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 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 for years ending December 31, 2019 and December 31, 2018, 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 that are most important to both the portrayal of the Company's financial condition and results of operations, and require management's most difficult, subjective or complex judgments.

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, 2019 and 2018, and also refer to Item 1 to this Form 10-K for more detailed discussion about the Company's business. A discussion and analysis of fiscal year 2017 may be found in Part II, Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations of the Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

As further described in Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions, to the Consolidated Financial Statements, the Company determined in prior years that the following businesses were discontinued operations and recast to present their results in the corporate segment:

• South Central Portfolio

• NRG Yield, Inc. and its Renewables Platform

• Carlsbad

• GenOn

Executive Summary

NRG is an integrated power company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to customers by producing and selling electricity and related products and services in major competitive power markets in the U.S. and Canada 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 brand names NRG, Reliant, Green Mountain Energy, Stream and XOOM Energy, as well as other brand names owned by NRG, supported by approximately 23,000 MW of generation as of December 31, 2019.

Business Environment

The industry dynamics and external influences affecting the Company and its businesses, and the power generation and retail energy industry in 2019 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 customers and producers. In 2019, the average natural gas prices at Henry Hub was 15.0% lower than in 2018.

If long-term gas prices increase, the Company is likely to encounter higher realized energy prices, leading to higher energy revenues as lower priced hedge contracts mature and are replaced by contracts with higher gas and power prices. This impact is partially offset by the retail business, as NRG's retail gross margins have historically decreased as natural gas prices increase.

NRG's retail gross margins have historically improved as natural gas prices decline. This would be partially offset by 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. 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 6, 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.

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, 2019 and December 31, 2018. 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 decreased for the year ended December 31, 2019 as compared to the same period in 2018.

			Average On-Peak Power Price ($/MWh)
			Year Ended December 31																								2019 vs 2018
Region			2019						2018									Change %
Texas (a)
ERCOT - Houston(a)			$	51.44					$	37.29								38		%
ERCOT - North(a)			50.80						36.26									40		%
East/West
MISO - Louisiana Hub(b)			30.58						43.70									(30)		%
NY J/NYC(b)			33.73						47.19									(29)		%
NEPOOL(b)			34.89						49.96									(30)		%
COMED (PJM)(b)			28.28						34.60									(18)		%
PJM West Hub(b)			30.85						41.66									(26)		%
CAISO - SP15(b)			38.15						47.33									(19)		%

(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, including the impact of settled hedges, for the years ended December 31, 2019 and December 31, 2018:

			Average Realized Power Price ($/MWh)
			Year Ended December 31																					2019 vs 2018
Region			2019						2018						Change %
Texas			$	46.58					$	37.12					25		%
East/West			35.03						37.00						(5)		%

The average realized power prices for December 31, 2019, as compared to the same period in 2018, increased in Texas as a result of higher power prices, and decreased in 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, continue 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 2019 energy consumption in the ERCOT market was generated from carbon-free resources with wind power contributing 20%. In addition, subsidies and incentives have contributed to the increase in renewable power sources, and customer awareness and preferences have shifted toward sustainable solutions. Increased demand for sustainable energy products from both residential and commercial customers 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, customers 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's operations are typically not exposed to the effects of extreme weather in all parts of its business at once. A significant portion of the Company's business is located within Texas, and extreme weather conditions occurring in Texas may have a material impact on the Company's financial position.

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 25, Environmental Matters, to the Consolidated Financial Statements and Item 1*—* Business, Environmental Matters. Details of regulatory matters are presented in Item 15 — Note 24, Regulatory Matters, to the Consolidated Financial Statements and Item 1*—* Business, Regulatory Matters. Details of legal proceedings are presented in Item 15 — Note 23, 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 has substantially completed its three-year Transformation Plan and expects to fully complete the remaining margin enhancement activities by the end of 2020. The Transformation Plan's targets and the Company's achievements towards such targets are as follows:

Operations and Cost Excellence

The Company targeted 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 2018 and $590 million of cost savings and $135 million of margin enhancements during 2019.

Under the Transformation Plan, by December 31, 2019, the Company fully realized $370 million of non-recurring working capital improvements and $278 million of one-time costs to achieve.

Portfolio Optimization

The Company targeted and completed $3.0 billion of asset sale cash proceeds received through December 31, 2019 as described below:

• In 2017 and 2018, NRG executed asset sales for aggregate cash of $1.6 billion, which includes the sale of its interest in NRG Yield, Inc and its Renewables Platform, BETM, Buckthorn Solar, and various other assets.

• On February 4, 2019, NRG sold the South Central portfolio, a 3,555 MW portfolio of generation assets, for cash consideration of $1.0 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 $385 million, excluding working capital and other adjustments

Capital Structure and Allocation

As of December 31, 2018, the Company achieved the planned credit ratio of 3.0x net debt / adjusted EBITDA(a). During the first quarter of 2019, the Company revised its credit metrics target in order to further strengthen its balance sheet and improve credit ratings by reducing leverage.

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

Other Significant Events

The following additional significant events occurred during 2019:

Stream Energy Acquisition

• On August 1, 2019, the Company completed the acquisition of Stream Energy's retail electricity and natural gas business operating in 9 states and Washington, D.C. for $329 million, including working capital and other adjustments of approximately $29 million. The acquisition increased NRG's retail portfolio by approximately 600,000 RCEs or 450,000 customers.

Financing Activities

*•*On May 14, 2019, NRG issued $733 million of aggregate principal amount at par of 5.25% senior unsecured notes due 2029. The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the remaining Company's $733 million of 6.25% Senior Notes due 2024.

• On May 28, 2019, NRG amended its existing credit agreement to, among other things, provide for a $184 million increase in revolving commitments, resulting in aggregate revolving commitments under the amended credit agreement equal to $2.6 billion. See Note 13, Debt and Finance Leases, for further discussion.

• On May 28, 2019, NRG issued $1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $600 million 3.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, or the Senior Secured Notes, at a discount. The proceeds from the issuance of the Senior Secured Notes, as well as cash on hand, were used to repay the Company's $1.7 billion 2023 Term Loan facility, resulting in a decrease of $594 million to long-term debt outstanding.

Share Repurchases

*•*In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its common stock. $1.25 billion was executed in 2018 with the remaining $0.25 billion completed in the first quarter of 2019.

*•*In 2019, the Company's board of directors authorized the Company to repurchase an additional $1.25 billion of its common stock, which was completed as of February 27, 2020.

Renewable Power Purchase Agreements

• During 2019, NRG began execution of its strategy to procure mid to long-term generation through power purchase agreements. As of December 31, 2019, NRG has entered into PPAs totaling approximately 1,600 MWs with third-party project developers and other counterparties. The tenor of these agreements is an average of ten years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business.

Dividend Increase

• Beginning in the first quarter of 2020, NRG increased the annual dividend to $1.20 per share from $0.12 per share and expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

Valuation Allowance for Net Deferred Tax Assets

• During the year ended December 31, 2019, NRG released the majority of its valuation allowance against its U.S. federal and state deferred tax assets, resulting in a non-cash benefit to income tax expense of approximately $3.5 billion. Refer to Item 15 – Note 20, Income Taxes, to the Consolidated Financial Statements for further discussion of the release in valuation allowance.

Consolidated Results of Operations for the years ended December 31, 2019 and 2018

The following table provides selected financial information for the Company:

			Year Ended December 31,
(In millions, except otherwise noted)			2019						2018						Change
Operating Revenues
Energy revenue (a)			$	1,222					$	1,548					$	(326)
Capacity revenue (a)			607						670						(63)
Retail revenue			7,676						7,105						571
Mark-to-market for economic hedging activities			33						(130)						163
Other revenues (b)			283						285						(2)
Total operating revenues			9,821						9,478						343
Operating Costs and Expenses
Cost of sales (b)			5,878						5,878						—
Mark-to-market for economic hedging activities			53						(144)						(197)
Contract and emissions credit amortization (c)			19						27						8
Operations and maintenance			1,082						1,083						1
Other cost of operations			271						264						(7)
Total cost of operations			7,303						7,108						(195)
Depreciation and amortization			373						421						48
Impairment losses			5						99						94
Selling, general and administrative			827						799						(28)
Reorganization costs			23						90						67
Development costs			7						11						4
Total operating costs and expenses			8,538						8,528						(10)
Gain on sale of assets			7						32						(25)
Operating Income			1,290						982						308
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates			2						9						(7)
Impairment losses on investments			(108)						(15)						(93)
Other income, net			66						18						48
Net loss on debt extinguishment			(51)						(44)						(7)
Interest expense			(413)						(483)						70
Total other expenses			(504)						(515)						11
Income from Continuing Operations Before Income Taxes			786						467						319
Income tax (benefit)/expense			(3,334)						7						(3,341)
Income from Continuing Operations			4,120						460						3,660
Income/(loss) from discontinued operations, net of income tax			321						(192)						513
Net Income			4,441						268						4,173
Less: Net income attributable to noncontrolling interests and redeemable noncontrolling interests			3						—						3
Net Income Attributable to NRG Energy, Inc.			$	4,438					$	268					$	4,170
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)			$	2.63					$	3.09					(15)		%

(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 for the years ended December 31, 2019 and 2018 based on the Company's reporting segments as of December 31, 2019:

			Year Ended December 31, 2019
									Generation
(In millions, except otherwise noted)			Retail						Texas						East/West/Other(a)						Subtotal						Corporate/Eliminations						Total
Energy revenue			$	—					$	1,987					$	733					$	2,720					$	(1,498)					$	1,222
Capacity revenue			—						—						606						606						1						607
Retail revenue			7,680						—						—						—						(4)						7,676
Mark-to-market for economic hedging activities			—						198						36						234						(201)						33
Other revenue			—						90						197						287						(4)						283
Operating revenue			7,680						2,275						1,572						3,847						(1,706)						9,821
Cost of fuel			—						(723)						(384)						(1,107)						(54)						(1,161)
Other costs of sales(b)			(5,821)						(168)						(283)						(451)						1,555						(4,717)
Mark-to-market for economic hedging activities			(267)						10						3						13						201						(53)
Contract and emission credit amortization			—						(19)						—						(19)						—						(19)
Gross margin			$	1,592					$	1,375					$	908					$	2,283					$	(4)					$	3,871
Less: Mark-to-market for economic hedging activities, net			(267)						208						39						247						—						(20)
Less: Contract and emission credit amortization			—						(19)						—						(19)						—						(19)
Economic gross margin			$	1,859					$	1,186					$	869					$	2,055					$	(4)					$	3,910
Business Metrics
MWh sold (thousands)									42,662						20,924
MWh generated (thousands)									37,994						16,375
(a) Includes Renewables and eliminations within Generation
(b) Includes purchased energy, capacity and emissions credits

			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						214						298						(13)						285
Operating revenue			7,103						1,496						1,947						3,443						(1,068)						9,478
Cost of fuel			—						(734)						(557)						(1,291)						(44)						(1,335)
Other costs of sales(c)			(5,308)						(133)						(275)						(408)						1,173						(4,543)
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					$	1,075					$	1,680					$	(18)					$	3,717
Less: Mark-to-market for economic hedging activities, net			253						(172)						(67)						(239)						—						14
Less: Contract and emission credit amortization			—						(26)						(1)						(27)						—						(27)
Economic gross margin			$	1,802					$	803					$	1,143					$	1,946					$	(18)					$	3,730
Business Metrics
MWh sold (thousands)									42,701						24,988
MWh generated (thousands)									38,214						21,089
(a) Includes Renewables and eliminations within Generation
(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

The table below represents the weather metrics for 2019 and 2018:

			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
2019
CDDs(a)			3,115						1,715						266						123						1,840						1,102						934						458						75						32
HDDs(a)			1,868						3,004						757						1,091						—						16						70						283						1,041						1,614
2018
CDDs			3,130						1,793						228						120						1,657						1,099						1,101						521						144						53
HDDs			1,875						2,973						815						1,112						1						18						91						325						968						1,518
10 year average
CDDs			3,053						1,675						266						125						1,672						1,021						1,009						487						106						42
HDDs			1,742						2,946						705						1,068						6						28						60						310						971						1,540

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

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)			2019						2018
Retail revenue			$	7,369					$	6,775
Supply management revenue			215						174
Capacity revenues			96						161
Customer mark-to-market			—						(7)
Operating revenue (a)			7,680						7,103
Cost of sales (b)			(5,821)						(5,308)
Mark-to-market for economic hedging activities			(267)						260
Gross margin			$	1,592					$	2,055
Less: Mark-to-market for economic hedging activities, net			(267)						253
Economic gross margin			$	1,859					$	1,802
Business Metrics
Mass electricity sales volume (GWh) - Texas			38,958						37,846
Mass electricity sales volume (GWh) - All other regions			9,918						7,968
C&I electricity sales volume (GWh) All regions (b)			20,190						21,176
Natural gas sales volumes (MDth)			23,359						11,253
Average Retail Mass customer count (in thousands)			3,470						3,063
Ending Retail Mass customer count (in thousands)			3,678						3,320

(a)Includes intercompany sales of $4 million and $5 million in 2019 and 2018, respectively, representing sales from Retail to the Texas region of Generation

(b)Includes intercompany purchases of $1,554 million and $1,163 million in 2019 and 2018, respectively

Retail gross margin decreased $463 million and retail economic gross margin increased $57 million for the year ended December 31, 2019, compared to the same period in 2018, due to:

			(In millions)
Lower gross margin due to weather driven by a decrease in load of 144,000 MWh, unfavorable impact of purchasing incremental supply during extreme weather conditions in Summer 2019 at escalated prices above $1,000/MWh and the impact of selling back excess supply in 2019 as compared to 2018			$	(34)
Lower gross margin from demand response activities due to lower auction clearing prices and fewer MW sold in PJM in 2019 compared to 2018			(29)
Higher gross margin from Mass due to higher revenues primarily driven by margin enhancement initiatives of approximately $4.50 per MWh or $278 million, partially offset by higher supply costs driven by an increase in power prices of approximately $4.40 per MWh or $272 million			6
Higher gross margin driven by higher volume from XOOM and Stream acquisitions			114
Increase in economic gross margin			$	57
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges			(520)
Decrease in gross margin			$	(463)

Generation gross margin and economic gross margin

Generation gross margin increased $603 million and generation economic gross margin increased $109 million, both of which include intercompany sales, during the year ended December 31, 2019, compared to the same period in 2018.

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 25% increase in average realized prices due to heat rate expansion			$	285
Higher gross margin due to a 6% increase in generation volumes driven by a planned outage at STP and a forced outage at T.H. Wharton in 2018, partially offset by current year forced outages at coal facilities			44
Higher gross margin due to Gregory return to service in June 2019			38
Higher gross margin from commercial optimization activities			28
Higher gross margin due to margin enhancement initiatives from reduced fuel supply cost			13
Lower gross margin due to lower sales of NOx emission credits			(23)
Other			(2)
Increase in economic gross margin			$	383
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges			380
Increase in contract and emission credit amortization			7
Increase in gross margin			$	770

East/West Region

			(In millions)
Lower gross margin due to the sale of BETM, Keystone and Conemaugh in the third quarter of 2018, the sale of Guam in the first quarter of 2019 and the retirement of Encina in December 2018			$	(122)
Lower gross margin due to Ivanpah and Agua deconsolidations in April 2018 and August 2018, respectively			(118)
Lower gross margin due to a 17% decrease in economic generation volumes due to dark spread and spark spread contractions and outages in 2019			(56)
Lower gross margin driven by a decrease in New York realized capacity			(29)
Lower gross margin from commercial optimization activities			(16)
Lower gross margin due to insurance proceeds from outages in 2018, partially offset by business interruption proceeds			(6)
Higher gross margin mainly due to 7% increase in weighted average realized prices, primarily at Midwest Generation			38
Higher gross margin due to lower supply costs coupled with an increase in load contract volumes			21
Higher gross margin due to a 10% increase in PJM capacity prices and a 42% increase in West capacity prices, partially offset by an 8% decrease in New England capacity prices			15
Other			(1)
Decrease in economic gross margin			$	(274)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges			106
Increase in contract and emission credit amortization			1
Decrease in gross margin			$	(167)

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 $34 million during the year ended December 31, 2019, compared to the same period in 2018.

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

			Year Ended December 31, 2019
									Generation
(In millions)			Retail						Texas						East/West/Other						Elimination (a)						Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses on settled positions related to economic hedges			$	1					$	187					$	30					$	(171)					$	47
Net unrealized (losses)/gains on open positions related to economic hedges			(1)						11						6						(30)						(14)
Total mark-to-market gains in operating revenues			$	—					$	198					$	36					$	(201)					$	33
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges			$	(293)					$	5					$	2					$	171					$	(115)
Reversal of acquired loss positions related to economic hedges.			6						—						—						—						6
Net unrealized gains on open positions related to economic hedges			20						5						1						30						56
Total mark-to-market (losses)/gains in operating costs and expenses			$	(267)					$	10					$	3					$	201					$	(53)

(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, 2018
									Generation
(In millions)			Retail						Texas						East/West/Other						Elimination (a)						Total
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) on open positions related to economic hedges			(5)						(206)						(25)						183						(53)
Total mark-to-market (losses) 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

Mark-to-market results consist of unrealized gains and losses on contracts 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, 2019 the $33 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. The $53 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains, partially offset by an increase in the value of open positions as a result of gains on ERCOT heat rate positions due to heat rate expansion.

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, 2019 and 2018. 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)			2019						2018
Trading gains
Realized			$	57					$	77
Unrealized			20						17
Total trading gains			$	77					$	94

Operations and Maintenance Expenses

Operations and maintenance expenses are comprised of the following:

									Generation																		Corporate						Eliminations
(In millions)			Retail						Texas						East/West/Other (a)																		Total
Year Ended December 31, 2019			$	242					$	441					$	393					$	9					$	(3)					$	1,082
Year Ended December 31, 2018			$	209					$	437					$	440					$	3					$	(6)					$	1,083

(a) Includes Renewables and eliminations within Generation

Operations and maintenance expenses decreased by $1 million for the year ended December 31, 2019, compared to the same period in 2018, due to the following:

			(In millions)
Increase primarily related to the lease of the Cottonwood facility from February 4, 2019			$	37
Increase in investments in Texas plants in preparation for summer operations			21
Increase due to XOOM and Stream Energy acquisitions in June 2018 and August 2019, respectively			21
Increase in operations and maintenance expenses due to margin enhancement initiatives			8
Increase in outages primarily due to both planned and forced outages in 2019, partially offset by planned STP outages in 2018			3
Decrease due to the final settlement of the asbestos liability and resulting reduction of the accrual for Midwest Generation			(27)
Decrease due to the deconsolidations of Ivanpah and Agua Caliente in 2018			(20)
Decrease in variable chemical costs due to reduction in East generation volumes			(18)
Decrease due to retirement of Encina and the sale of Keystone and Conemaugh in 2018			(14)
Decrease due to payments in settlement of certain legal matters in 2018			(13)
Other			1
Increase in operations and maintenance expense			$	(1)

Other Cost of Operations

Other Cost of operations are comprised of the following:

									Generation
(In millions)			Retail						Texas						East/West/Other						Total
Year Ended December 31, 2019			$	120					$	76					$	75					$	271
Year Ended December 31, 2018			$	109					$	76					$	79					$	264

Other cost of operations increased by $7 million for the year ended December 31, 2019, compared to the same period in 2018, due to the following:

			(In millions)
Increase in ARO accretion expense due to Encina decommissioning and Jewett Mine accretion in 2019, partially offset by a decrease due to prior year write-off of S.R. Bertron			$	15
Increase in gross receipts tax due to the Stream Energy acquisition and higher revenue from increased rates and customer counts			10
Decrease due to deconsolidation of Ivanpah and Agua Caliente in 2018			(8)
Decrease due to resolution of favorable property tax disputes			(7)
Decrease in other cost of operations due to cost efficiencies as a result of the Transformation Plan			(5)
Other			2
Increase in other cost of operations			$	7

Depreciation and Amortization

Depreciation and amortization expenses are comprised of the following:

									Generation						Corporate
(In millions)			Retail																		Total
Year Ended December 31, 2019			$	157					$	185					$	31					$	373
Year Ended December 31, 2018			$	116					$	272					$	33					$	421

Depreciation and amortization expense decreased by $48 million for the year ended December 31, 2019, compared to the same period in 2018, due to the deconsolidations of Ivanpah and Agua Caliente in April and August 2018, respectively, and the sale of the Cottonwood facility in February 2019, partially offset by the acquisitions of Stream Energy and XOOM.

Impairment Losses

For the year ended December 31, 2019 the Company recorded an impairment loss of $5 million compared to impairment losses of $99 million for the same period in 2018, as further described in Item 15 — Note 11, Asset Impairments, to the Consolidated Financial Statements*.*

Selling, General and Administrative Expenses

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

(In millions)						Retail						Generation						Corporate						Total
Year Ended December 31, 2019						$	576					$	227					$	24					$	827
Year Ended December 31, 2018						$	538					$	215					$	46					$	799

Selling, general and administrative expenses increased by $28 million for the year ended December 31, 2019, compared to the same period in 2018, due to the following:

			(In millions)
Increase in selling and marketing expenses for margin enhancement initiatives			$	56
Increase in selling expense due to the acquisitions of XOOM and Stream Energy in June 2018 and August 2019, respectively			31
Increase in bad debt expense primarily due to higher customer attrition and increased revenue due to acquisitions			10
Decrease in general and administrative expense from cost efficiencies as a result of the Transformation Plan			(51)
Decrease due to the sale of BETM in 2018			(19)
Other			1
Increase in selling, general and administrative expenses			$	28

Reorganization Costs

Reorganization costs, primarily related to severance and contract modifications, decreased by $67 million for the year ended December 31, 2019, compared to the same period in 2018. The Company has substantially completed its three-year Transformation Plan and expects this expense to decrease further as we complete the implementation by the end of 2020.

Gain on Sale of Assets

Gain on sale of assets for the year ended December 31, 2019 represents a gain on the sale of an investment, while the gain for the year ended December 31, 2018 represents gains on the sales of BETM and Canal 3.

Impairment Losses on Investments

For the year ended December 31, 2019, the Company recorded other-than-temporary impairment losses of $108 million, compared to $15 million recorded in the same period in 2018, as further described in Item 15 — Note 11, Asset Impairments, to the Consolidated Financial Statements.

Other Income, Net

Other income increased by $48 million for the year ended December 31, 2019, compared to the same period in 2018, primarily due to the loss on deconsolidation of Ivanpah in 2018.

Loss on Debt Extinguishment

A loss on debt extinguishment of $51 million was recorded for the year ended December 31, 2019, driven by the redemption of the Senior Notes, due 2024, and the repayment of the 2023 Term Loan Facility.

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.

Interest Expense

Interest expense decreased by $70 million for the year ended December 31, 2019, compared to the same period in 2018, due to the following:

			(In millions)
Decrease related to the debt reduction of $1.2 billion and refinancing $2.4 billion of debt at lower interest rates in 2019 and 2018			$	(66)
Decrease related to the deconsolidations of Ivanpah and Agua Caliente in 2018			(27)
Increase in derivative interest expense due to the termination of interest rate swaps in 2019 of $39 million partially offset by settlement of in-the-money interest rate swaps of $25 million			14
Increase due to California property tax indemnification accretion			7
Increase due to the amortization of the premium on the Convertible Senior Notes due 2048 that were issued in the second quarter of 2018			5
Other			(3)
Decrease in interest expense			$	(70)

Income Tax (Benefit)/Expense

For the year ended December 31, 2019, NRG recorded an income tax benefit of $3.3 billion on pre-tax income of $786 million. For the same period in 2018, NRG recorded income tax expense of $7 million on pre-tax income of $467 million. The effective tax rate was (424.2)% and 1.5% for the years ended December 31, 2019 and 2018, respectively. The large benefit for the year ended December 31, 2019 is due to a $3.5 billion release of the Company’s valuation allowance. Refer to the section entitled Critical Accounting Policies and Estimates – Income Taxes and Valuation Allowance for Deferred Tax Assets and Item 15 – Note 20, Income Taxes, to the Consolidated Financial Statements for further discussion of the release in valuation allowance.

For the year ended December 31, 2019, NRG's overall effective tax rate was different than the federal statutory tax rate of 21% primarily due to a tax benefit from the release of the valuation allowance.

			Year Ended December 31,
(In millions, except effective income tax rate)			2019						2018
Income from continuing operations before income taxes			$	786					$	467
Tax at federal statutory tax rate			165						98
State taxes			13						18
Deferred impact of state tax rate changes			12						—
Valuation allowance - current period activities			(3,492)						(106)
Permanent differences			(9)						7
Production tax credits			—						(7)
Recognition of uncertain tax benefits			(10)						1
Alternative minimum tax ("AMT") refundable credit			—						(4)
Other			(13)						—
Income tax (benefit)/expense			$	(3,334)					$	7
Effective income tax rate			(424.2)		%				1.5		%

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)						2019						2018						Change
South Central						$	28					$	66					$	(38)
Yield Renewables Platform & Carlsbad						296						(292)						588
Genon						(3)						34						(37)
Income/(Loss) from discontinued operations, net of tax						$	321					$	(192)					$	513

Refer to Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions, to the Consolidated Financial Statements for further discussion.

Liquidity and Capital Resources

Liquidity Position

As of December 31, 2019 and 2018, NRG's liquidity, excluding collateral funds deposited by counterparties, was approximately $2.1 billion and $2.0 billion, respectively, comprised of the following:

			As of December 31,
(In millions)			2019						2018
Cash and cash equivalents:			$	345					$	563
Restricted cash - operating			4						6
Restricted cash - reserves (a)			4						11
Total			353						580
Total credit facility availability			1,794						1,397
Total liquidity, excluding collateral funds deposited by counterparties			$	2,147					$	1,977

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

For the year ended December 31, 2019, total liquidity, excluding collateral funds deposited by counterparties, increased by $170 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, 2019 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

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

Credit Ratings

On December 13, 2019, Moody's upgraded the NRG corporate family rating to Ba1 and senior unsecured rating to Ba2. The agency affirmed the company's senior secured rating at Baa3.

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

			S&P						Moody's
NRG Energy, Inc.			BB Positive						Ba1 Positive
3.75% Senior Secured Notes, due 2024			BBB-						Baa3
7.25% Senior Notes, due 2026			BB						Ba2
6.625% Senior Notes, due 2027			BB						Ba2
5.75% Senior Notes, due 2028			BB						Ba2
4.45% Senior Secured Notes, due 2029			BBB-						Baa3
5.25% Senior Notes, due 2029			BB						Ba2
Revolving Credit Facility, due 2024			BBB-						Baa3

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 and financing arrangements. As described in Item 15 — Note 13, Debt and Finance Leases, to the Consolidated Financial Statements, the Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes and the Senior Secured Notes.

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 13, Debt and Finance Leases, to the Consolidated Financial Statements; (iii) capital expenditures, including environmental; and (iv) allocations in connection with return of capital and dividend payments to shareholders as described in Item 15 — Note 16, Capital Structure, to the Consolidated Financial Statements, acquisition opportunities, and debt repayments.

Issuance of 2029 Senior Notes

On May 14, 2019, NRG issued $733 million of aggregate principal amount at par of 5.25% senior unsecured notes due 2029. The proceeds from the issuance of the 2029 Senior Notes were utilized to redeem the Company's remaining $733 million of 6.25% Senior Notes due 2024.

Issuance of 2024 and 2029 Senior Secured Notes

On May 28, 2019, NRG issued $1.1 billion of aggregate principal amount of senior secured first lien notes, consisting of $600 million 3.75% senior secured first lien notes due 2024 and $500 million 4.45% senior secured first lien notes due 2029, at a discount. The proceeds from the issuance of the Senior Secured Notes, together with cash on hand, were used to repay the Company's 2023 Term Loan Facility.

2023 Term Loan Facility

On May 28, 2019, the Company repaid its $1.7 billion 2023 Term Loan Facility using the proceeds from the issuance of the Senior Secured Notes, as well as cash on hand, resulting in a decrease of $594 million to long-term debt outstanding. The Company recorded a loss on debt extinguishment of $17 million, which included the write-off of previously deferred debt issuance costs of $13 million. As a result of the repayment of the outstanding 2023 Term Loan Facility, the Company terminated the related interest rate swap agreements, which were in-the-money, and received $25 million that was recorded as a reduction to interest expense.

Revolving Credit Facility Modification

On May 28, 2019, the Company amended its existing credit agreement to, among other things, (i) provide for a $184 million increase in revolving commitments, resulting in aggregate revolving commitments under the amended credit agreement equal to $2.6 billion, (ii) extend the maturity date of the revolving loans and commitments under the amended credit agreement to May 28, 2024, (iii) provide for a release of the collateral securing the amended credit agreement if NRG obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw NRG’s investment grade rating or downgrade NRG’s rating below investment grade, (iv) reduce the applicable margins for borrowings under (a) ABR Revolving Loans from 1.25% to 0.75% and (b) Eurodollar Revolving Loans from 2.25% to 1.75%, (v) add a sustainability-linked pricing metric that permits an interest rate adjustment tied to NRG meeting targets related to environmental sustainability and (vi) make certain other changes to the existing covenants. As of December 31, 2019, $83 million of borrowings were outstanding under the Revolving Credit Facility.

Agua Caliente Borrower I - Non-Recourse Debt

On October 21, 2019, the Company repaid the outstanding amount on the Agua Caliente Borrower I notes at 102% plus accrued interest through the payment date.

Balance Sheet Target Ratio

NRG revised its credit metrics target to 2.5x -2.75x net debt / adjusted EBITDA(a) in the first quarter of 2019 in order to further strengthen its balance sheet and improve credit ratings by reducing leverage. As discussed above, during the second quarter of 2019, the Company reduced total outstanding debt by $594 million with the repayment of the 2023 Term Loan facility.

Petra Nova Debt Repayment

During the third quarter of 2019, NRG contributed approximately $95 million in cash to Petra Nova and posted a $12 million letter of credit to cover certain project debt reserve requirements. The cash portion of the contribution was used by Petra Nova to prepay a significant portion of the project debt. As a result, the financial guarantees previously provided by NRG were canceled and the remaining project debt became non-recourse to NRG.

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

Debt Service Obligations

Principal payments on debt as of December 31, 2019 are due in the following periods:

(In millions)
Description			2020						2021						2022						2023						2024						Thereafter						Total
Recourse Debt:
Senior notes, due 2026			$	—					$	—					$	—					$	—					$	—					$	1,000					$	1,000
Senior notes, due 2027			—						—						—						—						—						1,230						1,230
Senior notes, due 2028			—						—						—						—						—						821						821
Senior notes, due 2029			—						—						—						—						—						733						733
Convertible Senior Notes, due 2048			—						—						—						—						—						575						575
Senior Secured First Lien Notes, due 2024			—						—						—						—						600						—						600
Senior Secured First Lien Notes, due 2029			—						—						—						—						—						500						500
Revolving Credit Facility			83						—						—						—						—						—						83
Tax-exempt bonds			—						—						—						—						—						466						466
Subtotal Recourse Debt			83						—						—						—						600						5,325						6,008
Non-Recourse Debt:
Other			5						6						5						4						4						10						34
Subtotal Non-Recourse Debt			5						6						5						4						4						10						34
Total Debt			$	88					$	6					$	5					$	4					$	604					$	5,335					$	6,042

In addition to the debt shown in the above table, NRG had issued $723 million of letters of credit under the Company's $2.6 billion Revolving Credit Facility as of December 31, 2019.

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, 2019, commercial operations had total cash collateral outstanding of $190 million and $694 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, 2019, total funds deposited by counterparties was $32 million in cash and $102 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.

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of property and assets owned by NRG and the guarantors of its senior debt. 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 a 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, 2019, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

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

Equivalent Net Sales Secured by First Lien Structure (a)			2020						2021						2022						2023
In MW			642						644						699						753
As a percentage of total net coal and nuclear capacity (b)			14%						14%						15%						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

Stream Energy Acquisition

On August 1, 2019, the Company completed the acquisition of Stream Energy's retail electricity and natural gas business operating in 9 states and Washington, D.C. for $329 million, including working capital and other adjustments of approximately $29 million. The acquisition increased NRG's retail portfolio by approximately 600,000 RCEs or 450,000 customers.

Small Book Acquisitions

During 2019, the Company acquired several books of customers totaling approximately 72,000 customers for $17 million, of which $13 million was paid in 2019. During 2018, the Company acquired several books of customers totaling approximately 115,000 customers, along with brand names, for $44 million, of which $40 million was paid in 2018, $2 million was paid in 2019 and $2 million was prepaid in 2017. The majority of the purchase price for the 2019 and 2018 book acquisitions were allocated to acquired intangibles.

Asset Sale Proceeds

The following table summarizes the approximate cash proceeds received from sale transactions and related financings, net of working capital and other adjustments, completed by the Company during the years ended December 31, 2019 and 2018:

(In millions)			2019						2018
South Central Portfolio			$	962					$	—
Carlsbad			396						—
Guam			8						—
NRG Yield, Inc and Renewables Platform			—						1,348
Canal 3 (a)			—						167
UPMC Thermal Project (b)			—						84
BETM			—						70
Buckthorn Solar (b)			—						42
Other			14						12
Cash proceeds from sales transactions			$	1,380					$	1,723

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

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

Capital Expenditures

The following table summarizes the Company's capital expenditures for maintenance, environmental, and growth investments for the year ended December 31, 2019:

(In millions)			Maintenance						Environmental						Growth Investments						Total
Retail			$	13					$	—					$	47					$	60
Generation
Texas			91						1						—						92
East/West/Other (a)			40						2						—						42
Corporate			12						—						22						34
Total cash capital expenditures for the year ended December 31, 2019			156						3						69						228
Stream acquisition			—						—						326						326
Other investments(b)			—						—						240						240
Total capital expenditures and investments, net of financings			$	156					$	3					$	635					$	794

(a) Includes Renewables and the Cottonwood facility

(b) Other investments includes acquisitions, cost-to-achieve expenses, integration costs, and equity investments

*•*Growth Investments capital expenditures — For the year ended December 31, 2019, the Company's growth investment capital expenditures included $51 million for cost-to-achieve projects associated with the Transformation Plan and $18 million for the Company's other growth projects.

Environmental Capital Expenditures Estimate

NRG estimates that environmental capital expenditures from 2020 through 2024 required to comply with environmental laws will be approximately $40 million. These costs are primarily associated with the cost of adding NOx controls in Connecticut and water and landfill projects at W.A. Parish.

The table below summarizes the status of NRG's coal fleet with respect to air quality controls. NRG uses an integrated approach to fuels, controls and emissions markets to meet environmental requirements.

												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
Limestone 1-2						TX						FGD						1985-86						LNBOFA						2002/2003						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 by region:

(In millions)			Texas						East/West									Total
2020			$	3					$	4								$	7
2021			14						12									26
2022			6						5									11
2023			—						1									1
2024			—						—									—
Total			$	23					$	22								$	45

Share Repurchases

In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its common stock. Repurchases of $1.25 billion were executed in 2018 with the remaining $0.25 billion completed in the first quarter of 2019. In 2019, the Company's board of directors authorized the Company to repurchase additional $1.25 billion of its common stock, which was completed as of February 27, 2020. See Item 15 — Note 16, Capital Structure, to the Consolidated Financial Statements for additional discussion.

Common Stock Dividends

The Company returned $32 million of capital to shareholders in the year ended 2019 through a $0.12 dividend per common share.

Beginning in the first quarter of 2020, NRG increased the annual dividend to $1.20 per share from $0.12 per share and expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

On January 21, 2020, NRG declared a quarterly dividend on the Company's common stock of $0.30 per share, or $1.20 per share on an annualized basis, payable on February 18, 2020, to stockholders of record as of February 3, 2020. The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws and regulations.

Cash Flow Discussion

2019 compared to 2018

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

			Year ended December 31,
(In millions)			2019						2018						Change
Net cash provided by operating activities			$	1,413					$	1,377					$	36
Net cash provided/(used) by investing activities			556						(205)						761
Net cash used by financing activities			(2,148)						(1,526)						(622)

Net Cash Provided By Operating Activities

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

			(In millions)
Change in cash provided by discontinued operations			$	(366)
Increase in operating income adjusted for other non-cash items			230
Changes in cash collateral in support of risk management activities due to change in commodity prices			210
GenOn settlement in July 2018			63
Other changes in working capital			(101)
			$	36

Net Cash Provided By Investing Activities

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

			(In millions)
Decrease in cash used by discontinued operations			$	724
Cash removed in 2018 due to deconsolidation of Agua Caliente and Ivanpah projects			268
Decrease in capital expenditures primarily driven by construction projects in 2018			160
Increase in proceeds received from sales of nuclear decommissioning trust fund securities, net of purchases			24
Decrease in contributions to discontinued operations			16
Decrease in proceeds from sale of assets and discontinued operations			(271)
Increase in cash paid for acquisitions primarily due to Stream Energy acquisition in 2019			(112)
Change in investments in unconsolidated affiliates			(52)
Other			4
			$	761

Net Cash Used By Financing Activities

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

			(In millions)
Increase in payments of short and long-term debt			$	(837)
Change in cash provided by discontinued operations			(428)
Increase in payments for treasury stock			(190)
Increase in payments of debt extinguishment costs and deferred issuance costs			(10)
Increase in proceeds from issuance of short and long-term debt			816
Decrease in distributions to noncontrolling interests from subsidiaries			14
Other			13
			$	(622)

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications

As of December 31, 2019, the Company had domestic pre-tax book income of $771 million and foreign pre-tax book income of $15 million. For the year ended December 31, 2019, the Company utilized NOLs of $593 million due to current year taxable income. As of December 31, 2019, the Company has cumulative U.S. federal NOL carryforwards of $10.1 billion, which will begin expiring in 2031 and cumulative state NOL carryforwards of $5.5 billion. NRG also has cumulative foreign NOL carryforwards of $357 million, which do not have an expiration date. In addition to the above NOLs, NRG has a $361 million indefinite carryforward for interest deductions, as well as $384 million of tax credits to be utilized in future years. As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, the Company anticipates income tax payments, primarily due to state and local jurisdictions, of up to $16 million in 2020. See Item 15 — Note 20, Income Taxes, for further discussion regarding the release of the valuation allowance.

The Company has recorded as of December 31, 2019 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 2020 through 2022 pursuant to the 50% annual limitation as enacted by the Tax Act upon repeal of corporate AMT effective January 1, 2018. Of these amounts, short-term and long-term payables of $11 million each are due to GenOn for their share of the minimum tax credits.

In addition to these amounts, the Company has $15 million of tax effected uncertain state tax benefits for which the Company has recorded a non-current tax liability of $17 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 2016. With few exceptions, state and local income tax examinations are no longer open for years before 2011.

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 27, 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, 2019, 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. Ivanpah 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 $866 million as of December 31, 2019. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Item 15 — Note 17, 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 13, Debt and Finance Leases, Note 23, Commitments and Contingencies, and Note 27, Guarantees, to the Consolidated Financial Statements for additional discussion.

			By Remaining Maturity at December 31,
(In millions)			2019
Contractual Cash Obligations			Under 1 Year						1-3 Years						3-5 Years						Over 5 Years						Total (a)
Long-term debt (including estimated interest)			$	436					$	705					$	1,281					$	6,912					$	9,334
Operating leases			96						174						160						296						726
Fuel purchase and transportation obligations			124						198						115						139						576
Purchased power commitments(b)			35						117						112						349						613
Pension minimum funding requirement (c)			54						54						42						53						203
Other postretirement benefits minimum funding requirement (d)			7						11						11						17						46
Other liabilities (e)			45						57						40						125						267
Total			$	797					$	1,316					$	1,761					$	7,891					$	11,765

(a)Excludes $15 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 $728 million of asset retirement obligations that are discussed in Item 15 — Note 14, Asset Retirement Obligations, to the Consolidated Financial Statements

(b)Includes purchase power commitments and renewable minimum purchase power commitments under PPAs

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

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

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

			By Remaining Maturity at December 31,
(In millions)			2019
Guarantees			Under 1 Year						1-3 Years						3-5 Years						Over 5 Years						Total
Letters of credit and surety bonds(a)			$	878					$	115					$	31					$	—					$	1,024
Asset sales guarantee obligations			4						490						—						204						698
Other guarantees			77						5						—						206						288
Total guarantees			$	959					$	610					$	31					$	410					$	2,010

(a)Guarantees as of December 31, 2019 include $14 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 power plants or retail load obligations.

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, 2019, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2019. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Item 15 — Note 5, Fair Value of Financial Instruments, to the Consolidated Financial Statements.

Derivative Activity Gains/(Losses)			(In millions)
Fair value of contracts as of December 31, 2018			$	104
Contracts realized or otherwise settled during the period			(105)
Contracts acquired during the period			(12)
Changes in fair value			80
Fair value of contracts as of December 31, 2019			$	67

			Fair Value of Contracts as of December 31, 2019
(In millions)			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
Level 1			$	(31)					$	(27)					$	(2)					$	1					$	(59)
Level 2			56						49						(7)						(10)						88
Level 3			54						(2)						1						(15)						38
Total			$	79					$	20					$	(8)					$	(24)					$	67

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, 2019, NRG's net derivative asset was $67 million, a decrease to total fair value of $37 million as compared to December 31, 2018. This decrease was primarily driven by losses in trades settled and contracts acquired during the period, partially offset by increases in change in fair value during the period.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $41 million in the net value of derivatives as of December 31, 2019.

The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $36 million in the net value of derivatives as of December 31, 2019.

Critical Accounting Policies and Estimates

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

Upon repayment of the Term Loan in 2019, all of the Company's interest rate swaps were terminated. In order to qualify the derivative instruments for hedged transactions prior to termination, NRG estimated the forecasted borrowings for interest rate swaps occurring within a specified time period. Judgments related to the probability of forecasted borrowings were 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.

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 expected load requirements, 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, 2019, NRG’s deferred tax assets were primarily the result of U.S. federal and state NOLs, the difference between book and tax basis in property, plant, and equipment, and tax credit carryforwards. The realization of deferred tax assets is dependent upon the Company's ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in the Company's financial statements or tax returns and forecasting future profitability by tax jurisdiction.

A valuation allowance of $242 million and $3.8 billion was recorded against NRG’s gross deferred tax asset balance as of December 31, 2019, and December 31, 2018, respectively. During the year ended December 31, 2019, NRG released the majority of its valuation allowance against its U.S. federal and state deferred tax assets, resulting in a non-cash benefit to income tax expense of approximately $3.5 billion.

The Company evaluates its deferred tax assets quarterly on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of the Company’s deferred tax assets. In making the determination to release the majority of the valuation allowance as of December 31, 2019, the Company evaluated a number of factors, including its recent history of pre-tax earnings, utilization of $593 million of NOLs in 2019, as well as its forecasted future pre-tax earnings. Based on this evaluation, the Company determined that its future U.S. federal tax benefits are more-likely-than-not to be realized. Given the Company’s current level of pre-tax earnings and forecasted future pre-tax earnings, the Company expects to generate income before taxes in the U.S. in future periods at a level that would fully utilize its U.S. federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration.

NRG continues to maintain a valuation allowance of approximately $242 million as of December 31, 2019 against net deferred tax assets consisting of state net operating losses and foreign NOL carryforwards in jurisdictions where the Company does not currently believe that the realization of its deferred tax assets is more likely than not.

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 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.

The Company is no longer subject to U.S. federal income tax examinations for years prior to 2016. With few exceptions, state and local income tax examinations are no longer open for years before 2011.

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, 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 impact 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.

As of December 31, 2019, the Company recorded impairment losses of approximately $5 million, excluding impairment losses on equity and cost method investments discussed below. 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 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, 2019, the Company recorded impairment losses on its equity and cost method investments, primarily Petra Nova, of $108 million due to declines in value.

Goodwill and Other Intangible Assets

At December 31, 2019, NRG reported goodwill of $579 million, consisting of $165 million associated with the acquisition of Midwest Generation and $414 million for retail business acquisitions, including Texas non-commodity, XOOM and Stream Energy.

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 Retail Mass 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, 2019.

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, 2019:

Reporting Unit						% Fair Value Over Carrying Value
Midwest Generation (Generation Segment)						112		%
Texas Non-Commodity (Retail Segment)						140		%

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 the Midwest Generation plants. 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 next five years 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.

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 23, 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.