UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

 
FORM 8-K/A
(Amendment No. 1)

 
CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
 
Date of report (Date of earliest event reported)  December 14, 2012
 
NRG Energy, Inc.
(Exact Name of Registrant as Specified in Its Charter)
 
Delaware
(State or Other Jurisdiction of Incorporation)
 
001-15891	 	41-1724239	
(Commission File Number)	 	(IRS Employer Identification No.)	
 	 	 	
211 Carnegie Center, Princeton, NJ	 	08540	
(Address of Principal Executive Offices)	 	(Zip Code)	
 
609-524-4500
(Registrant’s Telephone Number, Including Area Code)
 
Not Applicable
(Former Name or Former Address, if Changed Since Last Report)
 
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
 
o           Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
 
o           Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
 
o           Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
 
o           Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 
Introductory Note
 
As previously reported, on December 14, 2012, NRG Energy, Inc. (“NRG” or the “Company”) completed the previously announced merger contemplated by that certain Agreement and Plan of Merger, dated as of July 20, 2012, by and among NRG, GenOn Energy, Inc. (“GenOn”) and Plus Merger Corporation, a wholly-owned subsidiary of NRG. This Current Report on Form 8-K/A (the “Form 8-K/A”) amends the Current Report on Form 8-K filed by NRG with the Securities and Exchange Commission on December 14, 2012 to include the financial statements of GenOn and the pro forma financial information required by Items 9.01(a) and 9.01(b), respectively, and to include the exhibits under Item 9.01(d) of this Form 8-K/A.
 
Section 9 — Financial Statements and Exhibits
 
Item 9.01. Financial Statements and Exhibits.
 
(a)  Financial Statements of Businesses Acquired.
 
The audited consolidated financial statements of GenOn as of December 31, 2011 and 2010, and for each of the three years in the period ended December 31, 2011, and the unaudited consolidated financial statements of GenOn as of September 30, 2012 and for the three and nine months ended September 30, 2012 and 2011 are attached to this Form 8-K/A as Exhibit 99.1 and Exhibit 99.2, respectively, and are incorporated herein by reference.
 
(b)  Pro Forma Financial Information.
 
The unaudited pro forma condensed combined consolidated financial statements and explanatory notes relating to NRG’s acquisition of GenOn are attached as Exhibit 99.3 to this Form 8-K/A and are incorporated herein by reference.
 
(d)  Exhibits.
 
Exhibit No.	 	Description	
 	 	 	
23.1	 	Consent of KPMG LLP.	
 	 	 	
99.1	 	Audited consolidated financial statements of GenOn as of December 31, 2011 and 2010, and for each of the three years in the period ended December 31, 2011.	
 	 	 	
99.2	 	Unaudited consolidated financial statements of GenOn as of September 30, 2012, and for the three and nine months ended September 30, 2012 and 2011.	
 	 	 	
99.3	 	Unaudited pro forma condensed combined consolidated financial statements and explanatory notes for the year ended December 31, 2011 and the quarterly period ended September 30, 2012.	
 
* * * * *
 
2

 
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 hereunto duly authorized.
 
 	NRG Energy, Inc.	
 	(Registrant)	
 	 	
 	By:	 /s/ David R. Hill	
 	 	David R. Hill	
 	 	Executive Vice President and General Counsel	
 	 	
Dated: March 1, 2013	 	
 
3

Exhibit 23.1
 
Consent of Independent Registered Public Accounting Firm
 
The Stockholder
GenOn Energy, Inc.:
 
We consent to the incorporation by reference in the registration statement (No. 333-185501) on Form S-8, (No. 333-182379) on Form S-8, (No. 333-171318) on Form S-8, (No. 333-151992) on Form S-8, (No. 333-135973) on Form S-8, (No. 333-114007) on Form S-8, (No. 333-123677) on Form S-3, (No. 333-183334) on Form S-4, (No. 333-178024) on Form S-4, (No. 333-175470) on Form S-4 and (No. 333-171323) on Form S-4 of NRG Energy, Inc. of our reports dated February 29, 2012, with respect to the consolidated balance sheets of GenOn Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), cash flows, and the related financial statement schedules for each of the years in the three-year period ended December 31, 2011 and the effectiveness of internal control over financial reporting as of December 31, 2011, which reports appear in the Form 8-K/A of NRG Energy, Inc. dated March 1, 2013.
 
/s/ KPMG LLP
 
Houston, Texas
March 1, 2013

Exhibit 99.1
 
GenOn Energy, Inc.
Audited CONSOLIDATED Financial Statements
As of december 31, 2011 and 2010, and for each of the three years IN THE PERIOD ended december 31, 2011
 
(a)	1. Financial Statements	 	
 	 	 	
 	Report of Independent Registered Public Accounting Firm	F-1	
 	Consolidated Statements of Operations	F-2	
 	Consolidated Balance Sheets	F-3	
 	Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss)	F-4	
 	Consolidated Statements of Cash Flows	F-5	
 	Notes to the Consolidated Financial Statements	F-6	
 	 	 	
 	2. Financial Statement Schedules	 	
 	 	 	
 	Report of Independent Registered Public Accounting Firm	F-94	
 	Schedule I—Condensed Statements of Operations (Parent)	F-95	
 	Schedule I—Condensed Balance Sheets (Parent)	F-96	
 	Schedule I—Condensed Statements of Cash Flows (Parent)	F-97	
 	Schedule I—Notes to Registrant’s Condensed Financial Statements (Parent)	F-98	
 	Schedule II—Valuation and Qualifying Accounts	F-100	

 
Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders
GenOn Energy, Inc.:
 
We have audited the accompanying consolidated balance sheets of GenOn Energy, Inc. and subsidiaries (the Company) as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2011. We also have audited the Company’s internal control over financial reporting at December 31, 2011, based on criteria established in Internal Control — Integrated Framework  issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting within Item 9A. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GenOn Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in  Internal Control—Integrated Framework  issued by COSO.
 
/s/ KPMG LLP
 
Houston, Texas
February 29, 2012
 
F-1

 
GENON ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions, except per share data)
(See notes 1 and 2 on the Merger)	 	
Operating revenues (including unrealized gains (losses) of $227, $45 and $(2), respectively)	 	$	3,614	 	$	2,270	 	$	2,309	 	
Cost of fuel, electricity and other products (including unrealized (gains) losses of $3, $87 and $(49), respectively)	 	1,610	 	963	 	710	 	
Gross Margin (excluding depreciation and amortization)	 	2,004	 	1,307	 	1,599	 	
Operating Expenses:	 	 	 	 	 	 	 	
Operations and maintenance	 	1,293	 	846	 	610	 	
Depreciation and amortization	 	375	 	224	 	149	 	
Impairment losses	 	133	 	565	 	221	 	
Gain on sales of assets, net	 	(6	)	(4	)	(22	)	
Total operating expenses	 	1,795	 	1,631	 	958	 	
Operating Income (Loss)	 	209	 	(324	)	641	 	
Other Income (Expense), net:	 	 	 	 	 	 	 	
Gain on bargain purchase, as retroactively amended	 	—	 	335	 	—	 	
Interest expense	 	(380	)	(254	)	(138	)	
Interest income	 	1	 	1	 	3	 	
Other, net	 	(19	)	7	 	(1	)	
Total other income (expense), net	 	(398	)	89	 	(136	)	
Income (Loss) Before Income Taxes	 	(189	)	(235	)	505	 	
Provision (benefit) for income taxes	 	—	 	(2	)	12	 	
Net Income (Loss)	 	$	(189	)	$	(233	)	$	493	 	
Basic and Diluted EPS:	 	 	 	 	 	 	 	
Basic EPS	 	$	(0.24	)	$	(0.53	)	$	1.20	 	
Diluted EPS	 	$	(0.24	)	$	(0.53	)	$	1.20	 	
Weighted average shares outstanding	 	772	 	441	 	411	 	
Effect of dilutive securities	 	—	 	—	 	1	 	
Weighted average shares outstanding assuming dilution	 	772	 	441	 	412	 	
 
The accompanying notes are an integral part of these consolidated financial statements
 
F-2

 
GENON ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 
 	 	December 31,	 	
 	 	2011	 	2010	 	
 	 	(in millions)	 	
 	 	(See notes 1 and 2
on the Merger)	 	
ASSETS	 	 	 	 	 	
Current Assets:	 	 	 	 	 	
Cash and cash equivalents	 	$	1,668	 	$	2,402	 	
Funds on deposit	 	422	 	1,834	 	
Receivables, net	 	357	 	538	 	
Derivative contract assets	 	999	 	1,420	 	
Inventories	 	563	 	553	 	
Prepaid rent and other expenses	 	167	 	155	 	
Total current assets	 	4,176	 	6,902	 	
Property, Plant and Equipment, net	 	6,191	 	6,229	 	
Noncurrent Assets:	 	 	 	 	 	
Intangible assets, net	 	48	 	140	 	
Derivative contract assets	 	733	 	716	 	
Deferred income taxes	 	294	 	361	 	
Prepaid rent	 	386	 	348	 	
Other	 	441	 	503	 	
Total noncurrent assets	 	1,902	 	2,068	 	
Total Assets	 	$	12,269	 	$	15,199	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	
Current Liabilities:	 	 	 	 	 	
Current portion of long-term debt	 	$	10	 	$	2,061	 	
Accounts payable and accrued liabilities	 	790	 	903	 	
Derivative contract liabilities	 	720	 	1,227	 	
Deferred income taxes	 	294	 	361	 	
Other	 	130	 	128	 	
Total current liabilities	 	1,944	 	4,680	 	
Noncurrent Liabilities:	 	 	 	 	 	
Long-term debt, net of current portion	 	4,122	 	4,020	 	
Derivative contract liabilities	 	131	 	189	 	
Pension and postretirement obligations	 	259	 	171	 	
Other	 	696	 	705	 	
Total noncurrent liabilities	 	5,208	 	5,085	 	
Commitments and Contingencies	 	 	 	 	 	
Stockholders’ Equity:	 	 	 	 	 	
Preferred stock, par value $.001 per share, authorized 125,000,000 shares, no shares issued at December 31, 2011 and 2010	 	—	 	—	 	
Common stock, par value $.001 per share, authorized 2.0 billion shares, issued 771,692,734 shares and 770,857,530 shares at December 31, 2011 and 2010, respectively	 	1	 	1	 	
Additional paid-in capital	 	7,449	 	7,432	 	
Accumulated deficit	 	(2,163	)	(1,974	)	
Accumulated other comprehensive loss	 	(170	)	(25	)	
Total stockholders’ equity	 	5,117	 	5,434	 	
Total Liabilities and Stockholders’ Equity	 	$	12,269	 	$	15,199	 	
 
The accompanying notes are an integral part of these consolidated financial statements
 
F-3

 
GENON ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME (LOSS)
 
 	 	Common
Stock	 	Additional
Paid-In
Capital	 	Accumulated
Deficit	 	Accumulated
Other
Comprehensive
Income (Loss)	 	Total
Stockholders’
Equity	 	Comprehensive
Income (Loss)	 	
 	 	(in millions)	 	
 	 	(See notes 1 and 2 on the Merger)	 	
Balance, December 31, 2008	 	$	—	 	$	6,074	 	$	(2,234	)	$	(90	)	$	3,750	 	 	 	
Share repurchases	 	—	 	(4	)	—	 	—	 	(4	)	 	 	
Stock-based compensation expense	 	—	 	26	 	—	 	—	 	26	 	 	 	
Net income	 	—	 	—	 	493	 	—	 	493	 	$	493	 	
Pension and other postretirement benefits, net of tax of $0	 	—	 	—	 	—	 	37	 	37	 	37	 	
Comprehensive income	 	 	 	 	 	 	 	 	 	 	 	$	530	 	
Balance, December 31, 2009	 	—	 	6,096	 	(1,741	)	(53	)	4,302	 	 	 	
Share repurchases	 	—	 	(11	)	—	 	—	 	(11	)	 	 	
Stock-based compensation expense	 	—	 	42	 	—	 	—	 	42	 	 	 	
Exercise of stock options	 	—	 	1	 	—	 	—	 	1	 	 	 	
Shares issued pursuant to the Merger of Mirant and RRI Energy	 	1	 	1,304	 	—	 	—	 	1,305	 	 	 	
Net loss	 	—	 	—	 	(233	)	—	 	(233	)	$	(233	)	
Pension and other postretirement benefits, net of tax of $0	 	—	 	—	 	—	 	6	 	6	 	6	 	
Deferred gain from cash flow hedges-interest rate swaps, net of tax of $0	 	—	 	—	 	—	 	21	 	21	 	21	 	
Change in fair value of available-for-sale securities, net of tax of $0	 	—	 	—	 	—	 	1	 	1	 	1	 	
Comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	$	(205	)	
Balance, December 31, 2010	 	1	 	7,432	 	(1,974	)	(25	)	5,434	 	 	 	
Stock-based compensation expense	 	—	 	14	 	—	 	—	 	14	 	 	 	
Exercise of stock options	 	—	 	3	 	—	 	—	 	3	 	 	 	
Net loss	 	—	 	—	 	(189	)	—	 	(189	)	(189	)	
Pension and other postretirement benefits, net of tax of $0	 	—	 	—	 	—	 	(89	)	(89	)	(89	)	
Deferred loss from cash flow hedges-interest rate swaps, net of tax of $0	 	—	 	—	 	—	 	(55	)	(55	)	(55	)	
Change in fair value of available-for-sale securities, net of tax of $0	 	—	 	—	 	—	 	(1	)	(1	)	(1	)	
Comprehensive loss	 	—	 	—	 	—	 	 	 	 	 	$	(334	)	
Balance, December 31, 2011	 	$	1	 	$	7,449	 	$	(2,163	)	$	(170	)	$	5,117	 	 	 	
 
The accompanying notes are an integral part of these consolidated financial statements
 
F-4

 
GENON ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)
(See notes 1 and 2 on the
Merger)	 	
Cash Flows from Operating Activities:	 	 	 	 	 	 	 	
Net income (loss)	 	$	(189	)	$	(233	)	$	493	 	
Adjustments to reconcile income (loss) and changes in operating assets and liabilities to net cash provided by operating activities:	 	 	 	 	 	 	 	
Depreciation and amortization	 	390	 	229	 	156	 	
Impairment losses	 	133	 	565	 	221	 	
Amortization of acquired contracts	 	(33	)	—	 	—	 	
Gain on sales of assets, net	 	(6	)	(4	)	(22	)	
Net changes in derivative contracts	 	(224	)	42	 	(47	)	
Stock-based compensation expense	 	14	 	41	 	24	 	
Postretirement benefits curtailment gain	 	—	 	(37	)	—	 	
Lower of cost or market inventory adjustments	 	13	 	22	 	32	 	
Gain on bargain purchase, as retroactively amended	 	—	 	(335	)	—	 	
Loss on early extinguishment of debt	 	23	 	—	 	—	 	
Potomac River settlement obligation	 	—	 	32	 	—	 	
Other, net	 	(5	)	28	 	1	 	
Changes in operating assets and liabilities, net of effects of the Merger:	 	 	 	 	 	 	 	
Receivables, net	 	204	 	(10	)	348	 	
Funds on deposit	 	17	 	(42	)	21	 	
Inventories	 	(21	)	(65	)	(35	)	
Other assets	 	(30	)	(41	)	(47	)	
Accounts payable and accrued liabilities	 	(47	)	(3	)	(334	)	
Other liabilities	 	26	 	10	 	2	 	
Total adjustments	 	454	 	432	 	320	 	
Net cash provided by operating activities of continuing operations	 	265	 	199	 	813	 	
Net cash provided by operating activities of discontinued operations	 	—	 	6	 	9	 	
Net cash provided by operating activities	 	265	 	205	 	822	 	
Cash Flows from Investing Activities:	 	 	 	 	 	 	 	
Cash acquired from RRI Energy, Inc.	 	—	 	717	 	—	 	
Capital expenditures	 	(450	)	(304	)	(676	)	
Proceeds from the sales of assets	 	18	 	4	 	26	 	
Capital contributions	 	—	 	—	 	(5	)	
Restricted funds on deposit, net	 	1,424	 	(1,545	)	1	 	
Other, net	 	(21	)	(43	)	3	 	
Net cash provided by (used in) investing activities	 	971	 	(1,171	)	(651	)	
Cash Flows from Financing Activities:	 	 	 	 	 	 	 	
Proceeds from long-term debt	 	107	 	1,896	 	—	 	
Repayment of long-term debt	 	(2,078	)	(379	)	(45	)	
Debt issuance costs	 	(2	)	(92	)	—	 	
Share repurchases	 	—	 	(11	)	(4	)	
Proceeds from exercises of stock options	 	3	 	1	 	—	 	
Net cash provided by (used in) financing activities	 	(1,970	)	1,415	 	(49	)	
Net Increase (Decrease) in Cash and Cash Equivalents	 	(734	)	449	 	122	 	
Cash and Cash Equivalents, beginning of year	 	2,402	 	1,953	 	1,831	 	
Cash and Cash Equivalents, end of year	 	$	1,668	 	$	2,402	 	$	1,953	 	
Supplemental Disclosures:	 	 	 	 	 	 	 	
Cash paid for interest, net of amounts capitalized	 	$	382	 	$	244	 	$	124	 	
Cash paid for income taxes (net of refunds received)	 	$	(9	)	$	(1	)	$	9	 	
Cash paid for claims and professional fees from bankruptcy	 	$	—	 	$	—	 	$	1	 	
Supplemental Disclosures for Non-Cash Investing and Financing Activities:	 	 	 	 	 	 	 	
Issuance of common stock to effect the Merger	 	$	—	 	$	1,305	 	$	—	 	
 
The accompanying notes are an integral part of these consolidated financial statements
 
F-5

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies
 
Background
 
We are a wholesale generator with approximately 23,700 MW of net electric generating capacity located, in many cases, near major metropolitan load centers in the PJM, MISO, Northeast and Southeast regions, and California. We also operate integrated asset management and proprietary trading operations. See note 17 for a discussion of generating facilities in the Eastern PJM and Western PJM/MISO segments that we expect to deactivate between 2012 and 2015.
 
We were formed as a Delaware corporation in August 2000 by CenterPoint (then known as Reliant Energy, Incorporated) in connection with the planned separation of its regulated and unregulated operations. CenterPoint transferred substantially all of its unregulated businesses, including the name Reliant Energy, to the company now named GenOn Energy, Inc. In May 2001, Reliant Energy (then known as Reliant Resources, Inc.) became a publicly traded company and in September 2002, CenterPoint distributed its remaining ownership of Reliant Energy’s common stock to its stockholders. RRI Energy changed its name from Reliant Energy, Inc. effective May 2, 2009 in connection with the sale of its retail business. GenOn changed its name from RRI Energy, Inc. effective December 3, 2010 in connection with the Merger. “We,” “us,” “our” and “GenOn” refer to GenOn Energy, Inc. and, except where the context indicates otherwise, its subsidiaries, after giving effect to the Merger.
 
Merger of Mirant and RRI Energy
 
On December 3, 2010, Mirant and RRI Energy completed the Merger. Upon completion of the Merger, RRI Energy Holdings, Inc., a direct and wholly- owned subsidiary of RRI Energy merged with and into Mirant, with Mirant continuing as the surviving corporation and a wholly-owned subsidiary of RRI Energy. Each of Mirant and RRI Energy received legal opinions that the Merger qualified as a tax-free reorganization under the IRC. Upon the closing of the Merger, each issued and outstanding share of Mirant common stock, including grants of restricted common stock, automatically converted into 2.835 shares of common stock of RRI Energy based on the Exchange Ratio. Approximately 417 million shares of RRI Energy common stock were issued. Additionally, upon the closing of the Merger, RRI Energy was renamed GenOn. Mirant stock options and other equity awards converted upon completion of the Merger into stock options and equity awards with respect to GenOn common stock, after giving effect to the Exchange Ratio. See note 2 for additional information on the Merger and note 6 for the related debt transactions.
 
During the third and fourth quarters of 2011, we recorded revisions to the provisional allocation of the purchase price at December 3, 2010 and accordingly retroactively revised amounts in our consolidated balance sheet at December 31, 2010 and our consolidated statements of operations for 2010 and the nine months ended September 30, 2011. See note 2.
 
Basis of Presentation
 
The consolidated financial statements of GenOn and its wholly-owned subsidiaries have been prepared in accordance with GAAP from records maintained by us. All significant intercompany accounts and transactions have been eliminated in consolidation.
 
In connection with the Merger, former Mirant stockholders received approximately 54% of the voting interest in the combined company. Although RRI Energy was the legal acquirer, the Merger is
 
F-6

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
accounted for as a reverse acquisition whereby Mirant is treated as the accounting acquirer and RRI Energy is treated as the acquired company for financial reporting purposes. As such, our consolidated financial statements include the results of the combined entities for the periods from December 3, 2010, and include the results of Mirant through December 2, 2010. Our consolidated results of operations in 2010 include operating revenues from RRI Energy of $168 million and a net loss of $60 million after the Merger. The consolidated financial statements presented herein for periods ended prior to the closing of the Merger (and any other financial information presented herein with respect to such pre-merger dates, unless otherwise specified) are the consolidated financial statements and other financial information of Mirant.
 
At December 31, 2011 and 2010, substantially all of our subsidiaries are wholly-owned and located in the United States. We did not consolidate five power generating facilities, which are under operating leases (see note 10); a 50% equity investment in a cogeneration facility; and a VIE, for which we are not the primary beneficiary (see note 13 for further discussion of MC Asset Recovery).
 
Use of Estimates
 
The preparation of consolidated financial statements in conformity with GAAP requires management to make various estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates. Our significant estimates include:
 
·                 estimating the fair value of assets acquired and liabilities assumed in connection with the Merger;
 
·                 estimating the fair value of certain derivative contracts;
 
·                 estimating future taxable income in evaluating the deferred tax asset valuation allowance;
 
·                 estimating the useful lives of long-lived assets;
 
·                 estimating future costs and the valuation of asset retirement obligations;
 
·                 estimating future cash flows in determining impairments of long-lived assets and definite-lived intangible assets;
 
·                 estimating the fair value and expected return on plan assets, discount rates and other actuarial assumptions used in estimating pension and other postretirement benefit plan liabilities; and
 
·                 estimating losses to be recorded for contingent liabilities.
 
We evaluate events that occur after the balance sheet date and through the date the financial statements are issued for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed herein.
 
F-7

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
Revenue Recognition
 
We recognize revenue when earned and collection is probable. We earn revenue from the following sources: (a) power generation revenues, (b) contracted and capacity revenues, (c) fuel sales and proprietary trading revenues and (d) power hedging revenues.
 
Power Generation Revenues.  We recognize revenue from the sale of electricity from our generating facilities. Sales of energy primarily are based on economic dispatch, or “as-ordered” by an ISO or RTO, based on member participation agreements, but without an underlying contractual commitment. ISO and RTO revenues and revenues from sales of energy based on economic-dispatch are recorded on the basis of MWh delivered, at the relevant day-ahead or real-time prices. Additionally, we include revenue from the sale of steam in power generation revenues.
 
Contracted and Capacity Revenues.  We recognize revenue received from providing ancillary services and revenue received from an ISO or RTO based on auction results or negotiated contract prices for making installed generation capacity available to meet system reliability requirements. In addition, when a long-term electric power agreement conveys to the buyer of the electric power the right to control the generating capacity of our facility, that agreement is evaluated to determine if it is a lease of the generating facility rather than a sale of electric power. Operating lease revenue for our generating facilities is normally recorded as capacity revenue.
 
Power Hedging Revenues.  We recognize revenue from contracts for the sale of both power and natural gas used to hedge power prices as well as for hedges to capture the incremental value related to the geographic location of our physical assets.
 
Fuel Sales and Proprietary Trading Revenues.  We recognize revenue from the sale of fuel oil and natural gas and revenues associated with fuel oil management and proprietary trading activities.
 
The following table reflects our revenues by type:
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Power generation revenues	 	$	1,802	 	$	1,237	 	$	805	 	
Contracted and capacity revenues	 	936	 	607	 	592	 	
Power hedging revenues	 	550	 	368	 	845	 	
Fuel sales and proprietary trading revenues	 	326	 	58	 	67	 	
Total operating revenues	 	$	3,614	 	$	2,270	 	$	2,309	 	
 
In accordance with accounting guidance related to derivative financial instruments, physical transactions or revenues from the sale of generated electricity to ISOs and RTOs are recorded on a gross basis in the consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded on a net basis in the consolidated statements of operations.
 
F-8

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
Cost of Fuel, Electricity and Other Products
 
Cost of fuel, electricity and other products on our consolidated statements of operations includes the costs of goods produced and sold through the combustion process, including the costs associated with handling and disposal of ash, natural gas transportation and services rendered during a reporting period. Cost of fuel, electricity and other products also includes purchased emissions allowances for CO 2 , SO 2  and NO x  and the settlements of and changes in fair value of derivative financial instruments used to hedge fuel economically. Additionally, cost of fuel, electricity and other products includes lower of cost or market inventory adjustments. Cost of fuel, electricity and other products excludes depreciation and amortization. Gross margin is total operating revenues less cost of fuel, electricity and other products.
 
Derivatives and Hedging Activities
 
In connection with the business of generating electricity, we are exposed to energy commodity price risk associated with the acquisition of fuel and emissions allowances needed to generate electricity, the price of electricity produced and sold, and the fair value of fuel inventories. Through our asset management activities, we enter into a variety of exchange-traded and OTC energy and energy-related derivative financial instruments, such as forward contracts, futures contracts, option contracts and financial swap agreements to manage exposure to commodity price risks. These contracts have varying terms and durations, which range from a few days to years, depending on the instrument. Our proprietary trading activities also utilize similar derivative contracts in markets where we have a physical presence to attempt to generate incremental gross margin. Our fuel oil management activities use derivative financial instruments to hedge economically the fair value of physical fuel oil inventories, optimize the approximately two million barrels of storage capacity that we own, and attempt to profit from market opportunities related to timing and/or differences in the pricing of various products. The open positions in our trading activities comprising proprietary trading and fuel oil management activities expose us to risks associated with changes in energy commodity prices.
 
Derivative financial instruments are recorded in the consolidated balance sheets at fair value, except for derivative contracts that qualify for and for which we have elected the normal purchase or normal sale exceptions, which are not reflected in the consolidated balance sheet or results of operations prior to accrual of the settlement. We present our derivative contract assets and liabilities on a gross basis (regardless of master netting arrangements with the same counterparty). Cash collateral amounts are also presented on a gross basis.
 
If certain criteria are met, a derivative financial instrument may be designated as a fair value hedge or cash flow hedge. In the fourth quarter of 2010, GenOn Marsh Landing entered into interest rate protection agreements (interest rate swaps) in connection with its project financing, which have been designated as cash flow hedges. GenOn Marsh Landing entered into the interest rate swaps to reduce the risks with respect to the variability of the interest rates for the term loans. With the exception of these interest rate swaps, we did not have any other derivative financial instruments designated as fair value or cash flow hedges for accounting purposes during 2011, 2010, or 2009.
 
The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive loss, net of tax, to the extent the contracts are, or have been, effective as hedges, until the forecasted
 
F-9

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
transactions affect earnings. We record the ineffective portion of changes in fair value of cash flow hedges immediately into earnings.
 
Derivative financial instruments designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item. If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in our results of operations. If it becomes probable that a forecasted transaction will not occur, we immediately recognize the related deferred gains or losses in our results of operations. Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated.
 
For our derivative financial instruments that have not been designated as cash flow hedges for accounting purposes, changes in such instruments’ fair values are recognized currently in earnings. Our derivative financial instruments are categorized based on the business objective the instrument is expected to achieve: asset management or trading, which includes proprietary trading and fuel oil management. For asset management activities, changes in fair value and settlement of derivative financial instruments used to hedge electricity economically are reflected in operating revenues and changes in fair value and settlement of derivative financial instruments used to hedge fuel economically are reflected in cost of fuel, electricity and other products in the consolidated statements of operations. Changes in the fair value and settlements of derivative financial instruments for proprietary trading and fuel oil management activities are recorded on a net basis as operating revenue in the consolidated statements of operations.
 
We also consider risks associated with interest rates, counterparty credit and our own non-performance risk when valuing derivative financial instruments. The nominal value of the derivative contract assets and liabilities is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the transactions being valued. See note 4.
 
Concentration of Revenues
 
During 2011, we had $2.3 billion in revenues from PJM, which represented 62% of consolidated revenues. The revenues generated from this counterparty are included in the Eastern PJM, Western PJM/MISO and Energy Marketing segments. During 2010, we had $1.5 billion in revenues from PJM, which represented 64% of consolidated revenues. The revenues generated from this counterparty are included in the Eastern PJM, Western PJM/MISO and Energy Marketing segments. During 2009, we had $1.0 billion in revenues from PJM, which represented 43% of consolidated revenues. The revenues generated from this counterparty are primarily included in the Eastern PJM segment. Additionally, during 2009 we had $332 million in revenues from another counterparty, which represented 14% of consolidated revenues. The revenues generated from this counterparty are included in the Eastern PJM, Energy Marketing and Other Operations segments.
 
Coal Supplier Concentration Risk
 
Our coal supply comes primarily from the Northern Appalachian and Central Appalachian coal regions. We enter into contracts of varying tenors to secure appropriate quantities of fuel that meet the varying specifications of our generating facilities. For the coal-fired generating facilities, we purchase
 
F-10

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
most of our coal from a small number of suppliers under contracts with terms of varying lengths, some of which extend to 2014 and one that extends to 2020. Excluding the Keystone and Conemaugh generating facilities (which are not 100% owned by us) and excluding the Seward generating facility (which burns waste coal supplied by an all-requirements contract), we had exposure to three counterparties at December 31, 2011 and 2010, that each represented an exposure of more than 10% of our total coal commitments, by volume, and in aggregate represented approximately 62% and 76% of our total coal commitments at December 31, 2011 and 2010, respectively. At December 31, 2011 and 2010, the single largest counterparty represented an exposure of 38% and 52%, respectively, of these total coal commitments, by volume.
 
Coal Transportation Concentration Risk
 
The coal to operate our coal-fired facilities is delivered primarily by train and we have a limited number of railroads transporting such coal. For 2011, one railroad represented 66% of our coal transportation costs and another railroad represented 22% of our coal transportation costs.
 
Concentration of Labor Subject to Collective Bargaining Agreements
 
At December 31, 2011, 50% of our employees are subject to collective bargaining agreements. Of those employees subject to collective bargaining agreements, 33% are represented by IBEW Local 459 in the Western PJM/MISO segment and 30% are represented by IBEW Local 1900 in the Eastern PJM segment. Less than five percent of our employees are subject to a collective bargaining agreement that will expire in 2012. We intend to negotiate the renewal of this agreement and do not anticipate any disruptions to our operations.
 
Cash and Cash Equivalents
 
We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At December 31, 2011 and 2010, except for amounts held in bank accounts to cover current payables, all of our cash and cash equivalents were invested in AAA-rated United States Treasury money market funds.
 
F-11

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
Funds on Deposit
 
Funds on deposit are included in current and noncurrent assets in the consolidated balance sheets. Funds on deposit include the following:
 
 	 	December 31,	 	
 	 	2011	 	2010	 	
 	 	(in millions)	 	
Cash collateral posted—energy trading and marketing	 	$	185	 	$	220	 	
Cash collateral posted—other operating activities(1)	 	39	 	45	 	
Cash collateral posted—surety bonds(2)	 	34	 	34	 	
GenOn Mid-Atlantic restricted cash(3)	 	166	 	—	 	
GenOn Marsh Landing development project cash collateral posted(4)	 	131	 	106	 	
Environmental compliance deposits(5)	 	34	 	32	 	
Funds deposited with the trustee to discharge the GenOn senior secured notes, due 2014(6)	 	—	 	285	 	
Funds deposited with the trustee to defease the PEDFA fixed-rate bonds, due 2036(6)	 	—	 	394	 	
Funds deposited with the trustee to discharge the GenOn North America senior notes, due 2013(6)	 	—	 	866	 	
Other	 	16	 	40	 	
Total current and noncurrent funds on deposit	 	605	 	2,022	 	
Less: Current funds on deposit	 	422	 	1,834	 	
Total noncurrent funds on deposit	 	$	183	 	$	188	 	

(1)                                Includes $32 million related to the Potomac River settlement. See note 5.
 
(2)                                Represents cash under surety bonds posted primarily with the Pennsylvania Department of Environmental Protection related to environmental obligations.
 
(3)                                Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation. See note 16.
 
(4)                                Represents cash-collateralized letters of credit to support the Marsh Landing development project.
 
(5)                                Represents deposits with the State of Pennsylvania to guarantee our obligations related to future closures of coal ash landfill sites and with the State of New Jersey to satisfy our obligations under the Industrial Site Recovery Act. See note 16 for our obligations related to ash landfill sites and site contamination remediation.
 
(6)                                See note 6 for discussion of the related debt.
 
Inventories
 
Inventories consist primarily of materials and supplies, fuel oil, coal and purchased emissions allowances. Inventory is generally stated at the lower of cost or market value and is expensed on a weighted average cost basis. Fuel inventory is removed from the inventory account as it is used in the
 
F-12

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
generation of electricity or sold to third parties, including sales related to our fuel oil management, natural gas transportation and storage activities. Materials and supplies are removed from the inventory account when they are used for repairs, maintenance or capital projects. Purchased emissions allowances are removed from inventory and charged to cost of fuel, electricity and other products in the consolidated statements of operations as they are utilized for emissions volumes.
 
Inventories were comprised of the following:
 
 	 	December 31,	 	
 	 	2011	 	2010	 	
 	 	(in millions)	 	
Fuel inventory:	 	 	 	 	 	
Coal	 	$	229	 	$	153	 	
Fuel oil	 	108	 	169	 	
Natural gas	 	1	 	1	 	
Other	 	5	 	1	 	
Materials and supplies	 	201	 	194	 	
Purchased emissions allowances	 	19	 	35	 	
Total inventories	 	$	563	 	$	553	 	
 
During 2011, 2010 and 2009, we recorded $13 million, $22 million and $32 million, respectively, for lower of average cost or market valuation adjustments in cost of fuel, electricity and other products.
 
Property, Plant and Equipment
 
Property, plant and equipment are recorded at cost, which includes materials, labor, associated payroll-related and overhead costs and the cost of financing construction. The cost of routine maintenance and repairs, such as inspections and corrosion removal, and the replacement of minor items of property are charged to expense as incurred. Certain expenditures incurred during a major maintenance outage of a generating facility are capitalized, including the replacement of major component parts and labor and overhead incurred to install the parts. Depreciation of the recorded cost of depreciable property, plant and equipment is determined using primarily composite rates. Leasehold improvements are depreciated over the shorter of the expected life of the related equipment or the lease term. Upon the retirement or sale of property, plant and equipment, the cost of such assets and the related accumulated depreciation are removed from the consolidated balance sheets. No gain or loss is recognized for ordinary retirements in the normal course of business since the composite depreciation rates used by us take into account the effect of interim retirements.
 
Impairment of Long-Lived Assets
 
We evaluate long-lived assets, such as property, plant and equipment and purchased intangible assets subject to amortization, for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Such evaluations are performed in accordance with the accounting guidance related to evaluating long-lived assets for impairment. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an
 
F-13

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds its fair value. See note 5.
 
Capitalization of Interest Cost
 
We capitalize interest on projects during their construction period. We determine which debt instruments represent a reasonable measure of the cost of financing construction in terms of interest costs incurred that otherwise could have been avoided. These debt instruments and associated interest costs are included in the calculation of the weighted average interest rate used for determining the capitalization rate. Once a project is placed in service, capitalized interest, as a component of the total cost of the construction, is depreciated over the estimated useful life of the asset constructed.
 
During 2011, 2010 and 2009, we incurred the following interest costs:
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Total interest costs	 	$	395	 	$	260	 	$	210	 	
Capitalized and included in property, plant and equipment, net	 	(15	)	(6	)	(72	)	
Interest expense	 	$	380	 	$	254	 	$	138	 	
 
The amounts of capitalized interest above include interest accrued. During 2011, 2010 and 2009, cash paid for interest was $396 million, $250 million and $192 million, respectively, of which $14 million, $6 million and $68 million, respectively, were capitalized.
 
Environmental Costs
 
We expense environmental expenditures related to existing conditions that do not have future economic benefit. We capitalize environmental expenditures for which there is a future economic benefit. We record liabilities for expected future costs, on an undiscounted basis, related to environmental assessments and/or remediation when they are probable and can be reasonably estimated. In determining the liabilities, we refer to currently available information, including relevant past experience, remedial objectives, available technologies and applicable laws and regulations. We record reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of recovery is highly probable.
 
Development Costs
 
We capitalize project development costs for generating facilities once it is probable that the project will be completed. These costs include professional fees, permits and other third party costs directly associated with the development of a new project. The capitalized costs are depreciated over the life of the asset or charged to operating expense if the completion of the project is deemed no longer probable. Project development costs are expensed when incurred until the probable threshold is met. We began capitalizing project development costs related to the Marsh Landing generating facility upon signing the PPA with PG&E on September 2, 2009. At December 31, 2011 and 2010, we have
 
F-14

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
capitalized $8 million and $5 million, respectively, of project development costs related to the Marsh Landing generating facility.
 
Operating Leases
 
We lease various assets under non-cancelable leasing arrangements, including generating facilities, office space and other equipment. The rent expense associated with leases that qualify as operating leases is recognized on a straight-line basis over the lease term within operations and maintenance expense in the consolidated statements of operations. Our most significant operating leases are GenOn Mid-Atlantic’s leases of a 100% interest in the Dickerson and Morgantown baseload units and REMA’s leases of a 16.45% interest in the Conemaugh facility, a 16.67% interest in the Keystone facility and a 100% interest in the Shawville facility. See note 10.
 
Intangible Assets
 
Intangible assets relate primarily to acquired contracts, granted emissions allowances, trading rights and development rights. Intangible assets with definite useful lives are amortized on a straight-line basis to their estimated residual values over their respective useful lives ranging up to 30 years. See note 5.
 
Debt Issuance Costs
 
Debt issuance costs are capitalized and amortized as interest expense under the effective interest method over the term of the related debt. The unamortized balance of debt issuance costs is included in other noncurrent assets on the consolidated balance sheets. Changes in debt issuance costs are as follows:
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Balance, January 1	 	$	103	 	$	29	 	$	38	 	
Capitalized(1)	 	2	 	92	 	—	 	
Amortized	 	(11	)	(9	)	(9	)	
Accelerated amortization/write-offs(1)(2)	 	(7	)	(9	)	—	 	
Balance, December 31	 	$	87	 	$	103	 	$	29	 	

(1)                                See note 6.
 
(2)                                Amounts are considered a portion of the net carrying value of the related debt and are expensed when accelerated as a component of debt extinguishments.
 
Income Taxes and Deferred Tax Asset Valuation Allowance
 
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
 
F-15

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
The guidance related to accounting for income taxes requires that a valuation allowance be established when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies.
 
At December 31, 2011, our deferred tax assets reduced by a valuation allowance are completely offset by our deferred tax liabilities. Objective positive evidence is necessary to support a conclusion that a valuation allowance is not needed for all or a portion of deferred tax assets when significant negative evidence exists. We think that future sources of taxable income, the reversal of taxable temporary differences and implemented tax planning strategies will be sufficient to realize deferred tax assets for which no valuation allowance has been established.
 
Earnings per Share
 
Basic earnings per share is calculated by dividing net income/loss applicable to common stockholders by the weighted average number of common shares outstanding. Diluted earnings per share is computed using the weighted average number of shares of common stock and dilutive potential common shares, including common shares from warrants, restricted stock units and stock options using the treasury stock method. Share amounts used in calculating earnings per share reflect Mirant’s historical activity through December 2, 2010 retroactively adjusted to give effect to the Exchange Ratio and includes the combined entities for the periods from December 3, 2010.
 
Fair Value of Financial Instruments
 
The accounting guidance related to the disclosure about fair value of financial instruments requires the disclosure of the fair value of all financial instruments that are not otherwise recorded at fair value in the financial statements. At December 31, 2011 and 2010, financial instruments recorded at contractual amounts that approximate fair value include certain funds on deposit, accounts receivable, notes and other receivables, and accounts payable and accrued liabilities. The fair values of such items are not materially sensitive to shifts in market interest rates because of the short term to maturity of these instruments. See note 4.
 
Recently Adopted Accounting Guidance
 
Fair Value Measurement and Disclosure.  We adopted FASB accounting guidance for the quarter ended March 31, 2011 that requires a reconciliation for Level 3 fair value measurements, including presenting separately the amounts of purchases, issuances and settlements on a gross basis. See note 4.
 
New Accounting Guidance Not Yet Adopted at December 31, 2011
 
Fair Value Measurement and Disclosure.  In May 2011, the FASB issued new fair value measurement and disclosure guidance. The new standard does not extend the use of fair value but rather provides guidance about how fair value should be determined and requires additional
 
F-16

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
1. Description of Business and Accounting and Reporting Policies (Continued)
 
disclosures. The guidance is not expected to have a material effect on our fair value measurements, but will require disclosure of the following:
 
·                 quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy;
 
·                 for those fair value measurements categorized within Level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and
 
·                 the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.
 
We will present the additional disclosures as required in our Form 10-Q for the quarter ended March 31, 2012.
 
Comprehensive Income.  In June 2011, the FASB issued guidance that revises the manner in which companies present comprehensive income in their financial statements. The guidance requires companies to report the components of comprehensive income in either (a) a continuous statement of comprehensive income or (b) two separate but consecutive statements. The guidance does not change the items that must be reported in comprehensive income. We will update our presentation as required in our Form 10-Q for the quarter ended March 31, 2012.
 
Balance Sheet Offsetting.  In December 2011, the FASB issued updated guidance to provide enhanced disclosures such that users of the financial statements will be able to better evaluate the effect or potential effect of netting arrangements on the statement of financial position. The guidance requires improved information about financial instruments and derivative instruments that are either offset according to specific guidance or subject to an enforceable master netting agreement or similar arrangement. The disclosures will provide both net and gross information for these assets and liabilities. Although we do not currently elect to offset assets and liabilities within the scope of the guidance, expanded disclosures will be required starting for the quarter ended March 31, 2013, along with retrospective presentation of prior periods.
 
2. Merger
 
On December 3, 2010, Mirant and RRI Energy completed the Merger. The Merger resulted in significant cost savings, a generation fleet with diversity and a significant presence in PJM and California, and a balance sheet with adequate liquidity.
 
Because the Merger is accounted for as a reverse acquisition with Mirant as the accounting acquirer (see note 1, “Basis of Presentation” section), the purchase price was computed based on shares of Mirant common stock that would have been issued to RRI Energy’s stockholders on the date of the Merger to give RRI Energy an equivalent ownership interest in Mirant as it had in the
 
F-17

 

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
2. Merger (Continued)
 
combined company (approximately 46%). The purchase price was calculated as follows (in millions, except closing stock price):
 
Number of shares of Mirant common stock that would have been issued to RRI Energy stockholders	 	125	 	
Closing price of Mirant common stock on December 3, 2010	 	$	10.39	 	
Total	 	1,302	 	
RRI Energy stock options	 	3	 	
Total purchase price	 	$	1,305	 	
 
The Merger is accounted for under the acquisition method of accounting for business combinations. Accordingly, we have conducted an assessment of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition are expensed as incurred. We finalized our assessment of fair value during 2011, and adjusted for information that was previously not available to us. The final allocation of the purchase price as of December 3, 2010 is as follows (in millions):
 
Cash and cash equivalents	 	$	717	 	
Current derivative contract assets	 	156	 	
Inventories	 	275	 	
Other current assets	 	305	 	
Property, plant and equipment	 	3,070	(1)	
Intangible assets	 	47	 	
Other noncurrent assets	 	275	 	
Current derivative contract liabilities	 	(100	)	
Other current liabilities	 	(457	)	
Debt	 	(1,931	)	
Pension and postretirement obligations	 	(105	)	
Other noncurrent liabilities	 	(612	)	
Fair value of net assets acquired	 	1,640	 	
Purchase price	 	1,305	 	
Gain on bargain purchase, as retroactively amended	 	$	335	(2)(3)	

(1)        The valuations of the acquired long-lived assets were primarily based on the income approach, and in particular, discounted cash flow analyses. The income approach was employed for the generating facilities because of the differing age, geographic location, market conditions, asset life, equipment condition and status of environmental controls of the assets. The discounted cash flows incorporated information based on observable market prices to the extent available and long-term prices derived from proprietary fundamental market modeling. For the generating facilities that were not valued using the income approach, the cost approach was used. The market approach was considered, but
 
F-18

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
2. Merger (Continued)
 
was ultimately given no weighting because of many of the factors listed as the primary reasons for application of the income approach as well as a lack of proximity of the observed transactions to the valuation date.
 
(2)        The gain on bargain purchase was recorded in other income in the consolidated statement of operations during 2010.
 
(3)        The acquisition is treated as a nontaxable merger for federal income tax purposes and there is no tax deductible goodwill resulting from the Merger.
 
The above allocation of the purchase price includes revisions to the provisional allocation that was reported at September 30, 2011, June 30, 2011, March 31, 2011 and December 31, 2010 primarily for property, plant and equipment, intangible assets and long-term liabilities related to out-of-market contracts and asset retirement obligations, which reduced the gain on bargain purchase recognized during 2010 by $183 million. Our consolidated balance sheet at December 31, 2010 has been retroactively amended for the revisions to the provisional allocation as follows:
 
 	 	Increase/
(Decrease)	 	
 	 	(in millions)	 	
Current Assets:	 	 	 	
Total current assets	 	$	1	 	
Property, Plant and Equipment, net	 	(69	)	
Noncurrent Assets:	 	 	 	
Intangible assets, net	 	(4	)	
Other	 	(3	)	
Total noncurrent assets	 	(7	)	
Total Assets	 	$	(75	)	
Current Liabilities:	 	 	 	
Total current liabilities	 	$	(5	)	
Noncurrent Liabilities:	 	 	 	
Total noncurrent liabilities	 	113	 	
Stockholders’ Equity:	 	 	 	
Accumulated deficit	 	(183	)	
Total stockholders’ equity	 	(183	)	
Total Liabilities and Stockholders’ Equity	 	$	(75	)	
 
Our results of operations have been retroactively amended for the revisions to the provisional allocation as follows: (a) for the nine months ended September 30, 2011, our net loss increased by $7 million and (b) for the year ended December 31, 2010, the gain on bargain purchase decreased by $183 million and the net loss increased by the same amount. The impacts on our results of operations for 2010, other than the gain on bargain purchase, as a result of the revisions to the provisional allocation were not material.
 
F-19

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
2. Merger (Continued)
 
Because the fair value of the net assets acquired exceeds the purchase price, the Merger is being accounted for as a bargain purchase in accordance with acquisition accounting guidance. The gain on the bargain purchase is primarily a result of differences between the long-term fundamental value of the generating facilities and the effect of the near-term view of the equity markets on the price of Mirant common stock at the close of the Merger, specifically as a result of the following:
 
·                 dark spreads (the difference between power prices and coal fuel costs) have decreased significantly in recent years as a result of natural gas prices that are lower compared to recent years and increased coal prices that are affected by international demand;
 
·                 uncertainty related to the nature and timing of environmental regulation, including carbon legislation; and
 
·                 certain generating facilities owned by RRI Energy prior to the Merger being located in markets experiencing lower demand for electricity as a result of economic conditions but forecasted to have long-term declining reserve margins.
 
We are subject to material contingencies, some of which may involve substantial amounts, relating to (a) pending natural gas litigation, (b) environmental matters, (c) the CenterPoint indemnity, (d) the Texas franchise tax audit and (e) income tax contingencies. For information regarding these contingencies, see notes 7 and 16. As a result of the number of variables and assumptions involved in assessing the possible outcome of these matters, sufficient information does not exist to reasonably estimate the fair value or a range of outcomes for these contingent liabilities, except as disclosed in notes 7 and 16. Unless otherwise noted in notes 7 and 16, we cannot predict the outcome of the matters. These material contingencies have been evaluated in accordance with the accounting guidance for contingencies, and no amounts for these matters have been recorded at the date of the Merger because the recognition criteria have not been met, except as denoted in notes 7 and 16. See note 10 for information regarding guarantees and indemnifications.
 
In connection with the Merger, we incurred stock issuance costs of an insignificant amount, which were recorded as an increase in additional paid-in capital in stockholders’ equity as of the date of the Merger and incurred debt issuance costs of $68 million, which are included in other noncurrent assets in the consolidated balance sheet. For information regarding debt issuance costs, see note 1. For information regarding Merger-related costs, see note 3.
 
The unaudited pro forma results give effect to the Merger as if it had occurred on January 1, 2010 and 2009, as applicable. The unaudited pro forma financial information is not necessarily indicative of either future results of operations or results that might have been achieved had the acquisition been
 
F-20

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
2. Merger (Continued)
 
consummated as of January 1, 2010 or January 1, 2009, as applicable. The unaudited pro forma results for 2010 and 2009 are as follows:
 
 	 	2010	 	2009	 	
 	 	(in millions, except
per share data)	 	
Revenues	 	$	4,166	 	$	4,115	 	
Income (loss) from continuing operations	 	(746	)	75	 	
Net income (loss)	 	(740	)	957	 	
Earnings (loss) per share from continuing operations:	 	 	 	 	 	
Basic and Diluted EPS	 	$	(0.96	)	$	0.10	 	
Net income (loss) per share:	 	 	 	 	 	
Basic and Diluted EPS	 	$	(0.96	)	$	1.25	 	
 
The unaudited pro forma information primarily includes the following adjustments, among others:
 
·                 amortization of fair value adjustments related to energy-related contracts;
 
·                 additional fuel expense related to fair value adjustments of fuel inventories;
 
·                 effects of fair value adjustments of property, plant and equipment;
 
·                 effects of fair value adjustments of debt and the issuance of a new revolving credit facility, new senior secured term loan and new senior unsecured notes; and
 
·                 adjustments to income taxes for a zero percent rate applied to the pro forma adjustments and historical federal and state deferred tax expense (benefit).
 
The unaudited pro-forma results exclude:
 
·                 transaction costs of $86 million (including amounts incurred prior to the close of the Merger) because these costs reflect non-recurring charges directly related to the Merger;
 
·                 $35 million of severance related to the Merger (see note 3) and $18 million of other Merger-related costs;
 
·                 write-off of $9 million of unamortized debt issuance costs for the debt refinanced, cash premiums and other transaction costs of the debt refinanced;
 
·                 $24 million of expense related to the accelerated vesting of stock-based compensation of former Mirant employees upon the completion of the Merger;
 
·                 the gain on bargain purchase; and
 
·                 cost savings from operating efficiencies or synergies that could result from the Merger.
 
F-21

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
3. Merger-related Costs
 
Changes in Merger-related costs (recorded in operations and maintenance expense in the Other Operations segment) are as follows (in millions):
 
Balance, January 1, 2010	 	$	—	 	
Accrued and expensed	 	114	(1)	
Paid	 	(84	)	
Balance, December 31, 2010	 	$	30	(2)	
Accrued and expensed	 	72	(3)	
Paid	 	(82	)(3)	
Other changes, net	 	(1	)	
Balance, December 31, 2011	 	$	19	(2)	

(1)        Includes $67 million of advisory and legal fees, $35 million of charges associated with employee severance and $12 million of charges related to integration and other activities. In addition, we incurred $24 million related to the accelerated vesting of Mirant’s stock-based compensation as a result of the Merger.
 
(2)        Included primarily in accounts payable and accrued liabilities in the applicable consolidated balance sheet.
 
(3)        Includes $45 million of charges associated with employee severance, $5 million of charges related to corporate facilities lease impairment and $22 million of charges related to integration and other activities.
 
F-22

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments
 
(a) Derivatives and Hedging Activities.
 
The following table presents the fair value of our derivative financial instruments:
 
 	 	Derivative Contract	 	Derivative Contract	 	Net Derivative	 	
 	 	Assets	 	Liabilities	 	Contract	 	
 	 	Current	 	Long-Term	 	Current	 	Long-Term	 	Assets (Liabilities)	 	
 	 	(in millions)	 	
December 31, 2011	 	 	 	 	 	 	 	 	 	 	 	
Commodity Contracts:	 	 	 	 	 	 	 	 	 	 	 	
Asset management	 	$	538	 	$	730	 	$	(255	)	$	(97	)	$	916	 	
Trading activities	 	461	 	3	 	(464	)	(3	)	(3	)	
Total commodity contracts	 	999	 	733	 	(719	)	(100	)	913	 	
Interest Rate Contracts	 	—	 	—	 	(1	)	(31	)	(32	)	
Total derivatives	 	$	999	 	$	733	 	$	(720	)	$	(131	)	$	881	 	
December 31, 2010	 	 	 	 	 	 	 	 	 	 	 	
Commodity Contracts:	 	 	 	 	 	 	 	 	 	 	 	
Asset management	 	$	564	 	$	627	 	$	(368	)	$	(117	)	$	706	 	
Trading activities	 	856	 	70	 	(859	)	(72	)	(5	)	
Total commodity contracts	 	1,420	 	697	 	(1,227	)	(189	)	701	 	
Interest Rate Contracts	 	—	 	19	 	—	 	—	 	19	 	
Total derivatives	 	$	1,420	 	$	716	 	$	(1,227	)	$	(189	)	$	720	 	
 
F-23

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments (Continued)
 
The following table presents the net gains (losses) for derivative financial instruments recognized in income in the consolidated statements of operations:
 
 	 	2011	 	2010	 	
Derivatives Not Designated as
Hedging Instruments	 	Operating
Revenues	 	Cost of Fuel,
Electricity and
Other Products	 	Operating
Revenues	 	Cost of Fuel,
Electricity and Other
Products	 	
 	 	(in millions)	 	
Asset Management Commodity Contracts:	 	 	 	 	 	 	 	 	 	
Unrealized	 	$	225	 	$	(3	)	$	50	 	$	(87	)	
Realized(1)(2)	 	331	 	(98	)	318	 	(191	)	
Total asset management	 	$	556	 	$	(101	)	$	368	 	$	(278	)	
Trading Commodity Contracts:	 	 	 	 	 	 	 	 	 	
Unrealized	 	$	2	 	$	—	 	$	(5	)	$	—	 	
Realized(1)(2)	 	(22	)	—	 	(23	)	—	 	
Total trading	 	$	(20	)	$	—	 	$	(28	)	$	—	 	
Total derivatives	 	$	536	 	$	(101	)	$	340	 	$	(278	)	

(1)        Represents the total cash settlements of derivative financial instruments during each reporting period (composed of the sum of the quarterly settlements) that existed at the beginning of each respective period.
 
(2)        Effective January 1, 2011, excludes settlement value of fuel contracts classified as inventory.
 
The following table presents the effect of the interest rate swaps designated as cash flow hedges in the consolidated statements of stockholders’ equity and comprehensive income/loss during 2011 and 2010 (gain/(loss)):
 
 	 	2011	 	2010	 	
 	 	(in millions)	 	
Recognized in OCI on interest rate derivatives	 	$	(55	)	$	21	 	
Reclassified from accumulated OCI into earnings	 	—	 	—	 	
Recognized in earnings on derivatives(1)(2)	 	—	 	—	 	

(1)        Represents the ineffective portion of the interest rate swaps classified as cash flow hedges and recorded in interest expense. The assessment of effectiveness excludes the default risk of the counterparties to these transactions and our own non-performance risk. The effect of these valuation adjustments, which is recorded in interest expense was a gain (loss) of $4 million and $(2) million during 2011 and 2010, respectively.
 
F-24

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments (Continued)
 
(2)        All of the forecasted transactions (future interest payments) were deemed probable of occurring; therefore, no cash flow hedges were discontinued and no amount was recognized in our results of operations as a result of discontinued cash flow hedges.
 
At December 31, 2011, the maximum length of time we are hedging our exposure to the variability in future cash flows that may result from changes in interest rates is 12 years. At December 31, 2011 and 2010, the accumulated other comprehensive income (loss) balance was $(34) million and $21 million, respectively. Because a significant portion of the interest expense incurred by GenOn Marsh Landing during construction will be capitalized, amounts included in accumulated other comprehensive loss associated with construction period interest payments will be reclassified to property, plant and equipment during the construction period and depreciated over the expected useful life of the Marsh Landing generating facility once it commences commercial operations in mid-2013. Actual amounts reclassified into earnings could vary from the amounts currently recorded as a result of future changes in interest rates.
 
The following tables present the notional quantity on long (short) positions for derivative financial instruments:
 
 	 	Notional Volumes at December 31,
2011	 	
Derivative Instruments	 	Derivative
Contract
Assets	 	Derivative
Contract
Liabilities	 	Net
Derivative
Contracts	 	
 	 	(in millions)	 	
Commodity Contracts (in equivalent MWh):	 	 	 	 	 	 	 	
Power(1)	 	(130	)	73	 	(57	)	
Natural gas	 	(8	)	10	 	2	 	
Fuel oil	 	—	 	—	 	—	 	
Coal	 	3	 	12	 	15	 	
Interest Rate Contracts (in dollars)(2)	 	—	 	475	 	475	 	
 
 	 	Notional Volumes at December 31,
2010	 	
Derivative Instruments	 	Derivative
Contract
Assets	 	Derivative
Contract
Liabilities	 	Net
Derivative
Contracts	 	
 	 	(in millions)	 	
Commodity Contracts (in equivalent MWh):	 	 	 	 	 	 	 	
Power(1)	 	(25	)	(26	)	(51	)	
Natural gas	 	(28	)	29	 	1	 	
Fuel oil	 	2	 	(3	)	(1	)	
Coal	 	10	 	10	 	20	 	
Interest Rate Contracts (in dollars)(2)	 	475	 	—	 	475	 	

(1)        Includes MWh equivalent of natural gas transactions used to hedge power economically.
 
(2)        When Marsh Landing commences commercial operation in mid-2013, the notional amount will increase to $500 million.
 
F-25

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments (Continued)
 
(b) Fair Value Measurements.
 
Fair Value Hierarchy and Valuation Techniques.  We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable prices for exchange-traded instruments to price curves that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:
 
Level 1:                         Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes natural gas and crude oil futures traded on the NYMEX and swaps cleared against NYMEX prices. The interest bearing funds and available-for-sale and trading securities are also valued using Level 1 inputs.
 
Level 2:                         Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. This category primarily includes non-exchange traded derivatives such as OTC forwards, swaps and options, and certain energy derivative instruments that are cleared and settled through exchanges. This category also includes the interest rate swaps.
 
Level 3:                         Represents commodity derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources (such as implied volatilities and correlations). The OTC, complex or structured derivative instruments that are transacted in less liquid markets with limited pricing information are included in Level 3. Examples are coal contracts, power transmission congestion products, power and natural gas contracts, and options valued using internally developed inputs.
 
In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls must be determined based on the lowest level input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and consideration of factors specific to the asset or liability.
 
A significant amount of the fair value of our derivative contract assets and liabilities is based on observable quoted prices from exchanges and indicative quoted prices from independent brokers in active markets that regularly facilitate our transactions. An active market is considered to have
 
F-26

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments (Continued)
 
transactions with sufficient frequency and volume to provide pricing information on an ongoing basis. We think these prices represent the best available information for valuation purposes. In determining the fair value of derivative contract assets and liabilities, we use third-party market pricing where available. For transactions classified in Level 1 of the fair value hierarchy, we use the unadjusted published settled prices on the valuation date. For transactions classified in Level 2 of the fair value hierarchy, we value these transactions using indicative quoted prices from independent brokers or other widely-accepted valuation methodologies. Transactions are classified in Level 2 if substantially all (greater than 90%) of the fair value can be corroborated using observable market inputs such as transactable broker quotes. In accordance with the exit price objective under the fair value measurements accounting guidance, the fair value of our derivative contract assets and liabilities is determined based on the net underlying position of the recorded derivative contract assets and liabilities using bid prices for assets and ask prices for liabilities. The quotes we obtain from brokers are non-binding in nature, but are from brokers that typically transact in the market being quoted and are based on their knowledge of market transactions on the valuation date. We typically obtain multiple broker quotes as of the valuation date that extend for the tenor of the underlying contracts for each delivery location. The number of quotes we can obtain depends on the relative liquidity of the delivery location on the valuation date. If multiple broker quotes are received for a contract, we use an average of the quoted bid or ask prices. If only one broker quote is received for a delivery location and it cannot be validated through other external sources, we will assign the quote to a lower level within the fair value hierarchy. In some instances, we may combine broker quotes for a liquid delivery hub with broker quotes for the price spread between the liquid delivery hub and the delivery location under the contract. We may also apply interpolation techniques to value monthly strips if broker quotes are only available on a seasonal or annual basis. We perform validation procedures on the broker quotes at least monthly. The validation procedures include reviewing the quotes for accuracy and comparing them to our internal price curves. In certain instances, we may exclude from consideration a broker quote if it is a clear outlier and other quotes are obtained. At December 31, 2011, we obtained broker quotes for 100% of our delivery locations classified in Level 2 of the fair value hierarchy.
 
Inactive markets are considered to be those markets with few transactions, noncurrent pricing or prices that vary over time or among market makers. Our transactions in Level 3 of the fair value hierarchy may involve transactions whereby observable market data, such as broker quotes, are not available for substantially all of the tenor of the contract or we are only able to obtain indicative broker quotes that cannot be corroborated by observable market data. In such cases, we may apply valuation techniques such as extrapolation and other quantitative methods to determine fair value. Proprietary models may also be used to estimate the fair value of derivative contract assets and liabilities that may be structured or otherwise tailored. Our techniques for fair value estimation include assumptions for market prices, correlation and volatility. The degree of estimation increases for longer duration contracts, contracts with multiple pricing features, option contracts and off-hub delivery points. At December 31, 2011, the assets and liabilities classified as Level 3 in the fair value hierarchy represented approximately 4% of total derivative contract assets and 11% of total derivative contract liabilities.
 
The fair value of our derivative contract assets and liabilities is also affected by assumptions as to time value, credit risk and non-performance risk. The nominal value of derivatives is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the transaction. Derivative contract assets are reduced to reflect the estimated default risk of counterparties
 
F-27

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments (Continued)
 
on their contractual obligations. The counterparty default risk for our overall net position is measured based on published spreads on credit default swaps for counterparties, where available, or proxies based upon published spreads, applied to our current exposure and potential loss exposure from the financial commitments in our risk management portfolio. The fair value of derivative contract liabilities is reduced to reflect the estimated risk of default on contractual obligations to counterparties and is measured based on published default rates of our debt, where available, or proxies based upon published spreads. Credit risk and non-performance risk are calculated with consideration of our master netting agreements with counterparties and our exposure is reduced by cash collateral posted against these obligations.
 
Fair Value of Derivative Instruments and Certain Other Assets.  The fair value measurements of financial assets and liabilities by class are as follows:
 
 	 	December 31, 2011	 	
 	 	Level 1(1)	 	Level 2(1)(2)	 	Level 3	 	Total
Fair Value	 	
 	 	(in millions)	 	
Derivative contract assets:	 	 	 	 	 	 	 	 	 	
Commodity Contracts	 	 	 	 	 	 	 	 	 	
Asset Management:	 	 	 	 	 	 	 	 	 	
Power	 	$	102	 	$	1,136	 	$	19	 	$	1,257	 	
Fuel	 	2	 	—	 	9	 	11	 	
Total Asset Management	 	104	 	1,136	 	28	 	1,268	 	
Trading Activities	 	124	 	302	 	38	 	464	 	
Total derivative contract assets	 	$	228	 	$	1,438	 	$	66	 	$	1,732	 	
Derivative contract liabilities:	 	 	 	 	 	 	 	 	 	
Commodity Contracts	 	 	 	 	 	 	 	 	 	
Asset Management:	 	 	 	 	 	 	 	 	 	
Power	 	$	45	 	$	206	 	$	2	 	$	253	 	
Fuel	 	19	 	1	 	79	 	99	 	
Total Asset Management	 	64	 	207	 	81	 	352	 	
Trading Activities	 	142	 	309	 	16	 	467	 	
Interest Rate Contracts	 	—	 	32	 	—	 	32	 	
Total derivative contract liabilities	 	$	206	 	$	548	 	$	97	 	$	851	 	
Interest-bearing funds(3)	 	$	1,985	 	$	—	 	$	—	 	$	1,985	 	
Other assets(4)	 	$	20	 	$	—	 	$	—	 	$	20	 	

(1)        Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no significant transfers during 2011.
 
(2)        Option contracts comprised approximately 1% of net derivative contract assets.
 
F-28

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments (Continued)
 
(3)        Represents investments in money market funds and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet. We had $1.626 billion of interest-bearing funds included in cash and cash equivalents, $202 million included in funds on deposit and $157 million included in other noncurrent assets.
 
(4)        Relates to mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees.
 
 	 	December 31, 2010	 	
 	 	Level 1(1)	 	Level 2(1)(2)	 	Level 3	 	Total
Fair Value	 	
 	 	(in millions)	 	
Derivative contract assets:	 	 	 	 	 	 	 	 	 	
Commodity Contracts	 	 	 	 	 	 	 	 	 	
Asset Management:	 	 	 	 	 	 	 	 	 	
Power	 	$	1	 	$	1,140	 	$	6	 	$	1,147	 	
Fuel	 	4	 	3	 	37	 	44	 	
Total Asset Management	 	5	 	1,143	 	43	 	1,191	 	
Trading Activities	 	530	 	385	 	11	 	926	 	
Interest Rate Contracts	 	—	 	19	 	—	 	19	 	
Total derivative contract assets	 	$	535	 	$	1,547	 	$	54	 	$	2,136	 	
Derivative contract liabilities:	 	 	 	 	 	 	 	 	 	
Commodity Contracts	 	 	 	 	 	 	 	 	 	
Asset Management:	 	 	 	 	 	 	 	 	 	
Power	 	$	12	 	$	340	 	$	4	 	$	356	 	
Fuel	 	18	 	2	 	109	 	129	 	
Total Asset Management	 	30	 	342	 	113	 	485	 	
Trading Activities	 	533	 	389	 	9	 	931	 	
Interest Rate Contracts	 	—	 	—	 	—	 	—	 	
Total derivative contract liabilities	 	$	563	 	$	731	 	$	122	 	$	1,416	 	
Interest-bearing funds(3)	 	$	2,977	 	$	—	 	$	—	 	$	2,977	 	
Other assets(4)	 	$	31	 	$	—	 	$	—	 	$	31	 	

(1)        Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no significant transfers during 2010.
 
(2)        Option contracts comprised approximately 7% of net derivative contract assets.
 
(3)        Represents investments in money market funds and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet. We had $2.385 billion of interest-bearing funds included in cash and cash equivalents, $425 million included in funds on deposit and $167 million included in other noncurrent assets.
 
(4)        Includes $13 million in available-for-sale securities (shares in a publicly traded exchange) and $18 million in mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees.
 
F-29

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments (Continued)
 
The following is a reconciliation of changes (comprised of the sum of the quarterly changes) in fair value of net commodity derivative contract assets and liabilities classified as Level 3 during 2011 and 2010:
 
 	 	Net Derivatives Contracts (Level 3)	 	
 	 	Asset
Management	 	Trading
Activities	 	Total	 	
 	 	(in millions)	 	
Balance, January 1, 2011 (net asset (liability))	 	$	(70	)	$	2	 	$	(68	)	
Total gains (losses) realized/unrealized:	 	 	 	 	 	 	 	
Included in earnings(1)	 	(4	)	28	 	24	 	
Purchases(2)	 	—	 	—	 	—	 	
Issuances(2)	 	—	 	—	 	—	 	
Settlements(3)	 	9	 	(8	)	1	 	
Transfers into Level 3(4)	 	—	 	—	 	—	 	
Transfers out of Level 3(4)	 	12	 	—	 	12	 	
Balance, December 31, 2011 (net asset (liability))	 	$	(53	)	$	22	 	$	(31	)	
Balance, January 1, 2010 (net asset (liability))	 	$	19	 	$	13	 	$	32	 	
Acquired and/or assumed in the Merger	 	2	 	—	 	2	 	
Total gains (losses) realized/unrealized:	 	 	 	 	 	 	 	
Included in earnings(1)	 	36	 	(49	)	(13	)	
Purchases(2)	 	—	 	—	 	—	 	
Issuances(2)	 	—	 	—	 	—	 	
Settlements(5)	 	(165	)	39	 	(126	)	
Transfers in and out of Level 3(4)	 	38	 	(1	)	37	 	
Balance, December 31, 2010 (net asset (liability))	 	$	(70	)	$	2	 	$	(68	)	

(1)        Represents the fair value, as of the end of each reporting period, of Level 3 contracts entered into during each reporting period and the gains and losses attributable to Level 3 contracts that existed as of the beginning of each reporting period and were still held at the end of each reporting period.
 
(2)        Contracts entered into during each reporting period are reported with other changes in fair value.
 
(3)        Effective January 1, 2011, represents the reversal of previously recognized unrealized gains and losses from settlement of contracts during each reporting period.
 
(4)        Denotes the total contracts that existed at the beginning of each reporting period and were still held at the end of each reporting period that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during each reporting period. Amounts reflect fair value as of the end of each reporting period.
 
F-30

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments (Continued)
 
(5)        Represents the total cash settlements of contracts during each reporting period that existed at the beginning of each reporting period.
 
The following table presents the amounts included in income related to derivative contract assets and liabilities classified as Level 3:
 
 	 	2011	 	2010	 	
 	 	Operating
Revenues	 	Cost of
Fuel,
Electricity
and Other
Products	 	Total	 	Operating
Revenues	 	Cost of
Fuel,
Electricity
and Other
Products	 	Total	 	
 	 	(in millions)	 	
Gains (losses) included in income	 	$	35	 	$	2	 	$	37	 	$	(28	)	$	(74	)	$	(102	)	
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at December 31	 	$	40	 	$	2	 	$	42	 	$	(4	)	$	(66	)	$	(70	)	
 
(c) Counterparty Credit Concentration Risk.
 
We are exposed to the default risk of the counterparties with which we transact. We manage our credit risk by entering into master netting agreements and requiring counterparties to post cash collateral or other credit enhancements based on the net exposure and the credit standing of the counterparty. We also have non-collateralized power hedges entered into by GenOn Mid-Atlantic. These transactions are senior unsecured obligations of GenOn Mid-Atlantic and the counterparties and do not require either party to post cash collateral for initial margin or for securing exposure as a result of changes in power or natural gas prices. Our credit valuation adjustment on derivative contract assets was $48 million and $21 million at December 31, 2011 and 2010, respectively.
 
At December 31, 2011 and 2010, $4 million and $3 million, respectively, of cash collateral posted by counterparties under master netting agreements were included in accounts payable and accrued liabilities on the consolidated balance sheets.
 
F-31

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments (Continued)
 
We monitor counterparty credit concentration risk on both an individual basis and a group counterparty basis. The following tables highlight the credit quality and the balance sheet settlement exposures related to these activities:
 
 	 	December 31, 2011	 	
Credit Rating Equivalent	 	Gross Exposure
Before
Collateral(1)	 	Net Exposure
Before
Collateral(2)	 	Collateral(3)	 	Exposure Net
of Collateral	 	% of Net
Exposure	 	
 	 	(dollars in millions)	 	
Clearing and Exchange	 	$	724	 	$	223	 	$	223	 	$	—	 	—	 	
Investment Grade:	 	 	 	 	 	 	 	 	 	 	 	
Financial institutions	 	860	 	817	 	—	 	817	 	78	%	
Energy companies	 	421	 	195	 	3	 	192	 	18	%	
Non-investment Grade:	 	 	 	 	 	 	 	 	 	 	 	
Energy companies	 	13	 	5	 	1	 	4	 	—	 	
No External Ratings:	 	 	 	 	 	 	 	 	 	 	 	
Internally-rated investment grade	 	18	 	18	 	—	 	18	 	2	%	
Internally-rated non-investment grade	 	15	 	15	 	—	 	15	 	2	%	
Total	 	$	2,051	 	$	1,273	 	$	227	 	$	1,046	 	100	%	
 
 	 	December 31, 2010	 	
Credit Rating Equivalent	 	Gross Exposure
Before
Collateral(1)	 	Net Exposure
Before
Collateral(2)	 	Collateral(3)	 	Exposure Net
of Collateral	 	% of Net
Exposure	 	
 	 	(dollars in millions)	 	
Clearing and Exchange	 	$	1,078	 	$	74	 	$	74	 	$	—	 	—	 	
Investment Grade:	 	 	 	 	 	 	 	 	 	 	 	
Financial institutions	 	837	 	729	 	—	 	729	 	65	%	
Energy companies	 	550	 	299	 	2	 	297	 	27	%	
Non-investment Grade:	 	 	 	 	 	 	 	 	 	 	 	
Energy companies	 	31	 	18	 	—	 	18	 	2	%	
No External Ratings:	 	 	 	 	 	 	 	 	 	 	 	
Internally-rated investment grade	 	52	 	45	 	—	 	45	 	4	%	
Internally-rated non-investment grade	 	34	 	34	 	8	 	26	 	2	%	
Total	 	$	2,582	 	$	1,199	 	$	84	 	$	1,115	 	100	%	

(1)        Gross exposure before collateral represents credit exposure, including both realized and unrealized transactions, before (a) applying the terms of master netting agreements with counterparties and (b) netting of transactions with clearing brokers and exchanges. The table excludes amounts related to contracts classified as normal purchases/normal sales and non-derivative contractual commitments that are not recorded at fair value in the consolidated balance sheets, except for any related accounts receivable. Such contractual commitments contain credit and economic risk if a
 
F-32

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
4. Financial Instruments (Continued)
 
counterparty does not perform. Non-performance could have a material adverse effect on the future results of operations, financial condition and cash flows.
 
(2)        Net exposure before collateral represents the credit exposure, including both realized and unrealized transactions, after applying the terms of master netting agreements and the netting of transactions with clearing brokers and exchanges.
 
(3)        Collateral includes cash and letters of credit received from counterparties.
 
We had credit exposure to two investment grade counterparties at December 31, 2011 and three investment grade counterparties at December 31, 2010, each representing an exposure of more than 10% of total credit exposure, net of collateral and totaling $664 million and $716 million at December 31, 2011 and 2010, respectively.
 
(d) Credit Risk.
 
Our standard industry contracts contain credit-risk-related contingent features such as ratings-related thresholds whereby we would be required to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade. Additionally, some of our contracts contain adequate assurance language, which is generally subjective in nature but could require us to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade. However, as a result of our current credit rating, we are typically required to post collateral in the normal course of business to offset either substantially or completely the net liability positions, after applying the terms of master netting agreements. At December 31, 2011, the fair value of financial instruments with credit-risk-related contingent features in a net liability position was $7 million for which we had posted collateral of $6 million, including cash and letters of credit.
 
At December 31, 2011 and 2010, we had $86 million and $107 million, respectively, of cash collateral posted with counterparties under master netting agreements that was included in funds on deposit on the consolidated balance sheets.
 
(e) Fair Values of Other Financial Instruments.
 
The fair values of certain funds on deposit, accounts receivable, notes and other receivables, and accounts payable and accrued liabilities approximate their carrying amounts.
 
The carrying amounts and fair values of debt are as follows:
 
 	 	December 31,	 	
 	 	2011	 	2010	 	
 	 	Carrying
Amount	 	Fair Value	 	Carrying
Amount	 	Fair Value	 	
 	 	(in millions)	 	
Liabilities:	 	 	 	 	 	 	 	 	 	
Long and short-term debt(1)	 	$	4,132	 	$	4,066	 	$	6,081	 	$	6,117	 	

(1)        The fair value of long- and short-term debt is estimated using reported market prices for instruments that are publically traded or estimated based on the income approach valuation technique for non-publicly traded debt using current interest rates for similar instruments with equivalent credit quality.
 
F-33

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
5. Long-Lived Assets
 
(a) Property, Plant and Equipment, Net.
 
Property, plant and equipment, net consisted of the following:
 
 	 	December 31, 2011	 	Depreciable	 	
 	 	2011	 	2010	 	Lives (years)	 	
 	 	(in millions)	 	 	 	
Production	 	$	5,488	 	$	5,526	 	3 to 33	 	
Leasehold improvements on leased generating facilities	 	1,297	 	1,205	 	4 to 34	 	
Construction work in progress	 	395	 	186	 	—	 	
Other	 	171	 	289	 	2 to 19	 	
Total	 	7,351	 	7,206	 	 	 	
Accumulated depreciation and amortization	 	(1,160	)	(977	)	 	 	
Total property, plant and equipment, net	 	$	6,191	 	$	6,229	 	 	 	
 
Depreciation of the recorded cost of property, plant and equipment is recognized on a straight-line basis over the estimated useful lives of the assets. Emissions allowances purchased in acquisitions prior to the Merger related to owned facilities were included in production assets above and are depreciated on a straight-line basis over the average life of the related generating facilities. See below for discussion of impairment of excess emissions allowances in 2011.
 
Depreciation expense was as follows:
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Depreciation expense	 	$	361	 	$	212	 	$	141	 	

(b) Intangible Assets, Net.
 
The following is a summary of intangible assets:
 
 	 	 	 	December 31, 2011	 	December 31, 2010	 	
 	 	Weighted Average
Amortization
Lives	 	Gross
Carrying
Amount	 	Accumulated
Amortization	 	Gross
Carrying
Amount	 	Accumulated
Amortization	 	
 	 	 	 	(in millions)	 	
Acquired contracts	 	7 years	 	$	33	 	$	(16	)	$	33	 	$	(7	)	
Emissions allowances	 	25 years	 	19	 	(7	)	120	 	(29	)	
Trading rights	 	16 years	 	15	 	(8	)	15	 	(6	)	
Development rights	 	30 years	 	13	 	(3	)	13	 	(2	)	
Other intangibles	 	30 years	 	4	 	(2	)	7	 	(4	)	
Total intangible assets	 	 	 	$	84	 	$	(36	)	$	188	 	$	(48	)	
 
Acquired contracts represent contracts acquired in connection with the Merger and represent the fair value on the Merger date of certain long-term tolling contracts, long-term natural gas
 
F-34

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
5. Long-Lived Assets (Continued)
 
transportation and storage contracts and REMA leases. The acquired contracts with positive fair values on the Merger date were recorded in intangible assets and the acquired contracts with negative fair values (out-of-market contracts) on the Merger date were recorded in other long-term liabilities in the consolidated balance sheet. At December 31, 2011 and 2010, $398 million and $444 million, respectively, were included in other long-term liabilities related to out-of-market contracts. The acquired contracts and out-of-market contracts are amortized in operating revenues, cost of fuel, electricity and other products and operations and maintenance expense, as applicable, based on the nature of the contracts and over their contractual lives.
 
Emissions allowances primarily represent allowances granted for the leasehold baseload units at the Dickerson and Morgantown generating facilities. See below for discussion of impairment of excess emissions allowances in 2011 and for information on the 2010 impairment of emissions allowances related to the Dickerson generating facility.
 
Trading rights are intangible assets recognized in connection with asset purchases that represent our ability to generate additional cash flows by incorporating our trading activities with the acquired generating facilities. See below for information on the 2009 impairment of the trading rights related to the Potrero and Contra Costa generating facilities.
 
Development rights represent the right to expand capacity at certain acquired generating facilities. The existing infrastructure, including storage facilities, transmission interconnections and fuel delivery systems, and contractual rights acquired, provide the opportunity to expand or repower certain generating facilities. See below for information on the 2010 impairment of the development rights related to the Dickerson generating facility and the 2009 impairment of the development rights related to the Potrero generating facility.
 
Amortization expense, excluding acquired contracts and out-of-market contracts, was as follows:
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Amortization expense	 	$	14	 	$	12	 	$	8	 	

Assuming no future acquisitions, dispositions or impairments of intangible assets, amortization expense, excluding acquired contracts and out-of-market contracts (see below), is estimated to be approximately the following for each of the next five years (in millions):
 
2012	 	$	3	 	
2013	 	3	 	
2014	 	3	 	
2015	 	1	 	
2016	 	1	 	
 
F-35

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
5. Long-Lived Assets (Continued)
 
Acquired contracts and out-of-market contracts amortization was as follows (increase (decrease), net):
 
 	 	2011	 	2010	 	
 	 	(in millions)	 	
Operating revenues	 	$	(23	)	$	(1	)	
Cost of fuel, electricity and other products	 	(51	)	3	 	
Operations and maintenance expense	 	(7	)	(1	)	

Acquired contracts and out-of-market contracts amortization is estimated to be approximately the following for each of the next five years (increase (decrease), net):
 
 	 	Operating
Revenues	 	Cost of Fuel,
Electricity and
Other Products	 	Operations and
Maintenance
Expense	 	
 	 	(in millions)	 	
2012	 	$	(7	)	$	(47	)	$	(7	)	
2013	 	2	 	(33	)	(7	)	
2014	 	—	 	(33	)	(7	)	
2015	 	—	 	(30	)	(7	)	
2016	 	—	 	(26	)	(7	)	

(c) Impairments on Assets Held and Used.
 
2011
 
Granted Emissions Credits
 
In August 2011, the EPA finalized the CSAPR, which was intended to replace the CAIR starting in 2012. In September 2011, we and others asked the D.C. Circuit to stay and vacate the CSAPR. In December 2011, the court ordered the EPA to stay implementation of the CSAPR and to keep CAIR in place until the court rules on the legal deficiencies alleged with respect to the CSAPR. The CSAPR addresses interstate transport of emissions of NO x  and SO 2 . The CSAPR establishes limitations on NO x  and/or SO 2  emissions from electric generating units that are (i) greater than 25 megawatts and (ii) located in 28 states (in the eastern half of the United States) that the EPA determined contribute significantly to nonattainment in other states, or to interfere with maintenance in other states, of one or more of three NAAQS: (a) the annual NAAQS for fine particulate matter (PM 2.5 ) promulgated in 1997; (b) the “24-hour” NAAQS for PM 2.5  promulgated in 2006 and (c) the ozone NAAQS promulgated in 1997. The CSAPR creates “emission budgets” for each of the covered states and allocates emissions allowances (denominated in tons of emissions) to each of the 28 states regulated under the CSAPR.
 
Under the CSAPR program, the EPA established new allowances for all of the new CSAPR programs and did not permit any carryover Acid Rain Program or CAIR allowances into the CSAPR trading programs. As a result, the NO x  allowances from the CAIR program would not have been used. Accordingly, we thought that the CAIR NO x  allowances would have no value after 2011. Similarly, the SO 2  allowances used for compliance in the CAIR program (which used the already existing Acid Rain
 
F-36

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
5. Long-Lived Assets (Continued)
 
Program allowances that would have continued to be usable for compliance with the Acid Rain Program) would not have been usable for compliance with the CSAPR SO 2  program and we thought they would have negligible value after 2011. As a result of the CSAPR, we recorded impairment losses of $133 million for (a) the write-off of excess NO x  and SO 2  emissions allowances previously included in intangible assets ($75 million) and (b) the write-off of excess NO x  and SO 2  emissions allowances previously included in property, plant and equipment ($58 million) during 2011. The emissions allowances within property, plant and equipment and intangible assets had previously been included with a generating facility asset group for purposes of impairment testing. Because we thought (a) there would be no future use of the NO x  emissions allowances and (b) the SO 2  emissions allowances would have negligible value after 2011 under the CSAPR and their price had fallen sharply, we evaluated, in conjunction with preparing our third quarter interim financial statements, these emissions allowances for impairment separately from the generating facility asset group and determined that impairments existed.
 
As we thought that CAIR NOx emissions allowances of $45 million would have no value after 2011, they were fully impaired. The excess Acid Rain Program SO 2  emissions allowances of $91 million were impaired to their estimated fair value of $3 million based on their current market prices obtained from brokers. The excess Acid Rain Program SO 2  emissions allowances were categorized in Level 3 in the fair value hierarchy.
 
Potomac River Generating Facility
 
In the fourth quarter of 2010, we recorded impairment losses of $42 million to reduce the carrying value of the Potomac River generating facility to its estimated fair value of approximately $1 million. In addition, as a result of the impairment of the Potomac River generating facility, we recorded $32 million in operations and maintenance expense and corresponding liabilities associated with our commitment to reduce particulate emissions as part of the agreement with the City of Alexandria, Virginia. This $32 million is held in an escrow account. The planned capital investment would not be recovered in future periods based on the current projected cash flows of the Potomac River generating facility.
 
In August 2011, we entered into an agreement with the City of Alexandria, Virginia to remove permanently from service our Potomac River generating facility. The agreement, which amends our Project Schedule and Agreement, dated July 17, 2008 with the City of Alexandria, provides for the retirement of the Potomac River generating facility on October 1, 2012, subject to the receipt of all necessary consents and approvals. PJM has determined that the retirement of the facility will not affect reliability. We must now receive consent from PEPCO. We will reverse the previously recorded obligation upon the receipt of consent from PEPCO and we will recognize a reduction in operations and maintenance expense. If the PEPCO consent has not been received by July 3, 2012, the Potomac River generating facility will be retired within 90 days after the receipt thereof. Upon retirement of the Potomac River generating facility, all funds in the escrow account ($32 million) established under the July 17, 2008 agreement shall be distributed to us, provided, that, if the retirement of the facility is after January 1, 2014, $750,000 of such funds shall be paid to the City of Alexandria.
 
F-37

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
5. Long-Lived Assets (Continued)
 
2010
 
GenOn Mid-Atlantic Generating Facilities
 
In December 2010, PJM published an updated load forecast, which depicted a decrease in the expected demand because of lower economic growth expectations. As a result of the load forecast, our expectation was that there would be a decrease in the clearing prices for future capacity auctions in certain years. As a result of the decrease in projected capacity revenue, we evaluated GenOn Mid-Atlantic long-lived assets for impairment. Each of the GenOn Mid-Atlantic generating facilities was viewed as an individual asset group.
 
Our assumptions related to future electricity and fuel prices were based on observable market prices to the extent available and long-term prices derived from proprietary fundamental market modeling. The assumptions regarding electricity demand were based on forecasts from PJM and assumptions for generating capacity additions and retirements included publicly-announced projects, which take into account renewable sources of electricity.
 
We recorded impairment losses of $523 million and $42 million on the consolidated statement of operations to reduce the carrying values of the Dickerson and Potomac River generating facilities, respectively, to their estimated fair values. In addition, as a result of the impairment of the Potomac River generating facility, we recorded $32 million in operations and maintenance expense and corresponding liabilities associated with our commitment at the time to reduce particulate emissions as part of the agreement with the City of Alexandria, Virginia. The planned capital investment would not have been recovered in future periods based on the projected cash flows of the Potomac River generating facility.
 
The following table sets forth by level within the fair value hierarchy our assets that were accounted for at fair value on a non-recurring basis. All of our assets that were measured at fair value as a result of impairment losses recorded during 2010 were categorized in Level 3 at December 31, 2010:
 
 	 	Quoted Prices in
Active Markets
for
Identical Assets
(Level 1)	 	Significant
Other
Observable
Inputs
(Level 2)	 	Significant
Other
Unobservable
Inputs
(Level 3)	 	Total	 	Loss
Included
in Earnings	 	
 	 	(in millions)	 	
Dickerson generating facility	 	$	—	 	$	—	 	$	91	 	$	91	 	$	462	 	
Dickerson intangible assets	 	—	 	—	 	8	 	8	 	61	 	
Potomac River generating facility(1)	 	—	 	—	 	1	 	1	 	42	 	
Total	 	$	—	 	$	—	 	$	100	 	$	100	 	$	565	 	

(1)                                The remaining carrying value represents the fair value of the related SO2 and NOx emissions allowances included in property, plant and equipment, net.
 
F-38

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
5. Long-Lived Assets (Continued)
 
2009
 
Potrero Generating Facility
 
During 2009, GenOn Potrero executed a settlement agreement with the City and County of San Francisco in which it agreed to shut down the Potrero generating facility when it was no longer needed for reliability, as determined by the CAISO. As a result of the settlement agreement, we evaluated the Potrero generating facility for impairment during the third quarter of 2009. All of the units at GenOn Potrero were viewed as a single asset group. Additionally, the asset group included intangible assets recorded at GenOn California North, LLC for trading and development rights related to GenOn Potrero.
 
We determined that the tangible assets for the Potrero generating facility were not impaired because the weighted average sum of the undiscounted cash flows exceeded the carrying value of the tangible assets in the third quarter of 2009.
 
As a result of certain terms included in the settlement agreement, we separately evaluated the trading and development rights associated with the Potrero generating facility for impairment and determined that both of these intangible assets were fully impaired at September 30, 2009. Accordingly, we recognized an impairment loss of $9 million on the consolidated statement of operations to write off the carrying value of the intangible assets related to the Potrero generating facility. This impairment loss is included in the results of our California segment for 2009.
 
Contra Costa Generating Facility
 
We entered into an agreement with PG&E in September 2009 for 674 MW at Contra Costa for the period from November 2011 through April 2013. At the end of the agreement, and subject to any necessary regulatory approvals, we have agreed to retire the Contra Costa facility.
 
We evaluated the intangible asset of trading rights related to our Contra Costa generating facility for impairment during the third quarter of 2009 as a result of the shutdown provisions in the tolling agreement. Because the Contra Costa generating facility is under contract with PG&E through its expected shutdown date of May 2013, we determined the intangible asset was fully impaired as of September 30, 2009. We recorded an impairment loss of $5 million on the consolidated statement of operations to write off the carrying value of the trading rights related to the Contra Costa generating facility. This impairment loss is included in the results of our California segment for 2009.
 
GenOn Mid-Atlantic Generating Facilities
 
During 2009, the continued decline in average natural gas prices caused power prices to decline in the Eastern PJM region. Additionally, weak economic conditions and various demand-response programs at the time resulted in a decrease in the forecasted gross margin of the GenOn Mid-Atlantic generating facilities.
 
We determined that the Potomac River generating facility was impaired, as the carrying value exceeded the undiscounted cash flows. As a result of the assessment, we recorded an impairment loss of $207 million in the fourth quarter of 2009 to reduce the carrying value of the Potomac River generating facility to its estimated fair value.
 
F-39

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
5. Long-Lived Assets (Continued)
 
The following table sets forth by level within the fair value hierarchy our assets that were accounted for at fair value on a non-recurring basis. All of our assets that were measured at fair value as a result of impairment losses recorded during 2009 were categorized in Level 3 at December 31, 2009:
 
 	 	Quoted Prices in
Active Markets
for
Identical Assets
(Level 1)	 	Significant
Other
Observable
Inputs
(Level 2)	 	Significant
Other
Unobservable
Inputs
(Level 3)	 	Total	 	Loss
Included
in Earnings	 	
 	 	(in millions)	 	
Potomac River generating facility	 	$	—	 	$	—	 	$	37	 	$	37	 	$	207	 	
Potrero intangible assets	 	—	 	—	 	—	 	—	 	9	 	
Contra Costa intangible assets	 	—	 	—	 	—	 	—	 	5	 	
Total	 	$	—	 	$	—	 	$	37	 	$	37	 	$	221	 	
 
(d) Asset Retirement Obligations.
 
Upon initial recognition of a liability for an asset retirement obligation or a conditional asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of accounting guidance are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.
 
We identified certain asset retirement obligations within our power generating facilities. These asset retirement obligations are primarily related to asbestos abatement in facilities on owned or leased property and other environmental obligations related to ash disposal sites. In addition, the asset retirement obligations also relate to environmental obligations for fuel storage facilities, wastewater treatment facilities and pipelines. See note 16.
 
Asbestos abatement is the most significant type of asset retirement obligation identified for recognition in connection with our policy related to accounting for conditional asset retirements. The EPA has regulations in place governing the removal of asbestos. Because of the nature of asbestos, it can be difficult to ascertain the extent of contamination in older facilities unless substantial renovation or demolition takes place. Therefore, we incorporated certain assumptions based on the relative age and size of our facilities to estimate the current cost for asbestos abatement. The actual abatement cost could differ from the estimates used to measure the asset retirement obligation. As a result, these amounts will be subject to revision when actual abatement activities are undertaken.
 
F-40

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
5. Long-Lived Assets (Continued)
 
The following table sets forth the balances of the asset retirement obligations and the additions, revisions in estimated cash flows and accretion of the asset retirement obligations. The asset retirement obligations are included in other noncurrent liabilities in the consolidated balance sheets:
 
 	 	2011	 	2010	 	
 	 	(in millions)	 	
Beginning balance January 1	 	$	122	 	$	43	 	
Assumed in the Merger	 	—	 	67	 	
Revisions in estimated cash flows	 	(3	)(1)	7	 	
Accretion expense	 	13	 	5	 	
Ending balance December 31	 	$	132	 	$	122	 	

(1)                                Includes $9 million of income recorded in the consolidated statement of operations as a result of changes in asset retirement obligations assumptions.
 
At December 31, 2011 and 2010, we had $26 million and $24 million, respectively (classified in other long-term assets) on deposit with the state of Pennsylvania to guarantee our obligation related to future closures of coal ash disposal landfill sites.
 
F-41

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
6. Long-Term Debt
 
(a)                                Overview.
 
Outstanding debt was as follows:
 
 	 	December 31, 2011	 	December 31, 2010	 	
 	 	Weighted
Average
Stated
Interest
Rate(1)	 	Long-term	 	Current	 	Weighted
Average
Stated
Interest
Rate(1)	 	Long-term	 	Current	 	
 	 	(in millions, except interest rates)	 	
Facilities, Bonds and Notes:	 	 	 	 	 	 	 	 	 	 	 	 	 	
GenOn:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior secured notes, due 2014(2)	 	—	 	$	—	 	$	—	 	6.75	%	$	—	 	$	279	 	
Senior unsecured notes, due 2014	 	7.625	%	575	 	—	 	7.625	 	575	 	—	 	
Senior unsecured notes, due 2017	 	7.875	 	725	 	—	 	7.875	 	725	 	—	 	
Senior secured term loan, due 2017(3)	 	6.00	 	684	 	7	 	6.00	 	691	 	7	 	
Senior unsecured notes, due 2018	 	9.50	 	675	 	—	 	9.50	 	675	 	—	 	
Senior unsecured notes, due 2020	 	9.875	 	550	 	—	 	9.875	 	550	 	—	 	
Unamortized debt discounts	 	 	 	(24	)	(2	)	 	 	(27	)	(2	)	
GenOn Americas Generation:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior unsecured notes, due 2011(4)	 	—	 	—	 	—	 	8.30	 	—	 	535	 	
Senior unsecured notes, due 2021	 	8.50	 	450	 	—	 	8.50	 	450	 	—	 	
Senior unsecured notes, due 2031	 	9.125	 	400	 	—	 	9.125	 	400	 	—	 	
Unamortized debt discounts	 	 	 	(2	)	—	 	 	 	(2	)	—	 	
GenOn North America:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior notes, due 2013(5)	 	—	 	—	 	—	 	7.375	 	—	 	850	 	
GenOn Marsh Landing:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior secured term loan, due 2017(6)	 	2.70	 	33	 	—	 	—	 	—	 	—	 	
Senior secured term loan, due 2023(6)	 	2.95	 	74	 	—	 	—	 	—	 	—	 	
Other:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital leases, due 2011 to 2015	 	7.375 - 8.19	 	14	 	5	 	7.375 - 8.19	 	18	 	4	 	
PEDFA fixed-rate bonds, due 2036(7)	 	—	 	—	 	—	 	6.75	 	—	 	371	 	
Adjustment to fair value of debt(8)	 	 	 	(32	)	—	 	 	 	(35	)	17	 	
Total	 	 	 	$	4,122	 	$	10	 	 	 	$	4,020	 	$	2,061	 	

(1)                                The weighted average stated interest rates are at December 31, 2011 and 2010, respectively.
 
(2)                                These notes were discharged at the closing of the Merger on December 3, 2010 and were redeemed on January 3, 2011 at a call price of 102.25% of the principal amount.
 
(3)                                The debt balance on the term loan facility is recorded at GenOn Americas, a direct subsidiary of GenOn Energy Holdings, because GenOn Americas is a co-borrower.
 
(4)                                These notes were repaid on May 2, 2011.
 
(5)                                These notes were discharged at the closing of the Merger on December 3, 2010 and were redeemed on January 3, 2011 at a call price of 101.844% of the principal amount.
 
F-42

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
6. Long-Term Debt (Continued)
 
(6)                                During the second quarter of 2011, we satisfied the required initial equity contributions of $147 million and GenOn Marsh Landing began borrowing under its credit facility.
 
(7)                                These notes were defeased at 103% of principal plus accrued and unpaid interest to the redemption date of June 1, 2011 and were redeemed on that day.
 
(8)                                Debt assumed in the Merger was adjusted to fair value on the Merger date. Included in interest expense is amortization of $3 million for valuation adjustments related to the assumed debt for the year ended December 31, 2011. Included in interest expense during 2010 is an insignificant amount of amortization expense for valuation adjustments related to the assumed debt.
 
Debt maturities for the principal amounts at December 31, 2011 are (in millions):
 
2012	 	$	12	 	
2013	 	11	 	
2014	 	587	 	
2015	 	12	 	
2016	 	7	 	
2017 and thereafter	 	3,563	(1)	
Total	 	$	4,192	 	

(1)                                Includes $107 million outstanding at December 31, 2011, under the $500 million GenOn Marsh Landing senior secured term loan facility. However, the balance outstanding on the commercial operation date will be fully amortized by the maturity dates in accordance with the GenOn Marsh Landing credit agreement repayment schedules, with such amortization commencing one quarter following the commercial operation of the Marsh Landing generating facility, expected in mid-2013.
 
GenOn
 
Senior Secured Term Loan Facility and Revolving Credit Facility.  In September 2010, GenOn entered into a credit agreement, which provides for:
 
·                 a seven-year amortizing senior secured term loan facility with a rate of LIBOR + 4.25% (with a LIBOR floor of 1.75%), with a balance of $691 million at December 31, 2011; and
 
·                 a $788 million five-year senior secured revolving credit facility, with an undrawn rate of 0.75% and a drawn rate of LIBOR + 3.50%.
 
Availability of borrowings under the GenOn revolving credit facility is reduced by any outstanding letters of credit. At December 31, 2011, outstanding letters of credit were $265 million and availability of borrowings under the revolving credit facility was $523 million.
 
Loans under the GenOn credit facilities are available at either of the following rates: (a) the base rate plus the applicable margin or (b) the LIBOR rate plus the applicable margin. The applicable margin with respect to loans under the GenOn senior secured revolving credit facility is 2.5% in the case of base rate loans, or 3.5% in the case of LIBOR rate loans. The applicable margin with respect to loans under the senior secured term loan is 3.25% in the case of base rate loans, or 4.25% in the
 
F-43

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
6. Long-Term Debt (Continued)
 
case of LIBOR rate loans. For the term loan facility only, the LIBOR rate shall not be less than 1.75% per annum. In addition, the term loan facility also accrued interest at 4.25% per annum during the period between the commitment date of September 20, 2010 and the date that the term loan was funded, which amounts were paid upon funding.
 
The terms of the GenOn credit facilities require GenOn to maintain a ratio of consolidated secured debt (net of up to $500 million in cash and certain collateral assets and deposits) to adjusted EBITDA of not more than 3.50 to 1.00, which will be tested at the end of each fiscal quarter and, in the case of EBITDA, will be calculated on a rolling four quarter basis ending on the last day of such fiscal quarter. In addition, the GenOn credit facilities restrict the ability of GenOn to, among other things, (a) incur additional indebtedness, (b) pay dividends, prepay subordinated indebtedness or purchase capital stock, (c) encumber assets, (d) enter into business combinations or divest assets, (e) make investments or loans, (f) enter into transactions with affiliates and (g) engage in sale and leaseback transactions, subject in each case to certain exceptions or excluded amounts. The GenOn credit facilities provide for acceleration of GenOn’s obligations and the termination of commitments thereunder upon the occurrence and continuance of certain events of default, including, without limitation: (a) failure to pay principal when due, (b) failure to pay for a period of five business days interest and other amounts when due, (c) default in the performance of certain covenants contained in the credit agreement, subject to grace or cure periods set forth therein, (d) failure to pay amounts due, after applicable grace periods, under, or upon acceleration of, certain material debt, (e) any money judgment rendered against us which is not stayed for any period of 60 days, (f) any change of control (as defined in the GenOn credit agreement) and (g) certain bankruptcy and insolvency events.
 
The GenOn credit facilities, and the subsidiary guarantees thereof, are the senior secured obligations of GenOn and certain of its existing and future direct and indirect subsidiaries, excluding GenOn Americas Generation; provided, however, that certain of GenOn Americas Generation’s subsidiaries (other than GenOn Mid-Atlantic and GenOn Energy Management and their subsidiaries) guarantee the GenOn credit facilities to the extent permitted under the indenture for the senior notes of GenOn Americas Generation. GenOn Americas became a co-borrower under the GenOn credit facilities upon the closing of the Merger.
 
Senior Unsecured Notes, Due 2018 and 2020.  In October 2010, GenOn Escrow issued two series of senior unsecured notes:
 
·                 $675 million of 9.5% senior notes due 2018; and
 
·                 $550 million of 9.875% senior notes due 2020.
 
The senior notes were issued at a discount to par, resulting in net proceeds to GenOn Escrow of $1.2 billion. Upon completion of the Merger, GenOn Escrow merged with and into GenOn which assumed all of GenOn Escrow’s obligations under the notes and the related indenture and the funds held in escrow were released to GenOn.
 
In connection with our obligations under the Registration Rights Agreement with the initial purchasers of these senior secured notes, dated October 4, 2010, we filed a registration statement and completed, in the second quarter of 2011, offerings to exchange the old notes for a like principal
 
F-44

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
6. Long-Term Debt (Continued)
 
amount at maturity of new notes. The new notes have the same terms and conditions as the old notes, including interest rates, maturity dates and covenants.
 
The senior notes and the related indentures restrict the ability of GenOn to incur additional liens and make certain restricted payments, including dividends and purchases of capital stock. At December 31, 2011, GenOn did not meet the consolidated debt ratio component of the restricted payments test and, therefore, the ability of GenOn to make restricted payments is limited to specified exclusions from the covenant, including up to $250 million of such restricted payments. In the event of a change of control of GenOn, holders of the senior notes have the right to require GenOn to purchase the outstanding senior notes at a price equal to 101% of the principal amount plus accrued and unpaid interest and additional interest (as defined in the indenture), if any. The senior notes will be subject to acceleration of GenOn’s obligations thereunder upon the occurrence of certain events of default, including: (a) default in interest payment for 30 days, (b) default in the payment of principal or premium, if any, (c) failure after 90 days of specified notice to comply with any other agreements in the indenture, (d) certain cross-acceleration events, (e) failure by GenOn or its significant subsidiaries to pay certain final and non-appealable judgments after 90 days and (f) certain events of bankruptcy and insolvency.
 
Under the senior notes and the related indentures, the senior notes are the sole obligation of GenOn and are not guaranteed by any subsidiary of GenOn.
 
Senior Secured Notes Due 2014.  The senior secured notes due 2014 were recorded at their fair value on the Merger date which approximated their redemption value. Upon the closing of the Merger, the senior secured notes were discharged following the deposit with the trustee of funds sufficient to pay the redemption price thereof, plus accrued interest to the date of redemption. The amount of funds on deposit with the trustee was $285 million at December 31, 2010 and was recorded as restricted cash and included in funds on deposit on the consolidated balance sheet.
 
In January 2011, the senior secured notes were redeemed at the call price of 102.25% of the principal amount plus accrued and unpaid interest through the date of redemption. The total payment on the date of redemption was $285 million and a $1 million loss on early extinguishment of debt was recognized during 2011.
 
Senior Unsecured Notes, Due 2014 and 2017.  The senior notes due 2014 and 2017 of GenOn were recorded at their fair values of $582 million and $683 million, respectively, on the Merger date. At December 31, 2011, $5 million premium and $37 million discount are being amortized to interest expense over the life of the related notes. The senior notes are senior unsecured obligations of GenOn having no recourse to any subsidiary or affiliate of GenOn. The senior notes restrict the ability of GenOn and its subsidiaries to encumber their assets.
 
GenOn Americas Generation
 
Senior Unsecured Notes.  The senior notes due 2021 and 2031 are senior unsecured obligations of GenOn Americas Generation having no recourse to any subsidiary or affiliate of GenOn Americas Generation. In May 2011, GenOn Americas Generation repaid at maturity $535 million of its senior notes due 2011.
 
F-45

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
6. Long-Term Debt (Continued)
 
GenOn North America
 
Senior Notes Due 2013.  Upon the closing of the Merger, the senior notes due 2013 of GenOn North America were discharged following the deposit with the trustee of funds sufficient to pay the redemption price thereof, plus accrued interest to the date of redemption. The amount of funds on deposit with the trustee was $866 million at December 31, 2010 and was recorded as restricted cash included in funds on deposit on the consolidated balance sheet.
 
In January 2011, the senior notes were redeemed at the call price of 101.844% of the principal amount plus accrued and unpaid interest through the date of redemption. The total payment on the date of redemption was $866 million and a $23 million loss on early extinguishment of debt (in other, net on the consolidated statement of operations) was recognized during 2011, which includes a $16 million premium and $7 million of unamortized debt issuance costs.
 
Senior Secured Credit Facilities.  Upon closing of the Merger, GenOn North America repaid the outstanding senior secured credit facility of $305 million plus accrued and unpaid interest through the date of repayment. The total payment was $305 million and a $9 million loss on extinguishment of debt was recognized in other, net in the consolidated statement of operations during 2010.
 
GenOn Marsh Landing
 
Credit Facility.  In October 2010, GenOn Marsh Landing entered into a credit agreement for up to approximately $650 million of commitments to provide construction and permanent financing for the Marsh Landing generating facility. The credit facility consists of a $155 million tranche A senior secured term loan facility, due 2017, a $345 million tranche B senior secured term loan facility, due 2023, a $50 million senior secured letter of credit facility to support GenOn Marsh Landing’s debt service reserve requirements and a $100 million senior secured letter of credit facility to support GenOn Marsh Landing’s collateral requirements under its PPA with PG&E. Prior to the commercial operation date of the project, the collateral requirements under the PPA and construction contracts are being met by a $165 million cash collateralized letter of credit facility entered into by GenOn Energy Holdings on behalf of GenOn Marsh Landing in September 2010. At or near the commercial operation date of the project, the GenOn Energy Holdings cash collateralized letter of credit facility will terminate. During the second quarter of 2011, we satisfied the required initial equity contributions of $147 million and GenOn Marsh Landing began borrowing under its credit facility.
 
The term loans are to be fully amortized by their maturity dates. The tranche A term loan matures on December 31, 2017 and the tranche B term loan matures on the date that is the earlier of the last day of the first fiscal quarter following the tenth anniversary of the conversion of the credit facility from a construction facility to a permanent facility upon commercial operation of the Marsh Landing project and December 31, 2023. The expiry date of the letters of credit is December 31, 2017. Interest on the tranche A term loan is based on a base rate or a LIBOR rate plus an initial applicable margin of 1.5% for base rate loans and 2.5% for LIBOR loans (with such margin increasing 0.25% every three years). Interest on the tranche B term loan is based on a base rate or a LIBOR rate plus an initial applicable margin of 1.75% for base rate loans and 2.75% for LIBOR loans (with such margin increasing 0.25% every three years). Fees on lenders’ exposure under the letters of credit accrue at a
 
F-46

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
6. Long-Term Debt (Continued)
 
rate equal to the applicable margin payable on the tranche A term loan that are based on the LIBOR rate. An undrawn commitment fee applies at a rate of 0.75%.
 
In connection with the credit agreement, GenOn Marsh Landing entered into interest rate swaps to mitigate the interest rate risks with respect to its term loans. GenOn Energy Holdings provided limited guarantees in respect of the interest rate swaps. The effective interest rate that GenOn Marsh Landing will pay for the term loans from the commercial operations date is 5.91% (plus the step-up in margin over time). The interest rate swaps are accounted for as cash flow hedges with changes in fair value recognized in other comprehensive income, with the exception of any ineffectiveness which is recognized in the consolidated statement of operations. GenOn expects the interest rate swaps to remain highly effective in mitigating the interest rate risk.
 
Loans under the credit facility will be subject to mandatory prepayment upon the occurrence of certain events, including an event of damage or an event of taking, the receipt of the proceeds of any claim under any document executed in connection with the Marsh Landing project and any amounts payable as a result of termination of the PPA. The credit facility includes customary affirmative and negative covenants and events of default. Negative covenants include limitations on additional debt, liens, negative pledges, investments, distributions, business activities, stock repurchases, asset dispositions, accounting changes, change orders and affiliate transactions. Events of default include non-performance of covenants, breach of representations, cross-acceleration of other material indebtedness, bankruptcy and insolvency, undischarged material judgments, a change in control and a failure to achieve commercial operation of the Marsh Landing project by December 31, 2013.
 
Other
 
Capital Leases.  These capital leases include a lease at our Chalk Point generating facility for an 84 MW peaking unit. The amount outstanding under the capital lease at December 31, 2011, which matures in 2015, is $18 million with an 8.19% annual interest rate. Depreciation expense related to this lease was $2 million during 2011, 2010 and 2009. The annual principal payments under this lease are $4 million in 2012 and 2013 and $5 million in 2014 and 2015. The gross amount of assets under the capital lease, recorded in property, plant and equipment, net, was $24 million at December 31, 2011 and 2010. The related accumulated depreciation was $18 million and $16 million at December 31, 2011 and 2010, respectively.
 
PEDFA Fixed-Rate Bonds.  The PEDFA bonds were recorded at their fair value on the Merger date which approximated their redemption value. Upon the closing of the Merger, the PEDFA bonds were defeased following the deposit with the trustee of funds sufficient to pay the redemption price thereof, plus accrued interest to the date of redemption. The amount of funds on deposit with the trustee was $394 million at December 31, 2010 and was recorded as restricted cash and included in the funds on deposit on the consolidated balance sheet.
 
In June 2011, the PEDFA bonds were redeemed at the call price of 103% of the principal amount plus accrued and unpaid interest through the date of redemption. The total payment on the date of redemption was $394 million and a $1 million gain on extinguishment of debt was recognized during 2011.
 
F-47

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
6. Long-Term Debt (Continued)
 
(b)                                Sources of Funds.
 
The principal sources of liquidity for us are expected to be: (a) existing cash on hand and expected cash flows from the operations of our subsidiaries, (b) letters of credit issued or borrowings made under the GenOn revolving credit facility and (c) letters of credit issued or borrowings made under GenOn Marsh Landing’s project financing.
 
GenOn and certain of its subsidiaries are holding companies and, as a result, GenOn and such subsidiaries are dependent upon dividends, distributions and other payments from their respective subsidiaries to generate the funds necessary to meet their obligations. In particular, a substantial portion of the cash from our operations is generated by GenOn Mid-Atlantic. The ability of certain of our subsidiaries to pay dividends and make distributions is restricted under the terms of their debt or other agreements, including the operating leases of GenOn Mid-Atlantic and REMA. 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 the event of a default under the respective operating leases or if the respective restricted payment tests are not satisfied, GenOn Mid-Atlantic and REMA would not be able to distribute cash. At December 31, 2011, GenOn Mid-Atlantic satisfied the restricted payments tests. At December 31, 2011, REMA did not satisfy the restricted payments test. As a result of certain lien restrictions in its lease documentation, GenOn Mid-Atlantic has reserved $165.6 million of cash (which is included in funds on deposit on the consolidated balance sheet) in respect of such liens. See note 16.
 
Pursuant to the terms of their respective lease and debt documents, GenOn Mid-Atlantic, REMA and GenOn Marsh Landing are restricted from, among other actions, (a) encumbering assets, (b) entering into business combinations or divesting assets, (c) incurring additional debt, (d) entering into transactions with affiliates on other than an arm’s length basis or (e) materially changing their business. Therefore, at December 31, 2011, all of GenOn Mid-Atlantic’s, REMA’s and GenOn Marsh Landing’s net assets (excluding cash) were deemed restricted for purposes of Rule 4-08(e)(3)(iii) of Regulation S-X.
 
The amounts of restricted net assets were as follows:
 
 	 	December 31,	 	
 	 	2011	 	2010	 	
 	 	(in millions)	 	
GenOn Mid-Atlantic	 	$	3,859	 	$	3,690	 	
REMA	 	534	 	422	 	
GenOn Marsh Landing	 	107	 	80	 	
Total restricted net assets	 	$	4,500	 	$	4,192	 	
 
The ability of GenOn Americas Generation to pay its obligations is dependent on the receipt of dividends from GenOn North America and, in turn, GenOn Mid-Atlantic; capital contributions or
 
F-48

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
6. Long-Term Debt (Continued)
 
intercompany loans from GenOn; and its ability to refinance all or a portion of those obligations as they become due.
 
7. Income Taxes
 
The income tax provision consisted of the following:
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Current income tax provision (benefit)	 	$	—	 	$	(2	)	$	12	 	
Deferred income tax provision	 	—	 	—	 	—	 	
Provision (benefit) for income taxes	 	$	—	 	$	(2	)	$	12	 	
 
A reconciliation of our federal statutory income tax provision to the effective income tax provision/benefit adjusted for permanent and other items during 2011, 2010 and 2009, is as follows:
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Provision for income taxes based on United States federal statutory income tax rate	 	$	(66	)	$	(82	)	$	177	 	
State and local income tax provision, net of federal income taxes	 	(8	)	2	 	29	 	
Change in deferred tax asset valuation allowance	 	183	 	(772	)	(170	)	
Effect of equity-related transactions	 	(49	)	22	 	13	 	
Tax settlements(1)	 	(25	)	—	 	—	 	
Merger-related costs	 	(15	)	24	 	—	 	
Merger-related write-off of NOL and state and local income tax provision, net of federal income taxes	 	(3	)	168	 	—	 	
Merger-related write-off of NOL and other deferred tax assets	 	(21	)	748	 	—	 	
Reorganization adjustments	 	—	 	2	 	(21	)	
Excess tax deductions related to bankruptcy transactions	 	—	 	—	 	(17	)	
Gain on bargain purchase, as retroactively amended	 	—	 	(117	)	—	 	
Other differences, net	 	4	 	3	 	1	 	
Tax provision (benefit)	 	$	—	 	$	(2	)	$	12	 	

(1)                                Settlements of tax disputes increased our tax basis in depreciable assets that had previously been written off as a result of Mirant’s emergence from bankruptcy in 2006.
 
F-49

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
7. Income Taxes (Continued)
 
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and their respective tax bases which give rise to deferred tax assets and liabilities are as follows:
 
 	 	December 31,	 	
 	 	2011	 	2010	 	
 	 	(in millions)	 	
Deferred Tax Assets:	 	 	 	 	 	
Employee benefits	 	$	185	 	$	146	 	
Contingencies and other liabilities	 	64	 	29	 	
Loss carryforwards	 	1,209	 	928	 	
Property and intangible assets	 	537	 	572	 	
Out-of-market contracts fair value adjustment	 	160	 	178	 	
Other	 	31	 	79	 	
Subtotal	 	2,186	 	1,932	 	
Valuation allowance(1)	 	(1,819	)	(1,636	)	
Net deferred tax assets	 	367	 	296	 	
Deferred Tax Liabilities:	 	 	 	 	 	
Derivative contracts	 	(339	)	(269	)	
Other	 	(28	)	(27	)	
Net deferred tax liabilities	 	(367	)	(296	)	
Net deferred taxes(1)	 	$	—	 	$	—	 	

(1)                                We acquired $1.309 billion of NOLs and other net deferred tax assets, before a complete offset by valuation allowances, of RRI Energy as a result of the Merger.
 
NOLs
 
As of the Merger, each of Mirant and RRI Energy had separately determined whether or not it had experienced an ownership change as defined in IRC § 382. IRC § 382 provides, in general, that an ownership change occurs when there is a greater than 50-percentage point increase in ownership of a company’s stock by new or existing stockholders who own (or are deemed to own under IRC § 382) 5% or more of the loss company’s stock over a three year testing period. IRC § 382 limits the amount of pre-merger NOLs that can be used during any post-ownership change year to offset taxable income. Based on information contained in a shareholder’s recent filing made pursuant to SEC Regulation 13G and subsequent inquiries made on the basis of such information, it is possible RRI Energy may have experienced an ownership change as defined above as a result of the Merger. As of this date, we have not completed verification of the change and we continue to seek “actual knowledge” with respect to certain facts pertaining to the possible ownership change. Should we determine that RRI  Energy had an ownership change at the Merger date, its NOLs would be substantially limited to reflect the requirements of IRC § 382. Prior to the Merger, RRI Energy received guidance from the Internal Revenue Service that specified the methodology to be used in determining whether an ownership change had occurred under circumstances when a stockholder owns interests in each of the merging
 
F-50

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
7. Income Taxes (Continued)
 
companies immediately prior to the Merger. Our initial analysis had concluded that sufficient overlapping stockholders of Mirant and RRI Energy existed immediately prior to the Merger such that the Merger did not cause an ownership change for RRI Energy. Therefore, RRI Energy’s pre-Merger NOLs were not adjusted for any IRC § 382 limitation as a result of the Merger. If RRI Energy had experienced an ownership change at the Merger date, the amount of future taxable income that may be offset by these limited NOLs would be approximately $47 million annually. Additionally, the write-off of federal and state NOLs at the Merger date would have been $585 million and $1.8 billion, respectively. These potential write-offs will not affect income tax expense as adjustments would be offset with a corresponding change in the valuation allowance.
 
Mirant had experienced an ownership change as a result of the Merger and we had reduced by $2.1 billion the amount of the Mirant federal NOLs that would have been available to offset post-merger taxable income based on a $54 million annual limit determined in accordance with IRC § 382. We also reduced our state NOLs by $2.5 billion for state jurisdictions that also follow IRC § 382.
 
At December 31, 2011, our federal NOL carryforward for financial reporting was $2.6 billion with expiration dates from 2022 to 2031. Similarly, there is an aggregate amount of $5.2 billion of state NOL carryforwards with various expiration dates (based on our review of the application of apportionment factors and other state tax limitations).
 
The guidance related to accounting for income taxes requires that a valuation allowance be established when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies.
 
At December 31, 2011, our deferred tax assets reduced by a valuation allowance are completely offset by our deferred tax liabilities. Objective positive evidence is necessary to support a conclusion that a valuation allowance is not needed for all or a portion of deferred tax assets when significant negative evidence exists. We evaluate this position quarterly and make our judgment based on the facts and circumstances at that time. We think that the realization of future taxable income sufficient to utilize existing deferred tax assets is less than more-likely-than-not at this time. The primary factors related to this conclusion are that prices for power and natural gas are low compared to several years ago and the effect of these lower prices on the projected gross margin and weak market conditions have resulted in a decrease in the forecasted gross margin of our generating facilities.
 
Tax Uncertainties
 
The recognition of contingent losses for tax uncertainties requires management to make significant assumptions about the expected outcomes of certain tax contingencies. Under the accounting guidance, we must reflect in our income tax provision the full benefit of all positions that will be taken in our income tax returns, except to the extent that such positions are uncertain and fall below the benefit recognition requirements. In the event that we determine that a tax position meets the uncertainty
 
F-51

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
7. Income Taxes (Continued)
 
criteria, an additional liability or an adjustment to our NOLs, determined under the measurement criteria, will result. We periodically reassess the tax positions in our tax returns for open years based on the latest information available and determine whether any portion of the tax benefits reflected should be treated as unrecognized. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
 
 	 	2011	 	2010	 	
 	 	(in millions)	 	
Unrecognized tax benefits, January 1	 	$	7	 	$	12	 	
Decrease as a result of lapse in the statute of limitations	 	(3	)	—	 	
Increase (decrease) based on tax positions related to the prior years	 	1	 	(1	)	
Settlements	 	—	 	(1	)	
Decrease as a result of IRC § 382	 	—	 	(11	)	
Assumed in the Merger	 	—	 	8	 	
Unrecognized tax benefits, December 31	 	$	5	 	$	7	 	
 
The unrecognized tax benefits included the review of tax positions relating to open tax years beginning in 2002 and continuing to the present. Our major tax jurisdictions are the United States at the federal level and multiple state and local jurisdictions. For United States federal and state income taxes, tax years are open subsequent to 2001. However, both the federal and state NOL carryforwards from any closed year are subject to examination until the year that such NOL carryforwards are utilized and that utilization year is closed for audit. We reduced the unrecognized tax benefits during 2010 as a result of the ownership change, as defined in IRC § 382, resulting from the Merger. The ownership change resulted in the write-off of NOLs and the related write-off of the unrecognized tax benefits. We do not anticipate any significant changes in our unrecognized tax benefits over the next 12 months. We have not recognized any tax benefits for certain filing positions for which the outcome is uncertain and the effect is estimable.
 
Included in the unrecognized tax benefits balance at December 31, 2011 and 2010, we had $4 million and $5 million, respectively, of unrecognized tax benefits that would affect the effective tax rate if they were recognized. Our tax provision in each period includes an insignificant amount for interest and penalties related to unrecognized tax benefits. The amounts recorded in our consolidated balance sheet for interest and penalties related to the unrecognized tax benefits at December 31, 2011 and 2010 are $3 million.
 
We continue to be under audit for multiple years by taxing authorities in various jurisdictions. Considerable judgment is required to determine the tax treatment of particular items that involve interpretations of complex tax laws. A tax liability is recorded for filing positions with respect to which the outcome is uncertain and the recognition criteria under the accounting guidance for uncertainty in income taxes has been met. Such liabilities are based on judgment and it can take many years to resolve a recorded liability such that the related filing position is no longer subject to question. We have not recorded a liability for those proposed tax adjustments related to the current tax audits when we continue to think our filing position meets the more-likely-than-not threshold prescribed in the accounting guidance related to accounting for uncertainty in income taxes. Any adverse outcomes arising from these matters could result in a material change in the amount of our deferred taxes.
 
F-52

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
7. Income Taxes (Continued)
 
We ceased being a member of the CenterPoint consolidated tax group at September 30, 2002 and could be limited in our ability to use tax attributes generated during periods through that date. The Internal Revenue Service’s audits of CenterPoint’s federal income tax returns for the 1997 to 2002 tax reporting periods have been closed, subject to a review by the Internal Revenue Service of certain claims formally submitted by us for the 2002 tax year. We have a tax allocation agreement that addresses the allocation of taxes pertaining to our separation from CenterPoint. This agreement provides that we may carry back net operating losses generated subsequent to September 30, 2002 to tax years when we were part of CenterPoint’s consolidated tax group. Any such carryback is subject to CenterPoint’s consent and any existing statutory carryback limitations. For items relating to periods prior to September 30, 2002, we will (a) recognize any net costs incurred by CenterPoint for settlement of temporary differences up to $15 million (of which zero had been recognized through December 31, 2011 and 2010) as an equity contribution and (b) recognize any net benefits realized by CenterPoint for settlement of temporary differences up to $1 million as an equity distribution. Generally, amounts for temporary differences in excess of the $15 million and $1 million thresholds will be settled in cash between us and CenterPoint. Pursuant to this agreement, generally, taxes related to permanent differences are the responsibility of CenterPoint.
 
8. Employee Benefit Plans
 
Pension and Other Postretirement Benefit Plans
 
Benefit Plans
 
We provide pension benefits to our eligible non-union and union employees through various defined benefit pension plans. These benefits are based on pay, service history and age at retirement. Most pension benefits are provided through tax-qualified plans that are funded in accordance with the Employee Retirement Income Security Act of 1974 and Internal Revenue Service requirements. Certain executive pension benefits that cannot be provided by the tax-qualified plans are provided through unfunded non-tax-qualified plans. The measurement date for the defined benefit plans was December 31 for all periods presented.
 
We also provide certain medical care and life insurance benefits for eligible retired employees. The measurement date for these postretirement benefit plans was December 31 for all periods presented.
 
F-53

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
8. Employee Benefit Plans (Continued)
 
The following table shows the benefit obligations and funded status for the defined benefit pension and other postretirement benefit plans:
 
 	 	Tax-Qualified
Pension Plans	 	Non-Tax-
Qualified
Pension Plans	 	Other
Postretirement
Benefit Plans	 	
 	 	2011	 	2010	 	2011	 	2010	 	2011	 	2010	 	
 	 	(in millions)	 	
Change in benefit obligation:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Benefit obligation, January 1	 	$	448	 	$	291	 	$	10	 	$	9	 	$	78	 	$	57	 	
Obligations assumed in the Merger	 	—	 	129	 	—	 	—	 	—	 	68	 	
Service cost	 	12	 	8	 	—	 	—	 	1	 	1	 	
Interest cost	 	23	 	17	 	—	 	1	 	3	 	2	 	
Benefits paid	 	(16	)	(11	)	(1	)	(1	)	(7	)	(1	)	
Actuarial (gain) loss	 	59	 	14	 	1	 	1	 	7	 	(1	)	
Participant contributions	 	—	 	—	 	—	 	—	 	2	 	—	 	
Curtailments	 	(3	)	—	 	—	 	—	 	—	 	(48	)	
Benefit obligation, December 31	 	$	523	 	$	448	 	$	10	 	$	10	 	$	84	 	$	78	 	
Change in plan assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets, January 1	 	$	359	 	$	240	 	$	—	 	$	—	 	$	—	 	$	—	 	
Assets acquired in the Merger	 	—	 	92	 	—	 	—	 	—	 	—	 	
Return on plan assets	 	5	 	37	 	—	 	—	 	—	 	—	 	
Employer contributions	 	5	 	1	 	1	 	1	 	5	 	2	 	
Benefits paid	 	(16	)	(11	)	(1	)	(1	)	(7	)	(2	)	
Participant contributions	 	—	 	—	 	—	 	—	 	2	 	—	 	
Fair value of plan assets, December 31	 	$	353	 	$	359	 	$	—	 	$	—	 	$	—	 	$	—	 	
Funded Status:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Underfunded at measurement date	 	$	(170	)	$	(89	)	$	(10	)	$	(10	)	$	(84	)	$	(78	)	
 
Amounts recognized in the consolidated balance sheets for pensions and other postretirement benefit plan obligations at December 31, 2011 and 2010 are:
 
 	 	Tax-Qualified
Pension Plans	 	Non-Tax
Qualified
Pension Plans	 	Other
Postretirement
Benefit Plans	 	
 	 	2011	 	2010	 	2011	 	2010	 	2011	 	2010	 	
 	 	(in millions)	 	
Current liabilities	 	$	—	 	$	—	 	$	(1	)	$	(1	)	$	(6	)	$	(5	)	
Noncurrent liabilities	 	(170	)	(89	)	(9	)	(9	)	(78	)	(73	)	
Total liabilities	 	$	(170	)	$	(89	)	$	(10	)	$	(10	)	$	(84	)	$	(78	)	
 
The accumulated benefit obligation exceeded the fair value of plan assets at December 31, 2011 and 2010 for the tax qualified pension plans. The total accumulated benefit obligation for the tax qualified plan at December 31, 2011 and 2010 was $480 million and $413 million, respectively.
 
F-54

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
8. Employee Benefit Plans (Continued)
 
Amounts recognized in other comprehensive income (loss) and accumulated other comprehensive income (loss) for the defined benefit pension and other postretirement benefit plans are:
 
 	 	Tax-Qualified
Pension Plans	 	Non-Tax-Qualified
Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	Net
(Loss) Gain	 	Prior
Service
(Cost) Credit	 	Net
Loss	 	Prior
Service
(Cost) Credit	 	Net
(Loss) Gain	 	Prior Service
(Cost)
Credit	 	
 	 	(in millions)	 	
Balance, December 31, 2009	 	$	(59	)	$	(3	)	$	(1	)	$	(2	)	$	(10	)	$	23	 	
Deferred Benefits	 	—	 	—	 	(1	)	1	 	14	 	(2	)	
Amortization	 	1	 	—	 	—	 	—	 	(1	)	(6	)	
Total amount recognized in other comprehensive loss	 	1	 	—	 	(1	)	1	 	13	 	(8	)	
Balance, December 31, 2010	 	$	(58	)	$	(3	)	$	(2	)	$	(1	)	$	3	 	$	15	 	
Deferred Benefits	 	(81	)	—	 	(1	)	—	 	(6	)	(1	)	
Amortization	 	3	 	1	 	—	 	—	 	—	 	(4	)	
Total amount recognized in other comprehensive loss	 	(78	)	1	 	(1	)	—	 	(6	)	(5	)	
Balance, December 31, 2011	 	$	(136	)	$	(2	)	$	(3	)	$	(1	)	$	(3	)	$	10	 	
 
During the second quarter of 2010, we entered into a new collective bargaining agreement with our Mid-Atlantic employees represented by IBEW Local 1900. The new agreement includes a change to the postretirement healthcare benefit plan covering those union employees to eliminate employer-provided healthcare subsidies through a gradual phase-out. Subsidies for employees who retired prior to June 1, 2010, continued through December 31, 2010. The curtailment resulted in a remeasurement of the liability related to postretirement benefits for Mid-Atlantic union employees. In performing the remeasurement, we used an updated discount rate of 5.31% as compared to the discount rate of 5.62% used in our previous measurement at December 31, 2009, but did not adjust any other valuation assumptions as a result of the remeasurement. We recorded the effects of the plan curtailment during the second quarter of 2010 and recognized a reduction in other postretirement liabilities of $48 million and a decrease in accumulated other comprehensive loss of $11 million on the consolidated balance sheet and a gain of $37 million reflected as a reduction in operations and maintenance expense on the consolidated statement of operations. In addition, we recognized an increase of $3 million in our pension liability and in accumulated other comprehensive loss as a result of planned salary increases under the new collective bargaining agreement.
 
F-55

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
8. Employee Benefit Plans (Continued)
 
The components of the net periodic benefit cost (credit) of our pension and other postretirement benefit plans for 2011, 2010 and 2009, are:
 
 	 	Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	2011	 	2010	 	2009	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Service cost	 	$	12	 	$	8	 	$	8	 	$	1	 	$	1	 	$	2	 	
Interest cost	 	23	 	18	 	16	 	3	 	2	 	3	 	
Expected return of plan assets	 	(29	)	(23	)	(22	)	—	 	—	 	—	 	
Net amortization(1)	 	4	 	1	 	2	 	(4	)	(7	)	(5	)	
Curtailments	 	—	 	—	 	—	 	—	 	(37	)	—	 	
Net periodic benefit cost (credit)	 	$	10	 	$	4	 	$	4	 	$	—	 	$	(41	)	$	—	 	

(1)                                Net amortization amount includes prior service cost and actuarial gains or losses.
 
The resulting total amount recognized of (income) loss in net periodic benefit cost and other comprehensive income/loss for the pension plans during 2011, 2010 and 2009 was $88 million, $3 million and $(30) million, respectively. The resulting total amount recognized of (income) loss in net periodic benefit cost and other comprehensive income/loss for the other postretirement benefit plans during 2011, 2010 and 2009 was $11 million, $(46) million and $(3) million, respectively.
 
The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost during 2012 are $8 million and $1 million, respectively.
 
The estimated net loss and prior service credit for other postretirement benefit plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost during 2012 are an insignificant amount and $4 million, respectively.
 
Assumptions
 
The discount rates used at December 31, 2011 and 2010, were determined based on individual bond-matching models comprised of portfolios of high quality corporate bonds with projected cash flows and maturity dates reflecting the expected time horizon during which that benefit will be paid. Bonds included in the model portfolios are from a cross-section of different issuers, are AA-rated or better, and are non-callable so that the yield to maturity can be attained without intervening calls.
 
F-56

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
8. Employee Benefit Plans (Continued)
 
The weighted average assumptions used for measuring year-end pension and other postretirement benefit plan obligations are:
 
 	 	Pension Plan	 	Other
Postretirement
Benefit Plans	 	
 	 	2011	 	2010	 	2011	 	2010	 	
Discount rate	 	4.56	%	5.12	%	4.26	%	4.80	%	
Rate of compensation increase	 	2.79	%	2.81	%	N/A	 	3.00	%	
 
Our assumed healthcare cost trend rates used for measuring year-end other postretirement benefit plan obligations are:
 
 	 	2011	 	2010	 	
Assumed medical inflation for next year:	 	 	 	 	 	
Before age 65	 	7.50	%	8.00	%	
Age 65 and after	 	7.71	%	8.20	%	
Assumed ultimate medical inflation rate	 	5.50	%	5.50	%	
Year in which ultimate rate is reached	 	2018	 	2018	 	
 
An annual increase or decrease of 1% in the assumed medical care cost trend rate would correspondingly increase or decrease the total accumulated benefit obligation of other postretirement benefit plans at December 31, 2011, by $7 million.
 
The weighted average assumptions used for our pension benefit cost and other postretirement benefit costs during each year were as follows:
 
 	 	Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	2011	 	2010	 	2009	 	2011	 	2010	 	2009	 	
Discount rate	 	5.12	%	5.36	%	5.40	%	4.80	%	5.03	%	5.37	%	
Rate of compensation increase	 	2.81	%	2.98	%	3.37	%	3.00	%	3.23	%	3.00	%	
Expected long-term rate of return on plan assets	 	8.25	%	8.20	%	8.50	%	N/A	 	N/A	 	N/A	 	
 
In determining the long-term rate of return for plan assets, we evaluate historic and current market factors such as inflation and interest rates before determining long-term capital market assumptions. We also consider the effects of diversification and portfolio rebalancing. To check for reasonableness and appropriateness, we review data about other companies, including their historic returns.
 
For purposes of expense recognition, we use a market-related value of assets that recognizes the difference between the expected return and the actual return on plan assets over a five-year period. Unrecognized asset gains or losses associated with our plan assets will be recognized in the calculation of the market-related value of assets and subject to amortization in future periods.
 
F-57

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
8. Employee Benefit Plans (Continued)
 
Our assumed healthcare cost trend rates used to measure the expected cost of benefits covered by our other postretirement plan are:
 
 	 	2011	 	2010	 	2009	 	
Assumed medical inflation for next year:	 	 	 	 	 	 	 	
Before age 65	 	8.00	%	8.40	%	8.50	%	
Age 65 and after	 	8.20	%	8.20	%	8.50	%	
Assumed ultimate medical inflation rate	 	5.50	%	5.30	%	5.00	%	
Year in which ultimate rate is reached	 	2018	 	2017	 	2018	 	
 
An annual increase or decrease of 1% in the assumed medical care cost trend rate would correspondingly increase or decrease the aggregate of the service and interest cost components of the annual other postretirement benefit cost during 2011 by $1 million.
 
Pension Plan Assets
 
Pension plans’ assets are managed solely in the interest of the plans’ participants and their beneficiaries and are invested with the objective of earning the necessary returns to meet the time horizons of the accumulated and projected retirement benefit obligations. We use a mix of equities and fixed income investments intended to manage risk to a reasonable and prudent level. Our risk tolerance is established through consideration of the plans’ liabilities and funded status as well as corporate financial condition. Equity investments are diversified across United States and non-United States stocks. For United States stocks, we employ both a passive and active approach by investing in index funds and actively managed funds. For non-United States stocks, we are invested in both developed and emerging market equity funds. Fixed income investments are comprised of long-term United States government and corporate securities. Derivative securities can be used for diversification, risk-control and return enhancement purposes but may not be used for the purpose of leverage.
 
In the fourth quarter of 2011, we adopted a new pension asset allocation methodology based on the results of a study completed by a third-party investment consulting firm. The methodology divides the pension plan assets into two primary portfolios: (a) return seeking assets, those assets intended to generate returns in excess of pension liability growth (United States and Non-United States equities) and (b) liability-hedging assets, those assets intended to have characteristics similar to pension liabilities (fixed income securities). As our pension plans’ funded status improves, the methodology actively moves the plan assets from return seeking assets toward liability-hedging assets. The following table shows the target allocations for our plans and the percentage of fair value of plan assets by asset fund
 
F-58

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
8. Employee Benefit Plans (Continued)
 
category (based on the nature of the underlying funds) for our qualified pension plans at December 31, 2011 and 2010:
 
 	 	Target	 	Percentage of
Fair Value of
Plan Assets at
December 31,	 	
 	 	Allocations	 	2011	 	2010	 	
United States equities	 	42	%	42	%	46	%	
Non-United States equities	 	28	 	27	 	24	 	
Fixed income securities	 	30	 	29	 	29	 	
Cash	 	—	 	2	 	1	 	
Total	 	100	%	100	%	100	%	
 
Investment risk and performance are monitored on an ongoing basis through quarterly portfolio reviews of each asset fund class to a related performance benchmark, if applicable, and annual pension liability measurements. Performance benchmarks adopted in the fourth quarter of 2011 are composed of the following indices:
 
Asset Class	 	Index	
United States equities	 	Dow Jones U.S. Total Stock Market Index	
Non-United States equities	 	MSCI All Country World Ex-U.S. IMI Index	
Fixed income securities	 	Barclays Capital Long Term Government/Credit Index	
 
Fair Value Hierarchy of Plan Assets
 
We are required to classify the fair value measurements of plan assets according to the fair value hierarchy. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values based on the observability of the inputs used in the valuation techniques for a fair value measurement. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Our assets are classified within Level 1 and Level 2 of the fair value hierarchy. Our plan assets classified within Level 1 consist of exchange-traded investment funds with readily observable prices. Our plan assets classified within Level 2 consist of non-exchange-traded investment funds whose fair values reflect the net asset value of the funds based on the fair value of the fund’s underlying securities. The underlying securities held by these funds are valued using quoted prices in active markets for identical or similar assets. We elected the practical expedient under the accounting guidance to measure the fair value of certain funds that use net asset value per share. Certain investment funds require redemption notification of 30 days or less for which no adjustment was made to their net asset value.
 
F-59

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
8. Employee Benefit Plans (Continued)
 
The following table presents plan assets measured at fair value at December 31, 2011, by category (based on the nature of the underlying funds):
 
 	 	Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)	 	Significant
Other
Observable
Inputs
(Level 2)	 	Significant
Other
Unobservable
Inputs
(Level 3)	 	Total	 	
 	 	(in millions)	 	
Asset Categories:	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	7	 	$	—	 	$	—	 	$	7	 	
Investment Funds:	 	 	 	 	 	 	 	 	 	
United States equities(1)	 	23	 	127	 	—	 	150	 	
Non-United States equities(2)	 	20	 	74	 	—	 	94	 	
Fixed income securities(3)	 	30	 	72	 	—	 	102	 	
Total	 	$	80	 	$	273	 	$	—	 	$	353	 	

(1)                                Comprised of multi-cap stocks.
 
(2)                                Comprised of large-cap stocks (approximately 50%) and multi-cap stocks (approximately 50%).
 
(3)                                Comprised primarily of U.S. corporate bonds (approximately 50%) and U.S. government bonds (approximately 50%).
 
The following table presents plan assets measured at fair value at December 31, 2010 by category (based on the nature of the underlying funds):
 
 	 	Quoted Prices in
Active Markets
for Identical
Assets
(Level 1)	 	Significant
Other
Observable
Inputs
(Level 2)	 	Significant
Other
Unobservable
Inputs
(Level 3)	 	Total	 	
 	 	(in millions)	 	
Asset Categories:	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	1	 	$	2	 	$	—	 	$	3	 	
Investment Funds:	 	 	 	 	 	 	 	 	 	
United States equities(1)	 	76	 	90	 	—	 	166	 	
Non-United States equities(2)	 	66	 	20	 	—	 	86	 	
Fixed income securities(3)	 	27	 	77	 	—	 	104	 	
Total	 	$	170	 	$	189	 	$	—	 	$	359	 	

(1)                                Comprised of large-cap stocks (approximately 75%) and small-cap stocks (approximately 25%).
 
(2)                                Comprised of large-cap stocks (approximately 75%) and multi-cap stocks (approximately 25%).
 
(3)                                Comprised primarily of U.S. corporate bonds (approximately 50%) and U.S. government bonds (approximately 50%).
 
F-60

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
8. Employee Benefit Plans (Continued)
 
We expect to contribute approximately $24 million to the tax-qualified pension plans during 2012. In addition, we expect to contribute approximately $1 million to the non-tax-qualified pension plans during 2012. As of December 31, 2011, we have related rabbi trust investments of $13 million to fund future benefit payments of the non-tax-qualified pension plans.
 
We expect the following benefits to be paid from the pension and other postretirement benefit plans:
 
 	 	Pension Plans	 	Other Postretirement
Benefits Plans	 	
 	 	Tax-
Qualified	 	Non-Tax
Qualified	 	Before Medicare
Subsidy	 	After Medicare
Subsidy	 	
 	 	(in millions)	 	
2012	 	$	18	 	$	1	 	$	6	 	$	6	 	
2013	 	21	 	1	 	6	 	6	 	
2014	 	22	 	1	 	6	 	6	 	
2015	 	24	 	1	 	7	 	7	 	
2016	 	27	 	1	 	6	 	6	 	
2017 through 2021	 	171	 	3	 	29	 	28	 	

Employee Savings and Profit Sharing Plan
 
We have employee savings plans under Sections 401(a) and 401(k) of the IRC whereby employees may contribute a portion of their base compensation to the employee savings plan, subject to limits under the IRC. Following the Merger, we provide a matching contribution each payroll period equal to 100% of the employee’s contribution up to 6% of the employee’s pay for that period. Prior to the Merger, we provided a matching contribution each payroll period equal to 75% of the employee’s contributions up to 6% of the employee’s pay for that period. For unionized employees, matching levels vary by bargaining unit.
 
We also provide for a profit sharing arrangement for non-union employees not accruing a benefit under the defined benefit pension plans, whereby we contribute a fixed contribution of 2% of eligible pay per pay period and may make an annual discretionary contribution up to 3% of eligible pay based on our performance. Prior to the Merger, our related contributions were 3% of eligible pay and we could make an annual discretionary contribution. Certain unionized employees are also eligible for the annual discretionary profit sharing contribution.
 
We also sponsor non-qualified deferred compensation plans for key and highly compensated employees. Our obligations under these plans were $31 million and $37 million and the related rabbi trust investments were $31 million and $38 million at December 31, 2011 and 2010, respectively.
 
Expense recognized for the matching, fixed profit sharing and discretionary profit sharing contributions during 2011, 2010 and 2009 were $30 million, $12 million and $10 million, respectively.
 
F-61

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
8. Employee Benefit Plans (Continued)
 
Immaterial Misstatement of Post-Employment Benefits in Prior Periods
 
During 2011, we identified an under accrual of post-employment benefits relating to over ten years up to and through 2010. In those years, we did not recognize a liability for future expected costs of benefits for inactive employees who were unable to perform services because of a disability. For 2010, 2009, 2008 and 2007, our operations and maintenance expense was understated by $0, $1 million, $1 million and $1 million, respectively. Our net income/loss for these years was misstated by the same amounts. The misstatements had no effect on cash flows for any of the periods.
 
To correct the misstatement in 2010, we recorded the following immaterial adjustments to the 2010 financial statements presented in this Form 10-K: (a) a cumulative increase to accumulated deficit and decrease to stockholders’ equity of $13 million in the consolidated balance sheet and consolidated statement of stockholders’ equity and comprehensive income (loss) at December 31, 2010 and (b) a cumulative increase to other long-term liabilities and total noncurrent liabilities of $13 million in the consolidated balance sheet at December 31, 2010. To correct the misstatement in 2009, we recorded the following immaterial adjustments to the 2009 financial statements presented in this Form 10-K: (a) a cumulative increase to accumulated deficit and decrease to stockholders’ equity of $13 million in the consolidated statements of stockholders’ equity and comprehensive income (loss) at December 31, 2009 and (b) an increase to operations and maintenance expense and a decrease to net income of $1 million in the consolidated statement of operations in 2009. To correct the cumulative misstatements prior to 2009, we recorded the following immaterial adjustment to the 2008 financial statements presented in this Form 10-K: a cumulative increase to accumulated deficit and decrease to stockholders’ equity of $12 million in the consolidated statements of stockholders’ equity and comprehensive income (loss) at December 31, 2008.
 
9. Stock-Based Compensation
 
Overview.  As of the date of the Merger, the GenOn Energy, Inc. 2010 Omnibus Incentive Plan became effective and permits us to grant various stock-based compensation awards to employees, consultants and directors. We terminated the GenOn Energy, Inc. 2002 Stock Plan, the GenOn Energy, Inc. 2002 Long-Term Incentive Plan, the Long-Term Incentive Plan of GenOn Energy, Inc., the GenOn Energy, Inc. Transition Stock Plan and the Mirant Corporation 2005 Omnibus Incentive Compensation Plan. Outstanding awards under the terminated plans remain subject to the terms and conditions of the applicable plans.
 
The GenOn Energy, Inc. 2010 Omnibus Incentive Plan provides for the granting of nonqualified stock options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards, other stock-based awards and non-employee director awards.
 
At December 31, 2011, 48 million shares are authorized for issuance to participants. Shares covered by an award are counted as used only to the extent that they are actually issued. Any shares related to awards that terminate by expiration, forfeiture, cancellation or otherwise without the issuance of such shares will be available again for grant under the stock-based compensation plan. We utilize both service condition and performance condition forms of stock-based compensation. We have generally issued new shares when stock options are exercised and for other equity-based awards.
 
F-62

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
9. Stock-Based Compensation (Continued)
 
Summary.  We recognize compensation expense in operations and maintenance expense in the consolidated statements of operations related to stock-based compensation. Compensation expense during 2011, 2010 and 2009 was as follows:
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Compensation expense from accelerated vesting of Mirant’s stock-based compensation awards upon closing of the Merger	 	$	—	 	$	24	 	$	—	 	
Service and performance condition stock-based compensation expense	 	14	 	16	 	24	 	
Modification expense(1)	 	—	 	1	 	—	 	
Total compensation expense (pre-tax)	 	$	14	 	$	41	 	$	24	 	
Income tax effect (includes effect of the valuation allowance)	 	$	—	 	$	—	 	$	—	 	

(1)                                 Represents modification expense for the vested stock options for Edward R. Muller, Chairman and Chief Executive Officer, which were modified such that the exercise period for the awards coincides with the expiration date.
 
At December 31, 2011, there was $15 million of total unrecognized compensation cost related to non-vested share-based compensation granted through service condition and performance condition awards, which is expected to be recognized on a straight-line basis over a weighted average period of approximately two years.
 
Effects of Merger.  Upon completion of the Merger, the following occurred to Mirant’s stock-based incentive awards:
 
·                 all outstanding Mirant stock options vested, converted into options covering GenOn common stock (with the number of shares subject to such options and the per share exercise price appropriately adjusted based on the Exchange Ratio) and remain outstanding, subject to the same terms and conditions as otherwise applied prior to the Merger; and
 
·                 restricted stock units vested in full, settled in Mirant common stock and converted into GenOn common stock based on the Exchange Ratio (with cash paid in lieu of fractional shares).
 
As appropriate, all share-based amounts disclosed herein have been adjusted for the Exchange Ratio. The amount of compensation cost recognized immediately upon the close of the Merger in our post-merger consolidated results of operations was $24 million from the accelerated vesting of Mirant’s stock options and restricted stock units as a result of the change in control triggered by the Merger.
 
Upon completion of the Merger, the following occurred to RRI Energy’s stock-based incentive awards:
 
·                 stock options vested in full, converted into options covering GenOn common stock and remain outstanding subject to the same terms and conditions as otherwise applied prior to the Merger;
 
·                 restricted stock units vested and settled in GenOn common stock; and
 
·                 cash units vested and settled in cash.
 
F-63

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
9. Stock-Based Compensation (Continued)
 
In the purchase price allocation for the Merger (see note 2), RRI Energy’s employee stock options and restricted stock units, which vested upon the close of the Merger, were measured and recorded at fair value resulting in an increase in additional paid-in capital of $10 million. In addition, in the purchase price allocation for the Merger, we recorded a liability of $6 million for RRI Energy’s cash units which vested upon the close of the Merger.
 
Upon completion of the Merger, Edward R. Muller, Chairman and Chief Executive Officer, was granted an award of restricted stock units with a value equal to two times the sum of his annual base salary and target bonus, which will vest in two equal installments on the first and second anniversaries of completion of the Merger.
 
In addition, upon completion of the Merger, Mark M. Jacobs, our former President and Chief Operating Officer, was granted an award of restricted stock units with a value equal to two times his annual base salary and target bonus, which were to vest in two equal installments on the first and second anniversaries of completion of the Merger. On August 24, 2011, Mark M. Jacobs resigned as President and Chief Operating Officer and a member of the Board of Directors of GenOn Energy. In connection with his resignation, Mark M. Jacobs will receive in 2012 an allocation of the unvested restricted stock units prorated for the time he was employed in 2011. The remainder of the unvested award was forfeited in 2011. See note 2 for further information regarding the Merger.
 
During 2011, we granted long-term incentive awards as follows:
 
Award Vehicle	 	Awards Granted	 	Vesting Period	 	
Time-based Restricted Stock Units	 	2,289,657	 	Vest ratably each year over a three-year period; settled in common stock	 	
Performance-based Restricted Stock Units	 	1,841,923	 	Linked to the 2011 short-term incentive plan performance goals, with performance measured at the end of the first year to determine a multiplier between 0% and 200% of the targeted grant; vest ratably each year over three-year period; settled in common stock	 	
Nonqualified Stock Options	 	4,190,711	 	Time-based; vest ratably each year over three-year period	 	
 
F-64

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
9. Stock-Based Compensation (Continued)
 
Stock Options
 
We grant service condition stock option awards to certain employees. Historically, stock options vested 33.33% per year for the three years and have a term of five to ten years. The fair value of stock options is estimated on the grant date using a Black-Scholes option-pricing model based on the assumptions noted in the following table.
 
 	 	2011	 	2010	 	2009	 	
 	 	Range	 	Weighted
Average	 	Range	 	Weighted
Average	 	Range	 	Weighted
Average	 	
Expected volatility(1)	 	45 - 55	%	47.2	%	39.3	%	39.3	%	48 - 59	%	58.9	%	
Expected dividends	 	—	%	—	%	—	%	—	%	—	%	—	%	
Expected term for service condition awards(2)	 	5 years	 	5 years	 	6 years	 	6 years	 	6 years	 	6 years	 	
Risk-free rate(3)	 	1.0 - 2.2%	 	2.1	%	3.1	%	3.1	%	2.6 - 2.9%	 	2.6	%	

(1)                                 After the Merger, we estimate volatility based on historical and implied volatility of our common stock after the Merger date and Mirant and RRI Energy common stock prior to the Merger date. Prior to the Merger, we utilized our own implied volatility of our traded options.
 
(2)                                 After the Merger, the expected term is based on a binomial lattice model. Prior to the Merger, as a result of the lack of exercise history for Mirant, the simplified method for estimating expected term was used in accordance with the accounting guidance related to share-based payments.
 
(3)                                 The risk-free rate for periods within the contractual term of the stock option is based on the United States Treasury yield curve in effect at the time of the grant.
 
Summarized stock options activity is:
 
 	 	2011	 	
 	 	Number
of Shares	 	Weighted
Average
Exercise Price	 	Weighted
Average
Remaining
Contractual
Term
(years)	 	Aggregate
Intrinsic
Value
(in millions)	 	
Stock Options	 	 	 	 	 	 	 	 	 	
Outstanding at January 1	 	17,968,143	 	$	9.19	 	4.7	 	$	1	 	
Granted	 	4,190,711	 	$	3.81	 	 	 	 	 	
Exercised	 	(836,790	)	$	3.66	 	 	 	 	 	
Forfeited	 	(500,114	)	$	3.81	 	 	 	 	 	
Expired	 	(6,432,526	)	$	11.95	 	 	 	 	 	
Outstanding at December 31	 	14,389,424	 	$	6.89	 	5.4	 	$	—	 	
Exercisable at December 31, 2011	 	10,932,701	 	$	7.86	 	4.2	 	$	—	 	
 
F-65

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
9. Stock-Based Compensation (Continued)
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions, except
per unit amounts)	 	
Weighted average grant date fair value of the stock options granted	 	$	1.68	 	$	1.99	 	$	2.08	 	
Proceeds from exercise of stock options	 	3	 	1	 	—	 	
Intrinsic value of exercised stock options	 	—	 	—	 	—	 	
Tax benefits realized	 	—	(1)	—	(1)	—	(1)	

(1)                                 None realized as a result of our net operating loss carryforwards.
 
Time-based Restricted Stock Units and Performance-based Restricted Stock Units
 
Time-based Awards.  We grant time-based restricted stock units to certain employees. These restricted stock units generally vest in three equal installments on each of the first, second and third anniversaries of the grant date. In addition, we grant time-based restricted stock units to non-management members of the Board of Directors. These awards vest on the grant date and delivery of the underlying shares is deferred until the directorship terminates. During 2011, we granted 2.3 million time-based restricted stock units.
 
In addition, upon the completion of the Merger, we granted Edward R. Muller, Chairman and Chief Executive Officer, and Mark M. Jacobs, our former President and Chief Operating Officer, an award of restricted stock units to vest in two equal installments on the first and second anniversaries of completion of the Merger, as further described above.
 
Performance-based Awards.  In 2011, we granted 1.8 million performance-based restricted stock units to certain employees. These restricted stock units are linked to the 2011 short-term incentive plan performance goals, with performance measured at the end of the first year to determine a multiplier between 0% and 200% of the targeted grant. These restricted stock units vest in three equal installments on each of the first, second and third anniversaries of the grant date. In February 2012, the performance multiplier was determined to be 174%.
 
General.  The grant date fair value of time-based based and performance-based restricted stock units is equal to our closing stock price on the grant date.
 
F-66

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
9. Stock-Based Compensation (Continued)
 
Summarized time-based and performance-based restricted stock units activity is:
 
 	 	2011	 	
 	 	Number
of Shares	 	Weighted
Average
Grant
Date Fair
Value	 	
Outstanding at January 1	 	2,242,532	 	$	3.67	 	
Granted	 	4,131,580	 	$	3.81	 	
Performance factor adjustments	 	1,124,239	 	$	3.81	 	
Vested	 	(106,589	)	$	7.18	 	
Forfeited	 	(966,446	)	$	3.70	 	
Outstanding at December 31	 	6,425,316	 	$	3.79	 	
Weighted average period over which the nonvested restricted stock units is expected to be recognized	 	2 years	 	 	 	
Aggregate intrinsic value of nonvested restricted stock units (in millions)	 	$	16.8	 	 	 	

 	 	2011	 	2010	 	2009	 	
 	 	(in millions, except
per unit amounts)	 	
Weighted average grant date fair value of restricted stock units granted	 	$	3.81	 	$	4.22	 	$	3.72	 	
Fair value of vested restricted stock units	 	—	 	27	 	7	 	

10. Commitments and Contingencies
 
We have made firm commitments to buy materials and services in connection with our ongoing operations and have provided cash collateral or financial guarantees relative to some of our investments.
 
F-67

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
10. Commitments and Contingencies (Continued)
 
(a) Commitments.
 
In addition to debt and other obligations in the consolidated balance sheets, we have the following annual commitments under various agreements at December 31, 2011, related to our operations:
 
 	 	Off-Balance Sheet Arrangements and Contractual
Obligations by Year	 	
 	 	Total	 	2012	 	2013	 	2014	 	2015	 	2016	 	>5 Years	 	
 	 	(in millions)	 	
GenOn Mid-Atlantic operating leases	 	$	1,596	 	$	132	 	$	138	 	$	131	 	$	110	 	$	150	 	$	935	 	
REMA operating leases	 	818	 	56	 	64	 	64	 	56	 	61	 	517	 	
Other operating leases	 	161	 	35	 	25	 	20	 	19	 	19	 	43	 	
Fuel commitments	 	942	 	636	 	275	 	31	 	—	 	—	 	—	 	
Commodity transportation commitments	 	533	 	68	 	56	 	59	 	61	 	61	 	228	 	
LTSA commitments	 	549	 	23	 	19	 	23	 	19	 	22	 	443	 	
Maryland Healthy Air Act	 	83	 	83	 	—	 	—	 	—	 	—	 	—	 	
GenOn Marsh Landing	 	347	 	299	 	48	 	—	 	—	 	—	 	—	 	
Pension funding obligations	 	181	 	25	 	35	 	36	 	34	 	31	 	20	 	
Other	 	529	 	318	 	24	 	17	 	14	 	16	 	140	 	
Total commitments	 	$	5,739	 	$	1,675	 	$	684	 	$	381	 	$	313	 	$	360	 	$	2,326	 	
 
Our contractual obligations table does not include the derivative obligations reported at fair value (other than fuel supply commitments), which are discussed in note 4 and the asset retirement obligations, which are discussed in note 5.
 
GenOn Mid-Atlantic Operating Leases
 
GenOn Mid-Atlantic leases a 100% interest in both the Dickerson and Morgantown baseload units and associated property through 2029 and 2034, respectively. GenOn Mid-Atlantic has an option to extend the leases. Any extensions of the respective leases would be for less than 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. We are accounting for these leases as operating leases and recognize rent expense on a straight-line basis. Rent expense totaled $96 million during 2011, 2010 and 2009, and is included in operations and maintenance expense in the consolidated statements of operations. At December 31, 2011 and 2010, we have paid $482 million and $444 million, respectively, of lease payments in excess of rent expense recognized, which is recorded in prepaid rent on the consolidated balance sheets. Of these amounts, $96 million is included in prepaid rent on our consolidated balance sheets at December 31, 2011 and 2010.
 
At December 31, 2011, the total notional minimum lease payments for the remaining terms of the leases aggregated $1.6 billion and the aggregate termination value for the leases was $1.3 billion, which generally decreases over time. GenOn Mid-Atlantic leases the Dickerson and the Morgantown baseload units from third party owner lessors. These owner lessors each own undivided interests in these baseload generating facilities. The subsidiaries of the institutional investors who hold the membership interests in the owner lessors are called owner participants. Equity funding by the owner participants
 
F-68

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
10. Commitments and Contingencies (Continued)
 
plus transaction expenses paid by the owner participants totaled $299 million. The issuance and sale of pass through certificates raised the remaining $1.2 billion needed for the owner lessors to acquire the undivided interests.
 
The pass through certificates are not direct obligations of GenOn Mid-Atlantic. Each pass through certificate represents a fractional undivided interest in one of three pass through trusts formed pursuant to three separate pass through trust agreements between GenOn Mid-Atlantic and United States Bank National Association (as successor in interest to State Street Bank and Trust Company of Connecticut, National Association), as pass through trustee. The property of the pass through trusts consists of lessor notes. The lessor notes issued by an owner lessor are secured by that owner lessor’s undivided interest in the lease facilities and its rights under the related lease and other financing documents. For restrictions under these leases, see note 6.
 
REMA Operating Leases
 
REMA leases 16.45% and 16.67% interests in the Conemaugh and Keystone baseload facilities, respectively, through 2034 and expects to make payments through 2029. REMA also leases a 100% interest in the Shawville baseload facility through 2026 and expects to make payments through that date. At the expiration of these leases, there are several renewal options related to fair value. We are accounting for these leases as operating leases and recognize rent expense on a straight-line basis. Rent expense totaled $35 million and $3 million during 2011 and December 2010, respectively, and is included in operations and maintenance expense in the consolidated statements of operations. At December 31, 2011, we have paid $18 million of lease payments in excess of rent expense recognized, which is recorded in prepaid rent on the consolidated balance sheet. We operate the Conemaugh and Keystone facilities under five-year agreements that expire in December 2015 that, subject to certain provisions and notifications, could be terminated annually with one year’s notice. We are reimbursed by the other owners for the cost of direct services provided to the Conemaugh and Keystone facilities. Additionally, we received fees of $10 million and $1 million during 2011 and December 2010, respectively. The fees, which are recorded in operations and maintenance expense in the consolidated statements of operation, are primarily to cover REMA’s administrative support costs of providing these services.
 
At December 31, 2011, the total notional minimum lease payments for the remaining terms of the leases aggregated $818 million and the aggregate termination value for the leases was $735 million, which generally decreases over time. REMA leases the Conemaugh, Keystone and the Shawville facilities from third party owner lessors. These owner lessors each own undivided interests in these baseload facilities. Equity funding by the owner participants plus transaction expenses paid by the owner participants totaled $169 million. The issuance and sale of pass through certificates raised the remaining $851 million needed for the owner lessors to acquire the undivided interests.
 
The pass through certificates are not direct obligations of REMA. Each pass through certificate represents a fractional undivided interest in one of the pass through trusts formed pursuant to three separate pass through trust agreements between REMA and Deutsche Bank Trust Company Americas, as pass through trustee. The property of the pass through trusts consists of lessor notes. The lessor notes issued by an owner lessor are secured by that owner lessor’s undivided interest in the lease
 
F-69

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
10. Commitments and Contingencies (Continued)
 
facilities and its rights under the related lease and other financing documents. For restrictions under these leases, see note 6.
 
We have recently completed an analysis of the cost of environmental controls required for the Shawville facility, including the installation of cooling towers. After evaluation of the forecasted energy and capacity prices, expected capital expenditures, operating costs, property taxes and other factors, we concluded that the forecasted returns on investments necessary to comply with the environmental regulations are insufficient. Accordingly, we plan to place the coal-fired units at the Shawville facility, which is leased, in a long-term protective layup in April 2015. Under the lease agreement for Shawville, our obligations generally are to pay the required rent and to maintain the leased assets in accordance with the lease documentation, including in compliance with prudent competitive electric generating industry practice and applicable laws. We will continue to evaluate our options under the lease, including termination of the lease for economic obsolescence and/or keeping the facility in long-term protective layup during the term of the lease. We do not think that the lease documentation mandates that we operate the facility continuously and, so long as we are not operating it, we do not think that the installation of cooling towers, emissions controls and other expenditures would be required under the lease documentation. During the long-term protective layup of the Shawville facility, we would continue to pay the required rent and to maintain the facility as required by the lease. See note 17 for a discussion of other generating facilities that we expect to deactivate between 2012 and 2015.
 
Other Operating Leases
 
We have commitments under other operating leases with various terms and expiration dates. Included in other operating leases is a long-term lease for our corporate headquarters which expires in 2018. Amounts in the table exclude future sublease income of $30 million associated with this long-term lease. Other operating leases also include a tolling agreement on the Vandolah facility which entitles us to purchase and dispatch electric generating capacity and extends through May 2012. Rent expense totaled $20 million, $10 million and $9 million during 2011, 2010 and 2009, respectively, related to these operating leases.
 
Fuel and Commodity Transportation Commitments
 
We have commitments under coal agreements and commodity transportation contracts, primarily related to natural gas and coal, of various quantities and durations. At December 31, 2011, the maximum remaining term under any individual fuel supply contract is three years and any transportation contract is 13 years. In addition, for 2013, we have committed to purchase volumes of one million tons under certain coal contracts for which the contract prices are subject to negotiation and agreement prior to the beginning of each year and thus the amounts are not included in the table.
 
LTSA Commitments
 
LTSA commitments primarily relate to long-term service agreements that cover some periodic maintenance, including parts, on power generation turbines. The long-term maintenance agreements terminate from 2014 to 2038 based on turbine usage.
 
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GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
10. Commitments and Contingencies (Continued)
 
Maryland Healthy Air Act
 
Maryland Healthy Air Act commitments reflect the remaining expected payments for capital expenditures to comply with the limitations for SO 2 , NO x  and mercury emissions under the Maryland Healthy Air Act. We completed the installation of the remaining pollution control equipment related to compliance with the Maryland Healthy Air Act in the fourth quarter of 2009. However, provisions in our construction contracts provide that certain payments be made after final completion of the project. See note 16.
 
GenOn Marsh Landing
 
In May 2010, GenOn Marsh Landing entered into an EPC agreement with Kiewit for the construction of the Marsh Landing generating facility. Under the EPC agreement, Kiewit is to design and construct the Marsh Landing generating facility on a turnkey basis, including all engineering, procurement, construction, commissioning, training, start-up and testing. The lump sum cost of the EPC agreement is $505 million (including the $212 million total cost under the Siemens Turbine Generator Supply and Services Agreement which was assigned to Kiewit in connection with the execution of the EPC agreement), plus the reimbursement of California sales and use taxes due under the Siemens Turbine Generator Supply and Services Agreement.
 
Pension Funding Obligations
 
Pension funding obligations represent our estimated pension contributions based on assumptions that are subject to change. We have estimated projected funding requirements through 2021. See note 8.
 
Other
 
Other primarily represents the open purchase orders less invoices received related to general procurement of products and services purchased in the ordinary course of business. These include construction, maintenance and labor activities at our generating facilities. Other also includes liabilities related to accounting for uncertainty in income taxes and miscellaneous liabilities.
 
(b) Cash Collateral.
 
In order to sell power and purchase fuel in the forward markets and perform other energy trading and marketing activities, we are often required to provide trade credit support to our counterparties or make deposits with brokers. In addition, we are often required to provide cash collateral for access to the transmission grid to participate in power pools and for other operating activities. In the event of default, the counterparty can apply cash collateral held to satisfy the existing amounts outstanding under an open contract.
 
F-71

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2011, 2010 and 2009
 
10. Commitments and Contingencies (Continued)
 
The following is a summary of cash collateral posted with counterparties:
 
 	 	December 31,	 	
 	 	2011	 	2010	 	
 	 	(in millions)	 	
Cash collateral posted—energy trading and marketing	 	$	185	 	$	220	 	
Cash collateral posted—other operating activities	 	39	 	45	 	
Total	 	$	224	 	$	265	 	
 
(c) Guarantees.
 
We generally conduct our business through various operating subsidiaries, which enter into contracts as a routine part of their business activities. In certain instances, the contractual obligations of such subsidiaries are guaranteed by, or otherwise supported by, GenOn or another of its subsidiaries, including by letters of credit issued under the GenOn credit facilities.
 
In addition, GenOn and its subsidiaries enter into various contracts that include indemnification and guarantee provisions. Examples of these contracts include financing and lease arrangements, purchase and sale agreements, including for commodities, construction agreements and agreements with vendors. Although the primary obligation of GenOn or a subsidiary under such contracts is to pay money or render performance, such contracts may include obligations to indemnify the counterparty for damages arising from the breach thereof and, in certain instances, other existing or potential liabilities. In many cases, our maximum potential liability cannot be estimated because some of the underlying agreements contain no limits on potential liability.
 
Upon issuance or modification of a guarantee, we determine if the obligation is subject to initial recognition and measurement of a liability and/or disclosure of the nature and terms of the guarantee. Generally, guarantees of the performance of a third party are subject to the recognition and measurement, as well as the disclosure provisions, of the accounting guidance related to guarantees. Such guarantees must initially be recorded at fair value, as determined in accordance with the accounting guidance.
 
Alternatively, guarantees between and on behalf of entities under common control are subject only to the disclosure provisions of the accounting guidance related to guarantors’ accounting and disclosure requirements for guarantees. We must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.
 
Letters of Credit and Surety Bonds
 
At December 31, 2011, GenOn and its subsidiaries were contingently obligated for $265 million under letters of credit issued under the GenOn senior secured revolving credit facility. Most of these letters of credit are issued in support of the obligations of our subsidiaries to perform under commodity agreements, financing or lease agreements or other commercial arrangements. In the event of default, the counterparty can draw on a letter of credit to satisfy the existing amounts outstanding under an open contract. A majority of these letters of credit expire within one year of issuance, and it
 
F-72

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2011, 2010 and 2009
 
10. Commitments and Contingencies (Continued)
 
is typical for them to be renewed on similar terms. In addition, at December 31, 2011, GenOn Energy Holdings has issued $131 million of cash-collateralized letters of credit in support of the GenOn Marsh Landing project. GenOn Marsh Landing also entered into a credit agreement which includes a $50 million senior secured letter of credit facility to support GenOn Marsh Landing’s debt service reserve requirements and a $100 million senior secured letter of credit facility to support GenOn Marsh Landing’s contractual requirements under its PPA with PG&E, under which no letters of credit were outstanding at December 31, 2011.
 
At December 31, 2011 and 2010, we had obligations outstanding under surety bonds of $46 million and $50 million, respectively, of which $1 million and $4 million, respectively, related to credit support for the transmission upgrades PG&E will be making in order to connect the Marsh Landing generating facility to the power grid.
 
Following is a summary of letters of credit issued and surety bonds provided:
 
 	 	December 31,	 	
 	 	2011	 	2010	 	
 	 	(in millions)	 	
Letters of credit—Marsh Landing development project(1)	 	$	175	 	$	106	 	
Letters of credit—rent reserves	 	130	 	133	 	
Letters of credit—energy trading and marketing	 	59	 	96	 	
Letters of credit—other operating activities	 	32	 	38	 	
Surety bonds(2)	 	46	 	50	 	
Total	 	$	442	 	$	423	 	

(1)                                Includes $131 million and $106 million of cash-collateralized letters of credit at December 31, 2011 and December 31, 2010, respectively.
 
(2)                                Includes $34 million of cash under surety bonds posted primarily with the Pennsylvania Department of Environmental Protection related to environmental obligations.	
 
Commercial Purchase and Sales Arrangements
 
In connection with the purchase and sale of fuel, emissions allowances and energy to and from third parties with respect to the operation of our generating facilities, we may be required to guarantee a portion of the obligations of certain of our subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments. At December 31, 2011, GenOn and its subsidiaries were contingently obligated for a total of $401 million under such arrangements. We do not expect that we will be required to make any material payments under these guarantees.
 
CenterPoint Guarantees
 
We have guaranteed some non-qualified benefits of CenterPoint’s existing retirees at September 20, 2002. The estimated maximum potential amount of future payments under the guarantee is $56 million at December 31, 2011 and $4 million is recorded in the consolidated balance sheet for this item, which represents the fair value of the guarantee on the Merger date.
 
F-73

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2011, 2010 and 2009
 
10. Commitments and Contingencies (Continued)
 
Other Guarantees and Indemnifications
 
Our debt agreements typically indemnify against liabilities that arise from the preparation, entry into, administration or enforcement of the agreement.
 
We have issued guarantees in conjunction with certain performance agreements and commodity and derivative contracts and other contracts that provide financial assurance to third parties on behalf of a subsidiary or an unconsolidated third party. The guarantees on behalf of subsidiaries are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the relevant subsidiary’s intended commercial purposes.
 
At December 31, 2011, we have issued $126 million of guarantees of obligations that our subsidiaries may incur in connection with construction agreements, equipment leases, interest rate swap agreements, settlement agreements and on-going litigation. We do not expect that we will be required to make any material payments under these guarantees.
 
We, through our subsidiaries, participate in several power pools with RTOs. The rules of these RTOs require that each participant indemnify the pool for defaults by other members. Usually, the amount indemnified is based upon the activity of the participant relative to the total activity of the pool and the amount of the default. Consequently, the amount of such indemnification cannot be quantified.
 
On a routine basis in the ordinary course of business, GenOn and its subsidiaries indemnify financing parties and consultants or other vendors who provide services to us. We do not expect that we will be required to make any material payments under these indemnity provisions.
 
Because some of the guarantees and indemnities we issue to third parties do not limit the amount or duration of our obligations to perform under them, there exists a risk that we may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit our liability exposure, we may not be able to estimate our potential liability until a claim is made for payment or performance, because of the contingent nature of these contracts.
 
Except as otherwise noted, we are unable to estimate our maximum potential exposure under these agreements until an event triggering payment occurs. We do not expect to make any material payments under these agreements.
 
11. Earnings Per Share
 
We calculate basic EPS by dividing income/loss available to stockholders by the weighted average number of common shares outstanding. Diluted EPS gives effect to dilutive potential common shares, including unvested restricted stock units, stock options and warrants. Share amounts below reflect Mirant’s historical activity through December 2, 2010 retroactively adjusted to give effect to the Exchange Ratio and include the combined entities for the periods from December 3, 2010.
 
F-74

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2011, 2010 and 2009
 
11. Earnings Per Share(Continued)
 
The following table shows the computation of basic and diluted EPS for 2011, 2010 and 2009:
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions, except per share data)	 	
Net income (loss)	 	$	(189	)	$	(233	)	$	493	 	
Basic and diluted	 	 	 	 	 	 	 	
Weighted average shares outstanding—basic	 	772	 	441	 	411	 	
Shares from assumed vesting of restricted stock units	 	—	(1)	—	(1)	1	 	
Weighted average shares outstanding—diluted	 	772	 	441	 	412	 	
Basic and Diluted EPS	 	 	 	 	 	 	 	
Basic EPS	 	$	(0.24	)	$	(0.53	)	$	1.20	 	
Diluted EPS	 	$	(0.24	)	$	(0.53	)	$	1.20	 	

(1)                                As we incurred a net loss for 2011 and 2010, diluted loss per share is calculated the same as basic loss per share.	
 
The weighted average number of securities that could potentially dilute basic EPS in the future that were not included in the computation of diluted EPS because to do so would have been antidilutive were as follows:
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Series A Warrants(1)	 	—	 	76	 	76	 	
Series B Warrants(1)	 	—	 	20	 	20	 	
Stock options	 	18	 	13	 	11	 	
Restricted stock units	 	4	 	3	 	2	 	
Total number of antidilutive shares	 	22	 	112	 	109	 	

(1)                                These warrants expired January 3, 2011.	
 
12. Stockholders’ Equity
 
On December 3, 2010, RRI Energy and Mirant completed the Merger. Upon closing, each issued and outstanding share of Mirant common stock automatically converted into 2.835 shares of common stock of RRI Energy, with cash paid in lieu of fractional shares. See note 2.
 
F-75

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2011, 2010 and 2009
 
12. Stockholders’ Equity(Continued)
 
The following summary of capital stock activity reflects Mirant’s historical activity through December 2, 2010 adjusted to give effect to the Exchange Ratio and includes the combined entities for the periods from December 3, 2010.
 
 	 	Common Stock	 	
 	 	(shares in millions)	 	
At December 31, 2008	 	410	 	
Shares repurchased	 	(1	)	
Transactions under stock plans(1)	 	2	 	
At December 31, 2009	 	411	 	
Shares repurchased	 	(3	)	
Transactions under stock plans(1)	 	8	 	
Issued in connection with the Merger(2)	 	355	 	
At December 31, 2010	 	771	 	
Transactions under stock plans(1)	 	1	 	
At December 31, 2011	 	772	 	

(1)                                See note 9 for further discussion of stock-based compensation and shares authorized for issuance under the GenOn Energy, Inc. 2010 Omnibus Incentive Plan.
 
(2)                                Represents RRI Energy’s outstanding common stock including restricted stock awards which vested upon completion of the Merger.	
 
Stockholders Rights Plan and Protective Charter Amendment
 
In November 2010, we amended our stockholder rights plan (Rights Agreement) and in May 2011 we adopted a Certificate of Amendment to our Third Restated Certificate of Incorporation (Protective Charter Amendment) to help protect our use of federal NOLs from certain restrictions contained in IRC § 382.
 
In general and subject to certain exceptions, if a person or group acquires a Beneficial Ownership (as defined in the Rights Agreement) of 4.99% or more of our outstanding common stock (Acquiring Person), the holder of each preferred stock purchase right (Right) other than the Acquiring Person, will be entitled to purchase the number of shares of common stock equal to $150 divided by one half of the per share current market price of common stock at that time. As an alternative, the board of directors may, at its option, exchange all or part of the Rights, other than rights beneficially owned by the Acquiring Person, for common stock at an exchange ratio of one share of common stock per Right. The Rights Agreement exempts persons that were existing 4.99% stockholders at the time of the amendment or became 4.99% stockholders solely as a result of the Merger. Certain institutional holders are also exempt.
 
Each share of our common stock has one Right attached, which trades with and is inseparable from the common stock. The Rights will expire on the earliest of: (a) November 23, 2013, (b) the time at which the Rights are redeemed or exchanged by us, or expire following certain transactions with
 
F-76

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2011, 2010 and 2009
 
12. Stockholders’ Equity(Continued)
 
persons who have acquired our common stock pursuant to a Permitted Offer (as defined in the Rights Agreement), (c) the repeal of IRC §382 or any successor statute if our board of directors determines that the Rights Agreement is no longer necessary for the preservation of NOLs or tax benefits and (d) the date on which the board of directors determines that no NOLs or other tax benefits may be carried forward.
 
The Protective Charter Amendment is designed to prevent transfers of our common stock that could result in an ownership change under IRC§ 382 and generally will restrict transfers if the effect would be to:
 
·                 increase the direct or indirect ownership of our stock by any Person (as defined in the Protective Charter Amendment) from less than 4.99% to 4.99% or more of our outstanding common stock; or
 
·                 increase the percentage of our common stock owned directly or indirectly by a Person owning or deemed to own 4.99% or more of our outstanding common stock.
 
Any transfer attempted in violation of the Protective Charter Amendment will be void as of the date of the restricted transfer as to the purported transferee or, in the case of an indirect transfer, the ownership of the direct owner of our common stock would terminate simultaneously with the transfer. In addition to a restricted transfer being void as of the date it is attempted, upon demand, the purported transferee must transfer the common stock purportedly acquired in violation of the Protective Charter Amendment to our agent, who is required to sell such stock.
 
The Protective Charter Amendment expires on the earliest of (a) the close of business on May 3, 2014, (b) the date on which the board of directors determines that the Protective Charter Amendment is no longer necessary or desirable for the preservation of our NOLs or other tax benefits because of the repeal of IRC § 382, (c) the date on which the board of directors determines that none of our NOLs or other tax benefits may be carried forward and (d) such date as the board of directors otherwise determines that the Protective Charter Amendment is no longer necessary or desirable.
 
Bankruptcy Plan
 
At December 31, 2011, approximately 1.3 million shares of common stock are, pursuant to the Plan, reserved for unresolved claims. See note 16.
 
Warrants
 
Mirant also issued two series of warrants that expired on January 3, 2011. The Series A Warrants and Series B Warrants entitled the holders as of the date of issuance to purchase an aggregate of approximately 35 million and 18 million shares of common stock, respectively. The exercise price of the Series A Warrants and Series B Warrants was $21.87 and $20.54 per share, respectively. In the Merger, all the outstanding Mirant warrants converted into warrants of GenOn entitling the holders to 2.835 shares of GenOn common stock for each warrant. During 2010 and 2009, the warrant exercises were immaterial. At December 31, 2010, there were approximately 26.9 million Series A Warrants and 7.1 million Series B Warrants outstanding.
 
F-77

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2011, 2010 and 2009
 
13. Variable Interest Entities
 
MC Asset Recovery
 
Under the Plan, the rights to certain actions filed by GenOn Energy Holdings and various 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 managers who are independent of us. Under the plan, any cash recoveries obtained by MC Asset Recovery from the actions transferred to it, net of fees and costs incurred in prosecuting the actions, are to be paid to the unsecured creditors of Mirant Corporation in the Chapter 11 proceedings and the holders of the equity interests in GenOn Energy Holdings immediately prior to the effective date of the Plan except where such a recovery results in an allowed claim in the bankruptcy proceedings.
 
MC Asset Recovery is considered a VIE because of our potential tax obligations which could arise from potential recoveries from legal actions that MC Asset Recovery is pursuing. Prior to January 1, 2010, under previous accounting guidance, we were considered the primary beneficiary of MC Asset Recovery and included the VIE in our consolidated financial statements. Based on the revised guidance related to accounting for VIEs that became effective on January 1, 2010, we reassessed our relationship with MC Asset Recovery and determined that we are no longer deemed to be the primary beneficiary. The characteristics of a primary beneficiary, as defined in the accounting guidance are: (a) the entity must have the power to direct the activities or make decisions that most significantly affect the VIE’s economic performance and (b) the entity must have an obligation to absorb losses or receive benefits that could be significant to the VIE. As MC Asset Recovery is governed by an independent Board of Managers that has sole power and control over the decisions that affect MC Asset Recovery’s economic performance, we do not meet the characteristics of a primary beneficiary. However, under the Plan, we are responsible for the taxes owed, if any, on any net recoveries up to $175 million obtained by MC Asset Recovery. We currently retain any tax obligations arising from the next approximately $74 million of potential recoveries by MC Asset Recovery. As a result of the initial application of this accounting guidance, we deconsolidated MC Asset Recovery effective January 1, 2010, and adjusted prior periods to conform to the current presentation.
 
GenOn Energy Holdings was obligated to make contributions to MC Asset Recovery as necessary to pay professional fees and certain other costs reasonably incurred by MC Asset Recovery, including expert witness fees and other costs of the actions transferred to MC Asset Recovery. On March 31, 2009, Southern Company and MC Asset Recovery entered into a settlement agreement and Southern Company paid $202 million to MC Asset Recovery. As a result of the settlement and related distributions made in September 2009, GenOn Energy Holdings has no further obligation to provide funding to MC Asset Recovery for professional fees and other costs incurred by MC Asset Recovery. See note 16.
 
14. Segment Reporting
 
In conjunction with the Merger, we began reporting in five segments in the fourth quarter of 2010: Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations. Prior to the Merger, we had four reportable segments: Mid-Atlantic, Northeast, California and Other Operations. We reclassified amounts for 2009 to conform to the current segment presentation. The segments were determined based on how the business is managed and align with the information provided to the chief operating decision maker for purposes of assessing performance and allocating resources. Generally,
 
F-78

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2011, 2010 and 2009
 
14. Segment Reporting(Continued)
 
our segments are engaged in the sale of electricity, capacity, ancillary and other energy services from their generating facilities in hour-ahead, day-ahead and forward markets in bilateral and ISO markets. We also engage in proprietary trading, fuel oil management and natural gas transportation and storage activities. Operating revenues consist of (a) power generation revenues, (b) contracted and capacity revenues, (c) power hedging revenues and (d) fuel sales and proprietary trading revenues.
 
Upon completion of the Merger, Mirant stockholders had a majority of the voting interest in the combined company. Although RRI Energy issued shares of RRI Energy common stock to Mirant stockholders to effect the Merger, the Merger is accounted for as a reverse acquisition under the acquisition method of accounting. Under the acquisition method of accounting, Mirant is treated as the accounting acquirer and RRI Energy is treated as the acquired company for financial reporting purposes. As such, our consolidated financial statements include the results of the combined entities for the periods from December 3, 2010, and include the results of Mirant through December 2, 2010. Our consolidated results of operations in 2010 include operating revenues from RRI Energy of $168 million and net loss of $60 million after the Merger.
 
The Eastern PJM segment consists of eight generating facilities located in Maryland, New Jersey and Virginia with total net generating capacity of 6,341 MW. The Western PJM/MISO segment (established as a result of the Merger) consists of 23 generating facilities located in Illinois, Ohio and Pennsylvania with total net generating capacity of 7,483 MW. See note 17 for a discussion of generating facilities in the Eastern PJM and Western PJM/MISO segments that we expect to retire, mothball or place in long-term protective layup between 2012 and 2015. The California segment consists of seven generating facilities located in California, with total net generating capacity of 5,391 MW and includes business development and construction activities for GenOn Marsh Landing. The total net generating capacity for California excludes the Potrero generating facility of 362 MW, which was shut down on February 28, 2011. The Energy Marketing segment consists of proprietary trading, fuel oil management and natural gas transportation and storage activities. Other Operations consists of eight generating facilities located in Florida, Massachusetts, Mississippi, New York and Texas with total net generating capacity of 4,482 MW. We sold our Indian River generating facility, which was included in the Other Operations segment, in January 2012. Other Operations also includes unallocated overhead expenses and other activity that cannot be specifically identified with another segment. All revenues are generated and long-lived assets are located within the United States.
 
The measure of profit or loss for our reportable segments is operating income/loss. This measure represents the lowest level of information that is provided to the chief operating decision maker for our reportable segments.
 
F-79

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2011, 2010 and 2009
 
14. Segment Reporting(Continued)
 
Operating Segments
 
 	 	Eastern PJM	 	Western
PJM/MISO	 	California	 	Energy
Marketing	 	Other
Operations	 	Eliminations	 	Total	 	
 	 	(in millions)	 	
2011:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues(1)	 	$	1,414	 	$	1,389	 	$	238	 	$	341	 	$	232	 	$	—	 	$	3,614	 	
Cost of fuel, electricity and other products(2)	 	555	 	654	 	16	 	255	 	130	 	—	 	1,610	 	
Gross margin (excluding depreciation and amortization)	 	859	 	735	 	222	 	86	 	102	 	—	 	2,004	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operations and maintenance	 	482	 	495	 	147	 	4	 	165	(3)	—	 	1,293	 	
Depreciation and amortization	 	146	 	118	 	44	 	2	 	65	 	—	 	375	 	
Impairment losses(4)	 	95	 	4	 	14	 	—	 	20	 	—	 	133	 	
Gain on sales of assets, net	 	—	 	—	 	(5	)	—	 	(1	)	—	 	(6	)	
Total operating expenses	 	723	 	617	 	200	 	6	 	249	 	—	 	1,795	 	
Operating income (loss)	 	$	136	 	$	118	 	$	22	 	$	80	 	$	(147	)	$	—	 	$	209	 	
Total assets	 	$	4,732	 	$	3,343	 	$	856	 	$	2,173	 	$	3,662	(5)	$	(2,497	)	$	12,269	 	
Capital expenditures	 	$	150	 	$	69	 	$	191	 	$	—	 	$	40	 	$	—	 	$	450	 	

(1)                                Includes unrealized gains (losses) of $119 million, $85 million, $2 million, $26 million and $(5) million for Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations, respectively.
 
(2)                                Includes unrealized (gains) losses of $(1) million, $4 million, $(2) million and $2 million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
 
(3)                                Includes $72 million of Merger-related costs.
 
(4)                                Represents impairment losses for the write-off of excess NOx and SO2 emissions allowances as a result of the CSAPR. See note 5.
 
(5)                                Includes our equity method investment in Sabine Cogen, LP of $22 million.
 
F-80

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2011, 2010 and 2009
 
14. Segment Reporting(Continued)
 
Operating Segments
 
 	 	Eastern PJM	 	Western
PJM/MISO	 	California	 	Energy
Marketing	 	Other
Operations	 	Eliminations	 	Total	 	
 	 	(in millions)	 	
2010:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues(1)	 	$	1,710	 	$	118	 	$	149	 	$	54	 	$	239	 	$	—	 	$	2,270	 	
Cost of fuel, electricity and other products(2)	 	698	 	75	 	23	 	28	 	139	 	—	 	963	 	
Gross margin (excluding depreciation and amortization)	 	1,012	 	43	 	126	 	26	 	100	 	—	 	1,307	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operations and maintenance	 	495	 	45	 	78	 	9	 	219	(3)	—	 	846	 	
Depreciation and amortization	 	142	 	9	 	31	 	1	 	41	 	—	 	224	 	
Impairment losses(4)	 	1,153	 	—	 	—	 	—	 	28	 	(616	)	565	 	
Gain on sales of assets, net	 	(3	)	—	 	—	 	—	 	(1	)	—	 	(4	)	
Total operating expenses	 	1,787	 	54	 	109	 	10	 	287	 	(616	)	1,631	 	
Operating income (loss)	 	$	(775	)	$	(11	)	$	17	 	$	16	 	$	(187	)	$	616	 	$	(324	)	
Total assets	 	$	4,892	 	$	3,743	 	$	747	 	$	2,767	 	$	6,915	(5)	$	(3,865	)	$	15,199	 	
Capital expenditures	 	$	232	 	$	13	 	$	40	 	$	—	 	$	19	 	$	—	 	$	304	 	

(1)                                Includes unrealized gains (losses) of $80 million, $(27) million, $(5) million and $(3) million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
 
(2)                                Includes unrealized (gains) losses of $73 million, $(5) million, $3 million and $16 million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
 
(3)                                Includes $114 million of Merger-related costs and $24 million related to the accelerated vesting of Mirant’s stock-based compensation as a result of the Merger.
 
(4)                                Includes impairment loss of goodwill of $616 million recorded at GenOn Mid-Atlantic on its stand alone balance sheet. The goodwill does not exist at our consolidated balance sheet. As such, the goodwill impairment loss is eliminated upon consolidation.
 
(5)                                Includes our equity method investment in Sabine Cogen, LP of $20 million.
 
F-81

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
14. Segment Reporting (Continued)
 
Operating Segments
 
 	 	Eastern PJM	 	Western
PJM/MISO	 	California	 	Energy
Marketing	 	Other
Operations	 	Eliminations	 	Total	 	
 	 	(in millions)	 	
2009:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues(1)	 	$	1,778	 	$	—	 	$	154	 	$	62	 	$	318	 	$	(3	)	$	2,309	 	
Cost of fuel, electricity and other products(2)	 	527	 	—	 	32	 	8	 	143	 	—	 	710	 	
Gross margin (excluding depreciation and amortization)	 	1,251	 	—	 	122	 	54	 	175	 	(3	)	1,599	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operations and maintenance	 	434	 	—	 	79	 	11	 	86	 	—	 	610	 	
Depreciation and amortization	 	98	 	—	 	22	 	1	 	28	 	—	 	149	 	
Impairment losses(3)	 	385	 	—	 	14	 	—	 	5	 	(183	)	221	 	
Gain on sales of assets, net	 	(14	)	—	 	—	 	—	 	(4	)	(4	)	(22	)	
Total operating expenses	 	903	 	—	 	115	 	12	 	115	 	(187	)	958	 	
Operating income	 	$	348	 	$	—	 	$	7	 	$	42	 	$	60	 	$	184	 	$	641	 	
Total assets	 	$	5,807	 	$	—	 	$	144	 	$	2,782	 	$	2,941	 	$	(2,146	)	$	9,528	 	
Capital expenditures	 	$	578	 	$	—	 	$	7	 	$	2	 	$	89	 	$	—	 	$	676	 	

(1)                                Includes unrealized gains (losses) of $136 million, $(113) million and $(25) million for Eastern PJM, Energy Marketing and Other Operations, respectively.
 
(2)                                Includes unrealized gains of $8 million and $41 million for Eastern PJM and Other Operations, respectively.
 
(3)                                Includes $183 million impairment loss of goodwill recorded at GenOn Mid-Atlantic on its standalone balance sheet. The goodwill does not exist at our consolidated balance sheet. As such, the goodwill impairment loss is eliminated upon consolidation.
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Operating income (loss) for all segments	 	$209	 	$(324	)	$641	 	
Gain on bargain purchase, as retroactively amended	 	—	 	335	 	—	 	
Interest expense	 	(380	)	(254	)	(138	)	
Interest income	 	1	 	1	 	3	 	
Other, net	 	(19	)(1)	7	 	(1	)(2)	
Income (loss) before income taxes	 	$(189	)	$(235	)	$505	 	

(1)                                Includes $6 million of equity in income of our equity method investment in Sabine Cogen, LP, which is included in Other Operations.
 
(2)                                Includes $1 million of equity in loss of our equity method investment in MC Asset Recovery, which is included in Other Operations.
 
F-82

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
15. Quarterly Financial Data (Unaudited)
 
Summarized quarterly financial data for 2011 and 2010 is as follows:
 
 	 	Quarters Ended	 	
 	 	March 31,
2011(1)	 	June 30,
2011(1)	 	September 30,
2011(1)	 	December 31,
2011	 	
 	 	(in millions except per share data)	 	
Operating revenues	 	$	814	(2)	$	812	(3)	$	1,080	(4)	$	908	(5)	
Cost of fuel, electricity and other products	 	$	401	(2)	$	390	(3)	$	526	(4)	$	293	(5)	
Operating income (loss)	 	$	23	(6)	$	(42	)(7)	$	45	(8)	$	183	(9)	
Net income (loss)	 	$	(111	)(10)	$	(138	)	$	(40	)	$	100	 	
Weighted average shares outstanding—basic	 	771	 	772	 	772	 	773	 	
Net income (loss) per weighted average shares outstanding—basic	 	$	(0.15	)	$	(0.18	)	$	(0.05	)	$	0.13	 	
Weighted average shares outstanding—diluted	 	771	 	772	 	772	 	773	 	
Net income (loss) per weighted average shares outstanding—diluted	 	$	(0.15	)	$	(0.18	)	$	(0.05	)	$	0.13	 	

(1)                                During the third and fourth quarters of 2011, we recorded revisions to the provisional allocation of the purchase price at December 3, 2010 and accordingly revised amounts in our consolidated statements of operations for the nine months ended September 30, 2011. See note 2.
 
(2)                                Includes unrealized losses of $99 million in operating revenues and unrealized gains of $20 million in cost of fuel, electricity and other products primarily as a result of increases in oil prices offset by decreases in forward power and natural gas prices in the quarter.
 
(3)                                Includes unrealized losses of $36 million in operating revenues and unrealized gains of $18 million in cost of fuel, electricity and other products primarily as a result of decreases in forward power and natural gas prices and increases in forward coal prices in the quarter.
 
(4)                                Includes unrealized gains of $49 million in operating revenues and unrealized losses of $11 million in cost of fuel, electricity and other products primarily as a result of decreases in forward power and natural gas prices in the quarter.
 
(5)                                Includes unrealized gains of $313 million in operating revenues and unrealized losses of $30 million in cost of fuel, electricity and other products primarily as a result of decreases in forward power and natural gas prices in the quarter.
 
(6)                                Includes $23 million in Merger-related costs. See note 3.
 
(7)                                Includes $14 million of Merger-related costs and a $30 million accrual for remediation costs at our Maryland ash facilities. See notes 3 and 16.
 
(8)                                Includes $24 million in Merger-related costs and $133 million in impairment losses for the write-off of excess NO x  and SO 2  emissions allowances as a result of the CSAPR. See notes 3 and 5.
 
(9)                                Includes $11 million in Merger-related costs and $29 million accrual for remediation costs at our Maryland ash facilities. See notes 3 and 16.
 
(10)                         Includes $23 million of loss on early extinguishment of debt. See note 6.
 
F-83

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
15. Quarterly Financial Data (Unaudited) (Continued)
 
 	 	Quarters Ended	 	
 	 	March 31,
2010	 	June 30,
2010	 	September 30,
2010	 	December 31,
2010(1)	 	
 	 	(in millions except per share data)	 	
Operating revenues	 	$	880	(2)	$	244	(3)	$	775	(4)	$	371	(5)	
Cost of fuel, electricity and other products	 	$	207	(2)	$	272	(3)	$	247	(4)	$	237	(5)	
Operating income (loss)	 	$	458	 	$	(212	)(6)	$	304	 	$	(874	)	
Net income (loss)	 	$	407	 	$	(263	)	$	254	 	$	(631	)(7)	
Weighted average shares outstanding—basic	 	412	 	412	 	412	 	525	 	
Net income (loss) per weighted average shares outstanding—basic	 	$	0.99	 	$	(0.64	)	$	0.62	 	$	(1.20	)	
Weighted average shares outstanding—diluted	 	413	 	412	 	413	 	525	 	
Net income (loss) per weighted average shares outstanding—diluted	 	$	0.99	 	$	(0.64	)	$	0.62	 	$	(1.20	)	

(1)                                Includes results from RRI Energy’s operations after the Merger. See note 2.
 
(2)                                Includes unrealized gains of $363 million in operating revenues and unrealized losses of $11 million in cost of fuel, electricity and other products primarily as a result of decreases in energy prices in the quarter.
 
(3)                                Includes unrealized losses of $231 million in operating revenues and unrealized losses of $109 million in cost of fuel, electricity and other products primarily as a result of increases in energy prices and the recognition of many of the coal agreements at fair value in the quarter.
 
(4)                                Includes unrealized gains of $154 million in operating revenues and unrealized gains of $13 million in cost of fuel, electricity and other products primarily as a result of decreases in energy prices and increases in coal prices in the quarter.
 
(5)                                Includes unrealized losses of $241 million in operating revenues and unrealized gains of $20 million in cost of fuel, electricity and other products primarily as a result of increases in energy prices in the quarter.
 
(6)                                Includes $37 million as a result of a curtailment gain resulting from an amendment to our postretirement healthcare benefits plan covering Eastern PJM union employees. See note 8.
 
(7)                                Includes impairment losses of $565 million related to the Dickerson and Potomac River generating facilities, $114 million in Merger- related costs and $24 million related to the accelerated vesting of Mirant’s stock-based compensation as a result of the Merger, offset in part by a gain on bargain purchase of $335 million, as retroactively amended, related to the Merger. See notes 2, 3 and 5.
 
The unaudited pro forma results give effect to the Merger as if it had occurred on January 1, 2010. The unaudited pro forma financial information is not necessarily indicative of either future results of operations or results that might have been achieved had the acquisition been consummated as of
 
F-84

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
15. Quarterly Financial Data (Unaudited) (Continued)
 
January 1, 2010. See note 2. Summarized unaudited pro forma quarterly financial data for 2010 is as follows:
 
 	 	Quarters Ended	 	
 	 	Pro Forma
March 31,
2010	 	Pro Forma
June 30,
2010	 	Pro Forma
September 30,
2010	 	Pro Forma
December 31,
2010	 	
 	 	(in millions except per share data)	 	
Operating revenues	 	$	1,481	 	$	639	 	$	1,467	 	$	579	 	
Cost of fuel, electricity and other products	 	$	459	 	$	522	 	$	537	 	$	328	 	
Operating income (loss)	 	$	326	 	$	(314	)	$	428	 	$	(773	)	
Net income (loss)	 	$	223	 	$	(403	)	$	336	 	$	(896	)	
Weighted average shares outstanding—basic	 	772	 	773	 	774	 	771	 	
Net income (loss) per weighted average shares outstanding—basic	 	$	0.29	 	$	(0.52	)	$	0.43	 	$	(1.16	)	
Weighted average shares outstanding—diluted	 	774	 	773	 	774	 	771	 	
Net income (loss) per weighted average shares outstanding—diluted	 	$	0.29	 	$	(0.52	)	$	0.43	 	$	(1.16	)	
 
16. Litigation and Other Contingencies
 
We are involved in a number of legal proceedings. In certain cases, plaintiffs seek to recover large or unspecified damages, and some matters may be unresolved for several years. We cannot currently determine the outcome of the proceedings described below or estimate the reasonable amount or range of potential losses, if any, and therefore have not made any provision for such matters unless specifically noted below.
 
Scrubber Contract Litigation
 
In January 2011, Stone & Webster, the EPC contractor for the scrubber projects at the Chalk Point, Dickerson and Morgantown generating facilities, filed three suits against us in the United States District Court for the District of Maryland. Stone & Webster claims that it has not been paid in accordance with the terms of the EPC agreements for the scrubber projects and sought $143.1 million in liens against the properties. In March 2011, the court granted these liens. In June 2011, Stone & Webster filed a motion to amend its lien claims at these facilities by an additional $90.5 million. In August 2011, the court granted these additional liens. In September 2011, GenOn Mid-Atlantic paid $68 million to Stone & Webster for achieving substantial completion under the EPC agreements, which reduced the outstanding liens amount to $165.6 million. As a result of certain lien restrictions in its lease documentation, GenOn Mid-Atlantic has reserved $165.6 million of cash (which is included in funds on deposit on the unaudited condensed consolidated balance sheet) in respect of such liens. The liens are interlocutory only and will not become final unless and until Stone & Webster is successful in prosecuting its contractual claims. We dispute Stone & Webster’s allegations and in February 2011 filed a related action against Stone &Webster in the United States District Court for the Southern District of New York. The proceedings in Maryland have been stayed pending resolution of the proceeding in New York. Assuming we are successful in pursuing our claims in the New York proceeding, the total estimated capital expenditures for compliance with the Maryland Healthy Air Act would not exceed the
 
F-85

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
16. Litigation and Other Contingencies (Continued)
 
$1.674 billion we currently have recorded. However, if the costs were to equal the amount claimed by Stone &Webster in the litigation, the total capital expenditures would exceed $1.674 billion by approximately 5%.
 
Pending Natural Gas Litigation
 
We are party to five lawsuits, several 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 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of antitrust and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name a number of unaffiliated energy companies as parties. In July 2011, the judge in the United States District Court for the District of Nevada handling four of the five cases granted the defendants’ motion for summary judgment dismissing all claims against us in those cases. The plaintiffs have appealed to the United States Court of Appeals for the Ninth Circuit. The fifth case is pending in the State of Nevada Supreme Court on plaintiff’s appeal of the dismissal of all its claims by the Eighth Judicial District Court for Clark County, Nevada. We have agreed to indemnify CenterPoint against certain losses relating to these lawsuits.
 
Bowline Property Tax Dispute
 
In 2011, 2010 and 2009 we filed suit against the town of Haverstraw to challenge the property tax assessment of the Bowline generating facility for each respective tax year. Although the assessments for the 2011 and 2010 tax years were reduced significantly from the assessment received in 2009, they continue to exceed significantly the estimated fair value of the generating facility. The tax litigation for all three years has been combined for trial purposes. While we are unable to predict the outcome of this litigation, if we are successful we expect to receive a refund for each of the years under protest.
 
Environmental Matters
 
Global Warming.  In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a suit in the United States District Court for the Northern District of California against GenOn and 23 other electric generating and oil and gas companies. The lawsuit seeks damages of up to $400 million for the cost of relocating the village allegedly because of global warming caused by the greenhouse gas emissions of the defendants. In late 2009, the District Court ordered that the case be dismissed and the plaintiffs appealed. Although we think claims such as this lack legal merit, it is possible that this trend of climate change litigation may continue.
 
New Source Review Matters.  The EPA and various states are investigating compliance of coal-fueled electric generating facilities with the pre-construction permitting requirements of the Clean Air Act known as “new source review.” In the past decade, the EPA has made information requests concerning the Avon Lake, Chalk Point, Cheswick, Conemaugh, Dickerson, Elrama, Keystone, Morgantown, New Castle, Niles, Portland, Potomac River, Shawville and Titus generating facilities. We are corresponding or have corresponded with the EPA regarding all of these requests. The EPA agreed to share information relating to its investigations with state environmental agencies. In January 2009, we received an NOV from the EPA alleging that past work at our Shawville, Portland and Keystone
 
F-86

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
16. Litigation and Other Contingencies (Continued)
 
generating facilities violated regulations regarding new source review. In June 2011, we received an NOV from the EPA alleging that past work at our Niles and Avon Lake generating facilities violated regulations regarding new source review.
 
In December 2007, the NJDEP filed suit against us in the United States District Court for the Eastern District of Pennsylvania, alleging that new source review violations occurred at the Portland generating facility. The suit seeks installation of “best available” control technologies for each pollutant, to enjoin us from operating the generating facility if it is not in compliance with the Clean Air Act and civil penalties. The suit also names three past owners of the plant as defendants. In March 2009, the Connecticut Department of Environmental Protection became an intervening party to the suit.
 
We think that the work listed by the EPA and the work subject to the NJDEP suit were conducted in compliance with applicable regulations. However, any final finding that we violated the new source review requirements could result in fines, penalties or significant capital expenditures associated with the implementation of emissions reductions on an accelerated basis. Most of these work projects were undertaken before our ownership or lease of those facilities.
 
In addition, the NJDEP filed two administrative petitions with the EPA in 2010 alleging that our Portland generating facility’s emissions were significantly contributing to nonattainment and/or interfering with the maintenance of certain NAAQS in New Jersey. In November 2011, the EPA published a final rule in response to one of the petitions that will require us to reduce our maximum allowable SO 2  emissions from the two coal-fired units by about 60% starting in January 2013 and by about 80% starting in January 2015. In January 2012, we challenged the rule in the United States Court of Appeals for the Third Circuit. In 2013 and 2014, we have several compliance options that include using lower sulfur coals (although this may at times reduce how much we are able to generate) or running just one unit at a time. Starting in January 2015, these units will be subject to more stringent rate limits, which will require either material capital expenditures and higher operating costs or the retirement of these two units.
 
Brunot Island NOV.  In November 2011, the PADEP alleged that we violated the Pennsylvania Clean Streams Law when we discharged discolored water in 2010 and released fuel oil into a navigable waterway in 2007 at the Brunot Island generating facility. In February 2012, we settled this matter with the PADEP by agreeing to pay a civil penalty of $152,500.
 
Potomac River NOV.  In August 2011, the Virginia DEQ issued an NOV related to the Potomac River generating facility. The Virginia DEQ asserted that (a) the facility is not equipped with all appropriate fugitive dust controls, (b) we failed to correctly calculate NO x  emissions rates and (c) NO x  emissions exceeded the permitted limits on six days in June and July 2011. In February 2012, we settled this matter with the Virginia DEQ by agreeing to pay a civil penalty of $280,700.
 
Cheswick Monarch Mine NOV.  In 2008, the PADEP issued an NOV related to the Monarch mine located near our Cheswick generating facility. It has not been mined for many years. We use it for disposal of low-volume wastewater from the Cheswick generating facility and for disposal of leachate collected from ash disposal facilities. The NOV addresses the alleged requirement to maintain a minimum pumping volume from the mine. The PADEP indicated it may assess a civil penalty in excess of $100,000. We contest the allegations in the NOV and have not agreed to such penalty. We are
 
F-87

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
16. Litigation and Other Contingencies (Continued)
 
currently assessing the need for capital expenditures in connection with wastewater from Cheswick and leachate from ash disposal facilities.
 
Conemaugh Alleged Clean Streams Law Violations.  The PADEP has alleged that several violations of Pennsylvania Clean Streams Law occurred at the Conemaugh generating facility. We expect to resolve these issues by entering into an agreement with the PADEP that would obligate us to pay a civil penalty of $500,000. We would be responsible for 16.45% of this amount.
 
Keystone Wastewater Settlement with PADEP.  In November 2011, the PADEP informed us that it believed that we had violated the Pennsylvania Clean Streams Law by (a) improperly permitting improvements to the plant required by the construction of scrubbers and (b) discharging stormwater associated with certain improvements. We expect to settle this matter with the PADEP by agreeing to pay a civil penalty of $120,000. We are responsible for 16.67% of this amount.
 
Maryland Fly Ash Facilities.  We have three fly ash facilities in Maryland: Faulkner, Westland and Brandywine. We dispose of fly ash from our Morgantown and Chalk Point generating facilities at Brandywine. We dispose of fly ash from our Dickerson generating facility at Westland. We no longer dispose of fly ash at the Faulkner facility. As described below, the MDE has sued us regarding Faulkner and Brandywine and threatened to sue regarding Westland. The MDE also has threatened not to renew the water discharge permits for all three facilities.
 
Faulkner Litigation.  In May 2008, the MDE sued us in the Circuit Court for Charles County, Maryland alleging violations of Maryland’s water pollution laws at Faulkner. The MDE contended that the operation of Faulkner had resulted in the discharge of pollutants that exceeded Maryland’s water quality criteria and without the appropriate NPDES permit. The MDE also alleged that we failed to perform certain sampling and reporting required under an applicable NPDES permit. The MDE complaint requested that the court (a) prohibit continuation of the alleged unpermitted discharges, (b) require us to cease from further disposal of any coal combustion byproducts at Faulkner and close and cap the existing disposal cells and (c) assess civil penalties. In July 2008, we filed a motion to dismiss the complaint, arguing that the discharges are permitted by a December 2000 Consent Order. In January 2011, the MDE dismissed without prejudice its complaint and informed us that it intended to file a similar lawsuit in federal court. In May 2011, the MDE filed a complaint against us in the United States District Court for the District of Maryland alleging violations of the Clean Water Act and Maryland’s Water Pollution Control Law at Faulkner. The MDE contends that (a) certain of our water discharges are not authorized by our existing permit and (b) operation of the Faulkner facility has resulted in discharges of pollutants that violate water quality criteria. The complaint asks the court to, among other things, (a) enjoin further disposal of coal ash; (b) enjoin discharges that are not authorized by our existing permit; (c) require numerous technical studies; (d) impose civil penalties and (e) award them attorneys’ fees. We dispute the allegations.
 
Brandywine Litigation.  In April 2010, the MDE filed a complaint against us in the United States District Court for the District of Maryland asserting violations of the Clean Water Act and Maryland’s Water Pollution Control Law at Brandywine. The MDE contends that the operation of Brandywine has resulted in discharges of pollutants that violate Maryland’s water quality criteria. The complaint requests that the court, among other things, (a) enjoin further disposal of coal combustion waste at
 
F-88

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
16. Litigation and Other Contingencies (Continued)
 
Brandywine, (b) require us to close and cap the existing open disposal cells within one year, (c) impose civil penalties and (d) award them attorney’s fees. We dispute the allegations. In September 2010, four environmental advocacy groups became intervening parties in the proceeding.
 
Threatened Westland Litigation.  In January 2011, the MDE informed us that it intends to sue us for alleged violations of Maryland’s water pollution laws at Westland. To date, MDE has not sued us regarding our ash disposal at Westland.
 
Permit Renewals.  In March 2011, the MDE tentatively determined to deny our application for the renewal of the water discharge permit for Brandywine, which could result in a significant increase in operating expenses for our Chalk Point and Morgantown generating facilities. The MDE also indicated that it was planning to deny our applications for the renewal of the water discharge permits for Faulkner and Westland. Denial of the renewal of the water discharge permit for the latter facility could result in a significant increase in operating expenses for our Dickerson generating facility.
 
Stay and Settlement Discussions.  In June 2011, the MDE agreed to stay the litigation related to Faulkner and Brandywine while we pursue settlement of allegations related to the three Maryland ash facilities. MDE also agreed not to pursue its tentative denial of our application to renew our water discharge permit at Brandywine and agreed not to act on our renewal applications for Faulkner or Westland while we are discussing settlement. As a condition to obtaining the stay, we agreed in principle to pay a civil penalty of $1.9 million to the MDE if we reach a comprehensive settlement regarding all of the allegations related to the three Maryland ash facilities. Accordingly, we accrued $1.9 million during 2011. We also developed a technical solution, which includes installing synthetic caps on the closed cells of each of the three ash facilities. During 2011, we accrued $47 million for the estimated cost of the technical solution. We continue to negotiate with the MDE. At this time, we cannot reasonably estimate the upper range of our obligations for remediating the sites for the following reasons: (a) we have not finished assessing each site including identifying the full impacts to both ground and surface water and the impacts to the surrounding habitat; (b) we have not finalized with the MDE the standards to which we must remediate; and (c) we have not identified the technologies required, if any, to meet the mandated remediation standards at each site nor the timing of the design and installation of such technologies. There are no assurances that we will be able to settle the three matters. If we are able to settle the three matters, there are no assurances that we will be able to do so for the amounts that we have accrued. The ultimate resolution of these matters could be material to our results of operations, financial position and cash flows.
 
Brandywine Storm Damage and Remediation.  As a result of Hurricane Irene and Tropical Storm Lee in August and September 2011, an estimated 10,000 cubic yards of coal fly ash stored in one of the cells at the Brandywine ash disposal site flowed onto 18 acres of private property adjacent to the site. During 2011, we accrued $10 million for the estimated costs to remove the ash and do other remediation. We are continuing to remove the ash and do other remediation in coordination with the MDE and the property owners. At this time, we cannot reasonably estimate the upper range of our obligations for this matter principally because we have not finished (a) assessing the volume of fly ash to be removed and (b) determining how most effectively to access some of the affected areas. We are pursuing recovery under our insurance policies for our costs to remove the ash and do other remediation.
 
F-89

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
16. Litigation and Other Contingencies (Continued)
 
Ash Disposal Facility Closures.  We are responsible for environmental costs related to the future closures of several ash disposal facilities. We have accrued the estimated discounted costs ($38 million and $36 million at December 31, 2011 and 2010, respectively) associated with these environmental liabilities as part of the asset retirement obligations. These amounts are exclusive of the $47 million accrual for the technical solution for the three ash facilities in Maryland discussed above.
 
Remediation Obligations.  We are responsible for environmental costs related to site contamination investigations and remediation requirements at four generating facilities in New Jersey. We have accrued the estimated long-term liability for the remediation costs of $6 million and $7 million at December 31, 2011 and 2010, respectively.
 
Chapter 11 Proceedings
 
In July 2003, and various dates thereafter, GenOn Energy Holdings and certain of its subsidiaries (collectively, the Mirant Debtors) filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. 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 Merger, those reserved shares converted into a reserve for approximately 1.3 million shares of GenOn 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.
 
Actions Pursued by MC Asset Recovery
 
Under the Plan, the rights to 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 managers who are independent of us. Under the Plan, any cash recoveries obtained by MC Asset Recovery from the actions transferred to it, net of fees and costs incurred in prosecuting the actions, are to be paid to the unsecured creditors of GenOn Energy Holdings in the Chapter 11 proceedings and the holders of the equity interests in GenOn Energy Holdings immediately prior to the effective date of the Plan except where such a recovery results in an allowed claim in the bankruptcy proceedings, as described below. MC Asset Recovery is a disregarded entity for income tax purposes, and GenOn Energy Holdings is responsible for income taxes related to its operations. The Plan provides that GenOn Energy Holdings may not reduce payments to be made to unsecured creditors and former holders of equity interests from recoveries obtained by MC Asset Recovery for the taxes owed by GenOn Energy Holdings, if any, on any net recoveries up to $175 million. If the aggregate recoveries exceed $175 million net of costs, then GenOn Energy Holdings may reduce the payments by the amount of any taxes it will owe or NOLs utilized with respect to taxable income resulting from the amount in excess of $175 million.
 
F-90

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
16. Litigation and Other Contingencies (Continued)
 
The Plan and the MC Asset Recovery Limited Liability Company Agreement also obligate GenOn Energy Holdings to make contributions to MC Asset Recovery as necessary to pay professional fees and certain other costs. In June 2008, GenOn Energy Holdings and MC Asset Recovery, with the approval of the Bankruptcy Court, agreed to limit the total amount of funding to be provided by GenOn Energy Holdings to MC Asset Recovery to $68 million, and the amount of such funding obligation not already incurred by GenOn Energy Holdings at that time was fully accrued. GenOn Energy Holdings was entitled to be repaid the amounts it funded from any recoveries obtained by MC Asset Recovery before any distribution was made from such recoveries to the unsecured creditors of GenOn Energy Holdings and the former holders of equity interests.
 
In March 2009, Southern Company and MC Asset Recovery entered into a settlement agreement resolving claims asserted by MC Asset Recovery in a suit that was pending in the United States District Court for the Northern District of Georgia (the Southern Company Litigation). Southern Company paid $202 million to MC Asset Recovery in settlement of all claims asserted in the Southern Company Litigation. MC Asset Recovery used a portion of that payment to pay fees owed to the managers of MC Asset Recovery and other expenses of MC Asset Recovery not previously funded by GenOn Energy Holdings, and it retained $47 million from that payment to fund future expenses and to apply against unpaid expenditures. MC Asset Recovery distributed the remaining $155 million to GenOn Energy Holdings. In accordance with the Plan, GenOn Energy Holdings retained approximately $52 million of that distribution as reimbursement for the funds it had provided to MC Asset Recovery and costs it incurred related to MC Asset Recovery that had not been previously reimbursed. We recognized the $52 million as a reduction of operations and maintenance expense during 2009. Pursuant to MC Asset Recovery’s Limited Liability Company Agreement and an order of the Bankruptcy Court dated October 31, 2006, GenOn Energy Holdings distributed $2 million to the managers of MC Asset Recovery. In September 2009, the remaining approximately $101 million of the amount recovered by MC Asset Recovery was distributed pursuant to the terms of the Plan. Following these distributions, GenOn Energy Holdings has no further obligation to provide funding to MC Asset Recovery. As a result, GenOn Energy Holdings reversed its remaining accrual of $10 million of funding obligations as a reduction in operations and maintenance expense for 2009. GenOn does not expect to owe any taxes related to the MC Asset Recovery settlement with Southern Company.
 
Based on a stipulation entered by the Bankruptcy Court in December 2011 and pursuant to the terms of the Plan and the MC Asset Recovery Limited Liability Company Agreement, GenOn Energy Holdings will distribute approximately $26 million of the $47 million in funds that had been previously retained by MC Asset Recovery. The distribution could occur as soon as March 2012.
 
One of the two remaining actions transferred to MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks (the Commerzbank Defendants) for alleged fraudulent transfers that occurred prior to the filing of GenOn Energy Holdings’ bankruptcy proceedings. In its amended complaint, MC Asset Recovery alleges that the Commerzbank Defendants in 2002 and 2003 received payments totaling approximately 153 million Euros directly or indirectly from GenOn Energy Holdings under a guarantee provided by GenOn Energy Holdings in 2001 of certain equipment purchase obligations. MC Asset Recovery alleges that at the time GenOn Energy Holdings provided the guarantee and made the payments to the Commerzbank Defendants, GenOn Energy Holdings was insolvent and did not receive fair value for those transactions. In December 2010, the
 
F-91

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
16. Litigation and Other Contingencies (Continued)
 
United States 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 United States District Court’s dismissal of its complaint against the Commerzbank Defendants to the United States Court of Appeals for the Fifth Circuit. If MC Asset Recovery succeeds in obtaining any recoveries on these avoidance claims, the Commerzbank Defendants have asserted that they will seek to file claims in GenOn Energy Holdings’ bankruptcy proceedings for the amount of those recoveries. GenOn Energy Holdings would vigorously contest the allowance of any such claims on the ground that, among other things, the recovery of such amounts by MC Asset Recovery does not reinstate any enforceable pre-petition obligation that could give rise to a claim. If such a claim were to be allowed by the Bankruptcy Court as a result of a recovery by MC Asset Recovery, then the Plan provides that the Commerzbank Defendants are entitled to the same distributions as previously made under the Plan to holders of similar allowed claims. Holders of previously allowed claims similar in nature to the claims that the Commerzbank Defendants would seek to assert have received 43.87 shares of GenOn Energy Holdings common stock for each $1,000 of claim allowed by the Bankruptcy Court. 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, the order entered by the Bankruptcy Court on December 9, 2005, confirming the Plan provides that 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 rather than distribute such amount to the unsecured creditors and former equity holders as described above.
 
Texas Franchise Audit
 
In 2008 and 2009, the state of Texas, as a result of its audit, issued franchise tax assessments against us indicating an underpayment of franchise tax of $70 million (including interest and penalties through December 31, 2011 of $27 million). These assessments are related primarily to a claim by Texas that would change the sourcing of intercompany receipts for the years 2000 through 2006, thereby increasing the amount of tax due to Texas. We disagree with most of the State’s assessment and its determination of the related tax liability. Given the disagreement with the State’s position, we have accrued a portion of the liability but have protested the entire assessment and are currently in the administrative appeals process. If we do not fully resolve or come to satisfactory settlement of the protested issues, then we could pay up to the entire amount of the assessed tax, penalties and interest. We intend to defend fully our position in the administrative appeals process and if such defense requires litigation, would be required to pay the full assessment and sue for refund.
 
17. Subsequent Event
 
Expected Retirements, Mothball or Long-Term Protective Layup of Generating Facilities.  We are subject to extensive environmental regulation by federal, state and local authorities under a variety of statutes, regulations and permits that address discharges into the air, water and soil; and the proper handling of solid, hazardous and toxic materials and waste. Complying with increasingly stringent environmental requirements involves significant capital and operating expenses. To the extent forecasted returns on investments necessary to comply with environmental regulations are insufficient for a particular facility, we plan to deactivate that facility. In determining the forecasted returns on investments, we factor in forecasted energy and capacity prices, expected capital expenditures, operating
 
F-92

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 2011, 2010 and 2009
 
17. Subsequent Event (Continued)
 
costs, property taxes and other factors. We currently expect to deactivate the following generating capacity, primarily coal-fired unit
s, in the referenced years: Niles (217 MW) 2012, Elrama (460 MW) mothball 2012 and retire in 2014, New Castle (330 MW) 2015, Titus (243 MW) 2015, Portland (401 MW) 2015, Shawville (597 MW) place in long-term protective layup in 2015 and Glen Gardner (160 MW) 2015. Further, although our evaluation of the viability of environmental controls for our Avon Lake facility (732 MW) is continuing, our initial analysis indicates that forecasted returns on such investments are insufficient. If such analysis is confirmed, we anticipate retiring the coal-fired units at the Avon Lake facility in 2015. The decision with respect to Avon Lake is influenced in part by retirement decisions announced by other companies that we are continuing to evaluate. At December 31, 2011, the aggregate carrying value of property, plant and equipment and materials and supplies inventory for these generating facilities was $212 million and $53 million, respectively.
 
F-93

 
Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders
GenOn Energy, Inc.:
 
Under date of February 29, 2012, we reported on the consolidated balance sheets of GenOn Energy, Inc. and subsidiaries (the Company) as of December 31, 2011 and 2010, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the years in the three-year period ended December 31, 2011. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related financial statement schedules as listed within Item 15. These financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statement schedules based on our audits.
 
In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
 
/s/ KPMG LLP	 	
 	 	
Houston, Texas	 	
February 29, 2012	 	
 
F-94

 
Schedule I
 
GENON ENERGY, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF OPERATIONS
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Operating income	 	$	—	 	$	—	 	$	63	 	
Other Income (Expense), net:	 	 	 	 	 	 	 	
Equity in income (loss) of affiliates (includes gain on bargain purchase of $335 million, as retroactively amended, in 2010)	 	(44	)	(226	)	436	 	
Interest income	 	—	 	—	 	2	 	
Interest income—affiliate	 	83	 	12	 	—	 	
Interest expense	 	(227	)	(21	)	—	 	
Other, net	 	(1	)	—	 	1	 	
Total other income (expense), net	 	(189	)	(235	)	439	 	
Income (loss) before income taxes	 	(189	)	(235	)	502	 	
Provision (benefit) for income taxes	 	—	 	(2	)	9	 	
Net income (loss)	 	$	(189	)	$	(233	)	$	493	 	
 
The accompanying notes are an integral part of the registrant’s condensed financial information
 
F-95

 
GENON ENERGY, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
 
 	 	December 31,	 	
 	 	2011	 	2010	 	
 	 	(in millions)	 	
ASSETS	 	 	 	 	 	
Current Assets:	 	 	 	 	 	
Cash and cash equivalents	 	$	659	 	$	577	 	
Funds on deposit	 	33	 	319	 	
Receivables, net	 	—	 	8	 	
Receivable, net—affiliate	 	86	 	106	 	
Notes receivables—affiliate	 	1,190	 	3,238	 	
Total current assets	 	1,968	 	4,248	 	
Noncurrent Assets:	 	 	 	 	 	
Investments in affiliates	 	4,590	 	2,924	 	
Notes receivables—affiliate	 	1,003	 	1,003	 	
Other	 	104	 	106	 	
Total noncurrent assets	 	5,697	 	4,033	 	
Total Assets	 	$	7,665	 	$	8,281	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	
Current Liabilities:	 	 	 	 	 	
Current portion of long-term debt, net of discount	 	$	(2	)	$	282	 	
Accounts payable and accrued liabilities	 	17	 	37	 	
Taxes payable	 	25	 	25	 	
Other	 	33	 	33	 	
Total current liabilities	 	73	 	377	 	
Noncurrent Liabilities:	 	 	 	 	 	
Long-term debt, net of current portion	 	2,475	 	2,470	 	
Total noncurrent liabilities	 	2,475	 	2,470	 	
Commitments and Contingencies	 	 	 	 	 	
Stockholders’ Equity:	 	 	 	 	 	
Preferred stock, par value $.001 per share, authorized 125,000,000 shares, no shares issued at December 31, 2011 and 2010	 	—	 	—	 	
Common stock, par value $.001 per share, authorized 2.0 billion shares, issued 771,692,734 shares and 770,857,530 shares at December 31, 2011 and 2010, respectively	 	1	 	1	 	
Additional paid-in capital	 	7,449	 	7,432	 	
Accumulated deficit	 	(2,163	)	(1,974	)	
Accumulated other comprehensive loss	 	(170	)	(25	)	
Total stockholders’ equity	 	5,117	 	5,434	 	
Total Liabilities and Stockholders’ Equity	 	$	7,665	 	$	8,281	 	
 
The accompanying notes are an integral part of the registrant’s condensed financial information
 
F-96

 
GENON ENERGY, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
 
 	 	2011	 	2010	 	2009	 	
 	 	(in millions)	 	
Cash Flows from Operating Activities:	 	 	 	 	 	 	 	
Net cash provided by (used in) operating activities	 	$	(59	)	$	(39	)	$	165	 	
Cash Flows from Investing Activities:	 	 	 	 	 	 	 	
Cash acquired from RRI Energy, Inc.	 	—	 	689	 	—	 	
Issuance (repayment) of notes receivables—affiliate	 	137	 	(1,049	)	(94	)	
Cash retained by GenOn Energy Holdings	 	—	 	(1,432	)	—	 	
Capital contributions to subsidiaries	 	—	 	—	 	(4	)	
Restricted funds on deposit, net	 	286	 	(286	)	—	 	
Net cash provided by (used in) investing activities	 	423	 	(2,078	)	(98	)	
Cash Flows from Financing Activities:	 	 	 	 	 	 	 	
Proceeds from long-term debt	 	—	 	1,203	 	—	 	
Repayment of long-term debt	 	(285	)	—	 	—	 	
Debt issuance costs	 	—	 	(25	)	—	 	
Share repurchases	 	—	 	(11	)	(4	)	
Issuance (repayment) of debt—affiliate	 	—	 	3	 	(1	)	
Proceeds from exercises of stock options	 	3	 	1	 	—	 	
Net cash provided by (used in) financing activities	 	(282	)	1,171	 	(5	)	
Net Increase (Decrease) in Cash and Cash Equivalents	 	82	 	(946	)	62	 	
Cash and Cash Equivalents, beginning of year	 	577	 	1,523	 	1,461	 	
Cash and Cash Equivalents, end of year	 	$	659	 	$	577	 	$	1,523	 	
Supplemental Disclosures:	 	 	 	 	 	 	 	
Cash paid for interest, net of amounts capitalized	 	$	224	 	$	60	 	$	—	 	
Cash paid for income taxes (net of refunds received)	 	$	(3	)	$	(1	)	$	6	 	
Supplemental Disclosures for Non-Cash Investing and Financing Activities:	 	 	 	 	 	 	 	
Conversion to equity of notes receivables from subsidiaries	 	$	—	 	$	(87	)	$	(159	)	
Conversion to equity of notes payable to subsidiaries	 	$	—	 	$	3	 	$	—	 	
 
The accompanying notes are an integral part of the registrant’s condensed financial information
 
F-97

 
GENON ENERGY, INC. (PARENT)
NOTES TO REGISTRANTS’ CONDENSED FINANCIAL STATEMENTS
 
1. Background and Basis of Presentation
 
Background
 
The condensed parent company financial statements have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X, as the restricted net assets of GenOn Energy Inc.’s subsidiaries exceed 25 percent of the consolidated net assets of GenOn Energy, Inc. These statements should be read in conjunction with the consolidated statements and notes thereto of GenOn Energy, Inc.
 
GenOn, a Delaware corporation, was formed in August 2000 by CenterPoint (then known as Reliant Energy, Incorporated) in connection with the planned separation of its regulated and unregulated operations. CenterPoint transferred substantially all of its unregulated businesses, including the name Reliant Energy, to the company now named GenOn Energy, Inc. In May 2001, Reliant Energy (then known as Reliant Resources, Inc.) became a publicly traded company and in September 2002, CenterPoint distributed its remaining ownership of Reliant Energy’s common stock to its stockholders. RRI Energy changed its name from Reliant Energy, Inc. effective May 2, 2009 in connection with the sale of its retail business. GenOn changed its name from RRI Energy, Inc. effective December 3, 2010. The Company refers to GenOn Energy, Inc. and, except where the context indicates otherwise, its subsidiaries, after giving effect to the Merger.
 
Merger of Mirant and RRI Energy
 
On December 3, 2010, Mirant and RRI Energy completed the Merger. Upon completion of the Merger, RRI Energy Holdings, Inc., a direct and wholly- owned subsidiary of RRI Energy merged with and into Mirant, with Mirant continuing as the surviving corporation and a wholly-owned subsidiary of RRI Energy. Additionally, upon the closing of the Merger, RRI Energy was renamed GenOn.
 
During the third and fourth quarters of 2011, we recorded revisions to the provisional allocation of the purchase price at December 3, 2010 and accordingly revised amounts in our consolidated balance sheet at December 31, 2010 and our consolidated statements of operations for 2010. Our results of operations for the year ended December 31, 2010 have been retroactively amended for the revisions to the provisional allocation to decrease equity in income/loss of affiliates by $183 million due to a decrease in the gain on bargain purchase and to increase the net loss by the same amount.
 
See notes 1 and 2 for additional information on the Merger and note 6 for the related debt transactions in the consolidated financial statements of GenOn.
 
Basis of Presentation
 
Upon completion of the Merger, Mirant stockholders had a majority of the voting interest in the combined company. Although RRI Energy issued shares of RRI Energy common stock to Mirant stockholders to effect the Merger, the Merger is accounted for as a reverse acquisition under the acquisition method of accounting. Under the acquisition method of accounting, Mirant is treated as the accounting acquirer and RRI Energy is treated as the acquired company for financial reporting purposes. As such, the condensed financial statements of GenOn Energy, Inc. (parent) include the results of GenOn Energy, Inc. for the periods from December 3, 2010, and include the results of GenOn Energy Holdings (former parent) through December 2, 2010. The condensed financial statements presented herein for periods ended prior to the closing of the Merger (and any other
 
F-98

 
GENON ENERGY, INC. (PARENT)
NOTES TO REGISTRANTS’ CONDENSED FINANCIAL STATEMENTS (Continued)
 
1. Background and Basis of Presentation (Continued)
 
financial information presented herein with respect to such pre-merger dates, unless otherwise specified) are the condensed financial statements and other financial information of Mirant.
 
Equity in income/loss of affiliates consists of earnings of direct subsidiaries of GenOn Energy, Inc. (parent).
 
During 2011, 2010 and 2009, GenOn Energy, Inc. received cash dividends from its subsidiaries of $100 million, $112 million and $115 million, respectively.
 
Immaterial Misstatement of Post-Employment Benefits in Prior Periods
 
During 2011, we identified an under accrual of post-employment benefits relating to over ten years up to and through 2010. In those years, we did not recognize a liability for future expected costs of benefits for inactive employees who were unable to perform services because of a disability. For 2010, 2009, 2008 and 2007, our equity in income/loss of affiliates excluded an expense of $0, $1 million, $1 million and $1 million, respectively. Our net income/loss for these years was misstated by the same amounts. The misstatements had no effect on cash flows for any of the periods.
 
To correct the misstatement in 2010, we recorded the following immaterial adjustments to the 2010 financial statements presented in this Form 10-K: (a) a cumulative increase to accumulated deficit and decrease to stockholders’ equity of $13 million in the condensed balance sheet at December 31, 2010 and (b) a cumulative decrease to investments in affiliates and total noncurrent assets of $13 million in the condensed balance sheet at December 31, 2010. To correct the misstatement in 2009, we recorded the following immaterial adjustments to the 2009 financial statements presented in this Form 10-K: a decrease to equity in income of affiliates and net income of $1 million in the condensed statement of operations in 2009.
 
2. Long-Term Debt
 
For a discussion of GenOn Energy, Inc.’s long-term debt, see note 6 to GenOn’s consolidated financial statements. GenOn’s senior secured term loan, due 2017, with an outstanding balance of $691 million (excluding the debt discount of $6 million) at December 31, 2011, has two co-borrowers, GenOn Energy, Inc. and GenOn Americas. The debt is recorded at GenOn Americas and, although not included in its balance sheet as long-term debt, GenOn Energy, Inc. is an obligor thereunder.
 
Debt maturities of GenOn Energy, Inc. at December 31, 2011 are (in millions):
 
2012	 	$	—	 	
2013	 	—	 	
2014	 	575	 	
2015	 	—	 	
2016	 	—	 	
2017 and thereafter	 	1,950	 	
Total	 	$	2,525	 	
 
3. Commitments and Contingencies
 
At December 31, 2011, the parent company had $527 million of guarantees, which are included in note 10 to GenOn’s consolidated financial statements.
 
See notes 10 and 16 to GenOn’s consolidated financial statements for a detailed discussion of GenOn Energy, Inc.’s contingencies.
 
F-99

 
Schedule II
 
GENON ENERGY, INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
 
 	 	December 31, 2011, 2010 and 2009	 	
 	 	 	 	Additions	 	 	 	 	 	
Description	 	Balance at
Beginning
of Period	 	Charged
to
Income	 	Charged to
Other
Accounts	 	Deductions(1)	 	Balance at
End of
Period	 	
 	 	(in millions)	 	
Provision for uncollectible accounts (current)	 	 	 	 	 	 	 	 	 	 	 	
2011	 	$	7	 	$	9	 	$	—	 	$	(3	)	$	13	 	
2010	 	4	 	8	 	—	 	(5	)	7	 	
2009	 	13	 	9	 	—	 	(18	)	4	 	
Provision for uncollectible accounts (noncurrent)	 	 	 	 	 	 	 	 	 	 	 	
2011	 	$	15	 	$	36	 	$	—	 	$	(12	)	$	39	 	
2010	 	11	 	18	 	—	 	(14	)	15	 	
2009	 	42	 	13	 	—	 	(44	)	11	 	

(1)        Deductions in 2011, 2010 and 2009 consisted primarily of reversals of credit reserves for derivative contract assets.
 
F-100

Exhibit 99.2
 
GENON ENERGY, INC.
UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
AS OF SEPTEMBER 30, 2012
AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012 and 2011	 	
 	 	
Condensed Consolidated Statements of Operations (Unaudited) Three and Nine Months Ended September 30, 2012 and 2011	1	
 	 	
Condensed Consolidated Statements of Comprehensive Loss (Unaudited) Three and Nine Months Ended September 30, 2012 and 2011	2	
 	 	
Condensed Consolidated Balance Sheets (Unaudited) September 30, 2012 and December 31, 2011	3	
 	 	
Condensed Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, 2012 and 2011	4	
 	 	
Notes to Condensed Consolidated Financial Statements (Unaudited)	5	

 
GENON ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
 	 	Three Months Ended September 30,	 	Nine Months Ended September 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	
 	 	(in millions, except per share data)	 	
 	 	 	 	 	 	 	 	 	 	
Operating revenues (including unrealized gains (losses) of $(245), $49, $(204) and $(86), respectively)	 	$	755	 	$	1,080	 	$	1,997	 	$	2,706	 	
Cost of fuel, electricity and other products (including unrealized (gains) losses of $(58), $11, $25 and $(27), respectively)	 	346	 	526	 	930	 	1,317	 	
Gross Margin (excluding depreciation and amortization)	 	409	 	554	 	1,067	 	1,389	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	
Operations and maintenance	 	268	 	286	 	840	 	963	 	
Depreciation and amortization	 	91	 	96	 	269	 	272	 	
Impairment losses	 	47	 	133	 	47	 	133	 	
Gain on sales of assets, net	 	(1	)	(6	)	(9	)	(5	)	
Total operating expenses	 	405	 	509	 	1,147	 	1,363	 	
Operating Income (Loss)	 	4	 	45	 	(80	)	26	 	
Other Income (Expense), net:	 	 	 	 	 	 	 	 	 	
Interest expense	 	(86	)	(86	)	(260	)	(291	)	
Interest income	 	1	 	1	 	1	 	1	 	
Other, net	 	—	 	1	 	2	 	(21	)	
Total other expense, net	 	(85	)	(84	)	(257	)	(311	)	
Loss Before Income Taxes	 	(81	)	(39	)	(337	)	(285	)	
Provision for income taxes	 	4	 	1	 	8	 	4	 	
Net Loss	 	$	(85	)	$	(40	)	$	(345	)	$	(289	)	
 	 	 	 	 	 	 	 	 	 	
Basic and Diluted EPS:	 	 	 	 	 	 	 	 	 	
Basic EPS	 	$	(0.11	)	$	(0.05	)	$	(0.45	)	$	(0.37	)	
Diluted EPS	 	$	(0.11	)	$	(0.05	)	$	(0.45	)	$	(0.37	)	
 	 	 	 	 	 	 	 	 	 	
Weighted average shares outstanding	 	774	 	772	 	774	 	771	 	
Effect of dilutive securities	 	—	 	—	 	—	 	—	 	
Weighted average shares outstanding assuming dilution	 	774	 	772	 	774	 	771	 	
 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements
 
1

 
GENON ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)
 
 	 	Three Months Ended September 30,	 	Nine Months Ended September 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	
Net Loss	 	$	(85	)	$	(40	)	$	(345	)	$	(289	)	
Other Comprehensive Income (Loss), net of tax of $0:	 	 	 	 	 	 	 	 	 	
Unrealized losses:	 	 	 	 	 	 	 	 	 	
Cash flow hedges—interest rate swaps	 	(5	)	(39	)	(17	)	(50	)	
Available-for-sale securities	 	—	 	—	 	—	 	(1	)	
Pension and other postretirement benefits— actuarial losses, net	 	(9	)	—	 	(9	)	—	 	
Reclassifications to net loss:	 	 	 	 	 	 	 	 	 	
Cash flow hedges—interest rate swaps	 	(1	)	—	 	(1	)	—	 	
Pension and other postretirement benefits— actuarial losses, net	 	2	 	1	 	6	 	3	 	
Pension and other postretirement benefits— prior service credit, net	 	—	 	(1	)	(2	)	(3	)	
Other, net	 	—	 	—	 	1	 	—	 	
Other Comprehensive Loss	 	(13	)	(39	)	(22	)	(51	)	
Comprehensive Loss	 	$	(98	)	$	(79	)	$	(367	)	$	(340	)	
 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements
 
2

 
GENON ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
 
 	 	September 30, 2012	 	December 31, 2011	 	
 	 	(in millions)	 	
ASSETS	 	 	 	 	 	
Current Assets:	 	 	 	 	 	
Cash and cash equivalents	 	$	1,855	 	$	1,668	 	
Funds on deposit	 	261	 	422	 	
Receivables, net	 	294	 	357	 	
Derivative contract assets	 	636	 	999	 	
Inventories	 	447	 	563	 	
Prepaid rent and other expenses	 	182	 	167	 	
Total current assets	 	3,675	 	4,176	 	
Property, plant and equipment, gross	 	7,616	 	7,351	 	
Accumulated depreciation and amortization	 	(1,351	)	(1,160	)	
Property, Plant and Equipment, net	 	6,265	 	6,191	 	
Noncurrent Assets:	 	 	 	 	 	
Intangible assets, net	 	44	 	48	 	
Derivative contract assets	 	588	 	733	 	
Deferred income taxes	 	196	 	294	 	
Prepaid rent	 	413	 	386	 	
Other	 	394	 	441	 	
Total noncurrent assets	 	1,635	 	1,902	 	
Total Assets	 	$	11,575	 	$	12,269	 	
 	 	 	 	 	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	
Current Liabilities:	 	 	 	 	 	
Current portion of long-term debt	 	$	10	 	$	10	 	
Accounts payable and accrued liabilities	 	690	 	790	 	
Derivative contract liabilities	 	398	 	720	 	
Deferred income taxes	 	196	 	294	 	
Other	 	105	 	130	 	
Total current liabilities	 	1,399	 	1,944	 	
Noncurrent Liabilities:	 	 	 	 	 	
Long-term debt, net of current portion	 	4,361	 	4,122	 	
Derivative contract liabilities	 	184	 	131	 	
Pension and postretirement obligations	 	252	 	259	 	
Other	 	617	 	696	 	
Total noncurrent liabilities	 	5,414	 	5,208	 	
Commitments and Contingencies	 	 	 	 	 	
Stockholders’ Equity:	 	 	 	 	 	
Preferred stock, par value $.001 per share, authorized 125,000,000 shares, no shares issued at September 30, 2012 and December 31, 2011	 	—	 	—	 	
Common stock, par value $.001 per share, authorized 2.0 billion shares, issued 772,922,439 shares and 771,692,734 shares at September 30, 2012 and December 31, 2011, respectively	 	1	 	1	 	
Additional paid-in capital	 	7,461	 	7,449	 	
Accumulated deficit	 	(2,508	)	(2,163	)	
Accumulated other comprehensive loss	 	(192	)	(170	)	
Total stockholders’ equity	 	4,762	 	5,117	 	
Total Liabilities and Stockholders’ Equity	 	$	11,575	 	$	12,269	 	
 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements
 
3

 
GENON ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
 	 	Nine Months Ended September 30,	 	
 	 	2012	 	2011	 	
 	 	(in millions)	 	
Cash Flows from Operating Activities:	 	 	 	 	 	
Net loss	 	$	(345	)	$	(289	)	
Adjustments to reconcile net loss and changes in operating assets and liabilities to net cash provided by operating activities:	 	 	 	 	 	
Depreciation and amortization	 	269	 	272	 	
Impairment losses	 	47	 	133	 	
Amortization of acquired contracts	 	(36	)	(25	)	
Gain on sales of assets, net	 	(9	)	(5	)	
Unrealized losses	 	229	 	59	 	
Stock-based compensation expense	 	15	 	11	 	
Excess materials and supplies inventory reserve	 	35	 	—	 	
Lower of cost or market inventory adjustments	 	82	 	2	 	
Loss on early extinguishment of debt	 	—	 	23	 	
Advance settlement of out-of-market contract obligation	 	(20	)	—	 	
Reversal of Potomac River settlement obligation	 	(31	)	—	 	
Large scale remediation and settlement costs	 	(3	)	30	 	
Other, net	 	13	 	10	 	
Changes in operating assets and liabilities	 	20	 	61	 	
Total adjustments	 	611	 	571	 	
Net cash provided by operating activities	 	266	 	282	 	
Cash Flows from Investing Activities:	 	 	 	 	 	
Capital expenditures	 	(486	)	(328	)	
Proceeds from the sales of assets	 	14	 	18	 	
Restricted funds on deposit and other, net	 	158	 	1,396	 	
Net cash provided by (used in) investing activities	 	(314	)	1,086	 	
Cash Flows from Financing Activities:	 	 	 	 	 	
Proceeds from long-term debt	 	243	 	50	 	
Repayment of long-term debt	 	(8	)	(2,075	)	
Other, net	 	—	 	1	 	
Net cash provided by (used in) financing activities	 	235	 	(2,024	)	
Net Increase (Decrease) in Cash and Cash Equivalents	 	187	 	(656	)	
Cash and Cash Equivalents, beginning of period	 	1,668	 	2,402	 	
Cash and Cash Equivalents, end of period	 	$	1,855	 	$	1,746	 	
 	 	 	 	 	 	
Supplemental Disclosures:	 	 	 	 	 	
Cash paid for interest, net of amounts capitalized	 	$	174	 	$	225	 	
Cash paid for income taxes (net of refunds received)	 	$	12	 	$	(6	)	
 
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements
 
4

 
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
 
1.  Description of Business and Accounting and Reporting Policies
 
Background
 
We are a wholesale generator with approximately 22,000 MW of net electric generating capacity located, in many cases, near major metropolitan load centers in the PJM, MISO, Northeast and Southeast regions, and California.  We also operate integrated asset management and proprietary trading operations.  See note 2 for a discussion of generating facilities in the Eastern PJM, Western PJM/MISO and California segments that have units we deactivated in 2012 or expect to deactivate in 2013 and 2015.
 
We were formed as a Delaware corporation in August 2000.  “We,” “us,” “our” and “GenOn” refer to GenOn Energy, Inc. and, except where the context indicates otherwise, its subsidiaries, after giving effect to the Mirant/RRI Merger.
 
Proposed Merger with NRG
 
On July 20, 2012, we entered into the NRG Merger Agreement with NRG Energy, Inc. and a direct wholly-owned subsidiary of NRG.  Upon the terms and subject to the conditions set forth in the NRG Merger Agreement, which has been approved by the boards of directors of GenOn and NRG, a wholly-owned subsidiary of NRG will merge with and into GenOn, with GenOn continuing as the surviving corporation and a wholly owned subsidiary of NRG.
 
Upon closing of the NRG Merger, each issued and outstanding share of our common stock will automatically convert into the right to receive 0.1216 shares of common stock of NRG based on the exchange ratio.  All outstanding stock options (other than options granted in 2012) will immediately vest and all outstanding stock options will generally convert upon completion of the NRG Merger into stock options with respect to NRG common stock, after giving effect to the exchange ratio.  In addition, all outstanding restricted stock units (other than restricted stock units granted in 2012) will immediately vest and all outstanding restricted stock units will be exchanged for the NRG Merger consideration.  All outstanding stock options and restricted stock units granted in 2012 will vest at the holder’s termination date if the termination is as a result of the NRG Merger and within two years of the closing date.  See note 7.
 
The NRG Merger is intended to qualify as a tax-free reorganization under the IRC, as amended, so that none of GenOn, NRG or any of our stockholders generally will recognize any gain or loss in the transaction, except with respect to cash received in lieu of fractional shares of NRG common stock.
 
Completion of the NRG Merger is contingent upon, among other things, (a) approvals by NRG stockholders of the issuance of NRG common stock in the NRG Merger and the approval and adoption of the amendment to NRG’s certificate of incorporation to allow the size of NRG’s board of directors to be increased to 16 in connection with the closing of the NRG Merger at a meeting to be held on November 9, 2012, (b) adoption of the NRG Merger Agreement by our stockholders at a meeting to be held on November 9, 2012, (c) effectiveness of an NRG registration statement on Form S-4, which occurred on October 5, 2012, and approval of the New York Stock Exchange listing for the NRG common stock to be issued in the NRG Merger, (d) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, which occurred on September 21, 2012, and (e) receipt of all required regulatory approvals, including approvals from the Public Utility Commission of Texas, which occurred on October 25, 2012, the FERC and the New York Public Service Commission.
 
We and NRG are also subject to restrictions on our respective ability to solicit alternative acquisition proposals and to provide information to, and engage in discussion with, third parties, except under limited circumstances to permit our or NRG’s board of directors to comply with their respective fiduciary duties.  The NRG Merger Agreement contains termination rights for both us and NRG and further provides that, upon termination of the NRG Merger Agreement under specified circumstances, NRG may be required to pay a termination fee of $120 million to us and we may be required to pay NRG a termination fee of $60 million.
 
5

 
In addition, at NRG’s request and upon the terms and subject to the conditions of the NRG Merger Agreement, we will commence a “change of control” tender offer for each series of our outstanding notes due 2014, 2017, 2018 and 2020, conditioned on the completion of the NRG Merger (the Change in Control Offers).  In addition, upon the terms and subject to the conditions of the NRG Merger Agreement, NRG may, at its election following consultation with us, commence a tender offer for cash or an exchange offer for securities for all or any portion of our outstanding notes due 2014, 2017, 2018 and 2020, conditioned on the completion of the NRG Merger (together with the Change in Control Offers, the Debt Offers).  NRG may, upon the terms and subject to the conditions of the NRG Merger Agreement, elect to also undertake a consent solicitation to alter the terms of any of our remaining notes due 2014, 2017, 2018 and 2020 outstanding after such tender or exchange offers.  NRG intends to fund the Debt Offers and the related fees, commissions and expenses with a combination of funds available at each company (including funds available under existing credit facilities) and, to the extent necessary, new financing for which NRG obtained commitment letters from Credit Suisse Securities (USA) LLC and Morgan Stanley Senior Funding, Inc. to fund up to $1.6 billion under a new senior secured term loan facility, to the extent such funds are necessary to consummate the Debt Offers.  On October 19, 2012, NRG elected to amend the commitment letters to permanently reduce the aggregate commitment amount to $1.0 billion and NRG indicated its intent to fund additional requirements, if any, from its available liquidity including cash on hand and credit facilities.  NRG has agreed to use reasonable best efforts to obtain the financing, to the extent required, and we have agreed to use reasonable best efforts to cooperate in NRG’s efforts to obtain the financing.  There are no financing conditions to the NRG Merger and the NRG Merger is not conditioned upon the completion of the Debt Offers or the funding of the financing.
 
In addition, we will experience an ownership change under the applicable tax rules as a result of the NRG Merger.  Immediately following the NRG Merger, we and NRG will be members of the same consolidated federal income tax group.  The ability of this consolidated tax group to deduct the pre-NRG Merger NOL carry forwards of GenOn against the post-merger taxable income of the group will be substantially limited as a result of the ownership change.
 
We anticipate completing the NRG Merger by the first quarter of 2013.  Prior to the completion of the NRG Merger, we and NRG will continue to operate as independent companies.  Except for specific references to the pending NRG Merger, the disclosures contained in this report on Form 10-Q relate solely to us.  Information concerning the proposed NRG Merger is included in a joint proxy statement/prospectus contained in the registration statement on Form S-4, which NRG filed with the Securities and Exchange Commission in connection with the NRG Merger on October 5, 2012.
 
Basis of Presentation
 
The consolidated interim financial statements and notes (interim financial statements) are unaudited, omit certain disclosures and should be read in conjunction with our audited consolidated financial statements and notes in our 2011 Annual Report on Form 10-K.  These interim financial statements have been prepared in accordance with GAAP from records maintained by us.  All significant intercompany accounts and transactions have been eliminated in consolidation.  The interim financial statements reflect all normal recurring adjustments necessary, in management’s opinion, to present fairly our financial position and results of operations for the reported periods.  Amounts reported for interim periods may not be indicative of a full year period because of seasonal fluctuations in demand for electricity and energy services, changes in commodity prices, and changes in regulations, timing of maintenance and other expenditures, dispositions, changes in interest expense and other factors.
 
At September 30, 2012 and December 31, 2011, substantially all of our subsidiaries are wholly-owned and located in the United States.  We do not consolidate five power generating facilities, which are under operating leases; a 50% equity investment in a cogeneration facility; and a VIE (MC Asset Recovery) for which we are not the primary beneficiary.  See note 11 for further discussion of MC Asset Recovery.
 
The preparation of interim financial statements in conformity with GAAP requires management to make various estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent
 
6

 
assets and liabilities at the date of the interim financial statements and the reported amounts of revenues and expenses during the period.  Actual results could differ from those estimates.  Our significant estimates include:
 
·                 estimating the fair value of certain derivative contracts;
 
·                 estimating the inventory reserve;
 
·                 estimating future taxable income in evaluating the deferred tax asset valuation allowance;
 
·                 estimating the useful lives of long-lived assets;
 
·                 estimating future costs and the valuation of asset retirement obligations;
 
·                 estimating future cash flows in determining impairments of long-lived assets and definite-lived intangible assets;
 
·                 estimating the fair value and expected return on plan assets, discount rates and other actuarial assumptions used in estimating pension and other postretirement benefit plan liabilities; and
 
·                 estimating losses to be recorded for contingent liabilities.
 
We evaluate events that occur after the balance sheet date but before the financial statements are issued for potential recognition or disclosure.  Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed herein.
 
Our results of operations for the three and nine months ended September 30, 2011 have been retroactively amended for the revisions to the provisional purchase price allocation in connection with the Mirant/RRI Merger.
 
We had disclosed in our 2011 Annual Report on Form 10-K that it was possible that RRI Energy had experienced an ownership change under the applicable tax rules as a result of the Mirant/RRI Merger.  Based on further inquiries, we do not think that RRI Energy experienced an ownership change as a result of the Mirant/RRI Merger or following the Mirant/RRI Merger through December 31, 2011.
 
7

 
Funds on Deposit
 
Funds on deposit are included in current and noncurrent assets in the consolidated balance sheets.  Funds on deposit include the following:
 
 	 	September 30,	 	December 31,	 	
 	 	2012	 	2011	 	
 	 	(in millions)	 	
 	 	 	 	 	 	
Cash collateral posted — energy trading and marketing	 	$	150	 	$	185	 	
Cash collateral posted — other operating activities(1) 	 	59	 	39	 	
Cash collateral posted — surety bonds(2) 	 	34	 	34	 	
GenOn Marsh Landing development project cash collateral posted(3) 	 	80	 	131	 	
Environmental compliance deposits(4) 	 	35	 	34	 	
GenOn Mid-Atlantic restricted cash(5) 	 	—	 	166	 	
Other	 	36	 	16	 	
Total current and noncurrent funds on deposit	 	394	 	605	 	
Less: Current funds on deposit	 	261	 	422	 	
Total noncurrent funds on deposit	 	$	133	 	$	183	 	

(1)        Includes $32 million related to the Potomac River obligation under the 2008 agreement with the City of Alexandria, which were returned to us in October 2012.  See note 2.
(2)        Represents cash under surety bonds posted primarily with the PADEP related to environmental obligations.
(3)        Represents cash-collateralized letters of credit to support the Marsh Landing development project.
(4)        Represents deposits with the State of Pennsylvania to guarantee our obligations related to future closures of coal ash landfill sites and with the State of New Jersey to satisfy our obligations to remediate site contamination.  See note 11.
(5)        Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation, which was settled in June 2012.  See note 11.
 
Inventories
 
Inventories were comprised of the following:
 
 	 	September 30,
2012	 	December 31,
2011	 	
 	 	(in millions)	 	
 	 	 	 	 	 	
Fuel inventory:	 	 	 	 	 	
Coal	 	$	153	 	$	229	 	
Fuel oil	 	87	 	108	 	
Natural gas	 	—	 	1	 	
Other	 	3	 	5	 	
Materials and supplies(1)	 	169	 	201	 	
Purchased emissions allowances	 	35	 	19	 	
Total inventories	 	$	447	 	$	563	 	

(1)        Amount is net of an inventory reserve of $35 million and $0 at September 30, 2012 and December 31, 2011, respectively.  See note 2.
 
During the three months ended September 30, 2012 and 2011, we recorded $17 million and $1 million, respectively, and during the nine months ended September 30, 2012 and 2011, we recorded $82 million and $2 million, respectively, for lower of average cost or market valuation adjustments in cost of fuel, electricity and other products.
 
8

 
Capitalization of Interest Cost
 
We incurred the following interest costs:
 
 	 	Three Months Ended September 30,	 	Nine Months Ended September 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	
Total interest costs	 	$	96	 	$	91	 	$	286	 	$	301	 	
Capitalized and included in property, plant and equipment, net	 	(10	)	(5	)	(26	)	(10	)	
Interest expense	 	$	86	 	$	86	 	$	260	 	$	291	 	
 
The amounts of capitalized interest above include interest accrued.  During the three months ended September 30, 2012 and 2011, cash paid for interest was $17 million and $16 million, respectively, of which $8 million and $4 million, respectively, were capitalized.  During the nine months ended September 30, 2012 and 2011, cash paid for interest was $197 million and $234 million, respectively, of which $23 million and $9 million, respectively, were capitalized.
 
Guarantees and Indemnifications
 
We generally conduct business through various operating subsidiaries which enter into contracts as part of their business activities.  In certain instances, the contractual obligations of such subsidiaries are guaranteed by, or otherwise supported by, us or another of our subsidiaries, including by letters of credit issued under the GenOn credit facilities.  See note 5.
 
In addition, we, including our subsidiaries, enter into various contracts that include indemnification and guarantee provisions.  Examples of these contracts include financing and lease arrangements, purchase and sale agreements, agreements to purchase or sell commodities, construction agreements and agreements with vendors.  Although the primary obligation under such contracts is to pay money or render performance, such contracts may include obligations to indemnify the counterparty for damages arising from the breach thereof and, in certain instances, other existing or potential liabilities.  In many cases, our maximum potential liability cannot be estimated because some of the underlying agreements contain no limits on potential liability.
 
We have guaranteed some non-qualified benefits of CenterPoint’s existing retirees at September 20, 2002.  The estimated maximum potential amount of future payments under the guarantee is $54 million at September 30, 2012 and $3 million is recorded in the consolidated balance sheet for this item.
 
Recently Adopted Accounting Guidance
 
Fair Value Measurement and Disclosure.  We adopted FASB accounting guidance for the first quarter of 2012 that requires disclosure of the following:
 
·                 quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy;
 
·                 for those fair value measurements categorized within Level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and
 
·                 the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.
 
See note 4 for these additional disclosures.
 
9

 
Comprehensive Income.  We adopted FASB accounting guidance for the first quarter of 2012 that requires companies to report the components of comprehensive income in either (a) a continuous statement of comprehensive income or (b) two separate but consecutive statements.  The guidance does not change the items that must be reported in comprehensive income.  See the consolidated statements of comprehensive loss and note 9.
 
New Accounting Guidance Not Yet Adopted at September 30, 2012
 
Balance Sheet Offsetting.  In December 2011, the FASB issued updated guidance to provide enhanced disclosures such that users of the financial statements will be able to better evaluate the effect or potential effect of netting arrangements in the balance sheet.  The guidance requires improved information about financial instruments and derivative instruments that are either offset according to specific guidance or subject to an enforceable master netting agreement or similar arrangement.  The disclosures will provide both net and gross information for these assets and liabilities.  Although we do not currently elect to offset assets and liabilities within the scope of the guidance, expanded disclosures will be required starting for the first quarter of 2013, along with retrospective presentation of prior periods.
 
2.  Retirements, Mothballing or Long-Term Protective Layup of Generating Facilities
 
Facilities Announced in 2012
 
We are subject to extensive environmental regulation by federal, state and local authorities under a variety of statutes, regulations and permits that address discharges into the air, water and soil, and the proper handling of solid, hazardous and toxic materials and waste.  Complying with increasingly stringent environmental requirements involves significant capital and operating expenses.  To the extent forecasted returns on investments necessary to comply with environmental regulations are insufficient for a particular facility, we plan to deactivate that facility.  In determining the forecasted returns on investments, we factor in forecasted energy and capacity prices, expected capital expenditures, operating costs, property taxes and other factors.  We deactivated the following coal-fired units at the referenced times:  Niles unit 2 (108 MW) June 2012, Niles unit 1 (109 MW) October 2012, Elrama units 1-3 (289 MW) mothballed June 2012 (plan to retire in March 2014) and Elrama unit 4 (171 MW) mothballed October 2012 (plan to retire in March 2014).  We expect to deactivate the following generating capacity, primarily coal-fired units, at the referenced times:  Portland (401 MW) January 2015, Gilbert unit 8 (90 MW) January 2015, Avon Lake (732 MW) April 2015, New Castle (330 MW) April 2015, Titus (243 MW) April 2015, Shawville (597 MW) place in long-term protective layup in April 2015 and Glen Gardner (160 MW) May 2015.  We filed for RMR arrangements for Niles unit 1 and Elrama unit 4 that were in effect from June 1 through September 30, 2012.  These RMR arrangements are subject to final FERC rulings.
 
Potomac River Generating Facility
 
During 2011, we entered into an agreement with the City of Alexandria, Virginia to remove permanently from service our 482 MW Potomac River generating facility. The agreement, which amends our Project Schedule and Agreement, dated July 2008 with the City of Alexandria, provides for the retirement of the Potomac River generating facility on October 1, 2012, subject to the determination of PJM that the retirement of the facility will not affect reliability and the consent of PEPCO.  PJM made the necessary determination and in June 2012 PEPCO gave its consent.  As a result, the Potomac River generating facility was retired in October 2012.  Upon retirement of the Potomac River generating facility, all funds in the escrow account ($32 million) established under the July 2008 agreement were distributed to us in October 2012.  We therefore reversed $31 million and $1 million of the previously recorded obligation under the 2008 agreement with the City of Alexandria as a reduction in operations and maintenance expense during the second and fourth quarters of 2012, respectively.
 
Contra CostaGenerating Facility
 
We entered into an agreement with PG&E in September 2009 for 674 MW at Contra Costa for the period from November 2011 through April 2013.  At the end of the agreement, and subject to any necessary regulatory approvals, we have agreed to retire the Contra Costa facility.
 
10

 
Expenses, Property, Plant and Equipment, and Materials and Supplies Inventory Related to Deactivations
 
In connection with our decision to deactivate the generating facilities, we evaluated our materials and supplies inventory and determined that we have excess inventory.  We established a reserve of $35 million (or $(0.04) per basic share) recorded to operations and maintenance expense during the first quarter of 2012 relating to our excess inventory.  We will continue to monitor the inventory balances and could make changes to the reserve in the future.  At September 30, 2012, the aggregate carrying value of property, plant and equipment, net and materials and supplies inventory, net for the generating facilities with an aggregate of 4,386 MW which we announced would be deactivated between 2012 and 2015 was $129 million and $25 million, respectively.  In addition to the excess materials and supplies inventory reserve recorded in the first quarter, we incurred $8 million and $11 million during the three and nine months ended September 30, 2012, respectively for costs to deactivate generating facilities, which is included in operations and maintenance expense.  We expect to incur additional costs in the future in connection with the deactivations, such as severance and other plant shutdown costs.
 
If market conditions and/or environmental and regulatory factors or assumptions change in the future, forecasted returns on investments necessary to comply with environmental regulations could change resulting in possible incremental investments if returns improve or deactivation of additional generating units or facilities if returns deteriorate.  Such deactivations could result in additional charges, including impairments, severance costs and other plant shutdown costs.
 
3.  Long-Lived Assets Impairments
 
Background
 
On July 20, 2012, we entered into the NRG Merger Agreement with NRG Energy, Inc. and a direct wholly-owned subsidiary of NRG.  We viewed the execution of the NRG Merger Agreement as a triggering event under accounting guidance and evaluated our long-lived assets for impairment.
 
For purposes of impairment testing, a long-lived asset must be grouped at the lowest level of identifiable cash flows.  Each of our generating facilities is viewed as an individual asset group.  Upon completion of the assessment, we determined that the Portland and Titus generating facilities were impaired at September 30, 2012, as the carrying values exceeded the undiscounted cash flows.
 
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Assumptions and Results
 
Our review of the long-lived assets included assumptions about the following: (a) electricity, fuel and emissions prices, (b) capacity prices, (c) impact of environmental regulations, including costs of CO 2  allowances under a potential cap-and-trade program, (d) timing and extent of generating capacity additions and retirements and (e) future capital expenditure requirements related to the generating facilities.
 
Our assumptions related to future prices of electricity, fuel, emissions allowances, and capacity were based on observable market prices to the extent available.  Longer term power and capacity prices were derived from proprietary fundamental market modeling and analysis.  The long-term capacity prices were based on estimated revenue requirements to incentivize new generation when needed to maintain reliability standards.  For markets with established capacity markets, such as PJM, these estimates are generally consistent with the current structures.  The assumptions regarding electricity demand were based on forecasts available from each ISO or NERC region, as applicable.  Assumptions for generating capacity additions and retirements included publicly available announcements, which take into account renewable sources of electricity, as well as the need for capacity to maintain reliability in the longer term.  In addition, we previously announced our plans for deactivation of the Portland and Titus generating facilities.  See note 2.
 
We recorded impairment losses of $37 million and $10 million during the three months ended September 30, 2012 in the consolidated statement of operations to reduce the carrying values of the Portland and Titus generating facilities, respectively, to their estimated fair values.
 
The following table sets forth by level within the fair value hierarchy our assets that were accounted for at fair value on a non-recurring basis.  All of our assets that were measured at fair value as a result of impairment losses recorded during the current period were categorized in Level 3 at September 30, 2012:
 
 	 	Fair Value at September 30, 2012	 	
 	 	Quoted Prices in
Active Markets
for
Identical Assets
(Level 1)	 	Significant
Other
Observable
Inputs
(Level 2)	 	Significant
Other
Unobservable
Inputs
(Level 3)	 	Total	 	Loss
Included
in Earnings	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Portland	 	$	—	 	$	—	 	$	17	 	$	17	 	$	37	 	
Titus	 	—	 	—	 	15	 	15	 	10	 	
Total	 	$	—	 	$	—	 	$	32	 	$	32	 	$	47	 	
 
4.  Financial Instruments
 
Derivatives and Hedging Activities
 
In connection with the business of generating electricity, we are exposed to energy commodity price risk associated with the acquisition of fuel and emissions allowances needed to generate electricity, the price of electricity produced and sold, and the fair value of fuel inventories.  Through our asset management activities, we enter into a variety of exchange-traded and OTC energy and energy-related derivative financial instruments, such as forward contracts, futures contracts, option contracts and financial swap agreements to manage exposure to commodity price risks.  These contracts have varying terms and durations, which range from a few days to years, depending on the instrument.  Our proprietary trading activities also utilize similar derivative contracts in markets where we have a physical presence to attempt to generate incremental gross margin.  Our fuel oil management activities use derivative financial instruments to hedge economically the fair value of physical fuel oil inventories, optimize the approximately two million barrels of storage capacity that we own, and attempt to profit from market opportunities related to timing and/or differences in the pricing of various products.  The open positions in our trading activities comprising proprietary trading and fuel oil management activities expose us to risks associated with changes in energy commodity prices.
 
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Derivative financial instruments are recorded in the consolidated balance sheets at fair value, except for derivative contracts that qualify for and for which we have elected the normal purchase or normal sale exceptions, which are not reflected in the consolidated balance sheet or results of operations prior to accrual of the settlement.  We present our derivative contract assets and liabilities on a gross basis (regardless of master netting arrangements with the same counterparty).  Cash collateral amounts are also presented on a gross basis.
 
During the second quarter of 2012, we could no longer assert that physical delivery was probable for the remaining coal agreements for which we had elected the normal purchase exception.  As such, the normal purchase exception was removed, and we are required to apply fair value accounting to these contracts in the current period and prospectively.
 
If certain criteria are met, a derivative financial instrument may be designated as a fair value hedge or cash flow hedge.  In 2010, GenOn Marsh Landing entered into interest rate protection agreements (interest rate swaps) in connection with its project financing, which have been designated as cash flow hedges.  GenOn Marsh Landing entered into the interest rate swaps to reduce the risks with respect to the variability of the interest rates for the term loan.  With the exception of these interest rate swaps, we did not have any other derivative financial instruments designated as fair value or cash flow hedges for accounting purposes during the nine months ended September 30, 2012 or 2011.
 
The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive loss, net of tax, to the extent the contracts are, or have been, effective as hedges, until the forecasted transactions affect earnings.  We record immediately into earnings the ineffective portion of changes in fair value of cash flow hedges.
 
Derivative financial instruments designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item.  If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in our results of operations.  If it becomes probable that a forecasted transaction will not occur, we immediately recognize the related deferred gains or losses in our results of operations.  Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated.
 
For our derivative financial instruments that have not been designated as cash flow hedges for accounting purposes, changes in such instruments’ fair values are recognized currently in earnings.  Our derivative financial instruments are categorized based on the business objective the instrument is expected to achieve:  asset management or trading, which includes proprietary trading and fuel oil management.  For asset management activities, changes in fair value and settlement of derivative financial instruments used to hedge electricity economically are reflected in operating revenue and changes in fair value and settlement of derivative financial instruments used to hedge fuel economically are reflected in cost of fuel, electricity and other products in the consolidated statements of operations.  Changes in the fair value and settlements of derivative financial instruments for proprietary trading and fuel oil management activities are recorded on a net basis as operating revenue in the consolidated statements of operations.
 
We also consider risks associated with interest rates, counterparty credit and our own non-performance risk when valuing derivative financial instruments.  The nominal value of the derivative contract assets and liabilities is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the transactions being valued.
 
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The following table presents the fair value of derivative financial instruments:
 
 	 	Derivative Contract Assets	 	Derivative Contract Liabilities	 	Net Derivative
Contract	 	
 	 	Current	 	Long-Term	 	Current	 	Long-Term	 	Assets (Liabilities)	 	
 	 	(in millions)	 	
September 30, 2012	 	 	 	 	 	 	 	 	 	 	 	
Commodity Contracts:	 	 	 	 	 	 	 	 	 	 	 	
Asset management	 	$	462	 	$	579	 	$	(222	)	$	(129	)	$	690	 	
Trading activities	 	174	 	9	 	(170	)	(11	)	2	 	
Total commodity contracts	 	636	 	588	 	(392	)	(140	)	692	 	
Interest Rate Contracts	 	—	 	—	 	(6	)	(44	)	(50	)	
Total derivatives	 	$	636	 	$	588	 	$	(398	)	$	(184	)	$	642	 	
 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2011	 	 	 	 	 	 	 	 	 	 	 	
Commodity Contracts:	 	 	 	 	 	 	 	 	 	 	 	
Asset management	 	$	538	 	$	730	 	$	(255	)	$	(97	)	$	916	 	
Trading activities	 	461	 	3	 	(464	)	(3	)	(3	)	
Total commodity contracts	 	999	 	733	 	(719	)	(100	)	913	 	
Interest Rate Contracts	 	—	 	—	 	(1	)	(31	)	(32	)	
Total derivatives	 	$	999	 	$	733	 	$	(720	)	$	(131	)	$	881	 	
 
The following table presents the net gains (losses) for derivative financial instruments recognized in income in the consolidated statements of operations:
 
 	 	Three Months Ended September 30,	 	
 	 	2012	 	2011	 	
Derivatives Not Designated as Hedging Instruments	 	Operating
Revenues	 	Cost of Fuel,
Electricity and
Other Products	 	Operating
Revenues	 	Cost of Fuel,
Electricity and
Other Products	 	
 	 	(in millions)	 	
Asset Management Commodity Contracts:	 	 	 	 	 	 	 	 	 	
Unrealized	 	$	(242	)	$	58	 	$	38	 	$	(11	)	
Realized(1)(2) 	 	102	 	(14	)	54	 	(27	)	
Total asset management	 	$	(140	)	$	44	 	$	92	 	$	(38	)	
 	 	 	 	 	 	 	 	 	 	
Trading Commodity Contracts:	 	 	 	 	 	 	 	 	 	
Unrealized	 	$	(3	)	$	—	 	$	11	 	$	—	 	
Realized(1)(2) 	 	8	 	—	 	(13	)	—	 	
Total trading	 	$	5	 	$	—	 	$	(2	)	$	—	 	
 	 	 	 	 	 	 	 	 	 	
Total derivatives	 	$	(135	)	$	44	 	$	90	 	$	(38	)	

(1)        Represents the total cash settlements of derivative financial instruments during each reporting period (composed of the sum of the quarterly settlements) that existed at the beginning of each respective period.
(2)        Excludes settlement value of fuel contracts classified as inventory.
 
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 	 	Nine Months Ended September 30,	 	
 	 	2012	 	2011	 	
Derivatives Not Designated as Hedging Instruments	 	Operating
Revenues	 	Cost of Fuel,
Electricity and
Other Products	 	Operating
Revenues	 	Cost of Fuel,
Electricity and
Other Products	 	
 	 	(in millions)	 	
Asset Management Commodity Contracts:	 	 	 	 	 	 	 	 	 	
Unrealized	 	$	(205	)	$	(25	)	$	(85	)	$	27	 	
Realized(1)(2) 	 	428	 	(42	)	194	 	(84	)	
Total asset management	 	$	223	 	$	(67	)	$	109	 	$	(57	)	
 	 	 	 	 	 	 	 	 	 	
Trading Commodity Contracts:	 	 	 	 	 	 	 	 	 	
Unrealized	 	$	1	 	$	—	 	$	(1	)	$	—	 	
Realized(1)(2) 	 	3	 	—	 	(8	)	—	 	
Total trading	 	$	4	 	$	—	 	$	(9	)	$	—	 	
 	 	 	 	 	 	 	 	 	 	
Total derivatives	 	$	227	 	$	(67	)	$	100	 	$	(57	)	

(1)        Represents the total cash settlements of derivative financial instruments during each reporting period (composed of the sum of the quarterly settlements) that existed at the beginning of each respective period.
(2)        Excludes settlement value of fuel contracts classified as inventory.
 
The following table presents the losses on the interest rate swaps designated as cash flow hedges in the consolidated statements of operations and comprehensive income/loss:
 
 	 	Three Months Ended September 30,	 	Nine Months Ended September 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	
Recognized in earnings on derivatives (1)(2)  	 	$	—	 	$	—	 	$	—	 	$	—	 	
Valuation adjustments(3) 	 	—	 	4	 	—	 	4	 	

(1)        Represents the ineffective portion of the interest rate swaps classified as cash flow hedges and recorded in interest expense.
(2)        All of the forecasted transactions (future interest payments) were deemed probable of occurring; therefore, no cash flow hedges were discontinued and no amount was recognized in our results of operations as a result of discontinued cash flow hedges.
(3)        Represents the default risk of the counterparties to these transactions and our own non-performance risk.  The effect of these valuation adjustments is recorded in interest expense.
 
At September 30, 2012, the maximum length of time we are hedging our exposure to the variability in future cash flows that may result from changes in interest rates is 11 years.  Because a significant portion of the interest expense incurred by GenOn Marsh Landing during construction will be capitalized, amounts included in accumulated other comprehensive loss associated with construction period interest payments will be reclassified to property, plant and equipment and depreciated over the expected useful life of the Marsh Landing generating facility once it commences commercial operations in mid-2013.  Actual amounts reclassified into earnings could vary from the amounts currently recorded as a result of future changes in interest rates.  See note 9 for the effect of the cash flow hedges in comprehensive income/loss.
 
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The following tables present the notional quantity on long (short) positions for derivative financial instruments:
 
 	 	Notional Volumes at September 30, 2012	 	
Derivative Instruments	 	Derivative
Contract
Assets	 	Derivative
Contract
Liabilities	 	Net
Derivative
Contracts	 	
 	 	(in millions)	 	
Commodity Contracts (in equivalent MWh):	 	 	 	 	 	 	 	
Power(1) 	 	(16	)	(53	)	(69	)	
Natural gas	 	2	 	(2	)	—	 	
Coal	 	(1	)	18	 	17	 	
Interest Rate Contracts (in dollars)(2) 	 	—	 	475	 	475	 	

(1)        Includes MWh equivalent of natural gas transactions used to hedge power economically.
(2)        Beginning in mid-2013, the notional amount will increase to $500 million.
 
 	 	Notional Volumes at December 31, 2011	 	
Derivative Instruments	 	Derivative
Contract
Assets	 	Derivative
Contract
Liabilities	 	Net
Derivative
Contracts	 	
 	 	(in millions)	 	
Commodity Contracts (in equivalent MWh):	 	 	 	 	 	 	 	
Power(1) 	 	(130	)	73	 	(57	)	
Natural gas	 	(8	)	10	 	2	 	
Coal	 	3	 	12	 	15	 	
Interest Rate Contracts (in dollars)(2) 	 	—	 	475	 	475	 	

(1)        Includes MWh equivalent of natural gas transactions used to hedge power economically.
(2)        Beginning in mid-2013, the notional amount will increase to $500 million.
 
Fair Value Measurements
 
Fair Value Hierarchy and Valuation Techniques.  We apply recurring fair value measurements to our financial assets and liabilities.  In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques.  The fair value measurement inputs we use vary from readily observable prices for exchange-traded instruments to price curves that cannot be validated through external pricing sources.  Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:
 
Level 1:                    Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date.  This category primarily includes natural gas and crude oil futures traded on the NYMEX and swaps cleared against NYMEX prices.  Interest bearing funds and trading securities are also valued using Level 1 inputs.
 
Level 2:                    Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data.  This category primarily includes non-exchange traded derivatives such as OTC forwards, swaps and options, and certain energy derivative instruments that are cleared and settled through exchanges.  This category also includes interest rate swaps.
 
Level 3:                    Representscommodity derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources (such as implied volatilities and correlations).  The OTC, complex or structured derivative instruments that are transacted in less liquid markets with limited pricing information are included in Level 3.  Examples are coal contracts, power transmission congestion products, less liquid power and natural gas contracts, and options valued using internally developed inputs.
 
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In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy.  In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls must be determined based on the lowest level input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and consideration of factors specific to the asset or liability.
 
A significant amount of the fair value of our derivative contract assets and liabilities is based on observable quoted prices from exchanges and indicative quoted prices from independent brokers in active markets that regularly facilitate our transactions.  An active market is considered to have transactions with sufficient frequency and volume to provide pricing information on an ongoing basis.  We think that these prices represent the best available information for valuation purposes.  In determining the fair value of derivative contract assets and liabilities, we use third-party market pricing where available.  For transactions classified in Level 1 of the fair value hierarchy, we use the unadjusted published settled prices on the valuation date.  For transactions classified in Level 2 of the fair value hierarchy, we value these transactions using indicative quoted prices from independent brokers or other widely-accepted valuation methodologies.  Transactions are classified in Level 2 if substantially all (greater than 90%) of the fair value can be corroborated using observable market inputs such as transactable broker quotes.  In accordance with the exit price objective under the fair value measurements accounting guidance, the fair value of our derivative contract assets and liabilities is determined based on the net underlying position of the recorded derivative contract assets and liabilities using bid prices for assets and ask prices for liabilities.  The quotes we obtain from brokers are non-binding in nature, but are from brokers that typically transact in the market being quoted and are based on their knowledge of market transactions on the valuation date.  We typically obtain multiple broker quotes as of the valuation date that extend for the tenor of the underlying contracts for each delivery location.  The number of quotes that we can obtain depends on the relative liquidity of the delivery location on the valuation date.  If multiple broker quotes are received for a contract, we use an average of the quoted bid or ask prices.  If only one broker quote is received for a delivery location and it cannot be validated through other external sources, we will assign the quote to a lower level within the fair value hierarchy.  In some instances, we may combine broker quotes for a liquid delivery hub with broker quotes for the price spread between the liquid delivery hub and the delivery location under the contract.  We also may apply interpolation techniques to value monthly strips if broker quotes are only available on a seasonal or annual basis.  We perform validation procedures on the broker quotes at least monthly.  The validation procedures include reviewing the quotes for accuracy and comparing them to our internal price curves.  In certain instances, we may exclude from consideration a broker quote if it is a clear outlier and other quotes are obtained.  At September 30, 2012, we obtained broker quotes for 100% of our delivery locations classified in Level 2 of the fair value hierarchy.
 
Inactive markets are considered to be those markets with few transactions, noncurrent pricing or prices that vary over time or among market makers.  Our transactions in Level 3 of the fair value hierarchy may involve transactions whereby observable market data, such as broker quotes, are not available for substantially all of the tenor of the contract or we are only able to obtain indicative broker quotes that cannot be corroborated by observable market data.  In such cases, we may apply valuation techniques such as extrapolation and other quantitative methods to determine fair value.  Our techniques for fair value estimation include assumptions for market prices, including market price volatility and the volatility of the spread between multiple market prices.  Proprietary models may also be used to estimate the fair value of derivative contract assets and liabilities that may be structured or otherwise tailored.  The degree of estimation increases for longer duration contracts, contracts with multiple pricing features, option contracts and off-hub delivery points.  At September 30, 2012, the assets and liabilities classified as Level 3 in the fair value hierarchy represented 3% of total derivative contract assets and 22% of total derivative contract liabilities.
 
The fair value of our derivative contract assets and liabilities is also affected by assumptions as to time value, credit risk and non-performance risk.  The nominal value of derivatives is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the transaction.  Derivative contract assets are reduced to reflect the estimated default risk of counterparties on their contractual obligations.  The counterparty default risk for our overall net position is measured based on published spreads on credit default swaps for counterparties, where available, or proxies based upon published spreads, applied to our current exposure and potential loss exposure from the financial commitments in our risk management portfolio.  The fair value of derivative contract liabilities is reduced to reflect the estimated risk of default on contractual obligations to counterparties and is measured based on
 
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published default rates of our debt, where available, or proxies based upon published spreads.  Credit risk and non-performance risk are calculated with consideration of our master netting agreements with counterparties and our exposure is reduced by cash collateral posted to us against these obligations.
 
Information about Sensitivity to Changes in Significant Unobservable Inputs.  The significant unobservable inputs used in the fair value measure of our commodity instruments categorized within Level 3 of the fair value hierarchy are estimates of future market volatility, estimates of forward congestion power price spreads and estimates of counterparty credit risk and our own non-performance risk.  These assumptions are generally independent of each other.  Volatility curves and power prices spreads are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price or volatility of the spread on a long position would result in a higher fair value measurement.  Increases in the price or volatility of the spread on a short position would result in a lower fair value measurement.  A change in the assumption used for the probability of default is accompanied by a directionally similar change in the adjustment to reflect the estimated default risk of counterparties on their contractual obligations, or the estimated risk of default on our own contractual obligations to counterparties.
 
Risk Management. The Risk and Finance Oversight Committee of the Board of Directors is responsible for oversight of the risk management of our commercial activities and enterprise risk management.  In order to ensure proper daily oversight of our commercial risk controls, the Risk and Finance Oversight Committee has established the ROC with membership determined by the Chief Executive Officer.  The ROC is responsible for ensuring that the necessary policies, procedures and systems are in place to measure, monitor and report on the risks associated with our commercial activities.  The ROC is also responsible for safeguarding proprietary models against the negative impact of inadequate model control by providing oversight and control to model development, back-testing and verification, automation, security and revision control.  The ROC must approve new valuation models or fundamental modifications to existing models.  Model forecasts are back-tested annually and the results reviewed with the ROC.
 
Comprehensive, accurate and timely reporting and monitoring is essential to effectively manage market, credit and operational risks and to protect against large unanticipated losses.  Management has established reporting and monitoring functions, which include daily and weekly reporting, to inform the ROC and Chief Risk Officer of its activities.  The chair of the ROC reports to the Risk and Finance Oversight Committee on a quarterly basis, or more frequently, if events and circumstances dictate.
 
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Fair Value of Derivative Instruments and Certain Other Assets. The fair value measurements of financial assets and liabilities by class are as follows:
 
 	 	September 30, 2012	 	
 	 	Level 1(1)	 	Level 2(1)(2)	 	Level 3	 	Total
Fair Value	 	
 	 	(in millions)	 	
Derivative contract assets:	 	 	 	 	 	 	 	 	 	
Commodity Contracts	 	 	 	 	 	 	 	 	 	
Asset Management:	 	 	 	 	 	 	 	 	 	
Power	 	$	120	 	$	903	 	$	12	 	$	1,035	 	
Fuel	 	—	 	1	 	5	(3)	6	 	
Total Asset Management	 	120	 	904	 	17	 	1,041	 	
Trading Activities	 	16	 	150	 	17	 	183	 	
Total derivative contract assets	 	$	136	 	$	1,054	 	$	34	 	$	1,224	 	
 	 	 	 	 	 	 	 	 	 	
Derivative contract liabilities:	 	 	 	 	 	 	 	 	 	
Commodity Contracts	 	 	 	 	 	 	 	 	 	
Asset Management:	 	 	 	 	 	 	 	 	 	
Power	 	$	48	 	$	180	 	$	5	 	$	233	 	
Fuel	 	2	 	1	 	115	(3)	118	 	
Total Asset Management	 	50	 	181	 	120	 	351	 	
Trading Activities	 	18	 	154	 	9	 	181	 	
Interest Rate Contracts	 	—	 	50	 	—	 	50	 	
Total derivative contract liabilities	 	$	68	 	$	385	 	$	129	 	$	582	 	
 	 	 	 	 	 	 	 	 	 	
Interest-bearing funds(4)	 	$	2,004	 	$	—	 	$	—	 	$	2,004	 	
Other assets(5) 	 	$	20	 	$	—	 	$	—	 	$	20	 	

(1)        Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period.  There were no transfers during the nine months ended September 30, 2012.
(2)        Option contracts comprised 1% of net derivative contract assets.
(3)        Primarily relates to coal.
(4)        Represents investments in money market funds and treasury bills and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet.  Of interest-bearing funds, we had $1.845 billion included in cash and cash equivalents, $54 million included in funds on deposit and $105 million included in other noncurrent assets.
(5)        Relates to mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees.
 
19

 
 	 	December 31, 2011	 	
 	 	Level 1(1)	 	Level 2(1)(2)	 	Level 3	 	Total
Fair Value	 	
 	 	(in millions)	 	
Derivative contract assets:	 	 	 	 	 	 	 	 	 	
Commodity Contracts	 	 	 	 	 	 	 	 	 	
Asset Management:	 	 	 	 	 	 	 	 	 	
Power	 	$	102	 	$	1,136	 	$	19	 	$	1,257	 	
Fuel	 	2	 	—	 	9	(3)	11	 	
Total Asset Management	 	104	 	1,136	 	28	 	1,268	 	
Trading Activities	 	124	 	302	 	38	 	464	 	
Total derivative contract assets	 	$	228	 	$	1,438	 	$	66	 	$	1,732	 	
 	 	 	 	 	 	 	 	 	 	
Derivative contract liabilities:	 	 	 	 	 	 	 	 	 	
Commodity Contracts	 	 	 	 	 	 	 	 	 	
Asset Management:	 	 	 	 	 	 	 	 	 	
Power	 	$	45	 	$	206	 	$	2	 	$	253	 	
Fuel	 	19	 	1	 	79	(3)	99	 	
Total Asset Management	 	64	 	207	 	81	 	352	 	
Trading Activities	 	142	 	309	 	16	 	467	 	
Interest Rate Contracts	 	—	 	32	 	—	 	32	 	
Total derivative contract liabilities	 	$	206	 	$	548	 	$	97	 	$	851	 	
 	 	 	 	 	 	 	 	 	 	
Interest-bearing funds(4) 	 	$	1,985	 	$	—	 	$	—	 	$	1,985	 	
Other assets(5) 	 	$	20	 	$	—	 	$	—	 	$	20	 	

(1)        Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period.  There were no significant transfers during 2011.
(2)        Option contracts comprised 1% of net derivative contract assets.
(3)        Primarily relates to coal.
(4)        Represents investments in money market funds and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet.  Of interest-bearing funds, we had $1.626 billion included in cash and cash equivalents, $202 million included in funds on deposit and $157 million included in other noncurrent assets.
(5)        Relates to mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees.
 
20

 
The following is a reconciliation of changes (comprised of the sum of the quarterly changes) in fair value of net commodity derivative contract assets and liabilities classified as Level 3 during the nine months ended September 30, 2012 and 2011:
 
 	 	Net Derivatives Contracts (Level 3)	 	
 	 	Asset
Management	 	Trading
Activities	 	Total	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	
Balance, January 1, 2012 (net asset (liability))	 	$	(53	)	$	22	 	$	(31	)	
Total gains (losses) realized/unrealized:	 	 	 	 	 	 	 	
Included in earnings(1) 	 	(112	)	12	 	(100	)	
Purchases(2) 	 	—	 	—	 	—	 	
Issuances(2) 	 	—	 	—	 	—	 	
Settlements(3) 	 	62	 	(26	)	36	 	
Transfers into Level 3(4) 	 	—	 	—	 	—	 	
Transfers out of Level 3(4) 	 	—	 	—	 	—	 	
Balance, September 30, 2012 (net asset (liability))	 	$	(103	)	$	8	 	$	(95	)	
 	 	 	 	 	 	 	 	
Balance, January 1, 2011 (net asset (liability))	 	$	(70	)	$	2	 	$	(68	)	
Total gains (losses) realized/unrealized:	 	 	 	 	 	 	 	
Included in earnings(1) 	 	5	 	9	 	14	 	
Purchases(2) 	 	—	 	—	 	—	 	
Issuances(2) 	 	—	 	—	 	—	 	
Settlements(3) 	 	7	 	(5	)	2	 	
Transfers into Level 3(4) 	 	—	 	—	 	—	 	
Transfers out of Level 3(4) 	 	12	 	—	 	12	 	
Balance, September 30, 2011 (net asset (liability))	 	$	(46	)	$	6	 	$	(40	)	

(1)        Represents the fair value, as of the end of each reporting period, of Level 3 contracts entered into during each reporting period and the gains and losses attributable to Level 3 contracts that existed as of the beginning of each reporting period and were still held at the end of each reporting period.
(2)        Contracts entered into during each reporting period are reported with other changes in fair value.
(3)        Represents the reversal of previously recognized unrealized gains and losses from settlement of contracts during each reporting period.
(4)        Denotes the total contracts that existed at the beginning of each reporting period and were still held at the end of each reporting period that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during each reporting period.  Amounts reflect fair value as of the end of each reporting period.
 
The following tables present the amounts included in income related to derivative contract assets and liabilities classified as Level 3:
 
 	 	Three Months Ended September 30,	 	
 	 	2012	 	2011	 	
 	 	Operating
Revenues	 	Cost of
Fuel,
Electricity
and Other
Products	 	Total	 	Operating
Revenues	 	Cost of
Fuel,
Electricity
and Other
Products	 	Total	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gains (losses) included in income	 	$	(19	)	$	55	 	$	36	 	$	(3	)	$	(10	)	$	(13	)	
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at September 30	 	$	(17	)	$	54	 	$	37	 	$	(2	)	$	(11	)	$	(13	)	
 
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 	 	Nine Months Ended September 30,	 	
 	 	2012	 	2011	 	
 	 	Operating
Revenues	 	Cost of
Fuel,
Electricity
and Other
Products	 	Total	 	Operating
Revenues	 	Cost of
Fuel,
Electricity
and Other
Products	 	Total	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gains (losses) included in income	 	$	(23	)	$	(41	)	$	(64	)	$	3	 	$	25	 	$	28	 	
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at September 30	 	$	(18	)	$	(81	)	$	(99	)	$	5	 	$	23	 	$	28	 	
 
Information about Sensitivity to Changes in Significant Unobservable Inputs.  The following table presents the range of sensitivity of unobservable inputs used in fair value measurements categorized within Level 3 of the fair value hierarchy:
 
 	 	Quantitative Information about Level 3 Fair Value Measurements(1)	 	
 	 	Net Fair Value at
September 30, 2012	 	Valuation
Techniques	 	Unobservable Input	 	Range (Weighted
Average)	 	
 	 	(in millions)	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	
Credit valuation adjustment	 	$	1	 	Internal model	 	Own credit risk	 	20% to (20)%	(2)	

(1)        Excludes immaterial unobservable inputs related to power transmission congestion products, power swaps, spread options, physical gas premiums on transactions and credit valuation adjustment related to counterparty credit risk.
(2)       Represents the range of the credit default swap spread curves used in the valuation analysis that we think market participants might use when pricing the contracts.
 
At September 30, 2012, net fair value asset of $10 million for power transactions and net fair value liability of $110 million for fuel transactions classified as Level 3 were priced based on unadjusted indicative broker quotes that cannot be corroborated by observable market data.  Quantitative information is excluded for these fair value measurements.
 
Counterparty Credit Concentration Risk
 
We are exposed to the default risk of the counterparties with which we transact.  We manage our credit risk by entering into master netting agreements and requiring most counterparties to post cash collateral or other credit enhancements based on the net exposure and the credit standing of the counterparty.  We also have non-collateralized power hedges entered into by GenOn Mid-Atlantic.  These transactions are senior unsecured obligations of GenOn Mid-Atlantic and the counterparties and have not required either party to post cash collateral for initial margin.  Since April 2012, the counterparties, in some cases, have been required to post cash collateral to secure credit exposure above an agreed threshold as a result of changes in power or natural gas prices.  At September 30, 2012 and December 31, 2011, $108 million and $4 million, respectively, of cash collateral posted by counterparties under master netting agreements were included in accounts payable and accrued liabilities in the consolidated balance sheets.  Our credit valuation adjustment on derivative contract assets was $9 million and $48 million at September 30, 2012 and December 31, 2011, respectively.
 
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We monitor counterparty credit concentration risk on both an individual basis and a group counterparty basis.  The following tables highlight the credit quality and the balance sheet settlement exposures related to these activities:
 
 	 	September 30, 2012	 	
Credit Rating Equivalent	 	Gross Exposure
Before
Collateral (1)	 	Net Exposure
Before
Collateral (2)	 	Collateral(3)	 	Exposure Net
of Collateral	 	% of Net
Exposure	 	
 	 	(dollars in millions)	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Clearing and Exchange	 	$	432	 	$	159	 	$	159	 	$	—	 	—	 	
Investment Grade:	 	 	 	 	 	 	 	 	 	 	 	
Financial institutions	 	721	 	686	 	106	 	580	 	69	%	
Energy companies	 	362	 	228	 	—	 	228	 	27	%	
Non-investment Grade:	 	 	 	 	 	 	 	 	 	 	 	
Energy companies	 	8	 	5	 	1	 	4	 	1	%	
No External Ratings:	 	 	 	 	 	 	 	 	 	 	 	
Internally-rated investment grade	 	21	 	19	 	—	 	19	 	2	%	
Internally-rated non-investment grade	 	6	 	5	 	—	 	5	 	1	%	
Total	 	$	1,550	 	$	1,102	 	$	266	 	$	836	 	100	%	
 
 	 	December 31, 2011	 	
Credit Rating Equivalent	 	Gross Exposure
Before
Collateral (1)	 	Net Exposure
Before
Collateral (2)	 	Collateral(3)	 	Exposure Net
of Collateral	 	% of Net
Exposure	 	
 	 	(dollars in millions)	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Clearing and Exchange	 	$	724	 	$	223	 	$	223	 	$	—	 	—	 	
Investment Grade:	 	 	 	 	 	 	 	 	 	 	 	
Financial institutions	 	860	 	817	 	—	 	817	 	78	%	
Energy companies	 	421	 	195	 	3	 	192	 	18	%	
Non-investment Grade:	 	 	 	 	 	 	 	 	 	 	 	
Energy companies	 	13	 	5	 	1	 	4	 	—	 	
No External Ratings:	 	 	 	 	 	 	 	 	 	 	 	
Internally-rated investment grade	 	18	 	18	 	—	 	18	 	2	%	
Internally-rated non-investment grade	 	15	 	15	 	—	 	15	 	2	%	
Total	 	$	2,051	 	$	1,273	 	$	227	 	$	1,046	 	100	%	

(1)        Gross exposure before collateral represents credit exposure, including both realized and unrealized transactions, before (a) applying the terms of master netting agreements with counterparties and (b) netting of transactions with clearing brokers and exchanges.  The table excludes amounts related to contracts classified as normal purchases/normal sales and non-derivative contractual commitments that are not recorded at fair value in the consolidated balance sheets, except for any related accounts receivable.  Such contractual commitments contain credit and economic risk if a counterparty does not perform.  Non-performance could have a material adverse effect on our future results of operations, financial condition and cash flows.
(2)        Net exposure before collateral represents the credit exposure, including both realized and unrealized transactions, after applying the terms of master netting agreements and the netting of transactions with clearing brokers and exchanges.
(3)        Collateral includes cash and letters of credit received from counterparties.
 
We had credit exposure to three and two investment grade counterparties at September 30, 2012 and December 31, 2011, respectively, each representing an exposure of more than 10% of total credit exposure, net of collateral and totaling $519 million and $664 million at September 30, 2012 and December 31, 2011, respectively.
 
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GenOn Credit Risk
 
Our standard industry contracts contain credit-risk-related contingent features such as ratings-related thresholds whereby we would be required to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade.  Additionally, some of our contracts contain adequate assurance language, which is generally subjective in nature that could require us to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade.  However, as a result of our current credit rating, we are typically required to post collateral in the normal course of business to offset either substantially or completely the net liability positions, after applying the terms of master netting agreements.  At September 30, 2012, the fair value of financial instruments with credit-risk-related contingent features in a net liability position was $22 million for which we had posted collateral of $18 million, including cash and letters of credit.
 
At September 30, 2012 and December 31, 2011, we had $98 million and $86 million, respectively, of cash collateral posted with counterparties under master netting agreements that was included in funds on deposit in the consolidated balance sheets.
 
Fair Values of Other Financial Instruments
 
The fair values of certain funds on deposit, accounts receivable, notes and other receivables, and accounts payable and accrued liabilities approximate their carrying amounts.
 
The carrying amounts and fair values of debt are as follows:
 
 	 	Carrying
Amount	 	Level 1	 	Level 2(1)	 	Level 3(2)	 	Total Fair Value	 	
 	 	(in millions)	 	
September 30, 2012	 	 	 	 	 	 	 	 	 	 	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	
Long and short-term debt	 	$	4,371	 	$	—	 	$	4,349	 	$	324	 	$	4,673	 	
 	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2011	 	 	 	 	 	 	 	 	 	 	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	
Long and short-term debt	 	$	4,132	 	$	—	 	$	3,969	 	$	97	 	$	4,066	 	

(1)        The fair value of long and short-term debt is estimated using broker quotes for instruments that are publicly traded.
(2)        The fair value of long and short-term debt is estimated based on the income approach valuation technique for non-publicly traded debt using current interest rates for similar instruments with equivalent credit quality.
 
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5.  Long-Term Debt
 
Outstanding debt was as follows:
 
 	 	September 30, 2012	 	December 31, 2011	 	
 	 	Weighted
Average
Stated
Interest
Rate (1)	 	Long-Term	 	Current	 	Weighted
Average
Stated
Interest
Rate (1)	 	Long-Term	 	Current	 	
 	 	(in millions, except interest rates)	 	
Facilities, Bonds and Notes:	 	 	 	 	 	 	 	 	 	 	 	 	 	
GenOn:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior unsecured notes, due 2014	 	7.625	%	$	575	 	$	—	 	7.625	%	$	575	 	$	—	 	
Senior unsecured notes, due 2017	 	7.875	 	725	 	—	 	7.875	 	725	 	—	 	
Senior secured term loan, due 2017(2)	 	6.00	 	679	 	7	 	6.00	 	684	 	7	 	
Senior unsecured notes, due 2018	 	9.50	 	675	 	—	 	9.50	 	675	 	—	 	
Senior unsecured notes, due 2020	 	9.875	 	550	 	—	 	9.875	 	550	 	—	 	
Unamortized debt discounts	 	 	 	(22	)	(2	)	 	 	(24	)	(2	)	
GenOn Americas Generation:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior unsecured notes, due 2021	 	8.50	 	450	 	—	 	8.50	 	450	 	—	 	
Senior unsecured notes, due 2031	 	9.125	 	400	 	—	 	9.125	 	400	 	—	 	
Unamortized debt discounts	 	 	 	(2	)	—	 	 	 	(2	)	—	 	
GenOn Marsh Landing:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior secured term loan, due 2017	 	2.75	 	109	 	—	 	2.76	 	33	 	—	 	
Senior secured term loan, due 2023	 	3.00	 	241	 	—	 	3.01	 	74	 	—	 	
Other:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital leases, due 2015	 	7.375-8.19	 	11	 	5	 	7.375-8.19	 	14	 	5	 	
Adjustment to fair value of debt(3)	 	 	 	(30	)	—	 	 	 	(32	)	—	 	
Total	 	 	 	$	4,361	 	$	10	 	 	 	$	4,122	 	$	10	 	

(1)        The weighted average stated interest rates are at September 30, 2012 and December 31, 2011, respectively.
(2)        The debt balance on the term loan facility is recorded at GenOn Americas, a direct subsidiary of GenOn Energy Holdings, because GenOn Americas is a co-borrower.
(3)        Debt assumed in the Mirant/RRI Merger was adjusted to fair value on the Mirant/RRI Merger date.  The adjustment is amortized to interest expense over various years through 2017.
 
GenOn Credit Facilities
 
Availability of borrowings under the GenOn revolving credit facility is reduced by any outstanding letters of credit.  At September 30, 2012, outstanding letters of credit were $228 million and availability of borrowings under the revolving credit facility was $560 million.
 
6.  Pension and Other Postretirement Benefit Plans
 
The components of the net periodic benefit cost (credit) are shown below:
 
 	 	Pension Plans	 	Other Postretirement
Benefit Plans	 	
 	 	Three Months Ended
September 30,	 	Nine Months Ended
September 30,	 	Three Months Ended
September 30,	 	Nine Months Ended
September 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	2012	 	2011	 	2012	 	2011	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Service cost	 	$	3	 	$	3	 	$	9	 	$	9	 	$	—	 	$	—	 	$	1	 	$	—	 	
Interest cost	 	6	 	5	 	18	 	17	 	1	 	1	 	3	 	3	 	
Expected return on plan assets	 	(8	)	(7	)	(23	)	(22	)	—	 	—	 	—	 	—	 	
Net amortization(1) 	 	3	 	1	 	7	 	3	 	(1	)	(1	)	(3	)	(3	)	
Special termination benefit	 	1	 	—	 	1	 	—	 	—	 	—	 	—	 	—	 	
Curtailment	 	—	 	—	 	—	 	—	 	(2	)	—	 	(2	)	—	 	
Net periodic benefit cost (credit)	 	$	5	 	$	2	 	$	12	 	$	7	 	$	(2	)	$	—	 	$	(1	)	$	—	 	

(1)        Net amortization amounts include actuarial gains/losses and prior service cost/credit.
 
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7.  Stock-Based Compensation
 
Compensation expense for the stock-based incentive plan was:
 
 	 	Three Months Ended
September 30,	 	Nine Months Ended
September 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	
Stock-based incentive plan compensation expense (pre-tax) (1)	 	$	6	 	$	3	 	$	15	 	$	11	 	

(1)        No tax benefits related to stock-based compensation were realized during the three and nine months ended September 30, 2012 and 2011 because of our NOL carryforwards.
 
During February 2012, we granted long-term incentive awards as follows:
 
Award Vehicle	 	Awards Granted	 	Vesting Period	
 	 	 	 	 	
Time-based Restricted Stock Units	 	2,821,302	 	Vest ratably each year over a three-year period; common stock settled	
 	 	 	 	 	
Performance-based Restricted Stock Units	 	2,586,482	 	Linked to the achievement of the 2012 short-term incentive plan performance goals, with performance measured at the end of the first year; vest ratably each year over a three-year period; common stock settled	
 	 	 	 	 	
Stock Options	 	5,897,990	 	Vest ratably each year over a three-year period	
 
Vesting in Connection with the NRG Merger.  All outstanding stock options (other than options granted in 2012) will immediately vest (to the extent not already fully vested) and all outstanding stock options will generally convert upon completion of the NRG Merger into stock options with respect to NRG common stock, after giving effect to the exchange ratio.  In addition, all outstanding restricted stock units (other than restricted stock units granted in 2012) will immediately vest (to the extent not already fully vested) and all outstanding restricted stock units will be exchanged for the NRG Merger consideration.  All outstanding stock options and restricted stock units granted in 2012 will vest (to the extent not already fully vested) at the holder’s termination date if the termination is as a result of the NRG Merger and within two years of the closing date.  See note 1.
 
8.  Earnings Per Share
 
We calculate basic EPS by dividing income/loss available to stockholders by the weighted average number of common shares outstanding.  Diluted EPS gives effect to dilutive potential common shares, including unvested restricted stock units and stock options.
 
26

 
The following table shows the computation of basic and diluted EPS:
 
 	 	Three Months Ended
September 30,	 	Nine Months Ended
September 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	
 	 	(in millions, except per share data)	 	
 	 	 	 	 	 	 	 	 	 	
Net loss	 	$	(85	)	$	(40	)	$	(345	)	$	(289	)	
 	 	 	 	 	 	 	 	 	 	
Basic and diluted shares	 	 	 	 	 	 	 	 	 	
Weighted average shares outstanding—basic	 	774	 	772	 	774	 	771	 	
Effect of dilutive securities(1) 	 	—	 	—	 	—	 	—	 	
Weighted average shares outstanding—diluted	 	774	 	772	 	774	 	771	 	
 	 	 	 	 	 	 	 	 	 	
Basic and Diluted EPS	 	 	 	 	 	 	 	 	 	
Basic EPS	 	$	(0.11	)	$	(0.05	)	$	(0.45	)	$	(0.37	)	
Diluted EPS	 	$	(0.11	)	$	(0.05	)	$	(0.45	)	$	(0.37	)	

(1)        As we incurred a net loss for the three and nine months ended September 30, 2012 and 2011, diluted loss per share is calculated the same as basic loss per share.
 
The weighted average number of securities that could potentially dilute basic EPS in the future that were not included in the computation of diluted EPS because to do so would have been antidilutive was as follows:
 
 	 	Three Months Ended
September 30,	 	Nine Months Ended
September 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	
Stock options	 	19	 	17	 	18	 	18	 	
Restricted stock units	 	9	 	5	 	8	 	5	 	
Total number of antidilutive shares	 	28	 	22	 	26	 	23	 	
 
9.  Accumulated Other Comprehensive Loss
 
The component balances of accumulated other comprehensive loss, included in the consolidated balance sheets, are as follows:
 
 	 	September 30,
2012	 	December 31,
2011	 	
 	 	(in millions)	 	
 	 	 	 	 	 	
Pension and other postretirement benefits—actuarial losses, net	 	$	(145	)	$	(142	)	
Pension and other postretirement benefits—prior service credit, net	 	5	 	7	 	
Cash flow hedges—interest rate swaps	 	(52	)	(34	)	
Other, net	 	—	 	(1	)	
Accumulated other comprehensive loss	 	$	(192	)	$	(170	)	
 
10.  Segment Reporting
 
We have five segments:  Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations.  The segments are determined based on how the business is managed and align with the information provided to the chief operating decision maker for purposes of assessing performance and allocating resources.  Generally, our segments are engaged in the sale of electricity, capacity, and ancillary and other energy services from their generating facilities in hour-ahead, day-ahead and forward markets in bilateral and ISO markets.  We also engage in proprietary trading, fuel oil management and natural gas transportation and storage activities.  Operating
 
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revenues consist of (a) power generation revenues, (b) contracted and capacity revenues, (c) power hedging revenues and (d) fuel sales and proprietary trading revenues.
 
The Eastern PJM segment consists of seven generating facilities located in Maryland and New Jersey.  The Western PJM/MISO segment consists of 22 generating facilities located in Illinois, Ohio and Pennsylvania.  The California segment consists of seven generating facilities located in California and includes business development and construction activities for GenOn Marsh Landing.  See note 2 for a discussion of generating facilities in the Eastern PJM, Western PJM/MISO and California segments that we expect to retire or place in long-term protective layup in 2015.  The Energy Marketing segment consists of proprietary trading, fuel oil management and natural gas transportation and storage activities.  Other Operations consists of seven generating facilities located in Florida, Massachusetts, Mississippi, New York and Texas.  Other Operations also includes unallocated overhead expenses and other activity that cannot be identified specifically with another segment.  All revenues are generated and long-lived assets are located within the United States.
 
The following table summarizes changes in our net generating capacity by segment:
 
 	 	Eastern
PJM	 	Western
PJM/MISO	 	California	 	Other	 	Total	 	
 	 	(in MWs)	 	
 	 	 	 	 	 	 	 	 	 	 	 	
MWs in service at January 1, 2011	 	6,336	 	7,483	 	5,725	 	5,055	 	24,599	 	
Potrero generating facility deactivated in February 2011	 	—	 	—	 	(362	)	—	 	(362	)	
Rating changes for generating facilities in 2011	 	5	 	—	 	28	 	13	 	46	 	
MWs in service at December 31, 2011	 	6,341	 	7,483	 	5,391	 	5,068	 	24,283	 	
Indian River generating facility sold in January 2012	 	—	 	—	 	—	 	(586	)	(586	)	
Vandolah generating facility expiration of tolling agreement in May 2012	 	—	 	—	 	—	 	(630	)	(630	)	
Niles unit 2 deactivated in June 2012	 	—	 	(108	)	—	 	—	 	(108	)	
Elrama units 1-3 deactivated in June 2012	 	—	 	(289	)	—	 	—	 	(289	)	
MWs in service at September 30, 2012	 	6,341	 	7,086	 	5,391	 	3,852	 	22,670	 	
Niles unit 1 deactivated in October 2012	 	—	 	(109	)	—	 	—	 	(109	)	
Elrama unit 4 deactivated in October 2012	 	—	 	(171	)	—	 	—	 	(171	)	
Potomac River generating facility deactivated in October 2012	 	(482	)	—	 	—	 	—	 	(482	)	
MWs in service at November 9, 2012	 	5,859	 	6,806	 	5,391	 	3,852	 	21,908	 	
 
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The measure of profit or loss for our reportable segments is operating income/loss.  This measure represents the lowest level of information that is provided to the chief operating decision maker for our reportable segments.
 
 	 	Eastern PJM	 	Western
PJM/MISO	 	California	 	Energy
Marketing	 	Other
Operations	 	Eliminations	 	Total	 	
 	 	(in millions)	 	
Three Months Ended September 30, 2012:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues(1)	 	$	220	 	$	236	 	$	209	 	$	14	 	$	76	 	$	—	 	$	755	 	
Cost of fuel, electricity and other products (2)  	 	107	 	154	 	20	 	30	 	35	 	—	 	346	 	
Gross margin (excluding depreciation and amortization)	 	113	 	82	 	189	 	(16	)	41	 	—	 	409	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operations and maintenance	 	101	 	102	 	34	 	1	 	30	 	—	 	268	 	
Depreciation and amortization	 	34	 	32	 	10	 	—	 	15	 	—	 	91	 	
Impairment losses	 	—	 	47	(3)	—	 	—	 	—	 	—	 	47	 	
Gain on sales of assets, net	 	(1	)	—	 	—	 	—	 	—	 	—	 	(1	)	
Total operating expenses	 	134	 	181	 	44	 	1	 	45	 	—	 	405	 	
Operating income (loss)	 	$	(21	)	$	(99	)	$	145	 	$	(17	)	$	(4	)	$	—	 	$	4	 	

(1)        Includes unrealized gains (losses) of $(136) million, $(81) million, $2 million, $(29) million and $(1) million for Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations, respectively.
(2)        Includes unrealized gains of $46 million, $8 million, $1 million and $3 million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
(3)        Represents long-lived assets impairments, see note 3.
 
 	 	Eastern PJM	 	Western
PJM/MISO	 	California	 	Energy
Marketing	 	Other
Operations	 	Eliminations	 	Total	 	
 	 	(in millions)	 	
Nine Months Ended September 30, 2012:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues(1) 	 	$	772	 	$	721	 	$	271	 	$	65	 	$	168	 	$	—	 	$	1,997	 	
Cost of fuel, electricity and other products (2)	 	376	 	399	 	22	 	45	 	88	 	—	 	930	 	
Gross margin (excluding depreciation and amortization)	 	396	 	322	 	249	 	20	 	80	 	—	 	1,067	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operations and maintenance (3)  	 	292	(4)	346	 	117	 	4	 	81	 	—	 	840	 	
Depreciation and amortization	 	101	 	93	 	33	 	—	 	42	 	—	 	269	 	
Impairment losses	 	—	 	47	(5)	—	 	—	 	—	 	—	 	47	 	
Gain on sales of assets, net	 	(1	)	(1	)	—	 	—	 	(7	)	—	 	(9	)	
Total operating expenses	 	392	 	485	 	150	 	4	 	116	 	—	 	1,147	 	
Operating income (loss)	 	$	4	 	$	(163	)	$	99	 	$	16	 	$	(36	)	$	—	 	$	(80	)	
Total assets at September 30, 2012	 	$	4,438	 	$	3,292	 	$	1,106	 	$	1,546	 	$	3,627	(6)	$	(2,434	)	$	11,575	 	

(1)        Includes unrealized gains (losses) of $(135) million, $(46) million, $1 million, $(15) million and $(9) million for Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations, respectively.
(2)        Includes unrealized (gains) losses of $26 million, $10 million, $1 million and $(12) million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
(3)        Includes costs to deactivate generating facilities of $11 million, $32 million and $4 million for Eastern PJM, Western PJM/MISO and California, respectively.
(4)        Includes $31 million of income related to the reversal of the Potomac River obligation under the 2008 agreement with the City of Alexandria.
 
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(5)        Represents long-lived assets impairments, see note 3.
(6)        Includes our equity method investment in Sabine Cogen, LP of $20 million.
 
 	 	Eastern PJM	 	Western
PJM/MISO	 	California	 	Energy
Marketing	 	Other
Operations	 	Eliminations	 	Total	 	
 	 	(in millions)	 	
Three Months Ended September 30, 2011:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues(1) 	 	$	346	 	$	433	 	$	128	 	$	88	 	$	85	 	$	—	 	$	1,080	 	
Cost of fuel, electricity and other products (2)  	 	179	 	206	 	11	 	71	 	59	 	—	 	526	 	
Gross margin (excluding depreciation and amortization)	 	167	 	227	 	117	 	17	 	26	 	—	 	554	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operations and maintenance	 	99	 	108	 	33	 	—	 	46	(3)	—	 	286	 	
Depreciation and amortization	 	34	 	29	 	11	 	1	 	21	 	—	 	96	 	
Impairment losses(4) 	 	95	 	4	 	14	 	—	 	20	 	—	 	133	 	
Gain on sales of assets, net	 	—	 	—	 	(5	)	—	 	(1	)	—	 	(6	)	
Total operating expenses	 	228	 	141	 	53	 	1	 	86	 	—	 	509	 	
Operating income (loss)	 	$	(61	)	$	86	 	$	64	 	$	16	 	$	(60	)	$	—	 	$	45	 	

(1)        Includes unrealized gains (losses) of $(2) million, $37 million, $1 million, $15 million and $(2) million for Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations, respectively.
(2)        Includes unrealized (gains) losses of $10 million, $1 million, $(1) million and $1 million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
(3)        Includes $24 million of Mirant/RRI Merger-related costs.
(4)        Represents impairment losses for the write-off of excess NOx and SO2emissions allowances as a result of the CSAPR.
 
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 	 	Eastern PJM	 	Western
PJM/MISO	 	California	 	Energy
Marketing	 	Other
Operations	 	Eliminations	 	Total	 	
 	 	(in millions)	 	
Nine Months Ended September 30, 2011:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues(1) 	 	$	962	 	$	1,050	 	$	200	 	$	292	 	$	202	 	$	—	 	$	2,706	 	
Cost of fuel, electricity and other products (2)	 	433	 	526	 	14	 	222	 	122	 	—	 	1,317	 	
Gross margin (excluding depreciation and amortization)	 	529	 	524	 	186	 	70	 	80	 	—	 	1,389	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operations and maintenance	 	351	(3)	368	 	111	 	2	 	131	(4)	—	 	963	 	
Depreciation and amortization	 	101	 	88	 	32	 	2	 	49	 	—	 	272	 	
Impairment losses(5) 	 	95	 	4	 	14	 	—	 	20	 	—	 	133	 	
Gain on sales of assets, net	 	—	 	—	 	(5	)	—	 	—	 	—	 	(5	)	
Total operating expenses	 	547	 	460	 	152	 	4	 	200	 	—	 	1,363	 	
Operating income (loss)	 	$	(18	)	$	64	 	$	34	 	$	66	 	$	(120	)	$	—	 	$	26	 	
Total assets at December 31, 2011	 	$	4,732	 	$	3,343	 	$	856	 	$	2,173	 	$	3,662	(6)	$	(2,497	)	$	12,269	 	

(1)        Includes unrealized gains (losses) of $(80) million, $2 million, $4 million and $(12) million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
(2)        Includes unrealized (gains) losses of $(17) million, $(8) million, $(1) million and $(1) million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
(3)        Includes $30 million of expense for large scale remediation and settlement costs.
(4)        Includes $61 million of Mirant/RRI Merger-related costs.
(5)        Represents impairment losses for the write-off of excess NOx and SO2emissions allowances as a result of the CSAPR.
(6)        Includes our equity method investment in Sabine Cogen, LP of $22 million.
 
 	 	Three Months Ended
September 30,	 	Nine Months Ended
September 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	
 	 	(in millions)	 	
 	 	 	 	 	 	 	 	 	 	
Operating income (loss) for all segments	 	$	4	 	$	45	 	$	(80	)	$	26	 	
Interest expense, net	 	(85	)	(85	)	(259	)	(290	)	
Other, net	 	—	 	1	 	2	 	(21	)	
Loss before income taxes	 	$	(81	)	$	(39	)	$	(337	)	$	(285	)	
 
11.  Litigation and Other Contingencies
 
We are involved in a number of legal proceedings.  In certain cases, plaintiffs seek to recover large or unspecified damages, and some matters may be unresolved for several years.  We cannot currently determine the outcome of the proceedings described below or estimate the reasonable amount or range of potential losses, if any, and therefore have not made any provision for such matters unless specifically noted below.
 
Scrubber Contract Litigation
 
In January 2011, Stone & Webster, the EPC contractor for the scrubber projects at the Chalk Point, Dickerson and Morgantown generating facilities, filed three suits against us in the United States District Court for the District of Maryland.  Stone & Webster claimed that it had not been paid in accordance with the terms of the EPC agreements for the scrubber projects and sought liens against the properties, which the court granted.  We disputed Stone & Webster’s allegations and in February 2011 filed a related action against Stone &Webster in the United States District Court for the Southern District of New York.  The proceedings in Maryland were stayed pending resolution of the proceeding in New York.
 
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In June 2012, we executed a settlement agreement with Stone & Webster.  Under the terms of the settlement agreement GenOn agreed to pay Stone & Webster $107.1 million in settlement of all outstanding invoices and amounts claimed to be owed by Stone & Webster in connection with the construction of the scrubber projects.  As part of the settlement, Stone & Webster released the $165.6 million in interlocutory liens that had been filed by Stone & Webster on the Chalk Point, Dickerson and Morgantown generating facilities.  As a result of the release of the liens, GenOn Mid-Atlantic released the $165.6 million in reserved cash during June 2012 (previously included as funds on deposit in the consolidated balance sheets).  In connection with the settlement agreement, we dismissed our dispute filed in the United States District Court for the Southern District of New York.
 
We incurred $1.7 billion in capital expenditures from 2007 to 2012 for compliance with the Maryland Healthy Air Act.
 
Pending Natural Gas Litigation
 
We are party to five lawsuits, several 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 antitrust and similar laws.  The lawsuits seek treble or punitive damages, restitution and/or expenses.  The lawsuits also name a number of unaffiliated energy companies as parties.  In July 2011, the judge in the United States District Court for the District of Nevada handling four of the five cases granted the defendants’ motion for summary judgment dismissing all claims against us in those cases.  The plaintiffs have appealed to the United States Court of Appeals for the Ninth Circuit.  In September 2012, the State of Nevada Supreme Court handling one of the five cases affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs’ claims against us.  In October 2012, the plaintiffs indicated that they intend to file a petition for certiorari to the United States Supreme Court.  We have agreed to indemnify CenterPoint against certain losses relating to these lawsuits.
 
Bowline Property Tax Dispute
 
In 2011, 2010 and 2009 we filed suit against the town of Haverstraw, New York to challenge the property tax assessment of the Bowline generating facility for each respective tax year.  Although the assessments for the 2011 and 2010 tax years were reduced significantly from the assessment received in 2009, they continue to exceed significantly the estimated fair value of the generating facility.  The tax litigation for all three years has been combined for trial purposes.  While we are unable to predict the outcome of this litigation, if we are successful we expect to receive a refund for each of the years under protest.
 
Environmental Matters
 
Global Warming.  In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a suit in the United States District Court for the Northern District of California against GenOn and 23 other electric generating and oil and gas companies.  The lawsuit sought damages of up to $400 million for the cost of relocating the village allegedly because of global warming caused by the greenhouse gas emissions of the defendants.  In late 2009, the District Court ordered that the case be dismissed and the plaintiffs appealed.  In September 2012, the United States Court of Appeals for the Ninth Circuit dismissed planitiffs’ appeal.  In October 2012, the plaintiffs petitioned for en banc rehearing of the case.  Although we think claims such as this lack legal merit, it is possible that this trend of climate change litigation may continue.
 
New Source Review Matters. The EPA and various states are investigating compliance of coal-fueled electric generating facilities with the pre-construction permitting requirements of the Clean Air Act known as “new source review.”  Since 2000, the EPA has made information requests concerning the Avon Lake, Chalk Point, Cheswick, Conemaugh, Dickerson, Elrama, Keystone, Morgantown, New Castle, Niles, Portland, Potomac River, Shawville and Titus generating facilities.  We are corresponding or have corresponded with the EPA regarding all of these requests.  The EPA agreed to share information relating to its investigations with state environmental agencies.  In January 2009, we received an NOV from the EPA alleging that past work at our Shawville, Portland and Keystone generating facilities violated regulations regarding new source review.  In June 2011, we received an NOV from the EPA alleging that past work at our Niles and Avon Lake generating facilities violated regulations regarding new source review.
 
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In December 2007, the NJDEP filed suit against us in the United States District Court for the Eastern District of Pennsylvania, alleging that new source review violations occurred at the Portland generating facility.  The suit seeks installation of “best available” control technologies for each pollutant, to enjoin us from operating the generating facility if it is not in compliance with the Clean Air Act and civil penalties.  The suit also names three past owners of the plant as defendants.  In March 2009, the Connecticut Department of Environmental Protection became an intervening party to the suit.
 
We think that the work listed by the EPA and the work subject to the NJDEP suit were conducted in compliance with applicable regulations.  However, any final finding that we violated the new source review requirements could result in fines, penalties or significant capital expenditures associated with the implementation of emissions reductions on an accelerated basis.  Most of these work projects were undertaken before our ownership or lease of those facilities.
 
In addition, the NJDEP filed two administrative petitions with the EPA in 2010 alleging that our Portland generating facility’s emissions were significantly contributing to nonattainment and/or interfering with the maintenance of certain NAAQS in New Jersey.  In November 2011, the EPA published a final rule in response to one of the petitions that will require us to reduce our maximum allowable SO 2  emissions from the two coal-fired units by about 60% starting in January 2013 and by about 80% starting in January 2015.  In January 2012, we challenged the rule in the United States Court of Appeals for the Third Circuit.  In 2013 and 2014, we have several compliance options that include using lower sulfur coals (although this may at times reduce how much we are able to generate) or running just one unit at a time.  Starting in January 2015, these units will be subject to more stringent rate limits, which will require either material capital expenditures and higher operating costs or the retirement of these two units.  See note 2 for a discussion of the Portland coal-fired units that we expect to deactivate in 2015.
 
Cheswick Class Action Complaint. In April 2012, a putative class action lawsuit was filed against us in the Court of Common Pleas of Allegheny County, Pennsylvania alleging that emissions from our Cheswick generating facility have damaged the property of neighboring residents.  We dispute these allegations.  Plaintiffs have brought nuisance, negligence, trespass and strict liability claims seeking both damages and injunctive relief.  Plaintiffs seek to certify a class that consists of people who own property or live within one mile of our plant.  In July 2012, we removed the lawsuit to the United States District Court for the Western District of Pennsylvania.  In October 2012, the court granted our motion to dismiss.  Plaintiffs have 30 days to appeal this order.
 
Cheswick Monarch Mine NOV.  In 2008, the PADEP issued an NOV related to the Monarch mine located near our Cheswick generating facility.  It has not been mined for many years.  We use it for disposal of low-volume wastewater from the Cheswick generating facility and for disposal of leachate collected from ash disposal facilities.  The NOV addresses the alleged requirement to maintain a minimum pumping volume from the mine.  The PADEP indicated it may assess a civil penalty in excess of $100,000.  We contest the allegations in the NOV and have not agreed to such penalty.  We are currently planning capital expenditures in connection with wastewater from Cheswick and leachate from ash disposal facilities.
 
Conemaugh Alleged Clean Streams Law Violations.  In September 2012, the PADEP filed a lawsuit in the Commonwealth Court of Pennsylvania alleging that several violations of the Pennsylvania Clean Streams Law occurred at the Conemaugh generating facility.  We have negotiated a proposed consent decree to address the allegations.  We expect that the proposed consent decree, which has been lodged with the court, will resolve these issues and obligate us to pay a civil penalty of $500,000.  We are responsible for 16.45% of this amount.
 
Ormond Beach Alleged Federal Clean Water Act Violations. In October 2012, the Wishtoyo Foundation, a California-based cultural and environmental advocacy organization, through its Ventura Coastkeeper Program, filed suit in the United States District Court for the Central District of California regarding alleged violations of the Clean Water Act associated with discharges of stormwater from the Ormond Beach generating facility.  The Wishtoyo Foundation alleges that elevated concentrations of pollutants in stormwater discharged from the Ormond Beach generating facility are affecting adjacent aquatic resources in violation of (a) the Statewide General Industrial Stormwater permit (a general National Pollution Discharge Elimination System permit issued by the California State Water Resources Control Board that authorizes stormwater discharges from industrial facilities in California) and (b) the state’s Porter-Cologne Water Quality Control Act.  The Wishtoyo Foundation further alleges that we have
 
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not implemented effective stormwater control and treatment measures and that we have not complied with the sampling and reporting requirements of the General Industrial Stormwater permit.  We dispute these allegations.
 
Maryland Fly Ash Facilities. We have three fly ash facilities in Maryland: Faulkner, Westland and Brandywine.  We dispose of fly ash from our Morgantown and Chalk Point generating facilities at Brandywine.  We dispose of fly ash from our Dickerson generating facility at Westland.  We no longer dispose of fly ash at the Faulkner facility.  As described below, the MDE has sued us regarding Faulkner and Brandywine and threatened to sue regarding Westland.  The MDE also had threatened not to renew the water discharge permits for all three facilities.
 
Faulkner Litigation.  In May 2008, the MDE sued us in the Circuit Court for Charles County, Maryland alleging violations of Maryland’s water pollution laws at Faulkner.  The MDE contended that the operation of Faulkner had resulted in the discharge of pollutants that exceeded Maryland’s water quality criteria and without the appropriate NPDES permit.  The MDE also alleged that we failed to perform certain sampling and reporting required under an applicable NPDES permit.  The MDE complaint requested that the court (a) prohibit continuation of the alleged unpermitted discharges, (b) require us to cease from further disposal of any coal combustion byproducts at Faulkner and close and cap the existing disposal cells and (c) assess civil penalties.  In July 2008, we filed a motion to dismiss the complaint, arguing that the discharges are permitted by a December 2000 Consent Order.  In January 2011, the MDE dismissed without prejudice its complaint and informed us that it intended to file a similar lawsuit in federal court.  In May 2011, the MDE filed a complaint against us in the United States District Court for the District of Maryland alleging violations at Faulkner of the Clean Water Act and Maryland’s Water Pollution Control Law.  The MDE contends that (a) certain of our water discharges are not authorized by our existing permit and (b) operation of the Faulkner facility has resulted in discharges of pollutants that violate water quality criteria.  The complaint asks the court to, among other things, (a) enjoin further disposal of coal ash; (b) enjoin discharges that are not authorized by our existing permit; (c) require numerous technical studies; (d) impose civil penalties and (e) award MDE attorneys’ fees.  We dispute the allegations.
 
Brandywine Litigation.  In April 2010, the MDE filed a complaint against us in the United States District Court for the District of Maryland asserting violations at Brandywine of the Clean Water Act and Maryland’s Water Pollution Control Law.  The MDE contends that the operation of Brandywine has resulted in discharges of pollutants that violate Maryland’s water quality criteria.  The complaint requests that the court, among other things, (a) enjoin further disposal of coal combustion waste at Brandywine, (b) require us to close and cap the existing open disposal cells within one year, (c) impose civil penalties and (d) award MDE attorneys’ fees.  We dispute the allegations.  In September 2010, four environmental advocacy groups became intervening parties in the proceeding.
 
Threatened Westland Litigation. In January 2011, the MDE informed us that it intended to sue us for alleged violations at Westland of Maryland’s water pollution laws.  To date, MDE has not sued us regarding our ash disposal.
 
Permit Renewals. In March 2011, the MDE tentatively determined to deny our application for the renewal of the water discharge permit for Brandywine, which could result in a significant increase in operating expenses for our Chalk Point and Morgantown generating facilities.  The MDE also had indicated that it was planning to deny our applications for the renewal of the water discharge permits for Faulkner and Westland.  Denial of the renewal of the water discharge permit for the latter facility could result in a significant increase in operating expenses for our Dickerson generating facility.
 
Stay and Settlement Discussions.  In June 2011, the MDE agreed to stay the litigation related to Faulkner and Brandywine while we pursued settlement of allegations related to the three Maryland ash facilities.  MDE also agreed not to pursue its tentative denial of our application to renew our water discharge permit at Brandywine and agreed not to act on our renewal applications for Faulkner or Westland while we were discussing settlement.  As a condition to obtaining the stay, we agreed in principle to pay a civil penalty of $1.9 million (for alleged past violations) to the MDE if we reach a comprehensive settlement regarding all of the allegations related to the three Maryland ash facilities.  We accrued $1.9 million during 2011 and an additional $0.6 million (for agreed prospective penalties while we implement the settlement) during the second quarter of 2012 for a total of $2.5 million.  We also developed a technical solution, which includes installing synthetic caps on the closed cells of each of the three ash facilities.  During 2011, we accrued $47 million for the estimated cost of the technical solution.  We have nearly
 
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concluded our settlement discussions with the MDE.  At this time, we cannot reasonably estimate the upper range of our obligations for remediating the sites for the following reasons: (a) we have not finished assessing each site including identifying the full impacts to both ground and surface water and the impacts to the surrounding habitat; (b) we have not finalized with the MDE the standards to which we must remediate; and (c) we have not identified the technologies required, if any, to meet the mandated remediation standards at each site nor the timing of the design and installation of such technologies.
 
Brandywine Storm Damage and Ash Recovery. As a result of Hurricane Irene and Tropical Storm Lee in August and September 2011, an estimated 8,800 cubic yards of coal fly ash stored in one of the cells at the Brandywine ash disposal site flowed onto 18 acres of private property adjacent to the site.  During 2011, we accrued $10 million for the estimated costs to remove and clean up the ash.  We have removed the released ash from the private property and completed the remaining clean-up activities.  We adjusted our estimate and reversed $4 million during the second quarter of 2012.  During the third quarter of 2012, we received $2 million of insurance proceeds in connection with our claims associated with the costs to remove and clean up the ash.
 
Brandywine Filling of Wetlands.  While expanding and installing a liner at the Brandywine ash disposal site, we inadvertently filled wetlands without having all of the requisite permits.  The MDE also has alleged that we violated the notice requirements of our sediment and erosion control plan.  In July 2012, the MDE filed a complaint in the Circuit Court for Prince George’s County, Maryland for civil penalties and injunctive relief in connection with the storm damage and the filling of the wetlands.  We have agreed to settle these matters by paying a fine of $300,000.
 
Ash Disposal Facility Closures.  We are responsible for environmental costs related to the future closures of several ash disposal facilities.  We have accrued the estimated discounted costs ($40 million and $38 million at September 30, 2012 and December 31, 2011, respectively) associated with these environmental liabilities as part of the asset retirement obligations.  These amounts are exclusive of the $47 million accrual for the technical solution for the three ash facilities in Maryland discussed above.
 
Remediation Obligations.  We are responsible under the Industrial Site Recovery Act for environmental costs related to site contamination investigations and remediation requirements at four generating facilities in New Jersey.  We have accrued the estimated long-term liability for the remediation costs of $6 million at September 30, 2012 and December 31, 2011.
 
Chapter 11 Proceedings
 
In July 2003, and various dates thereafter, the Mirant Debtors filed voluntary petitions in the Bankruptcy Court for relief under Chapter 11 of the United States 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.  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.
 
Actions Pursued by MC Asset Recovery
 
Under the Plan, the rights to 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 now governed by a manager who is independent of us.  Under the Plan, any cash recoveries obtained by MC Asset Recovery from the actions transferred to it, net of fees and costs incurred in prosecuting the actions, are to be paid to the unsecured creditors of GenOn Energy Holdings in the Chapter 11 proceedings and the holders of the equity interests in GenOn Energy Holdings immediately prior to the effective
 
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date of the Plan except where such a recovery results in an allowed claim in the bankruptcy proceedings, as described below.  MC Asset Recovery is a disregarded entity for income tax purposes, and GenOn Energy Holdings is responsible for income taxes related to its operations.  The Plan provides that GenOn Energy Holdings may not reduce payments to be made to unsecured creditors and former holders of equity interests from recoveries obtained by MC Asset Recovery for the taxes owed by GenOn Energy Holdings, if any, on any net recoveries up to $175 million.  If the aggregate recoveries exceed $175 million net of costs, then GenOn Energy Holdings may reduce the payments by the amount of any taxes it will owe or NOLs utilized with respect to taxable income resulting from the amount in excess of $175 million.
 
The Plan and the MC Asset Recovery Limited Liability Company Agreement also obligate GenOn Energy Holdings to make contributions to MC Asset Recovery as necessary to pay professional fees and certain other costs.  In June 2008, GenOn Energy Holdings and MC Asset Recovery, with the approval of the Bankruptcy Court, agreed to limit the total amount of funding to be provided by GenOn Energy Holdings to MC Asset Recovery to $68 million, and the amount of such funding obligation not already incurred by GenOn Energy Holdings at that time was fully accrued.  GenOn Energy Holdings was entitled to be repaid the amounts it funded from any recoveries obtained by MC Asset Recovery before any distribution was made from such recoveries to the unsecured creditors of GenOn Energy Holdings and the former holders of equity interests.
 
In March 2009, Southern Company and MC Asset Recovery entered into a settlement agreement resolving claims asserted by MC Asset Recovery in a suit that was pending in the United States District Court for the Northern District of Georgia.  Southern Company paid $202 million to MC Asset Recovery in settlement of all claims asserted in the litigation.  MC Asset Recovery used a portion of that payment to pay fees owed to the managers of MC Asset Recovery and other expenses of MC Asset Recovery not previously funded by GenOn Energy Holdings, and it retained $47 million from that payment to fund future expenses and to apply against unpaid expenditures.  MC Asset Recovery distributed the remaining $155 million to GenOn Energy Holdings.  In accordance with the Plan, GenOn Energy Holdings retained approximately $52 million of that distribution as reimbursement for the funds it had provided to MC Asset Recovery and costs it incurred related to MC Asset Recovery that had not been previously reimbursed.  GenOn Energy Holdings recognized the $52 million as a reduction of operations and maintenance expense during 2009.  Pursuant to MC Asset Recovery’s Limited Liability Company Agreement and an order of the Bankruptcy Court dated October 31, 2006, GenOn Energy Holdings distributed $2 million to the managers of MC Asset Recovery.  In September 2009, the remaining approximately $101 million of the amount recovered by MC Asset Recovery was distributed pursuant to the terms of the Plan.  Following these distributions, GenOn Energy Holdings has no further obligation to provide funding to MC Asset Recovery.  As a result, GenOn Energy Holdings reversed its remaining accrual of $10 million of funding obligations as a reduction in operations and maintenance expense for 2009.  GenOn does not expect to owe any taxes related to the MC Asset Recovery settlement with Southern Company.
 
Based on a stipulation entered by the Bankruptcy Court in December 2011 and pursuant to the terms of the Plan and the MC Asset Recovery Limited Liability Company Agreement, during March 2012, GenOn Energy Holdings distributed $26 million of the $47 million in funds that had been previously retained by MC Asset Recovery.
 
One of the two remaining actions transferred to MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks (the Commerzbank Defendants) for alleged fraudulent transfers that occurred prior to the filing of GenOn Energy Holdings’ bankruptcy proceedings.  In its amended complaint, MC Asset Recovery alleges that the Commerzbank Defendants in 2002 and 2003 received payments totaling approximately 153 million Euros directly or indirectly from GenOn Energy Holdings under a guarantee provided by GenOn Energy Holdings in 2001 of certain equipment purchase obligations.  MC Asset Recovery alleges that at the time GenOn Energy Holdings provided the guarantee and made the payments to the Commerzbank Defendants, GenOn Energy Holdings was insolvent and did not receive fair value for those transactions.  In December 2010, the United States 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 United States District Court’s dismissal of its complaint against the Commerzbank Defendants to the United States Court of Appeals for the Fifth Circuit.  In March 2012, the United States Court of Appeals for the Fifth Circuit reversed the United States 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 on these avoidance claims, the Commerzbank
 
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Defendants have asserted that they will seek to file claims in GenOn Energy Holdings’ bankruptcy proceedings for the amount of those recoveries.  GenOn Energy Holdings would vigorously contest the allowance of any such claims on the ground that, among other things, the recovery of such amounts by MC Asset Recovery does not reinstate any enforceable pre-petition obligation that could give rise to a claim.  If such a claim were to be allowed by the Bankruptcy Court as a result of a recovery by MC Asset Recovery, then the Plan provides that the Commerzbank Defendants are entitled to the same distributions as previously made under the Plan to holders of similar allowed claims.  Holders of previously allowed claims similar in nature to the claims that the Commerzbank Defendants would seek to assert have received 43.87 shares of GenOn Energy Holdings common stock for each $1,000 of claim allowed by the Bankruptcy Court.  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, the order entered by the Bankruptcy Court in December 2005, confirming the Plan provides that 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 rather than distribute such amount to the unsecured creditors and former equity holders as described above.
 
Texas Franchise Audit
 
In 2008 and 2009, the State of Texas, as a result of its audit, issued franchise tax assessments against us indicating an underpayment of franchise tax of $72 million (including interest and penalties through September 30, 2012 of $29 million).  These assessments are related primarily to a claim by Texas that would change the sourcing of intercompany receipts for the years 2000 through 2006, thereby increasing the amount of tax due to Texas.  We disagree with most of the State’s assessment and its determination of the related tax liability.  Given the disagreement with the State’s position, we have accrued a portion of the liability but have protested the entire assessment and are currently in the administrative appeals process.  If we do not fully resolve or come to satisfactory settlement of the protested issues, then we could pay up to the entire amount of the assessed tax, penalties and interest.  We intend to defend fully our position in the administrative appeals process and if such defense requires litigation, would be required to pay the full assessment and sue for refund.
 
NRG Merger Litigation
 
During July and August 2012, we, the members of our board of directors, NRG, and Plus Merger Corporation (a wholly-owned subsidiary of NRG) were named defendants in nine purported class action lawsuits filed in the Court of Chancery of the State of Delaware, one of which has been dismissed and the remainder of which were consolidated into one action ( In re GenOn Energy, Inc. Shareholders Litigation, Consolidated C.A. No. 7721-VCN ). In October 2012, we signed a memorandum of understanding to settle the Delaware consolidated action based on additional disclosures that were provided to stockholders.
 
In July 2012, we, the members of our board of directors, NRG, and Plus Merger Corporation were also named defendants in three purported class action lawsuits filed in the 189 th  District Court of Harris County, Texas, which have been consolidated into one action ( Akel, et al. v. GenOn Energy, Inc., et al., Consolidated Case No. 2012-42090 ) and one purported class action lawsuit filed in the United States District Court for the Southern District of Texas ( Bushansky v. GenOn Energy, Inc. et al., No. 4:12-CV-02257 ).  In October 2012, the United States District Court for the Southern District of Texas issued an order granting the parties’ joint motion to stay the action until the later of the resolution of a motion for injunction or the final settlement of the Delaware consolidated action, which is discussed above.
 
Each case was brought on behalf of proposed classes consisting of holders of our common stock, excluding defendants and their affiliates.  The complaints allege, among other things, that (a) the NRG Merger Agreement was the product of breaches of fiduciary duties by the individual defendants, in that it allegedly does not maximize the value for our stockholders and that the individual defendants acted in their own self-interest in negotiating the transaction, (b) the joint proxy statement contains incomplete and misleading disclosures and (c) the other defendants aided and abetted the individual defendants’ breaches of fiduciary duties.  The complaints seek, among other things, (a) a declaration that the NRG Merger Agreement was entered into in breach of the defendants’ duties, (b) to enjoin defendants from consummating the NRG Merger, (c) directing the defendants to exercise their duties to obtain a transaction which is in the best interests of our stockholders, (d) granting the class members any benefits allegedly improperly received by the defendants, (e) a rescission of the NRG Merger if it is consummated and/or (f)
 
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an order directing additional disclosure regarding the NRG Merger.  We think that the allegations of the complaints are without merit and that we have substantial meritorious defenses to the claims made in these actions.  See note 1.
 
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EXHIBIT 99.3
 
UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS
 
The Unaudited Pro Forma Condensed Combined Consolidated Financial Statements, or the pro forma financial statements, combine the historical consolidated financial statements of NRG and GenOn to illustrate the effect of the merger.  The pro forma financial statements were based on, and should be read in conjunction with, the:
 
·                 accompanying notes to the Unaudited Pro Forma Condensed Combined Consolidated Financial Statements;
 
·                 consolidated financial statements of NRG for the year ended December 31, 2011 and the notes relating thereto, included in NRG’s Annual Report on Form 10-K;
 
·                 consolidated financial statements of NRG for the nine months ended September 30, 2012, and the notes relating thereto, included in NRG’s Quarterly Report on Form 10-Q; and
 
·                 consolidated financial statements of GenOn for the year ended December 31, 2011 and for the nine months ended September 30, 2012 and the notes relating thereto, included elsewhere in this Form 8-K/A.
 
The historical consolidated financial statements have been adjusted in the pro forma financial statements to give effect to pro forma events that are (1) directly attributable to the merger, (2) factually supportable and (3) with respect to the pro forma statements of operations, expected to have a continuing impact on the combined results.  The Unaudited Pro Forma Condensed Combined Consolidated Statements of Operations, or the pro forma statement of operations, for the year ended December 31, 2011 and for the nine months ended September 30, 2012, give effect to the merger as if it occurred on January 1, 2011.  The Unaudited Pro Forma Condensed Combined Consolidated Balance Sheet, or the pro forma balance sheet, as of September 30, 2012, gives effect to the merger as if it occurred on September 30, 2012.  Intercompany transactions have not been eliminated as the amounts are not material to the pro forma financial statements.
 
As described in the accompanying notes, the pro forma financial statements have been prepared using the acquisition method of accounting under existing United States generally accepted accounting principles, or GAAP, and the regulations of the SEC.  NRG is the acquirer in the merger for accounting purposes.  The purchase price has been allocated to GenOn’s assets and liabilities based upon their estimated fair values as of the date of completion of the merger.  The initial allocation is not complete because the evaluation necessary to assess the fair values of certain assets acquired is still in process.  The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.  Accordingly, the pro forma purchase price adjustments are preliminary, subject to future adjustments, and have been made solely for the purpose of providing the unaudited pro forma combined financial information presented herewith.  Differences between these provisional estimates and the final acquisition accounting will occur and these differences could have a material impact on the accompanying pro forma financial statements and the combined company’s future results of operations and financial position.
 
The pro forma financial statements have been presented for informational purposes only and are not necessarily indicative of what the combined company’s results of operations and financial position would have been had the merger been completed on the dates indicated.  NRG has incurred and expects to incur additional costs to integrate NRG’s and GenOn’s businesses.  The pro forma financial statements do not reflect the cost of any integration activities or benefits that may result from synergies that may be derived from any integration activities.  In addition, the pro forma financial statements do not purport to project the future results of operations or financial position of the combined company.
 
Description of the Merger
 
On December 14, 2012, NRG completed the acquisition of GenOn.  NRG issued, as consideration for the acquisition, 0.1216 shares of NRG common stock for each outstanding share of GenOn, including restricted stock units outstanding, on the acquisition date, except for fractional shares which were paid in cash.  NRG issued 93.9 million shares of NRG common stock, or 29% of total common shares outstanding following the closing of the transaction.
 
Upon completion of the merger, all outstanding GenOn stock options have been converted into stock options with respect to NRG common stock (with the number of shares subject to such options and the per share exercise price appropriately adjusted based on the exchange ratio) and remain outstanding, subject to the same terms and conditions otherwise applicable to such stock options prior to the merger, except that all GenOn stock options other than those granted in 2012 have vested upon the completion of the merger.  GenOn stock options granted in 2012 will not be subject to accelerated vesting solely by reason of the completion of the merger and will remain subject to the vesting conditions applicable to such stock options prior to the merger.
 
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All outstanding GenOn restricted stock units (other than restricted stock units granted in 2012) were immediately vested and were exchanged for the merger consideration upon completion of the merger (with cash paid in lieu of fractional shares).  GenOn restricted stock units granted in 2012 have been converted into NRG restricted stock units (with the number of shares subject to such restricted stock units appropriately adjusted based on the exchange ratio and extent of performance goal attainment) and otherwise remain outstanding in accordance with their terms.
 
GenOn outstanding stock options and restricted stock units granted in 2012 will vest (to the extent not already fully vested) at the holder’s termination date if the termination is a result of the merger and occurs within two years of completion of the merger.
 
2

 
NRG ENERGY, INC. AND GENON ENERGY, INC.
UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Nine Months Ended September 30, 2012
 
(In millions, except for per share amounts)	 	NRG Energy, Inc.
Historical	 	GenOn Energy,
Inc. Historical (a)	 	Pro Forma
Adjustments	 	 	Pro Forma
Combined	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	
Total operating revenues	 	$	6,359	 	$	1,997	 	$	—	 	 	$	8,356	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	
Cost of operations	 	4,618	 	1,624	 	(53	)	(b)	6,189	 	
Depreciation and amortization	 	703	 	269	 	(49	)	(c)	923	 	
Impairment losses	 	—	 	47	 	—	 	 	47	 	
Selling, general and administrative	 	681	 	137	 	—	 	 	818	 	
GenOn acquisition-related transaction and integration costs	 	18	 	—	 	—	 	 	18	 	
Development costs	 	26	 	—	 	—	 	 	26	 	
Total operating costs and expenses	 	6,046	 	2,077	 	(102	)	 	8,021	 	
Operating Income/(Loss)	 	313	 	(80	)	102	 	 	335	 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	 	26	 	2	 	—	 	 	28	 	
Impairment charge on investment	 	(2	)	—	 	—	 	 	(2	)	
Other income, net	 	14	 	1	 	—	 	 	15	 	
Loss on debt extinguishment	 	(41	)	—	 	—	 	 	(41	)	
Interest expense	 	(495	)	(260	)	86	 	(d)	(669	)	
Total other expense	 	(498	)	(257	)	86	 	 	(669	)	
Loss Before Income Taxes	 	(185	)	(337	)	188	 	 	(334	)	
Income tax (benefit)/expense	 	(246	)	8	 	70	 	(e)	(168	)	
Net Income/(Loss)	 	61	 	(345	)	118	 	 	(166	)	
Less: Net income attributable to noncontrolling interest	 	18	 	—	 	—	 	 	18	 	
Net Income/(Loss) Attributable to NRG Energy, Inc.	 	43	 	(345	)	118	 	 	(184	)	
Dividends for preferred shares	 	7	 	—	 	—	 	 	7	 	
Income/(Loss) Available for Common Stockholders	 	$	36	 	$	(345	)	 	118	 	 	$	(191	)	
Earnings/(Loss) Per Share Attributable to NRG Energy, Inc. Common Stockholders	 	 	 	 	 	 	 	 	 	 	
Weighted average number of common shares outstanding — basic	 	228	 	774	 	(680	)	(f)	322	 	
Net income/(loss) per weighted average common share — basic	 	$	0.16	 	$	(0.45	)	 	 	 	$	(0.59	)	
Weighted average number of common shares outstanding — diluted	 	230	 	774	 	(682	)	(f)	322	 	
Net income/(loss) per weighted average common share — diluted	 	$	0.16	 	$	(0.45	)	 	 	 	$	(0.59	)	
 
The accompanying notes are an integral part of these unaudited pro forma condensed combined consolidated financial statements.
 
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NRG ENERGY, INC. AND GENON ENERGY, INC.
UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2011
 
(In millions, except for per share amounts)	 	NRG Energy, Inc.
Historical	 	GenOn Energy,
Inc. Historical (a)	 	Pro Forma
Adjustments	 	 	Pro Forma
Combined	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	 	
Total operating revenues	 	$	9,079	 	$	3,614	 	$	—	 	 	$	12,693	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	 	
Cost of operations	 	6,675	 	2,642	 	(70	)	(b)	9,247	 	
Depreciation and amortization	 	896	 	375	 	(103	)	(c)	1,168	 	
Impairment charge on emission allowances	 	160	 	—	 	—	 	 	160	 	
Impairment losses	 	—	 	133	 	—	 	 	133	 	
Selling, general and administrative	 	668	 	255	 	—	 	 	923	 	
Development costs	 	45	 	—	 	—	 	 	45	 	
Total operating costs and expenses	 	8,444	 	3,405	 	(173	)	 	11,676	 	
Operating Income	 	635	 	209	 	173	 	 	1,017	 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	 	35	 	6	 	—	 	 	41	 	
Impairment charge on investment	 	(495	)	—	 	—	 	 	(495	)	
Other income (expense), net	 	19	 	(2	)	—	 	 	17	 	
Loss on debt extinguishment	 	(175	)	(23	)	—	 	 	(198	)	
Interest expense	 	(665	)	(379	)	118	 	(d)	(926	)	
Total other expense	 	(1,281	)	(398	)	118	 	 	(1,561	)	
Loss Before Income Taxes	 	(646	)	(189	)	291	 	 	(544	)	
Income tax benefit	 	(843	)	—	 	108	 	(e)	(735	)	
Net Income/(Loss)	 	197	 	(189	)	183	 	 	191	 	
Dividends for preferred shares	 	9	 	—	 	—	 	 	9	 	
Income/(Loss) Available for Common Stockholders	 	$	188	 	$	(189	)	$	183	 	 	$	182	 	
Earnings/(Loss) Per Share Attributable to Common Stockholders	 	 	 	 	 	 	 	 	 	 	
Weighted average number of common shares outstanding — basic	 	240	 	772	 	(678	)	(f)	334	 	
Net income/(loss) per weighted average common share — basic	 	$	0.78	 	$	(0.24	)	 	 	 	$	0.54	 	
Weighted average number of common shares outstanding — diluted	 	241	 	772	 	(678	)	(f)	335	 	
Net income/(loss) per weighted average common share — diluted	 	$	0.78	 	$	(0.24	)	 	 	 	$	0.54	 	
 
The accompanying notes are an integral part of these unaudited pro forma condensed combined consolidated financial statements.
 
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NRG ENERGY, INC. AND GENON ENERGY, INC.
UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED BALANCE SHEETS
As of September 30, 2012
 
(In millions, except shares)	 	NRG Energy,
Inc. Historical	 	GenOn Energy,
Inc. Historical
(a)	 	Pro Forma
Adjustments	 	 	Pro Forma
Combined	 	
ASSETS	 	 	 	 	 	 	 	 	 	 	
Current Assets	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	1,610	 	$	1,685	 	$	(686	)	(g)	$	2,609	 	
Funds deposited by counterparties	 	76	 	170	 	—	 	 	246	 	
Restricted cash	 	237	 	55	 	—	 	 	292	 	
Accounts receivable, net	 	1,075	 	272	 	—	 	 	1,347	 	
Inventory	 	393	 	412	 	22	 	(h)	827	 	
Derivative instruments	 	2,677	 	636	 	—	 	 	3,313	 	
Deferred income taxes	 	—	 	—	 	3	 	(i)	3	 	
Cash collateral paid in support of energy risk management activities	 	98	 	150	 	—	 	 	248	 	
Prepayments and other current assets	 	217	 	260	 	(99	)	(j)	378	 	
Total current assets	 	6,383	 	3,640	 	(760	)	 	9,263	 	
Property, plant and equipment, net	 	15,866	 	6,265	 	(2,351	)	(k)	19,780	 	
Other Assets	 	 	 	 	 	 	 	 	 	 	
Equity investments in affiliates	 	649	 	20	 	—	 	 	669	 	
Note receivable — affiliate and capital leases, less current portion	 	78	 	—	 	—	 	 	78	 	
Goodwill	 	1,886	 	—	 	—	 	 	1,886	 	
Intangible assets, net	 	1,188	 	79	 	(40	)	(l)	1,227	 	
Nuclear decommissioning trust fund	 	469	 	—	 	—	 	 	469	 	
Derivative instruments	 	309	 	588	 	—	 	 	897	 	
Deferred income taxes	 	—	 	196	 	1,022	 	(i)	1,218	 	
Other non-current assets	 	392	 	787	 	(491	)	(m)	688	 	
Total other assets	 	4,971	 	1,670	 	491	 	 	7,132	 	
Total Assets	 	$	27,220	 	$	11,575	 	$	(2,620	)	 	$	36,175	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	 	 	 	 	 	
Current portion of long-term debt and capital leases	 	$	374	 	$	10	 	$	(5	)	(n)	$	379	 	
Accounts payable	 	1,246	 	264	 	—	 	 	1,510	 	
Derivative instruments	 	2,462	 	398	 	—	 	 	2,860	 	
Deferred income taxes	 	15	 	196	 	(211	)	(i)	—	 	
Cash collateral received in support of energy risk management activities	 	76	 	170	 	—	 	 	246	 	
Accrued expenses and other current liabilities	 	604	 	361	 	107	 	(o)	1,072	 	
Total current liabilities	 	4,777	 	1,399	 	(109	)	 	6,067	 	
Other Liabilities	 	 	 	 	 	 	 	 	 	 	
Long-term debt and capital leases	 	10,968	 	4,361	 	(201	)	(n)	15,128	 	
Nuclear decommissioning reserve	 	349	 	—	 	—	 	 	349	 	
Nuclear decommissioning trust liability	 	277	 	—	 	—	 	 	277	 	
Deferred income taxes	 	1,092	 	—	 	(1,029	)	(i)	63	 	
Derivative instruments	 	561	 	184	 	—	 	 	745	 	
Out-of-market contracts	 	161	 	341	 	733	 	(p)	1,235	 	
Other non-current liabilities	 	896	 	528	 	50	 	(q)	1,474	 	
Total non-current liabilities	 	14,304	 	5,414	 	(447	)	 	19,271	 	
Total Liabilities	 	19,081	 	6,813	 	(556	)	 	25,338	 	
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)	 	249	 	—	 	—	 	 	249	 	
Stockholders’ Equity	 	 	 	 	 	 	 	 	 	 	
Common stock	 	3	 	1	 	—	 	(r)	4	 	
Additional paid-in capital	 	5,388	 	7,461	 	(5,423	)	(r)	7,426	 	
Retained earnings	 	4,002	 	(2,508	)	3,167	 	(r)	4,661	 	
Less treasury stock, at cost	 	(1,920	)	—	 	—	 	 	(1,920	)	
Accumulated other comprehensive loss	 	(68	)	(192	)	192	 	(r)	(68	)	
Noncontrolling interest	 	485	 	—	 	—	 	 	485	 	
Total Stockholders’ Equity	 	7,890	 	4,762	 	(2,064	)	 	10,588	 	
Total Liabilities and Stockholders’ Equity	 	$	27,220	 	$	11,575	 	$	(2,620	)	 	$	36,175	 	
 
The accompanying notes are an integral part of these unaudited pro forma condensed combined consolidated financial statements.
 
5

 
Note 1. Basis of Pro Forma Presentation
 
The pro forma statements of operations for the nine months ended September 30, 2012, and the year ended December 31, 2011, give effect to the merger as if it were completed on January 1, 2011. The pro forma balance sheet as of September 30, 2012 gives effect to the merger as if it were completed on September 30, 2012.
 
The pro forma financial statements have been derived from the historical consolidated financial statements of NRG and the historical consolidated financial statements of GenOn.  Assumptions and estimates underlying the pro forma adjustments are described in the accompanying notes, which should be read in connection with the pro forma financial statements.
 
The pro forma financial statements were prepared using the acquisition method of accounting and the regulations of the SEC.  NRG is acquirer in the merger for accounting purposes.  Upon completion of the merger, NRG stockholders have a majority of the voting interest in the combined company.  The purchase price has been allocated to GenOn’s assets and liabilities based upon their estimated fair values as of the date of completion of the merger.  The initial allocation is not complete because the evaluation necessary to assess the fair values of certain assets acquired is still in process.  The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.  Therefore, the pro forma financial statements are preliminary and have been prepared solely for the purpose of providing unaudited pro forma condensed combined financial information.  Differences between these preliminary estimates and the final acquisition accounting will occur and these differences could have a material impact on the accompanying pro forma financial statements and the combined company’s future results of operations and financial position.
 
The merger is reflected in the pro forma financial statements as being accounted for based on the accounting guidance for business combinations.  Under the acquisition method, the total purchase price is calculated as described in Note 2, Purchase Price and Purchase Price Allocation, to the pro forma financial statements.  In accordance with accounting guidance for business combinations, the assets acquired and the liabilities assumed have been measured at fair value. The fair value measurements utilize estimates based on key assumptions of the merger, including prior acquisition experience, benchmarking of similar acquisitions and historical and current market data. The pro forma adjustments included herein are likely to be revised as additional information which existed as of the acquisition date becomes available and as additional analyses are performed.  The allocation of the purchase price may be modified up to one year from the date of the acquisition as more information is obtained about the fair value of the assets acquired and liabilities assumed.  The final amounts recorded for the merger may differ materially from the information presented in these pro forma financial statements.
 
Transaction and integration costs incurred during 2012 of $107 million, as well as the related tax benefit of $40 million, calculated at NRG’s statutory rate of 37.21%, have been excluded from the pro forma statements of operations as these costs reflect non-recurring charges directly related to the merger and if not incurred prior to the merger are expected to be incurred in the period which includes the merger.  However, the transaction costs incurred through December 31, 2012 are reflected in the pro forma balance sheet as an accrual to accrued expenses and other current liabilities and a decrease to retained earnings.
 
The pro forma financial statements do not reflect any cost savings from operating efficiencies or synergies that could result from the merger.
 
For the purpose of measuring the estimated fair value of the assets acquired and liabilities assumed, as reflected in the pro forma financial statements, NRG and GenOn have applied the accounting guidance for fair value measurements, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
 
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Note 2. Purchase Price and Purchase Price Allocation
 
Purchase Price:
 
NRG acquired all of the outstanding common shares of GenOn for a fixed ratio of 0.1216 NRG shares per GenOn share.  The purchase price for the business combination was determined as follows (in millions except exchange ratio and share price):
 
 	 	Number of
Shares/Awards
Issued	 	NRG Equivalent
Shares at 0.1216	 	Total Estimated
Fair Value	 	
Issuance of NRG common stock to GenOn stockholders at the exchange ratio of 0.1216 shares for each share of GenOn common stock; based on the closing price of NRG common stock as of December 14, 2012, of $23.00	 	772.5	 	93.9	 	$	2,160	 	
Issuance of NRG equity awards to replace existing GenOn equity awards (see  Description of the Merger )	 	 	 	 	 	28	 	
Total purchase price	 	 	 	 	 	$	2,188	 	
 
The purchase price was computed using GenOn’s outstanding shares as of December 14, 2012, adjusted for the exchange ratio.  The purchase price also reflects the fair value of GenOn’s share-based compensation awards outstanding as of December 14, 2012, excluding the value associated with employee service yet to be rendered.
 
Purchase Price Allocation as of Acquisition Date:
 
 	 	Total Fair Value	 	
Current and non-current assets	 	$	2,368	 	
Property, plant and equipment	 	3,936	 	
Derivative assets	 	1,157	 	
Deferred income taxes	 	2,265	 	
Total assets acquired	 	$	9,726	 	
 	 	 	 	
Current and non-current liabilities	 	$	1,312	 	
Out-of-market contracts and leases	 	1,064	 	
Derivative liabilities	 	399	 	
Long-term debt and capital leases	 	4,203	 	
Total liabilities acquired	 	6,978	 	
Net assets acquired	 	2,748	 	
Consideration paid	 	2,188	 	
Gain on bargain purchase	 	$	560	 	
 
The above allocation of the purchase price to the fair values of assets acquired and liabilities assumed includes adjustments to reflect the fair values of GenOn’s assets and liabilities at the time of the completion of the merger.  The initial allocation is not complete because the evaluation necessary to assess the fair values of certain net assets acquired is still in process.  The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.
 
As the fair value of the net assets acquired exceeds the purchase price, the merger is being accounted for as a bargain purchase in accordance with the accounting guidance for business combinations.  Prior to recording a gain, the acquiring entity must reassess whether all acquired assets and assumed liabilities have been identified and perform re-measurements to verify that the assets acquired and liabilities assumed have been properly valued.  The estimated gain has been excluded from the pro forma statements of operations as it is non-recurring in nature.  The estimated gain on the bargain purchase is primarily representative of the undiscounted value of the deferred tax assets generated by the reduction in book basis of the net assets recorded in connection with acquisition accounting as well as the undiscounted value of GenOn’s net operating losses and other deferred tax benefits that the combined company has the ability to realize in the post-acquisition period.
 
Note 3.  Significant Accounting Policies
 
Upon completion of the merger, NRG completed the review of GenOn’s significant accounting policies and there were no significant adjustments necessary to conform GenOn’s accounting policies to NRG’s accounting policies.
 
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Note 4. Pro Forma Adjustments
 
The pro forma adjustments included in the pro forma financial statements are as follows:
 
(a) GenOn historical presentation — Based on the amounts reported in the consolidated statements of operations for the nine months ended September 30, 2012, and the year ended December 31, 2011, and the consolidated balance sheet as of September 30, 2012, certain financial line items included in GenOn’s historical presentation have been reclassified to corresponding line items included in NRG’s historical presentation.  These reclassifications have no effect on the historical operating income (loss), net income (loss), or stockholders’ equity reported by NRG or GenOn.
 
Adjustments to Pro Forma Condensed Combined Consolidated Statements of Operations
 
(b) Cost of operations — Represents adjustments related to the operating leases, including out-of-market liabilities, for GenOn REMA, LLC, and its subsidiaries, or REMA, and GenOn MidAtlantic, LLC and its subsidiaries, or GenOn Mid-Atlantic, to decrease net lease expense as a result of fair value adjustments and amortization of the related out-of-market values:
 
 	 	For the Nine Months Ended
September 30, 2012	 	For the Year Ended
December 31, 2011	 	
 	 	(in millions)	 	
GenOn Mid-Atlantic leases	 	$	(38	)	$	(50	)	
REMA leases	 	(4	)	(5	)	
Total	 	$	(42	)	$	(55	)	
 
Out-of-market liabilities for gas transportation and storage contracts of $328 million have been recorded as part of the provisional purchase accounting, the amortization of which decreases cost of operations as follows:
 
 	 	For the Nine Months Ended
September 30, 2012	 	For the Year Ended
December 31, 2011	 	
 	 	(in millions)	 	
Gas transportation and storage contracts	 	$	(11	)	$	(15	)	

(c) Depreciation and amortization — Represents the net depreciation expense resulting from the fair value adjustments of GenOn’s property, plant and equipment.  The estimated useful lives of the property, plant and equipment acquired range from 2 to 37 years.  The adjustments to depreciation and amortization include:
 
 	 	For the Nine Months Ended
September 30, 2012	 	For the Year Ended
December 31, 2011	 	
 	 	(in millions)	 	
Net decrease to depreciation expense as a result of fair value adjustments of property, plant and equipment	 	$	(49	)	$	(103	)	

(d) Interest expense — Reflects a decrease in interest expense as a result of the fair value adjustments of GenOn’s debt, and a reduction in interest expense due to the payment of GenOn’s Term Loan due 2017, or the GenOn Term Loan, upon completion of the merger.  The fair value determination of debt is based on prevailing market interest rates at the completion of the merger and the fair value adjustment will be amortized as a reduction to interest expense over the remaining life of the applicable debt.
 
 	 	For the Nine Months Ended
September 30, 2012	 	For the Year Ended
December 31, 2011	 	
 	 	(in millions)	 	
Net decrease in interest expense as a result of fair value adjustments of debt	 	$	(47	)	$	(63	)	
Net decrease in interest expense as a result of the paydown of the GenOn Term Loan	 	(39	)	(55	)	
Total	 	$	(86	)	$	(118	)	
 
The estimated amortization of the fair value adjustment to long-term debt over the next five years is as follows (in millions):
 
2012 (3 months)	 	$	(16	)	
2013	 	(63	)	 	
2014	 	(57	)	 	
2015	 	(52	)	 	
2016	 	(53	)	 	
2017	 	(44	)	 	

(e) Income taxes — Adjustment to record the tax effect of pro forma adjustments to revenue and expense, calculated utilizing NRG’s estimated combined statutory federal and state tax rate of 37.21%.
 
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(f) Weighted average shares outstanding - basic and diluted — The pro forma weighted average number of basic shares outstanding is calculated by adding NRG’s weighted average number of basic shares of common stock outstanding for the nine months ended September 30, 2012 or the year ended December 31, 2011, as applicable, and GenOn’s weighted average number of basic shares of common stock outstanding for those same periods multiplied by the exchange ratio of 0.1216.  The following table illustrates these computations:
 
Description	 	For the Nine Months
Ended September 30,
2012	 	For the Year Ended
December 31, 2011	 	
 	 	(shares in millions)	 	
Basic:	 	 	 	 	 	
GenOn weighted average basic common shares subject to exchange	 	774	 	772	 	
Exchange ratio	 	0.1216	 	0.1216	 	
Equivalent NRG common shares	 	94	 	94	 	
NRG historical weighted average basic common shares	 	228	 	240	 	
Pro forma weighted average basic common shares	 	322	 	334	 	
Diluted:	 	 	 	 	 	
GenOn weighted average diluted common shares	 	774	 	772	 	
Exchange ratio	 	0.1216	 	0.1216	 	
Equivalent NRG common shares	 	94	 	94	 	
NRG historical weighted average diluted common shares	 	230	(1)	241	 	
Pro forma weighted average diluted common shares	 	324	 	335	 	
Change in weighted average shares outstanding:	 	 	 	 	 	
GenOn shares exchanged	 	(774	)	(772	)	
NRG pro forma shares issued	 	94	 	94	 	
Net reduction in pro forma shares outstanding - basic	 	(680	)	(678	)	
Adjustment to NRG historical weighted average diluted common shares	 	(2	)(1)	—	 	
Net reduction in pro forma shares outstanding - diluted	 	(682	)	(678	)	

(1) NRG’s historical weighted average diluted common shares for the nine months ended September 30, 2012 have been adjusted to equal the NRG historical weighted average basic common shares outstanding, reflecting the combined company’s loss in the pro forma statement of operations.
 
The following table includes the number of securities that could potentially dilute basic earnings per share in the future that were not included in the computation because to do so would have been anti-dilutive:
 
 	 	For the Nine Months Ended September 30, 2012	 	
 	 	Stock Options and
Performance Units	 	Restricted Stock Units	 	Embedded Derivative of
3.625% Redeemable
Perpetual Preferred	 	
 	 	 	 	(shares in millions)	 	 	 	
GenOn historical shares	 	18	 	8	 	—	 	
Exchange ratio	 	0.1216	 	0.1216	 	0.1216	 	
Equivalent NRG shares	 	2	 	1	 	—	 	
NRG historical shares	 	6	 	—	 	16	 	
Total pro forma shares	 	8	 	1	 	16	 	
 
 	 	For the Year Ended December 31, 2011	 	
 	 	Stock Options and
Performance Units	 	Restricted Stock Units	 	Embedded Derivative of
3.625% Redeemable
Perpetual Preferred	 	
 	 	 	 	(shares in millions)	 	 	 	
GenOn historical shares	 	18	 	4	 	—	 	
Exchange Ratio	 	0.1216	 	0.1216	 	0.1216	 	
Equivalent NRG shares	 	2	 	—	 	—	 	
NRG historical shares	 	7	 	—	 	16	 	
Total pro forma shares	 	9	 	—	 	16	 	
 
Adjustments to Pro Forma Condensed Combined Consolidated Balance Sheet
 
(g) Cash and cash equivalents — Represents cash utilized to pay down the GenOn Term Loan of $686 million.
 
(h) Inventory — Represents the adjustment to record coal and fuel oil inventory at market prices as well as adjustments to record the materials and supplies inventory at fair value.
 
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(i) Deferred taxes — Represents the estimated deferred tax impact related to the excess of GenOn’s historical tax basis of assets and liabilities over the net amount assigned to GenOn’s assets and liabilities, calculated at the combined company tax rate, and the estimated deferred tax assets with respect to net operating losses and other temporary differences that are expected to be realized during post-acquisition periods, as well as the reclassification of NRG’s non-current deferred income tax liabilities to non-current deferred tax assets, as follows:
 
 	 	As of September 30, 2012	 	
 	 	(In millions)	 	
 	 	 	 	
Deferred tax assets - current:	 	 	 	
Adjustment to record realizable GenOn deferred tax assets	 	$	203	 	
Impact of excess of tax basis over fair value	 	 	50	 	
Netting of liabilities against assets	 	(250	)	
 	 	$	3	 	
 	 	 	 	
Deferred tax assets - non-current:	 	 	 	
Adjustment to record realizable GenOn deferred tax assets	 	$	939	 	
Impact of excess of tax basis over fair value	 	1,611	 	
Netting of liabilities against assets	 	(1,528	)	
 	 	$	1,022	 	
 	 	 	 	
Deferred tax liabilities - current:	 	 	 	
Impact of excess of tax basis over fair value	 	$	11	 	
Adjustment to record realizable GenOn deferred tax liabilities	 	28	 	
Netting of liabilities against assets	 	(250	)	
 	 	$	(211	)	
 	 	 	 	
Deferred tax liabilities - non-current:	 	 	 	
Impact of excess of tax basis over fair value	 	$	306	 	
Adjustment to record realizable GenOn deferred tax liabilities	 	 	193	 	
Netting of liabilities against assets	 	(1,528	)	
 	 	$	(1,029	)	
 
(j) Prepayments and other current assets — Represents the removal of prepaid rent related to the REMA and GenOn Mid-Atlantic leases for $42 million and $97 million, respectively.  The adjustment also includes a tax benefit of $40 million related to the estimated transaction costs of $107 million, as discussed below in adjustment (o).
 
(k) Property, plant and equipment — Represents the adjustment to reduce GenOn’s property, plant and equipment by $2,351 million to their estimated fair values.  The estimated fair values were determined based on consideration of both an income method using discounted cash flows and a market approach based on recent transactions of comparable assets.  The income approach was primarily relied upon as the forecasted cash flows as it more appropriately incorporates differences in regional markets, plant type, age, useful life, equipment condition and environmental controls of each asset.  Furthermore, the income approach allows for a more accurate reflection of current and expected market dynamics such as supply and demand, commodity prices, and regulatory environment as of the valuation date.  Under this approach, the expected future cash flows associated with each plant were estimated and then discounted to present value at the weighted average cost of capital derived from an independent power producer peer group and risk adjusted to reflect the individual characteristics of each plant.  The market approach was computed based on data for transactions announced proximate to the valuation date and analyzed on a $/kW basis for fuel/dispatch type and region.  Due to the limited volume of recent transactions and amount of financial and operating characteristics that are publicly disclosed, that market approach was given less weight.  The estimated useful lives of the property, plant and equipment acquired range from 2 to 37 years.
 
(l) Intangible assets — Represents the adjustment to record the acquired emission allowances, development rights and other intangible assets at fair value.
 
(m) Other non-current assets — Represents the removal of $78 million of unamortized deferred financing costs for GenOn’s long-term debt, and the removal of $413 million of prepaid rent related to the GenOn Mid-Atlantic lease.
 
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(n) Long-term debt, including current portion — Represents adjustments to GenOn’s long-term debt as follows:
 
 	 	As of September 30, 2012	 	
 	 	(In millions)	 	
Estimated fair value adjustment of GenOn’s long-term debt	 	$	454	 	
Write-off of unamortized discount on GenOn’s long-term debt	 	26	 	
Paydown of the GenOn Term Loan	 	(686	)	
Total adjustments to GenOn’s long-term debt	 	$	(206	)	
 
The adjustments above reflect the paydown of the GenOn Term Loan upon closing of the merger.  The fair value adjustment of GenOn’s debt was estimated based on market prices and quotes from investment banks as of December 14, 2012 and will be amortized as a reduction to interest expense over the remaining life of the individual debt issues, with the longest amortization period being approximately 19 years.
 
(o) Accrued expenses and other current liabilities — Represents the accrual for transaction and integration costs of $107 million, consisting of investment banking fees, commitment fees, legal fees and other merger-related transaction and integration costs.  The merger transaction costs are excluded from the pro forma statements of operations as they reflect non-recurring charges not expected to have a continuing impact on the combined results.
 
(p) Out-of-market contracts — Represents an adjustment to the out-of-market fair value of the REMA and GenOn Mid-Atlantic leases of $63 million and $540 million, respectively, as well as an adjustment to the fair value of out-of-market gas transportation and storage contracts of $130 million.  The total out-of-market value of the lease contracts is $728 million and the out-of-market value of the gas transportation and storage contracts is $328 million.
 
(q) Other non-current liabilities — Represents an adjustment to record the asset retirement and pension obligations at fair value.
 
(r) Equity — Represents adjustments to common stock and additional paid-in capital to reflect the value of consideration transferred by NRG to complete the merger.  The adjustment to common stock is based on the par value of NRG common stock of $0.01 per share.  In addition, the pro forma equity also includes adjustments to retained earnings totaling approximately $560 million for the initial gain on bargain purchase and $107 million of transaction costs, net of the related tax benefit.  The transaction costs are shown as an adjustment to retained earnings in accordance with accounting guidance applicable to business combinations, which requires that these costs be expensed.
 
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