, representing the value of the forward contract to purchase additional shares. The ASR agreement will settle on or before December 31, 2018.

NRG Common Stock Dividends

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

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

$ 0.03



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

On ~~July 18,~~October 17, 2018, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable ~~August~~November 15, 2018, to stockholders of record as of ~~August~~November 1, 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. The reconciliation of NRG's basic and diluted loss per share is shown in the following table:


	Three months ended June 30,					Six months ended June 30,					Three months ended September 30,					Nine months ended September 30,
In millions, except per share data	2018		2017			2018		2017			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	)
Net (loss)/income attributable to NRG Energy, Inc. common stockholders											$	(72	)	$	171	$	280	$	(619	)
Weighted average number of common shares outstanding - basic	310		316			314		316			299			317		309		317
Earnings/(loss) per weighted average common share — basic	$	0.23	$	(1.98	)	$	1.12	$	(2.50	)
(Loss)/earnings per weighted average common share — basic											$	(0.24	)	$	0.54	$	0.91	$	(1.95	)
Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders	Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders										Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding - diluted	310		316			314		316			299			317		309		317
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	4		—			4		—			—			5		4		—
Total dilutive shares	314		316			318		316			299			322		313		317
Earnings/(loss) per weighted average common share — diluted	$	0.23	$	(1.98	)	$	1.10	$	(2.50	)
(Loss)/income per weighted average common share — diluted											$	(0.24	)	$	0.53	$	0.89	$	(1.95	)

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


	Three months ended June 30,		Six months ended June 30,		Three months ended September 30,		Nine months ended September 30,
In millions of shares	2018	2017	2018	2017	2018	2017	2018	2017
Equity compensation plans	—	6	1	6	4	1	—	6
2048 Convertible Senior Notes					12	—	6	—
Total	—	6	1	6	16	1	6	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~~Renewables and ~~BETM;~~international; 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.

~~During 2017, NRG Yield acquired several projects totaling 555 MW from NRG. On March~~ The financial information for the three and nine months ended September 30, 2018 the Company sold to NRG Yield, Inc. 100% of NRG's interests in Buckthorn Renewables, LLC, which owns a 154 MW construction-stage utility-scale solar generation project, located in Texas. These acquisitions were treated as a transfer of entities under common control and accordingly, all historical periods havehas been recast to reflect the ~~acquisitions~~current segment structure.

On August 31, 2018, as ~~if they had occurred at~~described in Note 3, Acquisitions, Discontinued Operations and Dispositions, NRG deconsolidated NRG Yield, Inc., its Renewables Platform and Carlsbadfor financial reporting purposes. The financial information for all historical periods has been recast to reflect the ~~beginning~~presentation of these entities as discontinued operations within the ~~financial statement period.~~corporate segment.

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


	Retail^(a)			Generation^(a)		Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total			Retail^(a)			Generation^(a)		Corporate^(a)			Eliminations				Total
Three months ended June 30, 2018	(In millions)
Three months ended September 30, 2018																				(In millions)
Operating revenues^(a)	$	1,817		$	1,218	$	113		$	307	$	7		$	(540	)	$	2,922		$	2,203		$	1,579	$	1		$	(722	)		$	3,061
Depreciation and amortization	31			66		40			82		8			—			227			30			73		7			2				112
Impairment losses	—			74		—			—		—			—			74
Reorganization costs	1			3		3			—		16			—			23			6			3		18			—				27
Equity in earnings/(losses) of unconsolidated affiliates	—			—		5			29		—			(16		)	18
Gain on sale of assets																				—			—		14			—				14
Equity in earnings of unconsolidated affiliates																				—			20		2			(2		)		20
Loss on debt extinguishment, net																				—			—		(19		)	—				(19		)
(Loss)/income from continuing operations before income taxes	(84		)	273		(17		)	103		(134		)	(12		)	129			(127		)	595		349			(504		)		313
(Loss)/income from continuing operations	(84		)	272		(12		)	96		(139		)	(12		)	121			(127		)	595		342			(504		)		306
Loss from discontinued operations, net of tax	—			—		—			—		(25		)	—			(25		)	—			—		(354		)	—				(354		)
Net (Loss)/Income	(84		)	272		(12		)	96		(164		)	(12		)	96			(127		)	595		(12		)	(504		)		(48		)
(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
(Loss)/Income attributable to NRG Energy, Inc. common stockholders																				$	(127	)	$	579	$	(23	)	$	(501	)	—	$	(72	)
Total assets as of September 30, 2018																				$	3,465		$	6,699	$	7,979		$	(6,693	)		$	11,450

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



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	1	$	740	$	(19	)	$	—	$	722


	Retail^(a)		Generation^(a)			Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total			Retail^(a)		Generation^(a)		Corporate^(a)			Eliminations			Total
Three months ended June 30, 2017	(In millions)
Three months ended September 30, 2017																				(In millions)
Operating revenues^(a)	$	1,603	$	882		$	119		$	288	$	3		$	(194	)	$	2,701		$	1,936	$	1,313	$	—		$	(509	)	$	2,740
Depreciation and amortization	29		95			49			79		8			—			260			28		128		8			(1		)	163
Impairment losses	—		41			22			—		—			—			63
Equity in (losses)/earnings of unconsolidated affiliates	—		(15		)	(2		)	16		3			(5		)	(3		)
Reorganization costs																				5		3		4			—			12
Equity in earnings of unconsolidated affiliates																				—		9		3			(3		)	9
Income/(loss) from continuing operations before income taxes	330		(89		)	(51		)	52		(134		)	(5		)	103			72		272		(157		)	(1		)	186
Income/(loss) from continuing operations	341		(90		)	(46		)	44		(145		)	(5		)	99			72		272		(158		)	(1		)	185
Loss from discontinued operations, net of tax	—		—			—			—		(741		)	—			(741		)	—		—		(22		)	—			(22		)
Net Income/(Loss)	341		(90		)	(46		)	44		(886		)	(5		)	(642		)	72		272		(180		)	(1		)	163
Net Income/(Loss) attributable to NRG Energy, Inc.	$	341	$	(90	)	$	(21	)	$	38	$	(919	)	$	25		$	(626	)
Net Income/(Loss) attributable to NRG Energy, Inc. common stockholders																				$	72	$	256	$	(159	)	$	2		$	171

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



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	3	$	493	$	13	$	—	$	509


	Retail^(a)		Generation^(a)			Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total			Retail^(a)		Generation^(a)		Corporate^(a)				Eliminations			Total
Six months ended June 30, 2018	(In millions)
Nine months ended September 30, 2018																				(In millions)
Operating revenues^(a)	$	3,298	$	1,545		$	199		$	532	$	9		$	(240	)	$	5,343		$	5,497	$	3,216	$	10			$	(928	)	$	7,795
Depreciation and amortization	59		133			90			163		17			—			462			86		259		25				—			370
Impairment losses	—		74			—			—		—			—			74			—		74		—				—			74
Reorganization costs	4		7			3			—		29			—			43			10		10		50			—	—			70
Equity in earnings/(losses) of unconsolidated affiliates	—		2			5			33		(1		)	(23		)	16
Gain on sale of assets																				—		1		29				—			30
Equity in earnings of unconsolidated affiliates																				—		27		4				(5		)	26
Loss on debt extinguishment, net																				—		—		(22		)		—			(22		)
Income/(Loss) from continuing operations before income taxes	861		(264		)	(56		)	102		(260		)	(22		)	361			733		303		812				(1,228		)	620
Income/(Loss) from continuing operations	861		(265		)	(45		)	96		(271		)	(22		)	354			733		302		794				(1,228		)	601
Income from discontinued operations, net of tax	—		—			—			—		(25		)	—			(25		)
Loss from discontinued operations, net of tax																				—		—		(320		)		—			(320		)
Net Income/(Loss)	861		(265		)	(45		)	96		(296		)	(22		)	329			733		302		474				(1,228		)	281
Net Income/(Loss) attributable to NRG Energy, Inc.	$	851	$	(265	)	$	(33	)	$	94	$	(392	)	$	96		$	351
Net Income/(Loss) attributable to NRG Energy, Inc. common stockholders																				$	732	$	293	$	479			$	(1,224	)	$	280

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



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	7	$	944	$	(23	)	$	—	$	928


	Retail ^(a)		Generation^(a)			Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total			Retail ^(a)		Generation^(a)			Corporate^(a)				Eliminations			Total
Six months ended June 30, 2017
Nine months ended September 30, 2017
Operating revenues^(a)	$	2,938	$	1,848		$	213		$	509	$	11		$	(436	)	$	5,083		$	4,868	$	3,289		$	13			$	(924	)	$	7,246
Depreciation and amortization	57		192			96			156		16			—			517			81		385			26				(2		)	490
Impairment losses	—		41			22			—		—			—			63			—		60			—				—			60
Reorganization costs																				5		3			10			—	—			18
Gain on sale of assets																				—		4			—				—			4
Equity in (losses)/earnings of unconsolidated affiliates	—		(28		)	(3		)	35		7			(9		)	2			—		(21		)	6				(5		)	(20		)
Income/(loss) from continuing operations before income taxes	303		(52		)	(87		)	49		(275		)	(9		)	(71		)	371		185			(433		)		(4		)	119
Income/(loss) from continuing operations	311		(54		)	(77		)	42		(283		)	(9		)	(70		)	380		183			(443		)		(4		)	116
Loss from discontinued operations, net of tax	—		—			—			—		(775		)	—			(775		)	—		—			(798		)		—			(798		)
Net Income/(loss)	311		(54		)	(77		)	42		(1,058		)	(9		)	(845		)	380		183			(1,241		)		(4		)	(682		)
Net Income/(loss) attributable to NRG Energy, Inc.	$	311	$	(54	)	$	(24	)	$	50	$	(1,091	)	$	18		$	(790	)
Net Income/(loss) attributable to NRG Energy, Inc. common stockholders																				$	380	$	169		$	(1,169	)		$	1		$	(619	)

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



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	3	$	872	$	49	$	—	$	924

Note 13 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:


	Three months ended June 30,						Six months ended June 30,						Three months ended September 30,						Nine months ended September 30,
In millions, except rates	2018			2017			2018			2017			2018			2017			2018			2017
Income/(Loss) before income taxes	$	129		$	103		$	361		$	(71	)
Income tax expense/(benefit) from continuing operations	8			4			7			(1		)
Income before income taxes													$	313		$	186		$	620		$	119
Income tax expense from continuing operations													7			1			19			3
Effective tax rate	6.2		%	3.9		%	1.9		%	1.4		%	2.2		%	0.5		%	3.1		%	2.5		%

For the three and ~~six~~nine months ended ~~June~~September 30, 2018, and 2017, NRG's overall effective tax rate was different than the statutory rate of 21% and 35%, respectively 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 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 and current state tax expense, partially offset by the generation of PTCs and ITCs from various wind and solar facilities, respectively.

Uncertain Tax Benefits

As of ~~June~~September 30, 2018, NRG has recorded a non-current tax liability of ~~$39~~$47 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the ~~six~~nine months ended ~~June~~September 30, 2018, NRG accrued ~~an immaterial amount~~$2 million of interest relating to the uncertain tax benefits. As of ~~June~~September 30, 2018, NRG had cumulative interest and penalties related to these uncertain tax benefits of $5 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 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.

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 and Dispositions, in connection with the Restructuring Support Agreement, NRG agreed to provide shared services to GenOn under the Services Agreement for an adjusted annualized fee of $84 million.

In December 2017, in conjunction with the confirmation of the GenOn Entities' plan of reorganization, the Services Agreement was terminated and replaced by the transition services agreement. Under the transition services agreement, NRG provided the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments. GenOn provided notice to NRG 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 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 ~~six~~nine months ended ~~June~~September 30, 2018, NRG recorded approximately ~~$21~~$18 million and ~~$42~~$53 million, respectively, under the transition services agreement against selling, general and administrative expenses post-Chapter 11 Filing. For the three and ~~six~~nine months ended ~~June~~September 30, 2017, NRG recorded ~~other income - affiliate~~$14 million and $104 million, respectively related to these ~~services of $39 million and $87 million, respectively.~~services.

Credit Agreement with GenOn

NRG and GenOn are party to a secured intercompany revolving credit agreement. The intercompany revolving credit agreement provided for a $500 million revolving credit facility, all of which was available for revolving loans and letters of credit. At ~~June~~September 30, 2018 and December 31, 2017, ~~$45~~$30 million and $92 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. ~~Additionally, as~~As of ~~June~~September 30, 2018 ~~and~~, there were no loans outstanding under intercompany secured revolving credit facility. As of December 31, 2017, there were ~~$151 million and~~ $125 million, ~~respectively,~~ of loans outstanding under the intercompany secured revolving credit facility. ~~In addition, the~~The intercompany secured revolving credit facility contains customary covenants and events of default. As of ~~June~~September 30, 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. As the Restructuring Support Agreement provided that the borrowings be repaid to NRG at or prior to emergence, NRG recorded its affiliate receivable for the amount outstanding net within accrued expenses and other current liabilities - affiliate on the consolidated balance sheet as of ~~June~~September 30, 2018. Interest continued to accrue during the pendency of the Chapter 11 Cases until July 2018, when all outstanding borrowings and 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. As mentioned above, as of September 30, 2018, GenOn, GenMa, and REMA collectively had $30 million outstanding in letters of credit issued under the secured intercompany revolving credit agreement. In connection with the settlement between NRG and GenOn, GenOn, GenMA and REMA have provided support for those outstanding letters of credit through a back-to-back letter of credit and cash collateral. The outstanding letters of credit will continue to accrue any contractual fees and expenses until they are terminated.

Commercial Operations Agreement

NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. As of ~~June~~September 30, 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~~September 30, 2018 and December 31, 2017, the Company had ~~$24~~$15 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 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 ~~June~~September 30, 2018, hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis.

Lignite Contract with Texas Westmoreland Coal Co.— The Company's Limestone facility historically blended lignite obtained from the Jewett mine, which was operated by Texas Westmoreland Coal Co, or TWCC, and coal sourced from the Powder River Basin in Wyoming. On August 18, 2016, NRG gave notice to TWCC terminating the active mining of lignite under the contract, effective on December 31, 2016. Under the contract, TWCC continues to be responsible for reclamation activities. NRG is responsible for reclamation costs and has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of $99 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.

On October 9, 2018, TWCC and certain of its affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code before the United States Bankruptcy Court for the Southern District of Texas. TWCC has obtained authorization from the bankruptcy court to continue to perform its obligations under its contract with the Company and to maintain surety bonds programs throughout its operations. In addition, NRG has not received any indication from the Railroad Commission of Texas of an intent to draw on the surety bonds. However, given the uncertainty involved in bankruptcy proceedings, it is uncertain whether and to what extent TWCC’s bankruptcy may in the future impact the reclamation costs incurred by NRG or the surety bonds.

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. On March 27, 2018, ComEd filed a Motion to Compel Payments of Claims seeking $61 million related to asbestos liabilities. On April 25, 2018, NRG filed an Omnibus Objection to All Remaining Claims of ComEd and Exelon.

~~Midwest Generation New Source Review Litigation— In 2009,~~ A trial before the ~~EPA and~~Bankruptcy Court to determine the ~~Illinois Attorney General, or the Government Plaintiffs, filed a complaint in the U.S. District Court~~amount of ComEd’s claims is currently scheduled for the Northern District of Illinois alleging violations of CAA PSD requirements and opacity and PM regulations. Several environmental groups intervened as plaintiffs in this litigation. Midwest Generation moved to dismiss nine of the ten PSD counts. The trial court granted the motion in 2010. Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in 2013. On MayApril 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 State of Illinois and the Federal Government and has agreed to make and maintain certain operational improvements. 2019.

Telephone Consumer Protection Act Purported Class Actions — Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC — one in California and two in New Jersey. The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages and equitable relief. On June 22, 2017, plaintiffs in the California case filed a motion for leave to file a second amended complaint to substitute new plaintiffs. Defendants filed an opposition to this motion on June 26, 2017. The court granted plaintiffs' motion to substitute new plaintiffs and on August 1, 2017, defendants filed an answer to the second amended complaint. On August 31, 2017, the court in the California case agreed that the litigation should be stayed pending final court approval of the New Jersey settlement. On July 12, 2017, the parties in one of the New Jersey 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 cases filed their motion for preliminary approval of the class 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 objections in response to the plaintiffs' complaint. The 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 objections to the amended complaints. On November 18, 2016, the court sustained the 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 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 July 30, 2018, the plaintiffs filed an opposition to the defendants’ motion to quash service of the summons and an opposition to the 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 was denied. On August 22, 2017, NRG filed a notice of appeal. 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 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 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. On September 7, 2018, the court granted NRG’s motion for summary judgment. Accordingly, NRG is no longer a party.

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 its answer and affirmative defenses on November 17, 2017.

GenOn Chapter 11 Cases — On ~~the Petition Date,~~June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. ~~Under~~On December 12, 2017, the ~~Restructuring Support Agreement~~Bankruptcy Court entered an order confirming GenOn’s Chapter 11 plan, which provides for, among other things, GenOn’s transition to ~~which~~a standalone enterprise. GenOn’s Chapter 11 plan has not yet become effective and there can be no assurance that the effective date will occur. However, the NRG Settlement was approved by the Bankruptcy Court on December 12, 2017, and was consummated on July 16, 2018, resulting in the exchange of broad, mutual releases among the GenOn Entities, NRG and certain of ~~GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them supported~~their respective related parties. Upon the ~~Bankruptcy Court's approval~~occurrence of the effective date of GenOn’s Chapter 11 plan, additional releases in favor of ~~reorganization. GenOn has a customary "fiduciary out" under the Restructuring Support Agreement. If the plan of reorganization is not 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~~become operative and the ~~noteholders, including claims relating to or arising out~~GenOn Entities will no longer be subsidiaries of ~~any shared services and any other relationships or transactions between the companies.~~NRG. See Note 3, Acquisitions, Discontinued Operations and Dispositions, for additional information related to the Chapter 11 Cases.

~~GenOn Noteholders' Lawsuit~~ —On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc. 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes due 2020, and the GenOn Americas Generation, LLC 8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims related to the Services Agreement between NRG and GenOn. Plaintiffs generally seek return of all monies paid under the Services Agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017. The Standstill Agreement terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty by certain current and former officers and directors of GenOn in relation to the Services Agreement and the alleged usurpation of corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs, among other things, generally seek return of all monies paid under the services agreement and any other damages that the court deems appropriate. On July 13, 2018, NRG and GenOn executed a term sheet that resolves and releases the GenOn 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. On November 7, 2017, the Bankruptcy Court 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. Because BTEC had not satisfied all of the contractually-required acceptance criteria by the MIPA expiration date, NRG elected to terminate the contract in June 2017. BTEC claimed that NRG Texas Power breached the MIPA by improperly terminating it, and sought a declaratory judgment as to the rights and obligations of the parties as well as damages, interest and attorney’s fees. 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 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 October 17, 2018, the bankruptcy court is scheduled to hear a Motion for a Final Decree to close the Mirant bankruptcy case.

Natural Gas Litigation — GenOn has 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 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. On March 30, 2017, the court denied the plaintiffs' motions for class certification, which the plaintiffs appealed to. The plaintiffs petitioned the Ninth Circuit for interlocutory review. On July 12, 2018, the Ninth Circuit 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' 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 review by either the Fifth Circuit Court of Appeals or the District Court.

In June 2018, GenOn reached a settlement with plaintiffs in three of the four remaining suits, which leaves only the one purported class action involving plaintiffs in Wisconsin. CenterPoint Energy Services is a defendant in that case, and GenOn has agreed to indemnify CenterPoint against certain losses relating to 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 July 2003, and various dates thereafter, the Mirant Debtors filed voluntary petitions in the U.S. Bankruptcy Court for the Northern District of 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 approved in conjunction with Mirant Corporation's emergence from bankruptcy protection, or the Mirant Plan, became effective. The remaining 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 Mirant Debtors that have not been resolved. Upon the Mirant/RRI Merger, those reserved shares converted into a reserve for approximately 1.3 million shares of 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, regardless of the 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 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 Motion for a Final Decree in the 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. In the state court action, the court has scheduled oral argument for September 25, 2018, on the owner lessors' dispositive motions.

Cheswick NPDES Permit Appeal —On September 24, 2018, Sierra Club and Three Rivers Waterkeeper filed an appeal challenging the NPDES permit that was issued to GenOn’s Cheswick power plant in July 2018. The appeal seeks, among other remedies, a hearing, a declaration that the permit is unlawful and inappropriate, and for an order remanding the permit to Pennsylvania’s Department of Environment to modify the permit to remedy the flaws about which the appellants complain. The parties are discussing a hearing scheduling order.

New Jersey Department of Environmental Protection Notice of Violation —On May 31, 2018, REMA (as successor-in-interest to Reliant Energy NJ Holdings) was issued a notice of violation by the New Jersey Department of Environmental Protection for alleged violations of the New Jersey Spill Compensation and Control Act (N.J.S.A. 58: 10-23 et seq.) at the Atlantic Substation property in Colts Neck Township, New Jersey. These alleged violations remain under review by REMA.

Note 16 — Regulatory Matters

This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 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 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. 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. ~~Briefing is complete.~~ On ~~May 29,~~September 13, 2018, the ~~United States filed an amicus brief at the invitation~~U.S. Court of Appeals for the Seventh Circuit ~~arguing that~~affirmed the ~~ZEC program is not preempted.~~District Court’s decision to dismiss the complaint. On September 27, 2018, NRG, along with other companies, filed a Petition for a Panel Rehearing with the Seventh Circuit. On October 9, 2018, the Seventh Circuit denied the rehearing.

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 July 25, 2017, 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. ~~Briefing is complete.~~ On ~~May 29,~~September 27, 2018, the ~~United States filed an amicus brief at~~Second Circuit affirmed the ~~invitation~~decision of the ~~Seventh Circuit arguing that the ZEC program is not preempted.~~District Court.

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 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.

Air

On August 31, 2018, EPA proposed replacing the Clean Power Plan (CPP) rule, which sought to broadly regulate CO2 emissions from the power sector, with the Affordable Clean Energy (ACE) rule, which if finalized, would require states to develop plans to seek heat rate improvements from coal-fired EGUs. The Company believes that the ACE rule replacing the CPP rule would on balance be positive for its generation fleet.

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. In 2017, the EPA agreed to reconsider the rule. On 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. On August 21, 2018, the DC Circuit found, among other things, that EPA had not adequately regulated unlined ponds and legacy ponds. Accordingly, we anticipate that EPA will promulgate new regulations to address these issues (including compliance deadlines) as it reconsiders other aspects of the existing rule. The EPA has stated that it intends to further revise the rule.

East/West

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 2007, Midwest Generation received an NOV from the EPA alleging that 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 Torrington Terminal, Franklin, Branford and Middletown generating stations violated regulations regarding NSR.

Note 18 — Condensed Consolidating Financial Information

As of ~~June~~September 30, 2018, the Company had outstanding ~~$5.4~~$4.8 billion of Senior Notes due from 2022 to 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 ~~June~~September 30, 2018:



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

NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. However, there may be restrictions for certain non-guarantor subsidiaries.

The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the SEC Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.

In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended ~~June~~September 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
	(In millions)															(In millions)
Operating Revenues
Total operating revenues	$	2,276		$	659		$	—		$	(13	)	$	2,922		$	2,618		$	445		$	—		$	(2	)	$	3,061
Operating Costs and Expenses
Cost of operations	1,778			282			(4		)	(5		)	2,051			2,005			295			9			(2		)	2,307
Depreciation and amortization	76			143			8			—			227			67			36			9			—			112
Impairment losses	—			74			—			—			74			—			—			—			—			—
Selling, general and administrative	110			34			77			(10		)	211			125			21			139			(73		)	212
Reorganization costs	1			—			22			—			23			—			—			27			—			27
Development costs	—			13			3			—			16			—			(2		)	3			—			1
Total operating costs and expenses	1,965			546			106			(15		)	2,602			2,197			350			187			(75		)	2,659
Gain on sale of assets	—			14			—			—			14			—			14			—			—			14
Operating Income/(Loss)	311			127			(106		)	2			334			421			109			(187		)	73			416
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	7			—			355			(362		)	—			6			—			466			(472		)	—
Equity in earnings of unconsolidated affiliates	—			18			—			—			18			—			20			—			—			20
Other income/(expense), net	4			(26		)	2			—			(20		)	4			8			5			—			17
Loss on debt extinguishment, net	—			—			(1		)	—			(1		)	—						(19		)	—			(19		)
Interest expense	(4		)	(92		)	(106		)	—			(202		)	(3		)	(8		)	(110		)	—			(121		)
Total other income/(expense)	7			(100		)	250			(362		)	(205		)	7			20			342			(472		)	(103		)
Income Before Income Taxes	318			27			144			(360		)	129
Income from Continuing Operations Before Income Taxes																428			129			155			(399		)	313
Income tax expense/(benefit)	108			(68		)	(32		)	—			8			122			41			(156		)	—			7
Income from Continuing Operations	210			95			176			(360		)	121			306			88			311			(399		)	306
Loss from discontinued operations, net of income tax	—			—			(25		)	—			(25		)
Net Income	210			95			151			(360		)	96
Income/(loss) from discontinued operations, net of income tax																—			17			(371		)	—			(354		)
Net Income/(Loss)																306			105			(60		)	(399		)	(48		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—			(57		)	79			2			24			—			(61		)	12			73			24
Net Income Attributable to NRG Energy, Inc.	$	210		$	152		$	72		$	(362	)	$	72
Net Income/(Loss) Attributable to NRG Energy, Inc. common stockholders																$	306		$	166		$	(72	)	$	(472	)	$	(72	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the ~~six~~nine months ended ~~June~~September 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
	(In millions)															(In millions)
Operating Revenues
Total operating revenues	$	4,120		$	1,249		$	—		$	(26	)	$	5,343		$	6,736		$	1,072		$	—		$	(13	)	$	7,795
Operating Costs and Expenses
Cost of operations	3,004			613			9			(17		)	3,609			5,006			719			18			(13		)	5,730
Depreciation and amortization	149			297			16			—			462			216			129			25			—			370
Impairment losses	—			74			—			—			74			—			74			—			—			74
Selling, general and administrative	213			60			139			(10		)	402			337			46			282			(74		)	591
Reorganization costs	3			—			40			—			43			4			—			66			—			70
Development costs	—			23			7			(1		)	29			—			—			10			(1		)	9
Total operating costs and expenses	3,369			1,067			211			(28		)	4,619			5,563			968			401			(88		)	6,844
Gain on sale of assets	3			13			—			—			16			3			27			—			—			30
Operating Income/(Loss)	754			195			(211		)	2			740			1,176			131			(401		)	75			981
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	9			—			685			(694		)	—			14			—			1,156			(1,170		)	—
Equity in earnings/(losses) of unconsolidated affiliates	—			17			(1		)	—			16			—			27			(1		)	—			26
Other income/(expense), net	8			(36		)	5			—			(23		)	13			(27		)	10			—			(4		)
Loss on debt extinguishment, net	—			—			(3		)	—			(3		)	—			—			(22		)	—			(22		)
Interest expense	(7		)	(164		)	(198		)	—			(369		)	(11		)	(42		)	(308		)	—			(361		)
Total other income/(expense)	10			(183		)	488			(694		)	(379		)	16			(42		)	835			(1,170		)	(361		)
Income Before Income Taxes	764			12			277			(692		)	361
Income from Continuing Operations Before Income Taxes																1,192			89			434			(1,095		)	620
Income tax expense/(benefit)	221			(20		)	(194		)	—			7			343			26			(350		)	—			19
Income from Continuing Operations	543			32			471			(692		)	354			849			63			784			(1,095		)	601
Loss from discontinued operations, net of income tax	—			—			(25		)	—			(25		)
Income/(loss) from discontinued operations, net of income tax																—			77			(397		)	—			(320		)
Net Income	543			32			446			(692		)	329			849			140			387			(1,095		)	281
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—			(119		)	95			2			(22		)	—			(181		)	107			75			1
Net Income Attributable to NRG Energy, Inc.	$	543		$	151		$	351		$	(694	)	$	351		$	849		$	321		$	280		$	(1,170	)	$	280


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME~~

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

~~(Unaudited)~~

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~~

~~For the six months ended June 30, 2018~~

~~(Unaudited)~~

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 BALANCE SHEETS~~

~~June 30, 2018~~

~~(Unaudited)~~

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

Eliminations^(a)
Consolidated
ASSETS (In millions)
Current Assets
Cash and cash equivalents $ 71
$ 395
$ 514
$ —
$ 980
Funds deposited by counterparties 71
—
—
—
71
Restricted cash 9
277
—
—
286
Accounts receivable, net 1,094
274
3
—
1,371
Inventory 309
176
—
—
485
Derivative instruments 837
36
15
(37 ) 851
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 173
122
35
(2 ) 328
Total current assets 3,962
1,518
708

(1,435 ) 4,753
Property, plant and equipment, net 2,402
10,164
231
(23 ) 12,774
Other Assets
Investment in subsidiaries 486
—
8,111
(8,597 ) —
Equity investments in affiliates —
1,055
—
—
1,055
Notes receivable, less current portion —
15
—
—
15
Goodwill 360
179
—
—
539
Intangible assets, net 415
1,448
—
(3 ) 1,860
Nuclear decommissioning trust fund 694
—
—
—
694
Derivative instruments 329
61
38
(2 ) 426
Deferred income tax 156
34
(64 ) —
126
Non-current assets held-for-sale —
50
—
—
50
Other non-current assets 81
454
120
—
655
Total other assets 2,521
3,296
8,205
(8,602 ) 5,420
Total Assets $ 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 $ —
$ 862
$ 92
$ (2 ) $ 952
Accounts payable 699
230
46
—
975
Accounts payable — affiliate 1,901
(207 ) (269 ) (1,396 ) 29
Derivative instruments 695
51
—
(37 ) 709
Cash collateral received in support of energy risk management activities 72
—
—
—
72
Current liabilities held-for-sale —
74
—
—
74
Accrued expenses and other current liabilities 270
123
326
—
719
Accrued expenses and other current liabilities-affiliate —
—
133
—
133
Total current liabilities 3,637
1,133
328
(1,435 ) 3,663
Other Liabilities
Long-term debt and capital leases 245
7,428
7,148
—
14,821
Nuclear decommissioning reserve 274
—
—
—
274
Nuclear decommissioning trust liability 410
—
—
—
410
Deferred income taxes 112
64
(159 ) —
17
Derivative instruments 237
50
—
(2 ) 285
Out-of-market contracts, net 58
137
—
—
195
Non-current liabilities held-for-sale —
12
—
—
12
Other non-current liabilities 410
311
409
—
1,130
Total non-current liabilities 1,746
8,002
7,398
(2 ) 17,144
Total liabilities 5,383
9,135
7,726
(1,437 ) 20,807
Redeemable noncontrolling interest in subsidiaries —
69
—
—
69
Stockholders’ Equity 3,502
5,774
1,418
(8,623 ) 2,071
Total Liabilities and Stockholders’ Equity $ 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~~

~~CONSOLIDATING STATEMENTS OF CASH FLOWS~~

~~For the six months ended June 30, 2018~~

~~(Unaudited)~~

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~~September 30, ~~2017~~2018

(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 )



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income	$	306		$	105		$	(60	)	$	(399	)	$	(48	)
Other Comprehensive Income/(Loss), net of tax
Unrealized gain/(loss) on derivatives, net	—			10			(13		)	7			4
Foreign currency translation adjustments, net	(2		)	(2		)	(1		)	3			(2		)
Defined benefit plans, net	—			—			(1		)	—			(1		)
Other comprehensive (loss)/income	(2		)	8			(15		)	10			1
Comprehensive Income/(Loss)	304			113			(75		)	(389		)	(47		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(58		)	11			73			26
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc. common stockholders	$	304		$	171		$	(86	)	$	(462	)	$	(73	)


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

(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 )



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net income	$	849		$	140		$	387		$	(1,095	)	$	281
Other comprehensive (loss)/income, net of tax
Unrealized gain on derivatives, net	—			30			9			(15		)	24
Foreign currency translation adjustments, net	(8		)	(8		)	(9		)	17			(8		)
Available-for-sale securities, net	—			—			1			—			1
Defined benefit plans, net	—			—			(3		)	—			(3		)
Other comprehensive (loss)/income	(8		)	22			(2		)	2			14
Comprehensive income	841			162			385			(1,093		)	295
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(167		)	107			75			15
Comprehensive income attributable to NRG Energy, Inc.	$	841		$	329		$	278		$	(1,168	)	$	280


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

September 30, 2018 (Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	130	$	22		$	1,207		$	—		$	1,359
Funds deposited by counterparties	30		—			—			—			30
Restricted cash	5		15			8			—			28
Accounts receivable, net	1,151		97			49			—			1,297
Inventory	301		107			—			—			408
Derivative instruments	687		24			17			(45		)	683
Deferred income tax	38		80			(118		)	—			—
Cash collateral paid in support of energy risk management activities	194		15			—			—			209
Accounts receivable - affiliate	458		55			762			(1,256		)	19
Prepayments and other current assets	160		35			53			—			248
Current assets - discontinued operations	—		4			—			—			4
Total current assets	3,154		454			1,978			(1,301		)	4,285
Property, plant and equipment, net	2,372		1,077			150			—			3,599
Other Assets
Investment in subsidiaries	477		—			4,379			(4,856		)	—
Equity investments in affiliates	—		452			—			—			452
Notes receivable, less current portion	—		10			12			(12		)	10
Goodwill	359		180			—			—			539
Intangible assets, net	403		199			—			—			602
Nuclear decommissioning trust fund	719		—			—			—			719
Derivative instruments	357		9			36			(10		)	392
Deferred income tax	34		(149		)	126			—			11
Other non-current assets	92		70			119			—			281
Non-current assets - discontinued operations	—		560			—			—			560
Total other assets	2,441		1,331			4,672			(4,878		)	3,566
Total Assets	$	7,967	$	2,862		$	6,800		$	(6,179	)	$	11,450
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	89		$	504		$	—		$	593
Accounts payable	705		55			64			—			824
Accounts payable — affiliate	1,610		(191		)	(148		)	(1,257		)	14
Derivative instruments	565		30			—			(45		)	550
Deferred income taxes	—		1			(1		)	—			—
Cash collateral received in support of energy risk management activities	30		—			—			—			30
Accrued expenses and other current liabilities	282		40			337			—			659
Accrued expenses and other current liabilities-affiliate	—		—			1			—			1
Current liabilities - discontinued operations	—		52			—			—			52
Total current liabilities	3,192		76			757			(1,302		)	2,723
Other Liabilities
Long-term debt and capital leases	244		244			6,182			(12		)	6,658
Nuclear decommissioning reserve	278		—			—			—			278
Nuclear decommissioning trust liability	432		—			—			—			432
Deferred income taxes	112		62			(156		)	—			18
Derivative instruments	361		6			—			(10		)	357
Out-of-market contracts, net	54		123			—			—			177
Other non-current liabilities	410		197			570			—			1,177
Non-current liabilities - discontinued operations	—		547			—			—			547
Total non-current liabilities	1,891		1,179			6,596			(22		)	9,644
Total liabilities	5,083		1,255			7,353			(1,324		)	12,367
Redeemable noncontrolling interest in subsidiaries	—		19			—			—			19
Stockholders’ Equity	2,884		1,588			(553		)	(4,855		)	(936		)
Total Liabilities and Stockholders’ Equity	$	7,967	$	2,862		$	6,800		$	(6,179	)	$	11,450


(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, 2018

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries				NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Cash Flows from Operating Activities
Net income	$	849		$	140			$	387		$	(1,095	)	$	281
Loss from discontinued operations	—			77				(397		)	—			(320		)
Income from continuing operations	849			63				784			(1,095		)	601
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	—			9				1			—			10
Depreciation, amortization and accretion	240			138				25			—			403
Provision for bad debts	55			2				—			—			57
Amortization of nuclear fuel	38			—				—			—			38
Amortization of financing costs and debt discount/premiums	—			5				16			—			21
Adjustment for debt extinguishment	—			—				22			—			22
Amortization of intangibles and out-of-market contracts	15			6				—			—			21
Amortization of unearned equity compensation	—			—				36			—			36
Impairment losses	—			89				—			—			89
Changes in deferred income taxes and liability for uncertain tax benefits	343			11				(360		)	—			(6		)
Changes in nuclear decommissioning trust liability	50			—				—			—			50
Changes in derivative instruments	(38		)	40				(4		)	(15		)	(17		)
Changes in collateral deposits in support of energy risk management activities	(16		)	(14		)		—			—			(30		)
Gain on sale of emission allowances	(20		)	—				—			—			(20		)
Gain on sale of assets	(3		)	(27		)		—			—			(30		)
GenOn settlement in July 2018	—			—				(125		)	—			(125		)
Loss on deconsolidation of business	—			13				—			—			13
Changes in other working capital	(567		)	(61		)		(857		)	1,110			(375		)
Cash provided/(used) by continuing operations	946			274				(462		)	—			758
Cash provided by discontinued operations	—			324				—			—			324
Net Cash Provided/(Used) by Operating Activities	946			598				(462		)	—			1,082
Cash Flows from Investing Activities
Acquisition of business, net of cash acquired	(2		)	(207		)		—			—			(209		)
Capital expenditures	(158		)	(150		)	—	(37		)	—			(345		)
Purchases of emission allowances	(30		)	—				—			—			(30		)
Proceeds from sale of emission allowances	54			—				—			—			54
Investments in nuclear decommissioning trust fund securities	(449		)	—				—			—			(449		)
Proceeds from the sale of nuclear decommissioning trust fund securities	398			—				—			—			398
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	10			8				1,537			—			1,555
Deconsolidation of business	—			(268		)		—			—			(268		)
Change in investments in unconsolidated affiliates	—			(62		)		—			—			(62		)
Cash (used)/provided by continuing operations	(177		)	(679		)		1,500			—			644
Cash used by discontinued operations	—			(703		)								(703		)
Net Cash (Used)/Provided by Investing Activities	(177		)	(1,382		)		1,500			—			(59		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(645		)	(12		)		657			—			—
Payment of dividends to common stockholders	—			—				(28		)	—			(28		)
Payment for treasury stock	—			—				(1,000		)	—			(1,000		)
Proceeds from issuance of long-term debt	—			163				832			—			995
Payments for short and long-term debt	—			(106		)		(864		)	—			(970		)
Receivable from affiliate	—			—				(26		)				(26		)
Net distributions to noncontrolling interests in subsidiaries	—			(17		)		—			—			(17		)
Payment of debt issuance costs	—			—				(19		)	—			(19		)
Other	—			(4		)		—			—			(4		)
Cash provided/(used) by continuing operations	(645		)	24				(448		)	—			(1,069		)
Cash provided by discontinued operations	—			403				—			—			403
Net Cash Provided/(Used) by Financing Activities	(645		)	427				(448		)	—			(666		)
Effect of exchange rate changes on cash and cash equivalents	—			1				—			—			1
Change in cash from discontinued operations	—			24				—			—			24
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	124			(380		)		590			—			334
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	41			399				643			—			1,083
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	165		$	19			$	1,233		$	—		$	1,417


(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, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	2,366		$	386		$	—		$	(12	)	$	2,740
Operating Costs and Expenses
Cost of operations	1,826			239			18			(11		)	2,072
Depreciation and amortization	100			55			8			—			163
Selling, general and administrative	106			16			69			(1		)	190
Reorganization costs	2			(7		)	17			—			12
Development costs	—			1			5			—			6
Total operating costs and expenses	2,034			304			117			(12		)	2,443
Operating Income/(Loss)	332			82			(117		)	—			297
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	7			—			459			(466		)	—
Equity in earnings/(losses) of unconsolidated affiliates	—			10			(1		)	—			9
Other income, net	7			38			8			(34		)	19
Interest expense	(4		)	(21		)	(114		)	—			(139		)
Total other income/(expense)	10			27			352			(500		)	(111		)
Income from Continuing Operations Before Income Taxes	342			109			235			(500		)	186
Income tax expense	—			—			1			—			1
Income from Continuing Operations	342			109			234			(500		)	185
Income/(loss) from discontinued operations, net of income tax	—			12			(34		)	—			(22		)
Net Income	342			121			200			(500		)	163
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(3		)	29			(34		)	(8		)
Net Income Attributable to NRG Energy, Inc. common stockholders	$	342		$	124		$	171		$	(466	)	$	171


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the nine months ended September 30, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries				NRG Energy, Inc. (Note Issuer)				Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	6,241		$	1,042			$	—			$	(37	)	$	7,246
Operating Costs and Expenses
Cost of operations	4,872			697				56				(36		)	5,589
Depreciation and amortization	299			167				24			—	—			490
Impairment losses	42			18				—				—			60
Selling, general and administrative	309			55			—	271				(1		)	634
Reorganization costs	2			(1		)		17				—			18
Development costs	—			4				14				—			18
Total operating costs and expenses	5,524			940				382				(37		)	6,809
Other income - affiliate	—			—				87				—			87
Gain on sale of assets	4			—				—				—			4
Operating Income/(Loss)	721			102				(295		)		—			528
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	20			—				738				(758		)	—
Equity in (losses) of unconsolidated affiliates	—			(17		)		(3		)		—			(20		)
Other income, net	7			82				23				(69		)	43
Interest expense	(11		)	(68		)		(353		)		—			(432		)
Total other income/(expense)	16			(3		)		405				(827		)	(409		)
Income from Continuing Operations Before Income Taxes	737			99				110				(827		)	119
Income tax (benefit)/expense	—			(7		)		10				—			3
Income from Continuing Operations	737			106				100				(827		)	116
Loss from discontinued operations, net of income tax	—			(134		)		(664		)		—			(798		)
Net Income/(Loss)	737			(28		)		(564		)		(827		)	(682		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(49		)		55				(69		)	(63		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	737		$	21			$	(619	)		$	(758	)	$	(619	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the three months ended September 30, 2017

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income	$	342	$	121		$	200		$	(500	)	$	163
Other Comprehensive Income, net of tax
Unrealized gain on derivatives, net	52		58			6			(109		)	7
Foreign currency translation adjustments, net	1		1			4			(4		)	2
Available-for-sale securities, net	—		—			1			—			1
Defined benefit plans, net	10		10			(1		)	(20		)	(1		)
Other comprehensive income	63		69			10			(133		)	9
Comprehensive Income	405		190			210			(633		)	172
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(3		)	32			(34		)	(5		)
Comprehensive Income Attributable to NRG Energy, Inc. common stockholders	$	405	$	193		$	178		$	(599	)	$	177


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the nine months ended September 30, 2017

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net income/(loss)	$	737	$	(28	)	$	(564	)	$	(827	)	$	(682	)
Other comprehensive income/(loss), net of tax
Unrealized gain on derivatives, net	52		57			7			(109		)	7
Foreign currency translation adjustments, net	6		6			10			(13		)	9
Available-for-sale securities, net	—		—			2			—			2
Defined benefit plans, net	10		39			25			(49		)	25
Other comprehensive income	68		102			44			(171		)	43
Comprehensive income/(loss)	805		74			(520		)	(998		)	(639		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(49		)	57			(69		)	(61		)
Comprehensive income/(loss) Attributable to NRG Energy, Inc.	$	805	$	123		$	(577	)	$	(929	)	$	(578	)


(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		Guarantor Subsidiaries			Non-Guarantor Subsidiaries				NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated^(b)
ASSETS	(In millions)													(In millions)
Current Assets
Cash and cash equivalents	$	—	$	348		$	643		$	—		$	991	$	—		$	124			$	643		$	—		$	767
Funds deposited by counterparties	37		—			—			—			37		37			—				—			—			37
Restricted cash	4		504			—			—			508		4			275				—			—			279
Accounts receivable, net	912		163			4			—			1,079		911			45				4			—			960
Inventory	338		194			—			—			532		338			148				—			—			486
Derivative instruments	646		29			9			(58		)	626		646			26				9			(57		)	624
Cash collateral paid in support of energy risk management activities	170		1			—			—			171		170			1				—			—			171
Accounts receivable - affiliate	685		133			(129		)	(594		)	95		685			183				(148		)	(534		)	186
Prepayments and other current assets														122			30				27			—			179
Current assets held-for-sale	8		107			—			—			115		8			108				—			—			116
Prepayments and other current assets	122		112			27			—			261
Current assets - discontinued operations														—			705				—			—			705
Total current assets	2,922		1,591			554			(652		)	4,415		2,921			1,645				535			(591		)	4,510
Property, plant and equipment, net	2,507		11,188			238			(25		)	13,908		2,507			3,695				237			(4		)	6,435
Other Assets
Investment in subsidiaries	266		—			7,581			(7,847		)	—		266			—				7,581			(7,847		)	—
Equity investments in affiliates	—		1,036			2			—			1,038		—			180				2			—			182
Note receivable, less current portion	—		2			38			(38		)	2		—			2			—	—			—			2
Goodwill	360		179			—			—			539		360			179				—			—			539
Intangible assets, net	454		1,295			—			(3		)	1,746		455			55				—			(3		)	507
Nuclear decommissioning trust fund	692		—			—			—			692		692			—				—			—			692
Derivative instruments	126		15			31			—			172		126		—	2				31			—			159
Deferred income taxes	377		(7		)	(236		)	—			134		377			(135		)		(236		)	—			6
Other non-current assets														50			124				120			—			294
Non-current assets held for sale	—		43			—			—			43		—			43				—			—			43
Other non-current assets	50		459			120			—			629
Non-current assets - discontinued operations														—			10,203				—			(22		)	10,181
Total other assets	2,325		3,022			7,536			(7,888		)	4,995		2,326			10,653				7,498			(7,872		)	12,605
Total Assets	$	7,754	$	15,801		$	8,328		$	(8,565	)	$	23,318	$	7,754		$	15,993			$	8,270		$	(8,467	)	$	23,550
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	667		$	59		$	(38	)	$	688	$	—		$	183			$	21		$	—		$	204
Accounts payable	610		216			55			—			881		609			47				55			—			711
Accounts payable — affiliate	742		(297		)	181			(593		)	33		742			(332		)		181			(534		)	57
Derivative instruments	556		57			—			(58		)	555		556			38				—			(57		)	537
Cash collateral received in support of energy risk management activities	37		—			—			—			37		37			—				—			—			37
Current liabilities held-for-sale	—		72			—			—			72
Accrued expenses and other current liabilities	303		162			425			—			890		304			64				401			—			769
Accrued expenses and other current liabilities - affiliate	—		—			161			—			161		—			—				161			—			161
Current liabilities held-for-sale														—			72				—			—			72
Current liabilities - discontinued operations														—			859				5			—			864
Total current liabilities	2,248		877			881			(689		)	3,317		2,248			931				824			(591		)	3,412
Other Liabilities
Long-term debt and capital leases	244		8,733			6,739			—			15,716		244			2,197				6,739			—			9,180
Nuclear decommissioning reserve	269		—			—			—			269		269			—				—			—			269
Nuclear decommissioning trust liability	415		—			—			—			415		415			—				—			—			415
Deferred income taxes	112		64			(155		)	—			21		112			64				(155		)	—			21
Derivative instruments	136		61			—			—			197		136			7				—			—			143
Out-of-market contracts, net	66		141			—			—			207		66			129				—			—			195
Other non-current liabilities														410			201				391			—			1,002
Non-current liabilities held-for-sale	—		8			—			—			8		—			8				—			—			8
Other non-current liabilities	410		321			391			—			1,122
Non-current liabilities - discontinued operations														—			6,859				—			—			6,859
Total non-current liabilities	1,652		9,328			6,975			—			17,955		1,652			9,465				6,975			—			18,092
Total Liabilities	3,900		10,205			7,856			(689		)	21,272		3,900			10,396				7,799			(591		)	21,504
Redeemable noncontrolling interest in subsidiaries	—		78			—			—			78		—			78				—			—			78
Stockholders’ Equity	3,854		5,518			472			(7,876		)	1,968		3,854			5,519				471			(7,876		)	1,968
Total Liabilities and Stockholders’ Equity	$	7,754	$	15,801		$	8,328		$	(8,565	)	$	23,318	$	7,754		$	15,993			$	8,270		$	(8,467	)	$	23,550


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


(b)	Retrospectively adjusted as discussed in Note 1, Basis of Presentation.

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)	$	737		$	(28	)	$	(564	)	$	(827	)	$	(682	)
Loss from discontinued operations	—			(134		)	(664		)	—			(798		)
Income from continuing operations	737			106			100			(827		)	116
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	—			(65		)	3			62			—
Depreciation, amortization and accretion	299			167			24			—			490
Provision for bad debts	42			—			15			—			57
Amortization of nuclear fuel	37			—			—			—			37
Amortization of financing costs and debt discount/premiums	—			2			13			—			15
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			18			—			—			60
Changes in deferred income taxes and liability for uncertain tax benefits	—			(7		)	6			—			(1		)
Changes in nuclear decommissioning trust liability	20			—			—			—			20
Changes in derivative instruments	(11		)	43			12			(8		)	36
Changes in collateral deposits in support of energy risk management activities	(126		)	23			—			—			(103		)
Proceeds from sale of emission allowances	21			—			—			—			21
Gain on sale of assets	(4		)	—			—			—			(4		)
Changes in other working capital	(1,035		)	(484		)	451			773			(295		)
Cash provided/(used) by continuing operations	42			(135		)	651			—			558
Cash provided by discontinued operations	—			178			—			—			178
Net Cash Provided by Operating Activities	42			43			651			—			736
Cash Flows from Investing Activities
Intercompany dividends	—			—			129			(129		)	—
Acquisition of businesses, net of cash acquired	—			(12		)	—			—			(12		)
Capital expenditures	(135		)	(18		)	(19		)	—			(172		)
Purchases of emission allowances	(47		)	—			—			—			(47		)
Proceeds from sale of emission allowances	105			(1		)	—			—			104
Investments in nuclear decommissioning trust fund securities	(402		)	—			—			—			(402		)
Proceeds from the sale of nuclear decommissioning trust fund securities	382			—			—			—			382
Proceeds from sale of assets, net of cash disposed of	36			—			273			—			309
Change in investments in unconsolidated affiliates	—			24			—			—			24
Other	30			—			—			—			30
Cash (used)/provided by continuing operations	(31		)	(7		)	383			(129		)	216
Cash used by discontinued operations	—			(638		)	—			—			(638		)
Net Cash (Used)/Provided by Investing Activities	(31		)	(645		)	383			(129		)	(422		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	9			417			(426		)	—			—
Intercompany dividends	—			(129		)	—			129			—
Payment of dividends to common stockholders	—			—			(28		)	—			(28		)
Net receipts from settlement of acquired derivatives that include financing elements	—			—			—			—			—
Proceeds from issuance of long-term debt	—			94			214			—			308
Payments for short and long-term debt	—			(124		)	(219		)	—			(343		)
Increase in notes receivable from affiliate	—			(125		)	—			—			(125		)
Net distributions to noncontrolling interests from subsidiaries	—			(18		)	—			—			(18		)
Payments of debt issuance costs	—			(34		)	(5		)	—			(39		)
Other	—			(8		)	—			—			(8		)
Cash provided/(used) by continuing operations	9			73			(464		)	129			(253		)
Cash provided by discontinued operations	—			39			—			—			39
Net Cash Provided/(Used) by Financing Activities	9			112			(464		)	129			(214		)
Effect of exchange rate changes on cash and cash equivalents	—			(10		)	—			—			(10		)
Change in cash from discontinued operations	—			(421		)	—			—			(421		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	20			(79		)	570			—			511
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	3			534			323			—			860
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	23		$	455		$	893		$	—		$	1,371


(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 ~~six~~nine months ended ~~June~~September 30, 2018 and 2017. Also refer to NRG's 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

NRG Energy, Inc., or NRG or the Company, is a leading customer-driven integrated power company built on a portfolio of ~~leading~~dynamic retail electricity brands and diverse generation assets. NRG is continuously focused on serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels. The Company:

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

owns ~~and operates~~ approximately ~~30,000~~26,000 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 ~~June~~September 30, 2018, by operating segment:


	Global Generation Portfolio^(a)									Global Generation Portfolio^{(a )(b)}
	(In MW)									(In MW)
	Generation									Generation
Generation Type	Gulf Coast^(f)(i)	East/West^(b)	Renewables^(c)(g)(j)(k)		NRG Yield^(d)(j)		Other^(e)(j)	Total Global		Gulf Coast^(d)(e)	East/West^(c)	Other^(f)	Total Global
Natural gas^(f)(d)	7,464	4,878	—		1,888		—	14,230		7,464	4,870	—	12,334
Coal	5,114	3,871	—		—		—	8,985		5,114	3,745	—	8,859
Oil	—	3,641	—		190		—	3,831		—	3,641	—	3,641
Nuclear	1,136	—	—		—		—	1,136		1,136	—	—	1,136
Wind^(g)	—	—	739		2,200		—	2,939
Utility Scale Solar	—	—	342		921		—	1,263		—	423	—	423
Distributed Solar	—	—	189		52		114	355		—	—	60	60
Total generation capacity^(h)	13,714	12,390	1,270		5,251		114	32,739
Capacity attributable to noncontrolling interest^(h)	—	—	(580	)	(2,358	)	—	(2,938	)
Total net generation capacity	13,714	12,390	690		2,893		114	29,801
Total generation capacity										13,714	12,679	60	26,453


(a)	All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.


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

(b) NRG Yield Inc and the Renewables Platform businesses which represented 3,428 MW of global generation was sold on August 31, 2018.


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


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

(d) Natural gas generation does not include 371 MW related to Greens Bayou 5 which was retired in January 2018.


(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 related to Greens Bayou 5 which was retired in January 2018.~~


~~(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 MW for noncontrolling interest for Spring Canyon II and III. NRG Yield's total generation capacity net of this noncontrolling interest was 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)~~(f)	~~Includes net MW for NRG Yield, Inc.~~The Distributed Solar figure within "Other" includes the aggregate production capacity of ~~2,893 MW~~installed and ~~the Renewables operating and development platform of 467 MW, which the Company expects to sell as announced on February 6, 2018.~~activated residential solar energy systems.

~~(k) Does not include net MW for Ivanpah of 196 MW due to deconsolidation in the second quarter of 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

NRG 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, 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 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 $3.2~~$3.1 billion of asset sale cash proceeds, ~~including divestitures of 6 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.~~detailed as follows:

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~~transaction is subject to certain closing conditions and ~~are~~is expected to close in the ~~second half~~fourth quarter of 2018.

On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of ~~the~~NRG's membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, a 527-MW natural gas-fired project in Carlsbad, ~~CA,~~California 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. The transaction is expected to close in the first quarter of 2019.

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 August 1, 2018, the Company completed the sale of 100% of its ownership interests in BETM to ~~a third party~~Diamond Energy Trading and Marketing, LLC for ~~$70~~$71 million, ~~subject to~~net of working capital adjustments. The sale also resulted in the release and return of approximately $119 million of letters of credit, ~~$30~~$32 million of parent guarantees, and $4 million of net cash collateral to NRG.

On August 31, 2018, the Company completed the sale of its interest in NRG Yield, Inc. and its Renewables Platform to GIP, for approximately $1.348 billion in cash proceeds.

During the nine months ended September 30, 2018, the Company completed the sale of various other assets for approximately $12 million.

Capital structure and allocation enhancements — A prioritized capital allocation strategy that targets a reduction in consolidated corporate debt to achieve its targeted 3.0x net debt / Adjusted EBITDA credit ratio.

~~Expected~~Year to date reduction of $9.2 billion in non-recourse debt related to the sale of ~~NRG's ownership in~~ NRG Yield, Inc. and the ~~NRG renewables platform and~~Renewable Platform, which includes the ~~sales of~~debt for Carlsbad Energy Center as well as the impact of deconsolidation of Agua Caliente and ~~Buckthorn Solar.~~Ivanpah.

~~Year~~The Company has also completed its targeted $640 million of debt reduction through the redemption of $485 million of its outstanding 6.250% senior notes due 2022 and the Term Loan prepayment of $155 million.

The annualized interest savings related to these activities to date ~~open market repurchases of $93 million, representing principal reduction of Senior Notes of $89~~totals $57 million.

Working Capital and Costs to 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~~$313 million of non-recurring working capital improvements and ~~$113~~$158 million of one-time costs to achieve.

Regulatory Matters

The Company’s regulatory matters are described in the Company’s 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.

Federal Energy Regulation

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~~On May 23, 2018, the New Jersey ~~Governor. In addition, Certain other states in~~Governor signed the ~~areas~~bill into law. On August 29, 2018, the New Jersey Board of Public Utilities issued an order to establish the ~~country in which NRG operates, including Ohio~~ZEC application process and ~~Pennsylvania, have considered but have not enacted proposals to provide out-of-market subsidy payments to potentially uneconomic nuclear and fossil generating units.~~related activities as required by law. NRG has opposed efforts to provide out-of-market subsidies, and intends to continue opposing them in the future.

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, 2018, PJM announced the results of its 2021/2022 base residual auction. NRG, excluding GenOn, cleared approximately 4,740 MW of Capacity Performance product. NRG’s expected capacity revenues, excluding GenOn, from the base residual auction for the 2021/2022 delivery year are approximately $328 million.

The table below provides a detailed description of NRG’s 2021/2022 base residual auction results from May 23, 2018:



	Capacity Performance Product
Zone	Cleared Capacity (MW)^(a)	Price ($/MW-day)
COMED	3,995	$	195.55
DPL	552	$	165.73
MAAC	121	$	140.00
PEPCO	72	$	140.00
Total	4,740


(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. On October 2, 2018, multiple parties, including NRG, filed their initial briefs, and on November 6, 2018, parties, including NRG, filed reply briefs. FERC ~~established a briefing schedule and~~has 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. On August 17, FERC denied the rehearings. The outcome of this proceeding could have a material impact on future PJM capacity prices.

New England

ISO-NE Retention of Mystic Units — 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 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 tariff and then redesign its capacity market to allow units retained for fuel security to set price in the capacity market. ~~Additional briefing is due 90 days after issuance of~~Multiple parties filed for rehearing. In the ~~order.~~

~~Competitive Auctions with Sponsored Resources Proposal (CASPR)~~ —~~On January 8,~~new proceeding, on August 31, 2018, ISO-NE filed ~~the CASPR~~its proposal ~~which attempts~~ to ~~accommodate state sponsored resources while maintaining competitive market pricing.~~establish a fuel security reliability standard and a short-term cost-of-service mechanism. On ~~January 29,~~September 21, 2018, NRG ~~protested certain aspects of the proposal and also supported ISO-NE’s beginning attempts~~filed a protest to ~~address state sponsored resources entering the capacity market. On March 9, 2018, FERC accepted~~ ISO-NE's proposal. ~~On April 9, 2018, NRG joined another generator in filing a request for rehearing. The rehearing is pending at FERC.~~ The outcome of this ~~proceeding~~matter will 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 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 generators, including NRG, filed a petition for review with the 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 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 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 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 12-M-0476 et 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 authority to regulate 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 noticed both an evidentiary and a collaborative track to address the functioning of the competitive retail markets. An administrative hearing on the evidentiary track concluded on December 12, 2017 after 10 days of testimony and is now ~~in the post-hearing brief phase.~~fully briefed. The outcome of the evidentiary and collaborative processes, combined with the outcome of the appeal of the Reset Order, could affect the viability of the New York retail energy market.

~~CAISO~~

Environmental Matters

NRG is subject to 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 during operation of power plants. Federal and state environmental laws historically have become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on our operations, which could affect the Company's operations. Complying with environmental laws often involves significant capital and operating 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 that may affect the Company are under review by the EPA, including ESPS for GHGs, ash disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated legal challenges are resolved. The Company’s environmental matters are described in the Company’s 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.

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 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 become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent 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 economic.

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 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. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. Accordingly, we anticipate that the EPA will promulgate new regulations to address these issues (including compliance deadlines) as it reconsiders other aspects of the existing rule. 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.

Regional Environmental Developments

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. On August 27, 2018, EPA proposed a rule to solicit additional public input on certain aspects of the final rule. The program is scheduled to begin on January 1, 2019. Several of the Company's units in Texas will be affected by this rule. The rule has been challenged by several environmental groups in the Fifth Circuit of the U.S. Court of Appeals, which litigation has been stayed pending resolution of administrative petitions for reconsideration.

Significant Events

The following significant events have occurred during 2018, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:

NRG Transformation Plan

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 acquisition increased NRG's retail portfolio by approximately 300,000 customers in the aggregate by ~~June~~September 30, 2018.

Agua Caliente Deconsolidation

During the third quarter of 2018, the Company, recognized a gain of $8 million on the deconsolidation and subsequent recognition of its 35% interest in Agua Caliente as an equity method investment, as discussed in more detail in Note 3, Acquisitions, Discontinued Operations and Dispositions

Ivanpah Deconsolidation

During the second quarter of 2018, the Company, recognized a loss of $22 million on the deconsolidation and subsequent recognition of its 54.6% interest in Ivanpah as an equity method investment, as discussed in more detail in Note 9, Variable Interest Entities, or VIEs.

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 24, 2018, the Company issued $575 million in aggregate principal amount at par of 2.75% convertible senior notes due 2048, as discussed in more detail in Note 8, Debt and Capital Leases.

On June 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~~nine months ended ~~June~~September 30, 2018, the Company ~~repurchased $43~~completed open market senior note repurchases and redeemed, collectively, $575 million in aggregate principal of its ~~Senior Notes in the open market~~senior notes for ~~$45~~$598 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 its Senior Notes in the open market for $48 million including accrued interest.~~

On August 1, 2018, the Company announced that it gave the required notice under the indenture governing its 6.25% Senior Notes due 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 indebtedness, will result in the retirement of outstanding indebtedness equal to approximately $575 million which is the aggregate principal amount of the Company's 2.75% convertible senior notes due 2048 issued on May 24, 2018.

Share Repurchases

In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock. As of September 30, 2018, the Company has completed the stock ~~with~~repurchase program. During the ~~first $500 million program beginning as soon as permitted. In March~~nine months ended September 30, 2018, the Company repurchased ~~3,114,748 shares of NRG common stock for approximately $93 million. During the second quarter of 2018,~~ 28,544,693 shares. As discussed in more detail in Note 10, Changes in Capital Structure, the Company ~~repurchased 11,748,553~~may receive additional 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~~upon settlement of the September ASR ~~Agreement, completing~~on or before December 31, 2018.

In the fourth quarter, the Company's board of directors has authorized an additional $500 million of share ~~repurchases. The average cost per share for the total $500 million of shares repurchased was $31.80.~~

repurchase program to be executed into 2019.

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 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 Pricing~~ — ERCOT forward prices for July and August 2018 are significantly higher than where previous summers have settled. These elevated pricing levels mean that deviations from expected demand and/or generation availability may have a material impact on the Company’s 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 June 30,									Six months ended June 30,									Three months ended September 30,										Nine months ended September 30,
(In millions except otherwise noted)	2018			2017			Change			2018			2017			Change			2018				2017			Change			2018			2017			Change
Operating Revenues
Energy revenue^(a)	$	673		$	656		$	17		$	1,292		$	1,243		$	49		$	479			$	490		$	(11	)	$	1,403		$	1,385		$	18
Capacity revenue^(a)	313			297			16			601			559			42			254				243			11			688			641			47
Retail revenue	1,816			1,605			211			3,302			2,946			356			2,200				1,934			266			5,498			4,873			625
Mark-to-market for economic hedging activities	15			41			(26		)	(91		)	159			(250		)	55				22			33			(31		)	177			(208		)
Contract amortization	(14		)	(14		)	—			(28		)	(29		)	1			5				5			—			12			11			1
Other revenues ^(b)	119			116			3			267			205			62			68				46			22			225			159			66
Total operating revenues	2,922			2,701			221			5,343			5,083			260			3,061				2,740			321			7,795			7,246			549
Operating Costs and Expenses
Cost of sales ^(c)	1,515			1,422			(93		)	2,908			2,683			(225		)	1,830				1,665			(165		)	4,702			4,316			(386		)
Mark-to-market for economic hedging activities	86			(18		)	(104		)	(216		)	118			334			124				50			(74		)	(93		)	168			261
Contract and emissions credit amortization ^(c)	7			8			1			13			16			3			7				8			1			20			24			4
Operations and maintenance	360			340			(20		)	730			712			(18		)	264				271			7			884			864			(20		)
Other cost of operations	83			89			6			174			175			1			82			—	78			(4		)	217			217			—
Total cost of operations	2,051			1,841			(210		)	3,609			3,704			(95		)	2,307				2,072			(235		)	5,730			5,589			141
Depreciation and amortization	227			260			33			462			517			55			112				163			51			370			490			120
Impairment losses	74			63			(11		)	74			63			(11		)	—				—			—			74			60			(14		)
Selling, general and administrative	211			221			10			402			481			79			212				190			(22		)	591			634			43
Reorganization costs	23			—			(23		)	43			—			(43		)	27				12			(15		)	70			18			(52		)
Development costs	16			18			2			29			35			6			1				6			5			9			18			9
Total operating costs and expenses	2,602			2,403			(199		)	4,619			4,800			181			2,659				2,443			(216		)	6,844			6,809			(35		)
Other income - affiliate	—			39			(39		)	—			87			(87		)	—				—			—			—			87			(87		)
Gain on sale of assets	14			2			12			16			4			12			14				—			14			30			4			26
Operating Income	334			339			(5		)	740			374			366			416				297			119			981			528			453
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	18			(3		)	21			16			2			14			20				9			11			26			(20		)	46
Other (losses)/income, net	(20		)	14			(34		)	(23		)	26			(49		)
Other income/(losses), net																			17				19			(2		)	(4		)	43			(47		)
Loss on debt extinguishment, net	(1		)	—			(1		)	(3		)	(2		)	(1		)	(19		)		—			(19		)	(22		)	—			(22		)
Interest expense	(202		)	(247		)	45			(369		)	(471		)	102			(121		)		(139		)	18			(361		)	(432		)	71
Total other expense	(205		)	(236		)	31			(379		)	(445		)	66			(103		)		(111		)	8			(361		)	(409		)	48
Income/(Loss) from Continuing Operations before Income Taxes	129			103			26			361			(71		)	432
Income tax expense/(benefit)	8			4			4			7			(1		)	8
Income/(Loss) from Continuing Operations	121			99			22			354			(70		)	424
Income from Continuing Operations before Income Taxes																			313				186			127			620			119			501
Income tax expense																			7				1			6			19			3			16
Income from Continuing Operations																			306				185			121			601			116			485
Loss from discontinued operations, net of income tax	(25		)	(741		)	716			(25		)	(775		)	750			(354		)		(22		)	(332		)	(320		)	(798		)	478
Net Income/(Loss)	96			(642		)	738			329			(845		)	1,174
Net (Loss)/Income																			(48		)		163			(211		)	281			(682		)	963
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	24			(16		)	40			(22		)	(55		)	33			24				(8		)	32			1			(63		)	64
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	72		$	(626	)	$	698		$	351		$	(790	)	$	1,141
Net (Loss)/Income Attributable to NRG Energy, Inc. common stockholders																			$	(72	)		$	171		$	(243	)	$	280		$	(619	)	$	899
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	2.80		$	3.18		(12		)%	$	2.90		$	3.25		(11		)%	$	2.90			$	3.00		(3		)%	$	2.90		$	3.17		(9		)%

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

(b) Includes unrealized trading gains and losses.

Management’s discussion of the results of operations for the three months ended ~~June~~September 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 three months ended ~~June~~September 30, 2018 and 2017. The average on-peak power prices for ERCOT - Houston and COMED (PJM) ~~decreased~~increased primarily due to the change in congestion pattern for the three months ended ~~June~~September 30, 2018, as compared to the same period in 2017.


	Average on Peak Power Price ($/MWh)						Average on Peak Power Price ($/MWh)
	Three months ended June 30,						Three months ended September 30,
Region	2018		2017		Change %		2018		2017		Change %
Gulf Coast ^(a)
ERCOT - Houston ^(b)	$	34.82	$	46.03	(24	)%	$	40.34	$	33.09	22	%
ERCOT - North^(b)	34.89		27.80		26	%	40.23		29.35		37	%
MISO - Louisiana Hub^(c)	44.20		42.77		3	%	41.22		39.56		4	%
East/West
NY J/NYC^(c)	36.41		39.35		(7	)%	46.82		37.42		25	%
NEPOOL^(c)	36.28		33.57		8	%	43.53		31.94		36	%
COMED (PJM)^(c)	31.88		33.40		(5	)%	37.31		34.38		9	%
PJM West Hub^(c)	39.73		32.79		21	%	40.06		35.10		14	%
CAISO - NP15^(c)	27.37		28.29		(3	)%	54.39		46.69		16	%
CAISO - SP15^(c)	27.75		30.72		(10	)%	74.86		46.54		61	%

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

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

The following table summarizes average realized power prices for each region in which NRG operates for the three months ended ~~June~~September 30, 2018 and 2017, which reflects the impact of settled hedges.


	Average Realized Power Price ($/MWh)						Average Realized Power Price ($/MWh)
	Three months ended June 30,						Three months ended September 30,
Region	2018		2017		Change %		2018		2017		Change %
Gulf Coast	$	36.33	$	34.68	5	%	$	43.20	$	34.69	25	%
East/West^(a)	35.63		36.67		(3	)%
East/West/Other^(a)							44.06		48.80		(10	)%

(a) does not include BETM energy revenue of ~~$15~~$4 million and ~~$14~~($12) million for 2018 and 2017, respectively.

Though the average on peak power prices have ~~remained relatively flat,~~increased on average by 25%, 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

The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.

Economic Gross Margin

In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales.

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

The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended ~~June~~September 30, 2018 and 2017:

Three months ended June 30, 2018
Generation
(In millions) Retail Gulf Coast
East/West^(a)
Subtotal Renewables NRG Yield Corporate/Eliminations Total
Energy revenue $ —

$ 508

$ 144

$ 652

$ 79

$ 192

$ (250 )
$ 673
Capacity revenue —

68

160

228

—

87

(2 )
313
Retail revenue 1,817

—

—

—

—

—

(1 )
1,816
Mark-to-market for economic hedging activities —

289

(15 )
274

5

—

(264 )
15
Contract amortization —

4

—

4

—

(18 )
—

(14 )
Other revenue ^(b)
—

42

18

60

29

46

(16 )
119
Operating revenue 1,817

911

307

1,218

113

307

(533 )
2,922
Cost of fuel (4 )
(260 )
(70 )
(330 )
—

(9 )
(25 )
(368 )
Other cost of sales^(c)
(1,315 )
(81 )
(21 )
(102 )
(2 )
(8 )
280

(1,147 )
Mark-to-market for economic hedging activities (346 )
(4 )
—

(4 )
—

—

264

(86 )
Contract and emission credit amortization —

(7 )
—

(7 )
—

—

—

(7 )
Gross margin $ 152

$ 559

$ 216

$ 775

$ 111

$ 290

$ (14 )
$ 1,314
Less: Mark-to-market for economic hedging activities, net (346 )
285

(15 )
270

5

—

—

(71 )
Less: Contract and emission credit amortization, net —

(3 )
—

(3 )
—

(18 )
—

(21 )
Economic gross margin $ 498

$ 277

$ 231

$ 508

$ 106

$ 308

$ (14 )
$ 1,406
Business Metrics
MWh sold (thousands)^(d)(e)
13,982
3,616
1,211
2,308

MWh generated (thousands)^(f)
12,959
2,903
1,211
2,675

(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 East/West and NRG Yield that generate revenue under capacity agreements.
(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.



	Three months ended September 30, 2018
				Generation
(In millions)	Retail			Gulf Coast				East/West/Other^(a)(b)			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	680			$	278		$	958		$	(479	)	$	479
Capacity revenue	—			66				187			253			1			254
Retail revenue	2,202			—				—			—			(2		)	2,200
Mark-to-market for economic hedging activities	1			268				27			295			(241		)	55
Contract amortization	—			5				—			5			—			5
Other revenue	—			36				32			68			—			68
Operating revenue	2,203			1,055				524			1,579			(721		)	3,061
Cost of fuel	(2		)	(315		)		(160		)	(475		)	30			(447		)
Other cost of sales^(c)	(1,700		)	(98		)	—	(32		)	(130		)	447			(1,383		)
Mark-to-market for economic hedging activities	(360		)	—				(5		)	(5		)	241			(124		)
Contract and emission credit amortization	—			(7		)		—			(7		)	—			(7		)
Gross margin	$	141		$	635			$	327		$	962		$	(3	)	$	1,100
Less: Mark-to-market for economic hedging activities, net	(359		)	268				22			290			—			(69		)
Less: Contract and emission credit amortization, net	—			(2		)		—			(2		)	—			(2		)
Economic gross margin	$	500		$	369			$	305		$	674		$	(3	)	$	1,171
Business Metrics
MWh sold (thousands)				15,742				6,076
MWh generated (thousands)				14,638				5,306
(a) Includes International, Renewables, and Generation eliminations .
(b) Includes BETM which was sold as of July 31, 2018 .
(c) Includes purchased energy, capacity and emissions credits


	Three months ended June 30, 2017																								Three months ended September 30, 2017
				Generation																								Generation
(In millions)	Retail			Gulf Coast			East/West^(a)			Subtotal			Renewables			NRG Yield			Corporate/Eliminations			Total			Retail			Gulf Coast			East/West/Other^(a)(b)			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	484		$	184		$	668		$	105		$	177		$	(294	)	$	656		$	—		$	540		$	333		$	873		$	(383	)	$	490
Capacity revenue	—			68			144			212			—			85			—			297			—			74			172			246			(3		)	243
Retail revenue	1,605			—			—			—			—			—			—			1,605			1,935			—			—			—			(1		)	1,934
Mark-to-market for economic hedging activities	(2		)	(90		)	13			(77		)	(3		)	—			123			41			—			133			1			134			(112		)	22
Contract amortization	—			3			—			3			—			(17		)	—			(14		)	1			4			—			4			—			5
Other revenue ^(b)	—			55			21			76			17			43			(20		)	116			—			41			15			56			(10		)	46
Operating revenue	1,603			520			362			882			119			288			(191		)	2,701			1,936			792			521			1,313			(509		)	2,740
Cost of fuel	(2		)	(284		)	(82		)	(366		)	(1		)	(7		)	5			(371		)	(1		)	(293		)	(125		)	(418		)	17			(402		)
Other cost of sales^(c)	(1,211		)	(79		)	(52		)	(131		)	(2		)	(7		)	300			(1,051		)	(1,459		)	(102		)	(79		)	(181		)	377			(1,263		)
Mark-to-market for economic hedging activities	158			(15		)	(2		)	(17		)	—			—			(123		)	18			(173		)	2			9			11			112			(50		)
Contract and emission credit amortization	—			(7		)	(1		)	(8		)	—			—						(8		)	—			(7		)	(1		)	(8		)	—			(8		)
Gross margin	$	548		$	135		$	225		$	360		$	116		$	274		$	(9	)	$	1,289		$	303		$	392		$	325		$	717		$	(3	)	$	1,017
Less: Mark-to-market for economic hedging activities, net	156			(105		)	11			(94		)	(3		)	—			—			59			(173		)	135			10			145			—			(28		)
Less: Contract and emission credit amortization, net	—			(4		)	(1		)	(5		)	—			(17		)	—			(22		)	1			(3		)	(1		)	(4		)	—			(3		)
Economic gross margin	$	392		$	244		$	215		$	459		$	119		$	291		$	(9	)	$	1,252		$	475		$	260		$	316		$	576		$	(3	)	$	1,048
Business Metrics
MWh sold (thousands)^(e)				13,958			4,598						1,059			2,112												15,568			6,824
MWh generated (thousands)^(f)				13,101			3,079						1,059			2,425												14,186			4,567
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
(a) Includes International, Renewables, and Generation eliminations .																									(a) Includes International, Renewables, and Generation eliminations .
(b) Includes BETM which was sold as of July 31, 2018 .																									(b) Includes BETM which was sold as of July 31, 2018 .
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 9 thousand or MWt of 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.

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


	Three months ended June 30,		Three months ended September 30,
Weather Metrics	Gulf Coast	East/West	Gulf Coast	East/West/Other
2018
CDDs ^(a)	1,067	265	1,621	855
HDDs ^(a)	108	425	1	26
2017
CDDs	921	281	1,528	770
HDDs	41	380	1	34
10-year average
CDDs	970	259	1,618	714
HDDs	67	429	4	40

(a)

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

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,						Three months ended September 30,
(In millions except otherwise noted)	2018			2017			2018			2017
Retail revenue	$	1,689		$	1,515		$	2,084		$	1,845
Supply management revenue	42			52			55			62
Capacity revenue	86			38			63			28
Customer mark-to-market	—			(2		)	1			—
Contract amortization							—			1
Operating revenue^(a)	1,817			1,603			2,203			1,936
Cost of sales ^(b)	(1,319		)	(1,213		)	(1,702		)	(1,460		)
Mark-to-market for economic hedging activities	(346		)	158			(360		)	(173		)
Contract amortization							—			—
Gross Margin	$	152		$	548		$	141		$	303
Less: Mark-to-market for economic hedging activities, net	(346		)	156			(359		)	(173		)
Less: Contract amortization, net							—			1
Economic Gross Margin	$	498		$	392		$	500		$	475

Business Metrics
Mass electricity sales volume — GWh - Gulf Coast	9,802			9,234			12,140			11,935
Mass electricity sales volume — GWh - All other regions	1,592			1,357			2,518			1,724
C&I electricity sales volume — GWh - All regions	5,403			5,308			5,669			5,087
Natural gas sales volumes (MDth)	1,244			438			1,431			241
Average Retail Mass customer count (in thousands)	2,973			2,859			3,162			2,884
Ending Retail Mass customer count (in thousands) ^(c)	3,173			2,887			3,167			2,880


(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~~$485 million and ~~$293~~$382 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.~~aggregate.

Retail gross margin decreased ~~$396~~$162 million and economic gross margin increased ~~$106~~$25 million for the three months ended ~~June~~September 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 )



	(In millions)
Higher gross margin due to higher volumes from higher average customer counts primarily driven by XOOM acquisition in June 2018	$	29
Higher gross margin due to unfavorable impacts from Hurricane Harvey in 2017 driven by $9 million from a reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7 million of customer relief	16
Higher gross margin due to an increase in capacity revenues from the Business Solutions unit due to additional MWs sold of $8 million and higher rates of $4 million	12
Lower gross margin due to higher supply cost of $124 million or approximately $5.82 per MWh, driven by an increase in power prices, partially offset by higher revenue of $101 million or approximately $ 4.87 per MWh, driven by customer product, term and mix	(23		)
Lower gross margin of $9 million primarily due to impacts of selling back excess supply in 2018 compared to 2017	(9		)
Increase in economic gross margin	$	25
Decrease in mark-to-market for economic hedging primarily due to net unrealized gain/losses on open positions related to economic hedges	(186		)
Decrease in contract amortization	(1		)
Decrease in gross margin	$	(162	)

Generation gross margin and economic gross margin

Generation gross margin increased ~~$415~~$245 million and economic gross margin increased ~~$49~~$98 million, both of which include intercompany sales, during the three months ended ~~June~~September 30, 2018, compared to the same period in 2017.

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

Gulf Coast Region

(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



	(In millions)
Higher gross margin due to a 25% increase in average realized prices in Texas offset by a 3% decrease in average realized prices in South Central	$	119
Higher energy margin due to an 8% decrease in supply cost on load contracts	13
Lower gross margin due to a decrease in tolling purchases in 2018 as a result of increased demand	(13		)
Lower capacity margins in South Central due to purchases to cover PJM capacity obligations	(7		)
Other	(3		)
Increase in economic gross margin	$	109
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	133
Increase in contract and emission credit amortization	1
Increase in gross margin	$	243

East/~~West~~West/Other

(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 )



	(In millions)
Lower gross margin primarily due to Ivanpah and Agua Caliente being deconsolidated in 2018	(52		)
Lower gross margin driven by a 20% decrease in realized capacity pricing in New York and expiration of the Long Beach capacity toll in July 2017	(18		)
Lower gross margin due to less volume of load contracts coupled with lower prices	(13		)
Higher gross margin due to a 36% increase in PJM and 28% NEISO cleared capacity pricing	31
Higher gross margin from commercial optimization activities	19
Higher gross margin as a result of trading activity at BETM	13
Higher gross margin due to a net overall increase in capacity volumes sold from improved historical capacity factors in NY and PJM	5
Other	4
Decrease in economic gross margin	$	(11	)
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
Increase in gross margin	$	2

~~Renewables gross margin and economic gross margin~~

Renewables gross margin decreased $5 million and economic gross margin decreased $13 million for the three months ended June 30, 2018, compared to the same period in 2017. This was driven by the deconsolidation of Ivanpah in May 2018, partially offset 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 three months ended June 30, 2018, compared to the same period in 2017. The increase is due to a 9% increase in volume generated by wind projects, primarily the Alta Wind projects and Wildorado from increased wind resources, as well as a 2% increase in solar generation, primarily at CVSR 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. Total net mark-to-market results decreased by ~~$130~~$41 million during the three months ended ~~June~~September 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:


	Three months ended June 30, 2018																	Three months ended September 30, 2018
				Generation																	Generation
	Retail			Gulf Coast			East/West			Renewables		Eliminations^(a)			Total			Retail			Gulf Coast			East/West/Other			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	$	—		$	(52	)	$	(8	)	$	—	$	28		$	(32	)
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges																		$	—		$	175		$	5		$	(179	)	$	1
Net unrealized gains/(losses) on open positions related to economic hedges	—			341			(7		)	5		(292		)	47			1			93			22			(62		)	54
Total mark-to-market gains/(losses) in operating revenues	$	—		$	289		$	(15	)	$	5	$	(264	)	$	15		$	1		$	268		$	27		$	(241	)	$	55
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 previously recognized unrealized (gains)/losses on settled positions related to economic hedges																		$	(260	)	$	(1	)	$	(3	)	$	179		$	(85	)
Reversal of acquired gain positions related to economic hedges	(1		)	—			—			—		—			(1		)	(10		)	—			—			—			(10		)
Net unrealized (losses)/gains on open positions related to economic hedges	(407		)	(2		)	3			—		292			(114		)	(90		)	1			(2		)	62			(29		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(346	)	$	(4	)	$	—		$	—	$	264		$	(86	)	$	(360	)	$	—		$	(5	)	$	241		$	(124	)


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

Three 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 ) $ (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 $ 45
$ (4 ) $ —
$ —
$ (50 ) $ (9 )
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



	Three months ended September 30, 2017
				Generation
	Retail			Gulf Coast			East/West/Other			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		$	(68	)	$	58
Net unrealized gains/(losses) on open positions related to economic hedges	—			12			(4		)	(44		)	(36		)
Total mark-to-market gains/(losses) in operating revenues	$	—		$	133		$	1		$	(112	)	$	22
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(127	)	$	(5	)	$	(1	)	$	68		$	(65	)
Reversal of acquired gain positions related to economic hedges	(2		)	—			—			—			(2		)
Net unrealized (losses)gains on open positions related to economic hedges	(44		)	7			10			44			17
Total mark-to-market (losses)/gains in operating costs and expenses	$	(173	)	$	2		$	9		$	112		$	(50	)


(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.

For the three months ended ~~June~~September 30, 2018, the ~~$15~~$55 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~~a decrease in New York capacity prices and ~~decreases in ERCOT electricity prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.~~outer year natural gas prices. The ~~$86~~$124 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized gains on contracts that settled during the period and acquired positions, as well as a decrease 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 losses on contracts that settled during the period.~~lower near-term natural gas prices.

For the three months ended ~~June~~September 30, 2017, the ~~$41~~$22 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~~partially offset by a decrease in the value of open positions as a result of ~~decreases~~an increase in ~~PJM power prices and New York capacity prices, partially offset by a decrease in value of open positions as a result of ERCOT heat rate expansion.~~natural gas prices. The ~~$18~~$50 million ~~gain~~loss in operating costs and expenses from economic hedge positions was driven primarily by ~~an increase in value of open positions as a result of ERCOT heat rate expansion, partially offset by a decrease in value of open positions as a result of decrease in coal prices and~~ the reversal of previously recognized unrealized gains on contracts that settled during the ~~period.~~period, partially offset by an increase in value of open positions as a result of an increase in coal prices.

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


	Three months ended June 30,				Three months ended September 30,
(In millions)	2018		2017		2018		2017
Trading gains
Trading gains/(losses)
Realized	$	25	$	14	$	23	$	(10	)
Unrealized	5		12		4		(5		)
Total trading gains	$	30	$	26
Total trading gains/(losses)					$	27	$	(15	)

~~Operations and Maintenance Expense~~

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

(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 $2 million in 2018 and $1 million in 2017.~~

~~Operations and maintenance expense increased by $20 million for the three 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
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~~$51 million for the three months ended ~~June~~September 30, 2018, compared to the three months ended ~~June~~September 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,~~Agua in August 2018 as well ~~and the impairment of the Dunkirk project,~~ as ~~described in Note 7,~~ ~~Impairments~~.prior year impairments.

Selling, General and Administrative

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

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



	Retail		Generation		Corporate		��	Total
			(In millions)
Three months ended September 30, 2018	$	144	$	54	$	14		$	212
Three months ended September 30, 2017	109		51		30			190

Selling, general and administrative expenses ~~decreased~~increased by ~~$10~~$22 million for the three months ended ~~June~~September 30, 2018, compared to the same period in 2017, due to the following:

(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 )



	(In millions)
Increase in selling and marketing expense associated with costs incurred for margin enhancement activities	$	40
Increase costs due to the XOOM acquisition	13
Decrease in general and administrative expenses from cost initiatives for the Transformation Plan	(29		)
Other	(2		)
	$	22

Reorganization Costs

Reorganization costs, ~~of $23 million,~~ primarily related to employee ~~costs,~~severance and contract cancellation expense of $27 million, were incurred as part of the Transformation ~~Plan.~~Plan during the three months ended September 30, 2018 compared to $12 million in the three months ended September 30, 2017.

~~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 three 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 three months ended June 30, 2017, represents a gain on the sale of land.~~

E~~quity in Earnings/(Losses) of Unconsolidated Affiliates~~

~~Equity in earnings of consolidated affiliates increased by $21~~$14 million for the three months ended ~~June~~September 30, 2018, ~~compared~~relates primarily to the three 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 three months ended June 30, 2018, primarily relate to the loss~~gain on ~~deconsolidation~~sale 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 well as income from pension and postretirement investments.BETM.

~~Interest Expense~~Gulf Coast Region

~~NRG's interest expense~~



	(In millions)
Higher gross margin due to a 25% increase in average realized prices in Texas offset by a 3% decrease in average realized prices in South Central	$	119
Higher energy margin due to an 8% decrease in supply cost on load contracts	13
Lower gross margin due to a decrease in tolling purchases in 2018 as a result of increased demand	(13		)
Lower capacity margins in South Central due to purchases to cover PJM capacity obligations	(7		)
Other	(3		)
Increase in economic gross margin	$	109
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	133
Increase in contract and emission credit amortization	1
Increase in gross margin	$	243

East/West/Other



	(In millions)
Lower gross margin primarily due to Ivanpah and Agua Caliente being deconsolidated in 2018	(52		)
Lower gross margin driven by a 20% decrease in realized capacity pricing in New York and expiration of the Long Beach capacity toll in July 2017	(18		)
Lower gross margin due to less volume of load contracts coupled with lower prices	(13		)
Higher gross margin due to a 36% increase in PJM and 28% NEISO cleared capacity pricing	31
Higher gross margin from commercial optimization activities	19
Higher gross margin as a result of trading activity at BETM	13
Higher gross margin due to a net overall increase in capacity volumes sold from improved historical capacity factors in NY and PJM	5
Other	4
Decrease in economic gross margin	$	(11	)
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
Increase in gross margin	$	2

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 decreased by ~~$46~~$41 million during the three months ended September 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:



	Three months ended September 30, 2018
				Generation
	Retail			Gulf Coast			East/West/Other			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	$	—		$	175		$	5		$	(179	)	$	1
Net unrealized gains/(losses) on open positions related to economic hedges	1			93			22			(62		)	54
Total mark-to-market gains/(losses) in operating revenues	$	1		$	268		$	27		$	(241	)	$	55
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(260	)	$	(1	)	$	(3	)	$	179		$	(85	)
Reversal of acquired gain positions related to economic hedges	(10		)	—			—			—			(10		)
Net unrealized (losses)/gains on open positions related to economic hedges	(90		)	1			(2		)	62			(29		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(360	)	$	—		$	(5	)	$	241		$	(124	)


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



	Three months ended September 30, 2017
				Generation
	Retail			Gulf Coast			East/West/Other			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		$	(68	)	$	58
Net unrealized gains/(losses) on open positions related to economic hedges	—			12			(4		)	(44		)	(36		)
Total mark-to-market gains/(losses) in operating revenues	$	—		$	133		$	1		$	(112	)	$	22
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(127	)	$	(5	)	$	(1	)	$	68		$	(65	)
Reversal of acquired gain positions related to economic hedges	(2		)	—			—			—			(2		)
Net unrealized (losses)gains on open positions related to economic hedges	(44		)	7			10			44			17
Total mark-to-market (losses)/gains in operating costs and expenses	$	(173	)	$	2		$	9		$	112		$	(50	)


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

For the three months ended September 30, 2018, the $55 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 a decrease in New York capacity prices and outer year natural gas prices. The $124 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized gains on contracts that settled during the period and acquired positions, as well as a decrease in the value of open positions as a result of lower near-term natural gas prices.

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



	Three months ended September 30,
(In millions)	2018		2017
Trading gains/(losses)
Realized	$	23	$	(10	)
Unrealized	4		(5		)
Total trading gains/(losses)	$	27	$	(15	)

Depreciation and amortization

Depreciation and amortization decreased by $51 million for the three months ended ~~June~~September 30, 2018, compared to the three months ended September 30, 2017, driven primarily by deconsolidation of Ivanpah in May 2018 and Agua in August 2018 as well as prior year impairments.

Selling, General and Administrative

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



	Retail		Generation		Corporate		��	Total
			(In millions)
Three months ended September 30, 2018	$	144	$	54	$	14		$	212
Three months ended September 30, 2017	109		51		30			190

Selling, general and administrative expenses increased by $22 million for the three months ended September 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 $ (35 )
Decrease in interest expense related to repurchases of Senior Notes (9 )
Decrease in interest expense related to Ivanpah deconsolidation (6 )
Other 4
$ (46 )



	(In millions)
Increase in selling and marketing expense associated with costs incurred for margin enhancement activities	$	40
Increase costs due to the XOOM acquisition	13
Decrease in general and administrative expenses from cost initiatives for the Transformation Plan	(29		)
Other	(2		)
	$	22

~~Income Tax Expense~~

~~For~~Reorganization Costs

Reorganization costs, primarily related to employee severance and contract cancellation expense of $27 million, were incurred as part of the Transformation Plan during the three months ended ~~June~~September 30, 2018 ~~NRG recorded an income tax expense~~compared to $12 million in the three months ended September 30, 2017.

Gain on Sale of $8Assets

Gain on sale of assets of $14 million ~~on pre-tax income of $129 million. For the same period in 2017, NRG recorded an income tax expense of $4 million on pre-tax income of $103 million. The effective tax rate was 6.2% and 3.9%~~ for the three months ended ~~June~~September 30, 2018, ~~and 2017, respectively.~~

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

~~Net loss attributable to noncontrolling interests and redeemable noncontrolling interests~~

For the three 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 Yield, Inc.'s share of net income.

~~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.~~

~~(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 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 )



	(In millions)
Higher gross margin due to a 25% increase in average realized prices in Texas offset by a 3% decrease in average realized prices in South Central	$	119
Higher energy margin due to an 8% decrease in supply cost on load contracts	13
Lower gross margin due to a decrease in tolling purchases in 2018 as a result of increased demand	(13		)
Lower capacity margins in South Central due to purchases to cover PJM capacity obligations	(7		)
Other	(3		)
Increase in economic gross margin	$	109
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	133
Increase in contract and emission credit amortization	1
Increase in gross margin	$	243

East/~~West~~West/Other

(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.



	(In millions)
Lower gross margin primarily due to Ivanpah and Agua Caliente being deconsolidated in 2018	(52		)
Lower gross margin driven by a 20% decrease in realized capacity pricing in New York and expiration of the Long Beach capacity toll in July 2017	(18		)
Lower gross margin due to less volume of load contracts coupled with lower prices	(13		)
Higher gross margin due to a 36% increase in PJM and 28% NEISO cleared capacity pricing	31
Higher gross margin from commercial optimization activities	19
Higher gross margin as a result of trading activity at BETM	13
Higher gross margin due to a net overall increase in capacity volumes sold from improved historical capacity factors in NY and PJM	5
Other	4
Decrease in economic gross margin	$	(11	)
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
Increase in gross margin	$	2

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~~decreased by ~~$84~~$41 million during the ~~six~~three months ended ~~June~~September 30, 2018, compared to the same period in ~~2017.~~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																		Three months ended September 30, 2018
				Generation																		Generation
	Retail			Gulf Coast			East/West			Renewables			Eliminations^(a)			Total			Retail			Gulf Coast			East/West/Other			Eliminations^(a)			Total
	(In millions)																		(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges																			$	—		$	175		$	5		$	(179	)	$	1
Net unrealized gains/(losses) on open positions related to economic hedges																			1			93			22			(62		)	54
Total mark-to-market gains/(losses) in operating revenues																			$	1		$	268		$	27		$	(241	)	$	55
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	(86	)	$	(8	)	$	—		$	31		$	(64	)	$	(260	)	$	(1	)	$	(3	)	$	179		$	(85	)
Reversal of acquired gain positions related to economic hedges																			(10		)	—			—			—			(10		)
Net unrealized (losses)/gains on open positions related to economic hedges	(5		)	(189		)	(17		)	(5		)	189			(27		)	(90		)	1			(2		)	62			(29		)
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
Total mark-to-market (losses)/gains in operating costs and expenses																			$	(360	)	$	—		$	(5	)	$	241		$	(124	)


(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 )



	Three months ended September 30, 2017
				Generation
	Retail			Gulf Coast			East/West/Other			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		$	(68	)	$	58
Net unrealized gains/(losses) on open positions related to economic hedges	—			12			(4		)	(44		)	(36		)
Total mark-to-market gains/(losses) in operating revenues	$	—		$	133		$	1		$	(112	)	$	22
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(127	)	$	(5	)	$	(1	)	$	68		$	(65	)
Reversal of acquired gain positions related to economic hedges	(2		)	—			—			—			(2		)
Net unrealized (losses)gains on open positions related to economic hedges	(44		)	7			10			44			17
Total mark-to-market (losses)/gains in operating costs and expenses	$	(173	)	$	2		$	9		$	112		$	(50	)


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

For the ~~six~~three months ended ~~June~~September 30, 2018, the ~~$91~~$55 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 a decrease in New York capacity prices and outer year natural gas prices. The $124 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized gains on contracts that settled during the period and acquired positions, as well as a decrease in the value of open positions as a result of lower near-term natural gas prices.

For the three months ended September 30, 2017, the $22 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 the 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, 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 primarilypartially offset 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~~an 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.~~prices.

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


	Six months ended June 30,					Three months ended September 30,
(In millions)	2018		2017			2018		2017
Trading gains/(losses)
Realized	$	40	$	28		$	23	$	(10	)
Unrealized	13		(2		)	4		(5		)
Total trading gains	$	53	$	26
Total trading gains/(losses)						$	27	$	(15	)

~~Operations and Maintenance Expense~~

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

(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~~$51 million for the ~~six~~three months ended ~~June~~September 30, 2018, compared to the ~~same period in~~three months ended September 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 six months ended June 30,~~ 2018 ~~the Company recorded impairment losses of $74 million related to the impairment of the Keystone Conemaugh generating stations,~~and Agua in August 2018 as well as ~~the impairment of the Dunkirk project as described in Note 7,~~ ~~Impairments~~.prior year 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



	Retail		Generation		Corporate		��	Total
			(In millions)
Three months ended September 30, 2018	$	144	$	54	$	14		$	212
Three months ended September 30, 2017	109		51		30			190

Selling, general and administrative expenses ~~decreased~~increased by ~~$79~~$22 million for the ~~six~~three months ended ~~June~~September 30, 2018, compared to the same period in ~~2017.~~

2017, due to the following:

(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 )



	(In millions)
Increase in selling and marketing expense associated with costs incurred for margin enhancement activities	$	40
Increase costs due to the XOOM acquisition	13
Decrease in general and administrative expenses from cost initiatives for the Transformation Plan	(29		)
Other	(2		)
	$	22

(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,~~severance and contract cancellation expense of $27 million, were incurred as part of the Transformation Plan during the ~~six~~three months ended ~~June~~September 30, ~~2018.~~2018 compared to $12 million in the three months ended September 30, 2017.

~~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 of $14 million for the ~~six~~three months ended ~~June~~September 30, 2018, ~~consists~~relates primarily ~~of the gain on the sale of Canal 3, while~~to the gain on sale of ~~assets for the six months ended June 30, 2017, represents a gain on the sale of land.~~BETM.

E~~quity 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 cost method investments as well as income from pension and postretirement investments.

Interest Expense

NRG's interest expense decreased by ~~$102~~$18 million for the ~~six~~three months ended ~~June~~September 30, 2018, compared to the same period in 2017 due to the following:


	(In millions)			(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	)
Increase in derivative interest expense from changes in the fair value of interest rate swaps driven by increased interest rates in 2018				$	1
Increase in interest expense related to Agua Caliente deconsolidation				4
Decrease in interest expense related to repurchases of Senior Notes	(20		)	(20		)
Decrease in interest expense related to Ivanpah deconsolidation	(6		)	(10		)
Other	(1		)	7
	$	(102	)	$	(18	)

Loss on Debt Extinguishment

A loss on debt extinguishment of $19 million was recorded for the three months ended September 30, 2018, primarily driven by the repurchase of Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.

Income Tax Expense

For the ~~six~~three months ended ~~June~~September 30, 2018, NRG recorded an income tax expense of $7 million on pre-tax income of ~~$361~~$313 million. For the same period in 2017, NRG recorded an income tax ~~benefit~~expense of $1 million on a pre-tax ~~loss~~income of ~~$71~~$186 million. The effective tax rate was ~~1.9%~~2.2% and ~~1.4%~~0.5% for the ~~six~~three months ended ~~June~~September 30, 2018 and 2017, respectively.

For the three months ended September 30, 2018, and 2017 ~~respectively.~~

~~For the six months ended June 30, 2018,~~ NRG's overall effective tax rate was different than the statutory rate of 21% and 35%, respectively primarily due to the tax benefit for the change in valuation allowance partially offset by current state tax expense.

Net income attributable to noncontrolling interests and redeemable noncontrolling interests

For the ~~generation~~three months ended September 30, 2018, net income attributable to noncontrolling interests and redeemable noncontrolling interest increased as compared to the same period in 2017, due to the sale of ~~PTCs~~NRG Yield, Inc. and Renewables Platform.

Management’s discussion of the results of operations for the nine months ended September 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 nine months ended September 30, 2018 and 2017. The average on-peak power prices have generally increased primarily due to increased heat rates for the nine months ended September 30, 2018, as compared to the same period in 2017.



	Average on Peak Power Price ($/MWh)
	Nine months ended September 30,
Region	2018		2017		Change %
Gulf Coast ^(a)
ERCOT - Houston ^(b)	$	36.10	$	35.61	1	%
ERCOT - North^(b)	35.60		26.64		34	%
MISO - Louisiana Hub^(c)	43.88		42.33		4	%
East/West
NY J/NYC^(c)	48.40		37.46		29	%
NEPOOL^(c)	48.56		33.11		47	%
COMED (PJM)^(c)	34.13		32.72		4	%
PJM West Hub^(c)	42.41		33.30		27	%
CAISO - NP15^(c)	38.16		33.82		13	%
CAISO - SP15^(c)	46.02		33.42		38	%

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

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

The following table summarizes average realized power prices for each region in which NRG operates for the nine months ended September 30, 2018 and 2017, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Nine months ended September 30,
Region	2018		2017		Change %
Gulf Coast	$	38.04	$	34.39	11	%
East/West/Other^(a)	48.25		49.36		(2	)%

(a) does not include BETM energy revenue of $37 million and $3 million for 2018 and 2017, respectively.

Though the average on peak power prices have increased on average by 21%, 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 nine months ended September 30, 2018 and 2017:



	Nine months ended September 30, 2018
				Generation
(In millions)	Retail			Gulf Coast			East/West/Other^(a)(b)			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	1,558		$	735		$	2,293		$	(890	)	$	1,403
Capacity revenue	—			201			487			688			—			688
Retail revenue	5,502			—			—			—			(4		)	5,498
Mark-to-market for economic hedging activities	(5		)	(7		)	2			(5		)	(21		)	(31		)
Contract amortization	—			12			—			12			—			12
Other revenue	—			164			64			228			(3		)	225
Operating revenue	5,497			1,928			1,288			3,216			(918		)	7,795
Cost of fuel	(13		)	(768		)	(313		)	(1,081		)	(2		)	(1,096		)
Other cost of sales^(c)	(4,117		)	(260		)	(126		)	(386		)	897			(3,606		)
Mark-to-market for economic hedging activities	86			(7		)	(7		)	(14		)	21			93
Contract and emission credit amortization	—			(19		)	(1		)	(20		)	—			(20		)
Gross margin	$	1,453		$	874		$	841		$	1,715		$	(2	)	$	3,166
Less: Mark-to-market for economic hedging activities, net	81			(14		)	(5		)	(19		)	—			62
Less: Contract and emission credit amortization, net	—			(7		)	(1		)	(8		)	—			(8		)
Economic gross margin	$	1,372		$	895		$	847		$	1,742		$	(2	)	$	3,112
Business Metrics
MWh sold (thousands)				40,962			14,807
MWh generated (thousands)				37,783			11,390
(a) Includes International, Renewables, and Generation eliminations .
(b) Includes BETM, which was sold as of July 31, 2018 .
(c) Includes purchased energy, capacity and emissions credits



	Nine months ended September 30, 2017
				Generation
(In millions)	Retail			Gulf Coast			East/West/Other^(a)(b)			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	1,407		$	862		$	2,269		$	(884	)	$	1,385
Capacity revenue	—			207			438			645			(4		)	641
Retail revenue	4,868			—			—			—			5			4,873
Mark-to-market for economic hedging activities	—			174			4			178			(1		)	177
Contract amortization	—			11			—			11			—			11
Other revenue	—			138			48			186			(27		)	159
Operating revenue	4,868			1,937			1,352			3,289			(911		)	7,246
Cost of fuel	(7		)	(790		)	(296		)	(1,086		)	48			(1,045		)
Other cost of sales^(c)	(3,664		)	(259		)	(204		)	(463		)	856			(3,271		)
Mark-to-market for economic hedging activities	(154		)	(22		)	7			(15		)	1			(168		)
Contract and emission credit amortization	—			(21		)	(3		)	(24		)	—			(24		)
Gross margin	$	1,043		$	845		$	856		$	1,701		$	(6	)	$	2,738
Less: Mark-to-market for economic hedging activities, net	(154		)	152			11			163			—			9
Less: Contract and emission credit amortization, net	—			(10		)	(3		)	(13		)	—			(13		)
Economic gross margin	$	1,197		$	703		$	848		$	1,551		$	(6	)	$	2,742
Business Metrics
MWh sold (thousands)				40,908			17,463
MWh generated (thousands)				37,975			11,524
(a) Includes International, Renewables, and Generation eliminations .
(b) Includes BETM, which was sold as of July 31, 2018 .
(c) Includes purchased energy, capacity and emissions credits

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



	Nine months ended September 30,
Weather Metrics	Gulf Coast	East/West/Other
2018
CDDs ^(a)	2,821	1,139
HDDs ^(a)	1,143	2,197
2017
CDDs	2,653	1,071
HDDs	674	2,041
10-year average
CDDs	2,681	990
HDDs	1,107	2,245

(a)

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)	2018			2017
Retail revenue	$	5,215		$	4,651
Supply management revenue	130			147
Capacity revenue	157			70
Customer mark-to-market	(5		)	—
Operating revenue^(a)	5,497			4,868
Cost of sales ^(b)	(4,130		)	(3,671		)
Mark-to-market for economic hedging activities	86			(154		)
Gross Margin	$	1,453		$	1,043
Less: Mark-to-market for economic hedging activities, net	81			(154		)
Economic Gross Margin	$	1,372		$	1,197

Business Metrics
Mass electricity sales volume — GWh - Gulf Coast	29,885			28,153
Mass electricity sales volume — GWh - All other regions	5,828			4,722
C&I electricity sales volume — GWh - All regions	16,099			15,228
Natural gas sales volumes (MDth)	4,850			1,941
Average Retail Mass customer count (in thousands)	3,001			2,856
Ending Retail Mass customer count (in thousands) ^(c)	3,167			2,880


(a)	Includes intercompany sales of $4 million and $4 million in 2018 and 2017, respectively, representing sales from Retail to the Gulf Coast region.


(b)	Includes intercompany purchases of $900 million and $885 million in 2018 and 2017, respectively.


(c)	The acquisition of XOOM Energy, LLC increased NRG's retail portfolio by approximately 300,000 customers.

Retail gross margin increased $410 million and economic gross margin increased $175 million for the nine months ended September 30, 2018, compared to the same period in 2017, due to:



	(In millions)
Higher gross margin due to an increase in capacity revenues from the Business Solutions unit due to additional MWs sold of $36 million and higher rates of $16 million	$	52
Higher gross margin due to higher revenue of $206 million or approximately $3.95 per MWh, driven by customer product, term and mix, offset by higher supply cost of $162 million or approximately $3.29 per MWh, driven by an increase in power prices	44
Higher gross margin of $37 million due to $50 million from an increase in load of $1,828,000 MWh, partially offset by $13 million due to unfavorable impacts of selling back excess supply in 2018 compared to 2017	37
Higher gross margin due to higher volumes from higher average customer counts primarily driven by XOOM acquisition in June 2018.	26
Higher gross margin due to unfavorable impacts from Hurricane Harvey in 2017 driven by $9 million from a reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7 million of customer relief	16
Increase in economic gross margin	$	175
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	235
Increase in gross margin	$	410

Generation gross margin and economic gross margin

Generation gross margin increased $14 million and economic gross margin increased $191 million, both of which include intercompany sales, during the nine months ended September 30, 2018, compared to the same period in 2017.

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

Gulf Coast Region



	(In millions)
Higher gross margin due to a 12% increase in average realized prices in Texas and a 4% increase in average realized prices in South Central	$	188
Higher gross margin from sales of NOx emission credits	35
Higher capacity margins due to an 11% increase in load demand in the South Central business	9
Higher gross margin from commercial optimization activities	7
Lower gross margin due to an increase in tolling purchases in 2018 as a result of increased demand and the cancellation of the Greens Bayou RMR agreement in 2017	(29		)
Lower energy margin due to an 18% increase in supply cost on load contracts	(13		)
Other	(5		)
Increase in economic gross margin	$	192
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(166		)
Increase in contract and emission credit amortization	3
Increase in gross margin	$	29

East/West/Other



	(In millions)
Lower gross margin primarily due to Ivanpah and Agua Caliente being deconsolidated in 2018	$	(88	)
Lower gross margin driven by 25% decrease in realized capacity pricing in New York and the expiration of Long Beach capacity toll in July 2017	(51		)
Lower gross margin due to less volume of load contracts coupled with lower prices	(26		)
Lower gross margin due to a 1% decrease in realized energy prices in the East	(10		)
Higher gross margin due to a 34% increase in in PJM cleared capacity and a 60% increase in NEISO cleared capacity	95
Higher gross margin from commercial optimization activities	33
Higher gross margin as a result of trading activity at BETM	25
Higher gross margin due to an increase in capacity volumes sold from improved historical capacity factors in NY	9
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
Decrease in economic gross margin	$	(1	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(16		)
Increase in contract and emission credit amortization	2
Decrease in gross margin	$	(15	)

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 $53 million during the nine months ended September 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:



	Nine months ended September 30, 2018
				Generation
	Retail			Gulf Coast			East/West/Other			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	)	$	89		$	(3	)	$	(148	)	$	(63	)
Net unrealized (losses)/gains on open positions related to economic hedges	(4		)	(96		)	5			127			32
Total mark-to-market (losses)/gains in operating revenues	$	(5	)	$	(7	)	$	2		$	(21	)	$	(31	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(156	)	$	(4	)	$	(10	)	$	148		$	(22	)
Reversal of acquired gain positions related to economic hedges	(11		)	—			—			—			(11		)
Net unrealized gains/(losses) on open positions related to economic hedges	253			(3		)	3			(127		)	126
Total mark-to-market gains/(losses) in operating costs and expenses	$	86		$	(7	)	$	(7	)	$	21		$	93


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



	Nine months ended September 30, 2017
				Generation
	Retail			Gulf Coast			East/West/Other			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	)	$	113		$	(32	)	$	21		$	101
Net unrealized gains/(losses) on open positions related to economic hedges	1			61			36			(22		)	76
Total mark-to-market gains/(losses) in operating revenues	$	—		$	174		$	4		$	(1	)	$	177
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(51	)	$	(12	)	$	1		$	(21	)	$	(83	)
Reversal of acquired gain positions related to economic hedges	(1		)	—			—			—			(1		)
Net unrealized (losses)/gains on open positions related to economic hedges	(102		)	(10		)	6			22			(84		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(154	)	$	(22	)	$	7		$	1		$	(168	)


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

For the nine months ended September 30, 2018, the $31 million loss in operating revenues from ~~various wind facilities~~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 the value of open positions as a result of decreases in outer year natural gas prices. The $93 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, partially offset by the ~~inclusion~~reversal of ~~consolidated partnerships~~previously recognized unrealized gains on contracts that settled during the period and ~~the current state tax expense.~~acquired deals.

For the ~~six~~nine months ended September 30, 2017, the $177 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 the value of open positions as a result of decreases in PJM power prices, New York capacity prices, and natural gas prices. The $168 million loss in operating costs and expenses from economic hedge positions was driven primarily by the decrease in value of open positions as a result of lower coal, natural gas and ERCOT power 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 nine months ended September 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 were primarily transacted through BETM.



	Nine months ended September 30,
(In millions)	2018		2017
Trading gains/(losses)
Realized	$	63	$	18
Unrealized	17		(7		)
Total trading gains	$	80	$	11

Operations and Maintenance Expense



	Retail		Generation				Corporate		Eliminations			Total
	Retail		Gulf Coast		East/West/Other^(a)		Corporate		Eliminations			Total
	(In millions)
Nine months ended September 30, 2018	$	152	$	419	$	317	$	2	$	(6	)	$	884
Nine months ended September 30, 2017	$	170	$	369	$	318	$	11	$	(4	)	864

(a) Includes International, Renewables, Generation and Generation eliminations

Operations and maintenance expense increased by $20 million for the nine months ended September 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 major maintenance due to planned outages of $15 million in Texas, increased outage hours at STP of $8 million, and $3 million in South Central, partially offset by $3 million due to forced outages related to Hurricane Harvey in 2017	23
Increase in operations and maintenance due to the gain on sale of Jewett Mine dragline in 2017	18
Increase in deactivation costs primarily at Dunkirk	8
Increase costs incurred for margin enhancement initiatives	2
Decrease in operations and maintenance expense due to cost efficiencies as a result of the Transformation Plan ^(a)	(58		)
Decrease in operations and maintenance due to deconsolidation of Ivanpah and Agua Caliente in 2018	(18		)
Increased compliance costs and other	12
	$	20

(a) Approximately $88 million of additional cost savings were achieved in the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016, as the savings became permanent through the Transformation Plan.

Depreciation and amortization

Depreciation and amortization decreased by $120 million for the nine months ended September 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 nine months ended September 30, 2018, the Company recorded impairment losses of $74 million related to the impairment of the Keystone and 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		Corporate		Total
			(In millions)
Nine months ended September 30, 2018	$	385	$	165	$	41	$	591
Nine months ended September 30, 2017	334		170		130		634

Selling, general and administrative expenses decreased by $43 million for the nine months ended September 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)	$	(133	)
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 bankruptcy proceedings	(11		)
Increase in selling and marketing expenses associated with costs incurred for margin enhancement initiatives	72
Increase in costs due to the XOOM acquisition	19
Increase in bad debt expense due to higher revenues	14
Other	16
	$	(43	)

(a) Approximately $67 million of additional cost savings were achieved in the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016, as the savings became permanent through the Transformation Plan.

Reorganization Costs

Reorganization costs, primarily related to employee severance and contract cancellation costs, of $70 million, were incurred as part of the Transformation Plan during the nine months ended September 30, 2018 compared to $18 million in the nine months ended September 30, 2017.

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 nine months ended September 30, 2018, consists primarily of the gain on the sale of BETM and Canal 3, while the gain on sale of assets for the nine months ended September 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 $46 million for the nine months ended September 30, 2018, compared to the nine months ended September 30, 2017, which was primarily driven by the equity in earnings recorded in 2018 for Ivanpah and Agua Caliente after deconsolidation, as well a prior year losses from Peta Nova.

Other Income, Net

Other income, net for the nine months ended September 30, 2018, primarily relates to the loss on deconsolidation as well as income from pension and postretirement investments. Other income for the nine months ended September 30, 2017, primarily relates to dividends received from cost method investments as well as income from pension and postretirement investments.

Interest Expense

NRG's interest expense decreased by $71 million for the nine months ended September 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	$	(20	)
Decrease in interest expense related to repurchases of Senior Notes	(29		)
Decrease in interest expense related to Ivanpah deconsolidation	(16		)
Decrease in interest expense related to Carlsbad deconsolidation	(7		)
Other	1
	$	(71	)

Loss on Debt Extinguishment

A loss on debt extinguishment of $22 million was recorded for the nine months ended September 30, 2018, primarily driven by the repurchase of Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.

Income Tax Expense

For the nine months ended September 30, 2018, NRG recorded an income tax expense of $19 million on pre-tax income of $620 million. For the same period in 2017, NRG recorded an income tax expense of $3 million on a pre-tax income of $119 million. The effective tax rate was 3.1% and 2.5% for the nine months ended September 30, 2018 and 2017, respectively.

For the nine months ended September 30, 2018, and 2017 NRG's overall effective tax rate was different than the statutory rate of 21% and 35%, respectively primarily due to the tax ~~expense~~benefit 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.~~current state tax expense.

Net ~~loss~~income attributable to noncontrolling interests and redeemable noncontrolling interests

For the ~~six~~nine months ended ~~June~~September 30, 2018, ~~and 2017,~~ net ~~loss~~income attributable to noncontrolling interests and redeemable noncontrolling ~~interests primarily reflects net losses allocated~~interest increased as compared to ~~tax equity investors~~the same period in ~~tax equity arrangements using~~2017, due to the ~~hypothetical liquidation at book value, or HLBV, method, partially offset by~~sale of NRG Yield, Inc.~~'s share of net income.~~ and Renewables Platform.

Liquidity and Capital Resources

Liquidity Position

As of ~~June~~September 30, 2018 and December 31, 2017, NRG's liquidity, excluding collateral received, was approximately ~~$2.5~~$2.8 billion and $~~3.2~~2.8 billion, respectively, comprised of the following:


(In millions)	June 30, 2018		December 31, 2017		September 30, 2018		December 31, 2017
Cash and cash equivalents:					$	1,359	$	767
NRG excluding NRG Yield	$	850	$	843
NRG Yield and subsidiaries	130		148
Restricted cash - operating	43		71		18		3
Restricted cash - reserves^(a)	243		437		10		276
Total	1,266		1,499		1,387		1,046
Total credit facility availability	1,222		1,711		1,454		1,711
Total liquidity, excluding collateral received	$	2,488	$	3,210	$	2,841	$	2,757

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

For the ~~six~~nine months ended ~~June~~September 30, 2018, total liquidity, excluding collateral funds deposited by counterparties, ~~decreased~~increased by ~~$722~~$84 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at ~~June~~September 30, 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.

Sources of Liquidity

The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from cash on hand, cash flows from operations, cash proceeds from future sales of assets, ~~including sales to NRG Yield, Inc. and 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 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 Yield Operating LLC senior unsecured notes, the NRG Yield, Inc. revolving credit facility,~~ and project-related financings.

The table below represents the approximate cash proceeds received from sale transactions and related financings completed by the company during the nine months ended September 30, 2018.



Sales	Cash Proceeds (in millions)
NRG Yield, Inc and Renewables Platform	$	1,348
Buckthorn Solar^(a)	42
UPMC Thermal Project ^(a)	84
BETM	70
Canal 3^(b)	167
Other Sales	12
Completed sales transactions as of September 30, 2018	$	1,723

^(a)Sale of ~~Ownership in NRG Yield, Inc. and Renewables Platform~~

~~On February 6, 2018, NRG and Global Infrastructure Partners, or GIP, entered into a purchase and sale agreement for GIP~~assets 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~~prior to discontinued operations ~~platforms and NRG's renewable energy non-ROFO backlog and pipeline.~~

^(b)In ~~connection with the transaction, the Company entered into a Consent and Indemnity Agreement with NRG Yield, Inc. and GIP setting forth key terms and conditions of NRG Yield, Inc.'s consent~~addition to the 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 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 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 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.

~~Sales of 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, subject to working capital adjustments.~~

On March 30, 2018, as part of the Transformation Plan, 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.

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. The transaction is expected to close during the fourth quarter of 2018.

~~Sale of Canal 3~~

~~On June 29, 2018, the Company completed the sale of Canal 3 to Stonepeak Kestrel for~~ cash proceeds ~~of approximately $16~~from sale, amount includes $151 million ~~and recorded a gain of $17 million. Prior~~related to ~~the sale, Canal 3 entered into~~ a financing arrangement ~~and received~~prior to the sale

The table below represents the approximate cash proceeds ~~of $167 million, of which $151 million was distributed~~expected from sales transactions anticipated to be completed by the Company. ~~The related debt is non-recourse to NRG and was transferred to Stonepeak Kestrel in connection with the sale of Canal 3.~~

~~Other Asset Sales~~

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



Expected Sales	Expected Close Date	Expected Cash Proceeds (in millions)
South Central Business	Q4 2018	$	1,000
Carlsbad	Q1 2019	365
Expected cash proceeds from anticipated sales transactions		$	1,365

2023 Term Loan Facility

On March 21, 2018, NRG 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.

~~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 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. 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. 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 ~~June~~September 30, 2018, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

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


Equivalent Net Sales Secured by First Lien Structure ^(a)	2018	2019	2020	2021	2022	2023	2018	2019	2020	2021	2022	2023
In MW	264	908	916	765	828	860	372	849	835	685	728	790
As a percentage of total net coal and nuclear capacity ^(b)	6%	19%	20%	16%	18%	18%	8%	18%	18%	15%	16%	17%


(a)	Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.


(b)	Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien which excludes coal assets acquired in the EME (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; (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases, return of capital and dividend payments to stockholders; and (v) costs necessary to execute the Transformation Plan.

Commercial Operations

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 ~~June~~September 30, 2018, commercial operations had total cash collateral outstanding of ~~$234~~$197 million and ~~$953~~$693 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of ~~June~~September 30, 2018, total collateral held from counterparties was ~~$76~~$30 million in cash and ~~$198~~$68 million of 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 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 ~~six~~nine months ended ~~June~~September 30, 2018, and the estimated capital expenditure and growth investments forecast for the remainder of 2018.


	Maintenance		Environmental		Growth Investments ^(b)			Total			Maintenance		Environmental		Growth Investments ^(b)			Total
	(In millions)										(In millions)
Retail	$	12	$	—	$	22		$	34		$	14	$	—	$	45		$	59
Generation
Gulf Coast	70		—		—			70			93		—		—			93
East/West ^(a)	15		—		208			223
Renewables	2		—		286			288
NRG Yield	17		—		28			45
East/West/Other ^(a)											22		1		133			156
Corporate	6		—		25			31			6		—		31			37
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		)
Total cash capital expenditures for the nine months ended September 30, 2018											135		1		209			345
Funding from debt financing, net of fees											—		—		(247		)	(247		)
Other investments ^(c)	—		—		286			286			—		—		232			232
Total capital expenditures and investments, net of financings	122		—		237			359			135		1		194			330

Estimated capital expenditures for the remainder of 2018	99		3		231			333			40		2		63			105
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(73		)	(73		)
Funding from debt financing, net of fees											—		—		84			84
Other investments ^(c)	—		—		10			10			—		—		64			64
NRG estimated capital expenditures for the remainder of 2018, net of financings ^(d)	$	99	$	3	$	168		$	270		$	40	$	2	$	211		$	253

(a) Includes International and ~~BETM~~Renewables

(b) ~~Total cash capital expenditures include $25~~Growth includes $44 million of cost-to-achieve spend associated with the Transformation Plan

(d) Maintenance capital expenditures includes approximately ~~$66~~$19 million for assets to be sold

Growth Investments capital expenditures

For the ~~six~~nine months ended ~~June~~September 30, 2018, the Company's growth investment capital expenditures included ~~$266 million for renewable projects, $208~~$134 million for repowering projects and ~~$95~~$75 million for the Company's other growth projects.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2018 through 2022 required to comply with environmental laws will be approximately ~~$76 million, which includes $14 million for Midwest Generation.~~$39 million.

Common Stock Dividends

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

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



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

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

Share Repurchases

In In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock. As of September 30, 2018, the Company has completed the stock ~~with~~repurchase program. During the ~~first $500 million program beginning as soon as permitted. In March~~nine months ended September 30, 2018, the Company repurchased ~~3,114,748 shares of NRG common stock for approximately $93 million. During the second quarter of 2018,~~ 28,544,693 shares. As discussed in more detail in Note 10, Changes in Capital Structure, the Company ~~repurchased 11,748,553~~may receive additional 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~~upon settlement of the September ASR ~~Agreement, completing the $500 million of share repurchases. The average cost per share for the total $500 million of shares repurchased was $31.80.~~on or before December 31, 2018.

Senior Note Repurchases

~~In connection with~~During the ~~Transformation Plan,~~second and third quarter, the Company ~~has committed to 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~~completed open market senior note repurchases ~~were completed to assist~~and partially redeemed the 6.250% notes due 2022, as detailed in ~~achieving this target.~~the table below. During the nine months ended September 30, 2018, a $22 million loss on debt extinguishment was recorded for these repurchases, which included the write-off of previously deferred financing costs of $6 million.


	Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage		Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage
In millions, except rates
5.750% senior notes due 2028	$	29	$	30	99.24	%	$	29	$	30	99.24	%
6.250% senior notes due 2022	14		15		103.25	%	14		15		103.25	%
Total at June 30, 2018	$	43	$	45			$	43	$	45
6.250% senior notes due 2022	$	6	$	6	103.25	%
6.250% senior notes due 2022^(b)							492		512		103.13	%
5.750% senior notes due 2028	20		21		99.13	%	20		20		99.13	%
6.625% senior notes due 2027	20		21		103.06	%	20		21		103.06	%
Total at August 2, 2018	$	89	$	93
Total at September 30, 2018							$	575	$	598

(a) Includes payment for accrued ~~interest.~~interest of $7 million as of September 30, 2018

~~As discussed in more detail in "Significant Events" in this~~ ~~Management's Discussion and Analysis~~(b) Includes partial redemption of ~~Financial Condition and Results~~$486 million during the third quarter of ~~Operations, on August 1,~~2018

On October 9, 2018, the Company ~~announced that it gave the required notice under the indenture governing~~redeemed all of its ~~6.25% Senior Notes~~outstanding 6.250% senior notes due 2022 ~~to redeem for cash $486 million~~in the aggregate principal amount of $485 million.

2023 Term Loan Facility

In accordance with the terms of the Credit Agreement, on October 5, 2018, the Company initiated an asset sale offer to purchase a portion of its ~~2022 Notes~~Term Loan following the sale of NRG Yield and the Renewables Platform. The offer expired on ~~August 31, 2018.~~November 5, 2018, and $260 million of Term Loan holders accepted the offer. As a result, the Company prepaid $155 million of Term Loans as part of its de-leveraging plan, as well as established an incremental first lien secured loan term facility under the Senior Credit Facility in the aggregate principal amount of $105 million on the same terms and conditions to stay within its debt reduction target.

Small Book Acquisitions

Through the end of October 2018, the Company has agreed to acquire several books of customers totaling approximately 115,000 customers, along with brand names, for $44 million.

XOOM Energy Acquisition

~~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.

~~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 April 20, 2018, NRG filed a motion requesting an additional extension of the suspension period to coincide with the CPUC’s final decision on SCE’s application seeking approval of resources procured through its Moorpark RFO, or until June 30, 2019, whichever is sooner.aggregate.

Cash Flow Discussion

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


	Six months ended June 30,									Nine months ended September 30,
	2018			2017			Change			2018			2017			Change
	(In millions)									(In millions)
Net cash provided/(used) by operating activities	$	524		$	74		$	450
Net cash provided by operating activities										$	1,082		$	736		$	346
Net cash used by investing activities	(1,146		)	(545		)	(601		)	(59		)	(422		)	363
Net cash used by financing activities	423			18			405			(666		)	(214		)	(452		)

Net Cash Provided By Operating Activities

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


	(In millions)			(In millions)
Increase in operating income adjusted for non-cash items	$	262		$	332
Changes in cash collateral in support of risk management activities due to changes in commodity prices	171
Change in cash from discontinued operations				146
Decrease in cash collateral paid/received in support of energy risk management activities				73
GenOn settlement in July 2018				(125		)
Increase in accounts receivable, net of payables, due to increased revenues within the Retail segment				(51		)
Other changes in working capital	(21		)	(29		)
Change in cash from discontinued operations	38
	$	450		$	346

Net Cash Used By Investing Activities

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

(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 )



	(In millions)
Increase in proceeds from sale of assets, primarily from sale of discontinued operations	$	1,246
Cash removed due to deconsolidation of business in 2018	(268		)
Increase in cash paid for acquisitions in 2018, primarily from the XOOM Energy acquisition	(197		)
Increase in capital expenditures for growth investments in generation assets	(173		)
Decrease in net contributions to unconsolidated affiliates	(86		)
Change in cash from discontinued operations	(65		)
Decrease in sales of emissions, net of purchases	(33		)
Increase in investments in nuclear decommissioning trust net of proceeds from sales	(31		)
Decrease in insurance proceeds received	(22		)
Other	(8		)
	$	363

Net Cash Provided By Financing Activities

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


	(In millions)			(In millions)
Repurchases of common stock in 2018, from open market repurchases and the ASR Agreement	$	(500	)	$	(1,000	)
Increase in payments for short and long-term debt	(318		)	(627		)
Increase in proceeds from the issuance of long-term debt, primarily for the Convertible Notes	659
Increase in proceeds from the issuance of long-term debt, primarily the 2.75% Convertible Notes				687
Change in cash from discontinued operations including long-term deposits in 2017	349			364
Increase in cash contributions, net of distributions from non-controlling interests in 2018, primarily related to tax equity financings	208
Decrease in notes issued to affiliates				99
Decrease in deferred financing costs due to fewer debt instruments refinanced in 2018				20
Other	7			5
	$	405		$	(452	)

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

For the ~~six~~nine months ended ~~June~~September 30, 2018, the Company had a total domestic pre-tax book income of ~~$361~~$620 million and an immaterial foreign pre-tax book income. As of December 31, 2017, the Company had cumulative domestic Federal NOL carryforwards of ~~$2.8~~$3.4 billion based on the latest income tax return filing, which will begin expiring in ~~2026~~2031 and cumulative state NOL carryforwards of $2.2 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of ~~$224~~$216 million, which do not have an expiration date. The NOL balances do not include the projected taxable income related to the sale of NRG Yield and the Renewable Platform of an estimated $1.8 billion. Contingent upon GenOn's emergence from bankruptcy, the Company will recognize an estimated $9.7 billion worthless stock deduction for tax purposes.

In addition to these amounts, the Company has ~~$39~~$47 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 $20 million in 2018.

The Company has recorded a non-current tax liability of ~~$39~~$47 million until final resolution with the related taxing authority. The ~~$39~~$47 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.

The Company is 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.

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

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

Retained or Contingent Interests

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

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of ~~June~~September 30, 2018, NRG has ~~several~~ investments in energy and energy-related entities that are accounted for under the equity method of accounting. ~~Several of these investments are~~NRG’s investment in Ivanpah is a variable interest ~~entities~~entity 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 ~~$1.2~~$1.0 billion as of ~~June~~September 30, 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 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 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 ~~six~~nine months ended ~~June~~September 30, 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 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 ~~June~~September 30, 2018, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at ~~June~~September 30, 2018.


Derivative Activity Gains	(In millions)
Derivative Activity Gains/(Losses)			(In millions)
Fair Value of Contracts as of December 31, 2017	$	46	$	103
Contracts realized or otherwise settled during the period	9		(106		)
Contracts acquired during the period	11		11
Changes in fair value	217		160
Fair Value of Contracts as of June 30, 2018	$	283
Fair Value of Contracts as of September 30, 2018			$	168


	Fair Value of Contracts as of June 30, 2018															Fair Value of Contracts as of September 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	$	(9	)	$	(30	)	$	(8	)	$	(1	)	$	(48	)	$	(27	)		$	(27	)	$	(7	)	$	—		$	(61	)
Level 2	10			137			16			15			178			148			—	105			3			(14		)	242
Level 3	141			32			(6		)	(14		)	153			12				(8		)	(3		)	(14		)	(13		)
Total	$	142		$	139		$	2		$	—		$	283		$	133			$	70		$	(7	)	$	(28	)	$	168

The Company has elected to present derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3 - Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of ~~June~~September 30, 2018, NRG's net derivative asset was ~~$283~~$168 million, an increase to total fair value of ~~$237~~$64 million as compared to December 31, 2017. This increase was driven by gains in fair value and acquired contracts, ~~and the~~partially offset by 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 a decrease of approximately ~~$191~~$197 million in the net value of derivatives as of ~~June~~September 30, 2018. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in an increase of approximately ~~$183~~$193 million in the net value of derivatives as of ~~June~~September 30, 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 annual budget is utilized to determine the cash flows associated with the Company's long-lived assets, which incorporates various assumptions, including the Company's long-term view of natural gas prices and its impact on merchant power prices and fuel costs. The Company's annual budget process is finalized and approved by the Board of Directors in the fourth quarter. It is reasonably possible that the updated long-term cash flows will not support the carrying value of certain assets, and the Company will be required to 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. Accordingly, if these decreases continue, it is possible that the Company's goodwill or long-lived assets will be impaired.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A — Quantitative and Qualitative Disclosures About Market Risk, of the Company's 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 ~~six~~nine months ending ~~June~~September 30, 2018 and 2017:


(In millions)	2018		2017		2018		2017
VaR as of June 30,	$	54	$	49
Three months ended June 30,
VaR as of September 30,					$	72	$	40
Three months ended September 30,
Average	$	59	$	59	$	67	$	30
Maximum	68		66		75		40
Minimum	52		49		61		25
Six months ended June 30,
Nine months ended September 30,
Average	59		$	56	62		$	27
Maximum	69		66		75		40
Minimum	48		41		48		20

In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of ~~June~~September 30, 2018, for the entire term of these instruments entered into for both asset management and trading was ~~$25~~$16 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 2017 Form 10-K for more information on the Company's interest rate swaps.

If all of the above swaps had been discontinued on ~~June~~September 30, 2018, the ~~Company~~counterparties would have owed the ~~counterparties~~Company $7954 million. Based on the credit ratings of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of ~~June~~September 30, 2018, a 1% change in variable interest rates would result in a $~~14.3~~8.6 million change in interest expense on a rolling twelve-month basis.

As of ~~June~~September 30, 2018, the fair value and related carrying value of the Company's debt was ~~$16.2~~$7.7 billion and ~~$16.0~~$7.3 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 ~~$981~~$541 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 $6182 million as of ~~June~~September 30, 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 $4467 million as of ~~June~~September 30, 2018. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of ~~June~~September 30, 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 internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the quarter ended ~~June~~September 30, 2018 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through ~~June~~September 30, 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 2017 Form 10-K. There have been no material changes in the Company's risk factors since those reported in its 2017 Form 10‑K.

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

In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock. As of September 30, 2018, the Company has completed the $1 billion common stock ~~with the first $500 million program beginning as soon as permitted. The authorization did not specify an expiration date.~~repurchase program.

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~~September 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



For the three months ended September 30, 2018	Total Number of Shares Purchased	Average Price Paid per Share		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
Month #1
(July 1, 2018 to July 31, 2018)	860,880	(a)		860,880	$	499,950,111
Month #2
(August1, 2018 to August 31, 2018)	—	$	—	—	$	499,950,111
Month #3
(September 1, 2018 to September 30, 2018)	12,820,512	(b)		12,820,512	$	—
Total at September 30, 2018	13,681,392			13,681,392


(a)	In May 2018, the Company executed an ASR Agreement to repurchase $354 million of outstanding common stock. 9,969,023 shares were delivered in May and additional 860,880 shares were delivered in July. The average price paid for all of the shares under the May ASR was $32.69 per share.

~~(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.~~


(b)	In September 2018, the Company executed an additional ASR Agreement to repurchase $500 million of outstanding common stock. The company received initial shares of 12,820,512 in September. The total number of shares ultimately delivered, and therefore the average price paid per share, will be determined at the end of the ASR period based on the total number of shared delivered under the ASR.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

See Note 3, Discontinued Operations and Dispositions, to the Condensed Consolidated Financial Statements of the Company's 2017 Form 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~~	Third Amendment Agreement, dated as of May 7, 2018, by and among NRG Energy, Inc., its subsidiaries parties thereto, the lenders from time to time parties thereto and 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 May 7, 2018.~~
~~10.2~~	~~NRG Energy, Inc. Amended and Restated Executive Change-in-Control and General Severance Plan for Tier IA and Tier IIA Executives (Amended and Restated Effective April 1, 2018).~~	~~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: ~~August 2,~~November 8, 2018	Chief Accounting Officer (Principal Accounting Officer)

~~110~~107



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	67
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	~~105~~102
ITEM 4 — CONTROLS AND PROCEDURES	~~107~~104
PART II — OTHER INFORMATION	~~108~~105
ITEM 1 — LEGAL PROCEEDINGS	~~108~~105
ITEM 1A — RISK FACTORS	~~108~~105
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	~~108~~105
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	~~108~~105
ITEM 4 — MINE SAFETY DISCLOSURES	~~108~~105
ITEM 5 — OTHER INFORMATION	~~108~~105
ITEM 6 — EXHIBITS	~~109~~106
SIGNATURES	~~110~~107



	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



	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



	(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	)



	(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



	(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	)



	(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	)



	(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



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