Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The discussion and analysis below has been organized as follows:


•	Executive Summary, including the business environment in which NRG Energy Inc., or NRG or the Company, operates, a discussion of regulation, weather, competition and other factors that affect the business, Transformation Plan update, and other significant events that are important to understanding the results of operations and financial condition;


•	Results of operations, including an explanation of significant differences between the periods in the specific line items of NRG's Consolidated Statements of Operations;


•	Financial condition addressing credit ratings, liquidity position, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements; and


•	Critical accounting policies which are most important to both the portrayal of the Company's financial condition and results of operations, and which require management's most difficult, subjective or complex judgment.

As you read this discussion and analysis, refer to NRG's Consolidated Statements of Operations to this Form 10-K, which presents the results of the Company's operations for the years ended December 31, 2018, 2017, and 2016, and also refer to Item 1 to this Form 10-K for more detailed discussion about the Company's business.

As further described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the Company is treating the following businesses as discontinued operations, which have been recast to present in the corporate segment:


•	South Central Portfolio


•	NRG Yield, Inc. and its Renewables Platform


•	Carlsbad


•	GenOn

Executive Summary

NRG 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. 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(a) MW of generation as of December 31, 2018.

Business Environment

The industry dynamics and external influences affecting the Company and its businesses, and the power generation and retail energy industry in general in 2018 and for the future medium term include:

Commodities Markets — The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates. Natural gas prices are driven by variables including demand from the industrial, residential, and electric sectors, productivity across natural gas supply basins, costs of natural gas production, changes in pipeline infrastructure, and the financial and hedging profile of natural gas consumers and producers. In 2018, average natural gas prices at Henry Hub was 1.0% lower than in 2017.

If long-term gas prices decrease, the Company is likely to encounter lower realized energy prices, leading to lower energy revenues as higher priced hedge contracts mature and are replaced by contracts with lower gas and power prices. NRG's retail gross margins have historically improved as natural gas prices decline and are likely to partially offset the impact of declining gas prices on conventional wholesale power generation. To further mitigate this impact, NRG may increase its percentage of coal and nuclear capacity sold forward using a variety of hedging instruments, as described under the heading "Energy-Related Commodities" in Item 15 — Note 5, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements.

Natural gas prices are a primary driver of coal demand. The low-priced commodity environment has stressed coal equities, leading coal suppliers to file for bankruptcy protection, launch debt exchanges, rationalize assets, and cut production. If multiple parties withdraw from the market, liquidity could be challenged in the short term. Inventory overhang will be utilized to offset production losses. Coal prices are typically affected by the price of natural gas.


(a)	excluding discontinued operations and held for sale

Electricity Prices — The price of electricity is a key determinant of the profitability of the Company. Many variables such as the price of different fuels, weather, load growth and unit availability all coalesce to impact the final price for electricity and the Company's profitability. An increase in supply cost volatility in the competitive retail markets may result in smaller companies choosing to exit the market, which may result in further consolidation in the competitive retail space. The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the years ended December 31, 2018, 2017, and 2016. Power prices were higher for the year ended December 31, 2018 as compared to the same period in 2017 and 2016. ERCOT power prices were higher primarily due to the continued effect of lower reserve margins as a result of asset retirements in the region. Power prices in East region increased for the year ended December 31, 2018 as compared to the same period in 2017 and 2016 primarily driven by higher winter demand and higher natural gas prices in the fourth quarter of 2018.



	Average On-Peak Power Price ($/MWh)
	Year Ended December 31						2018 vs 2017		2017 vs 2016
Region	2018		2017		2016		Change %		Change %
Texas (a)
ERCOT - Houston(a)	$	37.29	$	33.95	$	26.91	10	%	26	%
ERCOT - North(a)	36.26		25.86		24.53		40	%	5	%
East/West
MISO - Louisiana Hub(b)	43.70		40.02		34.30		9	%	17	%
NY J/NYC(b)	47.19		38.34		35.29		23	%	9	%
NEPOOL(b)	49.96		37.18		35.05		34	%	6	%
COMED (PJM)(b)	34.60		32.46		32.11		7	%	1	%
PJM West Hub(b)	41.66		34.14		33.79		22	%	1	%
CAISO - SP15(b)	47.33		36.48		31.17		30	%	17	%

(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 years ended December 31, 2018, 2017, and 2016, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Year Ended December 31						2018 vs 2017		2017 vs 2016
Region	2018		2017		2016		Change %		Change %
Texas	$	37.12	$	33.45	$	40.49	11	%	(17	)%
East/West	43.70		46.48		47.14		(6	)%	(1	)%

The average realized power prices for December 31, 2018 as compared to the same period in 2017, increased in Texas as a result of higher power prices, and decreased in East/West as a result of the roll off of hedges. The average realized power prices for December 31, 2017 as compared to the same period in 2016 decreased in both Texas and East/West as a result of the roll off of hedges.

Clean Infrastructure Development — Policy mechanisms at the state and federal level including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, RPS, and carbon trading plans, have supported and continue to support the development of renewable generation, demand-side and smart grid, and other clean infrastructure technologies. In addition, the costs associated with the development of clean infrastructure, such as wind and solar generating facilities, continues to decline. These factors continue to drive increases in the development of clean infrastructure in the markets where the Company participates, which may impact the ability of the Company's generating facilities to participate in those markets. According to ERCOT, Inc., more than 30% of 2018 energy consumption in the ERCOT market was generated from carbon-free resources with wind power contributing 19%. Certainly, subsidies and incentives have contributed to the increase in renewable power sources, but it is also true that customer awareness/preferences have shifted toward sustainable solutions. Alternatively, increased demand for sustainable energy products from both residential and commercial consumers creates opportunities for diversified product offerings in competitive retail markets.

Digitization and Customization — The electric industry is experiencing major technology changes in the way power is distributed and used by end-use customers. The electric grid is shifting from a centralized analog system, where power is generated from limited sources and flows in one direction, to a decentralized multidirectional system, where power can be generated from a number of distributed resources and stored or dispatched on an as-needed basis. In addition, consumers are seeking new ways to engage with their power providers. Technologies like smart thermostats, appliances and electric vehicles are giving individuals more choice and control over their electricity usage.

Weather — Weather conditions in the regions of the U.S. in which NRG does business influence the Company's financial results. Weather conditions can affect the supply and demand for electricity and fuels and may also impact the availability of the Company's generating assets. Changes in energy supply and demand may impact the price of these energy commodities in both the spot and forward markets, which may affect the Company's results in any given period. Typically, demand for and the price of electricity is higher in the summer and the winter seasons, when temperatures are more extreme. The demand for and price of natural gas is also generally higher in the winter. However, all regions of the U.S. typically do not experience extreme weather conditions at the same time, thus NRG is typically not exposed to the effects of extreme weather in all parts of its business at once.

Other Factors — A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for NRG's business. These factors include:


•	seasonal, daily and hourly changes in demand;


•	extreme peak demands;


•	available supply resources;


•	transportation and transmission availability and reliability within and between regions;


•	location of NRG's generating facilities relative to the location of its load-serving opportunities;


•	procedures used to maintain the integrity of the physical electricity system during extreme conditions; and


•	changes in the nature and extent of federal and state regulations

These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country as a result of regional differences in:


•	weather conditions;


•	market liquidity;


•	capability and reliability of the physical electricity and gas systems;


•	local transportation systems; and


•	the nature and extent of electricity deregulation

Environmental Matters, Regulatory Matters and Legal Proceedings — Details of environmental matters are presented in Item 15 — Note 23, Environmental Matters, to the Consolidated Financial Statements and Item 1— Business, Environmental Matters, section. Details of regulatory matters are presented in Item 15 — Note 22, Regulatory Matters, to the Consolidated Financial Statements and Item 1— Business, Regulatory Matters, section. Details of legal proceedings are presented in Item 15 — Note 21, Commitments and Contingencies, to the Consolidated Financial Statements. Some of this information relates to costs that may be material to the Company's financial results.

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 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 is on track 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 costs to achieve. By December 31, 2018, NRG has 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 costs to achieve in 2019.

Portfolio Optimization

Targeted and completed $3.0 billion of asset sale cash proceeds received through February 28, 2019, as described below:


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


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


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


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


•	On November 1, 2018, the Company offered to Clearway Energy, Inc. its ownership interest in Agua Caliente Borrower 1, LLC, for approximately $120 million, which owns a 35% interest in AGua Caliente, a 290 MW utility scale solar project. The offer expired on January 31, 2019 with no action taken by Clearway Energy, Inc. As a result of this expiration, the Company has removed this asset from the target asset sale cash proceeds under the Transformation Plan.

•

On November 1, 2018, the Company offered to Clearway Energy, Inc. its ownership interest in Agua Caliente Borrower 1, LLC, for approximately $120 million, which owns a 35% interest in AGua Caliente, a 290 MW utility scale solar project. The offer expired on January 31, 2019 with no action taken by Clearway Energy, Inc. As a result of this expiration, the Company has removed this asset from the target asset sale cash proceeds under the Transformation Plan.


•	During the twelve months ended December 31, 2018, the Company completed the sale of various other assets for approximately $28 million


•	On February 4, 2019, NRG sold the South Central portfolio, a 3,555 MW portfolio of generation assets, for cash consideration of $1 billion, excluding working capital and other adjustments


•	On February 20, 2019, NRG completed the sale of Guam for cash consideration of approximately $8 million


•	On February 27, 2019, NRG sold the Carlsbad project, a 528 MW natural gas-fired power plant, for cash consideration of $387 million, excluding working capital and other adjustments

Capital Structure and Allocation

As of December 31, 2018, the Company achieved the previously announced target of reducing consolidated corporate debt to 3.0x net debt / adjusted EBITDA(a) credit ratio on a pro forma basis that includes the South Central Portfolio sale proceeds. To achieve this ratio, the Company completed the following:


•	Reduction of $9.2 billion in non-recourse debt related to the sale of NRG Yield, Inc. and the Renewable Platform, which includes the debt for Carlsbad Energy Center, as well as the impact of deconsolidation of Agua Caliente and Ivanpah


•	The Company has completed its targeted $640 million of debt reduction through the redemption of $485 million of its outstanding 6.250% senior notes due 2022 and the Term Loan prepayment of $155 million. The annualized interest savings related to these activities to date totals $37 million

In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its common stock. As of February 28, 2019, the Company completed $1.5 billion of repurchases at an average price of $36.24 per share. In addition, the Company's board of directors authorized in February 2019 an additional $1 billion share repurchase program to be executed in 2019.

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

Other Significant Events

The following additional significant events occurred during 2018:

XOOM Energy Acquisition


•	On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for approximately $213 million in cash. See Note 3, Acquisitions, Discontinued Operations and Dispositions for further discussion on purchase price allocation. The acquisition increased NRG's retail portfolio by approximately 300,000 customers.

•

On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for approximately $213 million in cash. See Note 3, Acquisitions, Discontinued Operations and Dispositions for further discussion on purchase price allocation. The acquisition increased NRG's retail portfolio by approximately 300,000 customers.

Agua Caliente and Ivanpah Deconsolidation


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

During the second quarter of 2018, the Company, recognized a loss of $22 million on the deconsolidation and subsequent recognition of its 54.6% interest in Ivanpah as an equity method investment, as discussed in more detail in Note 15, Investments Accounted for by the Equity Method and Variable Interest Entities.

Financing Activities


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


•	On May 24, 2018, the Company issued $575 million in aggregate principal amount at par of 2.75% convertible senior notes due 2048, as discussed in more detail in Note 11, Debt and Capital Leases.


•	During the year ended December 31, 2018, the Company completed senior note repurchases of $1,061million in aggregate principal of its senior notes for $1,106 million, including accrued interest, as discussed in more detail in Note 11, Debt and Capital Leases.


•	The annualized interest savings related to these activities to date totals $20 million

Consolidated Results of Operations for the years ended December 31, 2018 and 2017

The following table provides selected financial information for the Company:



	Year Ended December 31,
(in millions except otherwise noted)	2018			2017			Change
Operating Revenues
Energy revenue (a)	$	1,548		$	1,636		$	(88	)
Capacity revenue (a)	670			612			58
Retail revenue	7,105			6,378			727
Mark-to-market for economic hedging activities	(130		)	252			(382		)
Contract amortization	—			(1		)	1
Other revenues (b)	285			197			88
Total operating revenues	9,478			9,074			404
Operating Costs and Expenses
Cost of sales (b)	5,878			5,432			(446		)
Mark-to-market for economic hedging activities	(144		)	46			190
Contract and emissions credit amortization (c)	27			34			7
Operations and maintenance	1,083			1,097			14
Other cost of operations	264			277			13
Total cost of operations	7,108			6,886			(222		)
Depreciation and amortization	421			596			175
Impairment losses	99			1,534			1,435
Selling, general and administrative	799			836			37
Reorganization costs	90			44			(46		)
Development costs	11			22			11
Total operating costs and expenses	8,528			9,918			1,390
Other income - affiliate	—			87			(87		)
Gain on sale of assets	32			16			16
Operating Income/(Loss)	982			(741		)	1,723
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	9			(14		)	23
Impairment losses on investments	(15		)	(79		)	64
Other income, net	18			51			(33		)
Net loss on debt extinguishment	(44		)	(49		)	5
Interest expense	(483		)	(557		)	74
Total other expenses	(515		)	(648		)	133
Income/(Loss) from Continuing Operations Before Income Taxes	467			(1,389		)	1,856
Income tax expense/(benefit)	7			(44		)	51
Income/(Loss) from Continuing Operations	460			(1,345		)	1,805
Loss from discontinued operations, net of income tax	(192		)	(992		)	800
Net Income/(Loss)	268			(2,337		)	2,605
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	—			(184		)	184
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	268		$	(2,153	)	$	2,421
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	3.09		$	3.11		(1		)%


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


(b)	Includes unrealized trading gains and losses


(c)	Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits

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 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 tables below present the composition and reconciliation of gross margin and economic gross margin which reflects the Company's current view of reporting segments for the years ended December 31, 2018 and 2017:



	Year Ended December 31, 2018
				Generation
(In millions except otherwise noted)	Retail			Texas			East/West/Other(a)(b)			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	1,585		$	1,092		$	2,677		$	(1,129	)	$	1,548
Capacity revenue	—			1			669			670			—			670
Retail revenue	7,110			—			—			—			(5		)	7,105
Mark-to-market for economic hedging activities	(7		)	(174		)	(28		)	(202		)	79			(130		)
Other revenue	—			84			203			287			(2		)	285
Operating revenue	7,103			1,496			1,936			3,432			(1,057		)	9,478
Cost of fuel	(23		)	(734		)	(557		)	(1,291		)	(4		)	(1,318		)
Other costs of sales(c)	(5,285		)	(133		)	(275		)	(408		)	1,133			(4,560		)
Mark-to-market for economic hedging activities	260			2			(39		)	(37		)	(79		)	144
Contract and emission credit amortization	—			(26		)	(1		)	(27		)	—			(27		)
Gross margin	$	2,055		$	605		$	1,064		$	1,669		$	(7	)	$	3,717
Less: Mark-to-market for economic hedging activities, net	253			(172		)	(67		)	(239		)	—			14
Less: Contract and emission credit amortization, net	—			(26		)	(1		)	(27		)	—			(27		)
Economic gross margin	$	1,802		$	803		$	1,132		$	1,935		$	(7	)	$	3,730
Business Metrics
MWh sold (thousands)				42,701			$	24,988
MWh generated (thousands)				38,214			$	21,089
(a) Includes International, Renewables, and Generation eliminations
(b) Includes Agua, BETM and Ivanpah which were sold or deconsolidated as of August, July and April 2018, respectively
(c) Includes purchased energy, capacity and emissions credits



	Year Ended December 31, 2017
				Generation
(In millions except otherwise noted)	Retail			Texas			East/West/Other(a)			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	1,427		$	1,298		$	2,725		$	(1,089	)	$	1,636
Capacity revenue	—			22			596			618			(6		)	612
Retail revenue	6,374			—			—			—			4			6,378
Mark-to-market for economic hedging activities	(4		)	94			(57		)	37			219			252
Contract amortization	(1		)	—			—			—			—			(1		)
Other revenue	—			35			200			235			(38		)	197
Operating revenue	6,369			1,578			2,037			3,615			(910		)	9,074
Cost of fuel	(13		)	(732		)	(542		)	(1,274		)	1			(1,286		)
Other costs of sales(b)	(4,759		)	(137		)	(370		)	(507		)	1,120			(4,146		)
Mark-to-market for economic hedging activities	181			(21		)	13			(8		)	(219		)	(46		)
Contract and emission credit amortization	—			(30		)	(4		)	(34		)	—			(34		)
Gross margin	$	1,778		$	658		$	1,134		$	1,792		$	(8	)	$	3,562
Less: Mark-to-market for economic hedging activities, net	177			73			(44		)	29			—			206
Less: Contract and emission credit amortization, net	(1		)	(30		)	(4		)	(34		)	—			(35		)
Economic gross margin	$	1,602		$	615		$	1,182		$	1,797		$	(8	)	$	3,391
Business Metrics
MWh sold (thousands)				42,662			27,923
MWh generated (thousands)				38,694			21,338
(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits

The table below represents the weather metrics for 2018 and 2017:



	Years ended December 31,		Quarters ended December 31,		Quarters ended September 30,		Quarters ended June 30,		Quarters ended March 31,
Weather Metrics	Texas	East/West/Other	Texas	East/West/Other	Texas	East/West/Other	Texas	East/West/Other	Texas	East/West/Other
2018
CDDs(a)	3,130	1,213	228	74	1,657	856	1,101	265	144	18
HDDs(a)	1,874	3,393	815	1,214	1	26	90	425	968	1,728
2017
CDDs	3,068	1,155	311	84	1,568	770	966	281	223	20
HDDs	1,270	3,198	665	1,157	1	33	32	380	572	1,628
10 year average
CDDs	3,023	1,059	264	69	1,654	714	1,004	259	101	17
HDDs	1,728	3,459	695	1,214	3	40	56	429	974	1,776


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

(a)

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

Retail gross margin and economic gross margin

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



	Years ended December 31,
(In millions except otherwise noted)	2018			2017
Retail revenue	$	6,775		$	6,104
Supply management revenue	174			187
Capacity revenues	161			83
Customer mark-to-market	(7		)	(4		)
Contract amortization	—			(1		)
Operating revenue (a)	7,103			6,369
Cost of sales (b)	(5,308		)	(4,772		)
Mark-to-market for economic hedging activities	260			181
Gross margin	$	2,055		$	1,778
Less: Mark-to-market for economic hedging activities, net	253			177
Less: Contract and emission credit amortization	—			(1		)
Economic gross margin	$	1,802		$	1,602
Business Metrics
Mass electricity sales volume (GWh) - Texas	37,846			36,169
Mass electricity sales volume (GWh) - All other regions	7,968			6,221
C&I electricity sales volume (GWh) All regions (b)	21,176			20,400
Natural gas sales volumes (MDth)	11,253			3,212
Average Retail Mass customer count (in thousands)	3,063			2,862
Ending Retail Mass customer count (in thousands)	3,320			2,876


(a)	Includes intercompany sales of $5 million and $5 million in 2018 and 2017, respectively, representing sales from Retail to the Texas region


(b)	Includes intercompany purchases of $1,163 million and $1,090 million in 2018 and 2017, respectively

Retail gross margin increased $277 million and retail economic gross margin increased $200 million for the year ended December 31, 2018, compared to the same period in 2017, due to:



	(In millions)
Higher gross margin driven by margin enhancement initiatives enhancing customer product, retention, term and mix of $3.30 per MWh, or $208 million partially offset by higher supply costs due to increased power prices in ERCOT of $2.40 MWh, or $150 million.	$	58
Higher gross margin due to higher volumes from net higher average customer counts primarily driven by XOOM acquisition in June 2018	60
Higher gross margin from the favorable impact of weather due to $44 million from an increase in load in 2018 of 1,893,000 MWh partially offset by an unfavorable impact of $14 million from selling back additional excess supply in 2018 as well as $16 million due to the impacts of Hurricane Harvey in 2017	46
Higher gross margin due to an increase in capacity revenues from the business solutions unit mainly due to approximately 1,600 additional MWs sold and margin enhancements from the sale of additional capacity of $11 million	36
Increase in economic gross margin	$	200
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	76
Increase in contract and emission credit amortization	1
Increase in gross margin	$	277

Generation gross margin and economic gross margin

Generation gross margin decreased $123 million and generation economic gross margin increased $138 million, both of which include intercompany sales, during the year ended December 31, 2018, compared to the same period in 2017.

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

Texas Region



	(In millions)
Higher gross margin due to a 11% increase in average realized prices	$	153
Higher gross margin from sales of NOx emission credits	36
Higher gross margin from commercial optimization activities	5
Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs	3
Lower gross margin driven by planned outages for both units at STP in 2018 as compared to a single unit planned outage in 2017	(9		)
Lower gross margin due to an increase in tolling purchases in 2018 as a result of increased demand and the cancellation of the Greens Bayou RMR agreement in 2017	(9		)
Other	9
Increase in economic gross margin	$	188
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(245		)
Increase in contract and emission credit amortization	4
Decrease in gross margin	$	(53	)

East/West Region



	(In millions)
Lower gross margin primarily due to Ivanpah and Agua Caliente being deconsolidated in April 2018 and August 2018, respectively	$	(123	)
Lower gross margin driven by a 26% decrease in realized capacity pricing in New York and expiration of the Long Beach capacity toll in July 2017	(51		)
Lower gross margin mainly due to an 11% decrease in average realized prices, primarily at Midwest Generation	(42		)
Lower gross margin due to decreased load contract volumes coupled with lower prices	(29		)
Lower gross margin at Sunrise in 2018 due to planned major maintenance activities that extended into a forced outage.	(17		)
Higher gross margin due to a 32% increase in PJM capacity prices and a 51% increase in NEISO capacity prices	132
Higher gross margin from commercial optimization activities	35
Higher gross margin due to 2017 lower cost of market adjustment for fuel inventory	31
Higher gross margin as a result of trading activity at BETM	8
Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs	4
Other	2
Decrease in economic gross margin	$	(50	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(23		)
Increase in contract and emission credit amortization	3
Decrease in gross margin	$	(70	)

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 $192 million during the year ended December 31, 2018, compared to the same period in 2017.

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



	Year Ended December 31, 2018
				Generation
	Retail			Texas			East/West/Other			Elimination (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	$	(2	)	$	32		$	(3	)	$	(104	)	$	(77	)
Net unrealized (losses)/gains on open positions related to economic hedges	(5		)	(206		)	(25		)	183			(53		)
Total mark-to-market (losses)/gains in operating revenues	$	(7	)	$	(174	)	$	(28	)	$	79		$	(130	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(81	)	$	(6	)	$	(13	)	$	104		$	4
Reversal of acquired gain positions related to economic hedges.	(10		)	—			—			—			(10		)
Net unrealized gains/(losses) on open positions related to economic hedges	351			8			(26		)	(183		)	150
Total mark-to-market gains/(losses) in operating costs and expenses	260			$	2		$	(39	)	$	(79	)	$	144


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

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



	Year Ended December 31, 2017
				Generation
	Retail			Texas			East/West/Other			Elimination (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	$	(2	)	$	140		$	(72	)	$	64		$	130
Net unrealized (losses)/gains on open positions related to economic hedges	(2		)	(46		)	15			155			122
Total mark-to-market (losses)/gains in operating revenues	$	(4	)	$	94		$	(57	)	$	219		$	252
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(1	)	$	(17	)	$	(1	)	$	(64	)	$	(83	)
Net unrealized gains/(losses) on open positions related to economic hedges	182			(4		)	14			(155		)	37
Total mark-to-market gains/(losses) in operating costs and expenses	$	181		$	(21	)	$	13		$	(219	)	$	(46	)


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

Mark-to-market results consist of unrealized gains and losses on contacts that are yet to be settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.

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

For the year ended December 31, 2018 the $130 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, as well as a decrease in value of open positions as a result of losses on ERCOT heat rate positions due to heat rate expansion. The $144 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of increases in ERCOT heat rate, partially offset by the reversal of acquired gain positions.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 2018 and 2017. The realized and unrealized financial and physical trading results are included in operating revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.



	Year ended December 31,
(In millions)	2018		2017
Trading gains/(losses)
Realized	$	77	$	43
Unrealized	17		(11		)
Total trading gains	$	94	$	32

Operations and Maintenance Expense



			Generation				Corporate			Eliminations
	Retail		Texas		East/West/Other				Total

Year Ended December 31, 2018	$	209	$	437	$	440	$	3		$	(6	)	$	1,083
Year Ended December 31, 2017	$	224	$	387	$	458	$	31		$	(3	)	$	1,097

Operations and maintenance expenses decreased by $14 million for the year ended December 31, 2018, compared to the same period in 2017, due to the following:



	(In millions)
Decrease in operations and maintenance due to cost efficiencies as a result of the Transformation Plan	$	(70	)
Decrease in operations and maintenance due to the deconsolidation of Ivanpah and Agua Caliente in April 2018 and August 2018, respectively	(31		)
Increase in major maintenance due to planned outages of $19 million in Texas and planned outages for both units at STP in 2018 as compared to a planned outage for a single unit in 2017 of $22 million	41
2018 payments in settlement of certain legal matters	13
Increase in technology and personnel costs for customer operations and retention related to margin enhancement	11
Increase in deactivation cost primarily at Dunkirk	8
Increase in costs due to the XOOM acquisition	7
Other	7
	$	(14	)

(a) Approximately $162 million of additional cost savings were achieved in the year ended December 31, 2017, as compared to the year ended December 31, 2016, as the savings became permanent through the Transformation Plan

Other Cost of Operations



			Generation
	Retail		Texas		East/West/Other		Total
			(In millions)
Year Ended December 31, 2018	$	109	$	76	$	79	$	264
Year Ended December 31, 2017	$	99	$	81	$	97	$	277

Other cost of operations, decreased by $13 million for the year ended December 31, 2018, compared to the same period in 2017.



	(In millions)
Decrease due to lower in accretion expense in 2018 at Huntley as a result of a cost estimate increase in 2017	$	(8	)
Decrease in property taxes as a result of the Transformation Plan	(4		)
Other	(1		)
	$	(13	)

Depreciation and Amortization



			Generation			Corporate
	Retail				Total
	(In millions)
Year Ended December 31, 2018	$	116	$	272		$	33	$	421
Year Ended December 31, 2017	$	110	$	454		$	32	$	596

Depreciation and amortization expense decreased by $175 million for the year ended December 31, 2018, compared to the same period in 2017, primarily due to impairments of $1,534 million in 2017 and the deconsolidation of Ivanpah and Agua Caliente in 2018.

Impairment Losses

For the year ended December 31, 2018, the Company recorded impairment losses of $99 million related to various facilities as further described in Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements.

In 2017, the Company recorded impairment losses of $1,534 million related to various facilities, as well as goodwill for its Texas reporting units, as further described in Item 15 — Note 9, Asset Impairments and Note 10, Goodwill and Other Intangibles, to the Consolidated Financial Statements.

Selling, General and Administrative Expenses



	Retail		Generation		Corporate		Total
	(In millions)
Year Ended December 31, 2018	$	538	$	212	$	49	$	799
Year Ended December 31, 2017	$	452	$	215	$	169	$	836

Selling, general and administrative expenses decreased by $37 million for the year ended December 31, 2018 compared to the same period in 2017.



	(In millions)
Decrease in general and administrative expense from cost initiatives for the Transformation Plan(a)	$	(164	)
Prior year fees associated with advisors engaged to assist the Company in its strategic review in 2017	(22		)
Increase in selling and marketing expenses associated with costs incurred for margin enhancement initiatives	51
Increase in commission expense associated with selling initiatives	32
Increase in costs due to the XOOM acquisition	32
Increase in bad debt expense primarily from increased usage due to weather	18
Increase due to additional litigation in 2018	10
Other	6
	$	(37	)

(a) Approximately $98 million of additional cost savings were achieved in the year ended December 31, 2017, as compared to the year ended December 31, 2016, as the savings became permanent through the Transformation Plan

Reorganization Costs

Reorganization costs, primarily related to severance and contract modifications, increased by $46 million for the year ended December 31, 2018, as compared to the same period in 2017 as the Company continued with the Transformation Plan announced in 2017.

Other Income - Affiliate

Other income - affiliate represents the services fees charged to GenOn for shared services under the Services Agreement through June 14, 2017, the date of deconsolidation of $87 million.

Gain on Sale of Assets

Gain on sale of assets for the year ended December 31, 2018, consists primarily of the gain on the sale of BETM and Canal 3, while the gain on sale of assets for the year ended December 31, 2017, represents a gain on the sale of land.

Impairment Losses on Investments

For the year ended December 31, 2018, the Company recorded other-than-temporary impairment losses of $15 million, compared to $79 million in other-than-temporary impairment losses recorded in the same period in 2017, as further described in Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements.

Loss on Debt Extinguishment

A loss on debt extinguishment of $44 million was recorded for the year ended December 31, 2018, primarily driven by the redemption of Senior Notes, due 2022 at a price above par value.

A loss on debt extinguishment of $49 million was recorded for the year ended December 31, 2017, driven by the repurchase of Senior Notes at a price above par value and the write-off of the unamortized debt issuance costs related to the replacement of the 2018 Term Loan Facility with the new 2023 Term Loan Facility.

Income Tax Expense

For the year ended December 31, 2018, NRG recorded income tax expense of $7 million on pre-tax income of $467 million. For the same period in 2017, NRG recorded income tax benefit of $44 million on a pre-tax loss of $1,389 million. The effective tax rate was 1.5% and 3.2% for the years ended December 31, 2018 and 2017, respectively.

For the year ended December 31, 2018, NRG's overall effective tax rate was different than the federal statutory tax rate of 21% primarily due to a tax benefit for the change in valuation allowance, the generation of PTCs from various wind facilities, and establishment of the previously sequestered ATM credit receivable, partially offset by current state tax expense.



	Year Ended December 31,
	2018			2017
	(In millions except as otherwise stated)
Income/(Loss) from continuing operations before income taxes	$	467		$	(1,389	)
Tax at federal statutory tax rate	98			(486		)
State taxes	18			19
Foreign operations	—			2
Tax Act - corporate income tax rate change	—			665
Valuation allowance due to corporate income tax rate change	—			(660		)
Valuation allowance - current period activities	(106		)	455
Impact of non-taxable entity earnings	—			(5		)
Book goodwill impairment	—			30
Permanent differences	7			—
Production tax credits	(7		)	(8		)
Recognition of uncertain tax benefits	1			(5		)
Alternative minimum tax ("AMT") refundable credit	(4		)	(64		)
Other	—			13
Income tax expense/(benefit)	$	7		$	(44	)
Effective income tax rate	1.5		%	3.2		%

The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740, Income Taxes, or ASC 740. These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.

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



	Year Ended December 31,
(In millions)	2018			2017			Change
South Central	$	66		87			$	(21	)
Yield Renewables Platform & Carlsbad	(292		)	(290		)	(2		)
Genon	34			(789		)	823
Loss from discontinued operations, net of tax	$	(192	)	$	(992	)	$	800

For the year ended December 31, 2018, NRG recorded a loss from discontinued operations, net of income tax of $192 million, a decrease of $800 million in losses from discontinued operations, net of income tax for the same period in 2017, as further described in Item 15 — Note 3 Acquisitions, Discontinued Operations and Dispositions .

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests was $0 million for the year ended December 31, 2018, compared to $184 million for the year ended December 31, 2017. For the years ended December 31, 2018, and 2017, the net losses attributable to noncontrolling interests primarily reflect losses allocated to tax equity investors using the hypothetical liquidation at book value, or HLBV, method, offset in whole and in part by NRG Yield, Inc.'s share of income for the periods, respectively. As a result of the disposition of NRG Yield Inc. and its Renewables Platform, the Company did not have material actuals in 2018 nor does it anticipate material NCI in the future.

Consolidated Results of Operations for the years ended December 31, 2017 and 2016

The following table provides selected financial information for the Company:



	Year Ended December 31,
(In millions except otherwise noted)	2017			2016			Change
Operating Revenues
Energy revenue (a)	$	1,636		$	2,269		$	(633	)
Capacity revenue (a)	612			637			(25		)
Retail revenue	6,378			6,368			10
Mark-to-market for economic hedging activities	252			(636		)	888
Contract amortization	(1		)	(1		)	—
Other revenues (b)	197			278			(81		)
Total operating revenues	9,074			8,915			159
Operating Costs and Expenses
Cost of sales (a)	5,432			5,562			130
Mark-to-market for economic hedging activities	46			(508		)	(554		)
Contract and emissions credit amortization (c)	34			40			6
Operations and maintenance	1,097			1,325			228
Other cost of operations	277			257			(20		)
Total cost of operations	6,886			6,676			(210		)
Depreciation and amortization	596			756			160
Impairment losses	1,534			483			(1,051		)
Selling, general and administrative	836			1,032			196
Reorganization costs	44			—			(44		)
Development costs	22			48			26
Total operating costs and expenses	9,918			8,995			(923		)
Other income - affiliate	87			193			(106		)
Gain/(loss) on sale of assets	16			(80		)	96
Operating (Loss)/Income	(741		)	33			(774		)
Other Income/(Expense)
Equity in losses of unconsolidated affiliates	(14		)	(18		)	4
Impairment losses on investments	(79		)	(268		)	189
Other income, net	51			47			4
Loss on debt extinguishment	(49		)	(142		)	93
Interest expense	(557		)	(583		)	26
Total other expense	(648		)	(964		)	316
Loss from Continuing Operations Before Income Taxes	(1,389		)	(931		)	(458		)
Income tax (benefit)/expense	(44		)	25			69
Net Loss from Continuing Operations	(1,345		)	(956		)	(389		)
(Loss)/income from discontinued operations, net of tax	(992		)	65			(1,057		)
Net Loss	(2,337		)	(891		)	(1,446		)
Less: Net loss attributable to noncontrolling interests and redeemable noncontrolling interests	(184		)	(117		)	(67		)
Net Loss Attributable to NRG Energy, Inc.	$	(2,153	)	$	(774	)	$	(1,379	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	3.11		$	2.46		26		%


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


(b)	Includes unrealized trading gains and losses


(c)	Includes amortization of SO2 and NOx credits and excludes amortization of RGGI

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

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.



	Year Ended December 31, 2017
				Generation
(In millions except otherwise noted)	Retail			Texas			East/West/Other(a)			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	1,427		$	1,298		$	2,725		$	(1,089	)	$	1,636
Capacity revenue	—			22			596			618			(6		)	612
Retail revenue	6,374			—			—			—			4			6,378
Mark-to-market for economic hedging activities	(4		)	94			(57		)	37			219			252
Contract amortization	(1		)	—			—			—			—			(1		)
Other revenue	—			35			200			235			(38		)	197
Operating revenue	6,369			1,578			2,037			3,615			(910		)	9,074
Cost of fuel	(13		)	(732		)	(542		)	(1,274		)	1			(1,286		)
Other costs of sales(b)	(4,759		)	(137		)	(370		)	(507		)	1,120			(4,146		)
Mark-to-market for economic hedging activities	181			(21		)	13			(8		)	(219		)	(46		)
Contract and emission credit amortization	—			(30		)	(4		)	(34		)	—			(34		)
Gross margin	$	1,778		$	658		$	1,134		$	1,792		$	(8	)	$	3,562
Less: Mark-to-market for economic hedging activities, net	177			73			(44		)	29			—			206
Less: Contract and emission credit amortization, net	(1		)	(30		)	(4		)	(34		)	—			(35		)
Economic gross margin	$	1,602		$	615		$	1,182		$	1,797		$	(8	)	$	3,391
Business Metrics
MWh sold (thousands)				42,662			27,923
MWh generated (thousands)				38,694			21,338
(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits



	Year Ended December 31, 2016
				Generation
(In millions except otherwise noted)	Retail			Texas			East/West/Other(a)			Subtotal			Corporate/Eliminations			Total
Energy revenue	$	—		$	1,705		$	1,538		$	3,243		$	(974	)	$	2,269
Capacity revenue	—			18			624			642			(5		)	637
Retail revenue	6,332			—			—			—			36			6,368
Mark-to-market for economic hedging activities	(1		)	(543		)	(22		)	(565		)	(70		)	(636		)
Contract amortization	(1		)	—			—			—			—			(1		)
Other revenue	—			48			265			313			(35		)	278
Operating revenue	6,330			1,228			2,405			3,633			(1,048		)	8,915
Cost of fuel	(8		)	(704		)	(566		)	(1,270		)	—			(1,278		)
Other costs of sales(b)	(4,675		)	(147		)	(463		)	(610		)	1,001			(4,284		)
Mark-to-market for economic hedging activities	365			67			6			73			70			508
Contract and emission credit amortization	(6		)	(29		)	(5		)	(34		)	—			(40		)
Gross margin	$	2,006		$	415		$	1,377		$	1,792		$	23		$	3,821
Less: Mark-to-market for economic hedging activities, net	364			(476		)	(16		)	(492		)	—			(128		)
Less: Contract and emission credit amortization, net	(7		)	(29		)	(5		)	(34		)	—			(41		)
Economic gross margin	$	1,649		$	920		$	1,398		$	2,318		$	23		$	3,990
Business Metrics
MWh sold (thousands)				42,108			32,625
MWh generated (thousands)				37,676			23,748
(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits

The table below represents the weather metrics for 2017 and 2016:



	Years ended December 31,		Quarter ended December 31,		Quarter ended September 30,		Quarter ended June 30,		Quarter ended March 31,
Weather Metrics	Texas	East/West	Texas	East/West	Texas	East/West	Texas	East/West	Texas	East/West
2017
CDDs(a)	3,068	1,155	311	84	1,568	770	966	281	223	20
HDDs(a)	1,270	3,198	665	1,157	1	33	32	380	572	1,628
2016
CDDs	3,030	1,169	382	71	1,675	806	892	273	82	19
HDDs	1,422	3,190	498	1,145	—	23	47	410	878	1,612
10 year average
CDDs	2,897	1,043	266	67	1,650	705	989	254	88	17
HDDs	1,928	3,504	691	1,227	5	40	64	438	1,025	1,799

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

Retail gross margin and economic gross margin

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



	Years ended December 31,
(In millions except otherwise noted)	2017			2016
Retail revenue	$	6,104		$	6,096
Supply management revenue	187			154
Capacity revenues	83			82
Customer mark-to-market	(4		)	(1		)
Contract amortization	(1		)	(1		)
Operating revenue (a)	6,369			6,330
Cost of sales (b)	(4,772		)	(4,683		)
Mark-to-market for economic hedging activities	181			365
Contract amortization	—			(6		)
Gross margin	$	1,778		$	2,006
Less: Mark-to-market for economic hedging activities, net	177			364
Less: Contract and emission credit amortization	(1		)	(7		)
Economic gross margin	$	1,602		$	1,649
Business Metrics
Mass electricity sales volume (GWh) - Texas	36,169			35,102
Mass electricity sales volume (GWh) - All other regions	6,221			6,764
C&I electricity sales volume (GWh) All regions	20,400			18,906
Natural gas sales volumes (MDth)	3,212			2,166
Average Retail Mass customer count (in thousands)	2,862			2,778
Ending Retail Mass customer count (in thousands)	2,876			2,818


(a)	Includes intercompany sales of $5 million and $4 million in 2017 and 2016, respectively, representing sales from Retail to the Texas region


(b)	Includes intercompany purchases of $1,090 million and $993 million in 2017 and 2016, respectively

Retail gross margin decreased $227 million and retail economic gross margin decreased $47 million for the year ended December 31, 2017, compared to the same period in 2016, due to:



	(In millions)
Lower gross margin due to lower rates to customers driven by customer product, term and mix of $103 million or approximately $1.60 per MWh, partially offset by lower supply cost of $28 million or approximately $0.50 per MWh driven by a decrease in supply costs	$	(75	)
Lower gross margin related to the impact of Hurricane Harvey in 2017, driven by a reduction in load of 200,000 MWh resulting in an impact of $9 million and the unfavorable impact of selling back excess supply along with $7 million of customer relief	(16		)
Lower gross margin due to milder weather conditions in 2017 as compared to 2016 resulting in a reduction in load of 350,000 MWh	(11		)
Higher gross margin driven by higher average customer counts of 85,000 along with higher average usage due to customer mix	55
Decrease in economic gross margin	$	(47	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(186		)
Increase in contract and emission credit amortization	6
Decrease in gross margin	$	(227	)

Generation gross margin and economic gross margin

Generation gross margin was flat and generation economic gross margin decreased $521 million, both of which include intercompany sales, during the year ended December 31, 2017, compared to the same period in 2016.

The tables below describe the change in generation gross margin and generation economic gross margin:

Texas Region



	(In millions)
Lower gross margin due to a 14% decrease in average realized prices due to lower hedged power prices	$	(352	)
Lower gross margin due to lower gas generation driven by the current mothball status of Gregory in Texas	(17		)
Higher gross margin due to a 17% increase in coal generation driven by the timing of planned and unplanned outages	55
Higher gross margin due to a decrease in tolling prices in 2017 offset by the cancellation of the Greens Bayou RMR agreement in 2017	5
Other	4
Decrease in economic gross margin	$	(305	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	549
Decrease in contract and emission credit amortization	(1		)
Increase in gross margin	$	243

East/West Region



	(In millions)
Lower gross margin from commercial optimization activities	$	(63	)
Lower gross margin due to a decrease in generation driven by lower economic generation due to milder weather conditions and the Will County outage partially offset by increased generation at Cottonwood	(43		)
Lower gross margin due to a lower cost of market adjustment for fuel oil inventory	(33		)
Lower gross margin due to lower load contracted prices coupled with slightly lower volumes	(28		)
Lower gross margin by BETM due to higher gains in 2016 on over the counter strategies, offset in small part by higher gains in 2017 congestion strategies	(20		)
Lower gross margin due to lower capacity bi-lateral margins in 2017	(11		)
Lower gross margins due to the sale of certain renewable assets in 2017	(10		)
Lower gross margin at Agua driven by lower sales volumes resulting from weather and outages in 2017	(5		)
Lower gross margins due to higher business interruption proceeds from Cottonwood in 2016 offset by Ivanpah proceeds in 2017	(4		)
Other	1
Decrease in economic gross margin	$	(216	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(28		)
Increase in contract and emission credit amortization	1
Decrease in gross margin	$	(243	)

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results increased by $334 million in the year ended December 31, 2017, compared to the same period in 2016.

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



	Year Ended December 31, 2017
				Generation
	Retail			Texas			East/West/Other			Elimination (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	$	(2	)	$	140		$	(72	)	$	64		$	130
Net unrealized (losses)/gains on open positions related to economic hedges	(2		)	(46		)	15			155			122
Total mark-to-market (losses)/gains in operating revenues	$	(4	)	$	94		$	(57	)	$	219		$	252
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(1	)	$	(17	)	$	(1	)	$	(64	)	$	(83	)
Net unrealized gains/(losses) on open positions related to economic hedges	182			(4		)	14			(155		)	37
Total mark-to-market gains/(losses) in operating costs and expenses	$	181		$	(21	)	$	13		$	(219	)	$	(46	)


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

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



	Year Ended December 31, 2016
				Generation
	Retail			Texas			East/West/Other			Elimination (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	$	(3	)	$	(390	)	$	(87	)	$	33		$	(447	)
Net unrealized gains/(losses) on open positions related to economic hedges	2			(153		)	65			(103		)	(189		)
Total mark-to-market losses in operating revenues	$	(1	)	$	(543	)	$	(22	)	$	(70	)	$	(636	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	305		$	27		$	20		$	(33	)	$	319
Reversal of acquired gain positions related to economic hedges.	—			—			(12		)	—			(12		)
Net unrealized gains/(losses) on open positions related to economic hedges	60			40			(2		)	103			201
Total mark-to-market gains in operating costs and expenses	$	365		$	67		$	6		$	70		$	508


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

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

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

For the year ended December 31, 2017, the $252 million gain in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as an increase in value of open positions as a result of decreases in gas prices. The $46 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, partially offset by an increase in the value of open positions as a result of increases in ERCOT heat rate.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 2017 and 2016. The realized and unrealized financial and physical trading results are included in operating revenues. The Company's trading activities are subject to limits within the Company's Risk Management Policy.



	Year Ended December 31,
	2017			2016
	(In millions)
Trading gains/(losses)
Realized	$	43		$	71
Unrealized	(11		)	28
Total trading gains	$	32		$	99

Operations and Maintenance Expense



			Generation				Corporate			Eliminations
	Retail		Texas		East/West/Other				Total
			(In millions)
Year Ended December 31, 2017	$	224	$	387	$	458	$	31		$	(3	)	$	1,097
Year Ended December 31, 2016	$	247	$	434	$	605	$	43		$	(4	)	$	1,325

Operations and maintenance expenses decreased by $228 million for the year ended December 31, 2017, compared to the same period in 2016, due to the following:



	(In millions)
Decrease in operation and maintenance expenses due to major maintenance activities and environmental control work in the East offset by higher variable operating costs	$	(100	)
Decrease in operations and maintenance expenses due to timing of planned outages in Texas	(32		)
Decrease in Retail operations and maintenance expenses due to reduced headcount	(22		)
Decrease in operations and maintenance expenses due to the gain on sale of Jewett Mine dragline in 2017	(18		)
Decrease in operations and maintenance expense due to reductions at Residential Solar	(16		)
Decrease in operations and maintenance expenses due to gain on sale of fixed assets in the East	(15		)
Decrease in operation and maintenance expenses due to a reduction in headcount related to the sale of the engine services business	(10		)
Decrease in operations and maintenance expenses due to the sale of wind assets in 2016 and early 2017	(10		)
Other	(5		)
	$	(228	)

Other cost of operations



			Generation				Corporate
	Retail		Texas		East/West/Other			Total
			(In millions)
Year Ended December 31, 2017	$	99	$	81	$	97	$	—	$	277
Year Ended December 31, 2016	$	93	$	75	$	88	$	1	$	257

Other cost of operations, comprised of asset retirement expense, insurance expense and property tax expense, increased by $20 million for the year ended December 31, 2017, compared to the same period in 2016.

Depreciation and Amortization



			Generation			Corporate
	Retail				Total
	(In millions)
Year Ended December 31, 2017	$	110	$	454		$	32	$	596
Year Ended December 31, 2016	$	114	$	593		$	49	$	756

Depreciation and amortization expense decreased by $160 million for the year ended December 31, 2017, compared to the same period in 2016, primarily due to due to the Jewett Mine being fully depreciated in December 2016 as well as impairments in 2016.

Impairment Losses

In 2017, the Company recorded impairment losses of $1,534 million related to various facilities, as well as goodwill for its Texas reporting unit, as further described in Item 15 — Note 9, Asset Impairments and Note 10, Goodwill and Other Intangibles, to the Consolidated Financial Statements.

In 2016, the Company recorded impairment losses of $483 million related to various facilities, as well as goodwill for its Texas and Home Solar reporting units, as further described in Item 15 - Note 9, Asset Impairments to the Consolidated Financial Statements.

Selling, General and Administrative Expenses



	Retail		Generation		Corporate		Total
	(In millions)
Year Ended December 31, 2017	$	452	$	215	$	169	$	836
Year Ended December 31, 2016	$	498	$	279	$	255	$	1,032

Selling, general and administrative expenses decreased by $196 million(a) for the year ended December 31, 2017 compared to the same period in 2016, primarily due to a reduction in personnel costs and selling and marketing activities as the Company continues to focus on cost management.

Development Costs

Development costs decreased by $26 million for the year ended December 31, 2017, compared to the same period in 2016, due to the strategic decision for a more focused development program primarily related to Renewables and the sale of EVgo in 2016.

Gain/(Loss) on Sale of Assets

Gain on sale of assets for the year ended December 31, 2017, represents a gain on the sale of land. The loss on sale of assets for the year ended December 31, 2016 is primarily due to the loss on sale of the Company's majority interest in its EVgo business to Vision Ridge Partners, which resulted in a loss on sale as described in Item 15 — Note 3, Acquisitions, Discontinued Operations and Dispositions, to the Consolidated Financial Statements.

Impairment Losses on Investments

For the year ended December 31, 2017, the Company recorded impairment losses of $79 million, which is primarily due to impairments on the Company's interests in Petra Nova Parish Holdings as well as as impairments on other investments as further described in Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements.

For the year ended December 31, 2016, the Company recorded impairment losses on certain of its cost and equity method investments of $270 million, as further described in Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements.

Loss on Debt Extinguishment

A loss on debt extinguishment of $49 million was recorded for the year ended December 31, 2017, primarily driven by the repurchase of Senior Notes at a price above par value and the write-off of the unamortized debt issuance costs related to the replacement of the 2018 Term Loan Facility with the new 2023 Term Loan Facility.

A loss on debt extinguishment of $142 million was recorded for the year ended December 31, 2016, primarily driven by the repurchase of NRG senior notes at a price above par value and the write-off of the unamortized debt issuance costs related to the replacement of the 2018 Term Loan Facility with the new 2023 Term Loan Facility.

Interest Expense

NRG's interest expense decreased by $26 million for the year ended December 31, 2017, compared to the same period in 2016, primarily due to lower debt balances resulting in less interest.

Income Tax Expense

For the year ended December 31, 2017, NRG recorded an income tax benefit of $44 million on a pre-tax loss of $1,389 million. For the same period in 2016, NRG recorded an income tax expense of $25 million on pre-tax loss of $931 million. The effective tax rate was 3.2% and (2.7)% for the years ended December 31, 2017 and 2016, respectively.

For the year ended December 31, 2017, NRG's overall effective tax rate was different than the federal statutory tax rate of 35% primarily due to tax expense recorded from the revaluation of the existing net deferred tax asset and state taxes, partially offset by the change in valuation allowance, establishing the AMT credit receivable and the generation of PTCs from various wind facilities. The tax expense recorded for revaluation of the net deferred tax asset is required to reflect the reduction in the corporate income tax rate from 35% to 21% in accordance with the Tax Act.



	Year Ended December 31,
	2017			2016
	(In millions except as otherwise stated)
Loss from continuing operations before income taxes	$	(1,389	)	$	(931	)
Tax at federal statutory tax rate	(486		)	(326		)
State taxes	19			—
Foreign operations	2			10
Tax Act - corporate income tax rate change	665			—
Valuation allowance due to corporate income tax rate change	(660		)	—
Valuation allowance - current period activities	455			382
Impact of non-taxable entity earnings	(5		)	22
Book goodwill impairment	30			—
Net interest accrued on uncertain tax positions	—			1
Production tax credits	(8		)	(7		)
Recognition of uncertain tax benefits	(5		)	2
Impact of changes is in effective state	—			(59		)
AMT refundable credit	(64		)	—
Other	13			—
Income tax (benefit)/expense	$	(44	)	$	25
Effective income tax rate	3.2		%	(2.7		)%

The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740. These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.

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



	Year Ended December 31,
(In millions)	2017			2016			Change
South Central	$	87		$	72		$	15
Yield Renewables Platform & Carlsbad	(290		)	(99		)	(191		)
Genon	(789		)	92			(881		)
(Loss)/income from discontinued operations, net of tax	$	(992	)	$	65		$	(1,057	)

For the year ended December 31, 2017, NRG recorded a loss from discontinued operations, net of income tax of $992 million, an increase of $1.1 billion in losses from discontinued operations, net of income tax for the same period in 2016, as further described in Item 15 — Note 3 Acquisitions, Discontinued Operations and Dispositions.

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

For the year ended December 31, 2017, NRG recorded loss from discontinued operations, net of income tax of $992 million, of which $359 million was related to operations of GenOn, Carlsbad, NRG Yield Inc. and its Renewables Platform, and the South Central Portfolio and $633 million was related to the loss, fees and other expenses associated with the dispositions.

For the year ended December 31, 2016, NRG recorded income from discontinued operations, net of income tax of $65 million which was related to operations of GenOn, NRG Yield Inc. and its Renewables Platform, and the South Central Portfolio.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests was $184 million for the year ended December 31, 2017, compared to $117 million for the year ended December 31, 2016. For the years ended December 31, 2017 and 2016, the net losses attributable to noncontrolling interests primarily reflect losses allocated to tax equity investors using the hypothetical liquidation at book value, or HLBV method.

Liquidity and Capital Resources

Liquidity Position

As of December 31, 2018 and 2017, NRG's liquidity, excluding collateral funds deposited by counterparties, was approximately $2.0 billion and $2.8 billion, respectively, comprised of the following:



	As of December 31,
	2018		2017
	(In millions)
Cash and cash equivalents:	$	563	$	770
Restricted cash - operating	6		85
Restricted cash - reserves (a)	11		194
Total	580		1,049
Total credit facility availability	1,397		1,711
Total liquidity, excluding collateral funds deposited by counterparties	$	1,977	$	2,760


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

For the year ended December 31, 2018, total liquidity, excluding collateral funds deposited by counterparties, decreased by $783 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at December 31, 2018 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common stockholders, and to fund other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

Credit Ratings

On December 6, 2018, Moody's upgraded the NRG corporate family rating to Ba2 and senior unsecured rating to Ba3 with positive outlook. The rating agency also affirmed the company's senior secured rating at Baa3.

On September 10, 2018, S&P upgraded its issuer credit rating to BB with a stable outlook. At the same time they raised the issue-level secured and unsecured ratings to BBB and BB respectively.

The following table summarizes the Company's current credit ratings:



	S&P	Moody's
NRG Energy, Inc.	BB Stable	Ba2 Positive
6.25% Senior Notes, due 2024	BB	Ba3
7.25% Senior Notes, due 2026	BB	Ba3
6.625% Senior Notes, due 2027	BB	Ba3
5.75% Senior Notes, due 2028	BB	Ba3
Term Loan Facility, due 2023	BBB-	Baa3

Sources of Liquidity

The principal sources of liquidity for NRG's 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 Item 15 — Note 11, Debt and Capital Leases, to the Consolidated Financial Statements, the Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes, and project-related financings.

Asset Sale Proceeds

The table below represents the approximate purchase price received from sale transactions and related financings completed by the Company during the year ended December 31, 2018.



Sales	Cash Proceeds (in millions)
NRG Yield, Inc and Renewables Platform	$	1,348
Buckthorn Solar (a)	42
UPMC Thermal Project (a)	84
BETM	70
Canal 3(b)	167
Other Sales	12
Completed sales transactions as of December 31, 2018	$	1,723

(a) Sale of assets to NRG Yield, Inc., prior to discontinued operations

(b) In addition to cash proceeds from sale, amount includes $151 million related to a financing arrangement prior to the sale

The table below represents the cash proceeds received from sales transactions, excluding working capital or other adjustments, completed by the Company by February 28, 2019.



Expected Sales	Close Date	Cash Proceeds (in millions)
South Central Portfolio	February 4, 2019	$	1,000
Carlsbad	February 27, 2019	387
Cash proceeds from sales transactions in 2019		$	1,387

2048 Convertible Senior Notes Issuance

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

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the EME (including Midwest Generation) acquisitions and NRG's assets that have project-level financing. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or gas used as a proxy for power. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have claim under the first lien program. The first lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity and 10% of its other assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of December 31, 2018, 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 December 31, 2018:



Equivalent Net Sales Secured by First Lien Structure (a)	2019		2020		2021		2022
In MW	596		831		712		743
As a percentage of total net coal and nuclear capacity (b)	13	%	18	%	16	%	16	%


(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, as described more fully in Item 15 — Note 11, Debt and Capital Leases, to the Consolidated Financial Statements; (iii) capital expenditures, including repowering development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, return of capital and dividend payments to stockholders, as described in Item 15 — Note 14, Capital Structure, to the Consolidated Financial Statements.

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 (e.g. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of December 31, 2018, commercial operations had total cash collateral outstanding of $287 million and $793 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of December 31, 2018, total collateral held from counterparties was $33 million in cash and $108 million of letters of credit.

Future liquidity requirements may change based on the Company's hedging activities and structures, power purchases and sales, 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.

2023 Term Loan Facility

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

In accordance with the terms of the credit agreement, upon the consummation of the sales of the South Central Portfolio and Carlsbad, the Company will initiate asset sale offers to purchase a portion of its Term Loan. The Company has one year from the date of each sale to initiate the offer.

Senior Note Repurchases in 2018

During the year ended December 31, 2018, the Company redeemed $1.1 billion in aggregate principal of its Senior Notes for $1.1 billion, which included accrued interest of $14 million. In connection with the redemptions, a $38 million loss on debt extinguishment was recorded in 2018, which included the write-off of previously deferred financing costs of $7 million.



	Principal Repurchased		Cash Paid (a)		Average Early Redemption Percentage
In millions, except percentages
5.750% senior notes due 2028	$	29	$	30	99.24	%
6.250% senior notes due 2022	14		15		103.25	%
Total at June 30, 2018	$	43	$	45
6.250% senior notes due 2022	493		512		103.13	%
5.750% senior notes due 2028	20		20		99.13	%
6.625% senior notes due 2027	20		21		103.06	%
Total at September 30, 2018	$	576	$	598
6.250% senior notes due 2022	485		508		103.13	%
Total at December 31, 2018	$	1,061	$	1,106

(a) Includes accrued interest of $14 million

Senior Note Redemptions in 2017

During the year ended December 31, 2017, the Company redeemed $1.5 billion in aggregate principal of its Senior Notes for $1.5 billion, which included accrued interest of $29 million. In connection with the redemptions, a $49 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $7 million.



	Principal Repurchased		Cash Paid (a)		Average Early Redemption Percentage
Amount in millions, except percentages
7.625% senior notes due 2018	$	398	$	411	101.42	%
7.875% senior notes due 2021	206		218		102.63	%
6.625% senior notes due 2023	869		915		103.57	%
Total	$	1,473	$	1,544

(a) Includes accrued interest of $29 million

Debt Service Obligations

Principal payments on debt and capital leases as of December 31, 2018 are due in the following periods:



Description	2019		2020		2021		2022		2023		Thereafter		Total
	(In millions)
Recourse Debt:
Senior notes, due 2024	$	—	$	—	$	—	$	—	$	—	$	733	$	733
Senior notes, due 2026	—		—		—		—		—		1,000		1,000
Senior notes, due 2027	—		—		—		—		—		1,230		1,230
Senior notes, due 2028	—		—		—		—		—		821		821
Convertible Senior Notes, due 2048	—		—		—		—		—		575		575
Term loan facility, due 2023	17		18		17		17		1,629		—		1,698
Tax-exempt bonds	—		—		—		—		—		466		466
Subtotal Recourse Debt	17		18		17		17		1,629		4,825		6,523
Non-Recourse Debt:
Agua Caliente Borrower 1, due 2038	3		3		3		3		2		72		86
Midwest Generation, due 2019	48		—		—		—		—		—		48
Other	6		5		6		5		4		8		34
Subtotal Non-Recourse Debt	57		8		9		8		6		80		168
Subtotal long-term debt	74		26		26		25		1,635		4,905		6,691
Capital Leases:
Capital leases	—		—		1		—		—		—		1
Subtotal Capital Leases	—		—		1		—		—		—		1
Total Debt and Capital Leases	$	74	$	26	$	27	$	25	$	1,635	$	4,905	$	6,692

In addition to the debt and capital leases shown in the above table, NRG had issued $1.0 billion of letters of credit under the Company's $2.4 billion Revolving Credit Facility as of December 31, 2018.

Capital Expenditures

The following table and descriptions summarize the Company's capital expenditures for maintenance, environmental, and growth investments, for the year ended December 31, 2018, and the estimated capital expenditure and growth investments forecast for 2019.



	Maintenance		Environmental		Growth Investments			Total
	(In millions)
Retail	$	19	$	—	$	71		$	90
Generation
Texas	77		—		—			77
East/West/Other (a)	54		1		135			190
Corporate	9		—		22			31
Total cash capital expenditures for the year ended December 31, 2018	159		1		228			388
Funding from debt financing, net of fees	—		—		(118		)	(118		)
XOOM acquisition and integration	—		—		208			208
Other investments(b)	—		—		176			176
Total capital expenditures and investments, net of financings	$	159	$	1	$	494		$	654

Estimated capital expenditures for 2019	$	155	$	3	$	65		$	223

(a) Includes International, Renewables and Cottonwood

(b) Other investments include restricted cash activity and acquisitions


•	Growth Investments capital expenditures — For the year ended December 31, 2018, the Company's growth investment capital expenditures included $134 million for repowering Canal 3, and $94 million for the Company's other growth projects.

Environmental Capital Expenditures Estimate

NRG estimates that environmental capital expenditures from 2019 through 2023 required to comply with environmental laws will be approximately $35 million. These costs are primarily associated with the cost of adding NOx controls in Connecticut.

The table below summarizes the status of NRG's coal fleet with respect to air quality controls. Planned investments are either in construction or budgeted in the existing capital expenditures budget. Changes to regulations could result in changes to planned installation dates. NRG uses an integrated approach to fuels, controls and emissions markets to meet environmental standards.



		SO2		NOx		Mercury		Particulate
Units	State	Control Equipment	Install Date	Control Equipment	Install Date	Control Equipment	Install Date	Control Equipment	Install Date
Indian River 4	DE	CDS	2011	LNBOFA/SCR	1999/2011	ACI/CDS/FF	2008/2011	ESP/FF	1980/2011
Joliet 6, 7, 8	IL	Gas Conversion	2016	OFA	2016	Gas Conversion	2016	Gas Conversion	2016
Limestone 1-2	TX	FGD	1985-86	LNBOFA	2002/2022	ACI	2015	ESP	1985-1986
Powerton 5	IL	DSI	2016	OFA/SNCR	2003/2012	ACI	2009	ESP/upgrade	1973/2016
Powerton 6	IL	DSI	2014	OFA/SNCR	2002/2012	ACI	2009	ESP/upgrade	1976/2014
W.A. Parish 5, 6, 7	TX	FF co-benefit	1988	SCR	2004	ACI	2015	FF	1988
W.A. Parish 8	TX	FGD	1982	SCR	2004	ACI	2015	FF	1988
Waukegan 7	IL	DSI	2014	LNBOFA	2002	ACI	2008	ESP/upgrade	1958/2002, 2014
Waukegan 8	IL	DSI	2015	LNBOFA	1999	ACI	2008	ESP/upgrade	1962/1999, 2015
Will County 4	IL	DSI	2017	LNBOFA/SNCR	1999,2001/ 2012	ACI	2009	ESP/upgrade	1963,72/ 2000



ACI - Activated Carbon Injection CDS - Circulating Dry Scrubber DSI - Dry Sorbent Injection with Trona ESP - Electrostatic Precipitator FGD - Flue Gas Desulfurization (wet)	FF- Fabric Filter LNBOFA - Low NOx Burner with Overfire Air OFA - Overfire Air SCR - Selective Catalytic Reduction SNCR - Selective Non-Catalytic Reduction

The following table summarizes the estimated environmental capital expenditures for the referenced periods by region:



	Texas		East/West		Total
	(In millions)
2019	$	1	$	2	$	3
2020	8		5		13
2021	3		8		11
2022	4		4		8
2023	—		—		—
Total	$	16	$	19	$	35

Common Stock Dividends

The Company returned $37 million of capital to shareholders in the year ended 2018 through a $0.12 dividend per common share.

On January 23, 2019, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, or $0.12 per share on an annualized basis, payable on February 15, 2019, to stockholders of record as of February 1, 2019. The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws and regulations.

Share Repurchases

In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its common stock. During the year ended December 31, 2018, the Company repurchased a total of 35,234,664 shares under these programs for $1.25 billion, and the remaining $250 million was repurchased by February 28, 2019. The average price paid per share for the $1.5 billion share repurchase was $36.24. In addition, the Company's board of directors authorized in February 2019 an additional $1 billion share repurchase program to be executed in 2019. See Note 14, Capital Structure, for additional discussion.

Targeted Debt Reduction

NRG is revising 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.

Small Book Acquisitions

During 2018, the Company has acquired several books of customers totaling approximately 115,000 customers, along with brand names, for $44 million.

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.

Cash Flow Discussion

2018 compared to 2017

The following table reflects the changes in cash flows for the comparative years:



	Year ended December 31,
(In millions)	2018			2017			Change
Net cash provided by operating activities	$	1,377		$	1,610		$	(233	)
Net cash used by investing activities	(205		)	(639		)	434
Net cash used by financing activities	(1,526		)	(1,138		)	(388		)

Net Cash Provided By Operating Activities

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



	(In millions)
Change in cash from discontinued operations	$	(380	)
Decrease in inventory during 2017 as a result of initiatives related to the Transformation Plan to reduce inventory levels	(112		)
GenOn settlement payment in July 2018, net of insurance proceeds received in December 2018	(63		)
Changes in cash collateral in support of risk management activities due to changes in commodity prices	(25		)
Increase in operating income adjusted for non-cash items	323
Increase in working capital in 2018 as a result of initiatives related to the Transformation Plan to increase working capital	24
	$	(233	)

Net Cash Used By Investing Activities

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



	(In millions)
Increase in proceeds from sale of assets and sale of discontinued operations	$	1,134
Change in cash from discontinued operations	254
Decrease in net investments in unconsolidated affiliates	18
Cash removed due to deconsolidation of Agua Caliente and Ivanpah in 2018	(268		)
Increase in cash paid for acquisitions in 2018, primarily for the XOOM acquisition	(229		)
Decrease in net distributions received from discontinued operations	(210		)
Increase in capital expenditures for growth investments and maintenance in generation assets	(134		)
Increase in investments in nuclear decommissioning trust net of proceeds from sales	(48		)
Decrease in sales of emissions, net of purchases	(47		)
Decrease in insurance proceeds received in 2018	(22		)
Decrease in cash grants received in 2018	(8		)
Other	(6		)
	$	434

Net Cash Used By Financing Activities

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



	(In millions)
Repurchases of common stock in 2018, from open market repurchases and the ASR agreement	$	(1,250	)
Decrease in proceeds from issuance of long-term debt	(68		)
Change in cash from discontinued operations	640
Decrease in payments for short and long-term debt	150
Decrease in notes issued to affiliates	99
Increase in cash received from issuance of stock due to exercise of employee share-based compensation	21
Decrease in net distributions paid to noncontrolling interests from subsidiaries	14
Other	6
	$	(388	)

2017 compared to 2016

The following table reflects the changes in cash flows for the comparative years:



	Year ended December 31,
(In millions)	2017			2016			Change
Net cash provided by operating activities	$	1,610		$	1,908		$	(298	)
Net cash used by investing activities	(639		)	(757		)	118
Net cash used by financing activities	(1,138		)	(768		)	(370		)

Net Cash Provided By Operating Activities

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



	(In millions)
Changes in cash collateral in support of risk management activities due to changes in commodity prices	$	(476	)
Other changes in working capital	(121		)
Decrease in operating income adjusted for non-cash items	(67		)
Decrease in inventory as a result of initiatives related to the Transformation Plan to reduce inventory levels in 2017 as compared to 2016	83
Change in cash from discontinued operations	283
	$	(298	)

Net Cash Used By Investing Activities

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



	(In millions)
Decrease in capital expenditures in 2017	$	290
Increase in proceeds from sale of assets	189
Increase due to net distributions received from discontinued operations	208
Increase in sales of emissions, net of purchases	67
Increase in investments in nuclear decommissioning trust net of proceeds from sales	30
Change in cash from discontinued operations, primarily due to increased capital expenditures in 2017 and asset sales in 2016	(591		)
Decrease in cash grants received in 2017	(28		)
Increase due to net contributions to unconsolidated affiliates	(24		)
Other	(23		)
	$	118

Net Cash Used By Financing Activities

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



	(In millions)
Decrease in payments for short and long-term debt primarily due to repurchases of Senior Notes in 2016	$	3,262
Change due to repurchase of preferred stock in 2016	226
Decrease in debt extinguishment costs	79
Decrease in deferred debt issuance costs	43
Decrease in payment of dividends, due to the annualized dividend rate being reduced from $0.58/share to $0.12/share in the first quarter of 2016	38
Decrease in borrowings primarily related to Agua Caliente borrowings in 2016	(3,234		)
Change in cash from discontinued operations	(652		)
Decrease due to payment notes issued to affiliates in 2017	(125		)
Other	(7		)
	$	(370	)

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

As of December 31, 2018, the Company had domestic pre-tax book income of $468 million and a foreign pre-tax book loss of $1 million. For the year ended December 31, 2018, the Company generated an NOL of $8.0 billion due to a current year taxable loss. As of December 31, 2018, the Company has cumulative domestic federal NOL carryforwards of $10.7 billion, which will begin expiring in 2031 and cumulative state NOL carryforwards of $5.6 billion. 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 indefinite carryforward for interest deductions, as well as $381 million of tax credits to be utilized in future years. As a result of the Company's tax position, including the benefit of $9.6 billion of tax losses and worthless stock deduction upon GenOn emerging from bankruptcy, and based on current forecasts, the Company anticipates income tax payments, primarily due to state and local jurisdictions, of up to $20 million in 2019.

The Company has recorded short-term and long-term receivables of $35 million and $34 million, respectively, representing refundable AMT credits from the IRS, which are anticipated to be received from 2019 through 2022 pursuant to the 50% annual limitation as enacted by the Tax Act upon repeal of corporate AMT effective January 1, 2018. Of this amount, short-term and long-term payables of $11 million each are due to GenOn for their share of minimum tax credits.

In addition to these amounts, the Company has $26 million of tax effected uncertain state tax benefits for which the Company has recorded a non-current tax liability of $30 million (including accrued interest) until such final resolution with the related taxing authority.

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. See also Item 15 — Note 25 Guarantees, to the Consolidated Financial Statements for additional discussion.

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 December 31, 2018, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. One of these investments is considered a variable interest entity for which NRG is not the primary beneficiary.

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $992 million as of December 31, 2018. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Item 15 — Note 15, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Consolidated Financial Statements for additional discussion.

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. The following tables summarize NRG's contractual obligations and contingent obligations for guarantees. See also Item 15 — Note 11, Debt and Capital Leases, Note 21, Commitments and Contingencies, and Note 25, Guarantees, to the Consolidated Financial Statements for additional discussion.



	By Remaining Maturity at December 31,
	2018
Contractual Cash Obligations	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total (a)		2017 Total
	(In millions)
Long-term debt (including estimated interest)	$	464	$	807	$	2,349	$	6,520	$	10,140	$	13,895
Capital lease obligations (including estimated interest)	—		1		—		—		1		5
Operating leases	61		102		91		317		571		675
Fuel purchase and transportation obligations	227		278		129		209		843		1,335
Fixed purchased power commitments	30		25		12		1		68		68
Pension minimum funding requirement (b)	39		53		82		79		253		205
Other postretirement benefits minimum funding requirement (c)	7		13		12		25		57		74
Other liabilities (d)	32		62		43		144		281		296
Total	$	860	$	1,341	$	2,718	$	7,295	$	12,214	$	16,553


(a)	Excludes $26 million non-current payable relating to NRG's uncertain tax benefits under ASC 740 as the period of payment cannot be reasonably estimated. Also excludes $679 million of asset retirement obligations which are discussed in Item 15 — Note 12 , Asset Retirement Obligations, to the Consolidated Financial Statements


(b)	These amounts represent the Company's estimated minimum pension contributions required under the Pension Protection Act of 2006. These amounts represent estimates that are based on assumptions that are subject to change


(c)	These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 2027 are currently not available


(d)	Includes water right agreements, service and maintenance agreements, stadium naming rights, LTSA commitments and other contractual obligations



	By Remaining Maturity at December 31,
	2018
Guarantees	Under 1 Year		1-3 Years		3-5 Years		Over 5 Years		Total		2017 Total
	(In millions)
Letters of credit and surety bonds(a)(b)	$	1,138	$	79	$	—	$	36	$	1,253	$	1,003
Asset sales guarantee obligations	—		4		257		532		793		312
Other guarantees	—		105		—		616		721		645
Total guarantees	$	1,138	$	188	$	257	$	1,184	$	2,767	$	1,960


(a)	As of December 31, 2017 excludes $92 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn


(b)	December 31, 2018 includes $32 million of letter of credit and surety bonds for the benefit of GenOn where NRG holds cash or letter of credit to back stop the liability

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 debt, NRG enters into interest rate swap agreements.

NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

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 December 31, 2018, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2018. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Item 15 — Note 4, Fair Value of Financial Instruments, to the Consolidated Financial Statements.



Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2017	$	103
Contracts realized or otherwise settled during the period	(99		)
Contracts acquired during the period	11
Changes in fair value	89
Fair value of contracts as of December 31, 2018	$	104



	Fair Value of Contracts as of December 31, 2018
	Maturity
Fair value hierarchy (Losses)/Gains	1 Year or Less			Greater Than 1 Year to 3 Years			Greater Than 3 Years to 5 Years			Greater Than 5 Years			Total Fair Value
	(In millions)
Level 1	$	(58	)	$	(25	)	$	(4	)	$	—		$	(87	)
Level 2	106			79			(1		)	(13		)	171
Level 3	43			(1		)	(4		)	(18		)	20
Total	$	91		$	53		$	(9	)	$	(31	)	$	104

The Company has elected to disclose 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 posted 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 7A — Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, 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 assets and liability position is a better indicator of NRG's hedging activity. As of December 31, 2018, NRG's net derivative asset was $104 million, an increase to total fair value of $1 million as compared to December 31, 2017. This increase was primarily driven by gains in fair value and contracts acquired during the period, largely offset by roll off trades that were 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 $230 million in the net value of derivatives as of December 31, 2018.

The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result in an increase of approximately $221 million in the net value of derivatives as of December 31, 2018.

Critical Accounting Policies and Estimates

NRG's discussion and analysis of the financial condition and results of operations are based upon the Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies 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 have 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.

NRG's significant accounting policies are summarized in Item 15 — Note 2, Summary of Significant Accounting Policies, to the consolidated financial statements. 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.




Accounting Policy	Judgments/Uncertainties Affecting Application
Derivative Instruments	Assumptions used in valuation techniques
	Assumptions used in forecasting generation
	Assumptions used in forecasting borrowings
	Market maturity and economic conditions
	Contract interpretation
	Market conditions in the energy industry, especially the effects of price volatility on contractual commitments
Income Taxes and Valuation Allowance for Deferred Tax Assets	Ability to be sustained upon audit examination of taxing authorities
	Interpret existing tax statute and regulations upon application to transactions
	Ability to utilize tax benefits through carry backs to prior periods and carry forwards to future periods
Impairment of Long-Lived Assets and Investments	Recoverability of investment through future operations
	Regulatory and political environments and requirements
	Estimated useful lives of assets
	Environmental obligations and operational limitations
	Estimates of future cash flows
	Estimates of fair value
	Judgment about impairment triggering events
Goodwill and Other Intangible Assets	Estimated useful lives for finite-lived intangible assets
	Judgment about impairment triggering events
	Estimates of reporting unit's fair value
	Fair value estimate of intangible assets acquired in business combinations
Contingencies	Estimated financial impact of event(s)
	Judgment about likelihood of event(s) occurring
	Regulatory and political environments and requirements

Derivative Instruments

The Company follows the guidance of ASC 815 to account for derivative instruments. ASC 815 requires the Company to mark-to-market all derivative instruments on the balance sheet and recognize changes in the fair value of non-hedge derivative instruments immediately in earnings. In certain cases, NRG may apply hedge accounting to the Company's derivative instruments. The criteria used to determine if hedge accounting treatment is appropriate are: (i) the designation of the hedge to an underlying exposure; (ii) whether the overall risk is being reduced; and (iii) if there is a correlation between the changes in fair value of the derivative instrument and the underlying hedged item. Changes in the fair value of derivatives instruments accounted for as hedges are deferred and recorded as a component of OCI and subsequently recognized in earnings when the hedged transactions occur.

For purposes of measuring the fair value of derivative instruments, NRG uses quoted exchange prices and broker quotes. When external prices are not available, NRG uses internal models to determine the fair value. These internal models include assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. In order to qualify the derivative instruments for hedged transactions, NRG estimates the forecasted borrowings for interest rate swaps occurring within a specified time period. Judgments related to the probability of forecasted borrowings are based on the estimated timing of project construction, which can vary based on various factors. The probability that forecasted borrowings will occur by the end of a specified time period could change the results of operations by requiring amounts currently classified in OCI to be reclassified into earnings, creating increased variability in the Company's earnings. These estimations are considered to be critical accounting estimates.

Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered to be NPNS. The availability of this exception is based upon the assumption that NRG has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are based on available baseload capacity, internal forecasts of sales and generation and historical physical delivery on contracts. Derivatives that are considered to be NPNS are exempt from derivative accounting treatment and are accounted for under accrual accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related contract would be recorded on the balance sheet at fair value combined with the immediate recognition through earnings.

Income Taxes and Valuation Allowance for Deferred Tax Assets

As of December 31, 2018, NRG had a valuation allowance of $3.8 billion. This amount is comprised of domestic federal net deferred tax assets of approximately $3.3 billion, domestic state net deferred tax assets of $454 million, foreign net operating loss carryforwards of $62 million and foreign capital loss carryforwards of approximately $1 million. The Company believes it is more likely than not that the results of future operations will not generate sufficient taxable income which includes the future reversal of existing taxable temporary differences to realize deferred tax assets, requiring a valuation allowance to be recorded.

NRG continues to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws, including the impact of the Tax Cuts and Jobs Act effective December 22, 2017. 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.

Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value

In accordance with ASC 360, Property, Plant, and Equipment, or ASC 360, NRG evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events are:


•	Significant decrease in the market price of a long-lived asset;


•	Significant adverse change in the manner an asset is being used or its physical condition;


•	Adverse business climate;


•	Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;


•	Current period loss combined with a history of losses or the projection of future losses; and


•	Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold, or disposed of before the end of its previously estimated useful life

Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the different courses of action available to the Company. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. NRG uses its best estimates in making these evaluations and considers various factors, including forward price curves for energy, fuel and operating costs. However, actual future market prices and project costs could vary from the assumptions used in the Company's estimates, and the impact of such variations could be material.

For assets to be held and used, if the Company determines that the undiscounted cash flows from the asset are less than the carrying amount of the asset, NRG must estimate fair value to determine the amount of any impairment loss. Assets held-for-sale are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value under ASC 360, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by their nature, subjective. NRG considers quoted market prices in active markets to the extent they are available. In the absence of such information, the Company may consider prices of similar assets, consult with brokers, or employ other valuation techniques. NRG will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or employ an expected present value method that probability-weights a range of possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in the Company's estimates, and the impact of such variations could be material.

Annually, during the fourth quarter, the Company revises its views of power and fuel prices including the Company's fundamental view for long term prices, forecasted generation and operating and capital expenditures, in connection with the preparation of its annual budget. Changes to the Company's views of long term power and fuel prices impacted the Company’s projections of profitability, based on management's estimate of supply and demand within the sub-markets for its operations and the physical and economic characteristics of each of its businesses. During the fourth quarter of 2018, the Company completed its annual budget and revised its view of long-term power and fuel prices and the corresponding impact on estimated cash flows associated with its long-lived assets. There were no significant changes to the Company's long-term view of natural gas prices despite management's expectation of continued trends towards more renewables and energy storage. There were minimal changes to the long-term view of energy and capacity prices, which did not have a significant negative impact on the Company's coal, nuclear, and renewable facilities.

The following long-lived asset impairment was recorded during 2018, as further described in Item 15 —Note 9, Asset Impairments, to the consolidated financial statements:

Guam— During the fourth quarter of 2018, the Company concluded its wholly-owned subsidiary, NRG Solar Guam, LLC, was held for sale after board approval and advanced negotiations to sell the business. Accordingly, the Company recorded the assets and liabilities at fair market value as of December 31, 2018 based on the contractual sale price, which resulted in an impairment loss of $12 million. The sale was completed on February 20, 2019.

Keystone and Conemaugh — On June 29, 2018, the Company entered into an agreement to sell its approximately 3.7% interests in the Keystone and Conemaugh generating stations. The Company recorded impairment losses of $14 million for Keystone and $14 million for Conemaugh to adjust the carrying amount of the assets to fair value based on the contractual sale price. The transaction closed on September 5, 2018.

Dunkirk — During the second quarter of 2018, NRG ceased its development of the project to add gas capability at the Dunkirk generating station. The project was put on hold in 2015 pending the resolution of a lawsuit filed by Entergy Corporation against the NYPSC, which challenged the legality of its contract with Dunkirk. The lawsuit was later dropped and development continued, but the delay imposed a new requirement on Dunkirk to enter into the NYISO interconnection study process. The NYISO studies have concluded that extensive electric system upgrades would be necessary for the station to return to service. This would cause the Company to incur a material increase in cost and delay the project schedule that would render the project impractical. Consequently, the Company has recorded an impairment loss of $46 million, reducing the carrying amount of the related assets to $0.

Other Impairments — As of December 31, 2018, the Company recorded additional impairment losses of approximately $13 million. These impairment losses were primarily to record the value of certain long-lived assets, including property, plant and equipment and intangible assets, at fair market value at the date of sale or in connection with an impairment indicator.

Equity and Cost Method Investments — NRG is also required to evaluate its equity method and cost method investments to determine whether or not they are impaired in accordance with ASC 323, Investments - Equity Method and Joint Ventures, or ASC 323. The standard for determining whether an impairment must be recorded under ASC 323 is whether a decline in the value is considered an other-than-temporary decline in value. The evaluation and measurement of impairments under ASC 323 involves the same uncertainties as described for long-lived assets that the Company owns directly and accounts for in accordance with ASC 360. Similarly, the estimates that NRG makes with respect to its equity and cost method investments are subjective, and the impact of variations in these estimates could be material. Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of ASC 360, NRG would record its proportionate share of that impairment loss and would evaluate its investment for an other-than-temporary decline in value under ASC 323. During the year ended December 31, 2018, the Company recorded impairment losses on its equity method investments of $15 million due to declines in value.

Goodwill and Other Intangible Assets

At December 31, 2018, NRG reported goodwill of $573 million, consisting of $165 million associated with the acquisition of Midwest Generation and $408 million for retail business acquisitions. The balance of goodwill increased by $34 million in 2018 due to the acquisition of XOOM.

The Company applies ASC 805, Business Combinations, or ASC 805, and ASC 350, to account for its goodwill and intangible assets. Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful lives, while goodwill has an indefinite life and is not amortized. Goodwill is tested for impairment at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company tests goodwill for impairment at the reporting unit level, which is identified by assessing whether the components of the Company's operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components. The Company performs the annual goodwill impairment assessment as of December 31 or when events or changes in circumstances indicate that the carrying value may not be recoverable. The Company first assesses qualitative factors to determine whether it is more likely than not that an impairment has occurred. In the absence of sufficient qualitative factors, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing to its book value. If it is determined that the fair value of a reporting unit is below its carrying amount, where necessary, the Company's goodwill will be impaired at that time.

The Company performed its qualitative assessment of macroeconomic, industry and market events and circumstances, and the overall financial performance of the NRG Business Solutions and Commodity Retail reporting units. The Company determined it was more likely than not that the fair value of the goodwill attributed to these reporting units were more than their carrying amount and accordingly, no impairment existed for the year ended December 31, 2018.

The Company performed a quantitative assessment for the reporting units in the following table. The Company determined the fair value of these reporting units using primarily an income approach. Under the income approach, the Company estimated the fair value of the reporting units' invested capital exceeds its carrying value and, as such, the Company concluded that goodwill associated with the reporting units in the following table is not impaired as of December 31, 2018:



Reporting Unit	% Fair Value Over Carrying Value
Midwest Generation (Generation Segment)	132	%
Texas Non-Commodity (Retail Segment)	135	%

The Company believes the methodology and assumptions used in its quantitative assessment are consistent with the views of market participants. Significant inputs to the determination of fair value were as follows:


•	The Company applied a discounted cash flow methodology to the long-term forecasts for all of the plants in the region. The significant assumptions used to derive the long-term budgets used in the income approach are affected by the following key inputs:

◦

The Company's views of power and fuel prices consider market prices for the first five-year period and the Company's fundamental view for the longer term, driven by the Company's long-term view of the price of natural gas. The Company's fundamental view for the longer term reflects the implied power price and heat rate that would support new build of a combined cycle gas plant. The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants. Hedging is included to the extent of contracts already in place;


◦	The Company's estimate of generation, fuel costs, capital expenditure requirements and the existing and anticipated impact of environmental regulations;


◦	The Company's fundamental view for the longer term, cash flows for the plants in the region were included in the fair value calculation through the end of each plants' estimated useful life; and


◦	Projected generation and resulting energy gross margin in the long-term forecasts is based on an hourly dispatch that simulates dispatch of each unit into the power market. The dispatch simulation is based on power prices, fuel prices, and the physical and economic characteristics of each plant


•	The Company applied a discounted cash flow methodology to the long-term budget for the Texas Non-Commodity reporting unit. The significant assumptions used to derive the long-term budgets used in the income approach are affected by the following key inputs: a terminal value utilizing assumed growth rates and discount rates that reflect the inherent cash flow risk for each reporting unit.

Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment test will prove to be accurate predictions of the future.

Contingencies

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. Gain contingencies are not recorded until management determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. NRG describes in detail its contingencies in Item 15 — Note 21, Commitments and Contingencies, to the consolidated financial statements.

Recent Accounting Developments

See Item 15 — Note 2, Summary of Significant Accounting Policies, to the consolidated financial statements for a discussion of recent accounting developments.

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