Edgar Filing: NRG ENERGY, INC.

Document

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, 2019

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)

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class	Trading Symbol(s)	Name of Exchange on Which Registered
Common Stock, par value $0.01	NRG	New York Stock Exchange

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 every Interactive Data File required to be submitted 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 such files).

Yes x No o

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



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

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

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

Yes o No x

As of April 30, 2019, there were 267,153,283 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	8
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	8
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	50
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	74
ITEM 4 — CONTROLS AND PROCEDURES	76
PART II — OTHER INFORMATION	77
ITEM 1 — LEGAL PROCEEDINGS	77
ITEM 1A — RISK FACTORS	77
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	77
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	77
ITEM 4 — MINE SAFETY DISCLOSURES	77
ITEM 5 — OTHER INFORMATION	77
ITEM 6 — EXHIBITS	78
SIGNATURES	79

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 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, 2018 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;


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


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


•	Volatile power supply costs and demand for power;


•	Changes in law, including judicial decisions;

•

Hazards customary to the power production industry and power generation operations, such as fuel and electricity price volatility, unusual weather conditions, 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 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:



2018 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 2018
2023 Term Loan Facility		The Company's $1.7 billion term loan facility due 2023, a component of the Senior Credit Facility
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
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
CAISO		California Independent System Operator
Carlsbad		Carlsbad Energy Center, a 528 MW natural gas-fired project located in Carlsbad, CA
CDD		Cooling Degree Day
CDWR		California Department of Water Resources
CFTC		U.S. Commodity Futures Trading Commission
C&I		Commercial industrial and governmental/institutional
CES		Clean Energy Standard
Cleco		Cleco Corporate Holdings LLC
CO₂		Carbon Dioxide
ComEd		Commonwealth Edison
Company		NRG Energy, Inc.
CPP		Clean Power Plan
CWA		Clean Water Act
D.C. Circuit		U.S. Court of Appeals for the District of Columbia Circuit
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
Economic gross margin		Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales
EGU		Electric Generating Unit
EME		Edison Mission Energy
EPA		U.S. Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESPP		NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
ESPS		Existing Source Performance Standards
Exchange Act		The Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGD		Flue gas desulfurization
FTRs		Financial Transmission Rights
GAAP		Generally accepted accounting principles in the U.S.
GenConn		GenConn Energy LLC



GenOn		GenOn Energy, Inc.
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
GHG		Greenhouse Gas
GIP		Global Infrastructure Partners
Green Mountain Energy		Green Mountain Energy Company
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
HLW		High-level radioactive waste
ICE		Intercontinental Exchange
ISO		Independent System Operator, also referred to as RTOs
ISO-NE		ISO New England Inc.
kWh		Kilowatt-hour
LaGen		Louisiana Generating, LLC
LIBOR		London Inter-Bank Offered Rate
LTIPs		Collectively, the NRG LTIP and the NRG GenOn LTIP
Mass Market		Residential and small commercial customers
MATS		Mercury and Air Toxics Standards promulgated by the EPA
MDth		Thousand Dekatherms
Midwest Generation		Midwest Generation, LLC
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		Million British Thermal Units
MW		Megawatts
MWe		Megawatt equivalent
MWh		Saleable megawatt hour net of internal/parasitic load megawatt-hour
NAAQS		National Ambient Air Quality Standards
NEPOOL		New England Power Pool
NERC		North American Electric Reliability Corporation
NJBPU		New Jersey Board of Public Utilities
Net Exposure		Counterparty credit exposure to NRG, net of collateral
NOL		Net Operating Loss
NO_x		Nitrogen Oxides
NPDES		National Pollutant Discharge Elimination System
NPNS		Normal Purchase Normal Sale
NRC		U.S. Nuclear Regulatory Commission
NRG		NRG Energy, Inc.
NRG Yield, Inc.		NRG Yield, Inc., which changed it's name to Clearway Energy, Inc. following the sale by NRG of NRG Yield and the Renewables Platform to GIP
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
Nuclear Waste Policy Act		U.S. Nuclear Waste Policy Act of 1982
NY DEC		New York Department of Environmental Conservation
NYISO		New York Independent System Operator
NYMEX		New York Mercantile Exchange
NYSPSC		New York State Public Service Commission



OCI/OCL		Other Comprehensive Income/(Loss)
ORDC		Operating Reserve Demand Curve
PA PUC		Pennsylvania Public Utility Commission
Peaking		Units expected to satisfy demand requirements during the periods of greatest or peak load on the system
Petra Nova		Petra Nova Parish Holdings, LLC which is 50% owned by NRG, owns and operates a 240 MWe carbon capture system and a 78 MW cogeneration facility, and owns an equity interest in an oilfield
PG&E		PG&E Corporation (NYSE: PCG) and its primary operating subsidiary, Pacific Gas and Electric Company
PJM		PJM Interconnection, LLC
PM2.5		Particulate Matter that has a diameter of less than 2.5 micrometers
PPA		Power Purchase Agreement
PUCT		Public Utility Commission of Texas
RCRA		Resource Conservation and Recovery Act of 1976
Reliant Energy		Reliant Energy Retail Services, LLC
Renewables		Consists of the following projects that NRG has an ownership interest in: Agua, Ivanpah, Sherbino and NFL stadiums
Renewables Platform		The renewable operating and development platform sold to GIP with NRG's interest in NRG Yield, Inc.
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
RGGI		Regional Greenhouse Gas Initiative
RTO		Regional Transmission Organization
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, 2018, NRG's $3.8 billion outstanding unsecured senior notes consisting of $733 million of 6.25% senior notes due 2024, $1.0 billion of the 7.25% senior notes due 2026, $1.23 billion of the 6.625% senior notes due 2027, and $821 million of 5.75% senior notes due 2028
SNF		Spent Nuclear Fuel
SO₂		Sulfur Dioxide
South Central Portfolio		NRG's South Central Portfolio, which owned and operated a portfolio of generation assets consisting of Bayou Cove, Big Cajun-I, Big Cajun-II, Cottonwood and Sterlington, was sold on February 4, 2019. NRG is leasing back the Cottonwood facility through May 2025
STP		South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOC		South Texas Project Nuclear Operating Company
Texas Genco		Texas Genco LLC
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

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)	2019			2018
Operating Revenues
Total operating revenues	$	2,165		$	2,065
Operating Costs and Expenses
Cost of operations	1,651			1,385
Depreciation and amortization	85			120
Selling, general and administrative	194			176
Reorganization costs	13			20
Development costs	2			5
Total operating costs and expenses	1,945			1,706
Gain on sale of assets	1			2
Operating Income	221			361
Other Income/(Expense)
Equity in (losses)/earnings of unconsolidated affiliates	(21		)	1
Other income, net	12			—
Loss on debt extinguishment, net	—			(2		)
Interest expense	(114		)	(116		)
Total other expense	(123		)	(117		)
Income from Continuing Operations Before Income Taxes	98			244
Income tax expense	4			6
Income from Continuing Operations	94			238
Income/(loss) from discontinued operations, net of income tax	388			(5		)
Net Income	482			233
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests	—			(46		)
Net Income Attributable to NRG Energy, Inc.	$	482		$	279
Earnings per Share Attributable to NRG Energy, Inc.
Weighted average number of common shares outstanding — basic	278			318
Income from continuing operations per weighted average common share — basic	$	0.34		$	0.90
Income/(loss) from discontinued operations per weighted average common share — basic	$	1.39		$	(0.02	)
Earnings per Weighted Average Common Share — Basic	$	1.73		$	0.88
Weighted average number of common shares outstanding — diluted	280			322
Income from continuing operations per weighted average common share — diluted	$	0.34		$	0.89
Income/(loss) from discontinued operations per weighted average common share — diluted	$	1.38		$	(0.02	)
Earnings per Weighted Average Common Share — Diluted	$	1.72		$	0.87
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

(Unaudited)



	Three months ended March 31,
	2019			2018
	(In millions)
Net Income	$	482		$	233
Other Comprehensive (Loss)/Income
Unrealized gain on derivatives	—			14
Foreign currency translation adjustments	1			(2		)
Defined benefit plans	(3		)	(1		)
Other comprehensive (loss)/income	(2		)	11
Comprehensive Income	480			244
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest	—			(38		)
Comprehensive Income Attributable to NRG Energy, Inc.	$	480		$	282

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31, 2019			December 31, 2018
(In millions, except share data)	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	859		$	563
Funds deposited by counterparties	11			33
Restricted cash	15			17
Accounts receivable, net	898			1,024
Inventory	391			412
Derivative instruments	611			764
Cash collateral paid in support of energy risk management activities	388			287
Prepayments and other current assets	285			302
Current assets - held for sale	—			1
Current assets - discontinued operations	—			197
Total current assets	3,458			3,600
Property, plant and equipment, net	2,650			3,048
Other Assets
Equity investments in affiliates	387			412
Operating lease right-of-use assets, net	517			—
Goodwill	573			573
Intangible assets, net	580			591
Nuclear decommissioning trust fund	718			663
Derivative instruments	347			317
Deferred income taxes	45			46
Other non-current assets	255			289
Non-current assets - held-for-sale	—			77
Non-current assets - discontinued operations	—			1,012
Total other assets	3,422			3,980
Total Assets	$	9,530		$	10,628
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	124		$	72
Current portion of operating lease liabilities	74			—
Accounts payable	697			863
Derivative instruments	489			673
Cash collateral received in support of energy risk management activities	11			33
Accrued expenses and other current liabilities	550			680
Current liabilities - held-for-sale	—			5
Current liabilities - discontinued operations	—			72
Total current liabilities	1,945			2,398
Other Liabilities
Long-term debt and capital leases	6,366			6,449
Non-current operating lease liabilities	529			—
Nuclear decommissioning reserve	286			282
Nuclear decommissioning trust liability	423			371
Derivative instruments	350			304
Deferred income taxes	62			65
Other non-current liabilities	1,089			1,274
Non-current liabilities - held-for-sale	—			65
Non-current liabilities - discontinued operations	—			635
Total other liabilities	9,105			9,445
Total Liabilities	11,050			11,843
Redeemable noncontrolling interest in subsidiaries	18			19
Commitments and Contingencies
Stockholders’ Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 421,786,061 and 420,288,886 shares issued and 267,538,257 and 283,650,039 shares outstanding at March 31, 2019 and December 31, 2018, respectively	4			4
Additional paid-in capital	8,473			8,510
Accumulated deficit	(5,548		)	(6,022		)
Less treasury stock, at cost - 154,247,804 and 136,638,847 shares at March 31, 2019 and December 31, 2018, respectively	(4,371		)	(3,632		)
Accumulated other comprehensive loss	(96		)	(94		)
Total Stockholders’ Equity	(1,538		)	(1,234		)
Total Liabilities and Stockholders’ Equity	$	9,530		$	10,628

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)	2019			2018
Cash Flows from Operating Activities
Net income	$	482		$	233
Income/(loss) from discontinued operations, net of income tax	388			(5		)
Net income from continuing operations	94			238
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in losses/(earnings) of unconsolidated affiliates	21			(1		)
Depreciation, amortization and accretion	92			131
Provision for bad debts	26			15
Amortization of nuclear fuel	13			13
Amortization of financing costs and debt discount/premiums	7			6
Adjustment for debt extinguishment	—			2
Amortization of intangibles and out-of-market contracts	6			9
Amortization of unearned equity compensation	4			6
Loss/(gain) on sale and disposal of assets	3			(10		)
Changes in derivative instruments	(15		)	(203		)
Changes in deferred income taxes and liability for uncertain tax benefits	(2		)	(1		)
Changes in collateral deposits in support of energy risk management activities	(123		)	163
Changes in nuclear decommissioning trust liability	9			34
Changes in other working capital	(270		)	(156		)
Cash (used)/provided by continuing operations	(135		)	246
Cash provided by discontinued operations	8			104
Net Cash (Used)/Provided by Operating Activities	(127		)	350
Cash Flows from Investing Activities
Payments for acquisitions of businesses	(16		)	(2		)
Capital expenditures	(49		)	(155		)
Net proceeds from sale of emission allowances	—			6
Investments in nuclear decommissioning trust fund securities	(122		)	(216		)
Proceeds from the sale of nuclear decommissioning trust fund securities	113			182
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	1,313			53
Changes in investments in unconsolidated affiliates	4			(8		)
Contributions to discontinued operations	(44		)	(29		)
Other	(1		)	—
Cash provided/(used) by continuing operations	1,198			(169		)
Cash used by discontinued operations	(2		)	(291		)
Net Cash Provided/(Used) by Investing Activities	1,196			(460		)
Cash Flows from Financing Activities
Payments of dividends to common stockholders	(8		)	(10		)
Payments for treasury stock	(747		)	(93		)
Distributions to noncontrolling interests from subsidiaries	(1		)	(10		)
Proceeds from issuance of common stock	2			7
Payment of debt issuance costs	—			(2		)
Payments for long-term debt	(37		)	(39		)
Cash used by continuing operations	(791		)	(147		)
Cash provided by discontinued operations	43			133
Net Cash Used by Financing Activities	(748		)	(14		)
Change in Cash from discontinued operations	49			(54		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	272			(70		)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	613			1,086
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	885		$	1,016

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(Unaudited)



	Common Stock		Additional Paid-In Capital			Accumulated Deficit			Treasury Stock			Accumulated Other Comprehensive Loss			Total Stock-holders' Equity
	(In millions)
Balances at December 31, 2018	$	4	$	8,510		$	(6,022	)	$	(3,632	)	$	(94	)	$	(1,234	)
Net income						482									482
Other comprehensive loss												(2		)	(2		)
Share repurchases			(10		)				(739		)				(749		)
Equity-based compensation			(32		)										(32		)
Issuance of common stock			5												5
Common stock dividends						(8		)							(8		)
Balances at March 31, 2019	$	4	$	8,473		$	(5,548	)	$	(4,371	)	$	(96	)	$	(1,538	)



	Common Stock		Additional Paid-In Capital			Accumulated Deficit			Treasury Stock			Accumulated Other Comprehensive Loss			Noncon- trolling Interest			Total Stock-holders' Equity
	(In millions)
Balances at December 31, 2017	$	4	$	8,376		$	(6,268	)	$	(2,386	)	$	(72	)	$	2,314		$	1,968
Net income/(loss)						279									(30		)	249
Other comprehensive income												11						11
Sale of assets to NRG Yield, Inc.			8												4			12
ESPP share purchases			(2		)				5									3
Share repurchases									(93		)							(93		)
Equity-based compensation			(10		)													(10		)
Issuance of common stock			7															7
Common stock dividends						(10		)										(10		)
Distributions to noncontrolling interests															(19		)	(19		)
Dividends paid to NRG Yield, Inc.															(30		)	(30		)
Contributions from noncontrolling interests															153			153
Adoption of new accounting standards						17												17
Balances at March 31, 2018	$	4	$	8,379		$	(5,982	)	$	(2,474	)	$	(61	)	$	2,392		$	2,258

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Nature of Business and Basis of Presentation

General

NRG Energy, Inc., or NRG or the Company, is an energy company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to consumers by producing, selling and delivering electricity and related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. NRG is perfecting the integrated model by balancing retail load with generation supply within its deregulated markets, while evolving to a customer-driven business. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the names "NRG", "Reliant" and other brand names owned by NRG, supported by approximately 23,000 MW of generation as of March 31, 2019.

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 2018 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, 2019, and the results of operations, comprehensive income, cash flows and statements of stockholders' equity for the three months ended March 31, 2019 and 2018.

Discontinued Operations

During the fourth quarter of 2018, as described in Note 4, Discontinued Operations and Dispositions, the Company concluded that the sale of its South Central Portfolio to Cleco, excluding the Cottonwood facility, met held-for-sale criteria and should be presented as discontinued operations, as the sale, which closed on February 4, 2019, represented a strategic shift in the business in which NRG operates. The financial information for all historical periods has been recast to reflect the presentation of these entities as discontinued operations.

On August 31, 2018, as described in Note 4, Discontinued Operations and Dispositions, NRG deconsolidated NRG Yield, Inc. and its Renewables Platform for financial reporting purposes. The financial information for all historical periods has been recast to reflect the presentation of these entities, as well as the Carlsbad project, as discontinued operations. As a result of the sale of NRG Yield, the Company no longer controls the Agua Caliente project. Due to this change in control, the Company also deconsolidated the Agua Caliente project from its financial results and began accounting for the project as an equity method investment.

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.

Note 2 — Summary of Significant Accounting Policies

Net Income attributable to NRG Energy, Inc.

The following table reflects the net income attributable to NRG Energy, Inc. after removing the net loss attributable to the noncontrolling interest and redeemable noncontrolling interest:



	Three months ended March 31,
	2019		2018
	(In millions)
Income from continuing operations, net of income tax	$	94	$	245
Income from discontinued operations, net of income tax	388		34
Net income attributable to NRG Energy, Inc.	$	482	$	279

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, 2019		December 31, 2018
	(In millions)
Accounts receivable allowance for doubtful accounts	$	32	$	32
Property, plant and equipment accumulated depreciation	1,610		1,811
Intangible assets accumulated amortization	1,171		1,149
Out-of-market contracts accumulated amortization	—		37

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 sheets that sum to the total of the same such amounts shown in the statements of cash flows.



	March 31, 2019		December 31, 2018		March 31, 2018		December 31, 2017
	(In millions)
Cash and cash equivalents	$	859	$	563	$	514	$	770
Funds deposited by counterparties	11		33		241		37
Restricted cash	15		17		261		279
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	885	$	613	$	1,016	$	1,086

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.

Recent Accounting Developments - Guidance Adopted in 2019

ASU 2016-02 - In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, which was further amended through various updates issued by the FASB thereafter, 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 adopted the standard and its subsequent corresponding updates effective January 1, 2019 under the modified retrospective approach by applying the provisions of the new leases guidance at the effective date without adjusting the comparative periods presented. The Company assessed its leasing arrangements, evaluated the impact of applying practical expedients and accounting policy elections, and implemented lease accounting software to meet the reporting requirements of the standard. The Company established operating lease liabilities of $404 million and right-of-use assets of $321 million upon adoption, before considering deferred taxes. The adoption of Topic 842 did not have a material impact on the statements of operations or cash flows. See Note 8, Leases, for further discussion.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU 2018-17 - In October 2018, the FASB issued ASU No. 2018-17, Consolidations (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities, in response to stakeholders’ observations that Topic 810, Consolidations, could be improved thereby improving general purpose financial reporting. Specifically, ASC 2018-17 requires application of the variable interest entity (VIE) guidance to private companies under common control and consideration of indirect interest held through related parties under common control for determining whether fees paid to decision makers and service providers are variable interests. The amendments are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. All entities are required to apply the amendments retrospectively with a cumulative-effect adjustment to retained earnings at the beginning of the earliest period presented. The Company is evaluating the impact of adopting this guidance on the consolidated financial statements and disclosures.

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

Note 3 — Revenue Recognition

Performance Obligations

As of March 31, 2019, estimated future fixed fee performance obligations are $500 million, $500 million, $535 million, $284 million and $29 million for fiscal years 2019, 2020, 2021, 2022 and 2023, respectively. These performance obligations are for cleared auction MWs in the PJM, ISO-NE, NYISO and MISO capacity auctions and are subject to penalties for non performance.

Disaggregated Revenues

The following table represents the Company’s disaggregation of revenue from contracts with customers for the three months ended March 31, 2019 and March 31, 2018, along with the reportable segment for each category:



	Three months ended March 31, 2019
			Generation
(In millions)	Retail		Texas			East/West/Other			Subtotal		Corporate/Eliminations			Total
Energy revenue^(a)(b)	$	—	$	358		$	224		$	582	$	(276	)	$	306
Capacity revenue^(a)	—		—			155			155		(1		)	154
Retail revenue
Mass customers	1,321		—			—			—		(1		)	1,320
Business Solutions customers	286		—			—			—		—			286
Total retail revenue	1,607		—			—			—		(1		)	1,606
Mark-to-market for economic hedging activities^(b)(c)	—		13			(8		)	5		15			20
Other revenues^(a)	—		29			52			81		(2		)	79
Total operating revenue	1,607		400			423			823		(265		)	2,165
Less: Lease revenue	3		—			2			2		—			5
Less: Realized and unrealized ASC 815 revenue^(b)	—		546			97			643		(262		)	381
Total revenue from contracts with customers	$	1,604	$	(146	)	$	324		$	178	$	(3	)	$	1,779
(a) The following amounts of energy and capacity revenue primarily relate to derivative instruments and are accounted for under ASC 815
	Retail		Texas			East/West/Other			Subtotal		Corporate/Eliminations			Total
Energy revenue	$	—	$	525		$	88		$	613	$	(277	)	$	336
Capacity revenue	—		—			18			18		—			18
Other revenue	—		8			(1		)	7		—			7

(b) Generation includes higher revenues due to the Company's large internal transfer of power based on average annualized market prices, which are offset by higher cost of operations within Retail



	Three months ended March 31, 2018
				Generation
(In millions)	Retail			Texas			East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue^(a)(b)	$	—		$	265		$	339		$	604		$	(161	)	$	443
Capacity revenue^(a)	—			—			142			142			—			142
Retail revenue
Mass customers	1,176			—			—			—			(1		)	1,175
Business Solutions customers	310			—			—			—			—			310
Total retail revenue	1,486			—			—			—			(1		)	1,485
Mark-to-market for economic hedging activities^(b)(c)	(6		)	(569		)	(5		)	(574		)	484			(96		)
Other revenues^(a)	—			53			45			98			(7		)	91
Total operating revenue	1,480			(251		)	521			270			315			2,065
Less: Lease revenue	3			—			2			2			—			5
Less: Realized and unrealized ASC 815 revenue^(b)	(6		)	(150		)	85			(65		)	327			256
Total revenue from contracts with customers	$	1,483		$	(101	)	$	434		$	333		$	(12	)	$	1,804
(a) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815
	Retail			Texas			East/West/Other			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	413		$	60		$	473		$	(157	)	$	316
Capacity revenue	—			—			26			26			—			26
Other revenue	—			5			3			8			—			8

(b) Generation includes higher revenues due to the Company's large internal transfer of power based on average annualized market prices, which are offset by higher cost of operations within Retail

Contract Balances

The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of March 31, 2019 and December 31, 2018:



(In millions)	March 31, 2019		December 31, 2018
Deferred customer acquisition costs	$	117	$	111

Accounts receivable, net - Contracts with customers	870		999
Accounts receivable, net - Derivative instruments	22		20
Accounts receivable, net - Affiliate	6		5
Total accounts receivable, net	$	898	$	1,024

Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	$	305	$	392
Deferred revenues	80		67

Note 4 — Discontinued Operations and Dispositions

Discontinued Operations

Sale of South Central Portfolio

On February 4, 2019, the Company completed the sale of the South Central Portfolio to Cleco for cash consideration of $1 billion excluding working capital and other adjustments. The Company concluded that the divested business met the criteria for discontinued operations as of December 31, 2018, as the disposition represented a strategic shift in the business in which NRG operates and the criteria for held-for-sale were met. As such, all current and prior period results for the operations of the South Central Portfolio, except for the Cottonwood facility as discussed below, have been reclassified as discontinued operations. In connection with the transaction, NRG also entered into a transition services agreement to provide certain corporate services to the divested business.

The South Central Portfolio includes the 1,153 MW Cottonwood natural gas generating facility. Upon the closing of the sale of the South Central Portfolio, NRG entered into an agreement with Cleco to leaseback the Cottonwood facility through May 2025. Due to its continuing involvement with the Cottonwood facility, NRG did not use discontinued operations treatment in accounting for historical and ongoing activity with Cottonwood.

Summarized results of the South Central Portfolio discontinued operations were as follows:



	Three months ended
(In millions)	March 31, 2019			March 31, 2018
Operating revenues	$	31		$	102
Operating costs and expenses	(23		)	(86		)
Gain from discontinued operations, net of tax	8			16
Gain on disposal of discontinued operations, net of tax	27			—
Gain from discontinued operations, including disposal, net of tax	$	35		$	16

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



(In millions)	December 31, 2018
Cash and cash equivalents	$	89
Accounts receivable, net - trade	49
Inventory	35
Other current assets	5
Current assets - discontinued operations	178
Property, plant and equipment, net	408
Other non-current assets	1
Non-current assets - discontinued operations	409
Accounts payable	19
Other current liabilities	5
Current liabilities - discontinued operations	24
Out-of-market contracts, net	50
Other non-current liabilities	11
Non-current liabilities - discontinued operations	$	61

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

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

Carlsbad

On February 6, 2018, NRG entered into an agreement with NRG Yield and GIP to sell 100% of its membership interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, for $385 million of cash consideration, excluding working capital adjustments. The primary condition to close the Carlsbad transaction was the completion of the sale of NRG Yield and the Renewables Platform. At the time of the sale of NRG Yield and the Renewables Platform in August 2018, the Company concluded that the Carlsbad project met the criteria for discontinued operations and accordingly, all current and prior period results for Carlsbad have been reclassified as discontinued operations. The Company continued to consolidate Carlsbad for financial reporting purposes until the transaction closed on February 27, 2019. Carlsbad continues to have a ground lease and easement agreement with NRG with an initial term ending in 2039 and two ten year extensions. As a result of the transaction, additional commitments related to the project totaled approximately $23 million as of December 31, 2018 and March 31, 2019.

Summarized results of NRG Yield, Inc. and the Renewables Platform and Carlsbad discontinued operations were as follows:



	Three months ended
(In millions)	March 31, 2019			March 31, 2018
Operating revenues	$	19		$	260
Operating costs and expenses	(9		)	(230		)
Other expenses	(5		)	(58		)
Gain/(loss) from operations of discontinued components, before tax	5			(28		)
Income tax benefit	—			(7		)
Gain/(loss) from discontinued operations, net of tax	5			(21		)
Gain on disposal of discontinued operations, net of tax	348			—
Gain/(loss) from discontinued operations, including disposal, net of tax	$	353		$	(21	)

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



(In millions)	December 31, 2018
Restricted cash	$	4
Accounts receivable, net - trade	10
Other current assets	5
Current assets - discontinued operations	19
Property, plant and equipment, net	590
Intangible assets, net	9
Other non-current assets	4
Non-current assets - discontinued operations	603
Current portion of long-term debt and capital leases	20
Accounts payable	27
Other current liabilities	1
Current liabilities - discontinued operations	48
Long-term debt and capital leases	572
Other non-current liabilities	2
Non-current liabilities - discontinued operations	$	574

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

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. NRG Yield, Inc. paid cash consideration of approximately $42 million, excluding working capital adjustments, and assumed non-recourse debt of approximately $183 million.

GenOn

On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings, NRG concluded that it no longer controlled GenOn as it was subject to the control of the Bankruptcy Court; and, accordingly, NRG deconsolidated GenOn for financial reporting purposes as of June 14, 2017.

By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that GenOn met the criteria for discontinued operations, as this represented a strategic shift in the business in which NRG operates. As such, all prior period results for GenOn have been reclassified as discontinued operations. GenOn's plan of reorganization was confirmed on December 14, 2018. Income from discontinued operations for the three months ended March 31, 2018 was immaterial.

Dispositions

The Company completed other asset sales for $10 million and $11 million of cash proceeds during the three months ended March 31, 2019 and 2018, respectively.

Note 5 — Fair Value of Financial Instruments

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 amounts approximate fair values 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, 2019				As of December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable	$	17	$	14	$	17	$	14
Liabilities:
Long-term debt, including current portion^(a)	6,558		6,971		6,591		6,697

(a) 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, 2019 and December 31, 2018:



	As of March 31, 2019				As of December 31, 2018
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	6,834	$	137	$	6,528	$	169

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, 2019
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	37	$	1	$	18	$	18
Nuclear trust fund investments:
Cash and cash equivalents	15		15		—		—
U.S. government and federal agency obligations	50		50		—		—
Federal agency mortgage-backed securities	96		—		96		—
Commercial mortgage-backed securities	29		—		29		—
Corporate debt securities	100		—		100		—
Equity securities	354		354		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	929		45		769		115
Interest rate contracts	29		—		29		—
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	70
Equity securities	9
Total assets	$	1,723	$	466	$	1,045	$	133
Derivative liabilities:
Commodity contracts	$	839	$	107	$	615	$	117
Total liabilities	$	839	$	107	$	615	$	117



	As of December 31, 2018
(In millions)	Total		Level 1		Level 2		Level 3
Investments in securities (classified within other current and non-current assets)	$	39	$	2	$	18	$	19
Nuclear trust fund investments:
Cash and cash equivalents	19		19		—		—
U.S. government and federal agency obligations	46		46		—		—
Federal agency mortgage-backed securities	100		—		100		—
Commercial mortgage-backed securities	22		—		22		—
Corporate debt securities	96		—		96		—
Equity securities	312		312		—		—
Foreign government fixed income securities	4		—		4		—
Other trust fund investments:
U.S. government and federal agency obligations	1		1		—		—
Derivative assets:
Commodity contracts	1,042		137		796		109
Interest rate contracts	39		—		39		—
Measured using net asset value practical expedient:
Equity securities — nuclear trust fund investments	64
Equity securities	8
Total assets	$	1,792	$	517	$	1,075	$	128
Derivative liabilities:
Commodity contracts	$	977	$	224	$	664	$	89
Total liabilities	$	977	$	224	$	664	$	89

There were no transfers during the three months ended March 31, 2019 and 2018 between Levels 1 and 2. The following tables reconcile, for the three months ended March 31, 2019 and 2018, 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, 2019
(In millions)	Debt Securities			Derivatives^(a)			Total
Beginning balance as of January 1, 2019	$	19		$	20		$	39
Total losses — realized/unrealized included in earnings	—			(10		)	(10		)
Cash received	(1		)	—			(1		)
Purchases	—			(2		)	(2		)
Transfers into Level 3^(b)	—			17			17
Transfers out of Level 3^(b)	—			(27		)	(27		)
Ending balance as of March 31, 2019	$	18		$	(2	)	$	16
(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, 2019	$	—		$	(12	)	$	(12	)


(a)	Consists of derivative assets and liabilities, net


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



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended March 31, 2018
(In millions)	Debt Securities		Derivatives^(a)			Total
Beginning balance as of January 1, 2018	$	19	$	(15	)	$	4
Total gains — realized/unrealized included in earnings	—		11			11
Purchases	—		1			1
Transfers into Level 3^(b)	—		4			4
Transfers out of Level 3^(b)	—		4			4
Ending balance as of March 31, 2018	$	19	$	5		$	24
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	$	—	$	12		$	12


(a)	Consists of derivative assets and liabilities, net


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

Derivative Fair Value Measurements

A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available. These contracts are valued based on various valuation techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of the observable market data with similar characteristics. As of March 31, 2019, contracts valued with prices provided by models and other valuation techniques make up 12% of derivative assets and 14% of 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, 2019 and December 31, 2018:



	March 31, 2019
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(In millions)
Power Contracts	$	89	$	104	Discounted Cash Flow	Forward Market Price (per MWh)	0		$	253	$	28
FTRs	26		13		Discounted Cash Flow	Auction Prices (per MWh)	(42	)	38		0
	$	115	$	117



	December 31, 2018
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	89	$	75	Discounted Cash Flow	Forward Market Price (per MWh)	$	1		$	214	$	31
FTRs	20		14		Discounted Cash Flow	Auction Prices (per MWh)	(90		)	34		0
	$	109	$	89

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of March 31, 2019 and December 31, 2018:



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, 2019 and December 31, 2018, the credit reserve did not result in a significant change in fair value in operating revenue and cost of operations.

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company's 2018 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 2018 Form 10-K. As of March 31, 2019, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $259 million and NRG held collateral (cash and letters of credit) against those positions of $102 million, resulting in a net exposure of $162 million. Approximately 50% of the Company's exposure before collateral is expected to roll off by the end of 2020. 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, 2019	100	%



	Net Exposure ^{(a) (b)}
Category by Counterparty Credit Quality	(% of Total)
Investment grade	52	%
Non-Investment grade/Non-Rated	48
Total as of March 31, 2019	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

The Company currently has no exposure to any individual wholesale counterparties in excess of 10% of total net exposure discussed above as of March 31, 2019. 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 its 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 the overall market and are excluded from the above exposures.

Exchange Traded Transactions

The Company enters into commodity transactions on registered exchanges, notably ICE, NYMEX and Nodal. 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 contracts, primarily solar PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company values 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, 2019, aggregate credit risk exposure managed by NRG to these counterparties was approximately $596 million for the next five years, including exposure to PG&E as described below. This amount excludes potential credit exposures for projects with long-term PPAs that have not reached commercial operations.

NRG, through its unconsolidated affiliates Ivanpah and Agua Caliente, has exposure to PG&E of approximately $326 million for the next five years. As a result of the bankruptcy filing by PG&E on January 29, 2019, it is uncertain whether and to what extent the bankruptcy may have an effect on these contracts. For further discussion see Note 10, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs.

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, 2019, 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 6 — Nuclear Decommissioning Trust Fund

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 for the securities held in the trust funds, as well as information about the contractual maturities of those securities.



	As of March 31, 2019							As of December 31, 2018
(In millions, except maturities)	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	$	15	$	—	$	—	—	$	19	$	—	$	—	—
U.S. government and federal agency obligations	50		2		—		13	46		1		—		12
Federal agency mortgage-backed securities	96		1		1		25	100		1		2		23
Commercial mortgage-backed securities	29		1		—		23	22		—		1		22
Corporate debt securities	100		3		1		11	96		1		2		11
Equity securities	424		276		—		—	376		231		1		—
Foreign government fixed income securities	4		—		—		10	4		—		—		9
Total	$	718	$	283	$	2		$	663	$	234	$	6

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,
	2019			2018
	(In millions)
Realized gains	$	3		$	3
Realized losses	(2		)	(3		)
Proceeds from sale of securities	113			182

Note 7 — Accounting for Derivative Instruments and Hedging Activities

Energy-Related Commodities

As of March 31, 2019, NRG had energy-related derivative instruments extending through 2034. The Company marks these derivatives to market through the statement of operations. NRG has executed power purchase agreements extending through 2033 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.

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, 2019, NRG had interest rate derivative instruments on recourse debt extending through 2021.

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, 2019 and December 31, 2018. 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, 2019			December 31, 2018
Category	Units	(In millions)
Emissions	Short Ton	1			(2		)
Renewable Energy Certificates	Certificates	1			1
Coal	Short Ton	9			13
Natural Gas	MMBtu	(236		)	(330		)
Oil	Barrels	—			1
Power	MWh	8			1
Capacity	MW/Day	(1		)	(1		)
Interest	Dollars	$	1,000		$	1,000

The decrease in the natural gas position was primarily the result of additional retail hedge positions and settlement of generation hedges.

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, 2019		December 31, 2018		March 31, 2019		December 31, 2018
	(In millions)
Derivatives Not Designated as Cash Flow or Fair Value Hedges:
Interest rate contracts current	$	15	$	17	$	—	$	—
Interest rate contracts long-term	14		22		—		—
Commodity contracts current	596		747		489		673
Commodity contracts long-term	333		295		350		304
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges	$	958	$	1,081	$	839	$	977

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 March 31, 2019 Balance Sheet
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
	(In millions)
Commodity contracts:
Derivative assets	$	929		$	(689	)	$	(5	)	$	235
Derivative liabilities	(839		)	689			92			(58		)
Total commodity contracts	90			—			87			177
Interest rate contracts:
Derivative assets	29			—			—			29
Total interest rate contracts	29			—			—			29
Total derivative instruments	$	119		$	—		$	87		$	206



	Gross Amounts Not Offset in the December 31, 2018 Balance Sheet
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
	(In millions)
Commodity contracts:
Derivative assets	$	1,042		$	(778	)	$	(31	)	$	233
Derivative liabilities	(977		)	778			114			(85		)
Total commodity contracts	65			—			83			148
Interest rate contracts:
Derivative assets	39			—			—			39
Total interest rate contracts	39			—			—			39
Total derivative instruments	$	104		$	—		$	83		$	187

Accumulated Other Comprehensive Loss

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



	Interest Rate Contracts
	Three months ended March 31,
	2019		2018
	(In millions)
Accumulated OCL beginning balance	$	—	$	(54	)
Reclassified from accumulated OCL to income:
Due to realization of previously deferred amounts	—		4
Mark-to-market of cash flow hedge accounting contracts	—		19
Accumulated OCL ending balance, net of $0, and $6 tax	$	—	$	(31	)

Amounts reclassified from accumulated OCL into income are recorded in discontinued operations.

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 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 commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.



	Three months ended March 31,
	2019			2018
Unrealized mark-to-market results	(In millions)
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	19		$	1
Reversal of acquired gain positions related to economic hedges	(2		)	—
Net unrealized gains on open positions related to economic hedges	3			205
Total unrealized mark-to-market gains for economic hedging activities	20			206
Reversal of previously recognized unrealized gains on settled positions related to trading activity	(6		)	(3		)
Net unrealized gains on open positions related to trading activity	13			11
Total unrealized mark-to-market gains for trading activity	7			8
Total unrealized gains	$	27		$	214



	Three months ended March 31,
	2019			2018
	(In millions)
Unrealized gains/(losses) included in operating revenues	$	27		$	(88	)
Unrealized gains included in cost of operations	—			302
Total impact to statement of operations — energy commodities	$	27		$	214
Total impact to statement of operations — interest rate contracts	$	(9	)	$	12

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, 2019, the $3 million unrealized gain from economic hedge positions was primarily the result of an increase in value of forward power positions due to a decrease in power prices.

For the three months ended March 31, 2018, the $205 million unrealized gains from 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.

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, 2019 was $17 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of March 31, 2019 was $23 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 $3 million as of March 31, 2019.

See Note 5, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.

Note 8 — Leases

The Company leases generating facilities, land, office and equipment, railcars, and storefront space at retail stores. Operating leases with an initial term greater than twelve months are recognized as right-of-use assets and lease liabilities in the consolidated balance sheets. The Company recognizes lease expense for all operating leases on a straight-line basis over the lease term. In the future, should another systematic basis become more representative of the pattern in which the lessee expects to consume the remaining economic benefit of the right-of-use asset, the Company will use that basis for lease expense.

The Company considers a contract to be or to contain a lease when both of the following conditions apply: 1) an asset is either explicitly or implicitly identified in the contract and 2) the contract conveys to the Company the right to control the use of the identified asset for a period of time. The Company has the right to control the use of the identified asset when the Company has both the right to obtain substantially all the economic benefits from the use of the identified asset and the right to direct how and for what purpose the identified asset is used throughout the period of use.

Lease payments are typically fixed and payable on a monthly, quarterly, semi-annual or annual basis. Lease payments under certain agreements may escalate over the lease term either by a fixed percentage or a fixed dollar amount. Certain leases may provide for variable lease payments in the form of payments based on usage, a percentage of sales from the location under lease, or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments. The Company has no leases which contain residual value guarantees provided by the Company as a lessee.

The Company’s leases may grant the Company an option to renew a lease for an additional term(s) or to terminate the lease after a certain period. As part of its transition from the guidance contained in Topic 840 to the updated guidance in Topic 842, the Company elected not to use the practical expedient of using hindsight to determine the lease term and in assessing impairment of the right-of-use assets.

As permitted by Topic 842, the Company made an accounting policy election for all asset classes not to recognize right-of-assets and lease liabilities in the consolidated balance sheets for its short-term leases, which are leases that have a lease term of twelve months or less. For the initial measurement of lease liabilities, the Company uses as the discount rate either the rate implicit in the lease, if known, or its incremental borrowing rate, which is the rate of interest that the Company would have to pay to borrow, on a collateralized basis, over a similar term an amount equal to the payments for the lease.

In transition to Topic 842, the Company elected to apply the effective date transition method as of the January 1, 2019 adoption date. In accordance with this method, the Company’s reporting for comparative periods prior to January 1, 2019 presented in the financial statements continues to be in conformity with the guidance in Topic 840. The Company elected the following practical expedients, which allow entities to:

1.not reassess whether any contracts that existed prior to the January 1, 2019 implementation date are or contain leases;


2.	not reassess the lease classification for any leases that commenced prior to the January 1, 2019 implementation date, meaning that all commenced capital leases under Topic 840 will be classified as finance leases under Topic 842 and all commenced operating leases under Topic 840 will be classified as operating leases under Topic 842;


3.	not reassess initial direct costs for any leases;


4.	not reassess whether existing land easements, which were not previously accounted as leases under Topic 840, are or contain leases; and


5.	not separate lease and non-lease components for all asset classes, except office space leases and generation facilities leases.

As described in Note 3, Discontinued Operations and Dispositions, upon the close of the South Central Portfolio sale, the Company entered into an agreement to leaseback the Cottonwood facility through May 2025. The lease was accounted for in accordance with ASC 842-40, Sale and Leaseback Transactions, as an operating lease and accordingly, a right-of-use asset and lease liability were established on the lease commencement date and will be amortized through the end of the lease.

Lease Cost:



(In millions)	Three months ended March 31, 2019
Operating lease cost	$	23
Variable lease cost	1
Sublease income	(4		)
Total lease cost	$	20

Other information:



(In millions)	Three months ended March 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	21
Right-of-use assets obtained in exchange for new operating lease liabilities	214

Lease Term and Discount Rate:



Weighted-average remaining lease term	In Years
Finance leases	2.8
Operating leases	8.2

Weighted-average discount rate	%
Finance leases	6.5
Operating leases	5.7

As of March 31, 2019, annual payments based on the maturities of NRG's leases are expected to be as follows:



	(In millions)
Remainder of 2019	$	76
2020	96
2021	86
2022	85
2023	86
Thereafter	370
Total undiscounted lease payments	$	799
Less: present value adjustment	(196		)
Total discounted lease payments	$	603

Note 9 — Debt and Capital Leases

Long-term debt and capital leases consisted of the following:



(In millions, except rates)	March 31, 2019			December 31, 2018			March 31, 2019 interest rate %^(a)

Recourse debt:
Senior Notes, due 2024	$	733		$	733		6.250
Senior Notes, due 2026	1,000			1,000			7.250
Senior Notes, due 2027	1,230			1,230			6.625
Senior Notes, due 2028	821			821			5.750
Convertible Senior Notes, due 2048	575			575			2.750
Term loan facility, due 2023	1,694			1,698			L+1.75
Tax-exempt bonds	466			466			4.125 - 6.00
Subtotal recourse debt	6,519			6,523
Non-recourse debt:
Agua Caliente Borrower 1, due 2038	83			86			5.430
Midwest Generation, due 2019	20			48			4.390
Other	34			34			various
Subtotal all non-recourse debt	137			168
Subtotal long-term debt (including current maturities)	6,656			6,691
Capital leases	1			1			various
Subtotal long-term debt and capital leases (including current maturities)	6,657			6,692
Less current maturities	(124		)	(72		)
Less debt issuance costs	(69		)	(70		)
Discounts	(98		)	(101		)
Total long-term debt and capital leases	$	6,366		$	6,449

(a) As of March 31, 2019, L+ equals 1-month LIBOR plus 1.75%

Agua Caliente Borrower 1

On January 22, 2019, the lenders of the Agua Caliente Borrower 1 debt notified Agua Caliente Borrower 1, a subsidiary of the Company, of certain defaults under the financing agreement as it relates to the bankruptcy filing made by PG&E on January 29, 2019. PG&E is the offtaker of the underlying contracts, which are material to the project. The financing was entered into along with Agua Caliente Borrower 2, LLC, a subsidiary of Clearway Energy Inc., which is joint and several to the parties. The Company is working with the lenders to determine a path forward.

Cottonwood - Letters of Credit

On January 4, 2019, the Company entered into an $80 million credit agreement to issue letters of credit, which is currently supporting the Cottonwood facility lease. Annual fees of 1.33% on the facility are paid quarterly in advance. As of March 31, 2019, the full $80 million is issued.

Note 10 — Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs

Entities that are not Consolidated

NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by a number of elements including impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates.

PG&E Bankruptcy - The Agua Caliente project and two of the three Ivanpah units are party to PPAs with PG&E. Both projects have project financing with the U.S. DOE. On January 29, 2019, PG&E Corp. and subsidiary utility PG&E filed for Chapter 11 bankruptcy protection. As part of their filing, PG&E asked the Bankruptcy Court to confirm exclusive jurisdiction over their "rights to reject" PPAs or other contracts regulated by FERC. As a result of the bankruptcy filing, the Agua Caliente and Ivanpah projects have issued notices of events of default under their respective loan agreements. The Company's subsidiaries are working with its partners on the projects and the loan counterparties, however, given the uncertainty involved in bankruptcy proceedings, it is uncertain whether, and to what extent, PG&E's bankruptcy may in the future impact the PPAs and have any resulting impact on the Agua Caliente and Ivanpah projects. NRG's maximum exposure to loss is limited to its equity investment, which was $201 million for Agua Caliente and $20 million for Ivanpah as of March 31, 2019. See Note 9, Debt and Capital Leases for further discussion on Agua Caliente.

Variable Interest Entities

NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, Consolidation, for which NRG is not the primary beneficiary, under the equity method.

Through its consolidated subsidiary, NRG Solar Ivanpah LLC, NRG owns a 54.5% interest in Ivanpah Master Holdings LLC, or Ivanpah, the owner of three solar electric generating projects located in the Mojave Desert with a total capacity of 393 MW. NRG considers this investment a VIE under ASC 810 and NRG is not considered the primary beneficiary. The Company accounts for its interest under the equity method of accounting.

The Ivanpah solar electric generating projects were funded in large part by loans guaranteed by the U.S. DOE and equity from the projects' partners. During the first quarter of 2018, all interested parties sought a restructuring of Ivanpah's debt in order to avoid a potential event of default with respect to the loans and entered into a settlement during the second quarter of 2018. The settlement resulted in certain transactions, including the release of reserves totaling $95 million to fund equity distributions to the partners, which reduced the equity at risk, and the prepayment of certain of the debt balance outstanding, and the amendment of certain of Ivanpah's governing documents. The equity distributions and prepayment of debt were funded by the agreed upon release of reserve funds. These events were considered to be a reconsideration event in accordance with ASC 810. As a result, NRG determined that it is not the primary beneficiary and deconsolidated Ivanpah.

Entities that are Consolidated

The Company has a controlling financial interest in certain entities that 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 eligible for certain tax credits as further described in Note 2, Summary of Significant Accounting Policies to the Company's 2018 Form 10-K.

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



(In millions)	March 31, 2019		December 31, 2018
Current assets	$	3	$	3
Net property, plant and equipment	75		76
Other long-term assets	27		28
Total assets	105		107
Current liabilities	1		2
Long-term debt	29		29
Other long-term liabilities	8		7
Total liabilities	38		38
Redeemable noncontrolling interest	18		19
Net assets less noncontrolling interests	$	49	$	50

Note 11 — Changes in Capital Structure

As of March 31, 2019 and December 31, 2018, 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, 2018	420,288,886	(136,638,847	)	283,650,039
Shares issued under LTIPs	1,497,175	—		1,497,175
Shares repurchased	—	(17,608,957	)	(17,608,957	)
Balance as of March 31, 2019	421,786,061	(154,247,804	)	267,538,257

Employee Stock Purchase Plan

In March 2019, the Company reopened participation in the ESPP, which allows eligible employees to elect to withhold between 1% and 10% of their eligible compensation to purchase shares of NRG common stock at the lesser of 95% of its market value on the offering date or 95% of the fair market value on the exercise date. An offering date will occur each April 1 and October 1. An exercise date will occur each September 30 and March 31.

Share Repurchases

During the three months ended March 31, 2019, the Company completed $250 million share repurchases in connection with the 2018 share repurchase program. In addition, in February 2019, the Company's board of directors authorized an additional $1.0 billion share repurchase program to be executed in 2019. The Company completed $500 million of share repurchases at an average price of $42.21 per share under the 2019 program through May 2, 2019.

On February 28, 2019, the Company executed an accelerated share repurchase agreement, or ASR Agreement, with a financial institution to repurchase a total of $400 million of outstanding common stock based on a volume weighted average price. The Company received initial shares of 9,086,903, which were recorded in treasury stock at fair value based on the closing price on March 12, 2019, of $390 million, with the remaining $10 million recorded in additional paid in capital, representing the value of the forward contract to purchase additional shares. In April 2019, the financial institution delivered the remaining shares pursuant to the ASR agreement and the Company received 351,768 additional shares. The average price paid for all the shares delivered under the ASR Agreement was $42.38 per share. Upon receipt of the additional shares in April 2019, the Company transferred the $10 million from additional paid in capital to treasury stock.

The following repurchases have been made during the three months ended March 31, 2019 and through May 2, 2019:



	Total number of shares purchased	Amounts paid for shares purchased (in millions)
Board Authorized Share Repurchases
2018 program:
Repurchases made during January-February to complete the 2018 program	6,153,415	$	250
2019 program:
Shares repurchased under February 28, 2019 Accelerated Share Repurchase Agreement	9,086,903	400
March repurchases	2,368,639	99
Total Share Repurchases during the three months ended March 31, 2019	17,608,957	$	749
Additional shares delivered upon ASR settlement in April	351,768	—
April repurchases	39,140	1
Total Share Repurchases during the period ended May 2, 2019	17,999,865	$	750

NRG Common Stock Dividends

A quarterly dividend of $0.03 per share was paid on the Company's common stock during the three months ended March 31, 2019. On April 8, 2019, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable May 15, 2019, to stockholders of record as of May 1, 2019, 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 12 — Earnings Per Share

Basic earnings per common share is computed by dividing net income 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 per share is computed in a manner consistent with that of basic income per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The outstanding non-qualified stock options, non-vested restricted stock units, and market stock units are not considered outstanding for purposes of computing basic income per share. However, these instruments are included in the denominator for purposes of computing diluted income per share under the treasury stock method. The 2048 Convertible Senior Notes are convertible, under certain circumstances, into the Company’s common stock, cash or combination thereof (at NRG's option). There is no dilutive effect for the 2048 Convertible Senior Notes due to the Company’s expectation to settle the liability in cash.

The reconciliation of NRG's basic and diluted income per share is shown in the following table:



	Three months ended March 31,
In millions, except per share data	2019		2018
Basic income per share attributable to NRG Energy, Inc;
Net income attributable to NRG Energy, Inc. common stockholders	$	482	$	279
Weighted average number of common shares outstanding - basic	278		318
Income per weighted average common share — basic	$	1.73	$	0.88

Diluted income per share attributable to NRG Energy, Inc;
Net income attributable to NRG Energy, Inc. available to common shareholders	$	482	$	279
Weighted average number of common shares outstanding - basic	278		318
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	2		4
Weighted average number of common shares outstanding - dilutive	280		322
Income per weighted average common share — diluted	$	1.72	$	0.87

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 income per share:



	Three months ended March 31,
In millions of shares	2019	2018
Equity compensation plans	—	1

Note 13 — Segment Reporting

The Company's segment structure reflects how management currently makes financial decisions and allocates resources. The Company's businesses are segregated into the Generation, Retail and corporate segments. Generation includes all power plant activities, domestic and international, as well as renewables. Retail includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products. Intersegment sales are accounted for at market. The financial information for the three months ended March 31, 2018 has been recast to reflect the current segment structure.

On February 4, 2019, as described in Note 4, Discontinued Operations and Dispositions, the Company completed the sale of and deconsolidated the South Central Portfolio. On August 31, 2018, as described in Note 4, Discontinued Operations and Dispositions, NRG deconsolidated NRG Yield, Inc., its Renewables Platform and Carlsbad for financial reporting purposes. The financial information for the three months ended March 31, 2018 has been recast to reflect the presentation of these entities 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)and net income/(loss) attributable to NRG Energy, Inc.



	Three months ended March 31, 2019^(a)
	Retail		Generation			Corporate			Eliminations			Total
	(In millions)
Operating revenues^(b)	$	1,607	$	823		$	1		$	(266	)	$	2,165
Depreciation and amortization	31		46			8			—			85
Reorganization costs	1		1			11			—			13
Equity in losses of unconsolidated affiliates	—		(20		)	27			(28		)	(21		)
Income/(loss) from continuing operations before income taxes	111		114			(100		)	(27		)	98
Income/(loss) from continuing operations	111		114			(104		)	(27		)	94
Income from discontinued operations, net of tax	—		—			388			—			388
Net Income attributable to NRG Energy, Inc.	$	111	$	114		$	284		$	(27	)	$	482
Total assets as of March 31, 2019	$	3,309	$	5,489		$	5,680		$	(4,948	)	$	9,530



^(a) Includes intersegment revenues and costs associated with the internal transfer of power, which is based on average annualized market prices and results in higher revenues in Generation and higher cost of operations in Retail that are eliminated in consolidation
^(b) Operating revenues include intersegment sales and net derivative gains and losses of:	$	3	$	235	$	28	$	—	$	266



	Three months ended March 31, 2018^(a)
	Retail		Generation			Corporate			Eliminations			Total
	(In millions)
Operating revenues^(b)	$	1,480	$	270		$	1		$	314		$	2,065
Depreciation and amortization	26		86			9			(1		)	120
Reorganization costs	3		4			13			—			20
Equity in earnings/(losses) of unconsolidated affiliates	—		2			(1		)	—			1
Income/(loss) from continuing operations before income taxes	944		(573		)	(128		)	1			244
Income/(loss) from continuing operations	944		(573		)	(134		)	1			238
Loss from discontinued operations, net of tax	—		—			(5		)	—			(5		)
Net Income/(Loss)	944		(573		)	(139		)	1			233
Net Income/(Loss) attributable to NRG Energy, Inc.	$	943	$	(565	)	$	(100	)	$	1		$	279



^(a) Includes intersegment revenues and costs associated with our internal transfer of power, which is based on average annualized market prices and results in higher revenues in Generation and higher cost of operations in Retail that are eliminated in consolidation
^(b) Operating revenues include intersegment sales and net derivative gains and losses of:	$	1	$	(309	)	$	(6	)	$	—	$	(314	)

Note 14 — Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:



	Three months ended March 31,
In millions, except rates	2019			2018
Income before income taxes	$	98		$	244
Income tax expense from continuing operations	4			6
Effective income tax rate	4.1		%	2.5		%

For the three months ended March 31, 2019 and 2018, NRG's overall effective tax rate was lower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance, partially offset by current state tax expense.

Uncertain Tax Benefits

As of March 31, 2019, NRG has recorded a non-current tax liability of $31 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the three months ended March 31, 2019, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of March 31, 2019, NRG had cumulative interest and penalties related to these uncertain tax benefits of $5 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years before 2010.

Note 15 — Related Party Transactions

The following table summarizes NRG's material related party transactions with third party affiliates:



	Three months ended March 31,
	2019		2018
	(In millions)
Revenues from Related Parties Included in Operating Revenues
Gladstone	$	1	$	1
GenConn	—		1
Ivanpah	10		—
Midway-Sunset	1		—
Revenues from Related Parties recorded against selling, general and administrative expenses
GenOn	—		21
Total	$	12	$	23

Gladstone — NRG provides services to Gladstone, an equity method investment, under an operations and maintenance agreement. Fees for services under this contract primarily include recovery of NRG's costs of operating the plant, as approved in the annual budget, as well as a base monthly fee.

GenConn — NRG provides services to GenConn under operations and maintenance agreements with GenConn Devon and GenConn Middletown that began in June 2010 and June 2011, respectively. NRG no longer has an ownership interest in GenConn as a result of the sale of its ownership interests in NRG Yield, Inc. and its Renewables Platform.

Ivanpah — NRG provides services to Ivanpah, an equity method investment, under an operations and maintenance agreement and a project management agreement with each project company. Fees for the services under these contracts primarily include recovery of NRG's costs of operating the plant and providing administrative services, plus a profit margin. Ivanpah became a related party to NRG upon deconsolidation in the second quarter of 2018.

Midway-Sunset — NRG provides services to Midway-Sunset, an equity method investment, under an operations and maintenance agreement. Fees for the services under this contract primarily include recovery of NRG's costs of operating the plant, as approved in the annual budget, as well as a base monthly fee and an annual incentive bonus.

GenOn — NRG provided various management, personnel and other services to GenOn under the transition services agreement in conjunction with the confirmation of the GenOn Entities' plan of reorganization. GenOn provided notice to NRG of its intent to terminate the transition services agreement effective August 15, 2018 and all amounts owed and payable to NRG were settled.

Note 16 — Commitments and Contingencies

Commitments

First Lien Structure

Jewett Mine Lignite Contract

The Company's Limestone facility historically blended lignite obtained from the Jewett mine, which was operated by Texas Westmoreland Coal Co, or TWCC, and coal sourced from the Powder River Basin in Wyoming. On August 18, 2016, NRG gave notice to TWCC terminating the active mining of lignite under the contract, effective on December 31, 2016. Under the contract, TWCC remained responsible for reclamation activities. NRG is responsible for reclamation costs and has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of approximately $99 million for the reclamation of the mine. Pursuant to the contract, NRG supports this obligation through surety bonds. Additionally, under the terms of the contract, NRG is obligated to provide additional performance assurance if required by the Railroad Commission of Texas.

On October 9, 2018, TWCC and certain of its affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code before the United States Bankruptcy Court for the Southern District of Texas. TWCC obtained authorization from the bankruptcy court to continue to perform its obligations under its contract with the Company and to maintain surety bonds programs throughout its operations. In addition, NRG has not received any indication from the Railroad Commission of Texas of an intent to draw on the surety bonds. TWCC and its debtor affiliates filed a plan of reorganization that the Bankruptcy Court confirmed on March 2, 2019. Pursuant to the plan, TWCC and its assets, including the Jewett mine and related agreements with NRG, were purchased by Westmoreland Mining LLC, an entity owned by Westmoreland Mining Holdings LLC, a new entity that is ultimately owned and controlled by certain holders of the pre-bankruptcy funded indebtedness of TWCC and certain of its affilates.

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, has been defending an asbestos-related indemnification claim brought by ComEd as a result of the Company's acquisition of EME. The parties have agreed to the terms of a settlement that will resolve all of ComEd's outstanding claims in the matter.

California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC - On January 29, 2016, CDWR and SDG&E (plaintiffs) filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation (defendants). 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, plaintiffs filed a notice of appeal. On January 10, 2018, plaintiffs filed their opening appellate brief. Defendants filed their opposition brief on April 10, 2018. On May 30, 2018, plaintiffs filed their reply brief. The case is now waiting for the court of appeal to schedule oral argument.

Griffoul v. NRG Residential Solar Solutions - On February 28, 2017, plaintiffs, consisting of New Jersey residential solar customers, filed a purported class action lawsuit in New Jersey state court. Plaintiffs allege violations of the New Jersey Consumer Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar contracts. The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits. On June 6, 2017, the defendants filed a motion to compel arbitration or dismiss the lawsuit. Plaintiffs filed their opposition on June 29, 2017. On July 14, 2017, the court denied NRG's motion to compel arbitration or dismiss the case. On July 25, 2017, NRG filed a motion for reconsideration of the appeal, which the court denied. On August 22, 2017, NRG filed a notice of appeal. After oral argument on April 24, 2018, the Appellate Division reversed the lower court on May 4, 2018, and ordered that the plaintiff must arbitrate their claims against NRG. On May 23, 2018, the plaintiff filed a petition for certification with the Supreme Court of New Jersey seeking to overturn the Appellate Division ruling. On January 25, 2019, the Supreme Court denied plaintiff’s petition for certification.

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. On February 4, 2019, NRG sold the South Central Portfolio, including the entities subject to this litigation. However, NRG has agreed to indemnify the purchaser for certain losses suffered in connection therewith.

Note 17 — Regulatory Matters

Environmental regulatory matters are discussed within Note 18, Environmental Matters, to this Form 10-Q.

NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.

In addition to the regulatory proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

Zero-Emission Credits for Nuclear Plants in Illinois and New York - In 2016, Illinois enacted a Zero Emission Credit, or ZEC, program for selected nuclear units in Illinois. In total, the program directs over $2.5 billion over ten years to two Exelon-owned nuclear power plants in Illinois. That same year, the NYSPSC issued its Clean Energy Standard, or CES, which provides 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 New York. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. NRG, along with other companies, filed complaints in the federal courts of Illinois and New York alleging that these state programs are preempted by federal law and in violation of the dormant commerce clause. These cases have proceeded through the federal district court as well as the federal appellate court in Illinois and New York, respectively. Petitions for Writ of Certiorari were filed and were subsequently denied on April 15, 2019.

South Central - On August 4, 2016, NRG received a document hold notice from FERC regarding conduct in the MISO and PJM markets. It required NRG to retain communications related to multiple generating units in the South Central region. Since sending the notice, FERC has been investigating potential violations of MISO rules involving bidding for the Big Cajun 2 facility, as well as other aspects of NRG’s operations in MISO. FERC has the authority to require disgorgement of profits and to impose penalties and NRG retains any liability following the sale of the South Central Portfolio. We expect a preliminary finding from FERC by the second quarter of 2019.

ISO-NE - On February 5, 2019, FERC has informed the Company that it has made a preliminary finding that the Company violated FERC's market behavior rules in connection with offers made into the ISO-NE Forward Capacity Auction in 2016. The Company understands that FERC is concerned that the Company was inaccurate in its communications with the Market Monitor regarding the costs and risks associated with operating certain units in the forward timeframe. NRG withdrew the bids prior to the 2016 auction in the normal course of our commercial business decision making. The Company will be engaging in discussions with FERC regarding this matter.

Note 18 — Environmental Matters

NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. The electric generation industry has been facing requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the current U.S. presidential administration, some of these rules are being reconsidered and reviewed. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the current U.S. presidential administration.

Air

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

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. In December 2018, the EPA proposed a finding that regulating HAPs was not "appropriate and necessary" because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the MATS rule. 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

Once Through Cooling Regulation — 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. The Company anticipates the cost of complying with these requirements to be immaterial.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, 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. On April 12, 2019, the United States Court of Appeals for the Fifth Circuit released its opinion remanding portions of the rule to the EPA. Accordingly, the Company has eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the rule is revised.

Byproducts, Wastes, Hazardous Materials and Contamination

In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amends the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. Accordingly, we anticipate that the EPA will promulgate new regulations to address these issues (including compliance deadlines) as it reconsiders other aspects of the existing rule. The EPA has stated that it intends to further revise the rule. The Company will determine estimates of the cost of compliance after the rule is revised.

Note 19 — Condensed Consolidating Financial Information

As of March 31, 2019, the Company had outstanding $4.4 billion of Senior Notes due from 2024 to 2048, as shown in Note 9, 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.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of March 31, 2019:



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

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

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

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended March 31, 2019

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	1,769		$	395		$	—		$	1		$	2,165
Operating Costs and Expenses
Cost of operations	1,358			283			9			1			1,651
Depreciation and amortization	54			23			8			—			85
Selling, general and administrative	122			16			56			—			194
Reorganization costs	—			—			13			—			13
Development costs	—			—			2			—			2
Total operating costs and expenses	1,534			322			88			1			1,945
Gain on sale of assets	1			—			—			—			1
Operating Income/(Loss)	236			73			(88		)	—			221
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	10			—			299			(309		)	—
Equity in losses of unconsolidated affiliates	—			(21		)	—			—			(21		)
Other income, net	4			1			7			—			12
Interest expense	(4		)	(4		)	(106		)	—			(114		)
Total other income/(expense)	10			(24		)	200			(309		)	(123		)
Income from Continuing Operations Before Income Taxes	246			49			112			(309		)	98
Income tax expense	—			—			4			—			4
Income from Continuing Operations	246			49			108			(309		)	94
Income from discontinued operations, net of income tax	9			5			374			—			388
Net Income Attributable to NRG Energy, Inc.	$	255		$	54		$	482		$	(309	)	$	482


(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, 2019

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income	$	255	$	54	$	482		$	(309	)	$	482
Other Comprehensive Income/(Loss)
Foreign currency translation adjustments, net	1		1		1			(2		)	1
Defined benefit plans, net	—		—		(3		)	—			(3		)
Other comprehensive income/(loss)	1		1		(2		)	(2		)	(2		)
Comprehensive Income Attributable to NRG Energy, Inc.	$	256	$	55	$	480		$	(311	)	$	480


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

March 31, 2019

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	—	$	27		$	832		$	—		$	859
Funds deposited by counterparties	11		—			—			—			11
Restricted cash	12		3			—			—			15
Accounts receivable, net	1,228		199			159			(688		)	898
Inventory	277		114			—			—			391
Derivative instruments	610		21			15			(35		)	611
Cash collateral paid in support of energy risk management activities	367		21			—			—			388
Prepayments and other current assets	192		11			82			—			285
Total current assets	2,697		396			1,088			(723		)	3,458
Property, plant and equipment, net	1,512		987			151			—			2,650
Other Assets
Investment in subsidiaries	477		—			3,765			(4,242		)	—
Equity investments in affiliates	—		387			—			—			387
Operating lease right-of-use assets, net	95		289			133			—			517
Goodwill	360		213			—			—			573
Intangible assets, net	414		166			—			—			580
Nuclear decommissioning trust fund	718		—			—			—			718
Derivative instruments	334		8			14			(9		)	347
Deferred income tax	6		(145		)	184			—			45
Other non-current assets	143		30			94			(12		)	255
Total other assets	2,547		948			4,190			(4,263		)	3,422
Total Assets	$	6,756	$	2,331		$	5,429		$	(4,986	)	$	9,530
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	108		$	16		$	—		$	124
Current portion of operating lease liabilities	23		30			21			—			74
Accounts payable	1,515		(218		)	88			(688		)	697
Derivative instruments	505		19			—			(35		)	489
Cash collateral received in support of energy risk management activities	11		—			—			—			11
Accrued expenses and other current liabilities	244		57			249			—			550
Total current liabilities	2,298		(4		)	374			(723		)	1,945
Other Liabilities
Long-term debt and capital leases	245		112			6,021			(12		)	6,366
Non-current operating lease liabilities	77		320			132			—			529
Nuclear decommissioning reserve	286		—			—			—			286
Nuclear decommissioning trust liability	423		—			—			—			423
Derivative instruments	354		5			—			(9		)	350
Deferred income taxes	112		60			(110		)	—			62
Other non-current liabilities	408		149			532			—			1,089
Total other liabilities	1,905		646			6,575			(21		)	9,105
Total Liabilities	4,203		642			6,949			(744		)	11,050
Redeemable noncontrolling interest in subsidiaries	—		18			—			—			18
Stockholders’ Equity	2,553		1,671			(1,520		)	(4,242		)	(1,538		)
Total Liabilities and Stockholders’ Equity	$	6,756	$	2,331		$	5,429		$	(4,986	)	$	9,530


(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, 2019

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Cash Flows from Operating Activities
Net income	$	255		$	54		$	482		$	(309	)	$	482
Income from discontinued operations	9			5			374			—			388
Net income from continuing operations	246			49			108			(309		)	94
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Equity in losses of unconsolidated affiliates	—			21			—			—			21
Depreciation, amortization and accretion	59			25			8			—			92
Provision for bad debts	23			3			—			—			26
Amortization of nuclear fuel	13			—			—			—			13
Amortization of financing costs and debt discount/premiums	—			—			7			—			7
Amortization of intangibles	6			—			—			—			6
Amortization of unearned equity compensation	—			—			4			—			4
Loss on sale of assets	—			—			3			—			3
Changes in derivative instruments	(29		)	5			9			—			(15		)
Changes in deferred income taxes and liability for uncertain tax benefits	—			1			(3		)	—			(2		)
Changes in collateral deposits in support of energy risk management activities	(114		)	(9		)	—			—			(123		)
Changes in nuclear decommissioning trust liability	9			—			—			—			9
Changes in other working capital	(221		)	(137		)	(221		)	309			(270		)
Cash used by continuing operations	(8		)	(42		)	(85		)	—			(135		)
Cash provided/(used) by discontinued operations	17			(9		)	—			—			8
Net Cash Provided/(Used) by Operating Activities	9			(51		)	(85		)	—			(127		)
Cash Flows from Investing Activities
Payments for acquisitions of businesses	(16		)	—			—			—			(16		)
Capital expenditures	(36		)	(6		)	(7		)	—			(49		)
Investments in nuclear decommissioning trust fund securities	(122		)	—			—			—			(122		)
Proceeds from the sale of nuclear decommissioning trust fund securities	113			—			—			—			113
Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees	1			404			908			—			1,313
Changes in investments in unconsolidated affiliates	—			4			—			—			4
Contributions to discontinued operations	—			(44		)	—			—			(44		)
Other	—			—			(1		)	—			(1		)
Cash (used)/provided by continuing operations	(60		)	358			900			—			1,198
Cash used by discontinued operations	—			(2		)	—			—			(2		)
Net Cash (Used)/Provided by Investing Activities	(60		)	356			900			—			1,196
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(4		)	(290		)	294			—			—
Payments of dividends to common stockholders	—			—			(8		)	—			(8		)
Payments for treasury stock	—			—			(747		)	—			(747		)
Distributions to noncontrolling interests from subsidiaries	—			(1		)	—			—			(1		)
Proceeds from issuance of common stock	—			—			2			—			2
Payments for long-term debt	—			(33		)	(4		)	—			(37		)
Cash used by continuing operations	(4		)	(324		)	(463		)	—			(791		)
Cash provided by discontinued operations	—			43			—			—			43
Net Cash Used by Financing Activities	(4		)	(281		)	(463		)	—			(748		)
Change in cash from discontinued operations	17			32			—			—			49
Net (Decrease)/Increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	(72		)	(8		)	352			—			272
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	95			38			480			—			613
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	23		$	30		$	832		$	—		$	885


(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, 2018

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	1,744		$	329		$	—		$	(8	)	$	2,065
Operating Costs and Expenses
Cost of operations	1,155			224			14			(8		)	1,385
Depreciation and amortization	60			52			8			—			120
Selling, general and administrative	104			11			61			—			176
Reorganization costs	2			—			18			—			20
Development costs	—			1			4			—			5
Total operating costs and expenses	1,321			288			105			(8		)	1,706
Gain/(loss) on sale of assets	3			(1		)	—			—			2
Operating Income/(Loss)	426			40			(105		)	—			361
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	1			—			332			(333		)	—
Equity in earnings/(losses) of unconsolidated affiliates	—			2			(1		)	—			1
Other income/(loss), net	5			(7		)	2			—			—
Loss on debt extinguishment, net	—			—			(2		)	—			(2		)
Interest expense	(3		)	(21		)	(92		)	—			(116		)
Total other income/(expense)	3			(26		)	239			(333		)	(117		)
Income from Continuing Operations Before Income Taxes	429			14			134			(333		)	244
Income tax expense/(benefit)	113			55			(162		)	—			6
Income/(Loss) from Continuing Operations	316			(41		)	296			(333		)	238
Income/(loss) from discontinued operations, net of income tax	15			(20		)	—			—			(5		)
Net Income/(Loss)	331			(61		)	296			(333		)	233
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(63		)	17			—			(46		)
Net Income Attributable to NRG Energy, Inc.	$	331		$	2		$	279		$	(333	)	$	279


(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, 2018

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	331		$	(61	)	$	296		$	(333	)	$	233
Other Comprehensive (Loss)/Income
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/(Loss)	329			(47		)	307			(345		)	244
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(46		)	24			(16		)	(38		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	$	329		$	(1	)	$	283		$	(329	)	$	282


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2018



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	55	$	28		$	480		$	—		$	563
Funds deposited by counterparties	33		—			—			—			33
Restricted cash	7		10			—			—			17
Accounts receivable, net	1,354		115			309			(754		)	1,024
Inventory	278		134			—			—			412
Derivative instruments	779		50			16			(81		)	764
Cash collateral paid in support of energy risk management activities	275		12			—			—			287
Prepayments and other current assets	180		32			90			—			302
Current assets - held-for-sale	—		1			—			—			1
Current assets - discontinued operations	177		20			—			—			197
Total current assets	3,138		402			895			(835		)	3,600
Property, plant and equipment, net	1,938		957			153			—			3,048
Other Assets
Investment in subsidiaries	446		—			4,707			(5,153		)	—
Equity investments in affiliates	—		412			—			—			412
Goodwill	359		214			—			—			573
Intangible assets, net	422		169			—			—			591
Nuclear decommissioning trust fund	663		—			—			—			663
Derivative instruments	296		4			22			(5		)	317
Deferred income taxes	6		(143		)	183			—			46
Other non-current assets	133		71			97			(12		)	289
Non-current assets - held for sale	—		77			—			—			77
Non-current assets - discontinued operations	405		607			—			—			1,012
Total other assets	2,730		1,411			5,009			(5,170		)	3,980
Total Assets	$	7,806	$	2,770		$	6,057		$	(6,005	)	$	10,628
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	55		$	17		$	—		$	72
Accounts payable	1,368		(185		)	434			(754		)	863
Derivative instruments	713		41			—			(81		)	673
Cash collateral received in support of energy risk management activities	33		—			—			—			33
Accrued expenses and other current liabilities	291		36			353			—			680
Current liabilities - held-for-sale	—		5			—			—			5
Current liabilities - discontinued operations	24		48			—			—			72
Total current liabilities	2,429		—			804			(835		)	2,398
Other Liabilities
Long-term debt and capital leases	244		192			6,025			(12		)	6,449
Nuclear decommissioning reserve	282		—			—			—			282
Nuclear decommissioning trust liability	371		—			—			—			371
Derivative instruments	306		3			—			(5		)	304
Deferred income taxes	112		61			(108		)	—			65
Other non-current liabilities	402		320			552			—			1,274
Non-current liabilities - held-for-sale	—		65			—			—			65
Non-current liabilities - discontinued operations	58		577			—			—			635
Total other liabilities	1,775		1,218			6,469			(17		)	9,445
Total Liabilities	4,204		1,218			7,273			(852		)	11,843
Redeemable noncontrolling interest in subsidiaries	—		19			—			—			19
Stockholders’ Equity	3,602		1,533			(1,216		)	(5,153		)	(1,234		)
Total Liabilities and Stockholders’ Equity	$	7,806	$	2,770		$	6,057		$	(6,005	)	$	10,628


(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/(loss)	$	331		$	(61	)	$	296		$	(333	)	$	233
Income/(loss) from discontinued operations	15			(20		)	—			—			(5		)
Net income/(loss) from continuing operations	316			(41		)	296			(333		)	238
Adjustments to reconcile net income to net cash provided/(used) by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	—			(2		)	1			—			(1		)
Depreciation, amortization and accretion	67			56			8			—			131
Provision for bad debts	15			—			—			—			15
Amortization of nuclear fuel	13			—			—			—			13
Amortization of financing costs and debt discount/premiums	—			—			6			—			6
Adjustment for debt extinguishment	—			—			2			—			2
Amortization of intangibles and out-of-market contracts	7			2			—			—			9
Amortization of unearned equity compensation	—			—			6			—			6
(Gain)/loss on sale of assets	(11		)	1			—			—			(10		)
Changes in derivative instruments	(203		)	2			15			(17		)	(203		)
Changes in deferred income taxes and liability for uncertain tax benefits	113			29			(143		)	—			(1		)
Changes in collateral deposits in support of energy risk management activities	162			1			—			—			163
Changes in nuclear decommissioning trust liability	34			—			—			—			34
Changes in other working capital	277			(339		)	(444		)	350			(156		)
Cash provided/(used) by continuing operations	790			(291		)	(253		)	—			246
Cash provided by discontinued operations	32			72			—			—			104
Net Cash Provided/(Used) by Operating Activities	822			(219		)	(253		)	—			350
Cash Flows from Investing Activities
Payments for acquisitions of businesses	(2		)	—			—			—			(2		)
Capital expenditures	(60		)	(74		)	(21		)	—			(155		)
Proceeds from sale of emission allowances, net of purchases	6			—			—			—			6
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	11			—			42			—			53
Change in investments in unconsolidated affiliates	—			(8		)	—			—			(8		)
Distributions to discontinued operations	—			(29		)	—			—			(29		)
Cash (used)/provided by continuing operations	(79		)	(111		)	21			—			(169		)
Cash used by discontinued operations	(1		)	(290		)	—			—			(291		)
Net Cash (Used)/Provided by Investing Activities	(80		)	(401		)	21			—			(460		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(481		)	417			64			—			—
Payment of dividends to common stockholders	—			—			(10		)	—			(10		)
Payments for treasury stock	—			—			(93		)	—			(93		)
Distributions to noncontrolling interests from subsidiaries	—			(10		)	—			—			(10		)
Proceeds from issuance of common stock	—			—			7			—			7
Payment of debt issuance costs	—			—			(2		)	—			(2		)
Payments for long-term debt	—			(34		)	(5		)	—			(39		)
Cash (used)/provided by continuing operations	(481		)	373			(39		)	—			(147		)
Cash provided by discontinued operations	—			133			—			—			133
Net Cash (Used)/Provided by Financing Activities	(481		)	506			(39		)	—			(14		)
Change in cash from discontinued operations	31			(85		)	—			—			(54		)
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash	230			(29		)	(271		)	—			(70		)
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period	41			425			620			—			1,086
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period	$	271		$	396		$	349		$	—		$	1,016


(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, 2019 and 2018. Also refer to NRG's 2018 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.

As further described in Note 4, Discontinued Operations and Dispositions, the Company is treating the following businesses as discontinued operations, and has recast prior periods to present in the corporate segment:


•	South Central Portfolio


•	NRG Yield, Inc. and its Renewables Platform


•	Carlsbad


•	GenOn

Executive Summary

Introduction and Overview

NRG Energy, Inc., or NRG or the Company, is an energy company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to consumers by producing, selling and delivering electricity and related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. NRG is perfecting the integrated model by balancing retail load with generation supply within its deregulated markets, while evolving to a customer-driven business. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the names "NRG" and "Reliant" and other brand names owned by NRG supported by approximately 23,000 MW of generation as of March 31, 2019. NRG was incorporated as a Delaware corporation on May 29, 1992.

The following table summarizes NRG's global generation portfolio as of March 31, 2019, by operating segment:



	Global Generation Portfolio^(a)
	(In MW)
	Generation
Generation Type	Texas^(b)	East/West^(c)(d)	Other^(e)	Total Global
Natural gas	4,759	5,138	—	9,897
Coal	4,174	3,745	—	7,919
Oil	—	3,600	—	3,600
Nuclear	1,126	—	—	1,126
Wind^(f)	—	75	—	75
Utility Scale Solar	—	321	—	321
Battery Storage & Distributed Solar	2	—	60	62
Total generation capacity	10,061	12,879	60	23,000


(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) Does not include plants outside of the ERCOT market or the Sherbino wind farm, which are included in East/West


(c)	Includes International and the remaining Renewables generation assets

(d) Includes 1,153 MW for the Cottonwood facility that was sold to Cleco on February 4, 2019, which the company is leasing until 2025


(e)	The Distributed Solar figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems

(f) Represents the Sherbino wind farm, which on March 29, 2019, NRG entered into an agreement to sell it's ownership interest and expects the sale to close in May 2019

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 innovative solutions to the end-use energy consumer. This strategy is intended to enable the Company to optimize the integrated model to generate predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is an integral piece of NRG's strategy and ties directly to business success, reduced risks and brand value.

To effectuate the Company’s strategy, NRG is focused on: (i) 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; (ii) deploying innovative and renewable energy solutions for consumers within its retail businesses; (iii) excellence in operating performance of its existing assets including optimal hedging of generation assets and retail load operations; and (iv) engaging in a proactive capital allocation plan within the dictates of prudent balance sheet management.

Transformation Plan

NRG is well underway in executing its Transformation Plan. The Company expects to fully implement the Transformation Plan by the end of 2020, with a significant portion of the plan completed in 2018. The three-part, three-year plan is comprised of the following targets, and the Company's achievements towards such targets are as follows:

Operations and cost excellence - Recurring cost savings and margin enhancement of $1,065 million, 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. The Company realized annual cost savings of $532 million and $32 million of margin enhancements during the year ended December 31, 2018, and expects to realize $590 million of cost savings and $135 million of margin enhancements in 2019.

The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and (ii) approximately $290 million one-time cost to achieve. By December 31, 2018, NRG had realized $333 million of non-recurring working capital improvements and $194 million of one-time costs to achieve. The Company expects to incur approximately $95 million of one-time cost to achieve in 2019.

Portfolio Optimization - Targeted and completed $3.0 billion of asset sale cash proceeds through March 31, 2019, including $1.4 billion in the first quarter of 2019 from the sales of the South Central portfolio, the Carlsbad project and Guam.

Capital Structure and Allocation - As of December 31, 2018, the Company achieved the planned credit ratio of 3.0x net debt / adjusted EBITDA^(a).

Energy Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2018 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 17, Regulatory Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q.

As participants in wholesale and retail energy markets and owners of power plants, 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 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

PG&E Corporation Bankruptcy Filing — On January 18, 2019, NextEra Energy, Inc., filed a petition for declaratory order requesting that FERC assert its jurisdiction over PG&E's wholesale contracts prior to PG&E's formal bankruptcy filing. Exelon Corporation and EDF Renewables filed similar complaints. On January 25, 2019, FERC found that it and the bankruptcy courts have concurrent jurisdiction to review and address the disposition of wholesale power contracts. The matter is in litigation.

(a) adjusted EBITDA as defined per the Senior Credit Facility

State Energy Regulation

State Out-Of-Market Subsidy Proposals — NRG has opposed efforts to provide out-of-market subsidies for nuclear generators and intends to continue opposing them in the future. Nuclear subsidy programs have either been implemented, are in the process of being implemented, or have been introduced for discussion in Connecticut, Illinois, New Jersey, Ohio and Pennsylvania. NRG and others were unsuccessful in challenging the legality of the subsidies in Illinois and New York, and the U.S. Supreme Court has declined to review the lower court decisions.

Illinois Legislature Considers Changes to the Generator Business Model -- In Illinois, in addition to legislation to provide more subsidies to nuclear power plants in the state, the Legislature is also considering several bills that may affect NRG’s wholesale and retail revenues, including a bill that would replace the PJM capacity market with a state-run capacity market. NRG is opposed to this legislative effort and has supported a competitive clean energy market design that would competitively procure additional zero emission power without sacrificing the consumer benefits of the competitive PJM market design.

Regional Regulatory Developments

NRG is affected by rule and tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 17, Regulatory Matters, to the Condensed Consolidated Financial Statements.

East/West

PJM

Capacity Market Reforms Filing — FERC is considering various proposals to reform the PJM capacity market, including whether to accommodate state subsidies in the wholesale market or to mitigate subsidized resources, along with other changes. As part of this process, FERC established a procedural timetable and delayed the 2019 Base Residual Auction until August 2019. Decisions around harmonizing federal and state policy initiatives are a critical factor for setting future prices.

PJM's Operational Reserve Demand Curve filing — On March 29, 2019, PJM proposed energy and reserve market reforms to enhance price formation in reserve markets, which includes modifying its Operating Reserve Demand Curve and aligning market-based reserve products in Day-Ahead and Real-Time markets.

Independent Market Monitor Market Seller Offer Cap Complaint — On February 21, 2019, the Independent Market Monitor filed a complaint alleging that the current Market Seller Offer Cap is too high. On April 9, 2019, PJM filed its answer arguing that as a threshold matter the Independent Market Monitor is not authorized to file a complaint against PJM. The outcome of the case could affect the offers placed in the market.

PJM’s Fast-Start Pricing Filing - On April 19, 2019, the Commission ordered PJM to implement fast-start pricing. The Commission found that fast-start pricing practices are unjust and unreasonable because they do not allow prices to reflect the marginal cost of serving load. PJM’s compliance filing is due later this year and will increase the number of units eligible to set the prevailing energy price. The changes will potentially provide more accurate pricing to reflect the marginal cost of serving load and are expected to increase average PJM energy prices.

New England

ISO-NE Retention of Mystic Units — ISO-NE is currently engaged in extensive litigation at FERC regarding how to ensure system reliability in a gas-constrained system. In particular, FERC has approved ISO-NE's proposal to retain units at the Mystic generating station, which utilizes liquefied natural gas for fuel security. Among other things, FERC specifically will allow resources retained for fuel security to enter a zero bid in the Forward Capacity Auction. On January 2, 2019, multiple parties filed for rehearing. The motions for rehearing are pending at FERC. The outcome of this matter may affect future capacity market prices.

ISO-NE Inventoried Energy Compensation Proposal — On March 25, 2019, ISO-NE proposed an interim measure to address near-term fuel security concerns. On April 15, 2019, NRG filed a protest. The outcome of this matter will potentially affect future capacity market prices and the compensation fuel secure units receive.

New York

New York State Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued an order referred to as the Retail Reset Order. Among other things, the Retail Reset Order placed a price cap on energy supply offers and imposed burdensome new regulations on customers. Various parties have challenged the NYSPSC's authority to regulate prices charged by competitive suppliers. This litigation is ongoing.

Texas

ORDC Reforms — In January 2019, the PUCT directed ERCOT to implement changes to its scarcity pricing structure, known as the ORDC, which is designed to increase the likelihood of scarcity pricing to support existing generation and new investment. The PUCT directed ORDC reforms to be implemented in two phases of gradually increasing magnitude. The first phase will become effective prior to the summer of 2019 and the second phase will become effective prior to the summer of 2020.

Environmental Regulatory 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 2018 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 18, 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. Significant changes to air regulatory programs affecting the Company are described below.

MATS — In 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. In December 2018, the EPA proposed a finding that regulating HAPs was not "appropriate and necessary" because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the MATS rule. 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.

Clean Power Plan — The attention in recent years on GHG emissions has resulted in federal regulations and state legislative and regulatory action. In October 2015, the EPA finalized the CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. The D.C. Circuit heard oral argument on the legal challenges to the CPP in September 2016. At the EPA's request, the D.C. Circuit agreed on April 28, 2017 to hold the case in abeyance. On October 16, 2017, the EPA proposed a rule to repeal the CPP. In August 2018, the EPA published the proposed Affordable Clean Energy, or ACE, rule to replace the CPP. The ACE rule, if finalized, would require states to develop plans to seek heat rate improvements from coal-fired EGUs to reduce GHG emissions.

Byproducts, Wastes, Hazardous Materials and Contamination

In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In September 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amends the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. Accordingly, we anticipate that the EPA will promulgate new regulations to address these issues (including compliance deadlines) as it reconsiders other aspects of the existing rule. The EPA has stated that it intends to further revise the rule. The Company will provide estimates of the cost of compliance after the rule is revised.

Domestic Site Remediation Matters

Under certain federal, state and local environmental laws, a current or previous owner or operator of a facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products. NRG may be responsible for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or

decommissioning of a facility, in addition to spills during its operations. Further discussions of affected NRG sites can be found in Note 18, Environmental Matters, to the Consolidated Financial Statements.

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

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

Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended in 1985, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. Texas is currently in a compact with the state of Vermont, and the compact low-level waste facility located in Andrews County in Texas has been operational since 2012.

Water

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. While 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, the Company anticipates the cost of complying with these restrictions to be immaterial.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, 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. On April 12, 2019, the United States Court of Appeals for the Fifth circuit addressed challenges to the rule brought by several environmental groups related to legacy wastewaters and coal ash leachate and remanded portions of the rule to the EPA. The Company has 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 EPA revises the rule.

Regional Environmental Developments

Burton Island Old Ash Landfill — In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. In December 2015, DNREC approved the Company's remediation design, the Company's Closure Report and the Company's Long Term Stewardship Plan. The cost of completing the work required by the approved remediation plan is consistent with amounts budgeted in early 2016 and remediation was completed in 2017. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in 2016.

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

In February 2019, NY DEC proposed a more stringent NOx regulation that depending on the outcome of the regulatory process, may result in the retirement of some of our combustion turbines in New York.

In March 2019, Illinois State Bill 9 was introduced regarding coal ash. The Company and other stakeholders are working with government officials to propose modifications to the Bill. Depending on the outcome of the legislative process, such a new law may be unfavorable to the Company's Midwest Generation facilities.

Significant Events

The following significant events have occurred during 2019, in addition to the Transformation Plan events, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:

Power Purchase Agreements

During the three months ended March 31, 2019, the Company began execution of its strategy to procure mid to long-term generation through power purchase agreements with third-party project developers and other counterparties. The Company expects to continue evaluating and executing such agreements that can support the mid to longer-term needs of its businesses.

Share Repurchases

During the three months ended March 31, 2019, the Company repurchased 6,153,415 shares for $250 million to complete the 2018 program. In addition, in February 2019, the Company's board of directors authorized an additional $1.0 billion share repurchase program to be executed into 2019. The Company repurchased 11,846,450 shares for $500 million at an average price of $42.21 per share under the 2019 program through May 2, 2019, of which 11,455,542 shares were repurchased during the first quarter for $499 million.

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 2018 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment.

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)	2019			2018			Change
Operating Revenues
Energy revenue^(a)	$	306		$	443		$	(137	)
Capacity revenue^(a)	154			142			12
Retail revenue	1,606			1,485			121
Mark-to-market for economic hedging activities	20			(96		)	116
Other revenues^(b)	79			91			(12		)
Total operating revenues	2,165			2,065			100
Operating Costs and Expenses
Cost of sales^(c)	1,341			1,322			(19		)
Mark-to-market for economic hedging activities	—			(302		)	(302		)
Contract and emissions credit amortization ^(c)	5			6			1
Operations and maintenance	248			292			44
Other cost of operations	57			67			10
Total cost of operations	1,651			1,385			(266		)
Depreciation and amortization	85			120			35
Selling, general and administrative	194			176			(18		)
Reorganization costs	13			20			7
Development costs	2			5			3
Total operating costs and expenses	1,945			1,706			(239		)
Gain on sale of assets	1			2			(1		)
Operating Income	221			361			(140		)
Other Income/(Expense)
Equity in (losses)/earnings of unconsolidated affiliates	(21		)	1			(22		)
Other income, net	12			—			12
Loss on debt extinguishment, net	—			(2		)	2
Interest expense	(114		)	(116		)	2
Total other expense	(123		)	(117		)	(6		)
Income from Continuing Operations before Income Taxes	98			244			(146		)
Income tax expense	4			6			(2		)
Income from Continuing Operations	94			238			(144		)
Income/(loss) from discontinued operations, net of income tax	388			(5		)	393
Net Income	482			233			249
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest	—			(46		)	46
Net Income Attributable to NRG Energy, Inc.	$	482		$	279		$	203
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	3.15		$	3.00		5		%

(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, 2019 and 2018

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, 2019 and 2018. The average on-peak power prices were lower in ERCOT - Houston and the East/West region primarily driven by mild weather especially in January and February.



	Average on Peak Power Price ($/MWh)
	Three months ended March 31,
Region	2019		2018		Change %
Texas
ERCOT - Houston^(a)	$	28.20	$	33.15	(15	)%
ERCOT - North^(a)	28.03		31.67		(11	)%
MISO - Louisiana Hub^(b)	32.84		46.24		(29	)%
East/West
NY J/NYC^(b)	45.16		61.97		(27	)%
NEPOOL^(b)	47.40		65.86		(28	)%
COMED (PJM)^(b)	30.09		33.21		(9	)%
PJM West Hub^(b)	33.79		47.43		(29	)%
CAISO - SP15^(b)	50.42		35.44		42	%

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

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

The following table summarizes average realized power prices for each region in which NRG operates for the three months ended March 31, 2019 and 2018, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Three months ended March 31,
Region	2019		2018		Change %
Texas	$	40.10	$	31.31	28	%
East/West/Other^(a)(b)	37.69		43.61		(14	)%

(a) Does not include BETM energy revenue of $17 million for 2018, which was sold in July of 2018

(b) Does not include Ivanpah or Agua Caliente energy revenue of $47 million, as they were deconsolidated in April 2018 and August 2018, respectively

The average realized power prices fluctuated at different rates for the three months ended March 31, 2019 and 2018 due to two factors:


•	The Company's multi-year hedging program

•

During the year, the Company transfers power between the Retail and Generation segments based on market prices. Within Texas, the Retail and Generation segments transact a large internal transfer of power based on average annualized market prices that can result in significant fluctuations on a quarterly basis, but annually have a mark-to-market of $0 at the time of execution. The impact of this internal transfer is more prominent in 2019 due to the increased forward power prices in summer 2019.

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, 2019 and 2018:



	Three months ended March 31, 2019
				Generation
(In millions)	Retail			Texas			East/West/Other^(a)			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	358		$	224		$	582		$	(276	)	$	306
Capacity revenue	—			—			155			155			(1		)	154
Retail revenue	1,607			—			—			—			(1		)	1,606
Mark-to-market for economic hedging activities	—			13			(8		)	5			15			20
Other revenue	—			29			52			81			(2		)	79
Operating revenue	1,607			400			423			823			(265		)	2,165
Cost of fuel	(40		)	(150		)	(99		)	(249		)	3			(286		)
Other cost of sales^(b)	(1,195		)	(46		)	(90		)	(136		)	276			(1,055		)
Mark-to-market for economic hedging activities	(8		)	18			5			23			(15		)	—
Contract and emission credit amortization	—			(5		)	—			(5		)	—			(5		)
Gross margin	$	364		$	217		$	239		$	456		$	(1	)	$	819
Less: Mark-to-market for economic hedging activities, net	(8		)	31			(3		)	28			—			20
Less: Contract and emission credit amortization, net	—			(5		)	—			(5		)	—			(5		)
Economic gross margin	$	372		$	191		$	242		$	433		$	(1	)	$	804
Business Metrics
MWh sold (thousands)				8,928			5,944
MWh generated (thousands)				7,634			4,422
(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits



	Three months ended March 31, 2018
				Generation
(In millions)	Retail			Texas			East/West/Other^(a)(b)			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	265		$	339		$	604		$	(161	)	$	443
Capacity revenue	—			—			142			142			—			142
Retail revenue	1,486			—			—			—			(1		)	1,485
Mark-to-market for economic hedging activities	(6		)	(569		)	(5		)	(574		)	484			(96		)
Other revenue	—			53			45			98			(7		)	91
Operating revenue	1,480			(251		)	521			270			315			2,065
Cost of fuel	(9		)	(124		)	(124		)	(248		)	(1		)	(258		)
Other cost of sales^(c)	(1,101		)	(27		)	(103		)	(130		)	167			(1,064		)
Mark-to-market for economic hedging activities	792			(2		)	(4		)	(6		)	(484		)	302
Contract and emission credit amortization	—			(6		)	—			(6		)	—			(6		)
Gross margin	$	1,162		$	(410	)	$	290		$	(120	)	$	(3	)	$	1,039
Less: Mark-to-market for economic hedging activities, net	786			(571		)	(9		)	(580		)	—			206
Less: Contract and emission credit amortization, net	—			(6		)	—			(6		)	—			(6		)
Economic gross margin	$	376		$	167		$	299		$	466		$	(3	)	$	839
Business Metrics
MWh sold (thousands)				8,463			6,637
MWh generated (thousands)				7,455			4,702
(a) Includes International, Renewables, and Generation eliminations
(b) Includes BETM which was sold as of July 31, 2018
(c) Includes purchased energy, capacity and emissions credits

The table below represents the weather metrics for the three months ended March 31, 2019 and 2018:



	Three months ended March 31,
Weather Metrics	Texas	East/West/Other^(b)
2019
CDDs ^(a)	75	32
HDDs ^(a)	1,041	1,614
2018
CDDs	144	53
HDDs	968	1,518
10-year average
CDDs	106	42
HDDs	971	1,540

(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

(b) The East/West/Other weather metrics are comprised of the average of the CDD and HDD regional results for the Northeast, West - California and West - South Central regions

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)	2019			2018
Retail revenue	$	1,570		$	1,445
Supply management revenue	34			33
Capacity revenue	3			8
Customer mark-to-market	—			(6		)
Operating revenue^(a)	1,607			1,480
Cost of sales^(b)	(1,235		)	(1,110		)
Mark-to-market for economic hedging activities	(8		)	792
Gross Margin	$	364		$	1,162
Less: Mark-to-market for economic hedging activities, net	(8		)	786
Economic Gross Margin	$	372		$	376

Business Metrics
Mass electricity sales volume — GWh - Texas	7,990			7,943
Mass electricity sales volume — GWh - All other regions	2,494			1,718
C&I electricity sales volume — GWh - All regions	4,831			5,027
Natural gas sales volumes (MDth)	10,547			2,175
Average Retail Mass customer count (in thousands)	3,330			2,878
Ending Retail Mass customer count (in thousands)	3,325			2,878


(a)	Includes intercompany sales of $1 million and $1 million in 2019 and 2018, respectively, representing sales from Retail to the Texas region


(b)	Includes intercompany purchases of $302 million and $164 million in 2019 and 2018, respectively, inclusive of the internal transfer of large average annualized market price transactions

Retail gross margin decreased $798 million and economic gross margin decreased $4 million for the three months ended March 31, 2019, compared to the same period in 2018, due to:



	(In millions)
Lower gross margin due to higher supply costs driven by an increase in power prices of approximately $3.25 per MWh or $46 million, partially offset by higher revenue driven by the effect of our margin enhancement initiatives of approximately $1.50 per MWh or $20 million	$	(26	)
Lower gross margin due to the unfavorable weather impact from a decrease in load of 185,000 MWh	(8		)
Higher gross margin primarily driven by higher volumes from XOOM and other customer acquisitions in 2018	30
Decrease in economic gross margin	$	(4	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gain/losses on open positions related to economic hedges	(794		)
Decrease in gross margin	$	(798	)

Generation gross margin and economic gross margin

Generation gross margin increased $576 million and economic gross margin decreased $33 million, both of which include intercompany sales, during the three months ended March 31, 2019, compared to the same period in 2018.

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

Texas Region



	(In millions)
Higher gross margin due to a 28% increase in average realized prices primarily due to the intersegment transactions at annual average power prices	$	38
Higher gross margin driven by planned outage at STP and a forced outage at T.H. Wharton in 2018	7
Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs	3
Higher gross margin from commercial optimization activities	3
Lower gross margin due to fewer sales of NOx emission credits	(22		)
Other	(5		)
Increase in economic gross margin	$	24
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	602
Increase in contract and emission credit amortization	1
Increase in gross margin	$	627

East/West/Other



	(In millions)
Lower gross margin due to the deconsolidations of Ivanpah in April 2018 and Agua Caliente in August 2018	$	(43	)
Lower gross margin primarily due to the sale of BETM, Keystone and Conemaugh in the third quarter of 2018	(24		)
Lower gross margin due to the retirement of Cabrillo I in December 2018	(9		)
Lower gross margin due to a decrease in economic generation volumes primarily due to spark spread contractions in the Northeast	(9		)
Lower gross margin driven by a 33% decrease in realized capacity pricing in New York	(7		)
Lower gross margin due to an extended forced outage at the Sunrise facility in 2019	(7		)
Lower gross margin from commercial optimization activities	(3		)
Higher gross margin due to a 38% increase in PJM capacity prices and a 16% increase in ISO-NE capacity prices	28
Higher gross margin primarily due to 6% increase in average realized prices, primarily at Midwest Generation	17
Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs	2
Other	(2		)
Decrease in economic gross margin	$	(57	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	6
Decrease in gross margin	$	(51	)

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results decreased by $186 million during the three months ended March 31, 2019, compared to the same period in 2018.

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, 2019
				Generation
	Retail			Texas			East/West/Other			Eliminations^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—		$	(79	)	$	(22	)	$	93		$	(8	)
Net unrealized gains/(losses) on open positions related to economic hedges	—			92			14			(78		)	28
Total mark-to-market gains/(losses) in operating revenues	$	—		$	13		$	(8	)	$	15		$	20
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	115		$	3		$	2		$	(93	)	$	27
Reversal of acquired gain positions related to economic hedges	(2		)	—			—			—			(2		)
Net unrealized (losses)/gains on open positions related to economic hedges	(121		)	15			3			78			(25		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(8	)	$	18		$	5		$	(15	)	$	—


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



	Three months ended March 31, 2018
				Generation
	Retail			Texas			East/West/Other			Eliminations^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	(35	)	$	—		$	3		$	(33	)
Net unrealized (losses)/gains on open positions related to economic hedges	(5		)	(534		)	(5		)	481			(63		)
Total mark-to-market (losses)/gains in operating revenues	$	(6	)	$	(569	)	$	(5	)	$	484		$	(96	)
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			(1		)	—			(481		)	268
Total mark-to-market gains/(losses) in operating costs and expenses	$	792		$	(2	)	$	(4	)	$	(484	)	$	302


(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, 2019, the $20 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of gains on power positions due to declines in power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The flat change in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, completely offset by a decrease in the value of open positions as a result of ERCOT heat rate contraction and the reversal of acquired gain positions.

For the three months ended March 31, 2018, the $96 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.

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, 2019 and 2018. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy.



	Three months ended March 31,
(In millions)	2019		2018
Trading gains
Realized	$	16	$	15
Unrealized	7		8
Total trading gains	$	23	$	23

Operations and Maintenance Expense



			Generation				Corporate		Eliminations
	Retail		Texas		East/West/Other		Corporate		Eliminations			Total

Three months ended March 31, 2019	$	54	$	114	$	78	$	3	$	(1	)	$	248
Three months ended March 31, 2018	$	47	$	121	$	124	$	1	$	(1	)	$	292

Operations and maintenance expenses decreased by $44 million for the three months ended March 31, 2019, compared to the same period in 2018, due to the following:



	(In millions)
Decrease in operations and maintenance due to reduction in accrual for the Midwest Generation asbestos liability following final settlement	$	(27	)
Decrease in operations and maintenance due to cost efficiencies as a result of the Transformation Plan	(25		)
Decrease in operations and maintenance due to deconsolidation of Ivanpah and Agua Caliente in 2018	(14		)
Increase in operations and maintenance primarily related to the lease of Cottonwood from February 4, 2019	7
Increase in operations and maintenance to invest in Texas plants in preparation for summer operations	7
Increase in operations and maintenance due to XOOM acquisition in June 2018	5
Increase in operations and maintenance associated with costs incurred for margin enhancement initiatives	2
Other	1
Decrease in operations and maintenance expense	$	(44	)

Other Cost of Operations



			Generation
	Retail		Texas		East/West/Other		Total
			(In millions)
Three months ended March 31, 2019	$	25	$	15	$	17	$	57
Three months ended March 31, 2018	$	24	$	21	$	22	$	67

Other cost of operations decreased by $10 million for the three months ended March 31, 2019, compared to the same period in 2018, due to the following:



	(In millions)
Decrease in other cost of operations due to cost efficiencies as a result of the Transformation Plan	$	(6	)
Decrease in ARO accretion expense due to prior year write off at S.R. Berton	(4		)
Decrease in other cost of operations	$	(10	)

Depreciation and amortization

Depreciation and amortization decreased by $35 million for the three months ended March 31, 2019, compared to the three months ended March 31, 2018, driven primarily by the deconsolidation of Ivanpah in May 2018, Agua Caliente in August 2018, the sale of Cottonwood in February 2019 and prior year impairments.

Selling, General and Administrative

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



	Retail		Generation		Corporate		Total
			(In millions)
Three months ended March 31, 2019	$	141	$	47	$	6	$	194
Three months ended March 31, 2018	116		51		9		176

Selling, general and administrative expenses increased by $18 million for the three months ended March 31, 2019, compared to the same period in 2018, due to the following:



	(In millions)
Increase in selling and marketing expenses associated with costs incurred for margin enhancement initiatives	$	15
Increase in bad debt expense primarily due to higher customer attrition	10
Increase in selling expense due to the acquisition of XOOM in June 2018	9
Decrease in general and administrative expense from cost initiatives for the Transformation Plan	(17		)
Other	1
Increase in selling, general and administrative	$	18

Interest Expense

NRG's interest expense decreased by $2 million for the three months ended March 31, 2019, compared to the same period in 2018 due to the following:



	(In millions)
Increase in derivative interest expense from changes in the fair value of interest rate swaps.	$	21
Decrease related to the deconsolidation of Ivanpah and Agua Caliente in 2018	(13		)
Decrease related to repurchases of $640 million of Senior Notes in 2018 and refinancing debt of $575 million at lower interest rates	(11		)
Other	1
Decrease in interest expense	$	(2	)

Income Tax Expense

For the three months ended March 31, 2019, NRG recorded an income tax expense of $4 million on pre-tax income of $98 million. For the same period in 2018, NRG recorded an income tax expense of $6 million on pre-tax income of $244 million. The effective tax rate was 4.1% and 2.5% for the three months ended March 31, 2019 and 2018, respectively.

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



	Three Months Ended March 31,
(In millions)	2019		2018			Change
South Central Portfolio	$	35	16			$	19
Yield Renewables Platform & Carlsbad	353		(21		)	374
Income/(Loss) from discontinued operations, net of tax	$	388	$	(5	)	$	393

For the three months ended March 31, 2019, NRG recorded income from discontinued operations, net of income tax of $388 million, an increase of $393 million from a loss of $5 million in the same period in 2018, as further described in Note 4, Discontinued Operations and Dispositions.

Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests

Net income/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests was immaterial for the three months ended March 31, 2019, compared to a net loss of $46 million for three months ended March 31, 2018. For the three months ended March 31, 2018 the net losses primarily reflect 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. As a result of the disposition of NRG Yield Inc. and its Renewables Platform, the Company does not anticipate material NCI in the future.

Liquidity and Capital Resources

Liquidity Position

As of March 31, 2019 and December 31, 2018, NRG's liquidity, excluding collateral received, was approximately $2.7 billion and $2.0 billion, respectively, comprised of the following:



(In millions)	March 31, 2019		December 31, 2018
Cash and cash equivalents:	$	859	$	563
Restricted cash - operating	11		6
Restricted cash - reserves^(a)	4		11
Total	874		580
Total credit facility availability	1,801		1,397
Total liquidity, excluding collateral received	$	2,675	$	1,977

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

For the three months ended March 31, 2019, total liquidity, excluding collateral funds deposited by counterparties, increased by $698 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, 2019, 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, and financing arrangements, as described in Note 9, Debt and Capital Leases, to this Form 10-Q. The Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes, and project-related financings.

The table below represents the approximate cash proceeds received from sale transactions and related financings net of working capital and other adjustments completed by the Company during the three months ended March 31, 2019.



Sales	Cash Proceeds (in millions)
South Central Portfolio	$	962
Carlsbad	396
Guam	8
Other	2
Completed sales transactions as of March 31, 2019	$	1,368

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. 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, 2019, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of March 31, 2019:



Equivalent Net Sales Secured by First Lien Structure^(a)	2019	2020	2021	2022	2023
In MW	374	853	729	786	864
As a percentage of total net coal and nuclear capacity^(b)	8%	19%	16%	17%	19%


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


(b)	Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien which excludes coal assets acquired in the Midwest Generation acquisition 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, 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); and (iv) initial collateral for large structured transactions. As of March 31, 2019, the Company had total cash collateral outstanding of $388 million and $472 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, 2019, total collateral held from counterparties was $11 million in cash and $105 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, 2019, and the estimated capital expenditure and growth investments forecast for the remainder of 2019.



	Maintenance		Environmental		Growth Investments^(c)		Total
	(In millions)
Retail	$	5	$	—	$	10	$	15
Generation
Texas	12		—		—		12
East/West/Other^(a)	15		—		—		15
Corporate	3		—		4		7
Total cash capital expenditures for the three months ended March 31, 2019	35		—		14		49
Other investments	—		—		55		55
Total capital expenditures and investments, net of financings	35		—		69		104

Estimated capital expenditures for the remainder of 2019^(b)	$	120	$	3	$	32	$	155

(a) Includes International, Renewables and Cottonwood

(b) Growth includes $32M of costs to achieve associated with the Transformation Plan

Growth Investments capital expenditures

For the three months ended March 31, 2019, the Company's growth investment capital expenditures included $13 million for cost-to-achieve projects associated with the Transformation Plan and $1 million for the Company's other growth projects.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2019 through 2023 required to comply with environmental laws will be approximately $36 million.

Common Stock Dividends

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

Petra Nova Debt Repayment

NRG has guaranteed up to $124 million of Petra Nova's $248 million project debt to its lenders for purposes of debt repayment in the event Petra Nova is unable to meet its projected debt coverage covenant as stipulated in its financing agreements. The covenant test and possible repayment, or a portion thereof, are scheduled to occur in the third quarter of 2019. Once such payment is made, NRG's guarantee will terminate.

Balance Sheet Target Ratio

NRG revised its balance sheet target ratios in order to further strengthen its balance sheet. In order to achieve the revised balance sheet targets, the Company is reserving up to $600 million in 2019 capital which may be allocated toward debt reduction.

Cash Flow Discussion

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



	Three months ended March 31,
	2019			2018			Change
	(In millions)
Net cash (used)/provided by operating activities	$	(127	)	$	350		$	(477	)
Net cash provided/(used) by investing activities	1,196			(460		)	1,656
Net cash used by financing activities	(748		)	(14		)	(734		)

Net Cash Used By Operating Activities

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



	(In millions)
Changes in cash collateral in support of risk management activities due to changes in commodity prices	$	(286	)
Decrease in cash provided by discontinued operations	(96		)
Decrease in accounts payable primarily due to the Transformation Plan	(87		)
Decrease in other working capital	(27		)
Increase in operating income adjusted for non-cash items	19
	$	(477	)

Net Cash Provided By Investing Activities

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



	(In millions)
Increase in proceeds from sale of assets and discontinued operations primarily due to sale of South Central Portfolio and Carlsbad	$	1,260
Decrease in cash used by discontinued operations	289
Decrease in capital expenditures	106
Increase in proceeds received from sales of nuclear decommissioning trust fund securities, net of purchases	25
Increase in contributions to discontinued operations	(15		)
Increase in cash paid for acquisitions due to deferred acquisition payment made in 2019	(14		)
Other	5
	$	1,656

Net Cash Used By Financing Activities

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



	(In millions)
Increase in repurchases of Common Stock in 2019	$	(654	)
Decrease in cash provided by discontinued operations	(90		)
Decrease in distributions from subsidiaries to noncontrolling interests	9
Other	1
	$	(734	)

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

For the three months ended March 31, 2019, the Company had domestic pre-tax book income of $97 million and foreign pre-tax book income of $1 million. As of December 31, 2018, the Company had cumulative domestic Federal NOL carryforwards of $10.7 billion, which will begin expiring in 2031, and cumulative state NOL carryforwards of $5.6 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $213 million, which do not have an expiration date. In addition to the above NOLs, NRG has a $442 million carryforward for interest deductions, as well as $381 million of tax credits to be utilized in future years. In addition to these amounts, the Company has $26 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 2019.

The Company has recorded a non-current tax liability of $31 million until final resolution with the related taxing authority. The $31 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, 2019, NRG has investments in energy and energy-related entities that are accounted for under the equity method of accounting. NRG’s investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. See also Note 10, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs, to this Form 10-Q.

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $1.0 billion as of March 31, 2019. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 15, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2018 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 2018 Form 10-K. See also Note 8, Leases, Note 9, Debt and Capital Leases, and Note 16, 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, 2019.

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 2018 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, 2019, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2019.



Derivative Activity Gains	(In millions)
Fair Value of Contracts as of December 31, 2018	$	104
Contracts realized or otherwise settled during the period	5
Changes in fair value	10
Fair Value of Contracts as of March 31, 2019	$	119



	Fair Value of Contracts as of March 31, 2019
	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	$	(40	)	$	(18	)	$	(4	)	$	—		$	(62	)
Level 2	141			57			(2		)	(13		)	183
Level 3	21			9			(7		)	(25		)	(2		)
Total	$	122		$	48		$	(13	)	$	(38	)	$	119

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, 2019, NRG's net derivative asset was $119 million, an increase to total fair value of $15 million as compared to December 31, 2018. This increase was driven by gains in fair value, as well as roll-off of trades that settled during the period.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $175 million in the net value of derivatives as of March 31, 2019. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in an increase of approximately $157 million in the net value of derivatives as of March 31, 2019.

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's significant accounting policies are outlined in Note 2 , Summary of Significant Accounting Policies. The Company's critical accounting estimates are described in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in the Company's 2018 Form 10-K. There have been no material changes to the Company's critical accounting policies and estimates since the 2018 Form 10-K.

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 2018 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, 2019 and 2018:



(In millions)	2019		2018
VaR as of March 31,	$	45	$	58
Three months ended March 31,
Average	$	45	$	58
Maximum	49		69
Minimum	42		48

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, 2019, for the entire term of these instruments entered into for both asset management and trading, was $13 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 11, Debt and Capital Leases, of the Company's 2018 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, 2019, the counterparties would have owed the Company $29 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, 2019, a 1% change in variable interest rates would result in a $7 million change in interest expense on a rolling twelve-month basis.

As of March 31, 2019, the fair value and related carrying value of the Company's debt was $7.0 billion and $6.6 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 $519 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 $69 million as of March 31, 2019, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $60 million as of March 31, 2019. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2019.

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 5, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 7, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.

Currency Exchange Risk

NRG's foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not hedge. As these earnings and investments are not material to NRG's consolidated results, the Company's foreign currency exposure is limited.

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.

Changes in Internal Control over Financial Reporting

There were no changes in NRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the quarter ended March 31, 2019 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, 2019, see Note 16, 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 2018 Form 10-K. There have been no material changes in the Company's risk factors since those reported in its 2018 Form 10‑K.

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

In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its common stock. $1.25 billion common stock repurchases were completed in 2018 and the remaining $0.25 billion completed through February 2019. In addition the Company's board of directors authorized in February 2019 an additional $1.0 billion share repurchase program to be executed in 2019.

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, 2019.



For the three months ended March 31, 2019	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, 2019 to January 31, 2019)^(c)	4,238,989	$	40.00	4,238,989	$	80,369,347
Month #2
(February 1, 2019 to February 28, 2019)^(c)	1,914,426	$	41.96	1,914,426	$	1,000,000,000
Month #3
(March 1, 2019 to March 31, 2019)	11,455,542	(d)		11,455,542	$	501,417,584
Total at March 31, 2019	17,608,957			17,608,957


(a)	The average price paid per share excludes commissions paid in connection with the open market share repurchases


(b)	Includes commissions paid in connection with the open market repurchases


(c)	Shares repurchased in January and February were open market repurchases made to complete the 2018 $1.5 billion share repurchase program

(d)

Shares repurchased in March were made under the 2019 $1.0 billion share repurchase program and consist of 2,368,639 in repurchases at an average price of $41.52 per share and 9,086,903 initial shares delivered under an ASR agreement. Upon final settlement of the ASR in April 2019, the financial institution delivered the remaining 351,768 shares to the Company. The average price paid for all the shares delivered under the ASR Agreement was $42.38 per share

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

ITEM 6 — EXHIBITS



Number	Description	Method of Filing
10.1	Amended and Restated Employee Stock Purchase Plan	Filed herewith.
31.1	Rule 13a-14(a)/15d-14(a) certification of Mauricio Gutierrez.	Filed herewith.
31.2	Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.	Filed herewith.
31.3	Rule 13a-14(a)/15d-14(a) certification of David Callen.	Filed herewith.
32	Section 1350 Certification.	Furnished herewith.
101 INS	XBRL Instance Document.	Filed herewith.
101 SCH	XBRL Taxonomy Extension Schema.	Filed herewith.
101 CAL	XBRL Taxonomy Extension Calculation Linkbase.	Filed herewith.
101 DEF	XBRL Taxonomy Extension Definition Linkbase.	Filed herewith.
101 LAB	XBRL Taxonomy Extension Label Linkbase.	Filed herewith.
101 PRE	XBRL Taxonomy Extension Presentation Linkbase.	Filed herewith.

SIGNATURES

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



	NRG ENERGY, INC. (Registrant)

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


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


	/s/ DAVID CALLEN
	David Callen
Date: May 2, 2019	Chief Accounting Officer (Principal Accounting Officer)