Note 8 — Leases

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

~~Note 7 —~~ ~~Impairments~~The Company considers a contract to be or to contain a lease when both of the following conditions apply: 1) an asset is either explicitly or implicitly identified in the contract and 2) the contract conveys to the Company the right to control the use of the identified asset for a period of time. The Company has the right to control the use of the identified asset when the Company has both the right to obtain substantially all the economic benefits from the use of the identified asset and the right to direct how and for what purpose the identified asset is used throughout the period of use.

~~2018 Impairment Losses~~Lease payments are typically fixed and payable on a monthly, quarterly, semi-annual or annual basis. Lease payments under certain agreements may escalate over the lease term either by a fixed percentage or a fixed dollar amount. Certain leases may provide for variable lease payments in the form of payments based on usage, a percentage of sales from the location under lease, or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments. The Company has no leases which contain residual value guarantees provided by the Company as a lessee.

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

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

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

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


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


3.	not reassess initial direct costs for any leases;


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


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

As described in Note 3, Discontinued Operations and ~~Conemaugh~~ Dispositions~~— On June 29, 2018,~~, upon the close of the South Central Portfolio sale, the Company entered into an agreement to ~~sell its approximately 3.7% interests~~leaseback the Cottonwood facility through May 2025. The lease was accounted for in accordance with ASC 842-40, Sale and Leaseback Transactions, as an operating lease and accordingly, a right-of-use asset and lease liability were established on the ~~Keystone~~lease commencement date and ~~Conemaugh generating stations. NRG recorded impairment losses of $14 million for Keystone and $14 million for Conemaugh to adjust~~will be amortized through the ~~carrying amount~~end of the ~~assets to fair value~~lease.

Lease Cost:



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

Other information:



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

Lease Term and Discount Rate:



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

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

As of March 31, 2019, annual payments based on the ~~contractual sale price. The transaction is~~maturities of NRG's leases are expected to ~~close in the third quarter of 2018.~~be as follows:

~~Dunkirk —~~ During the second quarter of 2018, NRG ceased its development of the project to add gas capability at the Dunkirk generating station. The project was put on hold in 2015 pending the resolution of a lawsuit filed by Entergy Corporation against the NYPSC which challenged the legality of the Dunkirk contract. The lawsuit was later dropped and development continued, but the delay imposed a new requirement on Dunkirk to enter into the NYISO interconnection process. The NYISO studies have shown that it would cause the Company to incur a material increase in costs. In addition, the interconnection upgrades that the NYISO has identified may not be ready until December 2023, which represents a significant delay the project schedule. This caused the Company to record an impairment loss of ~~$46 million, reducing the carrying amount of the related assets to~~ $0.

~~2017 Impairment Losses~~

~~Bacliff Project~~ — On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the contractual expiration date of May 31, 2017. As a result of the MIPA termination, the Company recorded an impairment loss of $41 million to reduce the carrying amount of the related construction in progress to $0 during the second quarter of 2017. Subsequent to the MIPA termination, BTEC filed claims against NRG Texas Power LLC with respect to the termination of the MIPA and NRG filed counterclaims against BTEC as further described in Note 15, ~~Commitments and Contingencies. On June 7, 2018, the parties resolved all claims and counterclaims in the lawsuit.~~

~~Other Impairments —~~ ~~During the second quarter of 2017, the Company recorded impairment losses of approximately $22 million in connection with the Company's Renewables business.~~



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

Note 89 — Debt and Capital Leases

~~This footnote should be read in conjunction with the complete description under~~ ~~Note 12~~, ~~Debt and Capital Leases, to the Company's 2017 Form 10-K.~~ Long-term debt and capital leases consisted of the following:

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

Recourse debt:
Senior Notes, due 2022 $ 977
$ 992
6.250
Senior Notes, due 2024 733
733
6.250
Senior Notes, due 2026 1,000
1,000
7.250
Senior Notes, due 2027 1,250
1,250
6.625
Senior Notes, due 2028 841
870
5.750
Convertible Senior Notes, due 2048 575
—
2.750
Revolving loan facility, due 2018 and 2021 26
—
L+1.75
Term loan facility, due 2023 1,862
1,872
L+1.75
Tax-exempt bonds 465
465
4.125 - 6.00
Subtotal recourse debt 7,729
7,182

Non-recourse debt:
NRG Yield, Inc. Convertible Senior Notes, due 2019 345
345
3.500
NRG Yield, Inc. Convertible Senior Notes, due 2020 288
288
3.250
NRG Yield Operating LLC Senior Notes, due 2024 500
500
5.375
NRG Yield Operating LLC Senior Notes, due 2026 350
350
5.000
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2023^(b)
—
55
L+1.75
El Segundo Energy Center, due 2023 369
400
L+1.75 - L+2.375
Marsh Landing, due 2023 305
318
L+2.125
Alta Wind I - V lease financing arrangements, due 2034 and 2035 901
926
5.696 - 7.015
Walnut Creek, term loans due 2023 254
267
L+1.625
Utah Portfolio, due 2022 273
278
various
Tapestry, due 2021 155
162
L+1.625
CVSR, due 2037 731
746
2.339 - 3.775
CVSR HoldCo, due 2037 188
194
4.680
Alpine, due 2022 133
135
L+1.750
Energy Center Minneapolis, due 2031, 2033, 2035 and 2037 328
208
various
Viento, due 2023 154
163
L+3.00
Buckthorn Solar, due 2018 and 2025 132
169
L+1.750
NRG Yield - other 564
579
various
Subtotal NRG Yield debt (non-recourse to NRG) ^(c)
5,970
6,083

Ivanpah, due 2033 and 2038 ^(e)
—
1,073
2.285 - 4.256
Carlsbad Energy Project ^(c)
513
427
L+1.625 - 4.120
Agua Caliente, due 2037 812
818
2.395 - 3.633
Agua Caliente Borrower 1, due 2038 86
89
5.430
Cedro Hill, due 2025 ^(c)
144
151
L+1.75
Midwest Generation, due 2019 108
152
4.390
NRG Other Renewables ^(c)
623
478
various
NRG Other 107
180
various
Subtotal other NRG non-recourse debt 2,393
3,368

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

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

16,633

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

16,638

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

$ 15,716



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

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

(a) As of ~~June 30, 2018,~~March 31, 2019, L+ equals ~~3-month~~1-month LIBOR plus ~~x%, except for Carlsbad, the Buckthorn Solar and Utah Solar Portfolio where L+ equals 1 month LIBOR plus x% and Viento where L+ equals 6-month LIBOR plus x%.~~

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

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

~~(d) The NRG Yield, Inc. Convertible Senior Notes, due 2019, become due in February 2019 and are recorded in current maturities as of June 30, 2018.~~

~~(e) The Company deconsolidated Ivanpah during the second quarter of 2018.~~

1.75%

~~Recourse Debt~~

~~2023 Term Loan Facility~~

~~On March 21, 2018, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 1.75% and reducing the LIBOR floor to 0.00%.~~

~~Senior Notes~~

~~Issuance of 2048 Convertible Senior Notes~~

During the second quarter of 2018, NRG issued $575 million in aggregate principal amount of 2.75% Convertible Senior Notes due 2048, or the Convertible Notes. The Convertible Notes are convertible, under certain circumstances, into the Company's common stock, cash or a combination thereof (at NRG's option) at an initial conversion price of $47.74 per common share, which is equivalent to an initial conversion rate of approximately 20.9479 shares of common stock per $1,000 principal amount of Convertible Notes. Interest on the Convertible Notes is payable semi-annually in arrears on June 1 and December 1 of each year, commencing on December 1, 2018. The Convertible Notes mature on June 1, 2048, unless earlier repurchased, redeemed or converted in accordance with their terms. The Convertible Notes are guaranteed by certain NRG subsidiaries. Prior to the close of business on the business day immediately preceding December 1, 2024, the Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter during specified periods as follows:

•~~from December 1, 2024 until the close of business on the second scheduled trading day immediately before June 1, 2025; and~~

•~~from December 1, 2047 until the close of business on the second scheduled trading day immediately before the maturity date.~~

~~The Convertible Notes are accounted for in accordance with ASC 470-20,~~ ~~Debt with Conversion and Other Options~~. Under ASC 470-20, issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are required to separately account for the liability (debt) and equity (conversion option) components. The carrying amount of the liability component at issuance date of $472 million was calculated by estimating the fair value of similar liabilities without a conversion feature. The residual principal amount of the notes of $103 million was allocated to the equity component with offset to debt discount. The debt discount will be amortized to interest expense using the effective interest method over seven years which is determined to be the expected life of the Convertible Notes.

The Company incurred approximately $12 million in transaction costs in connection with the issuance of the notes. These costs were allocated to the liability and equity components in proportion to the allocation of proceeds. Transaction costs of $9.5 million, allocated to the liability component, were recognized as deferred financing costs and are amortized over the seven years. Transaction costs of $2 million, allocated to the equity component, were recognized as a reduction of additional paid-in capital.

~~Senior Note Repurchases~~

In connection with the Transformation Plan, the Company has committed to reduce its debt balance by an additional $640 million to achieve a target net debt to adjusted EBITDA credit ratio of 3.0/1. The following open market senior note repurchases were completed to assist in achieving this target.

In connection with the repurchases during the six months ended June 30, 2018, a $1 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $1 million.

Principal Repurchased
Cash Paid ^(a)

Average Early Redemption Percentage
In millions, except rates

5.750% senior notes due 2028 $ 29

$ 30

99.24 %
6.250% senior notes due 2022 14

15

103.25 %
Total at June 30, 2018 $ 43

$ 45

6.250% senior notes due 2022 6

6

103.25 %
5.750% senior notes due 2028 20
21
99.13 %
6.625% senior notes due 2027 20
21
103.06 %
Total at August 2, 2018 $ 89
$ 93

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

~~Non-recourse Debt~~

~~NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility~~

NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, are parties to a senior secured revolving credit facility, which can be used for cash and for the issuance of letters of credit. On April 30, 2018, NRG Yield LLC and NRG Yield Operating LLC refinanced the revolving credit facility, which extended the maturity of the facility to April 28, 2023, and decreased the overall cost of borrowing from L+ 2.50% to L+1.75%. At June 30, 2018, there was $67 million of letters of credit issued under the revolving credit facility and no outstanding borrowings on the revolver.

~~Project Financings~~

~~Thermal Financing~~

On June 19, 2018, NRG Energy Center Minneapolis, a subsidiary of NRG Yield LLC, entered into an amended and restated Thermal note purchase and private shelf agreement whereas it authorized the issuance of the Series E Notes, Series F Notes, Series G Notes, and Series H Notes, as further described in the table below:

Amount Interest Rate
In millions, except rates
Energy Center Minneapolis Series E Notes, due 2033 $ 70
4.80 %
Energy Center Minneapolis Series F Notes, due 2033 10
4.60 %
Energy Center Minneapolis Series G Notes, due 2035 83
5.90 %
Energy Center Minneapolis Series H Notes, due 2037 40
4.83 %
Total proceeds $ 203

Repayment of Energy Center Minneapolis Series C Notes, due 2025 (83 ) 5.95 %
Net borrowings $ 120

The Series G Notes were used to refinance the Series C Notes due 2025. The amended and restated Thermal note purchase and private shelf agreement also established a private shelf facility for the future issuance of notes in the amount of $40 million.

~~Rosamond Financing~~

On June 4, 2018, Rosamond Solar Portfolio, LLC entered into a financing agreement with financial institutions for a $118 million construction loan, which will convert to a term loan upon completion of project construction and a $175 million investment tax credit, or ITC, bridge loan, both of which have an interest rate of LIBOR plus 1.75%, as well as a letter of credit facility with availability of up to $33 million. The ITC bridge loan is expected to be repaid with proceeds from a tax equity arrangement by April 30, 2019. The term loan matures on April 30, 2034. As of June 30, 2018, $83 million and $5 million had been borrowed under the construction loan and the ITC bridge loan, respectively.

Agua Caliente ~~Project Financing~~Borrower 1

On ~~February 17, 2017,~~January 22, 2019, the lenders of the Agua Caliente Borrower 1 ~~LLC and~~debt notified Agua Caliente Borrower 1, a subsidiary of the Company, of certain defaults under the financing agreement as it relates to the bankruptcy filing made by PG&E on January 29, 2019. PG&E is the offtaker of the underlying contracts, which are material to the project. The financing was entered into along with Agua Caliente Borrower 2, LLC, ~~or Agua Caliente Holdco, the indirect owners~~a subsidiary of 51% of the Agua Caliente solar facility, issued $130 million of senior secured notes under the Agua Caliente Holdco Financing Agreement, or 2038 Agua Caliente Holdco Notes, that bear interest at 5.43% and mature on December 31, 2038. As described in Note 3, ~~Acquisitions, Discontinued Operations and Dispositions~~Clearway Energy Inc., ~~on March 27, 2017, NRG Yield, Inc. acquired Agua Caliente Borrower 2 LLC from NRG. The debt~~which is joint and several to the parties. The Company is working with ~~respect~~the lenders to ~~Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC and is secured by the equity interests~~determine a path forward.

Cottonwood - Letters of ~~each borrower in the Agua Caliente solar facility.~~

~~Carlsbad Project Financing~~Credit

On ~~May 26, 2017, Carlsbad Energy Holdings, LLC~~January 4, 2019, the Company entered into ~~a note payable agreement with financial institutions for the issuance of up to $407~~an $80 million ~~of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038, and a~~ credit agreement ~~for a $194 million construction loan, that will convert~~ to ~~a term loan upon completion of the project as well as a letter~~issue letters of credit, which is currently supporting the Cottonwood facility ~~with an aggregate principal amount not to exceed $83 million, and a working capital loan~~lease. Annual fees of 1.33% on the facility ~~with an aggregate principal amount not to exceed $4 million.~~are paid quarterly in advance. As of ~~June 30, 2018, $513~~March 31, 2019, the full $80 million ~~was outstanding under both the note and the construction loan.~~

is issued.

Note 910 — Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs

Entities that are not Consolidated

~~NRG has interests in entities that are considered VIEs under ASC 810,~~ ~~Consolidation, but NRG is not considered the primary beneficiary.~~ NRG accounts for ~~its interests in these entities under~~the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by a number of elements including impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates.

~~Utility-Scale Solar Portfolio~~PG&E Bankruptcy—~~Through its consolidated subsidiary, NRG Yield, Inc.,~~ - The Agua Caliente project and two of the ~~Company has equity interests in Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC, which~~three Ivanpah units are ~~accounted for as equity method investments as the Company does not have a controlling financial interest.~~ ~~The assets have 20-year~~party to PPAs with ~~PacifiCorp.~~PG&E. Both projects have project financing with the U.S. DOE. On January 29, 2019, PG&E Corp. and subsidiary utility PG&E filed for Chapter 11 bankruptcy protection. As part of their filing, PG&E asked the Bankruptcy Court to confirm exclusive jurisdiction over their "rights to reject" PPAs or other contracts regulated by FERC. As a result of the bankruptcy filing, the Agua Caliente and Ivanpah projects have issued notices of events of default under their respective loan agreements. The Company's subsidiaries are working with its partners on the projects and the loan counterparties, however, given the uncertainty involved in bankruptcy proceedings, it is uncertain whether, and to what extent, PG&E's bankruptcy may in the future impact the PPAs and have any resulting impact on the Agua Caliente and Ivanpah projects. NRG's maximum exposure to loss is limited to its equity investment, which was ~~$338~~$201 million for Agua Caliente and $20 million for Ivanpah as of ~~June 30, 2018.~~March 31, 2019. See Note 9, Debt and Capital Leases for further discussion on Agua Caliente.

Variable Interest Entities

~~GenConn Energy LLC~~—NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, ~~Through its consolidated subsidiary,~~Consolidation, for which NRG ~~Yield, Inc.,~~is not the ~~Company owns a~~ ~~50%~~ ~~interest in GCE Holding LLC,~~primary beneficiary, under the ~~owner of GenConn, which owns and operates~~ ~~two190-MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its~~ equity ~~investment, which was~~ ~~$100 million~~ ~~as of~~ ~~June 30, 2018~~.method.

~~Ivanpah Master Holdings LLC~~ — Through its consolidated subsidiary, NRG Solar Ivanpah LLC, ~~the Company~~NRG owns a ~~54.6%~~54.5% interest in Ivanpah Master Holdings LLC, or Ivanpah, the owner of three solar electric generating projects located in the Mojave Desert with a total capacity of ~~392~~393 MW. NRG considers this investment a VIE under ASC 810 and NRG is not considered the primary beneficiary. The Company accounts for its interest under the equity method of accounting.

The Ivanpah solar electric generating projects were funded in large part by loans guaranteed by the U.S. DOE and equity from the projects' partners. During the first quarter of 2018, all interested parties sought a restructuring of Ivanpah's debt in order to avoid a potential event of default with respect to the loans ~~in connection with several recent events, including the planned sale of NRG's renewables platform. Ensuing negotiations culminated in~~and entered into a settlement during the second quarter of ~~2018 between the parties which~~2018. The settlement resulted in certain transactions, including the release of reserves totaling $95 million to fund equity distributions to the partners, which reduced the equity at risk, and the prepayment of certain of the debt balance outstanding, and the amendment of certain of Ivanpah's governing documents. The equity distributions and prepayment of debt were funded by the agreed upon release of reserve funds. These events were considered to be a reconsideration event in accordance with ASC ~~810, Consolidations.~~810. As a result, NRG determined that it is not the primary beneficiary and deconsolidated Ivanpah. ~~NRG recognized a loss of~~ ~~$22 million~~ ~~on the deconsolidation and subsequent recognition of Ivanpah as an equity method investment during the~~ ~~six months ended~~ June 30, 2018. The deconsolidation of Ivanpah reduced the Company's assets by approximately $1.3 billion, which was primarily property, plant and equipment, and reduced the Company's liabilities by $1.2 billion, which was primarily long-term debt. NRG's maximum exposure to loss is limited to its equity investment, which was ~~$57 million~~ ~~as of June 30, 2018.~~

Entities that are Consolidated

The Company has a controlling financial interest in certain entities ~~which~~that have been identified as VIEs under ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases ~~and wind facilities~~ eligible for certain tax credits as further described in Note 2, Summary of Significant Accounting Policies to the Company's ~~2017~~2018 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $83 million as of June 30, 2018, which would be required to be funded if the arrangement were to be dissolved.

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


(In millions)	June 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Current assets	$	191	$	118	$	3	$	3
Net property, plant and equipment	2,709		2,337		75		76
Other long-term assets	660		658		27		28
Total assets	3,560		3,113		105		107
Current liabilities	119		96		1		2
Long-term debt	814		661		29		29
Other long-term liabilities	211		209		8		7
Total liabilities	1,144		966		38		38
Redeemable noncontrolling interest	69		78		18		19
Noncontrolling interest	660		507
Net assets less noncontrolling interest	$	1,687	$	1,562
Net assets less noncontrolling interests					$	49	$	50

Note 1011 — Changes in Capital Structure

As of ~~June 30, 2018~~March 31, 2019 and December 31, ~~2017~~2018, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:

Issued Treasury Outstanding
Balance as of December 31, 2017 418,323,134
(101,580,045 ) 316,743,089
Shares issued under LTIPs 1,373,655
—
1,373,655
Shares issued under ESPP —
175,862
175,862
Shares repurchased —
(14,863,301 ) (14,863,301 )
Balance as of June 30, 2018 419,696,789
(116,267,484 ) 303,429,305



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

Employee Stock Purchase Plan

In ~~January 2018, 175,862~~March 2019, the Company reopened participation in the ESPP, which allows eligible employees to elect to withhold between 1% and 10% of their eligible compensation to purchase shares of NRG common stock ~~were issued to employee accounts from treasury stock for~~at the lesser of 95% of its market value on the offering ~~period~~date or 95% of ~~July~~the fair market value on the exercise date. An offering date will occur each April 1 ~~2017, to December 31, 2017. In January 2018, NRG suspended the ESPP.~~and October 1. An exercise date will occur each September 30 and March 31.

Share Repurchases

During the three months ended March 31, 2019, the Company completed $250 million share repurchases in connection with the 2018 share repurchase program. In addition, in February ~~2018,~~2019, the Company's board of directors authorized ~~the~~an additional $1.0 billion share repurchase program to be executed in 2019. The Company ~~to repurchase $1 billion of its common stock, with the first~~completed $500 million ~~program beginning as soon as permitted. The following~~of share repurchases ~~have been made during the six months ended June 30, 2018.~~

Total number of shares purchased
Average price paid per share ^(a)

Amounts paid for shares purchased (in millions) ^(a)
Board Authorized Share Repurchases
First Quarter 2018 3,114,748

$ 93
Second Quarter 2018 ^(b)
11,748,553

407
Total Board Authorized Share Repurchases as of June 30, 2018 14,863,301
$ 500
July 2018 860,880

—
Total Board Authorized Share Repurchases as of August 2, 2018 15,724,181
$ 31.80
$ 500

~~(a) The~~at an average price ~~paid~~of $42.21 per share ~~and amounts paid for shares purchased exclude~~under the ~~commissions of $0.01 per share paid in connection with the share repurchase.~~

~~(b) The share repurchases for the second quarter include 9,969,023 of the shares repurchased~~2019 program through ~~the ASR Agreement, as described below.~~

~~Accelerated Share Repurchase~~May 2, 2019.

On ~~May 24, 2018,~~February 28, 2019, the Company executed an accelerated share repurchase agreement, or ASR Agreement, with a financial institution to repurchase a total of ~~$354~~$400 million of outstanding common stock based on a volume weighted average price. The Company received initial shares of ~~9,969,023,~~9,086,903, which were recorded in treasury stock at fair value based on the closing price on March 12, 2019, of ~~$343~~$390 million, with the remaining ~~$11~~$10 million recorded in additional paid in capital, representing the value of the forward contract to purchase additional shares. In ~~July 2018,~~April 2019, the financial institution delivered the remaining shares pursuant to the ASR ~~Agreement~~agreement and the Company received an351,768 additional ~~860,880~~ shares. The average price paid for all of the shares delivered under the ASR Agreement was ~~$32.69~~$42.38 per share. Upon receipt of the additional shares in April 2019, the Company transferred the ~~$11~~$10 million from additional paid in capital to treasury stock.

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



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

NRG Common Stock Dividends

~~The following table lists~~A quarterly dividend of $0.03 per share was paid on the ~~dividends paid~~Company's common stock during the ~~six~~three months ended ~~June 30, 2018:~~

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

$ 0.03

March 31, 2019. On ~~July 18, 2018,~~April 8, 2019, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable ~~August~~May 15, ~~2018,~~2019, to stockholders of record as of ~~August~~May 1, ~~2018,~~2019, representing $0.12 per share on an annualized basis.

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.

Note 1112 — ~~Earnings/(Loss)~~Earnings Per Share

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

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

Three months ended June 30, Six months ended June 30,
In millions, except per share data 2018 2017 2018 2017
Basic income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Net income/(loss) attributable to NRG Energy, Inc. $ 72
$ (626 ) $ 351
$ (790 )
Weighted average number of common shares outstanding - basic 310
316

314
316
Earnings/(loss) per weighted average common share — basic $ 0.23
$ (1.98 ) $ 1.12
$ (2.50 )
Diluted income/(loss) per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding - diluted 310
316
314
316
Incremental shares attributable to the issuance of equity compensation (treasury stock method) 4
—
4
—
Total dilutive shares 314
316
318
316
Earnings/(loss) per weighted average common share — diluted $ 0.23
$ (1.98 ) $ 1.10
$ (2.50 )



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

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

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


	Three months ended June 30,		Six months ended June 30,		Three months ended March 31,
In millions of shares	2018	2017	2018	2017	2019	2018
Equity compensation plans	—	6	1	6	—	1
Total	—	6	1	6

Note 1213 — Segment Reporting

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

~~During 2017, NRG Yield acquired several projects totaling 555 MW from NRG. On~~products. Intersegment sales are accounted for at market. The financial information for the three months ended March ~~30,~~31, 2018 the Company sold to NRG Yield, Inc. 100% of NRG's interests in Buckthorn Renewables, LLC, which owns a 154 MW construction-stage utility-scale solar generation project, located in Texas. These acquisitions were treated as a transfer of entities under common control and accordingly, all historical periods havehas been recast to reflect the ~~acquisitions as if they had occurred at the beginning of the financial statement period.~~current segment structure.

On ~~June 14, 2017,~~February 4, 2019, as described in Note 3,4, ~~Acquisitions,~~ Discontinued Operations and Dispositions, the Company completed the sale of and deconsolidated the South Central Portfolio. On August 31, 2018, as described in Note 4, Discontinued Operations and Dispositions, NRG deconsolidated ~~GenOn~~ NRG Yield, Inc., its Renewables Platform and Carlsbadfor financial reporting purposes. The financial information for ~~all historical periods have~~the three months ended March 31, 2018 has been recast to reflect the presentation of ~~GenOn~~these entities as discontinued operations within the corporate segment.

NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and capital for allocation, as well as net income/(loss).and net income/(loss) attributable to NRG Energy, Inc.

Retail^(a)

Generation^(a)

Renewables^(a)
NRG Yield
Corporate^(a)
Eliminations Total
Three months ended June 30, 2018 (In millions)
Operating revenues^(a)
$ 1,817
$ 1,218
$ 113
$ 307
$ 7
$ (540 ) $ 2,922
Depreciation and amortization 31
66
40
82
8
—
227
Impairment losses —
74
—
—
—
—
74
Reorganization costs 1
3
3
—
16
—
23
Equity in earnings/(losses) of unconsolidated affiliates —
—
5
29
—
(16 ) 18
(Loss)/income from continuing operations before income taxes (84 ) 273
(17 ) 103
(134 ) (12 ) 129
(Loss)/income from continuing operations (84 ) 272
(12 ) 96
(139 ) (12 ) 121
Loss from discontinued operations, net of tax —
—
—
—
(25 ) —
(25 )
Net (Loss)/Income (84 ) 272
(12 ) 96
(164 ) (12 ) 96
(Loss)/Income attributable to NRG Energy, Inc. $ (88 ) $ 272
$ (35 ) $ 73

$ (244 ) $ 94
$ 72
Total assets as of June 30, 2018 $ 7,217
$ 4,306
$ 4,117
$ 8,448
$ 9,675
$ (10,816 ) $ 22,947



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

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



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


	Retail^(a)		Generation^(a)			Renewables^(a)			NRG Yield		Corporate^(a)			Eliminations			Total			Three months ended March 31, 2018^(a)
Three months ended June 30, 2017	(In millions)
Operating revenues^(a)	$	1,603	$	882		$	119		$	288	$	3		$	(194	)	$	2,701
																				Retail		Generation			Corporate			Eliminations			Total
																				(In millions)
Operating revenues^(b)																				$	1,480	$	270		$	1		$	314		$	2,065
Depreciation and amortization	29		95			49			79		8			—			260			26		86			9			(1		)	120
Impairment losses	—		41			22			—		—			—			63
Equity in (losses)/earnings of unconsolidated affiliates	—		(15		)	(2		)	16		3			(5		)	(3		)
Reorganization costs																				3		4			13			—			20
Equity in earnings/(losses) of unconsolidated affiliates																				—		2			(1		)	—			1
Income/(loss) from continuing operations before income taxes	330		(89		)	(51		)	52		(134		)	(5		)	103			944		(573		)	(128		)	1			244
Income/(loss) from continuing operations	341		(90		)	(46		)	44		(145		)	(5		)	99			944		(573		)	(134		)	1			238
Loss from discontinued operations, net of tax	—		—			—			—		(741		)	—			(741		)	—		—			(5		)	—			(5		)
Net Income/(Loss)	341		(90		)	(46		)	44		(886		)	(5		)	(642		)	944		(573		)	(139		)	1			233
Net Income/(Loss) attributable to NRG Energy, Inc.	$	341	$	(90	)	$	(21	)	$	38	$	(919	)	$	25		$	(626	)	$	943	$	(565	)	$	(100	)	$	1		$	279

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



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

Retail^(a)

Generation^(a)

Renewables^(a)
NRG Yield
Corporate^(a)
Eliminations Total
Six months ended June 30, 2018 (In millions)
Operating revenues^(a)
$ 3,298
$ 1,545
$ 199
$ 532
$ 9
$ (240 ) $ 5,343
Depreciation and amortization 59
133
90
163
17
—
462
Impairment losses —
74
—
—
—
—
74
Reorganization costs 4
7
3
—
29
—
43
Equity in earnings/(losses) of unconsolidated affiliates —
2
5
33
(1 ) (23 ) 16
Income/(Loss) from continuing operations before income taxes 861
(264 ) (56 ) 102
(260 ) (22 ) 361
Income/(Loss) from continuing operations 861
(265 ) (45 ) 96
(271 ) (22 ) 354
Income from discontinued operations, net of tax —
—
—
—
(25 ) —
(25 )
Net Income/(Loss) 861
(265 ) (45 ) 96
(296 ) (22 ) 329
Net Income/(Loss) attributable to NRG Energy, Inc. $ 851
$ (265 ) $ (33 ) $ 94
$ (392 ) $ 96
$ 351

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

Retail ^(a)

Generation^(a)

Renewables^(a)
NRG Yield
Corporate^(a)
Eliminations Total
Six months ended June 30, 2017
Operating revenues^(a)
$ 2,938
$ 1,848
$ 213
$ 509
$ 11
$ (436 ) $ 5,083
Depreciation and amortization 57
192
96
156
16
—
517
Impairment losses —
41
22
—
—
—
63
Equity in (losses)/earnings of unconsolidated affiliates —
(28 ) (3 ) 35
7
(9 ) 2
Income/(loss) from continuing operations before income taxes 303
(52 ) (87 ) 49
(275 ) (9 ) (71 )
Income/(loss) from continuing operations 311
(54 ) (77 ) 42
(283 ) (9 ) (70 )
Loss from discontinued operations, net of tax —
—
—
—
(775 ) —
(775 )
Net Income/(loss) 311
(54 ) (77 ) 42
(1,058 ) (9 ) (845 )
Net Income/(loss) attributable to NRG Energy, Inc. $ 311
$ (54 ) $ (24 ) $ 50
$ (1,091 ) $ 18
$ (790 )

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

Note 1314 — Income Taxes

Effective Income Tax Rate

The income tax provision consisted of the following:

Three months ended June 30, Six months ended June 30,
In millions, except rates 2018 2017 2018 2017
Income/(Loss) before income taxes $ 129
$ 103
$ 361
$ (71 )
Income tax expense/(benefit) from continuing operations 8
4
7
(1 )
Effective tax rate 6.2 % 3.9 %
1.9 %
1.4 %



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

For the three ~~and six~~ months ended ~~June 30,~~March 31, 2019 and 2018,, NRG's overall effective tax rate was ~~different~~lower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance, ~~and the generation of PTCs from various wind facilities~~ partially offset by ~~the inclusion of consolidated partnerships and the~~ current state tax expense.

For the three months ended June 30, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax benefit for the change in valuation allowance and the generation of PTCs and ITCs from various wind and solar facilities, respectively, partially offset by the inclusion of consolidated partnerships and current state tax expense.

For the six months ended June 30, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the tax expense for the change in valuation allowance and current state tax expense, partially offset by the generation of PTCs and ITCs from various wind and solar facilities, respectively.

Uncertain Tax Benefits

As of ~~June 30, 2018,~~March 31, 2019, NRG has recorded a non-current tax liability of ~~$39~~$31 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of ~~June 30, 2018,~~March 31, 2019, NRG had cumulative interest and penalties related to these uncertain tax benefits of ~~$5 million~~.$5 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

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

Note 1415 — Related Party Transactions

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



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

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

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

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

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

GenOn ~~with~~— NRG provided various management, personnel and other services which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn, or the Services Agreement. The initial term of the Services Agreement was through December 31, 2013, with an automatic renewal absent a request for termination. The fee charged was determined based on a fixed amount as described in the Services Agreement and was calculated based on historical GenOn expenses prior to the NRG Merger. The annual fees under the Services Agreement were approximately $193 million and management has concluded that this method of charging overhead costs is reasonable. As described in Note 3, ~~Acquisitions, Discontinued Operations and Dispositions, in connection with the Restructuring Support Agreement, NRG agreed to provide shared services~~ to GenOn under the ~~Services Agreement for an adjusted annualized fee of $84 million.~~

~~In December 2017,~~transition services agreement in conjunction with the confirmation of the GenOn Entities' plan of reorganization, the Services Agreement was terminated and replaced by the transition services agreement. Under the transition services agreement, NRG provided the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments.reorganization. GenOn provided notice to NRG of its intent to terminate the transition services agreement effective August 15, 2018 and ~~in connection with the settlement agreement described in Note 3,~~ ~~Acquisitions, Discontinued Operations and Dispositions~~, all amounts owed and payable to NRG were settled against the $28 million credit provided for in the Restructuring Support Agreement. NRG may provide additional separation services that are necessary for or reasonably related to the operation of GenOn's business after such date, subject to NRG's prior written consent, not to be unreasonably withheld. For the three and six months ended June 30, 2018, NRG recorded approximately $21 million and $42 million, respectively, under the transition services agreement against selling, general and administrative expenses post-Chapter 11 Filing. For the three and six months ended June 30, 2017, NRG recorded other income - affiliate related to these services of $39 million and $87 million, respectively.settled.

~~Credit Agreement with GenOn~~

NRG and GenOn are party to a secured intercompany revolving credit agreement. The intercompany revolving credit agreement provided for a $500 million revolving credit facility, all of which was available for revolving loans and letters of credit. At June 30, 2018 and December 31, 2017, $45 million and $92 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement for GenOn. Additionally, as of June 30, 2018 and December 31, 2017, there were $151 million and $125 million, respectively, of loans outstanding under the intercompany secured revolving credit facility. In addition, the intercompany secured revolving credit facility contains customary covenants and events of default. As of June 30, 2018, GenOn was in default under the secured intercompany revolving credit agreement due to the filing of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, no additional revolving loans or letters of credit are available to GenOn. As the Restructuring Support Agreement provided that the borrowings be repaid to NRG at or prior to emergence, NRG recorded its affiliate receivable for the amount outstanding net within accrued expenses and other current liabilities - affiliate on the consolidated balance sheet as of June 30, 2018. Interest continued to accrue during the pendency of the Chapter 11 Cases until July 2018, when all borrowings and related interest were settled against amounts owed by the Company to GenOn as further discussed in Note 3 , ~~Acquisitions, Discontinued Operations and Dispositions, in connection with the settlement between NRG and GenOn.~~

~~Commercial Operations Agreement~~

NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the agreements are generally consistent with industry practices and other third party arrangements. As of June 30, 2018, derivative assets and liabilities associated with these transactions are recorded within NRG's derivative instruments balances on the consolidated balance sheet, with related revenues and costs within operating revenues and cost of operations, respectively. Additionally, as of June 30, 2018 and December 31, 2017, the Company had $24 million and $32 million, respectively, of cash collateral posted in support of energy risk management activities by GenOn.

Note 1516 — Commitments and Contingencies

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

Commitments

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding ~~assets acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and~~ NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of ~~June 30, 2018,~~March 31, 2019, all hedges under the first lien were ~~in-the-money~~out-of-the-money for NRG on a counterparty aggregate basis.

Jewett Mine Lignite Contract

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

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

Contingencies

The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, the Company has established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.

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

Midwest Generation Asbestos Liabilities— The Company, through its subsidiary, ~~Midwest Generation, may be subject to potential asbestos liabilities~~has been defending an asbestos-related indemnification claim brought by ComEd as a result of ~~its~~the Company's acquisition of EME. The ~~Company is currently analyzing~~parties have agreed to the ~~scope~~terms of ~~potential liability as it may relate to Midwest Generation. The Company believes~~a settlement that ~~it has established an adequate reserve for these cases. On March 27, 2018, ComEd filed a Motion to Compel Payments~~will resolve all of ~~Claims seeking $61 million related to asbestos liabilities. On April 25, 2018, NRG filed an Omnibus Objection to All Remaining Claims of ComEd and Exelon.~~

~~Midwest Generation New Source Review Litigation— In 2009, the EPA and the Illinois Attorney General, or the Government Plaintiffs, filed a complaint~~ComEd's outstanding claims in the U.S. District Court for the Northern District of Illinois alleging violations of CAA PSD requirements and opacity and PM regulations. Several environmental groups intervened as plaintiffs in this litigation. Midwest Generation moved to dismiss nine of the ten PSD counts. The trial court granted the motion in 2010. Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in 2013. On May 10, 2018, the district court approved the Consent Decree settling this litigation and dismissed the case. Pursuant to the Consent Decree, Midwest Generation has paid $500,000 to each of the State of Illinois and the Federal Government and has agreed to make and maintain certain operational improvements.

~~Telephone Consumer Protection Act Purported Class Actions~~ —Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC — one in California and two in New Jersey. The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages and equitable relief. On June 22, 2017, plaintiffs in the California case filed a motion for leave to file a second amended complaint to substitute new plaintiffs. Defendants filed an opposition to this motion on June 26, 2017. The court granted plaintiffs' motion to substitute new plaintiffs and on August 1, 2017, defendants filed an answer to the second amended complaint. On August 31, 2017, the court in the California case agreed that the litigation should be stayed pending final court approval of the New Jersey settlement. On July 12, 2017, the parties in one of the New Jersey actions reached an agreement in principle to resolve the class allegations which was confirmed by a term sheet signed by the parties on July 28, 2017. On September 27, 2017, plaintiffs in one of the New Jersey cases filed their motion for preliminary approval of the class settlement which was approved by the court on November 17, 2017. On May 14, 2018, the court entered a final order approving the class action settlement and dismissing the lawsuit, thereby ending the New Jersey lawsuits. On July 2, 2018, the court in the California case entered an order dismissing the lawsuit.matter.

California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC —- On January 29, 2016, CDWR and SDG&E (plaintiffs) filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power ~~Corporation.~~Corporation (defendants). In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR. At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not. As such, the plaintiffs brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions. Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed objections in response to the plaintiffs' complaint. The objections were granted on June 14, 2016; however, the plaintiffs were allowed to file amended complaints on July 1, 2016. On July 27, 2016, defendants filed objections to the amended complaints. On November 18, 2016, the court sustained the objections and allowed plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. On April 21, 2017, the court issued an order sustaining the objections without leave to amend. On July 14, 2017, ~~CDWR~~plaintiffs filed a notice of appeal. On January 10, 2018, ~~CDWR~~plaintiffs filed ~~its~~their opening appellate brief. Defendants filed their opposition brief on April 10, 2018. On May 30, 2018, ~~CDWR~~plaintiffs filed their reply brief.

~~Braun v. NRG Yield, Inc.~~ ~~— On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc.,~~ The case is now waiting for the ~~current and former members~~court of ~~its board of directors individually, and other parties in California Superior Court in Kern County, CA. Plaintiffs allege various violations of the Securities Act due~~appeal to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On July 30, 2018, the plaintiffs filed an opposition to the defendants’ motion to quash service of the summons and an opposition to the defendants’ demurrer.schedule oral argument.

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

~~Rice v. NRG~~ ~~— On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court~~ for the Western District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc. Plaintiffs generally claim personal injury, trespass, nuisance and property damage related to the disposal of coal ash from GenOn's Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property. Plaintiffs filed an amended complaint on August 14, 2017. On October 20, 2017, NRG filed its answers and affirmative defenses. On July 6, 2018, NRG filed a motion for summary judgment. Plaintiffs filed their opposition to the motion for summary judgment on July 29, 2018.certification.

Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen —- On June 28, 2017, plaintiffs Washington-St. Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against Louisiana Generating, L.L.C., or LaGen, in the United States District Court for the Middle District of Louisiana. The plaintiffs claim breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology. Plaintiffs seek damages for the alleged improper charges and a declaration as to which charges are proper under the contract. On September 14, 2017, the court issued a scheduling order setting this case for trial on October 21, 2019. LaGen filed its answer and affirmative defenses on November 17, 2017.

~~GenOn Chapter 11 Cases~~ — On February 4, 2019, NRG sold the ~~Petition Date,~~South Central Portfolio, including the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under the Restructuring Support Agreement to which the GenOn Entities, NRG and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them supported the Bankruptcy Court's approval of the plan of reorganization. GenOn has a customary "fiduciary out" under the Restructuring Support Agreement. If the plan of reorganization is not consummated, NRG may not be entitled to the benefits of the Settlement Agreement provided under the Restructuring Support Agreement and it will remainentities subject to ~~any claims of GenOn and the noteholders, including claims relating to or arising out of any shared services and any other relationships or transactions between the companies. See Note 3,~~ ~~Acquisitions, Discontinued Operations and Dispositions, for additional information related to the Chapter 11 Cases.~~

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

~~Morgantown v. GenOn Mid-Atlantic~~ — On June 8, 2017, Morgantown and Dickerson Owner Lessors filed a lawsuit against GenOn Mid-Atlantic, LLC, NRG North America LLC, GenOn Americas Generation, LLC, NRG Americas, Inc., GenOn Energy Holdings, Inc., GenOn Energy, Inc., and NRG Energy, Inc. in New York State Supreme Court. The plaintiffs allege that they were overcharged by defendants for certain services outlined in a Services Agreement and that defendants caused a Qualified Credit Support portion of a Participation Agreement, or QCS Agreement, to be violated by causing the transfer of certain money outside the allowable confines set forth in the QCS Agreement. In addition, plaintiffs claim that the transfers were unfairly executed and done so in an effort to defraud plaintiffs and hinder their ability to continue to do business. As such, plaintiffs seek, among other things, the return of certain transferred funds and service charges paid and to bar defendants from executing additional transfers on plaintiffs’ behalf. On November 7, 2017, the Bankruptcy Court issued an order estimating the claims to be valued at $0. On December 14, 2017, a settlement agreement was executed between GenOn and NRG. On April 27, 2018, the parties executed a mutual release which in conjunction with the settlement agreement resolved this lawsuit.

~~BTEC v. NRG Texas Power~~ — On July 18, 2017, BTEC New Albany LLC, or BTEC, filed a lawsuit against NRG Texas Power LLC, or NRG Texas Power, in the Harris County District Court in Texas. On January 15, 2013, the parties entered into a Membership Interest and Purchase Agreement, or MIPA, whereby BTEC agreed to dismantle, transport and rebuild an electric power generation facility at the former P.H. Robinson Electric Generating Station in Bacliff, Texas. The MIPA required BTEC to meet a Guaranteed Commercial Completion Date of May 31, 2016. Because BTEC had not satisfied all of the contractually-required acceptance criteria by the MIPA expiration date, NRG elected to terminate the contract in June 2017. BTEC claimed that NRG Texas Power breached the MIPA by improperly terminating it, and sought a declaratory judgment as to the rights and obligations of the parties as well as damages, interest and attorney’s fees. On September 7, 2017, NRG Texas Power filed a counterclaim seeking damages in excess of $48 million. On June 7, 2018, the parties resolved all claims and counterclaims in the lawsuit and a dismissal order was subsequently entered by the court on July 12, 2018.

~~GenOn Related Contingencies~~

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

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

On March 7, 2016, class plaintiffs filed their motions for class certification. On March 30, 2017, the court denied the plaintiffs' motions for class certification, which the plaintiffs appealed to. The plaintiffs petitioned the Ninth Circuit for interlocutory review. On July 12, 2018, the Ninth Circuit heard oral arguments and the case is under submission pending a decision.

On February 26, 2018, GenOn filed objections to the proofs of claim filed in the Chapter 11 Cases by all of the plaintiffs in each of the four cases. GenOn filed that same day a motion asking the Bankruptcy Court to estimate all of the proofs of claim at zero dollars, to which the plaintiffs objected. The Bankruptcy Court denied the plaintiffs' objection, ruling that it had the authority to consider GenOn's objections to the proofs of claim and to estimate the claims, but has certified its decision for review by either the Fifth Circuit Court of Appeals or the District Court.

In June 2018, GenOn reached a settlement with plaintiffs in three of the four remaining suits, which leaves only the one purported class action involving plaintiffs in Wisconsin. CenterPoint Energy Services is a defendant in that case, and GenOn has agreed to indemnify ~~CenterPoint against~~the purchaser for certain losses ~~relating to the lawsuit. The Nevada District Judge granted summary judgment~~suffered in ~~favor of CenterPoint in that lawsuit and the plaintiffs appealed that decision to the Ninth Circuit. The appeal was argued on February 16, 2018, and the case is under submission pending a decision.~~

connection therewith.

~~Mirant Chapter 11 Proceedings~~ — In July 2003, and various dates thereafter, the Mirant Debtors filed voluntary petitions in the U.S. Bankruptcy Court for the Northern District of Texas, Fort Worth Division, for relief under Chapter 11 of the Bankruptcy Code. GenOn Energy Holdings and most of the other Mirant Debtors emerged from bankruptcy on January 3, 2006, when the plan of reorganization that was approved in conjunction with Mirant Corporation's emergence from bankruptcy protection, or the Mirant Plan, became effective. The remaining Mirant Debtors emerged from bankruptcy on various dates in 2007. Approximately 461,000 of the shares of GenOn Energy Holdings common stock to be distributed under the Mirant Plan have not yet been distributed and have been reserved for distribution with respect to claims disputed by the Mirant Debtors that have not been resolved. Upon the Mirant/RRI Merger, those reserved shares converted into a reserve for approximately 1.3 million shares of GenOn common stock. Upon the NRG Merger, those reserved shares converted into a reserve for approximately 159,000 shares of NRG common stock. Under the terms of the Mirant Plan, upon the resolution of such a disputed claim, the claimant will receive the same pro rata distributions of common stock, cash, or both as previously allowed claims, regardless of the price at which the common stock is trading at the time the claim is resolved. If the aggregate amount of any such payouts results in the number of reserved shares being insufficient, additional shares of common stock may be issued to address the shortfall. The bankruptcy court is scheduled to hear a Motion for a Final Decree in the Mirant bankruptcy on October 17, 2018.

~~Potomac River Environmental Investigation~~—In March 2013, NRG Potomac River LLC, a subsidiary of GenOn, received notice that the District of Columbia Department of Environment (now renamed the Department of Energy and Environment, or DOEE) was investigating potential discharges to the Potomac River originating from the Potomac River Generating facility site, a site where the generation facility is no longer in operation. In connection with that investigation, DOEE served a civil subpoena on NRG Potomac River LLC requesting information related to the site and potential discharges occurring from the site. NRG Potomac River LLC provided various responsive materials. In January 2016, DOEE advised NRG Potomac River LLC that DOEE believed various environmental violations had occurred as a result of discharges DOEE believes occurred to the Potomac River from the Potomac River Generating facility site and as a result of associated failures to accurately or sufficiently report such discharges. DOEE has indicated it believes that penalties are appropriate in light of the violations. NRG Potomac River LLC is currently reviewing the information provided by DOEE.

~~Natixis v. GenOn Mid-Atlantic~~—On February 16, 2018, Natixis Funding Corp. and Natixis, New York Branch filed a complaint in the Supreme Court of the State of New York against GenOn Mid-Atlantic, the owner lessors under GenOn Mid-Atlantic’s operating leases of the Dickerson and Morgantown coal generation units, and the lease indenture trustee under those leases. The plaintiffs’ allegations against GenOn Mid-Atlantic relate to a payment agreement between GenOn Mid-Atlantic and Natixis Funding Corp. to procure credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson. The plaintiffs seek approximately $34 million in damages arising from GenOn Mid-Atlantic’s purported breach of certain warranties in the payment agreement. On April 2, 2018, GenOn Mid-Atlantic removed the allegations against it to the U.S. District Court for the Southern District of New York. On April 11, 2018, the U.S. District Court for the Southern District of New York entered a briefing schedule on a forthcoming motion to remand by Natixis Funding Corp. and a forthcoming motion to transfer by GenOn Mid-Atlantic. On April 26, 2018, Natixis Funding Corp. filed its motion to remand. On May 31, 2018, GenOn Mid-Atlantic opposed the motion to remand and filed a cross-motion to transfer. The parties completed briefing on the motions to remand and transfer on July 9, 2018, and the U.S. District Court for the Southern District of New York held an oral argument on July 18, 2018 and continued the motions to a subsequent conference scheduled for September 26, 2018.

Note 1617 — Regulatory Matters

~~This footnote should be read in conjunction with the complete description under Note 23,~~ ~~Regulatory Matters, to the Company's 2017 Form 10-K.~~ Environmental regulatory matters are discussed within Note ~~17,~~18, Environmental Matters, to this Form 10-Q.

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

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

~~National~~

~~Department of Energy Consideration of 202(c) and Defense Production Act~~ —On March 29, 2018, FirstEnergy Solutions requested that the Department of Energy provide price supports for its coal and nuclear units by having the DOE issue an emergency must-run order under Section 202(c) of the Federal Power Act. A number of parties have filed comments with the DOE, including PJM, challenging the assertion that the FirstEnergy Solutions’ units are necessary for grid reliability. The DOE has not yet formally responded. On June 1, 2018, the White House announced that President Trump has directed Secretary of Energy Rick Perry to "prepare immediate steps to stop the loss" of coal and nuclear resources. No formal timeline for action on either proposal has been set by the Administration.

Zero-Emission Credits for Nuclear Plants in Illinois and New York— - In 2016, Illinois enacted a Zero Emission Credit, or ZEC, program for selected nuclear units in Illinois. In total, the program directs over $2.5 billion over ten years to two Exelon-owned nuclear power plants in Illinois. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On February 14, 2017, NRG, along with other companies, filed a complaint in the U.S. District Court for the Northern District of Illinois alleging that the state program is preempted by federal law and in violation of the dormant commerce clause. On July 14, 2017, Defendants' motions to dismiss were granted. On July 17, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Seventh Circuit. Briefing is complete. On May 29, 2018, the United States filed an amicus brief at the invitation of the Seventh Circuit arguing that the ZEC program is not preempted.

~~Zero-Emission Credits for Nuclear Plants in New York~~ ~~— On August 1, 2016,~~That same year, the NYSPSC issued its Clean Energy Standard, or CES, which ~~provided~~provides for ZECs which would provide more than $7.6 billion over 12 years in out-of-market subsidy payments to certain selected nuclear generating units in ~~the state.~~New York. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. ~~On October 19, 2016,~~ NRG, along with other companies, filed ~~a complaint~~complaints in the ~~U.S. District Court for the Southern District~~federal courts of Illinois and New York ~~challenging the validity~~alleging that these state programs are preempted by federal law and in violation of the ~~NYSPSC action~~dormant commerce clause. These cases have proceeded through the federal district court as well as the federal appellate court in Illinois and ~~the ZEC program. On July 25, 2017, Defendants' motions to dismiss~~New York, respectively. Petitions for Writ of Certiorari were ~~granted.~~filed and were subsequently denied on April 15, 2019.

South Central - On August 24, 2017, NRG, along with other plaintiff companies, filed a notice of appeal to the U.S. Court of Appeals for the Second Circuit. Briefing is complete. On May 29, 2018, the United States filed an amicus brief at the invitation of the Seventh Circuit arguing that the ZEC program is not preempted.

~~Department of Energy's Proposed Grid Resiliency Pricing Rule and Subsequent FERC Proceeding —~~ On September 29, 2017, the Department of Energy issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC to take action to reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 2, 2017, FERC issued a notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to address. On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner compatible with robust competitive markets. On January 8, 2018, FERC terminated the proposed rulemaking and opened a new proceeding asking each ISO/RTO to address specific questions focused on grid resilience. On March 9, 2018, the ISOs/RTOs filed comments to the questions posed by FERC. The Company responded on May 9, 2018 and is currently awaiting a decision from FERC.

~~East/West~~

~~Montgomery County Station Power Tax~~—~~On December 20, 2013,~~2016, NRG received a ~~letter~~document hold notice from ~~Montgomery County, Maryland requesting payment~~FERC regarding conduct in the MISO and PJM markets. It required NRG to retain communications related to multiple generating units in the South Central region. Since sending the notice, FERC has been investigating potential violations of ~~an energy tax~~MISO rules involving bidding for the ~~consumption~~Big Cajun 2 facility, as well as other aspects of ~~station power at~~NRG’s operations in MISO. FERC has the ~~Dickerson Facility over~~authority to require disgorgement of profits and to impose penalties and NRG retains any liability following the ~~previous three years. Montgomery County seeks payment~~sale of the South Central Portfolio. We expect a preliminary finding from FERC by the second quarter of 2019.

ISO-NE - On February 5, 2019, FERC has informed the Company that it has made a preliminary finding that the Company violated FERC's market behavior rules in connection with offers made into the ISO-NE Forward Capacity Auction in 2016. The Company understands that FERC is concerned that the Company was inaccurate in its communications with the Market Monitor regarding the costs and risks associated with operating certain units in the ~~amount of $22 million, which includes tax, interest and penalties.~~forward timeframe. NRG ~~disputed~~withdrew the applicability of the tax. On December 11, 2015, the Maryland Tax Court reversed Montgomery County's assessment. Montgomery County filed an appeal, and on February 2, 2017, the Montgomery County Circuit Court affirmed the decision of the tax court. On February 17, 2017, Montgomery County filed an appealbids prior to the ~~Court~~2016 auction in the normal course of ~~Special Appeals of Maryland. On April 24, 2018, the Court of Special Appeals of Maryland affirmed the lower court's~~our commercial business decision ~~and on May 29, 2018, Montgomery County petitioned the Court of Appeals of Maryland to issue a writ of certiorari to review that decision. NRG filed an answer opposing the petition on June 18, 2018.~~making. The ~~petition is currently pending before the Court of Appeals of Maryland.~~Company will be engaging in discussions with FERC regarding this matter.

~~Puente Power Project~~ — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months, which was granted on November 3, 2017. On May 31, 2018, the CEC extended the suspension period at NRG's request to July 1, 2019. The supplemental extension period should allow sufficient time to determine whether alternate procurement efforts undertaken by SCE supersede the need for the Puente Power Project.

Note 1718 — Environmental Matters

~~This footnote should be read in conjunction with the complete description under Note 24,~~ ~~Environmental Matters, to the Company's~~ ~~2017~~ ~~Form 10-K.~~

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

Air

~~The~~On August 31, 2018, EPA ~~finalized CSAPR in 2011,~~proposed replacing the Clean Power Plan (CPP) rule, which ~~was intended~~sought to replace CAIR in January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SObroadly regulate CO₂ ~~budgets for four~~emissions from the power sector, with the Affordable Clean Energy (ACE) rule, which if finalized, would require states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to ~~account for the more stringent 2008 Ozone NAAQS and~~develop plans to ~~address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit.~~seek heat rate improvements from coal-fired EGUs. The Company believes that the ACE rule replacing the CPP rule would on balance be positive for its ~~investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.~~generation fleet.

In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April ~~2015 (with some units getting a 1-year extension).~~2015. In ~~June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that~~December 2018, the EPA ~~unreasonably refused to consider costs when it determined~~proposed a finding that itregulating HAPs was not "appropriate and necessary" ~~to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacate~~because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In December 2015, the D.C. Circuit remanded the MATS rule to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. ~~On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the case in abeyance.~~ While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.

Water

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

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, ~~or FGD,~~ fly ash, bottom ash, and flue gas mercury control. ~~In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines.~~ On September 18, 2017, the EPA promulgated a final rule that, ~~(i)~~among other things, postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next ~~rulemaking and (ii) withdrew~~rulemaking. On April 12, 2019, the ~~April 2017 administrative stay. The legal challenges have been suspended while~~United States Court of Appeals for the ~~EPA reconsiders and likely modifies~~Fifth Circuit released its opinion remanding portions of the ~~rule.~~rule to the EPA. Accordingly, the Company has ~~largely~~ eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the rule is revised.

Byproducts, Wastes, Hazardous Materials and Contamination

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

~~East/West~~

~~New Source Review~~ — The ~~EPA and various states have been investigating compliance of electric generating facilities with the pre-construction permitting requirements~~Company will determine estimates of the ~~CAA known as “new source review,” or NSR. In 2007, Midwest Generation received an NOV from~~cost of compliance after the EPA alleging that past work at Crawford, Fisk, Joliet, Powerton, Waukegan and Will County generating stations violated NSR and other regulations. These alleged violations are the subject of litigation described in Note 15, ~~Commitments and Contingencies.~~ Additionally, in April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at oil-fired combustion turbines at the Torrington Terminal, Franklin, Branford and Middletown generating stations violated regulations regarding NSR.

rule is revised.

Note 1819 — Condensed Consolidating Financial Information

As of ~~June 30, 2018~~March 31, 2019, the Company had outstanding ~~$5.4~~$4.4 billion of Senior Notes due from ~~2022~~2024 to 2048, as shown in Note 89, Debt and Capital Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic ~~subsidiaries, and NRG Yield, Inc. and its~~ subsidiaries.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of ~~June 30, 2018~~March 31, 2019:



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

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

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

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended ~~June 30, 2018~~March 31, 2019

(Unaudited)

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

Eliminations^(a)
Consolidated
(In millions)
Operating Revenues
Total operating revenues $ 2,276
$ 659
$ —
$ (13 ) $ 2,922
Operating Costs and Expenses
Cost of operations 1,778
282
(4 ) (5 ) 2,051
Depreciation and amortization 76
143
8
—
227
Impairment losses —
74
—
—
74
Selling, general and administrative 110
34
77
(10 ) 211
Reorganization costs 1
—
22
—
23
Development costs —
13
3
—
16
Total operating costs and expenses 1,965
546
106
(15 ) 2,602
Gain on sale of assets —
14
—
—
14
Operating Income/(Loss) 311
127
(106 ) 2
334
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries 7
—
355
(362 ) —
Equity in earnings of unconsolidated affiliates —
18
—
—
18
Other income/(expense), net 4
(26 ) 2
—
(20 )
Loss on debt extinguishment, net —
—
(1 ) —
(1 )
Interest expense (4 ) (92 ) (106 ) —
(202 )
Total other income/(expense) 7
(100 ) 250
(362 ) (205 )
Income Before Income Taxes 318
27
144
(360 ) 129
Income tax expense/(benefit) 108
(68 ) (32 ) —
8
Income from Continuing Operations 210
95
176
(360 ) 121
Loss from discontinued operations, net of income tax —
—
(25 ) —
(25 )
Net Income 210
95
151
(360 ) 96
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests —
(57 ) 79
2
24
Net Income Attributable to
NRG Energy, Inc.
$ 210
$ 152
$ 72
$ (362 ) $ 72


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS~~

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

~~(Unaudited)~~


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)															(In millions)
Operating Revenues
Total operating revenues	$	4,120		$	1,249		$	—		$	(26	)	$	5,343		$	1,769		$	395		$	—		$	1		$	2,165
Operating Costs and Expenses
Cost of operations	3,004			613			9			(17		)	3,609			1,358			283			9			1			1,651
Depreciation and amortization	149			297			16			—			462			54			23			8			—			85
Impairment losses	—			74			—			—			74
Selling, general and administrative	213			60			139			(10		)	402			122			16			56			—			194
Reorganization costs	3			—			40			—			43			—			—			13			—			13
Development costs	—			23			7			(1		)	29			—			—			2			—			2
Total operating costs and expenses	3,369			1,067			211			(28		)	4,619			1,534			322			88			1			1,945
Gain on sale of assets	3			13			—			—			16			1			—			—			—			1
Operating Income/(Loss)	754			195			(211		)	2			740			236			73			(88		)	—			221
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	9			—			685			(694		)	—			10			—			299			(309		)	—
Equity in earnings/(losses) of unconsolidated affiliates	—			17			(1		)	—			16
Other income/(expense), net	8			(36		)	5			—			(23		)
Loss on debt extinguishment, net	—			—			(3		)	—			(3		)
Equity in losses of unconsolidated affiliates																—			(21		)	—			—			(21		)
Other income, net																4			1			7			—			12
Interest expense	(7		)	(164		)	(198		)	—			(369		)	(4		)	(4		)	(106		)	—			(114		)
Total other income/(expense)	10			(183		)	488			(694		)	(379		)	10			(24		)	200			(309		)	(123		)
Income Before Income Taxes	764			12			277			(692		)	361
Income tax expense/(benefit)	221			(20		)	(194		)	—			7
Income from Continuing Operations Before Income Taxes																246			49			112			(309		)	98
Income tax expense																—			—			4			—			4
Income from Continuing Operations	543			32			471			(692		)	354			246			49			108			(309		)	94
Loss from discontinued operations, net of income tax	—			—			(25		)	—			(25		)
Net Income	543			32			446			(692		)	329
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—			(119		)	95			2			(22		)
Income from discontinued operations, net of income tax																9			5			374			—			388
Net Income Attributable to NRG Energy, Inc.	$	543		$	151		$	351		$	(694	)	$	351		$	255		$	54		$	482		$	(309	)	$	482


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the three months ended ~~June 30, 2018~~March 31, 2019

(Unaudited)

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

Eliminations^(a)
Consolidated
(In millions)
Net Income $ 210
$ 95
$ 151
$ (360 ) $ 96
Other Comprehensive Income, net of tax
Unrealized gain on derivatives, net —
4
6
(5 ) 5
Foreign currency translation adjustments, net (4 ) (4 ) (5 ) 9
(4 )
Available-for-sale securities, net

—
—
1
—
1
Defined benefit plans, net —
—
(1 ) —
(1 )
Other comprehensive (loss)/income (4 ) —
1
4
1
Comprehensive Income 206
95
152
(356 ) 97
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest —
(57 ) 81
2
26
Comprehensive Income Attributable to NRG Energy, Inc. $ 206
$ 152
$ 71
$ (358 ) $ 71


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

~~NRG ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME~~

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

~~(Unaudited)~~

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

Eliminations^(a)
Consolidated
(In millions)
Net Income $ 543
$ 32
$ 446
$ (692 ) $ 329
Other Comprehensive (Loss)/Income, net of tax
Unrealized gain on derivatives, net —
20
21
(22 ) 19
Foreign currency translation adjustments, net (6 ) (6 ) (8 ) 14
(6 )
Available-for-sale securities, net —
—
1
—
1
Defined benefit plans, net —
—
(2 ) —
(2 )
Other comprehensive (loss)/income (6 ) 14
12
(8 ) 12
Comprehensive Income 537
46
458
(700 ) 341
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest —
(119 ) 105
2
(12 )
Comprehensive Income Attributable to NRG Energy, Inc. $ 537
$ 165
$ 353
$ (702 ) $ 353



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


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

~~June 30, 2018~~March 31, 2019

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated		Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)													(In millions)
Current Assets
Cash and cash equivalents	$	71	$	395		$	514		$	—		$	980	$	—	$	27		$	832		$	—		$	859
Funds deposited by counterparties	71		—			—			—			71		11		—			—			—			11
Restricted cash	9		277			—			—			286		12		3			—			—			15
Accounts receivable, net	1,094		274			3			—			1,371		1,228		199			159			(688		)	898
Inventory	309		176			—			—			485		277		114			—			—			391
Derivative instruments	837		36			15			(37		)	851		610		21			15			(35		)	611
Cash collateral paid in support of energy risk management activities	209		15			—			—			224		367		21			—			—			388
Accounts receivable - affiliate	1,189		123			141			(1,396		)	57
Current assets - held for sale	—		100			—			—			100
Prepayments and other current assets	173		122			35			(2		)	328		192		11			82			—			285
Total current assets	3,962		1,518			708			(1,435		)	4,753		2,697		396			1,088			(723		)	3,458
Property, plant and equipment, net	2,402		10,164			231			(23		)	12,774		1,512		987			151			—			2,650
Other Assets
Investment in subsidiaries	486		—			8,111			(8,597		)	—		477		—			3,765			(4,242		)	—
Equity investments in affiliates	—		1,055			—			—			1,055		—		387			—			—			387
Notes receivable, less current portion	—		15			—			—			15
Operating lease right-of-use assets, net														95		289			133			—			517
Goodwill	360		179			—			—			539		360		213			—			—			573
Intangible assets, net	415		1,448			—			(3		)	1,860		414		166			—			—			580
Nuclear decommissioning trust fund	694		—			—			—			694		718		—			—			—			718
Derivative instruments	329		61			38			(2		)	426		334		8			14			(9		)	347
Deferred income tax	156		34			(64		)	—			126		6		(145		)	184			—			45
Non-current assets held-for-sale	—		50			—			—			50
Other non-current assets	81		454			120			—			655		143		30			94			(12		)	255
Total other assets	2,521		3,296			8,205			(8,602		)	5,420		2,547		948			4,190			(4,263		)	3,422
Total Assets	$	8,885	$	14,978		$	9,144		$	(10,060	)	$	22,947	$	6,756	$	2,331		$	5,429		$	(4,986	)	$	9,530
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—	$	862		$	92		$	(2	)	$	952	$	—	$	108		$	16		$	—		$	124
Current portion of operating lease liabilities														23		30			21			—			74
Accounts payable	699		230			46			—			975		1,515		(218		)	88			(688		)	697
Accounts payable — affiliate	1,901		(207		)	(269		)	(1,396		)	29
Derivative instruments	695		51			—			(37		)	709		505		19			—			(35		)	489
Cash collateral received in support of energy risk management activities	72		—			—			—			72		11		—			—			—			11
Current liabilities held-for-sale	—		74			—			—			74
Accrued expenses and other current liabilities	270		123			326			—			719		244		57			249			—			550
Accrued expenses and other current liabilities-affiliate	—		—			133			—			133
Total current liabilities	3,637		1,133			328			(1,435		)	3,663		2,298		(4		)	374			(723		)	1,945
Other Liabilities
Long-term debt and capital leases	245		7,428			7,148			—			14,821		245		112			6,021			(12		)	6,366
Non-current operating lease liabilities														77		320			132			—			529
Nuclear decommissioning reserve	274		—			—			—			274		286		—			—			—			286
Nuclear decommissioning trust liability	410		—			—			—			410		423		—			—			—			423
Derivative instruments														354		5			—			(9		)	350
Deferred income taxes	112		64			(159		)	—			17		112		60			(110		)	—			62
Derivative instruments	237		50			—			(2		)	285
Out-of-market contracts, net	58		137			—			—			195
Non-current liabilities held-for-sale	—		12			—			—			12
Other non-current liabilities	410		311			409			—			1,130		408		149			532			—			1,089
Total non-current liabilities	1,746		8,002			7,398			(2		)	17,144
Total liabilities	5,383		9,135			7,726			(1,437		)	20,807
Total other liabilities														1,905		646			6,575			(21		)	9,105
Total Liabilities														4,203		642			6,949			(744		)	11,050
Redeemable noncontrolling interest in subsidiaries	—		69			—			—			69		—		18			—			—			18
Stockholders’ Equity	3,502		5,774			1,418			(8,623		)	2,071		2,553		1,671			(1,520		)	(4,242		)	(1,538		)
Total Liabilities and Stockholders’ Equity	$	8,885	$	14,978		$	9,144		$	(10,060	)	$	22,947	$	6,756	$	2,331		$	5,429		$	(4,986	)	$	9,530

Environmental Regulatory Matters

NRG is subject to numerous environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Federal and state environmental laws historically have become more stringent over time. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on our operations, which could affect the Company's operations. Complying with environmental laws often involves significant capital and operating expenses, as well as occasionally curtailing operations. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.

A number of regulations that may affect the Company are under review by the EPA, including ESPS for GHGs, ash disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated legal challenges are resolved. The Company’s environmental matters are described in the Company’s ~~2017~~2018 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in ~~Item 1 —~~ Note ~~17,~~18, Environmental Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q and as follows.

Air

The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO₂, ozone, and PM2.5. Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent air regulations could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting the Company are described below.

MATS — In 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015. In December 2018, the EPA proposed a finding that regulating HAPs was not "appropriate and necessary" because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the MATS rule. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.

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

Byproducts, Wastes, Hazardous Materials and Contamination

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

~~Water~~Domestic Site Remediation Matters

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

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

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

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

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

—Water

The Company is required under the CWA to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations have become more stringent and imposed new requirements.

Once Through Cooling Regulation — In August 2014, EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. While NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are ~~renewed.~~renewed, the Company anticipates the cost of complying with these restrictions to be immaterial.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, ~~or FGD,~~ fly ash, bottom ash, and flue gas mercury control. ~~In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines.~~ On September 18, 2017, the EPA promulgated a final rule that, ~~(i)~~among other things, postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next ~~rulemaking~~rulemaking. On April 12, 2019, the United States Court of Appeals for the Fifth circuit addressed challenges to the rule brought by several environmental groups related to legacy wastewaters and ~~(ii) withdrew~~coal ash leachate and remanded portions of the ~~April 2017 administrative stay.~~rule to the EPA. The ~~legal challenges have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the~~ Company has ~~largely~~ eliminated its estimate of the environmental capital expenditures that would have been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the ~~rule is revised.~~EPA revises the rule.

Regional Environmental Developments

~~Texas Regional Haze~~Burton Island Old Ash Landfill — ~~On October 17, 2017,~~In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the ~~EPA promulgated~~Indian River facility. In December 2015, DNREC approved the Company's remediation design, the Company's Closure Report and the Company's Long Term Stewardship Plan. The cost of completing the work required by the approved remediation plan is consistent with amounts budgeted in early 2016 and remediation was completed in 2017. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in 2016.

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

In February 2019, NY DEC proposed a ~~Texas-only SO~~₂~~cap-and-trade program to address regional haze. The program is scheduled to begin~~more stringent NOx regulation that depending on ~~January 1, 2019. Several~~the outcome of the ~~Company's units in Texas will be affected by this rule. The rule has been challenged by several environmental groups~~regulatory process, may result in the ~~Fifth Circuit~~retirement of some of our combustion turbines in New York.

In March 2019, Illinois State Bill 9 was introduced regarding coal ash. The Company and other stakeholders are working with government officials to propose modifications to the Bill. Depending on the outcome of the ~~U.S. Court of Appeals, which litigation has been stayed pending resolution of administrative petitions for reconsideration.~~

legislative process, such a new law may be unfavorable to the Company's Midwest Generation facilities.

Significant Events

The following significant events have occurred during ~~2018,~~2019, in addition to the Transformation Plan events, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:

~~NRG Transformation Plan~~Power Purchase Agreements

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

~~XOOM Energy Acquisition~~Share Repurchases

On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer operating in 19 states, Washington, D.C. and Canada for approximately $219 million in cash, inclusive of approximately $54 million in payments for estimated working capital, which is subject to further adjustment. The acquisition increased NRG's retail portfolio by approximately 300,000 customers in the aggregate by June 30, 2018.

~~Ivanpah Deconsolidation~~

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

~~Financing Activities~~

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

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

On June 19, 2018, the Company entered into an amended and restated Thermal note purchase and private shelf agreement whereas it authorized the issuance of the Series E Notes, Series F Notes, Series G Notes, and Series H Notes, as discussed in more detail in Note 8, ~~Debt and Capital Leases~~.

~~During the six~~three months ended ~~June 30, 2018,~~March 31, 2019, the Company repurchased ~~$43~~6,153,415 shares for $250 million to complete the 2018 program. In addition, in ~~aggregate principal of its Senior Notes in the open market for $45 million, including accrued interest as discussed in more detail in Note 8,~~ ~~Debt and Capital Leases~~. ~~In July 2018, the Company repurchased an additional $46 million in aggregate principal of its Senior Notes in the open market for $48 million including accrued interest.~~

On August 1, 2018, the Company announced that it gave the required notice under the indenture governing its 6.25% Senior Notes due 2022, or the 2022 Notes, to redeem for cash $486 million aggregate principal amount of its 2022 Notes, or the Partial Redemption, on August 31, 2018, or the Redemption Date. The redemption price for the 2022 Notes will be 103.125% of the principal amount of the 2022 Notes, plus accrued and unpaid interest to the Redemption Date. The Partial Redemption, combined with recently completed open market repurchases of approximately $89 million of the Company's outstanding indebtedness, will result in the retirement of outstanding indebtedness equal to approximately $575 million which is the aggregate principal amount of the Company's 2.75% convertible senior notes due 2048 issued on May 24, 2018.

~~Share Repurchases~~

In February ~~2018,~~2019, the Company's board of directors authorized an additional $1.0 billion share repurchase program to be executed into 2019. The Company repurchased 11,846,450 shares for $500 million at an average price of $42.21 per share under the ~~Company to repurchase $1 billion~~2019 program through May 2, 2019, of ~~its common stock, with~~which 11,455,542 shares were repurchased during the first ~~$500 million program beginning as soon as permitted. In March 2018, the Company repurchased 3,114,748 shares of NRG common stock~~quarter for ~~approximately $93~~$499 million. During the second quarter of 2018, the Company repurchased 11,748,553 shares of NRG common stock for approximately $407 million, including shares repurchased under the ASR Agreement. In July 2018, the Company received an additional 860,880 shares in connection with the settlement of the ASR Agreement, completing the $500 million of share repurchases. The average cost per share for the total $500 million of shares repurchased was $31.80.

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s ~~2017~~2018 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - ~~Trends Affecting Results of Operations and Future~~ Business ~~Performance,~~ ~~and below.~~Environment.

~~ERCOT Pricing~~ — ERCOT forward prices for July and August 2018 are significantly higher than where previous summers have settled. These elevated pricing levels mean that deviations from expected demand and/or generation availability may have a material impact on the Company’s actual results.

Changes in Accounting Standards

See Note 2, Summary of Significant Accounting Policies, to the Condensed Consolidated Financial Statements of this Form 10-Q, for a discussion of recent accounting developments.

Consolidated Results of Operations

The following table provides selected financial information for the Company:


	Three months ended June 30,									Six months ended June 30,									Three months ended March 31,
(In millions except otherwise noted)	2018			2017			Change			2018			2017			Change			2019			2018			Change
Operating Revenues
Energy revenue^(a)	$	673		$	656		$	17		$	1,292		$	1,243		$	49		$	306		$	443		$	(137	)
Capacity revenue^(a)	313			297			16			601			559			42			154			142			12
Retail revenue	1,816			1,605			211			3,302			2,946			356			1,606			1,485			121
Mark-to-market for economic hedging activities	15			41			(26		)	(91		)	159			(250		)	20			(96		)	116
Contract amortization	(14		)	(14		)	—			(28		)	(29		)	1
Other revenues ^(b)	119			116			3			267			205			62			79			91			(12		)
Total operating revenues	2,922			2,701			221			5,343			5,083			260			2,165			2,065			100
Operating Costs and Expenses
Cost of sales ^(c)	1,515			1,422			(93		)	2,908			2,683			(225		)	1,341			1,322			(19		)
Mark-to-market for economic hedging activities	86			(18		)	(104		)	(216		)	118			334			—			(302		)	(302		)
Contract and emissions credit amortization ^(c)	7			8			1			13			16			3			5			6			1
Operations and maintenance	360			340			(20		)	730			712			(18		)	248			292			44
Other cost of operations	83			89			6			174			175			1			57			67			10
Total cost of operations	2,051			1,841			(210		)	3,609			3,704			(95		)	1,651			1,385			(266		)
Depreciation and amortization	227			260			33			462			517			55			85			120			35
Impairment losses	74			63			(11		)	74			63			(11		)
Selling, general and administrative	211			221			10			402			481			79			194			176			(18		)
Reorganization costs	23			—			(23		)	43			—			(43		)	13			20			7
Development costs	16			18			2			29			35			6			2			5			3
Total operating costs and expenses	2,602			2,403			(199		)	4,619			4,800			181			1,945			1,706			(239		)
Other income - affiliate	—			39			(39		)	—			87			(87		)
Gain on sale of assets	14			2			12			16			4			12			1			2			(1		)
Operating Income	334			339			(5		)	740			374			366			221			361			(140		)
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	18			(3		)	21			16			2			14
Other (losses)/income, net	(20		)	14			(34		)	(23		)	26			(49		)
Equity in (losses)/earnings of unconsolidated affiliates																			(21		)	1			(22		)
Other income, net																			12			—			12
Loss on debt extinguishment, net	(1		)	—			(1		)	(3		)	(2		)	(1		)	—			(2		)	2
Interest expense	(202		)	(247		)	45			(369		)	(471		)	102			(114		)	(116		)	2
Total other expense	(205		)	(236		)	31			(379		)	(445		)	66			(123		)	(117		)	(6		)
Income/(Loss) from Continuing Operations before Income Taxes	129			103			26			361			(71		)	432
Income tax expense/(benefit)	8			4			4			7			(1		)	8
Income/(Loss) from Continuing Operations	121			99			22			354			(70		)	424
Loss from discontinued operations, net of income tax	(25		)	(741		)	716			(25		)	(775		)	750
Net Income/(Loss)	96			(642		)	738			329			(845		)	1,174
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	24			(16		)	40			(22		)	(55		)	33
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	72		$	(626	)	$	698		$	351		$	(790	)	$	1,141
Income from Continuing Operations before Income Taxes																			98			244			(146		)
Income tax expense																			4			6			(2		)
Income from Continuing Operations																			94			238			(144		)
Income/(loss) from discontinued operations, net of income tax																			388			(5		)	393
Net Income																			482			233			249
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest																			—			(46		)	46
Net Income Attributable to NRG Energy, Inc.																			$	482		$	279		$	203
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	2.80		$	3.18		(12		)%	$	2.90		$	3.25		(11		)%	$	3.15		$	3.00		5		%

Other Cost of Operations



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

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



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

Depreciation and amortization

Depreciation and amortization decreased by ~~$33~~$35 million for the three months ended ~~June 30, 2018,~~March 31, 2019, compared to the three months ended ~~June 30, 2017,~~March 31, 2018, driven primarily by ~~the impairment of property, plant and equipment in prior years as well as~~ the deconsolidation of Ivanpah in May ~~2018.~~

~~Impairment Losses~~

~~For the three months ended June 30,~~2018, Agua Caliente in August 2018, the ~~Company recorded impairment losses~~sale of ~~$74 million related to the impairment of the Keystone~~Cottonwood in February 2019 and ~~Conemaugh generating stations, as well and the impairment of the Dunkirk project, as described in Note 7,~~ ~~Impairments~~.prior year impairments.

Selling, General and Administrative

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

Retail Generation Renewables NRG Yield Corporate Total
(In millions)
Three months ended June 30, 2018 $ 126

$ 55

$ 12

$ 7

$ 11

$ 211
Three months ended June 30, 2017 106

52

14

7

42

221



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

Selling, general and administrative expenses ~~decreased~~increased by ~~$10~~$18 million for the three months ended ~~June 30, 2018,~~March 31, 2019, compared to the same period in ~~2017,~~2018, due to the following:

(In millions)
Decrease in general and administrative expense from cost initiatives for the Transformation Plan $ (36 )
Prior year fees associated with advisors engaged to assist the Company in its strategic review in 2017 (6 )
Increase in bad debt expense primarily from increased usage due to weather 6
Increase in expense for estimated legal settlements 10
Increase in selling and marketing expense associated with costs incurred for margin enhancement initiatives 16
$ (10 )



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

~~Reorganization Costs~~

~~Reorganization costs of $23 million, primarily related to employee costs, were incurred as part of the Transformation Plan.~~

~~Other Income - Affiliate~~

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

~~Gain on Sale of Assets~~

Gain on sale of assets for the three months ended June 30, 2018, consists primarily of the gain on the sale of Canal 3, while the gain on sale of assets for the three months ended June 30, 2017, represents a gain on the sale of land.

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

Equity in earnings of consolidated affiliates increased by $21 million for the three months ended June 30, 2018, compared to the three months ended June 30, 2017, which was primarily driven by the equity in earnings recorded in 2018 for Ivanpah after deconsolidation, as well as by prior year losses from Petra Nova Parish Holdings, offset by the prior period HLBV income allocated to the Company’s interests in the Utah Portfolio.

~~Other (Losses)/Income, Net~~

Other losses for the three months ended June 30, 2018, primarily relate to the loss on deconsolidation of Ivanpah of $22 million. Other income for the three months ended June 30, 2017, primarily relates to dividends received from cost method investments as well as income from pension and postretirement investments.

~~Interest~~Mark-to-market for Economic Hedging Activities

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

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



	Three months ended March 31, 2019
				Generation
	Retail			Texas			East/West/Other			Eliminations^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—		$	(79	)	$	(22	)	$	93		$	(8	)
Net unrealized gains/(losses) on open positions related to economic hedges	—			92			14			(78		)	28
Total mark-to-market gains/(losses) in operating revenues	$	—		$	13		$	(8	)	$	15		$	20
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	115		$	3		$	2		$	(93	)	$	27
Reversal of acquired gain positions related to economic hedges	(2		)	—			—			—			(2		)
Net unrealized (losses)/gains on open positions related to economic hedges	(121		)	15			3			78			(25		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(8	)	$	18		$	5		$	(15	)	$	—


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



	Three months ended March 31, 2018
				Generation
	Retail			Texas			East/West/Other			Eliminations^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	(35	)	$	—		$	3		$	(33	)
Net unrealized (losses)/gains on open positions related to economic hedges	(5		)	(534		)	(5		)	481			(63		)
Total mark-to-market (losses)/gains in operating revenues	$	(6	)	$	(569	)	$	(5	)	$	484		$	(96	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	42		$	(1	)	$	(4	)	$	(3	)	$	34
Net unrealized gains/(losses) on open positions related to economic hedges	750			(1		)	—			(481		)	268
Total mark-to-market gains/(losses) in operating costs and expenses	$	792		$	(2	)	$	(4	)	$	(484	)	$	302


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

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

For the three months ended March 31, 2019, the $20 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of gains on power positions due to declines in power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period. The flat change in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, completely offset by a decrease in the value of open positions as a result of ERCOT heat rate contraction and the reversal of acquired gain positions.

For the three months ended March 31, 2018, the $96 million loss in operating revenues from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of ERCOT heat rate expansion and increases in ERCOT electricity prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period. The $302 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in value of open positions as a result of ERCOT heat rate expansion and increases in ERCOT electricity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended March 31, 2019 and 2018. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy.



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

Operations and Maintenance Expense

~~NRG's interest expense~~



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

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

Operations and maintenance expenses decreased by ~~$46~~$44 million for the three months ended ~~June 30, 2018,~~March 31, 2019, compared to the same period in ~~2017~~2018, due to the following:

(In millions)
Decrease in derivative interest expense from changes in the fair value of interest rate swaps driven by increased interest rates in 2018 $ (35 )
Decrease in interest expense related to repurchases of Senior Notes (9 )
Decrease in interest expense related to Ivanpah deconsolidation (6 )
Other 4
$ (46 )



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

~~Income Tax Expense~~

~~For the three months ended June 30, 2018, NRG recorded an income tax expense~~

Other Cost of $8Operations



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

Other cost of operations decreased by $10 million ~~on pre-tax income of $129 million. For the same period in 2017, NRG recorded an income tax expense of $4 million on pre-tax income of $103 million. The effective tax rate was 6.2% and 3.9%~~ for the three months ended ~~June 30, 2018~~ ~~and 2017, respectively.~~

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

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

For the three months ended June 30, 2018 and 2017, net loss attributable to noncontrolling interests and redeemable noncontrolling interests primarily reflects net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method, partially offset by NRG Yield, Inc.'s share of net income.

~~Management’s discussion of the results of operations for the six months ended June 30, 2018 and 2017~~

~~Electricity Prices~~

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the six months ended June 30, 2018 and 2017. The average on-peak power prices have generally increased primarily due to increased heat rates for the six months ended June 30, 2018, asMarch 31, 2019, compared to the same period in ~~2017.~~2018, due to the following:

Average on Peak Power Price ($/MWh)
Six months ended June 30,
Region 2018 2017 Change %
Gulf Coast ^(a)

ERCOT - Houston ^(b)
$ 33.98
$ 36.86
(8 )%
ERCOT - North^(b)
33.28
25.28
32 %
MISO - Louisiana Hub^(c)
45.22
43.71
3 %
East/West
    NY J/NYC^(c)
49.19
37.48
31 %
    NEPOOL^(c)
51.07
33.69
52 %
    COMED (PJM)^(c)
32.54
31.89
2 %
    PJM West Hub^(c)
43.58
32.40
35 %
CAISO - NP15^(c)
30.05
27.38
10 %
CAISO - SP15^(c)
31.60
26.87
18 %



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

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

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

~~(c) Average on peak power prices based on day ahead settlement prices as published by the respective ISOs.~~

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

Average Realized Power Price ($/MWh)
Six months ended June 30,
Region 2018 2017 Change %
Gulf Coast $ 34.85
$ 34.25
2 %
East/West^(a)
40.69
40.20
1 %

~~(a) does not include BETM energy revenue of $32 million and $15 million for 2018 and 2017, respectively.~~

Though the average on peak power prices have increased on average by 19%, average realized prices by region for the Company have generally fluctuated at different rates year-over-year due to the Company's multi-year hedging program.

~~Gross Margin~~Depreciation and amortization

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

~~Economic Gross Margin~~

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

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

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

Six months ended June 30, 2018

Generation
(In millions) Retail Gulf Coast
East/West^(a)
Subtotal Renewables NRG Yield Corporate/Eliminations Total
Energy revenue $ —
$ 879
$ 362
$ 1,241
$ 156
$ 306
$ (411 ) $ 1,292
Capacity revenue —
135
300
435
—
169
(3 ) 601
Retail revenue 3,304
—
—
—
—
—
(2 ) 3,302
Mark-to-market for economic hedging activities (6 ) (275 ) (25 ) (300 ) (5 ) —
220
(91 )
Contract amortization —
7
—
7
—
(35 ) —
(28 )
Other revenue ^(b)
—
128
34
162
48
92
(35 ) 267
Operating revenue 3,298
874
671
1,545
199
532
(231 ) 5,343
Cost of fuel (12 ) (454 ) (152 ) (606 ) (1 ) (23 ) (88 ) (730 )
Other cost of sales^(c)
(2,415 ) (164 ) (90 ) (254 ) (4 ) (14 ) 509
(2,178 )
Mark-to-market for economic hedging activities 446
(7 ) (3 ) (10 ) —
—
(220 ) 216
Contract and emission credit amortization —
(12 ) (1 ) (13 ) —
—
—
(13 )
Gross margin $ 1,317
$ 237
$ 425
$ 662
$ 194
$ 495
$ (30 ) $ 2,638
Less: Mark-to-market for economic hedging activities, net 440
(282 ) (28 ) (310 ) (5 ) —
—
125
Less: Contract and emission credit amortization, net —
(5 ) (1 ) (6 ) —
(35 ) —
(41 )
Economic gross margin $ 877
$ 524
$ 454
$ 978
$ 199
$ 530
$ (30 ) $ 2,554
Business Metrics
MWh sold (thousands)^(d)(e)
25,220
8,110
2,227
3,924

MWh generated (thousands)^(f)
23,146
5,463
2,227
4,729

(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $26 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 18 thousand or MWt of 1,079 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 47 thousand or MWt of 987 thousand for thermal generated by NRG Yield.

Six months ended June 30, 2017
Generation
(In millions) Retail Gulf Coast
East/West^(a)
Subtotal Renewables NRG Yield Corporate/Eliminations Total
Energy revenue $ —
$ 868
$ 408
$ 1,276
$ 174
$ 294
$ (501 ) $ 1,243
Capacity revenue —
133
266
399
—
164
(4 ) 559
Retail revenue 2,939
—
—
—
—
—
7
2,946
Mark-to-market for economic hedging activities —
41
4
45
3
—
111
159
Contract amortization (1 ) 6
—
6
—
(34 ) —
(29 )
Other revenue ^(b)
—
102
20
122
36
85
(38 ) 205
Operating revenue 2,938
1,150
698
1,848
213
509
(425 ) 5,083
Cost of fuel (7 ) (498 ) (170 ) (668 ) (2 ) (18 ) 31
(664 )
Other cost of sales^(c)
(2,204 ) (157 ) (124 ) (281 ) (5 ) (12 ) 483
(2,019 )
Mark-to-market for economic hedging activities 20
(24 ) (3 ) (27 ) —
—
(111 ) (118 )
Contract and emission credit amortization —
(14 ) (2 ) (16 ) —
—
—
(16 )
Gross margin $ 747
$ 457
$ 399
$ 856
$ 206
$ 479
$ (22 ) $ 2,266
Less: Mark-to-market for economic hedging activities, net 20
17
1
18
3
—
—
41
Less: Contract and emission credit amortization, net (1 ) (8 ) (2 ) (10 ) —
(34 ) —
(45 )
Economic gross margin $ 728
$ 448
$ 400
$ 848
$ 203
$ 513
$ (22 ) $ 2,270
Business Metrics
MWh sold (thousands)^(d)(e)
25,340
9,776
1,974
3,789

MWh generated (thousands)^(f)
23,790
6,096
1,974
4,244

(a) Includes International, BETM and Generation eliminations.
(b) Renewables other revenue includes $14 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in East/West and NRG Yield that generate revenue under capacity agreements.
(e) Does not include thermal MWh of 18 thousand or MWt of 987 thousand for thermal sold by NRG Yield.
(f) Does not include thermal MWh of 36 thousand or MWt of 987 thousand for thermal generated by NRG Yield.

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

Six months ended June 30,
Weather Metrics Gulf Coast East/West
2018
CDDs ^(a)
1,200
283
HDDs ^(a)
1,142
2,152
2017
CDDs 1,125
301
HDDs 673
2,008
10-year average
CDDs 1,062
276
HDDs 1,103
2,206

~~(a)~~

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.~~

Six months ended June 30,
(In millions except otherwise noted) 2018 2017
Retail revenue $ 3,135
$ 2,813
Supply management revenue 75
84
Capacity revenue 94
42
Customer mark-to-market (6 ) —
Contract amortization —
(1 )
Other —
—
Operating revenue^(a)
3,298
2,938
Cost of sales ^(b)
(2,427 ) (2,211 )
Mark-to-market for economic hedging activities 446
20
Gross Margin $ 1,317
$ 747
Less: Mark-to-market for economic hedging activities, net 440
20
Less: Contract amortization, net —
(1 )
Economic Gross Margin $ 877
$ 728

Business Metrics
Mass electricity sales volume — GWh - Gulf Coast 17,745
16,218
Mass electricity sales volume — GWh - All other regions 3,310
2,998
C&I electricity sales volume — GWh - All regions 10,430
10,141
Natural gas sales volumes (MDth) 3,419
1,700
Average Retail Mass customer count (in thousands)
2,926
2,843
Ending Retail Mass customer count (in thousands) ^(c)
3,173
2,887


~~(a)~~	~~Includes intercompany sales of $2 million and $2 million in 2018 and 2017, respectively, representing sales from Retail to the Gulf Coast region.~~


~~(b)~~	~~Includes intercompany purchases of $415 million and $502 million in 2018 and 2017, respectively.~~


~~(c)~~	~~The acquisition of XOOM Energy, LLC increased NRG's retail portfolio by approximately 300,000 customers in the aggregate by June 30, 2018.~~

~~Retail gross margin increased $570 million and economic gross margin increased $149~~$35 million for the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, compared to the ~~same period in 2017, due to:~~

(In millions)
Higher gross margin due to higher revenue of $101 million or approximately $3.00 per MWh, driven by customer product, term and mix offset by higher supply costs of $40 million or approximately $1.25 per MWh, driven primarily by an increase in power prices $ 61
Higher gross margin from the Business Solutions unit reflecting the early settlement of capacity obligations for 2018 34
Higher gross margin due to an increase in load of 1,495,000 MWh driven by more favorable weather conditions in 2018 as compared to 2017 46
Higher gross margin due to higher volumes driven by higher average customer counts primarily driven by the XOOM acquisition in June 2018 8
Increase in economic gross margin $ 149
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges 420
Increase in contract amortization 1
Increase in gross margin $ 570

~~Generation gross margin and economic gross margin~~

~~Generation gross margin decreased $194 million and economic gross margin increased $130 million, both of which include intercompany sales, during the six~~three months ended ~~June 30,~~March 31, 2018, ~~compared to the same period in 2017.~~

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

~~Gulf Coast Region~~

(In millions)
Higher gross margin due to a 10% increase in average realized prices in South Central and a 2% increase in average realized prices in Texas $ 65
Higher gross margin from sales of NOx emission credits 35
Higher capacity margins due to an 15% increase in load demand in the South Central business 29
Lower energy margin due to a 14% increase in supply cost on load contracts (36 )
Lower capacity revenue due to the cancellation of the Greens Bayou RMR agreement in 2017 (14 )
Other (3 )
Increase in economic gross margin $ 76
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges (299 )
Increase in contract and emission credit amortization 3
Decrease in gross margin $ (220 )

~~East/West~~

(In millions)
Higher gross margin due to a 88% increase in New England cleared capacity pricing $ 34
Higher gross margin due to a 23% increase in PJM cleared capacity pricing which relates to the first full period of capacity performance product pricing 29
Higher gross margin from commercial optimization activities 15
Higher gross margin by BETM due to higher gains in congestion strategies 14
Higher gross margin due to a net overall increase in capacity volumes sold in New York 11
Lower gross margin due to a 31% decrease in capacity pricing in New York of $30 million and decreases in capacity pricing and volumes due to the Long Beach capacity toll expiration in July 2017 of $9 million (39 )
Lower gross margin due to lower load contracted prices coupled with lower contracted volumes (13 )
Lower gross margin due to a 10% decrease in generation volumes due to timing of planned and unplanned outages at Midwest Generation and Arthur Kill, offset by favorable fuel costs (10 )
Higher gross margin due to insurance proceeds from outages of $14 million in 2018, compared to business interruption proceeds of $8 million in 2017 6
Other 7
Increase in economic gross margin $ 54
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges (29 )
Increase in contract and emission credit amortization 1
Increase in gross margin $ 26

~~Renewables gross margin and economic gross margin~~

~~Renewables gross margin decreased $12 million and economic gross margin decreased $4 million for the six months ended June 30, 2018, compared to the same period in 2017. This was~~ driven primarily by the deconsolidation of Ivanpah in May 2018, ~~offset~~Agua Caliente in ~~part~~August 2018, the sale of Cottonwood in February 2019 and prior year impairments.

Selling, General and Administrative

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



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

Selling, general and administrative expenses increased by ~~additional distributed solar projects reaching commercial operations in late 2017 and early 2018.~~

~~NRG Yield gross margin and economic gross margin~~

~~NRG Yield gross margin increased $16 million and economic gross margin increased $17~~$18 million for the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, compared to the same period in ~~2017. The increase is~~2018, due ~~primarily~~ to ~~a 3% increase in volume generated by wind projects, primarily in connection with higher wind resource at~~ the ~~Alta Wind projects, as well as a 5% increase in solar generation, primarily at CVSR in connection with higher insolation and higher plant availability at Walnut Creek and El Segundo.~~

following:



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

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges. Total net mark-to-market results ~~increased~~decreased by ~~$84~~$186 million during the ~~six~~three months ended ~~June 30, 2018,~~March 31, 2019, compared to the same period in ~~2017.~~2018.

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


	Six months ended June 30, 2018																		Three months ended March 31, 2019
				Generation																		Generation
	Retail			Gulf Coast			East/West			Renewables			Eliminations^(a)			Total			Retail			Texas			East/West/Other			Eliminations^(a)			Total
	(In millions)																		(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(1	)	$	(86	)	$	(8	)	$	—		$	31		$	(64	)	$	—		$	(79	)	$	(22	)	$	93		$	(8	)
Net unrealized (losses)/gains on open positions related to economic hedges	(5		)	(189		)	(17		)	(5		)	189			(27		)
Total mark-to-market (losses)/gains in operating revenues	$	(6	)	$	(275	)	$	(25	)	$	(5	)	$	220		$	(91	)
Net unrealized gains/(losses) on open positions related to economic hedges																			—			92			14			(78		)	28
Total mark-to-market gains/(losses) in operating revenues																			$	—		$	13		$	(8	)	$	15		$	20
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	104		$	(3	)	$	(7	)	$	—		$	(31	)	$	63		$	115		$	3		$	2		$	(93	)	$	27
Reversal of acquired gain positions related to economic hedges	(1		)	—			—			—			—			(1		)	(2		)	—			—			—			(2		)
Net unrealized gains/(losses) on open positions related to economic hedges	343			(4		)	4			—			(189		)	154
Total mark-to-market gains/(losses) in operating costs and expenses	$	446		$	(7	)	$	(3	)	$	—		$	(220	)	$	216
Net unrealized (losses)/gains on open positions related to economic hedges																			(121		)	15			3			78			(25		)
Total mark-to-market (losses)/gains in operating costs and expenses																			$	(8	)	$	18		$	5		$	(15	)	$	—



Delaware (State or other jurisdiction of incorporation or organization)		41-1724239 (I.R.S. Employer Identification No.)

804 Carnegie Center, Princeton, New Jersey (Address of principal executive offices)		08540 (Zip Code)



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



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



CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	5
PART I — FINANCIAL INFORMATION	108
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	108
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	6750
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	~~105~~74
ITEM 4 — CONTROLS AND PROCEDURES	~~107~~76
PART II — OTHER INFORMATION	~~108~~77
ITEM 1 — LEGAL PROCEEDINGS	~~108~~77
ITEM 1A — RISK FACTORS	~~108~~77
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	~~108~~77
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	~~108~~77
ITEM 4 — MINE SAFETY DISCLOSURES	~~108~~77
ITEM 5 — OTHER INFORMATION	~~108~~77
ITEM 6 — EXHIBITS	~~109~~78
SIGNATURES	~~110~~79



~~2017~~2018 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018
2023 Term Loan Facility		The Company's ~~$1.9~~$1.7 billion term loan facility due 2023, a component of the Senior Credit Facility
~~Adjusted EBITDA~~		~~Adjusted earnings before interest, taxes, depreciation and amortization~~
ARO		Asset Retirement Obligation
ASC		The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASU		Accounting Standards Updates - updates to the ASC
Average realized prices		Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
~~BACT~~		~~Best Available Control Technology~~
Bankruptcy Code		Chapter 11 of Title 11 the U.S. Bankruptcy Code
Bankruptcy Court		United States Bankruptcy Court for the Southern District of Texas, Houston Division
BETM		Boston Energy Trading and Marketing LLC
BTU		British Thermal Unit
Business Solutions		NRG's business solutions group, which includes demand response, commodity sales, energy efficiency and energy management services
CAA		Clean Air Act
~~CAIR~~		~~Clean Air Interstate Rule~~
CAISO		California Independent System Operator
~~CASPR~~Carlsbad		~~Competitive Auctions with Sponsored Resources~~Carlsbad Energy Center, a 528 MW natural gas-fired project located in Carlsbad, CA
CDD		Cooling Degree Day
CDWR		California Department of Water Resources
~~CEC~~		~~California Energy Commission~~
~~CenterPoint~~		~~CenterPoint Energy Houston Electric, LLC~~
CFTC		U.S. Commodity Futures Trading Commission
~~Chapter 11 Cases~~		~~Voluntary cases commenced by the GenOn Entities under the Bankruptcy Code in the Bankruptcy Court~~
C&I		Commercial industrial and governmental/institutional
CES		Clean Energy Standard
Cleco		Cleco ~~Energy~~Corporate Holdings LLC
~~COD~~ CO₂		~~Commercial Operation Date~~Carbon Dioxide
ComEd		Commonwealth Edison
Company		NRG Energy, Inc.
~~CPUC~~CPP		~~California Public Utilities Commission~~
~~CSAPR~~		~~Cross-State Air Pollution Rule~~
~~CVSR~~		~~California Valley Solar Ranch~~Clean Power Plan
CWA		Clean Water Act
D.C. Circuit		U.S. Court of Appeals for the District of Columbia Circuit
~~DGPV Holdco 1~~		~~NRG DGPV Holdco 1 LLC~~
~~DGPV Holdco 2~~		~~NRG DGPV Holdco 2 LLC~~
~~DGPV Holdco 3~~		~~NRG DGPV Holdco 3 LLC~~
Distributed Solar		Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid



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

		For the Quarterly Period Ended: ~~June 30, 2018~~March 31, 2019

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



DNREC		Delaware Department of Natural Resources and Environmental Control
~~DSI~~		~~Dry Sorbent Injection~~
Economic gross margin		Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales
~~El Segundo Energy Center~~EGU		~~NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center project~~Electric Generating Unit
EME		Edison Mission Energy
~~Energy Plus Holdings~~		~~Energy Plus Holdings LLC~~
EPA		U.S. Environmental Protection Agency
~~EPC~~		~~Engineering, Procurement and Construction~~
~~EPSA~~		~~The Electric Power Supply Association~~
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
~~ESP~~		~~Electrostatic Precipitator~~
ESPP		NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
ESPS		Existing Source Performance Standards
Exchange Act		The Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FGD		Flue gas desulfurization
~~Fresh Start~~		~~Reporting requirements as defined by ASC-852,~~ ~~Reorganizations~~
FTRs		Financial Transmission Rights
GAAP		~~Accounting~~Generally accepted accounting principles ~~generally accepted~~ in the U.S.
GenConn		GenConn Energy LLC



GenOn		GenOn Energy, Inc.
~~GenOn Americas Generation~~		~~GenOn Americas Generation, LLC~~
~~GenOn Americas Generation Senior Notes~~		~~GenOn Americas Generation's $395 million outstanding unsecured senior notes consisting of $208 million of 8.5% senior notes due 2021 and $187 million of 9.125% senior notes due 2031~~
GenOn Entities		GenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation. that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court on June 14, 2017
~~GenOn Mid-Atlantic~~		~~GenOn Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries, which include the coal generation units at two generating facilities under operating leases~~
~~GenOn Senior Notes~~		GenOn's $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $649 million of 9.5% senior notes due 2018, and $489 million of 9.875% senior notes due 2020
~~GenOn Settlement~~		A settlement agreement and any other documents necessary to effectuate the settlement among NRG, GenOn, and certain holders of senior unsecured notes of GenOn Americas Generation and GenOn, and certain of GenOn's direct and indirect subsidiaries
GHG		Greenhouse Gas
GIP		Global Infrastructure Partners
GWGreen Mountain Energy		~~Gigawatt~~Green Mountain Energy Company
GWh		Gigawatt Hour
HAP		Hazardous Air Pollutant
HDD		Heating Degree Day
Heat Rate		A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh
~~HLBV~~HLW		~~Hypothetical Liquidation at Book Value~~

High-level radioactive waste

~~IASB~~ICE		~~International Accounting Standards Board~~
~~IFRS~~		~~International Financial Reporting Standards~~
~~IPA~~		~~Illinois Power Agency~~
~~IPPNY~~		~~Independent Power Producers of New York~~Intercontinental Exchange
ISO		Independent System Operator, also referred to as RTOs
ISO-NE		ISO New England Inc.
~~ITC~~		~~Investment Tax Credit~~
kWh		Kilowatt-hour
LaGen		Louisiana Generating, LLC
LIBOR		London Inter-Bank Offered Rate
LTIPs		Collectively, the NRG LTIP and the NRG GenOn LTIP
~~Marsh Landing~~		~~NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)~~
Mass Market		Residential and small commercial customers
MATS		Mercury and Air Toxics Standards promulgated by the EPA
MDth		Thousand Dekatherms
Midwest Generation		Midwest Generation, LLC
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		Million British Thermal Units
~~MOPR~~		~~Minimum Offer Price Rule~~
MW		Megawatts
MWe		Megawatt equivalent
MWh		Saleable megawatt hour net of internal/parasitic load megawatt-hour
~~MWt~~		~~Megawatts Thermal Equivalent~~
NAAQS		National Ambient Air Quality Standards
~~NEPGA~~		~~New England Power Generators Association~~
NEPOOL		New England Power Pool
NERC		North American Electric Reliability Corporation
NJBPU		New Jersey Board of Public Utilities
Net Exposure		Counterparty credit exposure to NRG, net of collateral
~~Net Generation~~		~~The net amount of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation~~
NOL		Net Operating Loss
~~NOV~~		~~Notice of Violation~~
NO_x		Nitrogen Oxides
NPDES		National Pollutant Discharge Elimination System
NPNS		Normal Purchase Normal Sale
NRC		U.S. Nuclear Regulatory Commission
NRG		NRG Energy, Inc.
NRG Yield,		~~Reporting segment including the projects owned by NRG Yield, Inc.~~
~~NRG Yield 2019 Convertible Notes~~		~~$345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019 issued by NRG Yield, Inc.~~
~~NRG Yield 2020 Convertible Notes~~		~~$287.5 million aggregate principal amount of 3.25% Convertible Notes due 2020 issued by NRG Yield, Inc.~~
~~NRG Yield,~~ Inc.		NRG Yield, Inc., which changed it's name to Clearway Energy, Inc. following the ~~owner of 54.8% of the economic interests~~sale by NRG of NRG Yield ~~LLC with a controlling interest,~~ and ~~issuer of publicly held shares of Class A and Class C common stock~~
~~NSR~~		~~New Source Review~~the Renewables Platform to GIP
Nuclear Decommissioning Trust Fund		NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, units 1 & 2
~~NYAG~~Nuclear Waste Policy Act		~~State~~U.S. Nuclear Waste Policy Act of 1982
NY DEC		New York ~~Office~~Department of ~~Attorney General~~Environmental Conservation
NYISO		New York Independent System Operator
NYMEX		New York Mercantile Exchange
NYSPSC		New York State Public Service Commission



~~NYSPSC~~		~~New York State Public Service Commission~~
OCI/OCL		Other Comprehensive Income/(Loss)
ORDC		Operating Reserve Demand Curve
PA PUC		Pennsylvania Public Utility Commission
Peaking		Units expected to satisfy demand requirements during the periods of greatest or peak load on the system
~~PER~~Petra Nova		~~Peak Energy Rent~~Petra Nova Parish Holdings, LLC which is 50% owned by NRG, owns and operates a 240 MWe carbon capture system and a 78 MW cogeneration facility, and owns an equity interest in an oilfield
~~Petition Date~~PG&E		~~June 14, 2017~~
~~Pipeline~~		~~Projects that range from identified lead to shortlisted with an offtake,~~PG&E Corporation (NYSE: PCG) and ~~represents a lower level of execution certainty.~~its primary operating subsidiary, Pacific Gas and Electric Company
PJM		PJM Interconnection, LLC
PM2.5		Particulate Matter that has a diameter of less than 2.5 micrometers
PPA		Power Purchase Agreement
~~PSD~~		~~Prevention of Significant Deterioration~~
~~PTC~~		~~Production Tax Credit~~
PUCT		Public Utility Commission of Texas
~~PUHCA~~		~~Public Utility Holding Company Act of 2005~~
RCRA		Resource Conservation and Recovery Act of 1976
~~REMA~~Reliant Energy		Reliant Energy Retail Services, LLC
Renewables		Consists of the following projects that NRG ~~REMA LLC, which leases a 100%~~has an ownership interest in: Agua, Ivanpah, Sherbino and NFL stadiums
Renewables Platform		The renewable operating and development platform sold to GIP with NRG's interest in ~~the Shawville generating facility and 16.7% and 16.5% interests in the Keystone and Conemaugh generating facilities, respectively~~
~~Restructuring Support Agreement~~		~~Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017 and as amended on October 2, 2017, by and among GenOn Energy,~~NRG Yield, Inc.~~, GenOn Americas Generation, LLC, and subsidiaries signatory thereto, NRG Energy, Inc. and the noteholders signatory thereto~~
Retail		Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG, as well as Business Solutions
~~Revolving Credit Facility~~		The Company’s $2.5 billion revolving credit facility, a component of the Senior Credit Facility. The revolving credit facility consists of $289 million of Tranche A Revolving Credit Facility, due 2018, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021
~~RFO~~		~~Request for Offer~~
RGGI		Regional Greenhouse Gas Initiative
~~RMR~~		~~Reliability Must-Run~~
~~ROFO~~		~~Right of First Offer~~
~~ROFO Agreement~~		~~Second Amended and Restated Right of First Offer Agreement by and between NRG Energy, Inc. and NRG Yield, Inc.~~
~~RPM~~		~~Reliability Pricing Model~~
~~RPV Holdco~~		~~NRG RPV Holdco 1 LLC~~
RTO		Regional Transmission Organization
~~RTR~~		~~Renewable Technology Resource~~
~~SCE~~		~~Southern California Edison~~
SDG&E		San Diego Gas & Electric
SEC		U.S. Securities and Exchange Commission
Securities Act		The Securities Act of 1933, as amended
Senior Credit Facility		NRG's senior secured credit facility, comprised of the Revolving Credit Facility and the 2023 Term Loan Facility
Senior Notes		As of December 31, ~~2017, NRG’s $4.8~~2018, NRG's $3.8 billion outstanding unsecured senior notes consisting of ~~$992 million of 6.25% senior notes due 2022,~~ $733 million of 6.25% senior notes due 2024, $1.0 billion of the 7.25% senior notes due 2026, ~~$1.25~~$1.23 billion of the 6.625% senior notes due 2027, and ~~$870~~$821 million of 5.75% senior notes due ~~2028.~~2028
~~Services Agreement~~SNF		NRG provided GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in the services agreement with GenOn
~~SIFMA~~		~~Securities Industry and Financial Markets Association~~Spent Nuclear Fuel
SO₂		Sulfur Dioxide



South Central Portfolio		NRG's South Central ~~business,~~Portfolio, which ~~owns~~owned and ~~operates~~operated a ~~3,555-MW~~ portfolio of generation assets consisting of ~~225-MW~~ Bayou Cove, ~~430-MW~~ Big Cajun-I, ~~1,461-MW~~ Big Cajun-II, ~~1,263-MW~~ Cottonwood and ~~176-MW~~ Sterlington, ~~and serves a customer base of cooperatives, municipalities and regional utilities under load contracts.~~was sold on February 4, 2019. NRG is leasing back the Cottonwood facility through May 2025
~~S&P~~STP		~~Standard & Poor's~~South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
~~TCPA~~STPNOC		~~Telephone Consumer Protection Act~~South Texas Project Nuclear Operating Company
Texas Genco		Texas Genco LLC
TSA		Transportation Services Agreement
TWCC		Texas Westmoreland Coal Co.
U.S.		United States of America
U.S. DOE		U.S. Department of Energy
Utility Scale Solar		Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaR		Value at Risk
VCP		Voluntary Clean-Up Program
VIE		Variable Interest Entity
~~WECC~~		~~Western Electricity Coordinating Council~~
~~WST~~		~~Washington-St. Tammany Electric Cooperative, Inc.~~
~~Yield Operating~~		~~NRG Yield Operating LLC~~



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


	June 30, 2018		December 31, 2017		June 30, 2017		December 31, 2016		March 31, 2019		December 31, 2018		March 31, 2018		December 31, 2017
	(In millions)								(In millions)
Cash and cash equivalents	$	980	$	991	$	752	$	938	$	859	$	563	$	514	$	770
Funds deposited by counterparties	71		37		19		2		11		33		241		37
Restricted cash	286		508		469		446		15		17		261		279
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows	$	1,337	$	1,536	$	1,240	$	1,386	$	885	$	613	$	1,016	$	1,086



	(In millions)
Balance as of December 31, 2017	$	2,314
Dividends paid to NRG Yield, Inc. public shareholders	(61		)
Distributions to noncontrolling interest	(34		)
Comprehensive income attributable to noncontrolling interest	12
Non-cash adjustments to noncontrolling interest	8
Contributions from noncontrolling interest	295
Sale of assets to NRG Yield, Inc.	(8		)
Deconsolidation of Ivanpah^(a)	(89		)
Balance as of June 30, 2018	$	2,437



	(In millions)
Balance as of December 31, 2017	$	78
Distributions to redeemable noncontrolling interest	(2		)
Contributions from redeemable noncontrolling interest	26
Non-cash adjustments to redeemable noncontrolling interest	(9		)
Comprehensive loss attributable to redeemable noncontrolling interest	(24		)
Balance as of June 30, 2018	$	69


	Three months ended June 30, 2018																					Three months ended March 31, 2019
			Generation																					Generation
(In millions)	Retail		Gulf Coast			East/West			Subtotal		Renewables		NRG Yield			Eliminations			Total			Retail		Texas			East/West/Other			Subtotal		Corporate/Eliminations			Total
Energy revenue^(a)(b)	$	—	$	508		$	144		$	652	$	79	$	192		$	(250	)	$	673		$	—	$	358		$	224		$	582	$	(276	)	$	306
Capacity revenue^(b)(a)	—		68			160			228		—		87			(2		)	313			—		—			155			155		(1		)	154
Retail revenue
Mass customers	1,380		—			—			—		—		—			(1		)	1,379			1,321		—			—			—		(1		)	1,320
Business solutions customers	437		—			—			—		—		—			—			437
Business Solutions customers																						286		—			—			—		—			286
Total retail revenue	1,817		—			—			—		—		—			(1		)	1,816			1,607		—			—			—		(1		)	1,606
Mark-to-market for economic hedging activities^(c)	—		289			(15		)	274		5		—			(264		)	15
Contract amortization	—		4			—			4		—		(18		)	—			(14		)
Other revenue^(a)(b)	—		42			18			60		29		46			(16		)	119
Mark-to-market for economic hedging activities^(b)(c)																						—		13			(8		)	5		15			20
Other revenues^(a)																						—		29			52			81		(2		)	79
Total operating revenue	1,817		911			307			1,218		113		307			(533		)	2,922			1,607		400			423			823		(265		)	2,165
Less: Lease revenue	6		—			1			1		96		267			—			370			3		—			2			2		—			5
Less: Derivative revenue	—		898			(1		)	897		5		—			(264		)	638
Less: Contract amortization	—		4			—			4		—		(18		)	—			(14		)
Less: Realized and unrealized ASC 815 revenue^(b)																						—		546			97			643		(262		)	381
Total revenue from contracts with customers	$	1,811	$	9		$	307		$	316	$	12	$	58		$	(269	)	$	1,928		$	1,604	$	(146	)	$	324		$	178	$	(3	)	$	1,779
(a) The following amounts of energy and capacity revenue relate to leases and are accounted for under ASC 840:
(a) The following amounts of energy and capacity revenue primarily relate to derivative instruments and are accounted for under ASC 815																						(a) The following amounts of energy and capacity revenue primarily relate to derivative instruments and are accounted for under ASC 815
	Retail		Gulf Coast			East/West			Subtotal		Renewables		NRG Yield			Eliminations			Total			Retail		Texas			East/West/Other			Subtotal		Corporate/Eliminations			Total
Energy revenue	$	—	$	—		$	—		$	—	$	90	$	182		$	—		$	272		$	—	$	525		$	88		$	613	$	(277	)	$	336
Capacity revenue	—		—			—			—		—		85			—			85			—		—			18			18		—			18
Other revenue	6		—			1			1		6		—			—			13			—		8			(1		)	7		—			7
(b) The following amounts of energy and capacity revenue relate to derivative instruments and are accounted for under ASC 815.
	Retail		Gulf Coast			East/West			Subtotal		Renewables		NRG Yield			Eliminations			Total
Energy revenue	$	—	$	610		$	(30	)	$	580	$	—	$	—		$	—		$	580
Capacity revenue	—		—			39			39		—		—			—			39
Other revenue	—		(1		)	5			4		—		—			—			4
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815.




(In millions)	June 30, 2018
Deferred customer acquisition costs	$	102
Accounts receivable, net - Contracts with customers	1,187
Accounts receivable, net - Leases	152
Accounts receivable, net - Derivative instruments	32
Total accounts receivable, net	$	1,371
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)	445
Deferred revenues	73



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



	Three months ended June 30, 2018			Period from April 1, 2017 through June 14, 2017			Six months ended June 30, 2018			Period from January 1, 2017 through June 14, 2017
(In millions)	Three months ended June 30, 2018			Period from April 1, 2017 through June 14, 2017			Six months ended June 30, 2018			Period from January 1, 2017 through June 14, 2017
Operating revenues	$	—		$	265		$	—		$	646
Operating costs and expenses	—			(327		)	—			(700		)
Other expenses	—			(54		)	—			(98		)
Loss from operations of discontinued components, before tax	—			(116		)	—			(152		)
Income tax expense	—			8			—			9
Loss from operations of discontinued components	—			(124		)	—			(161		)
Interest income - affiliate	2			3			3			6
Loss from operations of discontinued components, net of tax	2			(121		)	3			(155		)
Pre-tax loss on deconsolidation	—			(208		)	—			(208		)
Settlement consideration and services credit	—			(289		)	—			(289		)
Pension and post-retirement liability assumption	1			(119		)	1			(119		)
Advisory and consulting fees	(1		)	(4		)	(2		)	(4		)
Other	(27		)	—			(27		)	—
Loss on disposal of discontinued components, net of tax	(27		)	(620		)	(28		)	(620		)
Loss from discontinued operations, net of tax	$	(25	)	$	(741	)	$	(25	)	$	(775	)


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


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


	As of June 30, 2018				As of December 31, 2017				As of March 31, 2019				As of December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)								(In millions)
Assets:
Notes receivable^(a)	$	21	$	18	$	16	$	15	$	17	$	14	$	17	$	14
Liabilities:
Long-term debt, including current portion^(b)(a)	15,969		16,163		16,603		16,894		6,558		6,971		6,591		6,697



	As of June 30, 2018				As of December 31, 2017
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	9,586	$	6,577	$	8,934	$	7,960



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended June 30, 2018								Six months ended June 30, 2018
(In millions)	Debt Securities		Derivatives^(a)			Total			Debt Securities		Derivatives^(a)			Total
Beginning balance	$	19	$	(22	)	$	(3	)	$	19	$	(32	)	$	(13	)
Contracts acquired in Xoom acquisition	—		12			12			—		12			12
Total losses — realized/unrealized:
Included in earnings	—		(21		)	(21		)	—		(19		)	(19		)
Purchases	—		(4		)	(4		)	—		(3		)	(3		)
Transfers into Level 3 ^(b)	—		193			193			—		197			197
Transfers out of Level 3 ^(b)	—		(5		)	(5		)	—		(2		)	(2		)
Ending balance as of June 30, 2018	$	19	$	153		$	172		$	19	$	153		$	172
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of June 30, 2018	—		20			20			—		17			17


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


(b)	Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.2



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended June 30, 2017								Six months ended June 30, 2017
(In millions)	Debt Securities		Derivatives^(a)			Total			Debt Securities		Derivatives^(a)			Total
Beginning balance	$	18	$	(56	)	$	(38	)	$	17	$	(68	)	$	(51	)
Total gains — realized/unrealized:
Included in earnings	—		40			40			1		46			47
Included in nuclear decommissioning obligation	—		—			—			—		—			—
Purchases	—		5			5			—		9			9
Transfers into Level 3 ^(b)	—		3			3			—		(5		)	(5		)
Transfers out of Level 3 ^(b)	—		(3		)	(3		)	—		7			7
Ending balance as of June 30, 2017	$	18	$	(11	)	$	7		$	18	$	(11	)	$	7
Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of June 30, 2017	—		22			22			—		7			7


	Significant Unobservable Inputs
	June 30, 2018													March 31, 2019
	Fair Value						Input/Range							Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average		Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(In millions)													(In millions)
Power Contracts	$	481	$	330	Discounted Cash Flow	Forward Market Price (per MWh)	$	6		$	198	$	35	$	89	$	104	Discounted Cash Flow	Forward Market Price (per MWh)	0		$	253	$	28
FTRs	19		17		Discounted Cash Flow	Auction Prices (per MWh)	(48		)	47		—		26		13		Discounted Cash Flow	Auction Prices (per MWh)	(42	)	38		0
	$	500	$	347										$	115	$	117



Significant Unobservable Input	Position	Change In Input	Impact on Fair Value Measurement
Forward Market Price Power	Buy	Increase/(Decrease)	Higher/(Lower)
Forward Market Price Power	Sell	Increase/(Decrease)	Lower/(Higher)
FTR Prices	Buy	Increase/(Decrease)	Higher/(Lower)
FTR Prices	Sell	Increase/(Decrease)	Lower/(Higher)



	Net Exposure^(a)(b)
Category by Industry Sector	(% of Total)
Utilities, energy merchants, marketers and other	7678	%
Financial institutions	2422
Total as of ~~June 30, 2018~~March 31, 2019	100	%



	Net Exposure ^{(a) (b)}
Category by Counterparty Credit Quality	(% of Total)
Investment grade	7652	%
Non-Investment grade/Non-Rated	2448
Total as of ~~June 30, 2018~~March 31, 2019	100	%


(a)	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market ~~prices.~~prices


(b)	The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain ~~long term contracts.~~long-term contracts



	As of June 30, 2018							As of December 31, 2017
(In millions, except otherwise noted)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)
Cash and cash equivalents	$	25	$	—	$	—	—	$	47	$	—	$	—	—
U.S. government and federal agency obligations	42		1		—		14	43		1		—		11
Federal agency mortgage-backed securities	97		—		3		23	82		1		1		23
Commercial mortgage-backed securities	16		—		1		22	14		—		—		20
Corporate debt securities	101		1		2		10	99		2		1		11
Equity securities	407		272		—		—	402		272		—		—
Foreign government fixed income securities	6		—		—		8	5		—		—		9
Total	$	694	$	274	$	6		$	692	$	276	$	2



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