NRG ENERGY, INC. - Quarter Report: 2018 March (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

		For the Quarterly Period Ended: March 31, 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 March 31, 2018, there were 314,886,197 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS

Index



CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	5
PART I — FINANCIAL INFORMATION	10
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	10
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	55
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	81
ITEM 4 — CONTROLS AND PROCEDURES	83
PART II — OTHER INFORMATION	84
ITEM 1 — LEGAL PROCEEDINGS	84
ITEM 1A — RISK FACTORS	84
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	84
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	84
ITEM 4 — MINE SAFETY DISCLOSURES	84
ITEM 5 — OTHER INFORMATION	84
ITEM 6 — EXHIBITS	85
SIGNATURES	86

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;


•	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 assets to NRG Yield, Inc. and to close drop-down transactions;


•	NRG's ability to achieve its strategy of regularly returning capital to stockholders;


•	NRG's ability to obtain and maintain retail market share;


•	NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives;


•	NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses; and


•	NRG's ability to develop and maintain successful partnering relationships.

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

GLOSSARY OF TERMS

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



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
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
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., the owner of 53.7% of the economic interests of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A and Class C common stock
NSR		New Source Review
Nuclear Decommissioning Trust Fund		NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, units 1 & 2
NYAG		State of New York Office of Attorney General
NYISO		New York Independent System Operator
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 a lower level of execution certainty.
PJM		PJM Interconnection, 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
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 billion revolving credit facility, a component of the Senior Credit Facility. The revolving credit facility consists of $289 million of Tranche A Revolving Credit Facility, due 2018, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021
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.
Settlement Agreement		A settlement agreement and any other documents necessary to effectuate the settlement among NRG, GenOn, and certain holders of senior unsecured notes of GenOn Americas Generation and GenOn, and certain of GenOn's direct and indirect subsidiaries
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
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
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
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 March 31,
(In millions, except for per share amounts)	2018			2017
Operating Revenues
Total operating revenues	$	2,421		$	2,382
Operating Costs and Expenses
Cost of operations	1,558			1,862
Depreciation and amortization	235			257
Selling, general and administrative	191			260
Reorganization costs	20			—
Development costs	13			17
Total operating costs and expenses	2,017			2,396
Other income - affiliate	—			48
Gain on sale of assets	2			2
Operating Income	406			36
Other Income/(Expense)
Equity in (losses)/earnings of unconsolidated affiliates	(2		)	5
Other (expense)/income, net	(3		)	13
Loss on debt extinguishment, net	(2		)	(2		)
Interest expense	(167		)	(225		)
Total other expense	(174		)	(209		)
Income/(Loss) from Continuing Operations Before Income Taxes	232			(173		)
Income tax benefit	(1		)	(4		)
Income/(Loss) from Continuing Operations	233			(169		)
Loss from discontinued operations, net of income tax	—			(34		)
Net Income/(Loss)	233			(203		)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests	(46		)	(40		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	279		$	(163	)
Earnings/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	318			316
Income/(loss) from continuing operations per weighted average common share — basic	$	0.88		$	(0.41	)
Loss from discontinued operations per weighted average common share — basic	$	—		$	(0.11	)
Earnings/(Loss) per Weighted Average Common Share — Basic	$	0.88		$	(0.52	)
Weighted average number of common shares outstanding — diluted	322			316
Income/(loss) from continuing operations per weighted average common share — diluted	$	0.87		$	(0.41	)
Loss from discontinued operations per weighted average common share — diluted	$	—		$	(0.11	)
Earnings/(Loss) per Weighted Average Common Share — Diluted	$	0.87		$	(0.52	)
Dividends Per Common Share	$	0.03		$	0.03

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)



	Three months ended March 31,
	2018			2017
	(In millions)
Net income/(loss)	$	233		$	(203	)
Other comprehensive income/(loss), net of tax
Unrealized gain on derivatives, net of income tax expense of $0 and $1	14			4
Foreign currency translation adjustments, net of income tax expense of $0 and $0	(2		)	7
Defined benefit plans, net of income tax expense of $0 and $0	(1		)	—
Other comprehensive income	11			11
Comprehensive income/(loss)	244			(192		)
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest	(38		)	(39		)
Comprehensive income/(loss) attributable to NRG Energy, Inc.	282			(153		)
Comprehensive income/(loss) available for common stockholders	$	282		$	(153	)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions, except shares)	March 31, 2018			December 31, 2017
ASSETS
Current Assets
Cash and cash equivalents	$	764		$	991
Funds deposited by counterparties	241			37
Restricted cash	407			508
Accounts receivable, net	903			1,079
Inventory	528			532
Derivative instruments	1,015			626
Cash collateral paid in support of energy risk management activities	211			171
Accounts receivable - affiliate	73			95
Current assets - held for sale	89			115
Prepayments and other current assets	326			261
Total current assets	4,557			4,415
Property, plant and equipment, net	13,911			13,908
Other Assets
Equity investments in affiliates	1,011			1,038
Goodwill	539			539
Intangible assets, net	1,726			1,746
Nuclear decommissioning trust fund	680			692
Derivative instruments	354			172
Deferred income taxes	136			134
Non-current assets held-for-sale	157			43
Other non-current assets	681			631
Total other assets	5,284			4,995
Total Assets	$	23,752		$	23,318
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	956		$	688
Accounts payable	787			881
Accounts payable - affiliate	32			33
Derivative instruments	790			555
Cash collateral received in support of energy risk management activities	240			37
Current liabilities held-for-sale	80			72
Accrued expenses and other current liabilities	662			890
Accrued expenses and other current liabilities - affiliate	161			161
Total current liabilities	3,708			3,317
Other Liabilities
Long-term debt and capital leases	15,406			15,716
Nuclear decommissioning reserve	272			269
Nuclear decommissioning trust liability	400			415
Deferred income taxes	20			21
Derivative instruments	264			197
Out-of-market contracts, net	201			207
Non-current liabilities held-for-sale	7			8
Other non-current liabilities	1,136			1,122
Total non-current liabilities	17,706			17,955
Total Liabilities	21,414			21,272
Redeemable noncontrolling interest in subsidiaries	80			78
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4
Additional paid-in capital	8,379			8,376
Accumulated deficit	(5,982		)	(6,268		)
Less treasury stock, at cost — 104,518,931 and 101,580,045 shares, at March 31, 2018 and December 31, 2017, respectively	(2,474		)	(2,386		)
Accumulated other comprehensive loss	(61		)	(72		)
Noncontrolling interest	2,392			2,314
Total Stockholders’ Equity	2,258			1,968
Total Liabilities and Stockholders’ Equity	$	23,752		$	23,318

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three months ended March 31,
(In millions)	2018			2017
Cash Flows from Operating Activities
Net income/(loss)	$	233		$	(203	)
Loss from discontinued operations, net of income tax	—			(34		)
Income/(loss) from continuing operations	233			(169		)
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	12			8
Depreciation and amortization	235			257
Provision for bad debts	15			9
Amortization of nuclear fuel	13			12
Amortization of financing costs and debt discount/premiums	14			15
Adjustment for debt extinguishment	2			—
Amortization of intangibles and out-of-market contracts	22			30
Amortization of unearned equity compensation	13			8
Changes in deferred income taxes and liability for uncertain tax benefits	(3		)	1
Changes in nuclear decommissioning trust liability	34			36
Changes in derivative instruments	(247		)	38
Changes in collateral deposits in support of energy risk management activities	163			(127		)
Gain on sale of emission allowances	(8		)	—
Gain on sale of assets	(2		)	(2		)
Changes in other working capital	(139		)	(198		)
Cash provided/(used) by continuing operations	357			(82		)
Cash provided by discontinued operations	—			15
Net Cash Provided/(Used) by Operating Activities	357			(67		)
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(62		)	(3		)
Capital expenditures	(358		)	(236		)
Decrease in notes receivable	3			4
Purchases of emission allowances	(17		)	(9		)
Proceeds from sale of emission allowances	23			11
Investments in nuclear decommissioning trust fund securities	(216		)	(153		)
Proceeds from the sale of nuclear decommissioning trust fund securities	182			117
Proceeds from sale of assets, net of cash disposed of	11			14
Changes in investments in unconsolidated affiliates	2			(12		)
Other	—			18
Cash used by continuing operations	(432		)	(249		)
Cash used by discontinued operations	—			(32		)
Net Cash Used by Investing Activities	(432		)	(281		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(10		)	(9		)
Payment for treasury stock	(93		)	—
Net receipts from settlement of acquired derivatives that include financing elements	—			1
Proceeds from issuance of long-term debt	179			193
Payments for short and long-term debt	(228		)	(177		)
Net contributions from/(distributions to) noncontrolling interests in subsidiaries	110			(5		)
Payment of debt issuance costs	(7		)	(14		)
Other - contingent consideration	—			(10		)
Cash used by continuing operations	(49		)	(21		)
Cash used by discontinued operations	—			(132		)
Net Cash Used by Financing Activities	(49		)	(153		)
Effect of exchange rate changes on cash and cash equivalents	—			(7		)
Change in Cash from discontinued operations	—			(149		)
Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(124		)	(359		)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	1,536			1,386
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	1,412		$	1,027

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 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 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 March 31, 2018, and the results of operations, comprehensive income/(loss) and cash flows for the three months ended March 31, 2018 and 2017.

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:



	March 31, 2018		December 31, 2017
	(In millions)
Accounts receivable allowance for doubtful accounts	$	27	$	28
Property, plant and equipment accumulated depreciation	4,679		4,465
Intangible assets accumulated amortization	1,393		1,818
Out-of-market contracts accumulated amortization	364		358

Restricted Cash

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



	March 31, 2018		December 31, 2017		March 31, 2017		December 31, 2016
	(In millions)
Cash and cash equivalents	$	764	$	991	$	627	$	938
Funds deposited by counterparties	241		37		3		2
Restricted cash	407		508		397		446
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,412	$	1,536	$	1,027	$	1,386

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

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

Noncontrolling Interest

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



	(In millions)
Balance as of December 31, 2017	$	2,314
Dividends paid to NRG Yield, Inc. public shareholders	(30		)
Distributions to noncontrolling interest	(19		)
Comprehensive loss attributable to noncontrolling interest	(22		)
Non-cash adjustments to noncontrolling interest	6
Contributions from noncontrolling interest	147
Sale of assets to NRG Yield, Inc.	(4		)
Balance as of March 31, 2018	$	2,392

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	(1		)
Contributions from redeemable noncontrolling interest	12
Non-cash adjustments to redeemable noncontrolling interest	7
Comprehensive loss attributable to redeemable noncontrolling interest	(16		)
Balance as of March 31, 2018	$	80

Revenue Recognition

Revenue from Contracts with Customers

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

Retail Revenues

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

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

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

Energy Revenue

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

Capacity Revenue

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

Capacity revenue contracts mainly consist of:

Capacity auctions — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO. Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time performance, where NRG's actual revenues will be the combination of revenues based on the cleared auction MWs plus the net of any over- and under-performance of NRG's fleet. In addition, MISO has an annual auction, known as the Planning Resource Auction, or PRA. The Gulf Coast assets situated in the MISO market may participate in this auction. Estimated revenues for cleared auction MWs in the various capacity auctions are $554 million, $508 million, $423 million, $222 million and $57 million for fiscal years 2018, 2019, 2020, 2021 and 2022, respectively.

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

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

Renewable Energy Credits

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

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

Sale of Emission Allowances

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

Disaggregated Revenues

The following table represents the Company’s disaggregation of revenue from contracts with customers for the three months ended March 31, 2018, along with the reportable segment for each category:



	Three months ended March 31, 2018
				Generation
(In millions)	Retail			Gulf Coast			East/West^(a)			Subtotal			Renewables			NRG Yield			Eliminations			Total
Energy revenue^(a)(b)	$	—		$	371		$	218		$	589		$	77		$	114		$	(161	)	$	619
Capacity revenue^(a)(b)	—			67			140			207			—			82			(1		)	288
Retail revenue
Mass customers	1,171			—			—			—			—			—			(1		)	1,170
Business solutions customers	316			—			—			—			—			—			—			316
Total retail revenue	1,487			—			—			—			—			—			(1		)	1,486
Mark-to-market for economic hedging activities^(c)	(6		)	(564		)	(10		)	(574		)	(10		)	—			484			(106		)
Contract amortization	—			3			—			3			—			(17		)	—			(14		)
Other revenue^(a)(b)	—			86			16			102			19			46			(19		)	148
Total operating revenue	1,481			(37		)	364			327			86			225			302			2,421
Less: Lease revenue	6			—			1			1			64			181			—			252
Less: Derivative revenue	(6		)	(188		)	80			(108		)	(10		)	—			484			360
Less: Contract amortization	—			3			—			3			—			(17		)	—			(14		)
Total revenue from contracts with customers	$	1,481		$	148		$	283		$	431		$	32		$	61		$	(182	)	$	1,823
(a) The following amounts of energy and capacity revenue relate to leases and are accounted for under ASC 840:
	Retail			Gulf Coast			East/West			Subtotal			Renewables			NRG Yield			Eliminations			Total
Energy revenue	—			—			—			—			61			102			—			163
Capacity revenue	—			—			—			—			—			79			—			79
Other revenue	6			—			1			1			3			—			—			10
(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	—			371			61			432			—			—			—			432
Capacity revenue	—			—			26			26			—			—			—			26
Other revenue	—			5			3			8			—			—			—			8
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.

Contract Amortization

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

Lease Revenue

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

Contract Balances

The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of March 31, 2018:




(In millions)	March 31, 2018
Deferred customer acquisition costs	$	85

Accounts receivable, net - Contracts with customers	784
Accounts receivable, net - Leases	81
Accounts receivable, net - Derivative instruments	38
Total accounts receivable, net	903

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	292

Deferred revenues	63

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

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 a corresponding increase in other income, net on the statement of operations for the three months ended March 31, 2017.

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.

Note 3 — 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.

Discontinued Operations

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 March 31, 2017
(In millions)	Three months ended March 31, 2017
Operating revenues	$	381
Operating costs and expenses	(373		)
Other expenses	(44		)
Loss from operations of discontinued components, before tax	(36		)
Income tax expense	1
Loss from operations of discontinued components	(37		)
Interest income - affiliate	3
Loss from discontinued operations, net of tax	$	(34	)

Income recorded from discontinued operations was immaterial for the three months ended March 31, 2018.

Restructuring Support Agreement

NRG, GenOn and certain holders representing greater than 93% in aggregate principal amount of GenOn’s Senior Notes and certain holders representing greater than 93% in aggregate principal amount of GenOn Americas Generation’s Senior Notes entered into a Restructuring Support Agreement that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization that was approved by the Bankruptcy Court pursuant to an order of confirmation. Completion of the agreed upon terms is contingent upon certain milestones in the Restructuring Support Agreement and the satisfaction or waiver or certain conditions precedent. Certain principal terms of the Restructuring Support Agreement and the plan of reorganization are detailed below:


1)	The dismissal of litigation and full releases from GenOn and GenOn Americas Generation in favor of NRG upon the earlier of the consummation of the GenOn Entities' plan of reorganization or the Settlement Agreement; a condition precedent to the consummation of the Settlement Agreement is a full release or indemnification in favor of NRG from any claims of GenOn Mid-Atlantic and REMA.

NRG will provide settlement cash consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility. As of March 31, 2018, GenOn owed NRG approximately $125 million under the intercompany secured revolving credit facility. See Note 13, 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 March 31, 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 March 31, 2018, was approximately $91 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 March 31, 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 will continue to provide the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments. See Note 13, Related Party Transactions, for further discussion of the Services Agreement.


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

NRG and GenOn have 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. On March 22, 2018, NRG agreed to sell Canal 3 to Stonepeak Kestrel Holdings II LLC in conjunction with GenOn's sale of Canal Units 1 and 2 to Stonepeak Kestrel Holdings LLC. NRG expects to reimburse GenOn for $13.5 million of the one-time payment upon the close of the sale of Canal 3. This amount is recorded as a current liability as of March 31, 2018, and December 31, 2017.

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.

Transfer of Assets Under Common Control

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.

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.

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 March 31, 2018				As of December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable^(a)	$	15	$	14	$	16	$	15
Liabilities:
Long-term debt, including current portion^(b)	16,559		16,687		16,603		16,894

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

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

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



	As of March 31, 2018				As of December 31, 2017
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	8,772	$	7,915	$	8,934	$	7,960

Recurring Fair Value Measurements

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

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



	As of March 31, 2018
	Fair Value
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other non-current assets)	$	22	$	3	$	—	$	19
Nuclear trust fund investments:
Cash and cash equivalents	16		16		—		—
U.S. government and federal agency obligations	56		55		1		—
Federal agency mortgage-backed securities	92		—		92		—
Commercial mortgage-backed securities	16		—		16		—
Corporate debt securities	100		—		100		—
Equity securities	333		333		—		—
Foreign government fixed income securities	5		—		5		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,277		168		1,060		49
Interest rate contracts	92		—		92		—
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	62
Total assets	$	2,072	$	576	$	1,366	$	68
Derivative liabilities:
Commodity contracts	1,024		224		729		71
Interest rate contracts	30		—		30		—
Total liabilities	$	1,054	$	224	$	759	$	71



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

There were no transfers during the three months ended March 31, 2018 and 2017 between Levels 1 and 2. The following tables reconcile, for the three months ended March 31, 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)
	Three months ended March 31, 2018
(In millions)	Debt Securities		Derivatives^(a)			Total
Beginning balance	$	19	$	(32	)	$	(13	)
Total gains — realized/unrealized:
Included in earnings	—		2			2
Purchases	—		1			1
Transfers into Level 3 ^(b)	—		4			4
Transfers out of Level 3 ^(b)	—		3			3
Ending balance as of March 31, 2018	$	19	$	(22	)	$	(3	)
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 March 31, 2018	$	—	$	3		$	3


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


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



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended March 31, 2017
(In millions)	Debt Securities		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance	$	17	$	54	$	(68	)	$	3
Total gains — realized/unrealized:
Included in earnings	1		—		6			7
Included in nuclear decommissioning obligation	—		4		—			4
Purchases	—		—		4			4
Transfers into Level 3 ^(b)	—		—		(8		)	(8		)
Transfers out of Level 3 ^(b)	—		—		10			10
Ending balance as of March 31, 2017	$	18	$	58	$	(56	)	$	20
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of March 31, 2017	$	—	$	—	$	(15	)	$	(15	)


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


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

Derivative Fair Value Measurements

A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of March 31, 2018, contracts valued with prices provided by models and other valuation techniques make up 4% of the total derivative assets and 7% 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 March 31, 2018 and December 31, 2017:



	Significant Unobservable Inputs
	March 31, 2018
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	38	$	63	Discounted Cash Flow	Forward Market Price (per MWh)	$	9		$	319	$	40
FTRs	11		8		Discounted Cash Flow	Auction Prices (per MWh)	(28		)	46		—
	$	49	$	71



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

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of March 31, 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 March 31, 2018, the credit reserve resulted in a $2 million decrease in fair value in operating revenue and cost of operations. As of December 31, 2017, the credit reserve resulted in no change in fair value in operating revenue and cost of operations.

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company's 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 March 31, 2018, the Company's counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $505 million with net exposure of $244 million. NRG held collateral (cash and letters of credit) against those positions of $264 million. Approximately 83% 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	78	%
Financial institutions	22
Total as of March 31, 2018	100	%



	Net Exposure ^{(a) (b)}
Category by Counterparty Credit Quality	(% of Total)
Investment grade	78	%
Non-Investment grade/Non-Rated	22
Total as of March 31, 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 $65 million as of March 31, 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 March 31, 2018, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.1 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 March 31, 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 March 31, 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	$	16	$	—	$	—	—	$	47	$	—	$	—	—
U.S. government and federal agency obligations	56		1		1		11	43		1		—		11
Federal agency mortgage-backed securities	92		—		2		23	82		1		1		23
Commercial mortgage-backed securities	16		—		1		22	14		—		—		20
Corporate debt securities	100		1		2		11	99		2		1		11
Equity securities	395		265		—		—	402		272		—		—
Foreign government fixed income securities	5		—		—		8	5		—		—		9
Total	$	680	$	267	$	6		$	692	$	276	$	2

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



	Three months ended March 31,
	2018		2017
	(In millions)
Realized gains	$	3	$	2
Realized losses	3		2
Proceeds from sale of securities	182		117

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 March 31, 2018, NRG had energy-related derivative instruments extending through 2031. The Company marks these derivatives to market through the statement of operations.

Interest Rate Swaps

NRG is exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of March 31, 2018, NRG had interest rate derivative instruments on recourse debt extending through 2021, which are not designated as cash flow hedges. The Company had interest rate swaps on non-recourse debt extending through 2041, a portion of which are designated as cash flow hedges.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of March 31, 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
		March 31, 2018			December 31, 2017
Category	Units	(In millions)
Emissions	Short Ton	2			1
Coal	Short Ton	17			21
Natural Gas	MMBtu	(208		)	(17		)
Power	MWh	16			14
Capacity	MW/Day	(1		)	(1		)
Interest	Dollars	$	3,938		$	3,876
Equity	Shares	1			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
	March 31, 2018		December 31, 2017		March 31, 2018		December 31, 2017
	(In millions)
Derivatives Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	2	$	1	$	2	$	5
Interest rate contracts long-term	20		11		7		11
Total Derivatives Designated as Cash Flow or Fair Value Hedges	22		12		9		16
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	13		9		7		15
Interest rate contracts long-term	57		32		14		28
Commodity contracts current	1,000		616		781		535
Commodity contracts long-term	277		129		243		158
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	1,347		786		1,045		736
Total Derivatives	$	1,369	$	798	$	1,054	$	752

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



	Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of March 31, 2018	(In millions)
Commodity contracts:
Derivative assets	$	1,277		$	(835	)	$	(201	)	$	241
Derivative liabilities	(1,024		)	835			120			(69		)
Total commodity contracts	253			—			(81		)	172
Interest rate contracts:
Derivative assets	92			(4		)	—			88
Derivative liabilities	(30		)	4			—			(26		)
Total interest rate contracts	62			—			—			62
Total derivative instruments	$	315		$	—		$	(81	)	$	234



	Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of December 31, 2017	(In millions)
Commodity contracts:
Derivative assets	$	745		$	(578	)	$	(11	)	$	156
Derivative liabilities	(693		)	578			73			(42		)
Total commodity contracts	52			—			62			114
Interest rate contracts:
Derivative assets	53			(3		)	—			50
Derivative liabilities	(59		)	3			—			(56		)
Total interest rate contracts	(6		)	—			—			(6		)
Total derivative instruments	$	46		$	—		$	62		$	108

Accumulated Other Comprehensive Loss

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



	Interest Rate Contracts
	Three months ended March 31,
	2018			2017
	(In millions)
Accumulated OCI beginning balance	$	(54	)	$	(66	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	4			3
Mark-to-market of cash flow hedge accounting contracts	19			2
Accumulated OCI ending balance, net of $6, and $14 tax	$	(31	)	$	(61	)
Losses expected to be realized from OCI during the next 12 months, net of $2 tax	$	(9	)

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

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

Impact of Derivative Instruments on the Statements of Operations

Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges 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 March 31,
	2018			2017
Unrealized mark-to-market results	(In millions)
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	2		$	3
Net unrealized gains/(losses) on open positions related to economic hedges	194			(22		)
Total unrealized mark-to-market gains/(losses) for economic hedging activities	196			(19		)
Reversal of previously recognized unrealized gains on settled positions related to trading activity	(3		)	(15		)
Net unrealized gains on open positions related to trading activity	11			1
Total unrealized mark-to-market gains/(losses) for trading activity	8			(14		)
Total unrealized gains/(losses)	$	204		$	(33	)



	Three months ended March 31,
	2018			2017
	(In millions)
Unrealized (losses)/gains included in operating revenues	$	(98	)	$	104
Unrealized gains/(losses) included in cost of operations	302			(137		)
Total impact to statement of operations — energy commodities	$	204		$	(33	)
Total impact to statement of operations — interest rate contracts	$	48		$	5

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

For the three months ended March 31, 2018, the $194 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of ERCOT heat rate contracts due to ERCOT heat rate expansion.

For the three months ended March 31, 2017, the $22 million unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases of natural gas, coal, and ERCOT electricity due to decreases in natural gas, coal, and ERCOT electricity 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 March 31, 2018, was $20 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of March 31, 2018, was $5 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 $5 million as of March 31, 2018.

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

Note 7 — 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)	March 31, 2018			December 31, 2017			March 31, 2018 interest rate % ^(a)

Recourse debt:
Senior notes, due 2022	992			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	870			870			5.750
Term loan facility, due 2023	1,867			1,872			L+1.75
Tax-exempt bonds	465			465			4.125 - 6.00
Subtotal recourse debt	7,177			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)	75			55			L+2.500
El Segundo Energy Center, due 2023	369			400			L+1.75 - L+2.375
Marsh Landing, due 2023	309			318			L+2.125
Alta Wind I - V lease financing arrangements, due 2034 and 2035	926			926			5.696 - 7.015
Walnut Creek, term loans due 2023	259			267			L+1.625
Utah Portfolio, due 2022	278			278			various
Tapestry, due 2021	158			162			L+1.625
CVSR, due 2037	731			746			2.339 - 3.775
CVSR HoldCo, due 2037	188			194			4.680
Alpine, due 2022	135			135			L+1.750
Energy Center Minneapolis, due 2025	83			83			5.95
Energy Center Minneapolis, due 2031	125			125			3.55
Viento, due 2023	163			163			L+3.00
Buckthorn Solar, due 2018 and 2025	183			169			L+1.750
NRG Yield - other	573			579			various
Subtotal NRG Yield debt (non-recourse to NRG) ^(c)	6,038			6,083
Ivanpah, due 2033 and 2038	1,068			1,073			2.285 - 4.256
Carlsbad Energy Project ^(c)	475			427			L+1.625 - 4.120
Agua Caliente, due 2037	815			818			2.395 - 3.633
Agua Caliente Borrower 1, due 2038	86			89			5.430
Cedro Hill, due 2025 ^(c)	149			151			L+1.75
Midwest Generation, due 2019	132			152			4.390
NRG Other Renewables ^(c)	466			478			various
NRG Other	178			180			various
Subtotal other NRG non-recourse debt	3,369			3,368
Subtotal all non-recourse debt	9,407			9,451
Subtotal long-term debt (including current maturities)	16,584			16,633
Capital leases	4			5			various
Subtotal long-term debt and capital leases (including current maturities)	16,588			16,638
Less current maturities^(d)	(956		)	(688		)
Less debt issuance costs	(201		)	(204		)
Discounts	(25		)	(30		)
Total long-term debt and capital leases	$	15,406		$	15,716

(a) As of March 31, 2018, L+ equals 3 month LIBOR plus x%, except for the Buckthorn Solar and Utah Solar Portfolio where L+ equals 1 month LIBOR plus x%.

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

(d) The NRG Yield, Inc. Convertible Senior Notes, due 2019, become due in February 2019 and are recorded in current maturities as of March 31, 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%.

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 of letters of credit. At March 31, 2018, there was $67 million of letters of credit issued under the revolving credit facility and outstanding borrowings of $75 million on the revolver. 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%.

Project Financings

Agua Caliente Project Financing

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

Carlsbad Project Financing

On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038, 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 million, and a working capital loan facility with an aggregate principal amount not to exceed $4 million. As of March 31, 2018, $475 million was outstanding under both the note and the construction loan.

Note 8 — 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 March 31, 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 two 190 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its equity investment, which was $100 million as of March 31, 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 $81 million as of March 31, 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)	March 31, 2018		December 31, 2017
Current assets	$	171	$	118
Net property, plant and equipment	2,712		2,337
Other long-term assets	665		658
Total assets	3,548		3,113
Current liabilities	111		96
Long-term debt	856		661
Other long-term liabilities	211		209
Total liabilities	1,178		966
Redeemable noncontrolling interest	80		78
Noncontrolling interests	646		507
Net assets less noncontrolling interests	$	1,644	$	1,562

Note 9 — Changes in Capital Structure

As of March 31, 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
Balance as of December 31, 2017	418,323,134	(101,580,045	)	316,743,089
Shares issued under LTIPs	1,081,994	—		1,081,994
Shares issued under ESPP	—	175,862		175,862
Shares repurchased	—	(3,114,748	)	(3,114,748	)
Balance as of March 31, 2018	419,405,128	(104,518,931	)	314,886,197

Employee Stock Purchase Plan

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

Share Repurchases

In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock, with the first $500 million program beginning as soon as permitted. In March 2018, share repurchases were made as follows:



	Total number of shares purchased	Average price paid per share ^(a)		Amounts paid for shares purchased (in millions) ^(a)
Board Authorized Share Repurchases
March 2018	3,114,748	$	29.75	$	93

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

NRG Common Stock Dividends

The following table lists the dividends paid during the three months ended March 31, 2018:



	First Quarter 2018
Dividends per Common Share	$	0.03

On April 19, 2018, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable May 15, 2018, to stockholders of record as of May 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 10 — 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 March 31,
(In millions, except per share data)	2018		2017
Basic income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Net income/(loss) attributable to NRG Energy, Inc.	$	279	$	(163	)
Weighted average number of common shares outstanding - basic	318		316
Earnings/(loss) per weighted average common share — basic	$	0.88	$	(0.52	)
Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding - diluted	318		316
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	4		—
Total dilutive shares	322		316
Earnings/(loss) per weighted average common share — diluted	$	0.87	$	(0.52	)

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 March 31,
(In millions of shares)	2018	2017
Equity compensation plans	1	6
Total	1	6

Note 11 — Segment Reporting

The Company's segment structure reflects how management currently makes financial decisions and allocates resources. The Company's businesses are segregated as follows: Generation, which includes generation, international and BETM; Retail, which includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities.

During 2017, NRG Yield acquired several projects totaling 555 MW from NRG. On March 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 have been recast to reflect the acquisition as if they had occurred at the beginning of the financial statement period.

On June 14, 2017, as described in Note 3, Discontinued Operations and Dispositions, NRG deconsolidated GenOn for financial reporting purposes. The financial information for all historical periods have been recast to reflect the 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
Three months ended March 31, 2018			(In millions)
Operating revenues^(a)	$	1,481	$	327		$	86		$	225			$	2		$	300		$	2,421
Depreciation and amortization	28		67			51			81				8			—			235
Reorganization costs	3		4			—			—				13			—			20
Equity in earnings/(losses) of unconsolidated affiliates	—		2			—			4				(1		)	(7		)	(2		)
Income/(loss) from continuing operations before income taxes	946		(536		)	(40		)	(1		)		(126		)	(11		)	232
Income/(loss) from continuing operations	946		(536		)	(34		)	—				(132		)	(11		)	233
Net Income/(Loss)	946		(536		)	(34		)	—				(132		)	(11		)	233
Net Income/(Loss) attributable to NRG Energy, Inc.	$	940	$	(536	)	$	1		$	21		—	$	(148	)	$	1		$	279
Total assets as of March 31, 2018	$	3,521	$	7,313		$	5,191		$	8,362			$	9,108		$	(9,743	)	$	23,752



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	1	$	(307	)	$	8	$	—	$	(2	)	$	—	$	(300	)



	Retail^(a)			Generation^(a)			Renewables^(a)			NRG Yield			Corporate^(a)(b)			Eliminations			Total
Three months ended March 31, 2017				(In millions)
Operating revenues^(a)	$	1,335		$	965		$	95		$	221		$	10		$	(244	)	$	2,382
Depreciation and amortization	28			97			47			77			8			—			257
Equity in (losses)/earnings of unconsolidated affiliates	—			(13		)	—			19			3			(4		)	5
(Loss)/income from continuing operations before income taxes	(31		)	37			(35		)	(3		)	(137		)	(4		)	(173		)
(Loss)/income from continuing operations	(34		)	37			(29		)	(2		)	(137		)	(4		)	(169		)
Loss from discontinued operations, net of tax	—			—			—			—			(34		)	—			(34		)
Net (Loss)/Income	(34		)	37			(29		)	(2		)	(171		)	(4		)	(203		)
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(33	)	$	37		$	(1	)	$	12		$	(171	)	$	(7	)	$	(163	)



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	1	$	209	$	8	$	—	$	26	$	—	$	244
(b) Includes other income - affiliate	$	—	$	—	$	—	$	—	$	48	$	—	$	48

Note 12 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:



	Three months ended March 31,
(In millions except otherwise noted)	2018			2017
Income/(Loss) before income taxes	$	232		$	(173	)
Income tax benefit from continuing operations	(1		)	(4		)
Effective tax rate	(0.4		)%	2.3		%

For the three months ended March 31, 2018, NRG's overall effective tax rate was different than the statutory rate of 21% primarily due to the tax benefit for the change in valuation allowance, the generation of PTCs from various wind facilities and the inclusion of consolidated partnerships partially offset by current state tax expense.

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

Uncertain Tax Benefits

As of March 31, 2018, NRG has recorded a non-current tax liability of $35 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the three months ended March 31, 2018, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of March 31, 2018, NRG had cumulative interest and penalties related to these uncertain tax benefits of $3 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. 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 13 — 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, 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 will continue to provide the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments, until September 30, 2018, which GenOn can terminate earlier if NRG is provided 60 days' notice. 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 months ended March 31, 2018, NRG recorded approximately $21 million against selling, general and administrative expenses post-Chapter 11 Filing. For the three months ended March 31, 2017, NRG recorded other income - affiliate related to these services of $48 million.

In addition, as described in Note 3, Discontinued Operations and Dispositions, under the Restructuring Support Agreement, NRG has agreed to provide GenOn with a $28 million credit against amounts owed to NRG under the transition services agreement. The credit is intended to reimburse GenOn for its payment of financing costs. Any unused amount can be paid in cash at GenOn's request, subject to the terms and conditions of the transition services agreement.

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 March 31, 2018 and December 31, 2017, $86 million and $92 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of March 31, 2018 and December 31, 2017, there were $125 million of loans outstanding under the intercompany secured revolving credit facility, which will be applied against the settlement cash consideration that will be paid to GenOn upon emergence from bankruptcy, as further discussed in Note 3 , Discontinued Operations and Dispositions. In addition, the intercompany secured revolving credit facility contains customary covenants and events of default. As of March 31, 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. Effective with completion of the reorganization, GenOn must repay NRG for all revolving loans outstanding, with such amount to be netted against the settlement payment owed from NRG to GenOn. Accordingly, the affiliate receivable is recorded net within accrued expenses and other current liabilities - affiliate on the consolidated balance sheet as of March 31, 2018, all of which is to be settled at emergence. Interest continues to accrue during the pendency of the Chapter 11 Cases and borrowings remain secured obligations.

Commercial Operations Agreement

NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. As of March 31, 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 March 31, 2018 and December 31, 2017, the Company had $28 million and $32 million, respectively, of cash collateral posted in support of energy risk management activities by GenOn.

NRG will provide settlement cash consideration to GenOn of $261.3 million, which will be paid in cash less any amounts owed to NRG under the intercompany secured revolving credit facility.

Note 14 — Commitments and Contingencies

This footnote should be read in conjunction with the complete description under Note 22, Commitments and Contingencies, to the Company's 2017 Form 10-K.

Commitments

First Lien Structure

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 August 2009, the EPA and the Illinois Attorney General, or the Government Plaintiffs, filed a complaint, or the Governments’ Complaint, in the U.S. District Court for the Northern District of Illinois alleging violations of CAA PSD requirements by Midwest Generation arising from maintenance, repair or replacement projects at six Illinois coal-fired electric generating stations performed by Midwest Generation or ComEd, a prior owner of the stations, including alleged failures to obtain PSD construction permits and to comply with BACT requirements. The Government Plaintiffs also alleged violations of opacity and PM standards at the Midwest Generation plants. Finally, the Government Plaintiffs alleged that Midwest Generation violated certain operating permit requirements under Title V of the CAA allegedly arising from such claimed PSD, opacity and PM emission violations. Several environmental groups intervened as plaintiffs in this litigation and filed a complaint, or the Intervenors’ Complaint, which alleged opacity, PM and related Title V violations. Midwest Generation filed a motion to dismiss nine of the ten PSD counts in the Governments’ Complaint, and to dismiss the tenth PSD count to the extent the Governments’ Complaint sought civil penalties for that count. The trial court granted the motion in March 2010.

In June 2010, the Government Plaintiffs and Intervenors each filed an amended complaint. The Governments’ Amended Complaint again alleged that Midwest Generation violated PSD (based upon the same projects as alleged in their original complaint, but adding allegations that the Company was liable as the “successor” to ComEd), Title V and opacity and PM standards. It named EME and ComEd as additional defendants and alleged PSD violations (again, premised on the same projects) against them. The Intervenors’ Amended Complaint named only Midwest Generation as a defendant and alleged Title V and opacity/PM violations, as well as one of the ten PSD violations alleged in the Governments’ Amended Complaint. Midwest Generation again moved to dismiss all but one of the Government Plaintiffs’ PSD claims and the related Title V claims. Midwest Generation also filed a motion to dismiss the PSD claim in the Intervenors’ Amended Complaint and the related Title V claims. In March 2011, the trial court granted Midwest Generation’s partial motion to dismiss the Government Plaintiffs’ PSD claims. The trial court denied Midwest Generation’s motion to dismiss the PSD claim asserted in the Intervenors’ Amended Complaint, but noted that the plaintiffs would be required to convince the court that the statute of limitations should be equitably tolled. The trial court did not address other counts in the amended complaints that allege violations of opacity and PM emission limitations under the Illinois State Implementation Plan and related Title V claims. The trial court also granted the motions to dismiss the PSD claims asserted against EME and ComEd.

Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims, including the dismissal of nine of the ten PSD claims against Midwest Generation and of the PSD claims against the other defendants. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in July 2013. In addition, in 2012, all but one of the environmental groups that had intervened in the case dismissed their claims without prejudice. As a result, only one environmental group remains a plaintiff intervenor in the case. On March 9, 2018, the Consent Decree which provides that Midwest Generation will be required to (x) pay $500,000 to each of the State of Illinois and the Federal Government and (y) make and maintain certain operational improvements was lodged with the court.

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 the New Jersey action reached an agreement in principle to resolve the class allegations which was confirmed by a term sheet signed by the parties on July 28, 2017. On September 27, 2017, plaintiffs in the New Jersey case filed their motion for preliminary approval of the class settlement which was approved by the court on November 17, 2017. On May 1, 2018, the court granted plaintiffs' motion for final approval of the class action settlement.

California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation. In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR. At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not. As such, the plaintiffs brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions. Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed 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.

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. The case is currently stayed by agreement of the parties. On May 2, 2018, the court approved a joint stipulation which provides: (i) plaintiffs' opposition brief is due on or before July 30, 2018; (ii) defendants' reply brief is due on or before October 5, 2018; and (iii) a hearing on the motions is scheduled on October 30, 2018.

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 fully briefing the appeal, oral argument was heard on April 24, 2018.

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.

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, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under the Restructuring Support Agreement to which the GenOn Entities, NRG and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them supported the Bankruptcy Court's approval of the plan 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 and the noteholders, including claims relating to or arising out of any shared services and any other relationships or transactions between the companies. See Note 3, Discontinued Operations and Dispositions, for additional information related to the Chapter 11 Cases.

GenOn Noteholders' Lawsuit — On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc. 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes due 2020, and the GenOn Americas Generation, LLC 8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims related to the Services Agreement between NRG and GenOn. Plaintiffs generally seek return of all monies paid under the Services Agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017. The Standstill Agreement terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty by certain current and former officers and directors of GenOn in relation to the Services Agreement and the alleged usurpation of corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs, among other things, generally seek return of all monies paid under the services agreement and any other damages that the court deems appropriate. On December 14, 2017, a settlement agreement was executed between GenOn and NRG which should ultimately resolve this lawsuit.

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. But even a year later, BTEC had not satisfied all of the contractually-required acceptance criteria. As a result and given that the MIPA expiration date passed on May 31, 2017, NRG elected to terminate the contract in June 2017. BTEC claims that NRG Texas Power breached the MIPA by improperly terminating it, and seeks a declaratory judgment as to the rights and obligations of the parties. In addition, BTEC seeks damages, interest and attorney’s fees. On August 14, 2017, NRG Texas Power served its answer to the lawsuit. On September 7, 2017, NRG Texas Power filed a counterclaim seeking damages in excess of $48 million. On March 21, 2018, BTEC filed a Second Amended Petition in which they supplemented their previous claims and added a claim for specific performance.

GenOn Related Contingencies

Actions Pursued by MC Asset Recovery — With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings. MC Asset Recovery is governed by a manager who is independent of NRG and GenOn. MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings. In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants. In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit, or the Fifth Circuit. In March 2012, the Fifth Circuit reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. On December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29, 2015, MC Asset Recovery filed a notice to appeal this judgment with the Fifth Circuit. On June 1, 2017, the Fifth Circuit affirmed the District Court's judgment. On June 12, 2017, MC Asset Recovery petitioned the Fifth Circuit for rehearing. The petition for rehearing was denied and a court order and judgment affirming the District Court's judgments was entered on July 17, 2017. The bankruptcy court is scheduled to hear a Motion for a Final Decree in the Mirant bankruptcy on June 13, 2018.

Natural Gas Litigation — GenOn is party to several lawsuits, certain of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of state antitrust law and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of Nevada, which was handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, which reversed the decision of the District Court. GenOn along with the other defendants in the lawsuit filed a petition for a writ of certiorari to the U.S. Supreme Court challenging the Ninth Circuit's decision and the U.S. Supreme Court granted the petition. On April 21, 2015, the U.S. Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution. The U.S. Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. Supreme Court directed that the case be remanded to the U.S. District Court for the District of Nevada for further proceedings. On March 7, 2016, class plaintiffs filed their motions for class certification. On March 30, 2017, the court denied the plaintiffs' motions for class certification. On April 13, 2017, the plaintiffs petitioned the Ninth Circuit for interlocutory review of the court’s order denying class certification. On June 13, 2017, the Ninth Circuit granted plaintiffs' petition for interlocutory review. The appeal is fully briefed.

In May 2016 in one of the Kansas cases, the U.S. District Court for the District of Nevada granted the defendants' motion for summary judgment. Subsequently in December 2016, the plaintiffs filed a notice of appeal with the Ninth Circuit. The appeal was argued on February 16, 2018. On March 27, 2018, the Ninth Circuit reversed the District Court's decision. On April 10, 2018, the defendants filed a petition for rehearing. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.

In September 2012, the State of Nevada Supreme Court, which was handling the remaining case, affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffs in the Nevada case filed a petition for a writ of certiorari to the U.S. Supreme Court. In June 2013, the U.S. Supreme Court denied the petition for a writ of certiorari, thereby ending one of the five lawsuits.

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 seeking a schedule for a series of hearings to resolve the objections and asking the Bankruptcy Court to estimate all of the proofs of claim at zero dollars. The plaintiffs have objected to the request for Bankruptcy Court to estimate the proofs of claim. The Bankruptcy Court ordered briefing as to whether it had authority to resolve these claims.

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.

Note 15 — 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.

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. Subsequently, Senator Manchin of West Virginia has requested that the Administration utilize the Defense Production Act to require coal and nuclear units to continue to operate. The assertion is that these plants are needed to maintain national security. No formal timeline for action on either proposal has been set by the Administration.

Zero-Emission Credits for Nuclear Plants in Illinois — In 2016, Illinois enacted a Zero Emission Credit, or ZEC, program for selected nuclear units in Illinois. In total, the program directs over $2.5 billion over ten years to nuclear plants in Illinois that would otherwise retire. Pursuant to the legislation, the Illinois Power Agency, or IPA, conducts a competitive solicitation to procure ZECs, although both the Governor of Illinois and Exelon have already announced that the ZECs will be awarded to two Exelon-owned nuclear power plants in Illinois. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On February 14, 2017, NRG, along with other companies, filed a complaint in the U.S. District Court for the Northern District of Illinois alleging that the state program is preempted by federal law and in violation of the dormant commerce clause. Another plaintiff group filed a similar complaint on the same day. Subsequently, on March 31, 2017, NRG, along with other companies, filed a motion for preliminary injunction. On April 10, 2017, Exelon, as an intervenor defendant, and State defendants filed motions to dismiss. On July 14, 2017, Defendants' motions to dismiss were granted. On July 17, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Seventh Circuit. Briefing is complete. Oral argument was held on January 3, 2018, with supplemental briefs filed on January 26, 2018. On February 21, 2018, the Seventh Circuit invited the U.S. to file an amicus brief in the proceeding.

Zero-Emission Credits for Nuclear Plants in New York — On August 1, 2016, the NYSPSC issued its Clean Energy Standard, or CES, which provided for ZECs which would provide more than $7.6 billion over 12 years in out-of-market subsidy payments to certain selected nuclear generating units in the state. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On October 19, 2016, NRG, along with other companies, filed a complaint in the U.S. District Court for the Southern District of New York, challenging the validity of the NYSPSC action and the ZEC program. On March 29, 2017, the U.S. District Court heard oral arguments on a motion to dismiss filed by defendants. On July 25, 2017, the defendants' motions to dismiss were granted. On August 24, 2017, NRG, along with other plaintiff companies, filed a notice of appeal to the U.S. Court of Appeals for the Second Circuit. Briefing is complete. Oral argument took place on March 12, 2018.

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.

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.

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.

Note 16 — 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.

The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SO₂ budgets for four states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.

In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacate the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In December 2015, the D.C. Circuit remanded the MATS rule to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the case in abeyance. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.

Water

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

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, or FGD, fly ash, bottom ash, and flue gas mercury control. In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines. On September 18, 2017, the EPA promulgated a final rule that (i) postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking and (ii) withdrew the April 2017 administrative stay. The legal challenges have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company has largely eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the rule is revised.

Byproducts, Wastes, Hazardous Materials and Contamination

In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On September 13, 2017, the EPA granted the petition for reconsideration that the Utility Solid Waste Activities Group filed in May 2017. The Company has evaluated the impact of the new rule on the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of March 31, 2018.

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 14, 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 17 — Condensed Consolidating Financial Information

As of March 31, 2018, the Company had outstanding $4.8 billion of Senior Notes due from 2022 to 2028, as shown in Note 7, 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 March 31, 2018:



Ace Energy, Inc.	New Genco GP, LLC	NRG Northeast Affiliate Services Inc.
Allied Home Warranty GP LLC	Norwalk Power LLC	NRG Norwalk Harbor Operations Inc.
Allied Warranty LLC	NRG Advisory Services LLC	NRG Operating Services, Inc.
Arthur Kill Power LLC	NRG Affiliate Services 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 Portable Power LLC
BidURenergy, Inc.	NRG Bayou Cove LLC	NRG Power Marketing LLC
Cabrillo Power I LLC	NRG Business Services LLC	NRG Reliability Solutions 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 Northeast LLC
Cirro Energy Services, Inc.	NRG Connected Home LLC	NRG Rockford Acquisition LLC
Conemaugh Power LLC	NRG Connecticut Affiliate Services Inc.	NRG Saguaro Operations Inc.
Connecticut Jet Power LLC	NRG Construction LLC	NRG Security LLC
Cottonwood Development LLC	NRG Curtailment Solutions, Inc	NRG Services Corporation
Cottonwood Energy Company LP	NRG Development Company Inc.	NRG SimplySmart Solutions LLC
Cottonwood Generating Partners I LLC	NRG Devon Operations Inc.	NRG South Central Affiliate Services Inc.
Cottonwood Generating Partners II LLC	NRG Dispatch Services LLC	NRG South Central Generating LLC
Cottonwood Generating Partners III LLC	NRG Distributed Energy Resources Holdings LLC	NRG South Central Operations Inc.
Cottonwood Technology Partners LP	NRG Distributed Generation PR LLC	NRG South Texas LP
Devon Power LLC	NRG Dunkirk Operations Inc.	NRG Texas C&I Supply LLC
Dunkirk Power LLC	NRG El Segundo Operations Inc.	NRG Texas Gregory LLC
Eastern Sierra Energy Company LLC	NRG Energy Efficiency-L LLC	NRG Texas Holding Inc.
El Segundo Power, LLC	NRG Energy Labor Services LLC	NRG Texas LLC
El Segundo Power II LLC	NRG ECOKAP Holdings LLC	NRG Texas Power LLC
Energy Alternatives Wholesale, LLC	NRG Energy Services Group LLC	NRG Warranty Services LLC
Energy Choice Solutions LLC	NRG Energy Services International Inc.	NRG West Coast LLC
Energy Plus Holdings LLC	NRG Energy Services LLC	NRG Western Affiliate Services Inc.
Energy Plus Natural Gas LLC	NRG Generation Holdings, Inc.	O'Brien Cogeneration, Inc. II
Energy Protection Insurance Company	NRG Greenco LLC	ONSITE Energy, Inc.
Everything Energy LLC	NRG Home & Business Solutions LLC	Oswego Harbor Power LLC
Forward Home Security, LLC	NRG Home Services LLC	Reliant Energy Northeast LLC
GCP Funding Company, LLC	NRG Home Solutions LLC	Reliant Energy Power Supply, LLC
Green Mountain Energy Company	NRG Home Solutions Product LLC	Reliant Energy Retail Holdings, LLC
Gregory Partners, LLC	NRG Homer City Services LLC	Reliant Energy Retail Services, LLC
Gregory Power Partners LLC	NRG Huntley Operations Inc.	RERH Holdings, LLC
Huntley Power LLC	NRG HQ DG LLC	Saguaro Power LLC
Independence Energy Alliance LLC	NRG Identity Protect LLC	Somerset Operations Inc.
Independence Energy Group LLC	NRG Ilion Limited Partnership	Somerset Power LLC
Independence Energy Natural Gas LLC	NRG Ilion LP LLC	Texas Genco GP, LLC
Indian River Operations Inc.	NRG International LLC	Texas Genco Holdings, Inc.
Indian River Power LLC	NRG Maintenance Services LLC	Texas Genco LP, LLC
Keystone Power LLC	NRG Mextrans Inc.	Texas Genco Services, LP
Louisiana Generating LLC	NRG MidAtlantic Affiliate Services Inc.	US Retailers LLC
Meriden Gas Turbines LLC	NRG Middletown Operations Inc.	Vienna Operations Inc.
Middletown Power LLC	NRG Montville Operations Inc.	Vienna Power LLC
Montville Power LLC	NRG New Roads Holdings LLC	WCP (Generation) Holdings LLC
NEO Corporation	NRG North Central Operations Inc.	West Coast 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 March 31, 2018

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	1,483		$	885		$	—		$	53		$	2,421
Operating Costs and Expenses
Cost of operations	1,082			409			14			53			1,558
Depreciation and amortization	73			154			8			—			235
Selling, general and administrative	98			32			61			—			191
Reorganization costs	2			—			18			—			20
Development costs	—			9			4			—			13
Total operating costs and expenses	1,255			604			105			53			2,017
Gain/(loss) on sale of assets	3			(1		)	—			—			2
Operating Income/(Loss)	231			280			(105		)	—			406
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	210			—			330			(540		)	—
Equity in losses of unconsolidated affiliates	—			(1		)	(1		)	—			(2		)
Other income/(expense), net	21			(11		)	3			(16		)	(3		)
Loss on debt extinguishment, net	—			—			(2		)	—			(2		)
Interest expense	(3		)	(72		)	(92		)				(167		)
Total other income/(expense)	228			(84		)	238			(556		)	(174		)
Income Before Income Taxes	459			196			133			(556		)	232
Income tax expense/(benefit)	113			48			(162		)	—			(1		)
Net Income	346			148			295			(556		)	233
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—			(46		)	16			(16		)	(46		)
Net Income Attributable to NRG Energy, Inc.	$	346		$	194		$	279		$	(540	)	$	279


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the three months ended March 31, 2018

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income	$	346		$	148		$	295		$	(556	)	$	233
Other Comprehensive (Loss)/Income, net of tax
Unrealized gain on derivatives, net	—			16			15			(17		)	14
Foreign currency translation adjustments, net	(2		)	(2		)	(3		)	5			(2		)
Defined benefit plans, net	—			—			(1		)	—			(1		)
Other comprehensive (loss)/income	(2		)	14			11			(12		)	11
Comprehensive Income	344			162			306			(568		)	244
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(46		)	24			(16		)	(38		)
Comprehensive Income Attributable to NRG Energy, Inc.	$	344		$	208		$	282		$	(552	)	$	282


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

March 31, 2018

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	43	$	371		$	350		$	—		$	764
Funds deposited by counterparties	241		—			—			—			241
Restricted cash	8		399			—			—			407
Accounts receivable, net	610		290			3			—			903
Inventory	323		205			—			—			528
Derivative instruments	932		207			12			(136		)	1,015
Cash collateral paid in support of energy risk management activities	211		—			—			—			211
Accounts receivable - affiliate	509		141			491			(1,068		)	73
Current assets - held for sale	—		89			—			—			89
Prepayments and other current assets	154		134			38			—			326
Total current assets	3,031		1,836			894			(1,204		)	4,557
Property, plant and equipment, net	2,500		11,196			240			(25		)	13,911
Other Assets
Investment in subsidiaries	511		1			7,374			(7,886		)	—
Equity investments in affiliates	—		1,010			1			—			1,011
Goodwill	360		179			—			—			539
Intangible assets, net	439		1,290			—			(3		)	1,726
Nuclear decommissioning trust fund	680		—			—			—			680
Derivative instruments	245		118			38			(47		)	354
Deferred income tax	264		(34		)	(94		)	—			136
Non-current assets held-for-sale	—		157			—			—			157
Other non-current assets	73		489			119			—			681
Total other assets	2,572		3,210			7,438			(7,936		)	5,284
Total Assets	$	8,103	$	16,242		$	8,572		$	(9,165	)	$	23,752
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	935		$	21		$	—		$	956
Accounts payable	510		241			36			—			787
Accounts payable — affiliate	1,662		(121		)	(441		)	(1,068		)	32
Derivative instruments	857		69			—			(136		)	790
Cash collateral received in support of energy risk management activities	240		—			—			—			240
Current liabilities held-for-sale	—		80			—			—			80
Accrued expenses and other current liabilities	236		146			280			—			662
Accrued expenses and other current liabilities-affiliate	—		—			161			—			161
Total current liabilities	3,505		1,350			57			(1,204		)	3,708
Other Liabilities
Long-term debt and capital leases	244		8,387			6,775			—			15,406
Nuclear decommissioning reserve	272		—			—			—			272
Nuclear decommissioning trust liability	400		—			—			—			400
Deferred income taxes	112		64			(156		)	—			20
Derivative instruments	224		87			—			(47		)	264
Out-of-market contracts, net	62		139			—			—			201
Non-current liabilities held-for-sale	—		7			—			—			7
Other non-current liabilities	419		324			393			—			1,136
Total non-current liabilities	1,733		9,008			7,012			(47		)	17,706
Total liabilities	5,238		10,358			7,069			(1,251		)	21,414
Redeemable noncontrolling interest in subsidiaries	—		80			—			—			80
Stockholders’ Equity	2,865		5,804			1,503			(7,914		)	2,258
Total Liabilities and Stockholders’ Equity	$	8,103	$	16,242		$	8,572		$	(9,165	)	$	23,752


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

NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED

CONSOLIDATING STATEMENTS OF CASH FLOWS

For the three months ended March 31, 2018

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Cash Flows from Operating Activities
Net income	$	346		$	148		$	295		$	(556	)	$	233
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Distributions from unconsolidated affiliates	—			13			—			(3		)	10
Equity in losses of unconsolidated affiliates	—			1			1			—			2
Depreciation and amortization	73			154			8			—			235
Provision for bad debts	17			(2		)	—			—			15
Amortization of nuclear fuel	13			—			—			—			13
Amortization of financing costs and debt discount/premiums	—			10			4			—			14
Adjustment for debt extinguishment	—			—			2			—			2
Amortization of intangibles and out-of-market contracts	3			19			—			—			22
Amortization of unearned equity compensation	—			—			13			—			13
Changes in deferred income taxes and liability for uncertain tax benefits	114			27			(144		)	—			(3		)
Changes in nuclear decommissioning trust liability	34			—			—			—			34
Changes in derivative instruments	5			(220		)	(14		)	(18		)	(247		)
Changes in collateral deposits in support of energy risk management activities	162			1			—			—			163
Gain on sale of emission allowances	(8		)	—			—			—			(8		)
(Gain)/loss on sale of assets	(3		)	1			—			—			(2		)
Changes in other working capital	(442		)	22			(296		)	577			(139		)
Net Cash Provided/(Used) by Operating Activities	314			174			(131		)	—			357
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			25			(25		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(42		)	—			42			—
Acquisition of business, net of cash acquired	(2		)	(60		)	—			—			(62		)
Capital expenditures	(61		)	(276		)	(21		)	—			(358		)
Decrease in notes receivable	—			3			—			—			3
Purchases of emission allowances	(17		)	—			—			—			(17		)
Proceeds from sale of emission allowances	23			—			—			—			23
Investments in nuclear decommissioning trust fund securities	(216		)	—			—			—			(216		)
Proceeds from the sale of nuclear decommissioning trust fund securities	182			—			—			—			182
Proceeds from sale of assets, net of cash disposed of	10			1			—			—			11
Change in investments in unconsolidated affiliates	—			2			—			—			2
Net Cash (Used)/Provided by Investing Activities	(81		)	(372		)	4			17			(432		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(25		)	—			25			—
Payment from/(for) intercompany loans	18			80			(98		)	—			—
Acquisition of Drop Down Assets, net of cash acquired	—			—			42			(42		)	—
Payment of dividends to common and preferred stockholders	—			—			(10		)	—			(10		)
Payment for treasury stock	—			—			(93		)	—			(93		)
Proceeds from issuance of long-term debt	—			179			—			—			179
Payments for short and long-term debt	—			(222		)	(6		)	—			(228		)
Contributions from, net of distributions to noncontrolling interests in subsidiaries	—			110			—			—			110
Payment of debt issuance costs	—			(6		)	(1		)	—			(7		)
Net Cash Provided/(Used) by Financing Activities	18			116			(166		)	(17		)	(49		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	251			(82		)	(293		)	—			(124		)
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	$	292		$	770		$	350		$	—		$	1,412


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended March 31, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	1,599		$	867		$	—		$	(84	)	$	2,382
Operating Costs and Expenses
Cost of operations	1,260			664			18			(80		)	1,862
Depreciation and amortization	99			150			8			—			257
Selling, general and administrative	96			46			118			—			260
Development costs	—			12			5			—			17
Total operating costs and expenses	1,455			872			149			(80		)	2,396
Other income - affiliate	—			—			48			—			48
Gain on sale of assets	2			—			—			—			2
Operating Income/(Loss)	146			(5		)	(101		)	(4		)	36
Other (Expense)/Income
Equity in (losses)/earnings of consolidated subsidiaries	(42		)	1			68			(27		)	—
Equity in (losses)/earnings of unconsolidated affiliates	(1		)	7			(1		)	—			5
Other (expense)/income, net	(2		)	5			7			3			13
Loss on debt extinguishment, net	—			(2		)	—			—			(2		)
Interest expense	(4		)	(104		)	(117		)	—			(225		)
Total other expense	(49		)	(93		)	(43		)	(24		)	(209		)
Income/(Loss) from Continuing Operations Before Income Taxes	97			(98		)	(144		)	(28		)	(173		)
Income tax expense/(benefit)	19			(46		)	25			(2		)	(4		)
Income/(Loss) from Continuing Operations	78			(52		)	(169		)	(26		)	(169		)
(Loss)/income from discontinued operations, net of income tax	—			(37		)	3			—			(34		)
Net Income/(Loss)	78			(89		)	(166		)	(26		)	(203		)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest	—			(38		)	(3		)	1			(40		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	78		$	(51	)	$	(163	)	$	(27	)	$	(163	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the three months ended March 31, 2017

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	78	$	(89	)	$	(166	)	$	(26	)	$	(203	)
Other Comprehensive Income, net of tax
Unrealized gain on derivatives, net	—		5			4			(5		)	4
Foreign currency translation adjustments, net	5		4			7			(9		)	7
Defined benefit plans, net	—		1			(1		)	—			—
Other comprehensive income	5		10			10			(14		)	11
Comprehensive Income/(Loss)	83		(79		)	(156		)	(40		)	(192		)
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest	—		(37		)	(3		)	1			(39		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	$	83	$	(42	)	$	(153	)	$	(41	)	$	(153	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2017



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations ^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	—	$	348		$	643		$	—		$	991
Funds deposited by counterparties	37		—			—			—			37
Restricted cash	4		504			—			—			508
Accounts receivable, net	768		307			4			—			1,079
Inventory	338		194			—			—			532
Derivative instruments	625		81			9			(89		)	626
Cash collateral paid in support of energy risk management activities	170		1			—			—			171
Accounts receivable - affiliate	709		213			(129		)	(698		)	95
Current assets held-for-sale	8		107			—			—			115
Prepayments and other current assets	116		118			27			—			261
Total current assets	2,775		1,873			554			(787		)	4,415
Property, plant and equipment, net	2,502		11,194			238			(26		)	13,908
Other Assets
Investment in subsidiaries	305		—			7,581			(7,886		)	—
Equity investments in affiliates	—		1,036			2			—			1,038
Goodwill	360		179			—			—			539
Intangible assets, net	454		1,295			—			(3		)	1,746
Nuclear decommissioning trust fund	692		—			—			—			692
Derivative instruments	121		40			31			(20		)	172
Deferred income taxes	377		(7		)	(236		)	—			134
Non-current assets held for sale	—		43			—			—			43
Other non-current assets	50		461			158			(38		)	631
Total other assets	2,359		3,047			7,536			(7,947		)	4,995
Total Assets	$	7,636	$	16,114		$	8,328		$	(8,760	)	$	23,318
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	667		$	59		$	(38	)	$	688
Accounts payable	545		281			55			—			881
Accounts payable — affiliate	751		(201		)	181			(698		)	33
Derivative instruments	535		108			—			(88		)	555
Cash collateral received in support of energy risk management activities	37		—			—			—			37
Current liabilities held-for-sale	—		72			—			—			72
Accrued expenses and other current liabilities	290		175			425			—			890
Accrued expenses and other current liabilities - affiliate	—		—			161			—			161
Total current liabilities	2,158		1,102			881			(824		)	3,317
Other Liabilities
Long-term debt and capital leases	244		8,733			6,739			—			15,716
Nuclear decommissioning reserve	269		—			—			—			269
Nuclear decommissioning trust liability	415		—			—			—			415
Deferred income taxes	112		64			(155		)	—			21
Derivative instruments	110		107			—			(20		)	197
Out-of-market contracts, net	66		141			—			—			207
Non-current liabilities held-for-sale	—		8			—			—			8
Other non-current liabilities	410		321			391			—			1,122
Total non-current liabilities	1,626		9,374			6,975			(20		)	17,955
Total Liabilities	3,784		10,476			7,856			(844		)	21,272
Redeemable noncontrolling interest in subsidiaries	—		78			—			—			78
Stockholders’ Equity	3,852		5,560			472			(7,916		)	1,968
Total Liabilities and Stockholders’ Equity	$	7,636	$	16,114		$	8,328		$	(8,760	)	$	23,318


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the three months ended March 31, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Cash Flows from Operating Activities
Net income/(loss)	$	78		$	(89	)	$	(166	)	$	(26	)	$	(203	)
(Loss)/income from discontinued operations	—			(37		)	3			—			(34		)
Net income/(loss) from continuing operations	78			(52		)	(169		)	(26		)	(169		)
Adjustments to reconcile net income/(loss) to net cash (used)/provided by operating activities:
Distributions from unconsolidated affiliates	—			18			—			(5		)	13
Equity in losses/(earnings) of unconsolidated affiliates	1			(7		)	1			—			(5		)
Depreciation and amortization	99			150			8			—			257
Provision for bad debts	8			1			—			—			9
Amortization of nuclear fuel	12			—			—			—			12
Amortization of financing costs and debt discount/premiums	—			11			4			—			15
Amortization of intangibles and out-of-market contracts	6			24			—			—			30
Amortization of unearned equity compensation	—			—			8			—			8
Changes in deferred income taxes and liability for uncertain tax benefits	19			(46		)	28			—			1
Changes in nuclear decommissioning trust liability	36			—			—			—			36
Changes in derivative instruments	(4		)	43			(1		)	—			38
Changes in collateral deposits in support of energy risk management activities	(136		)	9			—			—			(127		)
Gain on sale of assets	(2		)	—			—			—			(2		)
Changes in other working capital	(118		)	458			(601		)	63			(198		)
Net cash (used)/provided by continuing operations	(1		)	609			(722		)	32			(82		)
Cash provided by discontinued operations	—			15			—			—			15
Net Cash (Used)/Provided by Operating Activities	(1		)	624			(722		)	32			(67		)
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			22			(22		)	—
Intercompany dividends	—			—			129			(129		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(131		)	—			131			—
Acquisition of businesses, net of cash acquired	—			(3		)	—			—			(3		)
Capital expenditures	(64		)	(168		)	(4		)	—			(236		)
Decrease in notes receivable	—			4			—			—			4
Purchases of emission allowances	(9		)	—			—			—			(9		)
Proceeds from sale of emission allowances	11			—			—			—			11
Investments in nuclear decommissioning trust fund securities	(153		)	—			—			—			(153		)
Proceeds from the sale of nuclear decommissioning trust fund securities	117			—			—			—			117
Proceeds from sale of assets, net of cash disposed of	11			3			—			—			14
Change in investments in unconsolidated affiliates	—			(12		)	—			—			(12		)
Other	18			—			—			—			18
Net cash (used)/provided by continuing operations	(69		)	(307		)	147			(20		)	(249		)
Cash used by discontinued operations	—			(32		)	—			—			(32		)
Net Cash (Used)/Provided by Investing Activities	(69		)	(339		)	147			(20		)	(281		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(22		)	—			22			—
Payments (for)/from intercompany loans	65			(428		)	395			(32		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			—			131			(131		)	—
Intercompany dividends	—			(129		)	—			129			—
Payment of dividends to common and preferred stockholders	—			—			(9		)	—			(9		)
Net receipts from settlement of acquired derivatives that include financing elements	—			1			—			—			1
Proceeds from issuance of long-term debt	—			167			26			—			193
Payments for short and long-term debt	—			(146		)	(31		)	—			(177		)
Distributions to, net of contributions from, noncontrolling interests in subsidiaries	—			(5		)	—			—			(5		)
Payment of debt issuance costs	—			(10		)	(4		)	—			(14		)
Other - contingent consideration	—			(10		)	—			—			(10		)
Net cash provided/(used) by continuing operations	65			(582		)	508			(12		)	(21		)
Cash used by discontinued operations	—			(132		)	—			—			(132		)
Net Cash Provided/(Used) by Financing Activities	65			(714		)	508			(12		)	(153		)
Effect of exchange rate changes on cash and cash equivalents	—			(7		)	—			—			(7		)
Change in cash from discontinued operations	—			(149		)	—			—			(149		)
Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(5		)	(287		)	(67		)	—			(359		)
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	$	8		$	763		$	256		$	—		$	1,027


(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 months ended March 31, 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


•	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 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 March 31, 2018, by operating segment:



	Global Generation Portfolio^(a)
	(In MW)
	Generation
Generation Type	Gulf Coast^(f)(i)	East/West^(b)	Renewables^(c)(g)(j)		NRG Yield^(d)(j)		Other^(e)(j)	Total Global
Natural gas^(f)	7,464	4,878	—		1,878		—	14,220
Coal	5,114	3,871	—		—		—	8,985
Oil	—	3,641	—		190		—	3,831
Nuclear	1,136	—	—		—		—	1,136
Wind^(g)	—	—	739		2,200		—	2,939
Utility Scale Solar	—	—	738		921		—	1,659
Distributed Solar	—	—	182		52		114	348
Total generation capacity^(h)	13,714	12,390	1,659		5,241		114	33,118
Capacity attributable to noncontrolling interest^(h)	—	—	(776	)	(2,353	)	—	(3,129	)
Total net generation capacity	13,714	12,390	883		2,888		114	29,989

(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.

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

(e) The Distributed Solar figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco.

(f) Natural gas generation does not include 371 MW 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 MWs 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)	Includes net MW for NRG Yield, Inc. of 2,888 MW and the Renewables operating and development platform of 467 MW, which the Company expects to sell as announced on February 6, 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 first quarter 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 billion of asset sale cash proceeds, including divestitures of 6 GWs of conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG Yield, Inc. and its renewables platform.


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

•

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

•

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


•	On February 23, 2018, NRG entered into an agreement to sell BETM for $70 million. The transaction is subject to customary closing conditions and is expected to close in the second half of 2018.


•	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.

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


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

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 $242 million of non-recurring working capital improvements and $83 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 15, Regulatory Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q as found in Item 1.

As owners of power plants and participants in wholesale and retail energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC, and the PUCT, as well as other public utility commissions in certain states where NRG's generating, thermal, or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where 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

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 proposed that FERC take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. 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.

State Energy Regulation

State Out-Of-Market Subsidy Proposals — On April 12, 2018, the New Jersey State Legislature passed a bill to provide out-of-market subsidies to the state’s nuclear plants. The bill has not yet been signed by the New Jersey Governor. In addition, Certain other states in the areas of the country in which NRG operates, including Ohio and Pennsylvania, have considered but have not enacted proposals to provide out-of-market subsidy payments to potentially uneconomic nuclear and fossil generating units. NRG has opposed efforts to provide out-of-market subsidies, and intends to continue opposing them in the future.

Regional Regulatory Developments

NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 15, 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, that 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

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. The outcome of this proceeding will potentially affect future capacity market prices.

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. Multiple parties filed for rehearing. On March 16, 2018, FERC issued a notice for technical conference that took place on April 24, 2018.

New England

Massachusetts Attorney General Report on the Retail Electric Market — On March 29, 2018, Massachusetts Attorney General Maura Healey released a study of the retail electric market titled “Are Consumers Benefitting from Competition: An Analysis of the Individual Residential Electricity Supply Market in Massachusetts.” The report compared retail electric supply prices with Basic Service rates charged by local distribution companies over a two year period from July 2015 to July 2017 and concluded that customers taking supply from the retail market paid more than if they remained on Basic Service. The Massachusetts Legislature is currently considering the Attorney General's report.

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. ISO-NE has also stated that it intends to start a new stakeholder process to consider the pricing impacts of the units retained for fuel security at a later date. Retention of resources through out-of-market mechanisms will suppress future prices in the Forward Capacity Market.

Competitive Auctions with Sponsored Resources Proposal (CASPR) — On January 8, 2018, ISO-NE filed the CASPR proposal which attempts to accommodate state sponsored resources while maintaining competitive market pricing. On January 29, 2018, NRG protested certain aspects of the proposal and also supported ISO-NE’s beginning attempts to address state sponsored resources entering the capacity market. On March 9, 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 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. Briefing is complete. The D.C. Circuit heard oral argument on April 13, 2018.

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.

Peak Energy Rent Adjustment Complaint — On September 30, 2016, the New England Power Generators Association, or NEPGA, filed a complaint against ISO-NE asking FERC to find the Peak Energy Rent, or PER, unjust and unreasonable. The PER adjustment reduces capacity payments on days where energy prices exceed a pre-defined level, known as the "PER strike price." On January 9, 2017, FERC granted NEPGA’s complaint requiring a change to the methodology used to calculate the PER strike price. FERC also directed the parties to determine any refunds for PER paid between September 30, 2016 and May 31, 2018. On July 26, 2017, NEPGA filed settlement documents at FERC, which NRG supported. On February 20, 2018, FERC accepted the settlement and directed ISO-NE to submit a compliance filing setting out the PER calculation. On March 22, 2018, ISO-NE submitted its compliance filing.

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. 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 16, 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

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. 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.

Retail Acquisition


•	On March 27, 2018, the Company entered into an agreement to acquire XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for approximately $204 million in cash, plus estimated transaction costs of $6 million. The acquisition is expected to close in the second half of 2018.

Canal 3 Sale

•

On March 22, 2018, NRG agreed to sell Canal 3 to Stonepeak Kestrel Holdings II LLC in conjunction with GenOn's sale of Canal Units 1 and 2 to Stonepeak Kestrel Holdings LLC. The final purchase price for the Canal 3 sale will be determined based on a formula including capital reimbursement, return on capital and a development fee. Upon closing the sale of Canal 3, NRG also expects to reimburse GenOn for $13.5 million of the $15 million one-time payment GenOn made in December 2017 to NRG as compensation for being granted a purchase option and a rejection option with respect to the Canal 3 project. The Canal 3 sale is expected to enhance 2018 capital allocation by approximately $130 million early in the third quarter of 2018.

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.

Share Repurchases


•	In February 2018, the Company's board of directors authorized the Company to repurchase $1 billion of its common stock, with the first $500 million program beginning as soon as permitted. In March 2018, the Company repurchased 3,114,748 shares of NRG common stock for approximately $93 million at an average cost of $29.75 per share.

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 an exaggerated and 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 March 31,
(In millions except otherwise noted)	2018			2017			Change
Operating Revenues
Retail revenue	$	1,486		$	1,341		$	145
Energy revenue^(a)	619			587			32
Capacity revenue ^(a)	288			262			26
Mark-to-market for economic hedging activities	(106		)	118			(224		)
Contract amortization	(14		)	(15		)	1
Other revenues ^(b)	148			89			59
Total operating revenues	2,421			2,382			39
Operating Costs and Expenses
Cost of sales ^(c)	1,391			1,259			(132		)
Mark-to-market for economic hedging activities	(302		)	137			439
Contract and emissions credit amortization ^(c)	6			7			1
Operations and maintenance	370			371			1
Other cost of operations	93			88			(5		)
Total cost of operations	1,558			1,862			304
Depreciation and amortization	235			257			22
Selling, general and administrative	191			260			69
Reorganization costs	20			—			(20		)
Development costs	13			17			4
Total operating costs and expenses	2,017			2,396			379
Other income - affiliate	—			48			(48		)
Gain on sale of assets	2			2			—
Operating Income	406			36			370
Other Income/(Expense)
Equity in (losses)/earnings of unconsolidated affiliates	(2		)	5			(7		)
Other income, net	(3		)	13			(16		)
Loss on debt extinguishment, net	(2		)	(2		)	—
Interest expense	(167		)	(225		)	58
Total other expense	(174		)	(209		)	35
Income/(Loss) from Continuing Operations before Income Taxes	232			(173		)	405
Income tax benefit	(1		)	(4		)	3
Income/(Loss) from Continuing Operations	233			(169		)	402
Loss from discontinued operations, net of income tax	—			(34		)	34
Net Income/(Loss)	233			(203		)	436
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest	(46		)	(40		)	(6		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	279		$	(163	)	$	442
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	3.00		$	3.32		(10		)%

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

(b) Includes unrealized trading gains and losses.

Management’s discussion of the results of operations for the three months ended March 31, 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 March 31, 2018 and 2017. The average on-peak power prices have generally increased primarily due to the increase in natural gas prices for the three months ended March 31, 2018 as compared to the same period in 2017.



	Average on Peak Power Price ($/MWh)
	Three months ended March 31,
Region	2018		2017		Change %
Gulf Coast ^(a)
ERCOT - Houston ^(b)	$	33.15	$	27.70	20	%
ERCOT - North^(b)	31.67		22.76		39	%
MISO - Louisiana Hub^(c)	46.24		44.66		4	%
East/West
NY J/NYC^(c)	61.97		35.61		74	%
NEPOOL^(c)	65.86		33.81		95	%
COMED (PJM)^(c)	33.21		30.39		9	%
PJM West Hub^(c)	47.43		32.02		48	%
CAISO - NP15^(c)	32.73		26.47		24	%
CAISO - SP15^(c)	35.44		23.01		54	%

(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 March 31, 2018 and 2017, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Three months ended March 31,
Region	2018		2017		Change %
Gulf Coast	$	36.42	$	35.83	2	%
East/West	85.12		74.58		14	%

Though the average on peak power prices have increased on average by 40%, average realized prices by region for the Company have generally fluctuated at a slower rate year-over-year due to the Company's multi-year hedging program.

Gross Margin

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

Economic Gross Margin

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

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

The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended March 31, 2018 and 2017:



	Three months ended March 31, 2018
				Generation
(In millions)	Retail			Gulf Coast			East/West^(a)			Subtotal			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	—		$	371		$	218		$	589		$	77		$	114		$	(161	)	$	619
Capacity revenue	—			67			140			207			—			82			(1		)	288
Retail revenue	1,487			—			—			—			—			—			(1		)	1,486
Mark-to-market for economic hedging activities	(6		)	(564		)	(10		)	(574		)	(10		)	—			484			(106		)
Contract amortization	—			3			—			3			—			(17		)	—			(14		)
Other revenue ^(b)	—			86			16			102			19			46			(19		)	148
Operating revenue	1,481			(37		)	364			327			86			225			302			2,421
Cost of fuel	(8		)	(193		)	(83		)	(276		)	(1		)	(15		)	(63		)	(363		)
Other cost of sales^(c)	(1,100		)	(79		)	(73		)	(152		)	(1		)	(5		)	230			(1,028		)
Mark-to-market for economic hedging activities	792			(3		)	(3		)	(6		)	—			—			(484		)	302
Contract and emission credit amortization	—			(6		)	—			(6		)	—			—			—			(6		)
Gross margin	$	1,165		$	(318	)	$	205		$	(113	)	$	84		$	205		$	(15	)	$	1,326
Less: Mark-to-market for economic hedging activities, net	786			(567		)	(13		)	(580		)	(10		)	—			—			196
Less: Contract and emission credit amortization, net	—			(3		)	—			(3		)	—			(17		)	—			(20		)
Economic gross margin	$	379		$	252		$	218		$	470		$	94		$	222		$	(15	)	$	1,150
Business Metrics
MWh sold (thousands)^(d)(e)				11,238			4,494						1,015			1,616
MWh generated (thousands)^(f)				10,186			2,561						1,015			1,616
(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 617 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 19 thousand or MWt of 617 thousand for thermal generated by NRG Yield.



	Three months ended March 31, 2017
				Generation
(In millions)	Retail			Gulf Coast			East/West^(a)			Subtotal			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	—		$	383		$	225		$	608		$	70		$	116		$	(207	)	$	587
Capacity revenue	—			66			121			187			—			79			(4		)	262
Retail revenue	1,334			—			—			—			—			—			7			1,341
Mark-to-market for economic hedging activities	2			131			(9		)	122			6			—			(12		)	118
Contract amortization	(1		)	3			—			3			—			(17		)	—			(15		)
Other revenue ^(b)	—			46			(1		)	45			19			43			(18		)	89
Operating revenue	1,335			629			336			965			95			221			(234		)	2,382
Cost of fuel	(5		)	(214		)	(87		)	(301		)	(1		)	(12		)	26			(293		)
Other cost of sales^(c)	(992		)	(78		)	(74		)	(152		)	(3		)	(4		)	185			(966		)
Mark-to-market for economic hedging activities	(139		)	(10		)	—			(10		)	—			—			12			(137		)
Contract and emission credit amortization	—			(6		)	(1		)	(7		)	—			—			—			(7		)
Gross margin	$	199		$	321		$	174		$	495		$	91		$	205		$	(11	)	$	979
Less: Mark-to-market for economic hedging activities, net	(137		)	121			(9		)	112			6			—			—			(19		)
Less: Contract and emission credit amortization, net	(1		)	(3		)	(1		)	(4		)	—			(17		)	—			(22		)
Economic gross margin	$	337		$	203		$	184		$	387		$	85		$	222		$	(11	)	$	1,020
Business Metrics
MWh sold (thousands)^(d)(e)				11,383			5,178						915			1,677
MWh generated (thousands)^(f)				10,689			3,017						915			1,677
(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits
(d) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 9 thousand or MWt of 569 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 32 thousand or MWt of 569 thousand for thermal generated by NRG Yield.

The table below represents the weather metrics for the three months ended March 31, 2018 and 2017:



	Three months ended March 31,
Weather Metrics	Gulf Coast	East/West
2018
CDDs ^(a)	133	18
HDDs ^(a)	1,034	1,728
2017
CDDs	204	20
HDDs	1,086	1,799
10 year average
CDDs	93	17
HDDs	1,036	1,776

(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 March 31,
(In millions except otherwise noted)	2018			2017
Retail revenue	$	1,446		$	1,295
Supply management revenue	33			33
Capacity revenue	8			6
Customer mark-to-market	(6		)	2
Contract amortization	—			(1		)
Operating revenue^(a)	1,481			1,335
Cost of sales ^(b)	(1,108		)	(997		)
Mark-to-market for economic hedging activities	792			(139		)
Gross Margin	$	1,165		$	199
Less: Mark-to-market for economic hedging activities, net	786			(137		)
Less: Contract amortization, net	—			(1		)
Economic Gross Margin	$	379		$	337

Business Metrics
Mass electricity sales volume — GWh - Gulf Coast	7,943			6,984
Mass electricity sales volume — GWh - All other regions	1,718			1,641
C&I electricity sales volume — GWh - All regions	5,027			4,833
Natural gas sales volumes (MDth)	2,175			1,262
Average Retail Mass customer count (in thousands)	2,878			2,826
Ending Retail Mass customer count (in thousands)	2,878			2,832


(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 $164 million and $209 million in 2018 and 2017, respectively.

Retail gross margin increased $966 million and economic gross margin increased $42 million for the three months ended March 31, 2018, compared to the same period in 2017, due to:



	(In millions)
Higher gross margin due to higher revenue of $37 million, driven by customer product, term, and mix, offset by higher supply costs of $14 million driven primarily by an increase in power prices	$	23
Higher gross margin of $19 million due to an increase in load of 706,000 MWh driven by colder weather conditions in 2018 compared to 2017	19
Increase in economic gross margin	$	42
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	923
Increase in contract amortization	1
Increase in gross margin	$	966

Generation gross margin and economic gross margin

Generation gross margin decreased $608 million and economic gross margin increased $83 million, both of which include intercompany sales, during the three months ended March 31, 2018, compared to the same period in 2017:

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

Gulf Coast Region



	(In millions)
Higher gross margin from sales of NOx emission credits	$	35
Higher gross margin due to a 17% increase in average realized prices in South Central and a 3% increase in average realized prices in Texas	20
Higher capacity margins due to an 18% increase in demand in the South Central business	15
Higher gross margin from commercial optimization activities	10
Lower energy margin due to a 33% increase in supply cost on load contracts	(27		)
Other	(4		)
Increase in economic gross margin	$	49
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(688		)
Decrease in gross margin	$	(639	)

East/West



	(In millions)
Higher gross margin due to a 108% increase in New England cleared capacity pricing	$	20
Higher gross margin due to a 20% increase in PJM cleared capacity pricing	14
Higher gross margin from commercial optimization activities	16
Lower gross margin due to a 31% decrease in capacity pricing in New York of $12 million coupled with decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration and unit retirements in California	(18		)
Lower gross margin due to lower load contracted prices coupled with lower contracted volumes	(12		)
Higher gross margin by BETM due to higher gains in congestion strategies	14
Increase in economic gross margin	$	34
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(4		)
Increase in contract and emission credit amortization	1
Increase in gross margin	$	31

Renewables gross margin and economic gross margin

Renewables gross margin decreased $7 million and economic gross margin increased $9 million for the three months ended March 31, 2018, compared to the same period in 2017. The increase in economic gross margin was primarily driven by additional distributed solar facilities reaching commercial operations in 2017 and early 2018. The decrease in gross margin was primarily driven by unrealized losses on wind hedges.

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 $215 million during the three months ended March 31, 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 March 31, 2018
				Generation
	Retail			Gulf Coast			East/West			Renewables			Eliminations^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	(34	)	$	—		$	—		$	3		$	(32	)
Net unrealized (losses)/gains on open positions related to economic hedges	(5		)	(530		)	(10		)	(10		)	481			(74		)
Total mark-to-market (losses)/gains in operating revenues	$	(6	)	$	(564	)	$	(10	)	$	(10	)	$	484		$	(106	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	42		$	(1	)	$	(4	)	$	—		$	(3	)	$	34
Net unrealized gains/(losses) on open positions related to economic hedges	750			(2		)	1			—			(481		)	268
Total mark-to-market gains/(losses) in operating costs and expenses	$	792		$	(3	)	$	(3	)	$	—		$	(484	)	$	302


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



	Three months ended March 31, 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	)	$	(26	)	$	—	$	39		$	12
Net unrealized gains/(losses) on open positions related to economic hedges	2			132			17			6		(51		)	106
Total mark-to-market gains/(losses) in operating revenues	$	2		$	131		$	(9	)	$	6	$	(12	)	$	118
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	31		$	(3	)	$	2		$	—	$	(39	)	$	(9	)
Net unrealized (losses)/gains on open positions related to economic hedges	(170		)	(7		)	(2		)	—		51			(128		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(139	)	$	(10	)	$	—		$	—	$	12		$	(137	)


(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 March 31, 2018, the $106 million loss in operating revenues from economic hedge positions was driven primarily by a decrease in the 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 gains on contracts that settled during the period. The $302 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in value of open positions as a result of ERCOT heat rate expansion and increases in ERCOT electricity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period.

For the three months ended March 31, 2017, the $118 million gain in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of decreases in natural gas and ERCOT electricity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period. The $137 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in value of open positions as a result of decreases in natural gas, coal, and ERCOT electricity prices, in addition to 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 three months ended March 31, 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.



	Three months ended March 31,
(In millions)	2018		2017
Trading gains/(losses)
Realized	$	15	$	14
Unrealized	8		(14		)
Total trading gains	$	23	$	—

Operations and Maintenance Expense



	Retail		Generation				Renewables		NRG Yield		Corporate		Eliminations			Total
	Retail		Gulf Coast		East/West^(a)		Renewables		NRG Yield		Corporate		Eliminations			Total
			(In millions)
Three months ended March 31, 2018	$	47	$	151	$	105	$	28	$	52	$	1	$	(14	)	$	370
Three months ended March 31, 2017	$	59	$	143	$	96	$	28	$	52	$	4	$	(11	)	$	371

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

Operations and maintenance expense decreased by $1 million for the three months ended March 31, 2018, compared to the same period in 2017, due to the following:



	(In millions)
Decrease in Retail operation and maintenance expenses due to reduced headcount	$	(12	)
Increase in operation and maintenance expenses due to planned outages primarily at Midwest Generation	9
Increase in operation and maintenance expenses primarily due to timing of outages at W.A Parish, offset by a decrease in personnel costs due to the sale of the engine services business	8
Other	(6		)
	$	(1	)

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 March 31 2018	$	115	$	50	$	10	$	6	$	10	$	191
Three months ended March 31, 2017	119		61		14		4		62		260

Selling, general and administrative expenses decreased by $69 million for the three months ended March 31, 2018 compared to the same period in 2017. The decrease in year over year expenses is due primarily to a $18 million reduction in general and administrative expenses and an $11 million reduction in selling and marketing activities as the Company continues to focus on cost management. In addition, there was a reduction to general and administrative expenses of $25 million related to prior year consulting costs incurred of which $14 million related to advisors engaged to assist the Company in its strategic review and $11 million in connection with advisors and other consultants engaged to assist the Company with GenOn's ability to continue as a going concern.

Reorganization Costs

Reorganization costs of $20 million, primarily related to employee costs, were incurred as part of the Transformation Plan.

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.

Interest Expense

NRG's interest expense decreased by $58 million for the three months ended March 31, 2018, compared to the same period in 2017 due to the following:



	(In millions)
Decrease in derivative interest expense from changes in fair value of interest rate swaps	$	(45	)
Decrease due to repurchases of Senior Notes	(20		)
Other, primarily related to the issuance of project-level debt	7
	$	(58	)

Income Tax Expense

For the three months ended March 31, 2018, NRG recorded an income tax benefit of $1 million on pre-tax income of $232 million. For the same period in 2017, NRG recorded an income tax benefit of $4 million on a pre-tax loss of $173 million. The effective tax rate was (0.4)% and 2.3% for the three months ended March 31, 2018 and 2017, respectively.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

For the three months ended March 31, 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.

Liquidity and Capital Resources

Liquidity Position

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



(In millions)	March 31, 2018		December 31, 2017
Cash and cash equivalents:
NRG excluding NRG Yield	$	591	$	843
NRG Yield and subsidiaries	173		148
Restricted cash - operating	77		71
Restricted cash - reserves^(a)	330		437
Total	1,171		1,499
Total credit facility availability	1,614		1,711
Total liquidity, excluding collateral received	$	2,785	$	3,210

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

For the three months ended March 31, 2018, total liquidity, excluding collateral funds deposited by counterparties, decreased by $425 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at March 31, 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 7, 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.

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 to purchase NRG's ownership in NRG Yield, Inc. and NRG's renewables platform for cash of $1.375 billion, subject to certain adjustments. The purchase and sale agreement includes the sale of all of NRG's ownership in NRG Yield, Inc., NRG's renewable energy development and operations platforms and NRG's renewable energy non-ROFO backlog and pipeline.

In connection with 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 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 expected to close in the second half of 2018 and is subject to various customary closing conditions, approvals and consents. Upon the closing of the transaction, NRG’s 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 various customary 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 February 23, 2018, the Company entered into an agreement to sell BETM to a third party for $70 million. The transaction is expected to close in the second half of 2018 and is subject to various customary closing conditions, approvals and consents.

Sale of Assets to NRG Yield, Inc.

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

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%.

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 March 31, 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 March 31, 2018:



Equivalent Net Sales Secured by First Lien Structure ^(a)	2018		2019		2020		2021		2022
In MW	454		—		—		—		—
As a percentage of total net coal and nuclear capacity ^(b)	10	%	—	%	—	%	—	%	—	%


(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 March 31, 2018, commercial operations had total cash collateral outstanding of $211 million and $607 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of March 31, 2018, total collateral held from counterparties was $241 million in cash and $47 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 three months ended March 31, 2018, and the estimated capital expenditure and growth investments forecast for the remainder of 2018.



	Maintenance		Environmental		Growth Investments ^(b)			Total
	(In millions)
Retail	$	4	$	—	$	16		$	20
Generation
Gulf Coast	38		—		—			38
East/West ^(a)	9		—		109			118
Renewables	1		—		142			143
NRG Yield	8		—		10			18
Corporate	4		—		17			21
Total cash capital expenditures for the three months ended March 31, 2018	64		—		294			358
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(169		)	(169		)
Other investments ^(c)	—		—		62			62
Total capital expenditures and investments, net of financings	64		—		187			251

Estimated capital expenditures for the remainder of 2018	157		3		206			366
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(222		)	(222		)
Other investments ^(c)	—		—		234			234
NRG estimated capital expenditures for the remainder of 2018, net of financings ^(d)	$	157	$	3	$	218		$	378

(a) Includes International and BETM

(b) Total cash capital expenditures includes $17 million of cost-to-achieve spend associated with the Transformation Plan

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


•	Growth Investments capital expenditures — For the three months ended March 31, 2018, the Company's growth investment capital expenditures included $152 million for renewable projects, $114 million for repowering projects and $28 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 $79 million, which includes $14 million for Midwest Generation.

Common Stock Dividends

The following table lists the dividends paid during the three months ended March 31, 2018:



	First Quarter 2018
Dividends per Common Share	$	0.030

On April 19, 2018, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable May 15, 2018, to stockholders of record as of May 1, 2018 representing $0.12 on an annualized basis.

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

Share Repurchases

Xoom Energy Acquisition

On March 27, 2018, the Company entered into an agreement to acquire XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for approximately $204 million in cash, plus estimated transaction costs of $6 million. The acquisition is expected to close in the second half of 2018.

Fuel 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.

Canal 3 — The Company is currently overseeing construction of the Canal 3 project, a dual-fueled peaking facility, which when completed will consist of approximately 333 MWs of net generating capacity. In January 2018, Final Notice To Proceed was issued, and construction commenced with an anticipated COD by summer 2019. On March 22, 2018, NRG agreed to sell Canal 3 to Stonepeak Kestrel Holdings II LLC. The sale is expected to close early in the third quarter of 2018.

Cash Flow Discussion

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



	Three months ended March 31,
	2018			2017			Change
	(In millions)
Net cash provided/(used) by operating activities	$	357		$	(67	)	$	424
Net cash used by investing activities	(432		)	(281		)	(151		)
Net cash used by financing activities	(49		)	(153		)	104

Net Cash Provided By Operating Activities

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



	(In millions)
Changes in cash collateral in support of risk management activities due to changes in commodity prices	$	290
Increase in operating income adjusted for non-cash items	87
Other changes in working capital	85
Decrease in accounts receivable due to timing of cash receipts	27
Decrease in inventory as a result of initiatives related to the Transformation Plan	13
Change in cash from discontinued operations	(15		)
Decrease in accounts payable due to lower expenses in 2018	(63		)
	$	424

Net Cash Used By Investing Activities

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



	(In millions)
Increase in capital expenditures for growth investments of $119 million primarily for solar and repowering projects	$	(122	)
Increase in cash paid for acquisitions in 2018 compared to 2017	(59		)
Decrease in insurance proceeds	(18		)
Other	(2		)
Increase in sales of emissions, net of purchases	4
Decrease in investments in unconsolidated affiliates	14
Change in cash from discontinued operations related to capital expenditures in 2017	32
	$	(151	)

Net Cash Provided By Financing Activities

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



	(In millions)
Change in cash from discontinued operations related to long term deposits in 2017	$	132
Increase in cash contributions, net of distributions from non-controlling interest in 2018, primarily related to tax equity financing	115
Other	15
Increase in debt payments of $51 million as well as a $14 million reduction in borrowings in 2018	(65		)
Repurchase of common stock in 2018	(93		)
	$	104

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

For the three months ended March 31, 2018, the Company had a total domestic pre-tax book income of $233 million and a foreign pre-tax book loss of $1 million. As of December 31, 2017, the Company had cumulative domestic Federal NOL carryforwards of $2.8 billion, which will begin expiring in 2026 and cumulative state NOL carryforwards of $2.2 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $224 million, which do not have an expiration date. Contingent upon GenOn's emergence from bankruptcy, the Company will recognize an estimated $9.5 billion worthless stock deduction for tax purposes.

In addition to these amounts, the Company has $35 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 $35 million until final resolution with the related taxing authority. The $35 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 March 31, 2018, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Several of these investments are variable interest entities for which NRG is not the primary beneficiary. See also Note 8, 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 $594 million as of March 31, 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 7, Debt and Capital Leases, and Note 14, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the three months ended March 31, 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 March 31, 2018, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2018.



Derivative Activity Gains	(In millions)
Fair Value of Contracts as of December 31, 2017	$	46
Contracts realized or otherwise settled during the period	3
Changes in fair value	266
Fair Value of Contracts as of March 31, 2018	$	315



	Fair Value of Contracts as of March 31, 2018
	Maturity
Fair value hierarchy (Losses)/Gains	1 Year or Less			Greater than 1 Year to 3 Years			Greater than 3 Years to 5 Years			Greater than 5 Years			Total Fair Value
	(In millions)
Level 1	$	(13	)	$	(39	)	$	(3	)	$	(1	)	$	(56	)
Level 2	223			139			19			12			393
Level 3	15			(13		)	(7		)	(17		)	(22		)
Total	$	225		$	87		$	9		$	(6	)	$	315

The Company has elected to present derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3 - Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of March 31, 2018, NRG's net derivative asset was $315 million, an increase to total fair value of $269 million as compared to December 31, 2017. This increase was driven by gains in fair value and the roll-off of trades that settled during the period.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $6 million in the net value of derivatives as of March 31, 2018. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in a decrease of approximately $11 million in the net value of derivatives as of March 31, 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-live 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 months ending March 31, 2018 and 2017:



(In millions)	2018		2017
VaR as of March 31,	$	58	$	60
Three months ended March 31,
Average	$	58	$	52
Maximum	69		60
Minimum	48		41

In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of March 31, 2018, for the entire term of these instruments entered into for both asset management and trading was $19 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 March 31, 2018, the Company would have owed the counterparties $64 million. Based on the credit ratings of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of March 31, 2018, a 1% change in variable interest rates would result in a $14.5 million change in interest expense on a rolling twelve month basis.

As of March 31, 2018, the fair value and related carrying value of the Company's debt was $16.7 billion and $16.6 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 $930 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 $54 million as of March 31, 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 $37 million as of March 31, 2018. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 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

Effective January 1, 2018, NRG adopted ASC 606, Revenue from Contracts with Customers. Changes were made to relevant business processes and related control activities in order to monitor and maintain controls over financial reporting. There were no other changes in NRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) during the quarter ended March 31, 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 March 31, 2018, see Note 14, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

Information regarding risk factors appears in Part I, Item 1A, 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, with the first $500 million program beginning as soon as permitted. The authorization did not specify an expiration date.

The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act), of NRG's common stock during the quarter ended March 31, 2018.



For the three months ended March 31, 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
(January 1, 2018 to January 31, 2018)	—	$	—	—	$	—
Month #2
(February 1, 2018 to February 28, 2018)	—	$	—	—	$	—
Month #3
(March 1, 2018 to March 31, 2018)	3,114,748	$	29.75	3,114,748	$	907,314,521
Total	3,114,748			3,114,748

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

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

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
10.1	Second Amendment Agreement, dated as of March 21, 2018, by and among NRG Energy, Inc., 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 March 22, 2018.
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: May 3, 2018	Chief Accounting Officer (Principal Accounting Officer)