Edgar Filing: GenOn Energy, Inc.

10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

		For the Quarterly Period Ended: September 30, 2015

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

GenOn Energy, Inc.

(Exact name of registrant as specified in its charter)

75-0655566 (I.R.S. Employer Identification No.)

Commission File Number: 001-16455

GenOn Americas Generation, LLC

(Exact name of registrant as specified in its charter)

51-0390520 (I.R.S. Employer Identification No.)

Commission File Number: 333-63240

GenOn Mid-Atlantic, LLC

(Exact name of registrant as specified in its charter)

58-2574140 (I.R.S. Employer Identification No.)

Commission File Number: 333-61668



Delaware (State or other jurisdiction of incorporation or organization)		(609) 524-4500 (Registrants' telephone number, including area code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. (As a voluntary filer not subject to filing requirements, the registrant nevertheless filed all reports which would have been required to be filed by Section 15(d) of the Exchange Act during the preceding 12 months had the registrant been required to file reports pursuant to Section 15(d) of the Exchange Act solely as a result of having registered debt securities under the Securities Act of 1933.)



GenOn Energy, Inc.	o	Yes	o	No
GenOn Americas Generation, LLC	o	Yes	o	No
GenOn Mid-Atlantic, LLC	o	Yes	o	No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).



GenOn Energy, Inc.	x	Yes	o	No
GenOn Americas Generation, LLC	x	Yes	o	No
GenOn Mid-Atlantic, LLC	x	Yes	o	No

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



	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company
GenOn Energy, Inc.	o	o	x	o
GenOn Americas Generation, LLC	o	o	x	o
GenOn Mid-Atlantic, LLC	o	o	x	o
			(Do not check if a smaller reporting company)

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



GenOn Energy, Inc.	o	Yes	x	No
GenOn Americas Generation, LLC	o	Yes	x	No
GenOn Mid-Atlantic, LLC	o	Yes	x	No

Each Registrant’s outstanding equity interests are held by its respective parent and there are no equity interests held by nonaffiliates.



Registrant		Parent
GenOn Energy, Inc.		NRG Energy, Inc.
GenOn Americas Generation, LLC		NRG Americas, Inc.
GenOn Mid-Atlantic, LLC		NRG North America LLC

This combined Form 10-Q is separately filed by GenOn Energy, Inc., GenOn Americas Generation, LLC and GenOn Mid-Atlantic, LLC. Information contained in this combined Form 10-Q relating to GenOn Energy, Inc., GenOn Americas Generation, LLC and GenOn Mid-Atlantic, LLC is filed by such registrant on its own behalf and each registrant makes no representation as to information relating to registrants other than itself.

NOTE: WHEREAS GENON ENERGY, INC., GENON AMERICAS GENERATION, LLC AND GENON MID-ATLANTIC, LLC MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q, THIS COMBINED FORM 10-Q IS BEING FILED WITH THE REDUCED DISCLOSURE FORMAT PURSUANT TO GENERAL INSTRUCTION H(2).

TABLE OF CONTENTS



CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATON		2
GLOSSARY OF TERMS		3
PART I — FINANCIAL INFORMATION		5
	Item 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	5
	Item 2 — MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	36
	Item 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	55
	Item 4 — CONTROLS AND PROCEDURES	55
PART II — OTHER INFORMATION		56
	Item 1 — LEGAL PROCEEDINGS	56
	Item 1A — RISK FACTORS	56
	Item 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	56
	Item 3 — DEFAULTS UPON SENIOR SECURITIES	56
	Item 4 — MINE SAFETY DISCLOSURES	56
	Item 5 — OTHER INFORMATION	56
	Item 6 — EXHIBITS	57
	SIGNATURES	58

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION

(GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The words "believe," "project," "anticipate," "plan," "expect," "intend," "estimate" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause the Registrants’ actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A - Risk Factors, in Part I, Item 1A of the Registrants' Annual Report on Form 10-K for the year ended December 31, 2014, and the following:


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


•	Volatile power supply costs and demand for power;

•

Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that the Registrants may not have adequate insurance to cover losses as a result of such hazards;


•	The effectiveness of the Registrants’ risk management policies and procedures, and the ability of the Registrants’ counterparties to satisfy their financial commitments;


•	Counterparties' collateral demands and other factors affecting the Registrants' liquidity position and financial condition;


•	The Registrants’ ability to operate their businesses efficiently, manage capital expenditures and costs tightly, and generate earnings and cash flows from their asset-based businesses in relation to their debt and other obligations;


•	The Registrants’ ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;


•	The liquidity and competitiveness of wholesale markets for energy commodities;


•	Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of CO₂ and other GHG emissions;


•	Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately compensate the Registrants' generation units for all of their costs;


•	The Registrants’ ability to borrow additional funds and access capital markets, as well as GenOn’s substantial indebtedness and the possibility that the Registrants may incur additional indebtedness going forward; and


•	Operating and financial restrictions placed on the Registrants and their subsidiaries that are contained in the indentures governing GenOn’s outstanding notes, and in debt and other agreements of certain of the Registrants’ subsidiaries and project affiliates generally.

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

GLOSSARY OF TERMS

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



2014 Form 10-K		The Registrants' Annual Report on Form 10-K for the year ended December 31, 2014
ASC		The FASB Accounting Standards Codification, which the FASB established as the source of authoritative U.S. GAAP
ASU		Accounting Standards Updates, which reflect updates to the ASC
Average realized prices		Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
Bankruptcy Court		United States Bankruptcy Court for the Northern District of Texas, Fort Worth Division
CAIR		Clean Air Interstate Rule
CenterPoint		CenterPoint Energy, Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries prior to August 31, 2002
CFTC		U.S. Commodity Futures Trading Commission
CO2		Carbon Dioxide
CSAPR		Cross-State Air Pollution Rule
CWA		Clean Water Act
D.C. Circuit		U.S. Court of Appeals for the District of Columbia Circuit
Direct Energy		Direct Energy Business Marketing, LLC
Economic gross margin		Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of sales
EPA		United States Environmental Protection Agency
Exchange Act		The Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FCM		Forward Capacity Market
FERC		Federal Energy Regulatory Commission
FTRs		Financial Transmission Rights
FPA		Federal Power Act
GenOn		GenOn Energy, Inc. and, except where the context indicates otherwise, its subsidiaries
GenOn Americas Generation		GenOn Americas Generation, LLC and, except where the context indicates otherwise, its subsidiaries
GenOn Energy Holdings		GenOn Energy Holdings, Inc. and, except where the context indicates otherwise, its subsidiaries
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
GHG		Greenhouse Gases
HAPs		Hazardous Air Pollutants
ICAP		New York Installed Capacity
IPPNY		Independent Power Producers of New York
ISO		Independent System Operator, also referred to as RTO
ISO-NE		ISO New England Inc.
LIBOR		London Interbank Offered Rate
MATS		Mercury and Air Toxics Standards promulgated by the EPA
MC Asset Recovery		MC Asset Recovery, LLC
MDE		Maryland Department of the Environment
Mirant		GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries
Mirant/RRI Merger		The merger completed on December 3, 2010 of Mirant Corporation and RRI Energy Inc. to form GenOn Energy, Inc.



Mirant Debtors		GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and certain of its subsidiaries
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		Million British Thermal Units
MW		Megawatt
MWh		Saleable megawatt hours net of internal/parasitic load megawatt-hours
NAAQS		National Ambient Air Quality Standards
Net Exposure		Counterparty credit exposure to GenOn, GenOn Americas Generation or GenOn Mid-Atlantic, as applicable, net of collateral
NERC		North American Electric Reliability Corporation
NextEra		NextEra Energy Resources, LLC
NO_x		Nitrogen Oxide
NPDES		National Pollution Discharge Elimination System
NPNS		Normal Purchase Normal Sale
NRG		NRG Energy, Inc. and, except where the context indicates otherwise, its subsidiaries
NRG Merger		The merger completed on December 14, 2012, whereby GenOn became a wholly owned subsidiary of NRG
NYISO		New York Independent System Operator
NYSPSC		New York State Public Service Commission
OCI		Other Comprehensive Income/(Loss)
PJM		PJM Interconnection, LLC
Plan		The plan of reorganization that was approved in conjunction with Mirant Corporation's emergence from bankruptcy protection on January 3, 2006
PPM		Parts Per Million
PSCs		Public Service Commissions
RCRA		Resource Conservation and Recovery Act of 1976
Registrants		GenOn, GenOn Americas Generation and GenOn Mid-Atlantic, collectively
REMA		NRG REMA LLC (formerly known as GenOn REMA, LLC)
RMR		Reliability Must-Run
RTO		Regional Transmission Organization
SCR		Selective Catalytic Reduction Control System
Securities Act		The Securities Act of 1933, as amended
SO₂		Sulfur Dioxide
U.S.		United States of America
U.S. GAAP		Accounting principles generally accepted in the United States

PART I - FINANCIAL INFORMATION

ITEM 1 - CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

GENON ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	(In millions)
Operating Revenues
Operating revenues	$	648		$	713		$	1,950		$	2,300
Operating revenues — affiliate	(3		)	(4		)	6			17
Total operating revenues	645			709			1,956			2,317
Operating Costs and Expenses
Cost of operations	361			385			1,269			1,388
Cost of operations — affiliate	78			69			210			367
Depreciation and amortization	52			52			163			172
Impairment loss	—			60			—			60
General and administrative	—			19			—			60
General and administrative — affiliate	43			31			135			90
Acquisition-related transaction and integration costs	—			1			—			3
Total operating costs and expenses	534			617			1,777			2,140
Loss on sale of assets	—			—			—			(6		)
Operating Income	111			92			179			171
Other Income/(Expense)
Other income, net	—			2			4			4
Interest expense	(49		)	(46		)	(146		)	(140		)
Interest expense — affiliate	(3		)	(2		)	(8		)	(9		)
Total other expense	(52		)	(46		)	(150		)	(145		)
Income Before Income Taxes	59			46			29			26
Income tax expense	1			—			—			2
Net Income	$	58		$	46		$	29		$	24

See accompanying notes to condensed consolidated financial statements.

GENON ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)



	Three months ended September 30,					Nine months ended September 30,
	2015		2014			2015			2014
	(In millions)
Net Income	$	58	$	46		$	29		$	24
Other Comprehensive (Loss)/Income, net of tax of $0:
Defined benefit plans	—		(5		)	(2		)	3
Other comprehensive (loss)/income	—		(5		)	(2		)	3
Comprehensive Income	$	58	$	41		$	27		$	27

See accompanying notes to condensed consolidated financial statements.

GENON ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2015			December 31, 2014
	(unaudited)
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	1,093		$	920
Funds deposited by counterparties	40			54
Accounts receivable — trade	110			120
Inventory	426			507
Derivative instruments	371			591
Derivative instruments — affiliate	20			11
Cash collateral paid in support of energy risk management activities	73			38
Prepayments and other current assets	156			150
Total current assets	2,289			2,391
Property, plant and equipment, net of accumulated depreciation of $597 and $436	3,052			3,045
Other Assets
Intangible assets, net of accumulated amortization of $50 and $66	73			72
Derivative instruments	240			195
Derivative instruments — affiliate	6			10
Other non-current assets	238			201
Total other assets	557			478
Total Assets	$	5,898		$	5,914
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	6		$	10
Accounts payable	132			135
Accounts payable — affiliate	82			14
Derivative instruments	306			382
Derivative instruments — affiliate	20			35
Cash collateral received in support of energy risk management activities	40			54
Accrued expenses and other current liabilities	279			238
Total current liabilities	865			868
Other Liabilities
Long-term debt and capital leases	3,073			3,120
Derivative instruments	139			69
Derivative instruments — affiliate	12			3
Out-of-market contracts	912			969
Other non-current liabilities	469			484
Total non-current liabilities	4,605			4,645
Total Liabilities	5,470			5,513
Commitments and Contingencies
Stockholder's Equity
Common stock: $0.001 par value, 1 share authorized and issued at September 30, 2015 and December 31, 2014	—			—
Additional paid-in capital	325			325
Retained earnings	107			78
Accumulated other comprehensive loss	(4		)	(2		)
Total Stockholder's Equity	428			401
Total Liabilities and Stockholder's Equity	$	5,898		$	5,914

See accompanying notes to condensed consolidated financial statements.

GENON ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine months ended September 30,
	2015			2014
	(In millions)
Cash Flows from Operating Activities
Net Income	$	29		$	24
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	163			172
Amortization of financing costs and debt discount/premiums	(43		)	(43		)
Amortization of out-of-market contracts and emission allowances	(23		)	(17		)
Loss on sale of asset	—			6
Impairment loss	—			60
Changes in derivative instruments	158			323
Changes in collateral deposits supporting energy risk management activities	(35		)	(73		)
Changes in other working capital	103			(173		)
Net Cash Provided by Operating Activities	352			279
Cash Flows from Investing Activities
Capital expenditures	(175		)	(125		)
Proceeds from sale of assets, net of cash disposed of	—			50
Other	—			5
Net Cash Used by Investing Activities	(175		)	(70		)
Cash Flows from Financing Activities
Payments for short and long-term debt	(4		)	(1		)
Net Cash Used by Financing Activities	(4		)	(1		)
Net Increase in Cash and Cash Equivalents	173			208
Cash and Cash Equivalents at Beginning of Period	920			760
Cash and Cash Equivalents at End of Period	$	1,093		$	968

See accompanying notes to condensed consolidated financial statements.

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	(In millions)
Operating Revenues
Operating revenues	$	587		$	667		$	1,808		$	2,123
Operating revenues — affiliate	21			(25		)	40			110
Total operating revenues	608			642			1,848			2,233
Operating Costs and Expenses
Cost of operations	181			198			711			753
Cost of operations — affiliate	315			336			925			1,185
Depreciation and amortization	18			21			55			70
General and administrative	—			2			—			7
General and administrative — affiliate	20			19			61			58
Total operating costs and expenses	534			576			1,752			2,073
Loss on sale of assets	—			—			—			(6		)
Operating Income	74			66			96			154
Other Expense
Interest expense	(17		)	(17		)	(49		)	(50		)
Interest expense — affiliate	(1		)	(2		)	(4		)	(6		)
Total other expense	(18		)	(19		)	(53		)	(56		)
Income Before Income Taxes	56			47			43			98
Income tax	—			—			—			—
Net Income	$	56		$	47		$	43		$	98

See accompanying notes to condensed consolidated financial statements.

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2015		December 31, 2014
	(unaudited)
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	248	$	103
Funds deposited by counterparties	40		54
Accounts receivable — trade	99		106
Accounts receivable — affiliate	57		—
Note receivable — affiliate	331		331
Inventory	253		318
Derivative instruments	371		591
Derivative instruments — affiliate	200		261
Cash collateral paid in support of energy risk management activities	64		29
Prepayments and other current assets	96		90
Total current assets	1,759		1,883
Property, plant and equipment, net of accumulated depreciation of $225 and $170	1,111		1,110
Other Assets
Intangible assets, net of accumulated amortization of $50 and $66	73		72
Derivative instruments	240		196
Derivative instruments — affiliate	103		60
Other non-current assets	122		111
Total other assets	538		439
Total Assets	$	3,408	$	3,432
LIABILITIES AND MEMBER'S EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1	$	5
Accounts payable	72		50
Accounts payable — affiliate	—		23
Derivative instruments	306		382
Derivative instruments — affiliate	182		292
Cash collateral received in support of energy risk management activities	40		54
Accrued expenses and other current liabilities	135		93
Total current liabilities	736		899
Other Liabilities
Long-term debt and capital leases	922		929
Derivative instruments	139		69
Derivative instruments — affiliate	120		66
Out-of-market contracts	527		547
Other non-current liabilities	105		106
Total non-current liabilities	1,813		1,717
Total Liabilities	2,549		2,616
Commitments and Contingencies
Member’s Equity
Member’s interest	859		816
Total Member’s Equity	859		816
Total Liabilities and Member’s Equity	$	3,408	$	3,432

See accompanying notes to condensed consolidated financial statements.

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine months ended September 30,
	2015			2014
	(In millions)
Cash Flows from Operating Activities
Net Income	$	43		$	98
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	55			70
Amortization of debt premiums	(7		)	(7		)
Amortization of out-of-market contracts and emission allowances	14			10
Loss on sale of assets	—			6
Changes in derivative instruments	132			258
Changes in collateral deposits supporting energy risk management activities	(35		)	(131		)
Changes in other working capital	—			49
Net Cash Provided by Operating Activities	202			353
Cash Flows from Investing Activities
Capital expenditures	(53		)	(25		)
Decrease in note receivable — affiliate	—			(32		)
Proceeds from sale of assets, net of cash disposed of	—			50
Net Cash Used by Investing Activities	(53		)	(7		)
Cash Flows from Financing Activities
Payments for short and long-term debt	(4		)	—
Capital contributions	—			37
Distributions to member	—			(320		)
Net Cash Used by Financing Activities	(4		)	(283		)
Net Increase in Cash and Cash Equivalents	145			63
Cash and Cash Equivalents at Beginning of Period	103			63
Cash and Cash Equivalents at End of Period	$	248		$	126

See accompanying notes to condensed consolidated financial statements.

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	(In millions)
Operating Revenues
Operating revenues	$	4		$	46		$	8		$	(110	)
Operating revenues — affiliate	216			199			684			878
Total operating revenues	220			245			692			768
Operating Costs and Expenses
Cost of operations	121			141			420			535
Cost of operations — affiliate	20			26			102			29
Depreciation and amortization	16			18			49			61
General and administrative — affiliate	15			15			44			48
Total operating costs and expenses	172			200			615			673
Operating Income	48			45			77			95
Other Expense
Interest expense	—			—			(1		)	(1		)
Interest expense — affiliate	(1		)	(1		)	(2		)	(3		)
Total other expense	(1		)	(1		)	(3		)	(4		)
Income Before Income Taxes	47			44			74			91
Income tax	—			—			—			—
Net Income	$	47		$	44		$	74		$	91

See accompanying notes to condensed consolidated financial statements.

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2015		December 31, 2014
	(unaudited)
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	291	$	157
Accounts receivable — trade	3		10
Inventory	158		166
Derivative instruments	29		100
Derivative instruments — affiliate	181		141
Prepayments and other current assets	75		80
Total current assets	737		654
Property, plant and equipment, net of accumulated depreciation of $184 and $135	928		958
Other Assets
Intangible assets, net	13		10
Derivative instruments — affiliate	128		141
Other non-current assets	116		87
Total other assets	257		238
Total Assets	$	1,922	$	1,850
LIABILITIES AND MEMBER'S EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1	$	5
Accounts payable	20		27
Accounts payable — affiliate	2		14
Derivative instruments	—		1
Derivative instruments — affiliate	128		127
Accrued expenses and other current liabilities	78		53
Total current liabilities	229		227
Other Liabilities
Derivative instruments — affiliate	49		22
Out-of-market contracts	527		547
Other non-current liabilities	49		60
Total non-current liabilities	625		629
Total Liabilities	854		856
Commitments and Contingencies
Member’s Equity
Member’s interest	1,068		994
Total Member’s Equity	1,068		994
Total Liabilities and Member’s Equity	$	1,922	$	1,850

See accompanying notes to condensed consolidated financial statements.

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine months ended September 30,
	2015			2014
	(In millions)
Cash Flows from Operating Activities
Net Income	$	74		$	91
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	49			61
Amortization of out-of-market contracts and emission allowances	(20		)	(12		)
Changes in derivative instruments	71			259
Changes in other working capital	(10		)	(3		)
Net Cash Provided by Operating Activities	164			396
Cash Flows from Investing Activities
Capital expenditures	(26		)	(11		)
Net Cash Used by Investing Activities	(26		)	(11		)
Cash Flows from Financing Activities
Payments for short and long-term debt	(4		)	—
Distributions to member	—			(320		)
Net Cash Used by Financing Activities	(4		)	(320		)
Net Increase in Cash and Cash Equivalents	134			65
Cash and Cash Equivalents at Beginning of Period	157			64
Cash and Cash Equivalents at End of Period	$	291		$	129

See accompanying notes to condensed consolidated financial statements.

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Basis of Presentation (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

GenOn Energy, Inc., a wholly owned subsidiary of NRG, is a wholesale power generator engaged in the ownership and operation of power generation facilities, with approximately 17,752 MW of net electric generating capacity located in the U.S. In the first nine months of 2015, GenOn mothballed Osceola and Shawville, retired Coolwater, Glen Gardner, Gilbert and Werner, and restored Unit 2 at Bowline to full capacity following the boiler restoration completed in June 2015, resulting in a net decrease in generation capacity of 1,777 MW from December 31, 2014. Shawville is planned to return to service with a natural gas addition during the summer of 2016.

GenOn Americas Generation is a wholesale power generator with approximately 7,985 MW of net electric generating capacity located, in many cases, near major metropolitan areas. During June 2015, GenOn Americas Generation restored Unit 2 at Bowline to full capacity, as discussed above, resulting in an increase of 389 MW from December 31, 2014. GenOn Americas Generation's electric generating capacity is part of the 17,752 MW of net electric generating capacity of GenOn.

GenOn Mid-Atlantic operates and owns or leases 4,683 MW of net electric generating capacity in Maryland near Washington, D.C. GenOn Mid-Atlantic’s electric generating capacity is part of the 7,985 MW of net electric generating capacity of GenOn Americas Generation. GenOn Mid-Atlantic’s generating facilities serve the Eastern PJM markets.

GenOn Americas Generation and GenOn Mid-Atlantic are Delaware limited liability companies and indirect wholly owned subsidiaries of GenOn. GenOn Mid-Atlantic is an indirect wholly owned subsidiary of GenOn Americas Generation.

The Registrants sell power from their generation portfolio, offer capacity or similar products to retail electric providers and others, and provide ancillary services to support system reliability.

This is a combined quarterly report of the Registrants for the quarter ended September 30, 2015. The notes to the condensed consolidated financial statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by U.S. GAAP for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the Registrants' financial statements in the Registrants' 2014 Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Registrants' consolidated financial positions as of September 30, 2015, and the results of operations, comprehensive income/(loss) and cash flows for the three and nine months ended September 30, 2015, and 2014.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Reclassifications

Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.

Note 2 — Summary of Significant Accounting Policies (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

Oil Inventory Adjustment (GenOn, GenOn Americas Generation, and GenOn Mid-Atlantic)

During the nine months ended September 30, 2015, certain oil inventory was identified as unusable and the related value of $16 million was written off to cost of operations in the statement of operations.

Impairment Loss (GenOn)

During the three months ended September 30, 2014, GenOn determined that it would mothball the 463 MW natural gas-fired Osceola facility in Saint Cloud, Florida. GenOn considered this to be an indicator of impairment and performed an impairment test for these assets under ASC 360, Property, Plant and Equipment. The carrying amount of the assets was higher than the future net cash flows expected to be generated by the assets and as a result, the assets were considered to be impaired. GenOn measured the impairment loss as the difference between the carrying amount and the fair value of the assets. Due to the location of the facility, it was determined that the best indicator of fair value is the market value of the combustion turbines. GenOn recorded an impairment loss of approximately $60 million during the three months ended September 30, 2014, which represents the excess of the carrying value over the fair market value, and mothballed the facility effective January 1, 2015.

Recent Accounting Developments (GenOn, GenOn Americas Generation, and GenOn Mid-Atlantic)

ASU 2015-02 — In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, or ASU No. 2015-02. The amendments of ASU No. 2015-02 were issued in an effort to minimize situations under previously existing guidance in which a reporting entity was required to consolidate another legal entity in which that reporting entity did not have: (1) the ability through contractual rights to act primarily on its own behalf; (2) ownership of the majority of the legal entity's voting rights; or (3) the exposure to a majority of the legal entity's economic benefits. ASU No. 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. The guidance in ASU No. 2015-02 is effective for periods beginning after December 15, 2015. Early adoption is permitted. The Registrants adopted the standard effective January 1, 2015 and the adoption of this standard did not impact the Registrants' results of operations, cash flows or financial position.

ASU 2014-16 — In November 2014, the FASB issued ASU No. 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity, or ASU No. 2014-16. The amendments of ASU No. 2014-16 clarify how U.S. GAAP should be applied in determining whether the nature of a host contract is more akin to debt or equity and in evaluating whether the economic characteristics and risks of an embedded feature are "clearly and closely related" to its host contract. The guidance in ASU No. 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Registrants adopted the standard effective January 1, 2015 and the adoption of this standard did not impact the Registrants' results of operations, cash flows or financial position.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09. The amendments of ASU No. 2014-09 complete the joint effort between the FASB and the International Accounting Standards Board, or IASB, to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards, or IFRS, and to improve financial reporting. The guidance in ASU No. 2014-09 provides that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for the goods or services provided and establishes the following steps to be applied by an entity: (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies the performance obligation. In August 2015, the FASB issued ASU 2015-14, which formally deferred the effective date by one year to make the guidance of ASU No. 2014-09 effective for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, but not prior to the original effective date, which was for annual reporting periods beginning after December 15, 2016. The Registrants are currently evaluating the impact of the standard on the Registrants' results of operations, cash flows and financial position.

Note 3 — Fair Value of Financial Instruments (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

This footnote should be read in conjunction with the complete description under Note 4, Fair Value of Financial Instruments, to the Registrants' 2014 Form 10-K.

For cash and cash equivalents, funds deposited by counterparties, accounts receivable, note receivable — affiliate, accounts payable, accrued liabilities, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amounts approximate fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

The estimated carrying amounts and fair values of GenOn and GenOn Americas Generation’s debt are as follows:

GenOn



	As of September 30, 2015				As of December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt, including current portion	$	3,076	$	2,566	$	3,122	$	2,706

The fair value of long-term debt that is estimated using reported market prices for instruments that are publicly traded is classified as Level 2 within the fair value hierarchy. The fair value of non-publicly traded debt is based on the income approach valuation technique using current interest rates for similar instruments with equivalent credit quality and is classified as Level 3 within the fair value hierarchy.

GenOn Americas Generation



	As of September 30, 2015				As of December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt, including current portion	$	922	$	694	$	929	$	720

The fair value of long-term debt is estimated using reported market prices for instruments that are publicly traded and is classified as Level 2 within the fair value hierarchy.

Recurring Fair Value Measurements

Derivative assets and liabilities are carried at fair market value. Realized and unrealized gains and losses included in earnings that are related to energy derivatives are recorded in operating revenues and cost of operations.

GenOn

The following tables present assets and liabilities (including affiliate amounts) measured and recorded at fair value on GenOn’s consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:



	As of September 30, 2015
	Fair Value
	Level 1 ^(a)		Level 2 ^(a)		Level 3		Total
	(In millions)
Derivative assets:
Commodity contracts	$	190	$	437	$	10	$	637
Derivative liabilities:
Commodity contracts	$	130	$	337	$	10	$	477
Other assets ^(b)	$	14	$	—	$	—	$	14

(a) There were no transfers between Levels 1 and 2 during the three and nine months ended September 30, 2015.

(b) Relates to mutual funds held in a rabbi trust for non-qualified deferred compensation plans for certain key and highly compensated employees.



	As of December 31, 2014
	Fair Value
	Level 1 ^(a)		Level 2 ^(a)		Level 3		Total
	(In millions)
Derivative assets:
Commodity contracts	$	179	$	582	$	46	$	807
Derivative liabilities:
Commodity contracts	$	105	$	371	$	13	$	489
Other assets ^(b)	$	21	$	—	$	—	$	21

(a) There were no transfers between Levels 1 and 2 during the year ended December 31, 2014.

(b) Relates to mutual funds held in a rabbi trust for non-qualified deferred compensation plans for certain key and highly compensated employees.

The following table reconciles, for the three and nine months ended September 30, 2015, and 2014, the beginning and ending balances for derivatives that are recognized at fair value in GenOn's consolidated financial statements at least annually using significant unobservable inputs:



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	Derivatives ^(a)						Derivatives^(a)
	(In millions)
Beginning balance	$	14		$	(44	)	$	33		$	(4	)
Total (losses)/gains included in earnings — realized/unrealized	(18		)	1			(44		)	3
Purchases	(2		)	22			5			(19		)
Transfers into Level 3 ^(b)	—			1			—			—
Transfers out of Level 3 ^(b)	6			—			6			—
Ending balance	$	—		$	(20	)	$	—		$	(20	)
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of September 30	$	(14	)	$	—		$	(20	)	$	(1	)

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

(b) Transfers in/out of level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period.

GenOn Americas Generation

The following tables present assets and liabilities (including affiliate amounts) measured and recorded at fair value on GenOn Americas Generation's consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:



	As of September 30, 2015
	Fair Value
	Level 1 ^(a)		Level 2 ^(a)		Level 3		Total
	(In millions)
Derivative assets:
Commodity contracts	$	255	$	640	$	19	$	914
Derivative liabilities:
Commodity contracts	$	148	$	581	$	18	$	747

(a) There were no transfers between Levels 1 and 2 during the three and nine months ended September 30, 2015.



	As of December 31, 2014
	Fair Value
	Level 1 ^(a)		Level 2 ^(a)		Level 3		Total
	(In millions)
Derivative assets:
Commodity contracts	$	208	$	848	$	52	$	1,108
Derivative liabilities:
Commodity contracts	$	137	$	640	$	32	$	809

(a) There were no transfers between Levels 1 and 2 during the year ended December 31, 2014.

The following table reconciles, for the three and nine months ended September 30, 2015, and 2014, the beginning and ending balances for GenOn Americas Generation's derivatives that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	Derivatives ^(a)						Derivatives ^(a)
	(In millions)
Beginning balance	$	12		$	(41	)	$	20		$	(1	)
Total (losses)/gains included in earnings — realized/unrealized	(16		)	1			(26		)	1
Purchases	(1		)	22			1			(18		)
Transfers out of Level 3 ^(b)	6			—			6			—
Ending balance	$	1		$	(18	)	$	1		$	(18	)
(Losses)/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 September 30	$	(13	)	$	1		$	(11	)	$	—

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

(b) Transfers out of level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period.

GenOn Mid-Atlantic

The following tables present assets and liabilities (including affiliate amounts) measured and recorded at fair value on GenOn Mid-Atlantic's consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:



	As of September 30, 2015
	Fair Value
	Level 1 ^(a)		Level 2 ^(a)		Level 3		Total
	(In millions)
Derivative assets:
Commodity contracts	$	168	$	169	$	1	$	338
Derivative liabilities:
Commodity contracts	$	61	$	116	$	—	$	177

(a) There were no transfers between Levels 1 and 2 during the three and nine months ended September 30, 2015.



	As of December 31, 2014
	Fair Value
	Level 1 ^(a)		Level 2 ^(a)		Level 3		Total
	(In millions)
Derivative assets:
Commodity contracts	$	145	$	211	$	26	$	382
Derivative liabilities:
Commodity contracts	$	71	$	73	$	6	$	150

(a) There were no transfers between Levels 1 and 2 during the year ended December 31, 2014.

The following table reconciles, for the three and nine months ended September 30, 2015, and 2014, the beginning and ending balances for GenOn Mid-Atlantic's derivatives that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	Derivatives^(a)						Derivatives ^(a)
	(In millions)
Beginning balance	$	13		$	(41	)	$	20		$	—
Total (losses)/gains included in earnings — realized/unrealized	(15		)	1			(25		)	—
Purchases	(3		)	22			—			(18		)
Transfers out of Level 3 ^(b)	6			—			6			—
Ending balance	$	1		$	(18	)	$	1		$	(18	)
(Losses)/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 September 30	$	(13	)	$	1		$	(11	)	$	—

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

(b) Transfers out of level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period.

Derivative Fair Value Measurements

A portion of the Registrants' contracts are exchange-traded contracts with readily available quoted market prices. A majority of the Registrants' contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of September 30, 2015, contracts valued with prices provided by models and other valuation techniques make up 2% of GenOn's derivative assets and 2% of GenOn's derivative liabilities, 2% of GenOn Americas Generation’s derivative assets and 2% of GenOn Americas Generation's derivative liabilities and less than 1% of GenOn Mid-Atlantic’s derivative assets and less than 1% of GenOn Mid-Atlantic's derivative liabilities.

The Registrants' significant positions classified as Level 3 include physical and financial power and physical coal executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power and coal location pricing, which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, the Registrants use the most recent auction prices to derive the fair value.

The following tables quantify the significant unobservable inputs used in developing the fair value of the Registrants' Level 3 positions as of September 30, 2015 and December 31, 2014:

GenOn



	Significant Unobservable Inputs
	September 30, 2015
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	6	$	—	Discounted Cash Flow	Forward Market Price (per MWh)	$	12		$	56	$	30
Coal Contracts	—		10		Discounted Cash Flow	Forward Market Price (per ton)	46			49		47
FTRs	4		—		Discounted Cash Flow	Auction Prices (per MWh)	(1		)	4		1
	$	10	$	10



	Significant Unobservable Inputs
	December 31, 2014
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	39	$	5	Discounted Cash Flow	Forward Market Price (per MWh)	$	18		$	68	$	46
Coal Contracts	3		1		Discounted Cash Flow	Forward Market Price (per ton)	53			56		54
FTRs	4		7		Discounted Cash Flow	Auction Prices (per MWh)	(10		)	3		(1		)
	$	46	$	13

GenOn Americas Generation



	Significant Unobservable Inputs
	September 30, 2015
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(In millions)
Power Contracts	$	5	$	5	Discounted Cash Flow	Forward Market Price (per MWh)	$	12	$	56	$	30
Coal Contracts	10		9		Discounted Cash Flow	Forward Market Price (per ton)	46		49		47
FTRs	4		4		Discounted Cash Flow	Auction Prices (per MWh)	—		1		—
	$	19	$	18



	Significant Unobservable Inputs
	December 31, 2014
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	39	$	18	Discounted Cash Flow	Forward Market Price (per MWh)	$	18		$	68	$	46
Coal Contracts	3		3		Discounted Cash Flow	Forward Market Price (per ton)	53			56		54
FTRs	10		11		Discounted Cash Flow	Auction Prices (per MWh)	(1		)	1		—
	$	52	$	32

GenOn Mid-Atlantic

Significant Unobservable Inputs

September 30, 2015

Fair Value

Input/Range

Assets

Liabilities

Valuation Technique

Significant Unobservable Input

Low

High

Weighted Average

(In millions)

FTRs

—

Discounted Cash Flow

Auction Prices (per MWh)

—



	Significant Unobservable Inputs
	December 31, 2014
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	26	$	5	Discounted Cash Flow	Forward Market Price (per MWh)	$	24		$	68	$	47
FTRs	—		1		Discounted Cash Flow	Auction Prices (per MWh)	(1		)	1		—
	$	26	$	6

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of September 30, 2015, and December 31, 2014:



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

The fair value of each contract is discounted using a risk free interest rate. In addition, the Registrants apply a non-performance/credit reserve to reflect credit risk which is calculated based on published default probabilities. The Registrants' (non-performance)/credit reserves were as follows:



	As of September 30, 2015			As of December 31, 2014
	(In millions)
GenOn	$	(1	)	$	—
GenOn Americas Generation	(1		)	—
GenOn Mid-Atlantic	3			2

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Registrants' 2014 Form 10-K, the following is a discussion of the concentration of credit risk for the Registrants’ financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Registrants are exposed to counterparty credit risk through various activities including wholesale sales and fuel purchases.

Counterparty Credit Risk

The Registrants' counterparty credit risk policies are disclosed in their 2014 Form 10-K. As of September 30, 2015, GenOn's counterparty credit exposure was $337 million and GenOn held $30 million of collateral (cash and letters of credit) against those positions, resulting in a net exposure of $307 million. Approximately 71% of GenOn's exposure before collateral is expected to roll off by the end of 2016. As of September 30, 2015, GenOn Americas Generation’s counterparty credit exposure was $329 million and GenOn Americas Generation held $30 million of collateral (cash and letters of credit) against those positions, resulting in a net exposure of $299 million. Approximately 72% of GenOn Americas Generation’s exposure before collateral is expected to roll off by the end of 2016. As of September 30, 2015, GenOn Mid-Atlantic’s counterparty credit exposure was $29 million and GenOn Mid-Atlantic held no collateral (cash and letters or credit) against those positions, resulting in a net exposure of $29 million. 100% of GenOn Mid-Atlantic’s exposure before collateral is expected to roll off by the end of 2016. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for the Registrants with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market, NPNS and non-derivative transactions. The exposure is shown net of collateral held and includes amounts net of receivables or payables.



	Net Exposure ^(a) (% of Total)
Category	GenOn		GenOn Americas Generation		GenOn Mid-Atlantic
Financial institutions	74	%	76	%	100	%
Utilities, energy merchants, marketers and other	8		5		—
ISOs	18		19		—
Total as of September 30, 2015	100	%	100	%	100	%



	Net Exposure ^(a) (% of Total)
Category	GenOn		GenOn Americas Generation		GenOn Mid-Atlantic
Investment grade	100	%	100	%	100	%
Total as of September 30, 2015	100	%	100	%	100	%

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

The Registrants have counterparty credit risk exposure to certain counterparties, each of which represent more than 10% of their respective total net exposure discussed above. The aggregate of such counterparties' exposure was $249 million, $249 million and $29 million for GenOn, GenOn Americas Generation and GenOn Mid-Atlantic, respectively. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, the Registrants do not anticipate a material impact on their financial position or results of operations from nonperformance by any of their counterparties.

Note 4 — Accounting for Derivative Instruments and Hedging Activities (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

This footnote should be read in conjunction with the complete description under Note 5, Accounting for Derivative Instruments and Hedging Activities, to the 2014 Form 10-K.

Energy-Related Commodities (GenOn)

As of September 30, 2015, GenOn had energy-related derivative financial instruments extending through 2019.

Volumetric Underlying Derivative Transactions (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

The following table summarizes the net notional volume buy/(sell) of the Registrants’ open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of September 30, 2015, and December 31, 2014. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.



		GenOn			GenOn Americas Generation			GenOn Mid-Atlantic
		Total Volume			Total Volume			Total Volume
		As of September 30, 2015		As of December 31, 2014	As of September 30, 2015		As of December 31, 2014	As of September 30, 2015		As of December 31, 2014
Commodity	Units	(In millions)
Coal	Short Ton	7		8	4		5	4		5
Natural Gas	MMBtu	122		(21)	(12	)	(74)	(22	)	(79)
Power	MWh	(48	)	(36)	(22	)	(16)	(20	)	(15)

The decrease in the natural gas position was the result of buying natural gas to convert fixed price natural gas hedges into fixed price power hedges, as well as the settlement of positions during the period.

Fair Value of Derivative Instruments (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

The following tables summarize the fair value within the derivative instrument valuation on the balance sheet:

GenOn



	Fair Value
	Derivative Assets				Derivative Liabilities
	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014
	(In millions)
Derivatives Not Designated as Cash Flow Hedges:
Commodity contracts current	$	391	$	602	$	326	$	417
Commodity contracts long-term	246		205		151		72
Total Derivatives Not Designated as Cash Flow Hedges	$	637	$	807	$	477	$	489

GenOn Americas Generation



	Fair Value
	Derivative Assets				Derivative Liabilities
	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014
	(In millions)
Derivatives Not Designated as Cash Flow Hedges:
Commodity contracts current	$	571	$	852	$	488	$	674
Commodity contracts long-term	343		256		259		135
Total Derivatives Not Designated as Cash Flow Hedges	$	914	$	1,108	$	747	$	809

GenOn Mid-Atlantic



	Fair Value
	Derivative Assets				Derivative Liabilities
	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014
	(In millions)
Derivatives Not Designated as Cash Flow Hedges:
Commodity contracts current	$	210	$	241	$	128	$	128
Commodity contracts long-term	128		141		49		22
Total Derivatives Not Designated as Cash Flow Hedges	$	338	$	382	$	177	$	150

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

GenOn



	Gross Amounts Not Offset in the Statement of Financial Position
Description	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
September 30, 2015	(In millions)
Commodity contracts:
Derivative assets	$	611		$	(366	)	$	(40	)	$	205
Derivative assets - affiliate	26			(26		)	—			—
Derivative liabilities	(445		)	366			—			(79		)
Derivative liabilities - affiliate	(32		)	26			6			—
Total derivative instruments	$	160		$	—		$	(34	)	$	126



	Gross Amounts Not Offset in the Statement of Financial Position
Description	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
December 31, 2014	(In millions)
Commodity contracts:
Derivative assets	$	786		$	(425	)	$	(54	)	$	307
Derivative assets - affiliate	21			(21		)	—			—
Derivative liabilities	(451		)	425			—			(26		)
Derivative liabilities - affiliate	(38		)	21			17			—
Total derivative instruments	$	318		$	—		$	(37	)	$	281

GenOn Americas Generation



	Gross Amounts Not Offset in the Statement of Financial Position
Description	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
September 30, 2015	(In millions)
Commodity contracts:
Derivative assets	$	611		$	(366	)	$	(40	)	$	205
Derivative assets - affiliate	303			(302		)	—			1
Derivative liabilities	(445		)	366			—			(79		)
Derivative liabilities - affiliate	(302		)	302			—			—
Total derivative instruments	$	167		$	—		$	(40	)	$	127



	Gross Amounts Not Offset in the Statement of Financial Position
Description	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
December 31, 2014	(In millions)
Commodity contracts:
Derivative assets	$	787		$	(425	)	$	(54	)	$	308
Derivative assets - affiliate	321			(321		)	—			—
Derivative liabilities	(451		)	425			—			(26		)
Derivative liabilities - affiliate	(358		)	321			17			(20		)
Total derivative instruments	$	299		$	—		$	(37	)	$	262

GenOn Mid-Atlantic



	Gross Amounts Not Offset in the Statement of Financial Position
Description	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted		Net Amount
September 30, 2015	(In millions)
Commodity contracts:
Derivative assets	$	29		$	—		$	—	$	29
Derivative assets - affiliate	309			(177		)	—		132
Derivative liabilities - affiliate	(177		)	177			—		—
Total derivative instruments	$	161		$	—		$	—	$	161



	Gross Amounts Not Offset in the Statement of Financial Position
Description	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted		Net Amount
December 31, 2014	(In millions)
Commodity contracts:
Derivative assets	$	100		$	—		$	—	$	100
Derivative assets - affiliate	282			(149		)	—		133
Derivative liabilities	(1		)	—			—		(1		)
Derivative liabilities - affiliate	(149		)	149			—		—
Total derivative instruments	$	232		$	—		$	—	$	232

Impact of Derivative Instruments on the Statements of Operations (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges are reflected in current period earnings.

The following tables summarize the pre-tax effects of economic hedges that have not been designated as cash flow hedges and trading activity on the Registrants’ statements of operations. These amounts are included within operating revenues and cost of operations.

GenOn



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Unrealized mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(19	)	$	(59	)	$	(146	)	$	(210	)
Net unrealized (losses)/gains on open positions related to economic hedges	(6		)	57			(12		)	(112		)
Total unrealized mark-to-market losses for economic hedging activities	(25		)	(2		)	(158		)	(322		)
Reversal of previously recognized unrealized gains on settled positions related to trading activity	—			—			—			(1		)
Total unrealized mark-to-market losses for trading activity	—			—			—			(1		)
Total unrealized losses	$	(25	)	$	(2	)	$	(158	)	$	(323	)



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Revenue from operations — energy commodities	$	(17	)	$	3		$	(91	)	$	(341	)
Cost of operations	(8		)	(5		)	(67		)	18
Total impact to statements of operations	$	(25	)	$	(2	)	$	(158	)	$	(323	)

GenOn Americas Generation



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Unrealized mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(23	)	$	(65	)	$	(153	)	$	(201	)
Net unrealized gains/(losses) on open positions related to economic hedges	10			30			21			(55		)
Total unrealized mark-to-market losses for economic hedging activities	(13		)	(35		)	(132		)	(256		)
Reversal of previously recognized unrealized gains on settled positions related to trading activity	—			—			—			(1		)
Total unrealized mark-to-market losses for trading activity	—			—			—			(1		)
Total unrealized losses	$	(13	)	$	(35	)	$	(132	)	$	(257	)



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Revenue from operations — energy commodities	$	(4	)	$	(27	)	$	(84	)	$	(266	)
Cost of operations	(9		)	(8		)	(48		)	9
Total impact to statements of operations	$	(13	)	$	(35	)	$	(132	)	$	(257	)

GenOn Mid-Atlantic



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Unrealized mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(20	)	$	(63	)	$	(79	)	$	(203	)
Net unrealized gains/(losses) on open positions related to economic hedges	17			31			8			(54		)
Total unrealized losses	$	(3	)	$	(32	)	$	(71	)	$	(257	)



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Revenue from operations — energy commodities	$	(1	)	$	(24	)	$	(29	)	$	(267	)
Cost of operations	(2		)	(8		)	(42		)	10
Total impact to statements of operations	$	(3	)	$	(32	)	$	(71	)	$	(257	)

Credit Risk Related Contingent Features (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

Certain of GenOn and GenOn Americas Generation’s hedging agreements contain provisions that require the Registrants to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the agreements, or require the Registrants to post additional collateral if there were a one notch downgrade in the Registrants’ credit rating. The collateral required for contracts that have adequate assurance clauses that are in net liability positions as of September 30, 2015, was $32 million for GenOn and GenOn Americas Generation. The collateral required for contracts with credit rating contingent features that are in a net liability position as of September 30, 2015, was $1 million for GenOn and GenOn Americas Generation. In addition, GenOn and GenOn Americas Generation are parties to certain marginable agreements under which they have net liability positions, but the counterparties have not called for collateral due, which was zero for GenOn and GenOn Americas Generation as of September 30, 2015. As of September 30, 2015, GenOn Mid-Atlantic is not party to certain marginable agreements under which they have net liability positions, but the counterparties have not called for collateral due.

See Note 3, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.

Note 5 —Debt and Capital Leases (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

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



(In millions, except rates)	September 30, 2015		December 31, 2014		September 30, 2015 interest rate %

GenOn Mid-Atlantic:
Chalk Point capital lease, due 2015	$	1	$	5	8.190
Subtotal GenOn Mid-Atlantic	1		5
GenOn Americas Generation:
Senior unsecured notes, due 2021	491		496		8.500
Senior unsecured notes, due 2031	431		433		9.125
Subtotal GenOn Americas Generation ^(a)	922		929
GenOn Energy:
Senior unsecured notes, due 2017	753		766		7.875
Senior unsecured notes, due 2018	741		757		9.500
Senior unsecured notes, due 2020	603		610		9.875
Other liability ^(b)	57		60
GenOn capital lease	2		3
Subtotal GenOn Energy	2,156		2,196
Subtotal	3,079		3,130
Less current maturities	6		10
Total long-term debt and capital leases	$	3,073	$	3,120

(a) This amount includes GenOn Mid-Atlantic.


(b)	The Long Term Service Agreement for the Hunterstown facility is accounted for as a debt financing liability in accordance with U.S. GAAP.

Long-term debt includes the following premiums:



(In millions)	September 30, 2015		December 31, 2014

GenOn Americas Generation:
Senior unsecured notes, due 2021	$	41	$	46
Senior unsecured notes, due 2031	31		33
GenOn Energy:
Senior unsecured notes, due 2017	28		41
Senior unsecured notes, due 2018	67		83
Senior unsecured notes, due 2020	53		60
Total premium	$	220	$	263

Note 6 — Income Taxes (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

GenOn

GenOn’s income tax expense consisted of the following:



	Three months ended September 30,						Nine months ended September 30,
(In millions except otherwise noted)	2015			2014			2015			2014
Income before income taxes	$	59		$	46		$	29		$	26
Income tax expense	1			—			—			2
Effective tax rate	1.7		%	—		%	—		%	7.7		%

For the three months ended September 30, 2015, GenOn's overall effective tax rate was lower than the statutory rate of 35% due to a change in the valuation allowance, partially offset by the impact of state income taxes.

For the three months ended September 30, 2014, GenOn's overall effective tax rate was lower than the statutory rate of 35% primarily due to a change in the valuation allowance.

For the nine months ended September 30, 2015, GenOn's overall effective tax rate was lower than the statutory rate of 35% due to a change in the valuation allowance.

For the nine months ended September 30, 2014, GenOn's overall effective tax rate was lower than the statutory rate of 35% due to a change in the valuation allowance, partially offset by the impact of state income taxes.

GenOn Americas Generation

GenOn Americas Generation's allocated income taxes resulting from its operations for the three and nine months ended September 30, 2015, and 2014 were $0. GenOn Americas Generation's pro forma income taxes resulting from its operations for the three and nine months ended September 30, 2015, and 2014 are $0 due to the valuation allowance recorded on its stand-alone financial results.

GenOn Mid-Atlantic

GenOn Mid-Atlantic’s allocated income taxes resulting from its operations are $0 for the three and nine months ended September 30, 2015, and 2014. The pro forma income tax provision attributable to income before taxes is a tax expense of $17 million and $16 million during the three months ended September 30, 2015, and 2014, respectively. The pro forma income tax provision attributable to income before taxes is a tax expense of $27 million and $33 million during the nine months ended September 30, 2015 and 2014, respectively. The balance of GenOn Mid-Atlantic's pro forma deferred income taxes is a net deferred tax asset of $24 million and $51 million as of September 30, 2015, and December 31, 2014, respectively, as no valuation allowance is required on the net deferred tax asset.

Note 7 — Related Party Transactions (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

Services Agreement with NRG

NRG provides GenOn with various management, personnel and other services, which include human resources, regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and asset management, as set forth in its services agreement with NRG, 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 is 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 are approximately $193 million. NRG charges these fees on a monthly basis, less amounts incurred directly by GenOn. Management has concluded that this method of charging overhead costs is reasonable. For the three and nine months ended September 30, 2015, GenOn recorded costs related to these services of $43 million and $135 million, respectively, as general and administrative — affiliate. For the three and nine months ended September 30, 2014, GenOn recorded costs related to these services of $31 million and $90 million, respectively, as general and administrative — affiliate.

Under the Services Agreement, NRG also provides GenOn Americas Generation and GenOn Mid-Atlantic with various management, personnel and other services consistent with those set forth in the Services Agreement discussed above between NRG and GenOn. GenOn's costs incurred under the Services Agreement with NRG are allocated to its subsidiaries based on each operating subsidiary's planned operating expenses relative to all operating subsidiaries of GenOn. These allocations and charges are not necessarily indicative of what would have been incurred had GenOn Americas Generation and GenOn Mid-Atlantic been unaffiliated entities. Management has concluded that this method of charging overhead costs is reasonable.

The following costs were incurred under these arrangements:

GenOn Americas Generation



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
	(In millions)
Allocated costs:
Cost of operations — affiliate	$	—	$	—	$	2	$	1
General and administrative — affiliate	20		19		61		58
Total	$	20	$	19	$	63	$	59

GenOn Mid-Atlantic



	Three months ended September 30,				Nine months ended September 30,
	2015		2014		2015		2014
	(In millions)
Allocated costs:
Cost of operations — affiliate	$	—	$	—	$	1	$	—
General and administrative — affiliate	15		15		44		48
Total	$	15	$	15	$	45	$	48

Credit Agreement with NRG (GenOn)

In connection with the closing of the NRG Merger, GenOn and GenOn Americas entered into a secured intercompany revolving credit agreement with NRG. This credit agreement provides for a $500 million revolving credit facility, all of which is available for revolving loans and letters of credit. At September 30, 2015, and December 31, 2014, $215 million and $237 million, respectively, of letters of credit were issued and outstanding under the NRG credit agreement, of which $166 million and $173 million, respectively, were issued on behalf of GenOn Americas Generation. At September 30, 2015, and December 31, 2014, no loans were outstanding under this credit agreement. In connection with the execution of the agreement, certain of GenOn's subsidiaries, as guarantors, entered into a guarantee agreement pursuant to which these guarantors guaranteed amounts borrowed and obligations incurred under the credit agreement. The credit agreement has a three year maturity and is payable at maturity, subject to certain exceptions primarily related to asset sales not in the ordinary course of business and borrowings of debt. NRG has agreed to extend the maturity an additional three years, with the revised maturity occurring in December of 2018. In addition, the guarantors are restricted from incurring additional liens on their assets. At GenOn's election, the interest rate per year applicable to the loans under the credit agreement will be determined by reference to either (i) the base rate plus 2.50% per year or (ii) the LIBOR rate plus 3.50% per year. In addition, the credit agreement contains customary covenants and events of default.

Intercompany Cash Management Program (GenOn Americas Generation)

GenOn Americas Generation and certain of its subsidiaries participate in separate intercompany cash management programs whereby cash balances at GenOn Americas Generation and the respective participating subsidiaries are transferred to central concentration accounts to fund working capital and other needs of the respective participants. The balances under this program are reflected as notes receivable — affiliate and accounts receivable — affiliate or notes payable — affiliate and accounts payable — affiliate, as appropriate. The balances are due on demand and notes receivable — affiliate and notes payable — affiliate accrue interest on the net position, which is payable quarterly, at a rate determined by GenOn Energy Holdings, a wholly owned subsidiary of GenOn. At September 30, 2015, and December 31, 2014, GenOn Americas Generation had a net current note receivable — affiliate from GenOn Energy Holdings of $331 million related to its historical intercompany cash management activity. For the three and nine months ended September 30, 2015, and 2014, GenOn Americas Generation earned an insignificant amount of net interest income related to these notes. Additionally, at September 30, 2015, and December 31, 2014, GenOn Americas Generation had an accounts receivable — affiliate of $133 million and $118 million, respectively, with GenOn Energy Holdings.

Note 8 — Commitments and Contingencies (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

This footnote should be read in conjunction with the complete description under Note 16, Commitments and Contingencies, to the Registrants' 2014 Form 10-K.

Contingencies

The Registrants’ material legal proceedings are described below. The Registrants believe that they have valid defenses to these legal proceedings and intend to defend them vigorously. The Registrants record 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. 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 Registrants are 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 Registrants’ liabilities and contingencies could be at amounts that are different from their currently recorded reserves and that such difference could be material.

In addition to the legal proceedings noted below, the Registrants are parties 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 the Registrants’ respective consolidated financial position, results of operations, or cash flows.

Actions Pursued by MC Asset Recovery (GenOn) — With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings. MC Asset Recovery is governed by a manager who is independent of NRG and GenOn. MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings. In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants. In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit. In March 2012, the Court of Appeals reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. If MC Asset Recovery succeeds in obtaining any recoveries from the Commerzbank Defendants, the Commerzbank Defendants have asserted that they will seek to file claims in Mirant's bankruptcy proceedings for the amount of those recoveries. GenOn Energy Holdings would vigorously contest the allowance of any such claims. If the Commerzbank Defendants were to receive an allowed claim as a result of a recovery by MC Asset Recovery on its claims against them, GenOn Energy Holdings would retain from the net amount recovered by MC Asset Recovery an amount equal to the dollar amount of the resulting allowed claim.

Natural Gas Litigation (GenOn) — GenOn is party to several lawsuits, certain of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of state antitrust law and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of Nevada, which was handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit 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 Court of Appeals' 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. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.

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

Maryland Department of the Environment v. GenOn Chalk Point and GenOn Mid-Atlantic — On January 25, 2013, Food & Water Watch, the Patuxent Riverkeeper and the Potomac Riverkeeper (together, the Citizens Group) sent GenOn Mid-Atlantic a letter alleging that the Chalk Point, Dickerson and Morgantown generating facilities were violating the terms of the three National Pollution Discharge Elimination System permits by discharging nitrogen and phosphorous in excess of the limits in each permit. On March 21, 2013, the MDE sent GenOn Mid-Atlantic a similar letter with respect to the Chalk Point and Dickerson generating facilities, threatening to sue within 60 days if the generating facilities were not brought into compliance. On June 11, 2013, the Maryland Attorney General on behalf of the MDE filed a complaint in the U.S. District Court for the District of Maryland alleging violations of the CWA and Maryland environmental laws related to water. The lawsuit is ongoing and seeks injunctive relief and civil penalties in excess of $100,000. The Registrants do not expect the resolution of this matter to have a material impact on the Registrants' consolidated financial position, results of operations, or cash flows.

Chapter 11 Proceedings (GenOn and GenOn Americas Generation) — In July 2003, and various dates thereafter, the Mirant Debtors filed voluntary petitions in the Bankruptcy Court for relief under Chapter 11 of the U.S. Bankruptcy Code. GenOn Energy Holdings and most of the other Mirant Debtors emerged from bankruptcy on January 3, 2006, when the 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 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 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.

Note 9 — Regulatory Matters (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

This footnote should be read in conjunction with the complete description under Note 17, Regulatory Matters, to the Registrants' 2014 Form 10-K.

The Registrants operate in a highly regulated industry and are subject to regulation by various federal and state agencies. As such, the Registrants are affected by regulatory developments at both the federal and state levels and in the regions in which they operate. In addition, the Registrants are subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which they participate. These power markets are subject to ongoing legislative and regulatory changes that may impact the Registrants' wholesale business.

In addition to the regulatory proceedings noted below, the Registrants 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 the Registrants’ respective consolidated financial position, results of operations, or cash flows.

National

Court Rejects FERC's Jurisdiction Over Demand Response — On May 23, 2014, the D.C. Circuit vacated FERC’s rules (known as Order No. 745) that allowed demand response resources to participate in FERC-jurisdictional energy markets. The Court of Appeals held that the FPA does not authorize FERC to exercise jurisdiction over demand response and that instead demand response is part of the retail market over which the states have jurisdiction. The specific order being challenged related to energy market compensation, but this ruling also calls into question whether demand response will be permitted to participate in the capacity markets in the future. Parties including the U.S. Solicitor General filed petitions for a writ of certiorari with the U.S. Supreme Court. On May 4, 2015, the U.S. Supreme Court granted certiorari on two questions: first, on whether the FPA gives FERC jurisdiction over demand response, and second, whether FERC was arbitrary and capricious when it established in Order No. 745 the level of compensation to be paid to demand response resources participating in the wholesale energy markets. On July 16, 2015, the Registrants filed an amicus brief with the U.S. Supreme Court. The U.S. Supreme Court heard oral argument on October 14, 2015. The eventual outcome of this proceeding could result in refunds of payments made for non-jurisdictional services and resettlement of wholesale markets, but it is not possible to predict the outcome or estimate the impact on the Registrants at this time.

East Region

Montgomery County Station Power Tax — On December 20, 2013, NRG received a letter from Montgomery County, Maryland requesting payment of an energy tax for the consumption of station power at the Dickerson Facility over the previous three years. Montgomery County seeks payment in the amount of $22 million, which includes tax, interest and penalties. NRG is disputing the applicability of the tax. On December 17, 2014, the Maryland Tax Court heard oral arguments from the parties. Subsequently, post hearing briefs were filed. The decision is pending.

Note 10 — Environmental Matters (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

This footnote should be read in conjunction with the complete description under Note 18, Environmental Matters, to the Registrants' 2014 Form 10-K.

The Registrants are 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. The Registrants are also subject to laws and regulations surrounding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. Environmental laws have become increasingly stringent and the Registrants expect this trend to continue. The electric generation industry is facing new requirements to address various emissions, including GHG, as well as combustion byproducts, water discharge and use, and threatened and endangered species. 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 Registrants' facilities, which could have a material effect on the Registrants' operations.

The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address each state's obligation 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 D.C. Circuit ordered the EPA to revise the Phase 2 (or 2017) (i) SO₂budgets for four states and (ii) ozone-season NO_xbudgets for 11 states including Maryland, New Jersey, New York, Ohio and Pennsylvania. While the Registrants cannot predict the final outcome of this rulemaking, the Registrants believe their investment in pollution controls and cleaner technologies coupled with planned plant retirements leave the fleet well positioned for compliance.

In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which limits must be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacate the MATS rule but rather remanded it to the D.C. Circuit for further proceedings.

Water

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

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. These byproducts will be regulated as solid wastes. The Registrants are evaluating the impact of the new rule on their results of operations, financial condition and cash flows and have accrued their environmental and asset retirement obligations under the rule based on current estimates as of September 30, 2015.

East Region

Maryland Environmental Regulations — In December 2014, MDE proposed a regulation regarding NO_x emissions from coal-fired electric generating units, which if finalized would have required by 2020 the Registrants (at each of the three Dickerson coal-fired units and the Chalk Point coal-fired unit that does not have an SCR) to either (1) install and operate an SCR; (2) retire the unit; or (3) convert the fuel source from coal to natural gas. In early 2015, a new gubernatorial administration in Maryland decided not to finalize the regulation as proposed. In September 2015, MDE proposed revised regulations to address future NO_xreductions, which when finalized may negatively affect certain of the Registrants' coal-fired units in Maryland.

Environmental Capital Expenditures

GenOn estimates that environmental capital expenditures from 2015 through 2019 required to comply with environmental laws will be approximately $98 million for GenOn, which includes $16 million for GenOn Americas Generation. The amount for GenOn Americas Generation includes $10 million for GenOn Mid-Atlantic. The majority of these costs will be expended by the end of 2016. The increase in environmental capital expenditures for GenOn relates to the Avon Lake Unit 9 MATS compliance project.

Item 2 — MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

As you read this discussion and analysis, refer to the Registrants' Condensed Consolidated Financial Statements to this Form 10-Q, which present the results of operations for the three and nine months ended September 30, 2015, and 2014. Also, refer to the Registrants' 2014 Form 10-K, which includes detailed discussions of various items impacting the Registrants' business, results of operations and financial condition.

Overview

The following table summarizes the generation portfolio as of September 30, 2015, by Registrant:



	(In MW)
Generation Type	GenOn	GenOn Americas Generation	GenOn Mid-Atlantic
Natural gas ^(a)(d)	10,762	4,118	1,942
Coal^(b)	5,143	2,433	2,433
Oil^(c)	1,847	1,434	308
Total generation capacity	17,752	7,985	4,683


(a)	GenOn's natural gas generation portfolio does not include 463 MW related to Osceola, which was mothballed on January 1, 2015; 636 MW related to Coolwater, which was retired on January 1, 2015; 160 MW related to Glen Gardner, which was retired on May 1, 2015; and 98 MW related to Gilbert, which was retired on May 1, 2015.


(b)	GenOn’s coal generation portfolio does not include 597 MW related to Shawville, which was mothballed on May 31, 2015 with plans to return to service with a natural gas addition in Summer 2016.


(c)	GenOn’s oil generation portfolio does not include 212 MW related to Werner, which was retired on May 1, 2015.


(d)	GenOn Americas Generation's natural gas generation portfolio increased 389 MW as Bowline Unit 2 was restored to full capacity on June 23, 2015, following a boiler restoration.

Regulatory Matters

The Registrants' regulatory matters are described in the Registrants' 2014 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 9, Regulatory Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q as found in Item 1.

As owners of power plants and participants in wholesale energy markets, certain of the Registrants' subsidiaries are subject to regulation by various federal and state government agencies. These include the CFTC and FERC, as well as other public utility commissions in certain states where the Registrants' generating assets are located. In addition, the Registrants are subject to the market rules, procedures and protocols of the various ISO markets in which they participate. The Registrants must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where they operate.

East Region

PJM

PJM Auction Results — On August 21, 2015, PJM announced the results of its 2018/2019 Base Residual Auction, officially integrating the new Capacity Performance product into the market. GenOn cleared approximately 8,610 MWs of Capacity Performance product and 464 MWs of Base Capacity product in the 2018/2019 Base Residual Auction. GenOn's expected capacity revenues from the 2018/2019 Base Residual Auction are approximately $565 million. GenOn Americas Generation (including GenOn Mid-Atlantic) cleared approximately 3,801 MWs of Capacity Performance product and 58 MWs of Base Capacity product in the 2018/2019 Base Residual Auction. GenOn Americas Generation's (including GenOn Mid-Atlantic) expected capacity revenues from the 2018/2019 Base Residual Auction are approximately $232 million. PJM announced the results of its Transitional Capacity Auctions for the 2016/2017 and 2017/2018 delivery years, respectively, on August 31, 2015, and September 9, 2015. GenOn cleared approximately 850 MWs of Capacity Performance product in the 2016/2017 Transactional Capacity Auction, and 5,897 MWs of Capacity Performance product in the 2017/2018 Transitional Capacity Auctions. GenOn Americas Generation (including GenOn Mid-Atlantic) cleared approximately 2,501 MWs of Capacity Performance product in the 2017/2018 Transitional Capacity Auctions. GenOn and GenOn Americas Generation (including GenOn Mid-Atlantic) expect an approximate $170 million and $50 million increase in PJM capacity revenue, respectively, from 2016/2017 to 2018/2019 due to the Capacity Performance product.

The tables below provide a detailed description of the Registrant's Base Residual Auction results:

GenOn:



	Base Capacity Product		Capacity Performance Product
Zone	Cleared Capacity (MW)⁽¹⁾	Price ($/MW-day)	Cleared Capacity (MW)⁽¹⁾	Price ($/MW-day)
COMED	—	$200.21	579	$215.00
EMAAC	91	$210.63	424	$225.42
MAAC	67	$149.98	6,431	$164.77
RTO	306	$149.98	1,176	$164.77
Total	464		8,610

(1) Includes imports.

GenOn Americas Generation & GenOn Mid-Atlantic:



	Base Capacity Product		Capacity Performance Product
Zone	Cleared Capacity (MW)⁽¹⁾	Price ($/MW-day)	Cleared Capacity (MW)⁽¹⁾	Price ($/MW-day)
MAAC ⁽²⁾	58	$149.98	3,801	$164.77
Total	58		3,801

(1) Includes imports.

(2) Plants that participate in the PJM auctions for GenOn Americas Generation are solely those operated by GenOn Mid-Atlantic.

Capacity Performance Rehearings — On June 9, 2015, FERC approved a substantial revamp to PJM’s capacity market. Major elements of the approved changes to the Capacity Performance framework include the calculation of the bid cap, elimination of the 2.5% holdback for short lead-time resources, and substantial new performance penalties on Capacity Performance resources that do not perform in real time during specific periods of high demand. The new rules mandate that underperformance penalties be paid to units that over perform during those periods of high demand. The Registrants' actual revenues will be the combination of the revenues based on the cleared auction MWs plus the net of any over and under performance of the Registrants' fleet. On July 9, 2015, multiple parties, including the Registrants, filed requests for rehearings at FERC regarding the framework of the new annual capacity auctions. Rehearing is pending.

In addition, multiple parties sought clarification on whether Demand Resources could participate in the Capacity Performance Transition Auctions. On July 22, 2015, FERC issued an Order allowing demand response and energy efficiency resources to participate in the upcoming Capacity Performance Transition Auctions. Rehearing is pending.

New Jersey and Maryland's Generator Contracting Programs — The New Jersey Board of Public Utilities and the Maryland Public Service Commission awarded long-term power purchase contracts to generation developers to encourage the construction of new generation capacity in the respective states. The constitutionality of the long-term contracts was challenged and the U.S. District Court for the District of New Jersey (in an October 25, 2013, decision) and the U.S. District Court for the District of Maryland (in an October 24, 2013, decision) found that the respective contracts violated the Supremacy Clause of the U.S. Constitution and were preempted. On June 30, 2014, the U.S. Court of Appeals for the Fourth Circuit affirmed the Maryland District Court's decision. On September 11, 2014, the U.S. Court of Appeals for the Third Circuit affirmed the New Jersey District Court's decision. Various parties filed petitions for a writ of certiorari seeking U.S. Supreme Court review of both cases. On October 19, 2015, the U.S. Supreme Court granted certiorari in the Fourth Circuit case. The outcome of this litigation and the validity of the contracts may affect future capacity prices in PJM.

NextEra/Direct Energy Complaint Against PJM on Capacity Performance Transition Auctions — On August 6, 2015, NextEra and Direct Energy filed a complaint challenging PJM’s methodology for conducting its transitional capacity auction. NRG protested the complaint. On August 25, 2015, FERC denied the NextEra/Direct Energy complaint finding that the complainants did not demonstrate that PJM’s clearing methodology failed to follow its tariff, or is unjust and unreasonable.

Complaint Against PJM on RPM Load Forecasts — On June 30, 2015, a group of consumer advocates and state PSCs filed a complaint against PJM alleging that PJM has violated Section 206 of the FPA by failing to update its methodology for defining load forecast for purposes of the upcoming annual Base Residual Auction and the Transition Auctions. Briefing is underway. Any change to the load forecast of the underlying models could affect capacity prices going forward.

MOPR Revisions — On May 2, 2013, FERC accepted PJM's proposal to substantially revise its Minimum Offer Price Rule. Among other things, FERC approved the portions of the PJM proposal that exempt many new entrants from demonstrating that their proposed projects are economic, as well as providing a similar exemption from public power entities and certain self-supply entities. This exemption is subject to certain conditions designed to limit the financial incentive of such entities to suppress market prices. On June 3, 2013, NRG filed a request for rehearing of the FERC order and subsequently protested the manner in which PJM proposed to implement the FERC order. On October 15, 2015, FERC denied the requests for rehearing and accepted PJM’s compliance filing. NRG is now considering appealing FERC’s decision.

New York

Competitive Entry Exemption to Buyer-Side Mitigation Rules — On December 4, 2014, pursuant to Section 206 of the FPA, a group of New York transmission owners filed a complaint seeking a competitive entry exemption to the current NYISO buyer-side mitigation rules. On December 16, 2014, TDI USA Holdings Corporation filed a complaint under Section 206 of the FPA against the NYISO claiming that the NYISO’s application of the Mitigation Exemption Test under the buyer-side mitigation rules to TDI’s Champlain Hudson 1,000 MW transmission line project is unjust and unreasonable and seeks an exemption from the Mitigation Exemption Test. On February 26, 2015, FERC granted the complaint filed by the New York transmission owners and directed the NYISO to adopt a competitive entry exemption into its tariff within 30 days. In a companion order issued on the same day, FERC rejected the TDI complaint on the grounds that TDI’s concerns were adequately addressed by FERC’s first order. On March 30, 2015, NRG filed a request for rehearing. On August 4, 2015, FERC granted in part and denied in part the rehearing requests and conditionally accepted NYISO's compliance filing subject to revisions clarifying that the competitive entry exemption is not available for generator or unforced capacity deliverability rights projects that are members of the completed class years.

Revisions to the Buyer-Side Mitigation Rules — On May 8, 2015, several New York entities, including the NYSPSC, filed a complaint against the NYISO under Section 206 of the FPA seeking revisions to the buyer-side market power mitigation measures of the NYISO tariff. The parties requested FERC to find that the current buyer-side mitigation rules are unjust and unreasonable because they prevent the ICAP market from functioning properly and that the rules should apply only to a limited subset of generation facilities. NRG protested the complaint. On October 9, 2015, FERC held that certain renewables and self-supply resources should be exempt from buyer-side mitigation rules. Vast amounts of uneconomic resources could enter the market and harm current and future investments.

Gulf Coast Region

MISO (GenOn)

Complaints regarding the 2015/2016 Planning Resource Auction — In May 2015, the Illinois Attorney General, Public Citizen, Inc., and Southwestern Electric Cooperative, Inc. filed complaints against MISO on the grounds that the results of the MISO 2015/2016 Planning Resource Auction resulted in unjust and unreasonable prices, specifically the auction clearing price in Zone 4. NRG, on behalf of itself and GenOn, filed comments providing its view on the rationale for the market outcome. On October 20, 2015, FERC held a technical conference on MISO's Planning Resource Auction, which in part addressed whether 2015/2016 delivery year prices were valid. The matter remains pending at FERC.

Consumer Group Complaint Seeking Reforms — On June 30, 2015, the Illinois Energy Consumers filed at FERC a complaint under Section 206 of the FPA regarding MISO’s Planning Resource Auction tariff provisions, stating that the current MISO tariff does not produce just and reasonable results. The complaint suggests specific tariff modifications to address these alleged deficiencies, particularly as to the initial reference level price and the failure of the MISO tariff to count capacity sold in neighboring capacity markets toward meeting Local Clearing Requirements in effect for the zones where capacity is physically located. On October 20, 2015, FERC held a technical conference on MISO's Planning Resource Auction, which in part addressed possible changes to MISO's auction design. The matter remains pending at FERC.

Environmental Matters

The Registrants are subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require governmental authorizations to build and operate power plants. Environmental laws have become increasingly stringent and the Registrants expect this trend to continue. The Registrants' environmental matters are described in the Registrants' 2014 Form 10-K in Item 1, Business — Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 10, Environmental Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q as found in Item 1 and as follows.

On October 23, 2015, the EPA promulgated the final GHG emissions rules for new and existing fossil-fuel-fired electric generating units. The Registrants are evaluating the potential impacts of these rules regarding existing units. The Registrants expect that it will take several years for the impacts of these rules to be fully known and to take effect because of the likely legal challenges and because it may take several years for states to develop and put in place plans that will be required to implement these rules and to achieve state-specific goals.

On October 26, 2015, the EPA promulgated a rule that reduces the ozone NAAQS to 0.070 ppm. This more stringent NAAQS will obligate the states to develop plans to reduce NO_x (an ozone precursor), which could affect some of the Registrants' units.

On November 3, 2015, the EPA promulgated a rule revising the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which will result in more stringent requirements for wastewater streams from flue gas desulfurization, fly ash, bottom ash, flue gas mercury control and gasification of fuels such as coal. The Registrants will be reviewing this rule in concert with the Coal Combustion Byproducts rule to evaluate the impact on operations.

Changes in Accounting Standards

See Note 2, Summary of Significant Accounting Policies, to this Form 10-Q as found in Item 1, for a discussion of recent accounting developments.

Consolidated Results of Operations

GenOn

The following table provides selected financial information for GenOn:



	Three months ended September 30,								Nine months ended September 30,
(In millions except otherwise noted)	2015			2014			Change %		2015			2014			Change %
Operating Revenues
Energy revenue ^(a)	$	420		$	478		(12	)%	$	1,415		$	1,888		(25	)%
Capacity revenue ^(a)	234			221			6		606			730			(17	)
Mark-to-market for economic hedging activities	(17		)	3			N/M		(91		)	(340		)	73
Other revenues ^(b)	8			7			14		26			39			(33	)
Total operating revenues	645			709			(9	)	1,956			2,317			(16	)
Operating Costs and Expenses
Generation cost of sales ^(a)	264			280			(6	)	859			1,217			(29	)
Mark-to-market for economic hedging activities	8			5			(60	)	67			(18		)	(472	)
Contract and emissions credit amortization	(5		)	(10		)	(50	)	(22		)	(16		)	38
Operations and maintenance	148			152			3		505			508			1
Other cost of operations	24			27			(11	)	70			64			9
Total cost of operations	439			454			(3	)	1,479			1,755			(16	)
Depreciation and amortization	52			52			—		163			172			(5	)
Impairment loss	—			60			(100	)	—			60			(100	)
General and administrative	—			19			(100	)	—			60			(100	)
General and administrative - affiliate	43			31			39		135			90			50
Acquisition-related transaction and integration costs	—			1			(100	)	—			3			(100	)
Total operating costs and expenses	534			617			(13	)	1,777			2,140			(17	)
Loss on sale of assets	—			—			—		—			(6		)	100
Operating Income	111			92			21		179			171			5
Other Income/(Expense)
Other income, net	—			2			(100	)	4			4			—
Interest expense	(52		)	(48		)	8		(154		)	(149		)	3
Total other expense	(52		)	(46		)	13		(150		)	(145		)	3
Income Before Income Taxes	59			46			28		29			26			12
Income tax expense	1			—			100		—			2			(100	)
Net Income	$	58		$	46		26		$	29		$	24		21
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	2.77		$	4.06		(32	)%	$	2.80		$	4.55		(38	)%
MWh sold (in thousands)	8,517			7,594			12		22,882			25,467			(10	)
MWh generated (in thousands)	9,055			8,527			6		25,952			27,949			(7	)


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


(b)	Includes unrealized trading gains and losses.

N/M - Not meaningful.

Electricity Prices

The following tables summarize average on-peak power prices for each of the major markets in which the Registrants operate for the three and nine months ended September 30, 2015, and 2014. Average on-peak power prices decreased primarily due to the decrease in natural gas prices for the three and nine months ended September 30, 2015, as compared to the same periods in 2014.



	Average on Peak Power Price ($/MWh) ^(a)
	Three months ended September 30,
	2015	2014
MISO - Louisiana Hub^(b)	35.03	39.15
NY J/NYC	41.32	41.19
NY A/West NY	40.68	43.02
NEPOOL	42.68	41.28
PEPCO (PJM)	42.62	45.25
PJM West Hub	39.35	41.34
CAISO - NP15	37.20	48.47
CAISO - SP15	38.20	49.16

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

(b) Region also transacts in PJM - West Hub.



	Average on Peak Power Price ($/MWh) ^(a)
	Nine months ended September 30,
Region	2015	2014
MISO - Louisiana Hub^(b)	37.14	52.36
NY J/NYC	52.51	81.43
NY A/West NY	44.46	64.43
NEPOOL	53.31	84.26
PEPCO (PJM)	49.52	77.48
PJM West Hub	45.33	68.08
CAISO - NP15	37.01	51.41
CAISO - SP15	32.86	50.11

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

(b) Region also transacts in PJM - West Hub.

Economic Gross Margin

The Registrants evaluate their 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 is defined as the sum of energy revenue, capacity revenue and other revenue, less cost of sales.

The 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 following tables presents the composition of economic gross margin for the three and nine months ended September 30, 2015 and 2014:



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Energy revenue	$	420		$	478		$	1,415		$	1,888
Capacity revenue	234			221			606			730
Other revenues	8			7			26			39
Generation revenue	662			706			2,047			2,657
Generation cost of sales	(264		)	(280		)	(859		)	(1,217		)
Economic gross margin	$	398		$	426		$	1,188		$	1,440

Economic gross margin decreased by $28 million for the three months ended September 30, 2015, compared to the same period in 2014 due to:



	(In millions)
Lower gross margin due to an 18% decrease in average realized prices, partially offset by lower fuel costs driven by significantly lower natural gas prices in 2015	(48		)
Lower gross margin due to a drop in contracted capacity volumes primarily due to the retirement of Coolwater in 2015, combined with lower contracted capacity prices in CAISO driven primarily by the expiration of certain tolling arrangements, which were replaced with lower priced agreements	(16		)
Lower gross margin due to higher purchased capacity to meet capacity supply obligations for deactivated units	(9		)
Higher gross margin due to a 7% increase in generation, partially offset by deactivations during the current year	18
Higher gross margin due to a 37% increase in PJM cleared auction capacity prices, partially offset by a 14% decrease in PJM cleared auction capacity volumes	27
	$	(28	)

Economic gross margin decreased by $252 million for the nine months ended September 30, 2015, compared to the same period in 2014 due to:



	(In millions)
Lower gross margin due to a 7% decrease in generation due to prior year weather conditions in the East as well as a decrease in average realized prices driven by significantly lower natural gas prices in 2015	$	(102	)
Lower gross margin due to a 16% decrease in PJM cleared auction capacity prices	(77		)
Lower gross margin due to a drop in contracted capacity volumes primarily due to the retirement of Coolwater and Osceola in 2015, combined with lower contracted capacity prices in CAISO driven primarily by the expiration of certain tolling arrangements, which were replaced with lower priced agreements	(78		)
Lower gross margin due to higher purchased capacity to meet capacity supply obligations for deactivated units	(14		)
Lower gross margin due to market adjustments for fuel oil inventory	(16		)
Higher gross margin due to a 51% decrease in natural gas prices, partially offset by a 19% decrease in average realized energy prices	17
Higher gross margin due to increased capacity contracts for Bowline as well as an increase of 75% in prices in New York during 2015	22
Other	(4		)
	$	(252	)

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.

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



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(22	)	$	(63	)	$	(154	)	$	(225	)
Net unrealized gains/(losses) on open positions related to economic hedges	5			66			63			(115		)
Total mark-to-market (losses)/gains in operating revenues	$	(17	)	$	3		$	(91	)	$	(340	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	3		$	4		$	8		$	15
Net unrealized (losses)/gains on open positions related to economic hedges	(11		)	(9		)	(75		)	3
Total mark-to-market (losses)/gains in operating costs and expenses	$	(8	)	$	(5	)	$	(67	)	$	18

Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.

For the three months ended September 30, 2015, the $17 million loss in operating revenues from economic hedge positions was primarily driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period, partially offset by an increase in the value of forward sales of power contracts as a result of decreases in forward power prices. The $8 million loss in operating costs and expenses from economic hedge positions was primarily driven by a decrease in the value of forward purchases of fuel contracts as a result of decreases in forward coal prices.

For the three months ended September 30, 2014, the $3 million gain in operating revenues from economic hedge positions was driven by an increase in the value of forward sales of natural gas contracts as a result of decreases in forward natural gas prices, largely offset by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period. The $5 million loss in operating costs and expenses from economic hedge positions was driven by a decrease in the value of forward purchases of fuel contracts as a result of decreases in forward coal prices, partially offset by the reversal of previously recognized unrealized losses from fuel contracts that settled during the period.

For the nine months ended September 30, 2015, the $91 million loss in operating revenues from economic hedge positions was primarily driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period, partially offset by an increase in the value of forward sales of power contracts as a result of decreases in forward power prices. The $67 million loss in operating costs and expenses from economic hedge positions was primarily driven by a decrease in the value of forward purchases of fuel contracts as a result of decreases in forward coal prices.

For the nine months ended September 30, 2014, the $340 million loss in operating revenues from economic hedge positions was driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period and a decrease in the value of forward sales of electricity contracts as a result of increases in forward power prices. The $18 million gain in operating costs and expenses from economic hedge positions was driven by the reversal of previously recognized unrealized losses from fuel contracts that settled during the period and an increase in the value of forward purchases of fuel contracts as a result of increases in forward coal prices.

In accordance with ASC 815, the following table represents the results of GenOn's financial and physical trading of energy commodities. The realized and unrealized financial and physical trading results are included in other operating revenues. GenOn's trading activities are subject to limits within the risk management policy. GenOn had no trading gains or losses for the three and nine months ended September 30, 2015.



	Three months ended September 30,				Nine months ended September 30,
(In millions)	2015		2014		2015		2014
Trading gains/(losses)
Realized	$	—	$	—	$	—	$	2
Unrealized	—		—		—		(1		)
Total trading gains	$	—	$	—	$	—	$	1

Operations and Maintenance

Operations and maintenance decreased by $4 million for the three months ended September 30, 2015, compared to the same period in 2014 primarily due to lower variable costs resulting from less generation during the quarter. Operations and maintenance decreased by $3 million for the nine months ended September 30, 2015, compared to the same period in 2014 primarily due to increased outage hours at Canal, Morgantown and Bowline during the current year.

Other Cost of Operations

Other cost of operations decreased by $3 million for the three months ended September 30, 2015, compared to the same period in 2014 primarily due to a property tax settlement received for Morgantown in 2015. Other cost of operations increased by $6 million for the nine months ended September 30, 2015, compared to the same period in 2014 primarily due to adjustments to AROs related to Shawville, and Maryland ash in 2014, partially offset by a property tax settlement received in 2015 for Morgantown and lower property tax rates for GenOn Mid-Atlantic.

Impairment Loss

For the three and nine months ended September 30, 2014, GenOn recorded an impairment loss of $60 million related to the Osceola facility, as described in Note 2, Summary of Significant Accounting Policies.

GenOn Americas Generation

The following table provides selected financial information for GenOn Americas Generation:



	Three months ended September 30,								Nine months ended September 30,
(In millions except otherwise noted)	2015			2014			Change %		2015			2014			Change %
Operating Revenues
Energy revenue ^(a)	$	365		$	441		(17	)	$	1,289		$	1,746		(26	)
Capacity revenue ^(a)	240			222			8		623			716			(13	)
Mark-to-market for economic hedging activities	(4		)	(27		)	85		(84		)	(265		)	68
Other revenues ^(b)	7			6			17		20			36			(44	)
Total operating revenues	608			642			(5	)	1,848			2,233			(17	)
Operating Costs and Expenses
Generation cost of sales ^(a)	411			445			(8	)	1,303			1,682			(23	)
Mark-to-market for economic hedging activities	9			8			13		48			(9		)	N/M
Contract and emissions credit amortization	—			—			—		—			11			(100	)
Operations and maintenance	65			64			2		246			215			14
Other cost of operations	11			17			(35	)	39			39			—
Total cost of operations	496			534			(7	)	1,636			1,938			(16	)
Depreciation and amortization	18			21			(14	)	55			70			(21	)
General and administrative	20			21			(5	)	61			65			(6	)
Total operating costs and expenses	534			576			(7	)	1,752			2,073			(15	)
Loss on sale of assets	—			—			—		—			(6		)	(100	)
Operating Income	74			66			12		96			154			(38	)
Other Expense
Interest expense	(18		)	(19		)	(5	)	(53		)	(56		)	(5	)
Total other expense	(18		)	(19		)	(5	)	(53		)	(56		)	(5	)
Income Before Income Taxes	56			47			19		43			98			(56	)
Income tax	—			—			—		—			—			—
Net Income	$	56		$	47		19		$	43		$	98		(56	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	2.77		$	4.06		(32	)	$	2.80		$	4.55		(38	)
MWh sold (in thousands)	3,104			2,695			15		8,111			10,241			(21	)
MWh generated (in thousands)	2,796			2,702			3		8,225			10,289			(20	)

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

(b) Includes unrealized trading gains and losses.

N/M - Not meaningful.

Economic Gross Margin



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Energy revenue	$	365		$	441		$	1,289		$	1,746
Capacity revenue	240			222			623			716
Other revenues	7			6			20			36
Generation revenue	612			669			1,932			2,498
Generation cost of sales	(411		)	(445		)	(1,303		)	(1,682		)
Economic gross margin	$	201		$	224		$	629		$	816

Economic gross margin reflects the following pass-through amounts for GenOn Energy Management for services including the bidding and dispatch of the generating units, fuel procurement and the execution of contracts, including economic hedges, to reduce price risk:



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Energy revenue	$	176		$	203		$	578		$	716
Capacity revenue	123			124			310			386
Other revenues	9			13			12			23
Generation revenue	308			340			900			1,125
Generation cost of sales	(308		)	(340		)	(900		)	(1,125		)
Economic gross margin	$	—		$	—		$	—		$	—

Economic gross margin decreased by $23 million for the three months ended September 30, 2015, compared to the same period in 2014 due to:



	(In millions)
Lower gross margin at GenOn Mid-Atlantic due to an 18% decrease in average realized prices and a decrease in fuel costs due to significantly lower natural gas prices in 2015	$	(27	)
Lower gross margin at GenOn Mid-Atlantic due to a 13% decrease in generation as a result of an increase in planned and unplanned outage hours	(18		)
Lower gross margin due to higher purchased capacity to meet capacity supply obligations for deactivated units	(5		)
Higher gross margin due to a 32% increase in PJM cleared auction capacity prices, partially offset by an 8% decrease in PJM cleared auction capacity volumes	15
Higher gross margin due to a 77% increase in generation at Bowline	12
	$	(23	)

Economic gross margin decreased by $187 million for the nine months ended September 30, 2015, compared to the same period in 2014 due to:



	(In millions)
Lower gross margin at GenOn Mid-Atlantic due a 32% decrease in generation as a result of prior year weather conditions and an increase in planned and unplanned outage hours in 2015	$	(116	)
Lower gross margin at GenOn Mid-Atlantic due to a 19% decrease in average realized prices and a decrease in fuel costs due to significantly lower natural gas prices in 2015	(54		)
Lower gross margin due to a 14% decrease in PJM cleared auction capacity prices and a 5% decrease in PJM cleared auction capacity volumes	(45		)
Lower gross margin due to a 30% decrease in generation at Canal offset by a 19% increase in generation at Bowline primarily due to the timing of outages	(16		)
Lower gross margin due to market adjustments for fuel oil inventory	(15		)
Lower gross margin due to higher purchased capacity to meet capacity supply obligations for deactivated units	(14		)
Higher gross margin due to decrease in fuel costs as natural gas prices dropped by 47% in New York and New England, partially offset by a 13% decrease in average realized prices	48
Higher gross margin due to increased capacity contracts for Bowline as well as an increase of 74% in capacity prices in New York during 2015	22
Other	3
	$	(187	)

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.

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



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(26	)	$	(68	)	$	(163	)	$	(212	)
Net unrealized gains/(losses) on open positions related to economic hedges	22			41			79			(53		)
Total mark-to-market losses in operating revenues	$	(4	)	$	(27	)	$	(84	)	$	(265	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	3		$	3		$	10		$	11
Net unrealized losses on open positions related to economic hedges	(12		)	(11		)	(58		)	(2		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(9	)	$	(8	)	$	(48	)	$	9

Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.

For the three months ended September 30, 2015, the $4 million loss in operating revenues from economic hedge positions was primarily driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period, largely offset by an increase in the value of forward sales of power contracts as a result of decreases in forward power prices. The $9 million loss in operating costs and expenses from economic hedge positions was primarily driven by a decrease in the value of forward purchases of fuel contracts as a result of decreases in forward coal prices.

For the three months ended September 30, 2014, the $27 million loss in operating revenues from economic hedge positions was driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period, partially offset by an increase in the value of forward sales of natural gas contracts as a result of decreases in forward natural gas prices. The $8 million loss in operating costs and expenses from economic hedge positions was driven by a decrease in the value of forward purchases of fuel contracts as a result of decreases in forward coal prices, partially offset by the reversal of previously unrealized losses from fuel contracts that settled during the period.

For the nine months ended September 30, 2015, the $84 million loss in operating revenues from economic hedge positions was primarily driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period, partially offset by an increase in the value of forward sales of power and natural gas contracts as a result of decreases in forward power and natural gas prices. The $48 million loss in operating costs and expenses from economic hedge positions was primarily driven by a decrease in the value of forward purchases of fuel contracts as a result of decreases in forward coal prices.

For the nine months ended September 30, 2014, the $265 million loss in operating revenues from economic hedge positions was driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period and a decrease in the value of forward sales of electricity contracts as a result of increases in forward power prices. The $9 million gain in operating costs and expenses from economic hedge positions was primarily driven by the reversal of previously recognized unrealized losses from fuel contracts that settled during the period.

In accordance with ASC 815, the following table represents the results of GenOn Americas Generation's financial and physical trading of energy commodities. The realized and unrealized financial and physical trading results are included in other operating revenues. GenOn Americas Generation's trading activities are subject to limits within the risk management policy. GenOn Americas Generation had no trading gains or losses for the three and nine months ended September 30, 2015.



	Three months ended September 30,				Nine months ended September 30,
(In millions)	2015		2014		2015		2014
Trading gains/(losses)
Realized	$	—	$	—	$	—	$	2
Unrealized	—		—		—		(1		)
Total trading gains	$	—	$	—	$	—	$	1

Operations and Maintenance

Operations and maintenance increased by $1 million for the three months ended September 30, 2015, compared to the same period in 2014 due to increased outage hours at Canal and Morgantown in the current quarter, partially offset by lower variable costs resulting from less generation during the quarter. Operations and maintenance increased by $31 million for the nine months ended September 30, 2015, compared to the same period in 2014 due to increased outage hours at Canal, Morgantown and Bowline during the current year, partially offset by lower variable costs due to lower generation.

Other Cost of Operations

Other cost of operations decreased by $6 million for the three months ended September 30, 2015, compared to the same period in 2014 due to a property tax settlement received for Morgantown during 2015 and lower property tax rates at GenOn Mid-Atlantic. Other cost of operations did not change for the nine months ended September 30, 2015, compared to the same period in 2014.

GenOn Mid-Atlantic

The following table provides selected financial information for GenOn Mid-Atlantic:



	Three months ended September 30,								Nine months ended September 30,
(In millions except otherwise noted)	2015			2014			Change %		2015			2014			Change %
Operating Revenues
Energy revenue ^(a)	$	149		$	211		(29	)%	$	529		$	799		(34	)%
Capacity revenue ^(a)	69			56			23		183			224			(18	)
Mark-to-market for economic hedging activities	(1		)	(24		)	96		(29		)	(267		)	89
Other revenues	3			2			50		9			12			(25	)
Total operating revenues	220			245			(10	)	692			768			(10	)
Operating Costs and Expenses
Generation cost of sales ^(a)	85			96			(11	)	285			375			(24	)
Mark-to-market for economic hedging activities	2			8			(75	)	42			(10		)	N/M
Contract and emissions credit amortization	—			1			(100	)	—			10			(100	)
Operations and maintenance	45			49			(8	)	166			155			7
Other cost of operations	9			13			(31	)	29			34			(15	)
Total cost of operations	141			167			(16	)	522			564			(7	)
Depreciation and amortization	16			18			(11	)	49			61			(20	)
General and administrative — affiliate	15			15			—		44			48			(8	)
Total operating costs and expenses	172			200			(14	)	615			673			(9	)
Operating Income	48			45			7		77			95			(19	)
Other Expense
Interest expense	(1		)	(1		)	—		(3		)	(4		)	(25	)
Total other expense	(1		)	(1		)	—		(3		)	(4		)	(25	)
Income Before Income Taxes	47			44			7		74			91			(19	)
Income tax	—			—			—		—			—			—
Net Income	$	47		$	44		7		$	74		$	91		(19	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	2.77		$	4.06		(32	)	$	2.80		$	4.55		(38	)
MWh sold (in thousands)	2,303			2,241			3		6,427			8,576			(25	)
MWh generated (in thousands)	1,954			2,241			(13	)	6,410			8,576			(25	)

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

N/M - Not meaningful.

Economic Gross Margin



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Energy revenue	$	149		$	211		$	529		$	799
Capacity revenue	69			56			183			224
Other revenues	3			2			9			12
Generation revenue	221			269			721			1,035
Generation cost of sales	(85		)	(96		)	(285		)	(375		)
Economic gross margin	$	136		$	173		$	436		$	660

Economic gross margin decreased by $37 million for the three months ended September 30, 2015, compared to the same period in 2014 due to:



	(In millions)
Lower gross margin due to a 18% decrease in average realized prices and a decrease in fuel costs due to significantly lower natural gas prices in 2015	$	(27	)
Lower gross margin due to a 13% decrease in generation as a result of an increase in planned and unplanned outage hours	(18		)
Lower gross margin due to market adjustments for fuel oil inventory	(4		)
Higher gross margin due to a 32% increase in PJM cleared auction capacity prices, partially offset by an 8% decrease in PJM cleared auction capacity volumes	12
	$	(37	)

Economic gross margin decreased by $224 million for the nine months ended September 30, 2015, compared to the same period in 2014 due to:



	(In millions)
Lower gross margin due a 32% decrease in generation as a result of prior year weather conditions and an increase in planned and unplanned outage hours in 2015	$	(116	)
Lower gross margin due to a 19% decrease in average realized prices and a decrease in fuel costs due to significantly lower natural gas prices in 2015	(54		)
Lower gross margin due to a 14% decrease in PJM cleared auction capacity prices and a 5% decrease in PJM cleared auction capacity volumes	(41		)
Lower gross margin due to market adjustments for fuel oil inventory	(4		)
Other	(9		)
	$	(224	)

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.

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



	Three months ended September 30,						Nine months ended September 30,
(In millions)	2015			2014			2015			2014
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(23	)	$	(65	)	$	(89	)	$	(214	)
Net unrealized gains/(losses) on open positions related to economic hedges	22			41			60			(53		)
Total mark-to-market losses in operating revenues	$	(1	)	$	(24	)	$	(29	)	$	(267	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	3		$	2		$	10		$	11
Net unrealized losses on open positions related to economic hedges	(5		)	(10		)	(52		)	(1		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(2	)	$	(8	)	$	(42	)	$	10

Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.

For the three months ended September 30, 2015, the $1 million loss in operating revenues from economic hedge positions was primarily driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period, largely offset by an increase in the value of forward sales of power contracts as a result of decreases in forward power prices. The $2 million loss in operating costs and expenses from economic hedge positions was primarily driven by a decrease in the value of forward purchases of fuel contracts as a result of decreases in forward coal prices.

For the three months ended September 30, 2014, the $24 million loss in operating revenues from economic hedge positions was driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period, partially offset by an increase in the value of forward sales of natural gas contracts as a result of decreases in forward natural gas prices. The $8 million loss in operating costs and expenses from economic hedge positions was primarily driven by a decrease in the value of forward purchases of fuel contracts as a result of decreases in forward coal prices.

For the nine months ended September 30, 2015, the $29 million loss in operating revenues from economic hedge positions was primarily driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period, partially offset by an increase in the value of forward sales of power and natural gas contracts as a result of decreases in forward power and natural gas prices. The $42 million loss in operating costs and expenses from economic hedge positions was primarily driven by a decrease in the value of forward purchases of fuel contracts as a result of decreases in forward coal prices.

For the nine months ended September 30, 2014, the $267 million loss in operating revenues from economic hedge positions was driven by the reversal of previously recognized unrealized gains from electricity and natural gas contracts that settled during the period and a decrease in the value of forward sales of electricity contracts as a result of increases in forward power prices. The $10 million gain in operating costs and expenses from economic hedge positions was primarily driven by the reversal of previously recognized unrealized losses from fuel contracts that settled during the period.

Operations and Maintenance

Operations and maintenance decreased by $4 million for the three months ended September 30, 2015, compared to the same period in 2014 primarily due lower variable costs resulting from less generation during the quarter. Operations and maintenance increased by $11 million for the nine months ended September 30, 2015, compared to the same period in 2014 primarily due to increased outage hours at Morgantown during the current year, partially offset by lower variable costs resulting from less generation during the quarter.

Other Cost of Operations

Other cost of operations decreased by $4 million for the three months ended September 30, 2015, compared to the same period in 2014 primarily due to a property tax settlement received in 2015 for Morgantown. Other cost of operations decreased by $5 million for the nine months ended September 30, 2015, compared to the same period in 2014 primarily due to lower property tax rates in 2015 and a property tax settlement received in 2015 for Morgantown.

Liquidity and Capital Resources

Liquidity Position

As of September 30, 2015, and December 31, 2014, the Registrants' liquidity was comprised of the following:



	September 30, 2015		December 31, 2014
	(In millions)
Cash and cash equivalents:
GenOn excluding GenOn Mid-Atlantic and REMA	$	576	$	441
GenOn Mid-Atlantic ^(a)	291		157
REMA ^(a)	226		322
Total	1,093		920
Credit facility availability	285		263
Total liquidity	$	1,378	$	1,183

(a) At September 30, 2015, REMA and GenOn Mid-Atlantic did not satisfy the restricted payment tests under certain of their agreements and therefore, could not use such funds to distribute cash and make other restricted payments.

For the nine months ended September 30, 2015, total liquidity increased $195 million.

Management believes that the Registrants' liquidity position and cash flows from operations will be adequate to finance operating, maintenance and capital expenditures, to fund debt service obligations and other liquidity commitments other than as described further below for GenOn.

GenOn’s financial position continues to be adversely affected by a sustained decline in natural gas prices and its resulting effect on wholesale power prices. As disclosed in Note 5, Debt and Capital Leases, certain of GenOn’s senior unsecured notes mature in 2017 and 2018. If GenOn is not able to refinance these notes, GenOn will consider all options available to it, including potential sales of certain generating assets or issuances of new debt securities. Given current economic and market conditions, including the depressed commodity markets, GenOn may be unable to complete these actions on a timely basis or on satisfactory terms or at all. These actions also may not be sufficient to enable GenOn to continue to satisfy its cash commitments as they become due. In addition, GenOn Mid-Atlantic and REMA are currently unable to make distributions of cash and certain other restricted payments to GenOn. NRG, GenOn’s parent company, has no obligation to provide any financial support other than as described in Note 7, Related Party Transactions.

Management continues to regularly monitor the ability of GenOn Americas Generation and GenOn Mid-Atlantic to finance the needs of its operating, financing and investing activities.

Restricted Payments Tests

The ability of certain of GenOn’s and GenOn Americas Generation’s subsidiaries to pay dividends and make distributions is restricted under the terms of certain agreements, including the GenOn Mid-Atlantic and REMA operating leases. Under their respective operating leases, GenOn Mid-Atlantic and REMA are not permitted to make any distributions and other restricted payments unless: (a) they satisfy the fixed charge coverage ratio for the most recently ended period of four fiscal quarters; (b) they are projected to satisfy the fixed charge coverage ratio for each of the two following periods of four fiscal quarters, commencing with the fiscal quarter in which such payment is proposed to be made; and (c) no significant lease default or event of default has occurred and is continuing. In addition, prior to making a dividend or other restricted payment, REMA must be in compliance with the requirement to provide credit support to the owner lessors securing its obligation to pay scheduled rent under its leases. Based on GenOn Mid-Atlantic’s and REMA’s most recent calculations of these tests, GenOn Mid-Atlantic and REMA did not satisfy the restricted payments tests. As a result, as of September 30, 2015, GenOn Mid-Atlantic and REMA could not make distributions of cash and certain other restricted payments. Each of GenOn Mid-Atlantic and REMA may recalculate its fixed charge coverage ratios from time to time and, subject to compliance with the restricted payments test described above, make dividends or other restricted payments.

The GenOn senior notes due 2018 and 2020 and the related indentures also restrict the ability of GenOn to incur additional liens and make certain restricted payments, including dividends. In the event of a default or if restricted payment tests are not satisfied, GenOn would not be able to distribute cash to its parent, NRG. At September 30, 2015, GenOn did not meet the consolidated debt ratio component of the restricted payments test.

Credit Ratings

On October 2, 2015, Standard & Poor's lowered its corporate credit ratings on GenOn, GenOn Mid-Atlantic, REMA and GenOn Americas Generation to CCC+ from B-. The ratings outlook for GenOn, GenOn Mid-Atlantic, REMA and GenOn Americas Generation is stable. Standard & Poor's also lowered the issue ratings on the GenOn senior notes, the pass-through certificates at GenOn Mid-Atlantic and the GenOn Americas Generation senior notes to B- from B. The issue rating on the pass-through certificates of REMA was lowered by Standard & Poor's to B from B+. Additionally, on September 5, 2015, Moody's lowered its outlook for GenOn, GenOn Mid-Atlantic, REMA and GenOn Americas Generation to negative.

The following table summarizes the Registrants' credit ratings of its senior notes as of November 4, 2015:



	S&P	Moody's
GenOn 7.875% Senior Notes, due 2017	B-	B3
GenOn 9.500% Senior Notes, due 2018	B-	B3
GenOn 9.875% Senior Notes, due 2020	B-	B3
GenOn Americas Generation 8.500% Senior Notes, due 2021	B-	Caa1
GenOn Americas Generation 9.125% Senior Notes, due 2031	B-	Caa1

Sources of Liquidity

The principal sources of liquidity for the Registrants' future operating and capital expenditures are expected to be derived from existing cash on hand and cash flows from operations. The Registrants' operating cash flows may be affected by, among other things, demand for electricity, the difference between the cost of fuel used to generate electricity and the market value of the electricity generated, commodity prices (including prices for electricity, emissions allowances, natural gas, coal and oil), operations and maintenance expenses in the ordinary course, planned and unplanned outages, terms with trade creditors, cash requirements for capital expenditures relating to certain facilities (including those necessary to comply with environmental regulations) and the potential impact of future environmental regulations.

Uses of Liquidity

The Registrants' requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) debt service obligations; (ii) capital expenditures, including maintenance and environmental; and (iii) payments under the GenOn Mid-Atlantic and REMA operating leases.

Capital Expenditures

The following tables and descriptions summarize the Registrant's capital expenditures for maintenance, environmental, and fuel conversions/ additions for the nine months ended September 30, 2015, and currently estimated capital expenditures forecast for the remainder of 2015.



	Maintenance		Environmental		Fuel Conversions/ Additions		Total
	(In millions)
Total cash capital expenditures for the nine months ended September 30, 2015
GenOn	$	101	$	26	$	48	$	175
GenOn Americas Generation	53		—		—		53
GenOn Mid-Atlantic	26		—		—		26
Estimated capital expenditures for the remainder of 2015
GenOn	39		17		67		123
GenOn Americas Generation	19		5		—		24
GenOn Mid-Atlantic	6		2		—		8

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

Item 3 has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H(2) to Form 10-Q.

ITEM 4 — CONTROLS AND PROCEDURES (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There were no changes in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the third quarter of 2015 that materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

PART II

OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

For a discussion of material legal proceedings in which the Registrants were involved through September 30, 2015, see Note 8, Commitments and Contingencies, to this Form 10-Q.

Item 1A — RISK FACTORS (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

Information regarding risk factors appears in Part I, Item 1A, Risk Factors, in the Registrants' 2014 Form 10-K. There have been no material changes in the Registrants' risk factors since those reported in the Registrants' 2014 Form 10-K.

Item 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

Item 2 has been omitted from this report for the Registrants pursuant to the reduced disclosure format permitted by General Instruction H(2) to Form 10-Q.

Item 3 — DEFAULTS UPON SENIOR SECURITIES (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

Item 3 has been omitted from this report for the Registrants pursuant to the reduced disclosure format permitted by General Instruction H(2) to Form 10-Q.

Item 4 — MINE SAFETY DISCLOSURES (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

Not applicable.

Item 5 — OTHER INFORMATION (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

None.

Item 6 — EXHIBITS (GenOn, GenOn Americas Generation and GenOn Mid-Atlantic)

GenOn Energy, Inc. Exhibit Index



Number	Description	Method of Filing
31.1A1	Rule 13a-14(a)/15d-14(a) certification of David Crane.	Filed herewith.
31.2A1	Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.	Filed herewith.
31.3A1	Rule 13a-14(a)/15d-14(a) certification of David Callen.	Filed herewith.
32.A1	Section 1350 Certification.	Filed herewith.
101 INS	XBRL Instance Document.	Filed herewith.
101 SCH	XBRL Taxonomy Extension Schema.	Filed herewith.
101 CAL	XBRL Taxonomy Extension Calculation Linkbase.	Filed herewith.
101 DEF	XBRL Taxonomy Extension Definition Linkbase.	Filed herewith.
101 LAB	XBRL Taxonomy Extension Label Linkbase.	Filed herewith.
101 PRE	XBRL Taxonomy Extension Presentation Linkbase.	Filed herewith.

GenOn Americas Generation, LLC Exhibit Index



Number	Description	Method of Filing
31.1A2	Rule 13a-14(a)/15d-14(a) certification of David Crane.	Filed herewith.
31.2A2	Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.	Filed herewith.
31.3A2	Rule 13a-14(a)/15d-14(a) certification of David Callen.	Filed herewith.
32.A2	Section 1350 Certification.	Filed herewith.
101 INS	XBRL Instance Document.	Filed herewith.
101 SCH	XBRL Taxonomy Extension Schema.	Filed herewith.
101 CAL	XBRL Taxonomy Extension Calculation Linkbase.	Filed herewith.
101 DEF	XBRL Taxonomy Extension Definition Linkbase.	Filed herewith.
101 LAB	XBRL Taxonomy Extension Label Linkbase.	Filed herewith.
101 PRE	XBRL Taxonomy Extension Presentation Linkbase.	Filed herewith.

GenOn Mid-Atlantic, LLC Exhibit Index



Number	Description	Method of Filing
31.1A3	Rule 13a-14(a)/15d-14(a) certification of David Crane.	Filed herewith.
31.2A3	Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.	Filed herewith.
31.3A3	Rule 13a-14(a)/15d-14(a) certification of David Callen.	Filed herewith.
32.A3	Section 1350 Certification.	Filed herewith.
101 INS	XBRL Instance Document.	Filed herewith.
101 SCH	XBRL Taxonomy Extension Schema.	Filed herewith.
101 CAL	XBRL Taxonomy Extension Calculation Linkbase.	Filed herewith.
101 DEF	XBRL Taxonomy Extension Definition Linkbase.	Filed herewith.
101 LAB	XBRL Taxonomy Extension Label Linkbase.	Filed herewith.
101 PRE	XBRL Taxonomy Extension Presentation Linkbase.	Filed herewith.

SIGNATURES

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



	GENON ENERGY, INC. (Registrant)

		/s/ DAVID CRANE

		David Crane Chief Executive Officer
		(Principal Executive Officer)

		/s/ KIRKLAND B. ANDREWS

		Kirkland B. Andrews Chief Financial Officer
		(Principal Financial Officer)

		/s/ DAVID CALLEN

		David Callen Chief Accounting Officer
		(Principal Accounting Officer)

Date: November 4, 2015

SIGNATURES

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



	GENON AMERICAS GENERATION, LLC (Registrant)

		/s/ DAVID CRANE

		David Crane Chief Executive Officer
		(Principal Executive Officer)

		/s/ KIRKLAND B. ANDREWS

		Kirkland B. Andrews Chief Financial Officer
		(Principal Financial Officer)

		/s/ DAVID CALLEN

		David Callen Chief Accounting Officer
		(Principal Accounting Officer)

Date: November 4, 2015

SIGNATURES

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



	GENON MID-ATLANTIC, LLC (Registrant)

		/s/ DAVID CRANE

		David Crane Chief Executive Officer
		(Principal Executive Officer)

		/s/ KIRKLAND B. ANDREWS

		Kirkland B. Andrews Chief Financial Officer
		(Principal Financial Officer)

		/s/ DAVID CALLEN

		David Callen Chief Accounting Officer
		(Principal Accounting Officer)

Date: November 4, 2015