Filed by NRG Energy, Inc.
Commission File No. 001-15891
 
Pursuant to Rule 425 of the Securities Act of 1933, as amended, and
deemed filed pursuant to Rule 14a-6 of the Securities Exchange Act of 1934, as amended
 
Subject Company:
GenOn Energy, Inc.
Commission File No. 001-16455

 
NRG Energy, Inc. Reports Third Quarter 2012 Results and Narrows Guidance to Middle of Range
 
Financial Highlights
 
·                 $657 million of adjusted EBITDA, including $173 million delivered by NRG’s retail businesses in the third quarter of 2012;
·                 $1,496 million of adjusted EBITDA in the first nine months of 2012, including $504 million delivered by NRG’s retail businesses;
·                 $806 million of Free Cash Flow (FCF) before growth investments in the first nine months of 2012;
·                 $2,710 million of total liquidity at the end of the third quarter, adjusted for the $270 million redemption of our Senior Notes in October
 
Guidance
 
·                 2012 Guidance Narrowed:
 
·                 Adjusted EBITDA: $1,875-$1,925 million;
·                 FCF before growth investments: $900-$950 million
 
·                 2013 and 2014 Guidance Reaffirmed (NRG standalone basis):
 
·                 2013 Adjusted EBITDA $1,700-$1,900 million;
·                 2013 FCF before growth investments: $650-$850 million;
·                 2014 Adjusted EBITDA $1,700-$1,900 million;
·                 2014 FCF before growth investments: $500-$700 million
 
Business and Operational Highlights
 
·                 GenOn merger remains on track with closing expected by first quarter 2013;
·                 $100 million in deleveraging, representing approximately $14 million in annual interest savings, achieved via refinancing of Senior Unsecured Notes, due 2017;
·                 $110 million reduction in expected environmental capital expenditures through 2016 reflecting a decrease in costs related to changes in technology, completing projects below budget, and shifts in compliance schedules based on regulatory changes;
·                 Retail customer count increased 124,000 since year end 2011 including 79,000 in the Northeast markets
 
PRINCETON, NJ; November 2, 2012—NRG Energy, Inc. (NYSE: NRG) today reported third quarter 2012 adjusted EBITDA of $657 million with Wholesale contributing $449 million, Retail contributing $173 million and Solar projects contributing $35 million. The Company reported third quarter 2012 net loss of

 
$1 million, or ($0.01) per diluted common share compared, to a net loss of $55 million, or ($0.24) per diluted common share, for the third quarter of 2011.
 
Adjusted EBITDA for the nine months ended September 30, 2012, was $1,496 million and adjusted cash flow from operations was $993 million. Adjusted cash flow from operations improved $386 million as compared to the nine months ended September 30, 2011, due to improved operational results, reduced interest expense and reductions in collateral postings. Wholesale contributed $928 million of adjusted EBITDA, Retail contributed $504 million of adjusted EBITDA and Solar projects contributed $64 million. Year-to-date 2012 FCF before growth investments was $806 million. Net income for the first nine months of 2012 was $43 million, or $0.16 per diluted common share, compared to net income of $306 million, or $1.22 per diluted common share, for the first nine months of 2011.
 
“The twin focus of NRG management this quarter has been on achieving in a timely manner all of the milestones, including integration planning, towards closing the GenOn transaction and on delivering a solid third quarter 2012 financial performance.  I am pleased to say that we have achieved both,” commented David Crane, NRG’s President and Chief Executive Officer. “As we move to realize the substantial EBITDA and cash flow synergies directly created by this powerful merger, we are also preparing to capture the ‘knock on’ benefits of the combination in terms of operational cost synergies, retail expansion and the like.”
 
Segment Results
 
Table 1: Adjusted EBITDA
 
($ in millions)	 	Three Months Ended	 	Nine Months Ended	 	
Segment	 	9/30/12	 	9/30/11	 	9/30/12	 	9/30/11	 	
Retail	 	173	 	145	 	504	 	504	 	
Texas	 	324	 	188	 	689	 	642	 	
Northeast	 	58	 	43	 	83	 	94	 	
South Central	 	31	 	42	 	84	 	106	 	
West	 	31	 	34	 	68	 	59	 	
Other	 	16	 	15	 	52	 	43	 	
Alternative Energy(1)	 	24	 	(5	)	35	 	(9	)	
Corporate	 	—	 	(4	)	(19	)	(9	)	
Adjusted EBITDA(2)	 	657	 	458	 	1,496	 	1,430	 	

(1)        Alternative Energy includes the results of the Company’s Solar projects
(2)        Detailed adjustments by region are shown in Appendix A
 
Table 2: Net (Loss)/Income
 
($ in millions)	 	Three Months Ended	 	Nine Months Ended	 	
Segment	 	9/30/12	 	9/30/11	 	9/30/12	 	9/30/11	 	
Retail	 	(300	)	36	 	504	 	350	 	
Texas	 	299	 	(45	)	(202	)	193	 	
Northeast	 	33	 	6	 	(20	)	(13	)	
South Central	 	19	 	21	 	—	 	46	 	
West	 	35	 	27	 	42	 	51	 	
Other	 	9	 	5	 	25	 	14	 	
Alternative Energy	 	(9	)	(12	)	(40	)	(42	)	
Corporate	 	(87	)	(93	)	(266	)	(293	)	
Net Income	 	(1	)	(55	)	43	 	306	 	
 
Retail: Adjusted EBITDA for the third quarter of 2012 was $173 million; $28 million higher than in 2011. Gross margin was favorable by $87 million driven by the acquisition of Energy Plus which added $41
 
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million, with the remaining difference due to increased customer count and usage, lower supply costs and favorable year over year weather impacts. Partially offsetting the higher margin realized in 2012 was an increase in operating costs which were the result of the acquisition of Energy Plus and continued efforts to drive market expansion and customer growth, resulting in an approximate 124,000 increase in customer count since December 31, 2011.
 
Texas (Generation): Adjusted EBITDA for the third quarter of 2012 was $324 million; $136 million higher compared to the third quarter of 2011. Gross Margin increased $150 million, driven by a combination of 21% higher realized energy margin and improved bi-lateral capacity contracts which together added $194 million. The substantial year-over-year increase in third quarter realized energy margin is largely attributable to the impact of the unprecedented hot weather and resulting ERCOT power price spikes in August of 2011. Partially offsetting the increase was a 13% decline in coal generation due to longer plant outages in 2012.
 
Northeast: Adjusted EBITDA for the third quarter of 2012 was $58 million; $15 million higher compared to the third quarter of 2011. The increase was driven by higher gross margin of $16 million as the Northeast benefited from additional energy sales to the Company’s retail providers as a result of efforts to expand its retail presence in the region. Also contributing to the positive results were more favorable capacity pricing in the PJM markets and increased revenues resulting from the Reliability Support Services Agreement in Western New York.
 
South Central: Adjusted EBITDA for the third quarter of 2012 was $31 million; $11 million lower than the third quarter 2011. Gross margin in 2012 decreased by $10 million versus the third quarter of 2011 due to 12% lower average realized prices. The region experienced a 5% decline in coal generation that was partially offset by a 10% increase in generation at Cottonwood as compared to the third quarter of 2011.
 
West: Adjusted EBITDA for the third quarter of 2012 was $31 million; $3 million lower than the third quarter 2011 due to a decrease in capacity revenues partially offset by an increase in unrealized trading activity.
 
Alternative Energy: Adjusted EBITDA for the third quarter of 2012 was $24 million; up $29 million from 2011. Gross margin was $55 million, a $45 million increase driven by the addition of the Roadrunner facility, which began commercial operations in late 2011 and the addition of the Company’s Agua Caliente solar facility, which as of September 30, 2012 had reached commercial operations on 230 MWs. Offsetting the improved margin were NRG’s continued development efforts in our other new businesses.
 
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Liquidity and Capital Resources
 
Table 3: Corporate Liquidity
 
($ in millions)	 	9/30/12	 	6/30/12	 	12/31/11	 	
Cash and Cash Equivalents	 	1,610	 	1,149	 	1,105	 	
Funds deposited by counterparties	 	76	 	135	 	258	 	
Restricted cash	 	237	 	208	 	292	 	
Total Cash and Funds Deposited	 	1,923	 	1,492	 	1,655	 	
Revolver Availability	 	1,133	 	1,049	 	673	 	
Total Liquidity	 	3,056	 	2,541	 	2,328	 	
Less: Funds deposited as collateral by hedge counterparties	 	(76	)	(135	)	(258	)	
Total Current Liquidity	 	2,980	 	2,406	 	2,070	 	
Less: Reserve for 2017 bond redemption(1)	 	(270	)	—	 	—	 	
Total Current Liquidity, adjusted	 	2,710	 	2,406	 	2,070	 	

(1) On October 24th, NRG redeemed the remaining $270 million outstanding of the 2017 Senior Notes
 
Total liquidity, adjusted as of September 30, 2012, was $2,710 million, an increase of $640 million from December 31, 2011 driven largely by a $460 million increase in Revolver availability primarily due to the sell-down of the Agua Caliente project. The $55 million decrease in restricted cash is primarily due to reduced collateral requirements for the Company’s solar projects as NRG continues to contribute equity to these projects.  Finally, cash and cash equivalents increased by $235 million due to the following items:
 
·                 $993 million of adjusted cash flow from operations;
·                 $174 million in proceeds from the sale of Schkopau;
·                 $122 million in proceeds from the sell down of the Agua Caliente project;
·                 Partially offset by $1,013 million of cash outflows consisting of the following items:
 
·                 $180 million of cash paid for maintenance and environmental capital expenditures (net of financing of $9 million);
·                 $527 million for solar and conventional growth investments (net of debt and third party funding of $1,704 million);
·                 $172 million net paydown of Senior Unsecured Notes and $46 million of scheduled debt amortization; and
·                 $47 million of changes in dividends, restricted cash and other investing and financing activities
 
Growth Initiatives and Developments
 
NRG continued to advance its leadership position in sustainable energy including:
 
Solar
 
·                 Agua Caliente — As of September 30, 2012, 230 MWs of generation capacity have achieved commercial operation making Agua Caliente the largest operating solar PV project in the United States.  Overall, construction at Agua Caliente is several months ahead of schedule. Power generated by Agua Caliente will be sold under a 25-year power purchase agreement (PPA) with Pacific Gas and Electric Co (PG&E).
·                 CVSR — Construction of the California Valley Solar Ranch project is well advanced, with 22 MWs achieving operation on September 19, 2012. We continue to expect all other phases of the project to be completed earlier than the dates anticipated at the time the project was acquired, with 125 MWs on-line by the end of 2012 and the remaining 125 MWs completed in the third and fourth quarter of 2013. Power from this project will be sold to PG&E under 25-year PPAs.
 
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·                 Ivanpah —Unit 1 (124 MWs) is expected to produce its first steam in January 2013 and be completed and producing power in May 2013. The remaining two units (each at 127 MWs) are currently expected to be completed in the third and fourth quarter of 2013. Power from Units 1 and 3 will be sold to PG&E via two 25-year PPAs, and power from Unit 2 will be sold to Southern California Edison under a 20-year PPA.
·                 Other Solar —NRG Solar also has several other smaller projects under construction that are expected to reach commercial operation within 2012; ranging from the Borrego project (26 MWs under a 25-year PPA with San Diego Gas and Electric) to smaller Distributed Generation scale installations, such as our “showcase” solar projects currently operating or under construction at four NFL stadiums.
 
Alternative Energy
 
·                 Petra Nova— Petra Nova continues with the development of its peaking unit at NRG’s WA Parish Generating Station and on August 14, 2012 signed a $24 million lump-sum, turnkey EPC contract.  Petra Nova is targeting a May 2013 commercial operation date, and it is anticipated that the unit will eventually be used as a cogeneration facility dedicated to a Carbon Capture Utilization and Storage Project, sponsored in part by the Department of Energy, at the Parish facility.  The peaking unit is being financed, in part with the proceeds of a $54 million tax-exempt bond financing that was completed on May 3, 2012, of which NRG has drawn $16 million through September 30, 2012.
 
Guidance Update
 
Notwithstanding the comparatively mild summer weather on the back of extremely mild weather last winter, NRG is pleased to narrow its adjusted EBITDA guidance for 2012 to the center of the previous range.  For fiscal year 2012, NRG projects $1,875-$1,925 million of adjusted EBITDA on a standalone basis with Wholesale contributing $1,170-$1,195 million, Retail contributing $630-$650 million and Solar projects contributing $75-80 million. The Company is also narrowing its free cash flow before growth investments guidance range to $900-$950 million. For fiscal years 2013 and 2014, NRG also affirms the standalone guidance previously given.
 
Table 4: 2012 Reconciliation of Adjusted EBITDA Guidance
 
($ in millions)	 	11/2/12	 	8/8/12	 	
Adjusted EBITDA guidance	 	1,875 – 1,925	 	1,825 – 2,000	 	
Interest payments	 	(659	)	(605	)	
Income tax	 	(30	)	(50	)	
Collateral/working capital/other changes	 	(36	)	(94	)	
Adjusted cash flow from operations	 	1,150 – 1,200	 	1,050 – 1,250	 	
Maintenance capital expenditures,net	 	(232	)	(240)-(260	)	
Environmental capital expenditures, net	 	(6	)	(5)-(15	)	
Preferred dividends	 	(9	)	(9	)	
Free cash flow — before growth investments	 	900 – 950	 	800 – 1,000	 	
 
Note: Subtotals and totals are rounded
 
2012 Capital Allocation Program
 
On September 24, 2012, NRG issued $990 million aggregate principal amount at par of 6.625% Senior Notes due 2023. The Company used the net proceeds, $978 million, and additional cash on hand to redeem $820 million of the 2017 Notes through a tender offer at an early redemption percentage of 104.125%, with the remaining $270 million of notes redeemed during October. This refinancing reduces corporate debt by $100 million, decreases annual interest expense by $14 million and creates a single covenant package
 
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across credit facilities and debt securities enabling the Company to invest more opportunistically in growth initiatives and enhance its ability to efficiently return capital to all investors.
 
Earnings Conference Call
 
On November 2, 2012, NRG will host a conference call at 8:30 am eastern to discuss these results. Investors, the news media and others may access the live webcast of the conference call and accompanying presentation materials by logging on to NRG’s website at http://www.nrgenergy.com and clicking on “Investors.” The webcast will be archived on the site for those unable to listen in real time.
 
About NRG
 
NRG is at the forefront of changing how people think about and use energy. A Fortune 500 company, NRG is a pioneer in developing cleaner and smarter energy choices for our customers: whether as one of the largest solar power developers in the country, or by building the first privately funded electric vehicle charging infrastructure or by giving customers the latest smart energy solutions to better manage their energy use. Our diverse power generating facilities can support over 20 million homes and our retail electricity providers—Reliant, Green Mountain Energy Company and Energy Plus—serve more than two million customers. More information is available at nrgenergy.com. Connect with NRG Energy on Facebook and follow us on Twitter @nrgenergy.
 
Safe Harbor Disclosure
 
In addition to historical information, the information presented in this report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. These statements involve estimates, expectations, projections, goals, assumptions, known and unknown risks and uncertainties and can typically be identified by terminology such as “may,” “will,” “should,” “could,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “expect,” “intend,” “seek,” “plan,” “think,” “anticipate,” “estimate,” “predict,” “target,” “potential” or “continue” or the negative of these terms or other comparable terminology. Such forward-looking statements include, but are not limited to, statements about the anticipated benefits of the proposed transaction between NRG and GenOn, each party’s and the combined company’s future revenues, income, indebtedness, capital structure, plans, expectations, objectives, projected financial performance and/or business results and other future events, each party’s views of economic and market conditions, and the expected timing of the completion of the proposed transaction.
 
Forward-looking statements are not a guarantee of future performance and actual events or results may differ materially from any forward-looking statement as result of various risks and uncertainties, including, but not limited to, those relating to: the ability to satisfy the conditions to the proposed transaction between NRG and GenOn, the ability to successfully complete the proposed transaction (including any financing arrangements in connection therewith) in accordance with its terms and in accordance with expected schedule, the ability to obtain stockholder, regulatory or other approvals for the proposed transaction, or an inability to obtain them on the terms proposed or on the anticipated schedule, diversion of management attention on transaction-related issues, impact of the transaction on relationships with customers, suppliers and employees, the ability to finance the combined business post-closing and the terms on which such financing may be available, the financial performance of the combined company following completion of the proposed transaction, the ability to successfully integrate the businesses of NRG and GenOn, the ability to realize anticipated benefits of the proposed transaction (including expected cost savings and other synergies) or the risk that anticipated benefits may take longer to realize than expected, legislative, regulatory and/or market developments, the outcome of pending or threatened lawsuits, regulatory or tax proceedings or investigations, the effects of competition or regulatory intervention, financial and economic market conditions, access to capital, the timing and extent of changes in law and regulation (including environmental), commodity prices, prevailing demand and market prices for electricity, capacity, fuel and emissions allowances, weather conditions, operational constraints or outages, fuel supply or transmission issues, hedging ineffectiveness.
 
Additional information concerning other risk factors is contained in NRG’s and GenOn’s most recently filed Annual Reports on Form 10-K, subsequent Quarterly Reports on Form 10-Q, recent Current Reports on Form 8-K, and other SEC filings.
 
Many of these risks, uncertainties and assumptions are beyond NRG’s ability to control or predict. Because of these risks, uncertainties and assumptions, you should not place undue reliance on these forward-looking statements. Furthermore, forward-looking statements speak only as of the date they are made, and NRG does not undertake any obligation to update publicly or revise any forward-looking statements to reflect events or circumstances that may arise after the date of this communication. All subsequent written and oral forward-looking statements concerning NRG, GenOn, the proposed transaction, the combined
 
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company or other matters and attributable to NRG, GenOn or any person acting on their behalf are expressly qualified in their entirety by the cautionary statements above.
 
Additional Information about the Proposed Transaction and Where You Can Find It
 
In connection with the proposed merger between NRG and GenOn, NRG filed with the Securities and Exchange Commission (“SEC”) a registration statement on Form S-4 that includes a joint proxy statement of NRG and GenOn and that also constitutes a prospectus of NRG. The registration statement was declared effective by the SEC on October 5, 2012. NRG and GenOn first mailed the joint proxy statement/prospectus to their respective stockholders on or about October 10, 2012. NRG and GenOn may also file other documents with the SEC regarding the proposed transaction. INVESTORS AND SECURITY HOLDERS OF NRG AND GENON ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS THAT ARE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Investors and stockholders may obtain free copies of the joint proxy statement/prospectus and other documents containing important information about NRG and GenOn through the website maintained by the SEC at www.sec.gov. In addition, NRG makes available free of charge at www.nrgenergy.com (in the “Investors” section), copies of materials it files with, or furnish to, the SEC.
 
Participants In The Merger Solicitation
 
NRG, GenOn, and certain of their respective directors and executive officers may be deemed to be participants in the solicitation of proxies from the stockholders of NRG and GenOn in connection with the proposed transaction.  Information about the directors and executive officers of NRG is set forth in its proxy statement for its 2012 annual meeting of stockholders, which was filed with the SEC on March 12, 2012.  Information about the directors and executive officers of GenOn is set forth in its proxy statement for its 2012 annual meeting of stockholders, which was filed with the SEC on March 30, 2012.  Other information regarding the participants in the proxy solicitation can be found in the above-referenced registration statement on Form S-4. These documents can be obtained free of charge from the sources indicated above.
 
Contacts:	 	
 	 	
Media:	Investors:	
 	 	
Jerianne Thomas	Chad Plotkin	
713.537.2087	609.524.4526	
 	 	
Lori Neuman	Stefan Kimball	
609.524.4525	609.524.4527	
 	 	
Dave Knox	 	
713.537.2130	 	
 
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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
 
 	 	Three months ended September 30,	 	Nine months ended September 30,	 	
(In millions, except for per share amounts)	 	2012	 	2011	 	2012	 	2011	 	
 	 	 	 	 	 	 	 	 	 	
Operating Revenues	 	 	 	 	 	 	 	 	 	
Total operating revenues	 	$	2,331	 	$	2,674	 	$	6,359	 	$	6,947	 	
Operating Costs and Expenses	 	 	 	 	 	 	 	 	 	
Cost of operations	 	1,726	 	2,053	 	4,618	 	4,985	 	
Depreciation and amortization	 	239	 	238	 	703	 	665	 	
Impairment charge on emissions allowance	 	—	 	160	 	—	 	160	 	
Selling, general and administrative	 	253	 	169	 	681	 	479	 	
Acquisition-related transaction and integration costs	 	18	 	—	 	18	 	—	 	
Development costs	 	9	 	11	 	26	 	32	 	
Total operating costs and expenses	 	2,245	 	2,631	 	6,046	 	6,321	 	
Operating Income	 	86	 	43	 	313	 	626	 	
Other Income/(Expense)	 	 	 	 	 	 	 	 	 	
Equity in earnings of unconsolidated affiliates	 	4	 	16	 	26	 	26	 	
Impairment charge on investment	 	(1	)	(3	)	(2	)	(495	)	
Other income, net	 	10	 	5	 	14	 	13	 	
Loss on debt extinguishment	 	(41	)	(32	)	(41	)	(175	)	
Interest expense	 	(163	)	(164	)	(495	)	(504	)	
Total other expense	 	(191	)	(178	)	(498	)	(1,135	)	
Loss Before Income Taxes	 	(105	)	(135	)	(185	)	(509	)	
Income tax benefit	 	(113	)	(80	)	(246	)	(815	)	
Net Income/(Loss)	 	8	 	(55	)	61	 	306	 	
Less: Net income attributable to noncontrolling interest	 	9	 	—	 	18	 	—	 	
Net Income/(Loss) Attributable to NRG Energy, Inc.	 	(1	)	(55	)	43	 	306	 	
Dividends for preferred shares	 	2	 	2	 	7	 	7	 	
(Loss) /Income Available for Common Stockholders	 	$	(3	)	$	(57	)	$	36	 	$	299	 	
(Loss) Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders	 	 	 	 	 	 	 	 	 	
Weighted average number of common shares outstanding — basic	 	228	 	240	 	228	 	243	 	
Net (Loss)/Income per weighted average common share — basic	 	$	(0.01	)	$	(0.24	)	$	0.16	 	$	1.23	 	
Weighted average number of common shares outstanding —diluted	 	228	 	240	 	230	 	245	 	
Net (Loss)/Income per weighted average common share —diluted	 	$	(0.01	)	$	(0.24	)	$	0.16	 	$	1.22	 	
Dividends Per Common Share	 	$	0.09	 	$	—	 	$	0.09	 	$	—	 	
 
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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE LOSS
(Unaudited)
 
 	 	Three months ended 
September 30,	 	Nine months ended 
September 30,	 	
 	 	2012	 	2011	 	2012	 	2011	 	
Net Income/(Loss)	 	$	8	 	$	(55	)	$	61	 	$	306	 	
Other Comprehensive (Loss)/Income net of tax	 	 	 	 	 	 	 	 	 	
Unrealized loss on derivatives, net of income tax benefit of $24, $45, $76 and $131	 	(43	)	(76	)	(132	)	(225	)	
Foreign currency translation adjustments, net of income tax benefit (expense) of $0, $16, $1 and $4	 	1	 	(27	)	(1	)	(5	)	
Reclassification adjustment for translation gain realized upon sale of Schkopau, net of income tax benefit of $6,$0,$6 and $0	 	(11	)	—	 	(11	)	—	 	
Available -for-sale securities, net of income tax benefit of ($1), $1, ($1) and $1	 	2	 	(1	)	2	 	(2	)	
Defined benefit plans	 	—	 	—	 	—	 	1	 	
Other comprehensive loss	 	(51	)	(104	)	(142	)	(231	)	
Comprehensive (Loss)/Income	 	(43	)	(159	)	(81	)	75	 	
Less: Comprehensive income attributable to noncontrolling interest	 	9	 	—	 	18	 	—	 	
Comprehensive (Loss)/Income Attributable to NRG Energy, Inc.	 	(52	)	(159	)	(99	)	75	 	
Dividends for preferred shares	 	2	 	2	 	7	 	7	 	
Comprehensive (Loss)/Income available for common stockholders	 	$	54	 	$	(161	)	$	(106	)	$	68	 	
 
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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 
(In millions, except shares)	 	September 30, 2012	 	December 31, 2011	 	
 	 	(unaudited)	 	 	 	
ASSETS	 	 	 	 	 	
Current Assets	 	 	 	 	 	
Cash and cash equivalents	 	$	1,610	 	$	1,105	 	
Funds deposited by counterparties	 	76	 	258	 	
Restricted cash	 	237	 	292	 	
Accounts receivable — trade, less allowance for doubtful accounts of $39 and $23	 	1,075	 	834	 	
Inventory	 	393	 	308	 	
Derivative instruments	 	2,677	 	4,216	 	
Cash collateral paid in support of energy risk management activities	 	98	 	311	 	
Prepayments and other current assets	 	217	 	273	 	
Total current assets	 	6,383	 	7,597	 	
Property, plant and equipment, net of accumulated depreciation of $5,194 and $4,570	 	15,866	 	13,621	 	
Other Assets	 	 	 	 	 	
Equity investments in affiliates	 	649	 	640	 	
Note receivable — affiliate and capital leases, less current portion	 	78	 	342	 	
Goodwill	 	1,886	 	1,886	 	
Intangible assets, net of accumulated amortization of $1,628 and $1,452	 	1,188	 	1,419	 	
Nuclear decommissioning trust fund	 	469	 	424	 	
Derivative instruments	 	309	 	450	 	
Other non-current assets	 	392	 	336	 	
Total other assets	 	4,971	 	5,497	 	
Total Assets	 	$	27,220	 	$	26,715	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	
Current Liabilities	 	 	 	 	 	
Current portion of long-term debt and capital leases	 	$	374	 	$	87	 	
Accounts payable	 	1,246	 	808	 	
Derivative instruments	 	2,462	 	3,751	 	
Deferred income taxes	 	15	 	127	 	
Cash collateral received in support of energy risk management activities	 	76	 	258	 	
Accrued expenses and other current liabilities	 	604	 	640	 	
Total current liabilities	 	4,777	 	5,671	 	
Other Liabilities	 	 	 	 	 	
Long-term debt and capital leases	 	10,968	 	9,745	 	
Nuclear decommissioning reserve	 	349	 	335	 	
Nuclear decommissioning trust liability	 	277	 	254	 	
Deferred income taxes	 	1,092	 	1,389	 	
Derivative instruments	 	561	 	464	 	
Out-of-market commodity contracts	 	161	 	183	 	
Other non-current liabilities	 	896	 	756	 	
Total non-current liabilities	 	14,304	 	13,126	 	
Total Liabilities	 	19,081	 	18,797	 	
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)	 	249	 	249	 	
Commitments and Contingencies	 	 	 	 	 	
Stockholders’ Equity	 	 	 	 	 	
Common stock	 	3	 	3	 	
Additional paid-in capital	 	5,388	 	5,346	 	
Retained earnings	 	4,002	 	3,987	 	
Less treasury stock, at cost — 76,505,718 and 76,664,199 shares, respectively	 	(1,920	)	(1,924	)	
Accumulated other comprehensive (loss) income	 	(68	)	74	 	
Noncontrolling interest	 	485	 	183	 	
Total Stockholders’ Equity	 	7,890	 	7,669	 	
Total Liabilities and Stockholders’ Equity	 	$	27,220	 	$	26,715	 	
 
10

 
NRG 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 income	 	$	61	 	$	306	 	
Adjustments to reconcile net loss to net cash provided by operating activities:	 	 	 	 	 	
Distributions and equity in earnings of unconsolidated affiliates	 	8	 	8	 	
Depreciation and amortization	 	703	 	665	 	
Provision for bad debts	 	40	 	41	 	
Amortization of nuclear fuel	 	29	 	31	 	
Amortization of financing costs and debt discount/premiums	 	25	 	25	 	
Loss on debt extinguishment	 	8	 	58	 	
Amortization of intangibles and out-of-market commodity contracts	 	108	 	118	 	
Amortization of unearned equity compensation	 	27	 	14	 	
Changes in deferred income taxes and liability for uncertain tax benefits	 	(261	)	(829	)	
Changes in nuclear decommissioning trust liability	 	25	 	20	 	
Changes in derivative instruments	 	360	 	(201	)	
Changes in collateral deposits supporting energy risk management activities	 	213	 	7	 	
Impairment charge on investment	 	—	 	481	 	
Impairment charge on emission allowances	 	—	 	160	 	
Cash used by changes in other working capital	 	(288	)	(236	)	
Net Cash Provided by Operating Activities	 	1,058	 	668	 	
Cash Flows from Investing Activities	 	 	 	 	 	
Acquisitions of business, net of cash acquired	 	(40	)	(352	)	
Capital expenditures	 	(2,474	)	(1,355	)	
Increase in restricted cash, net	 	(96	)	(92	)	
Decrease /(increase) in restricted cash to support equity requirements for U.S. DOE funded projects	 	151	 	(316	)	
(Increase)/decrease in notes receivable	 	(22	)	27	 	
Purchase of emissions allowances	 	(8	)	(27	)	
Proceeds from sale of emission allowances	 	8	 	6	 	
Investments in nuclear decommissioning trust fund securities	 	(341	)	(314	)	
Proceeds from sales of nuclear decommissioning trust fund securities	 	316	 	294	 	
Proceeds from renewable energy grants	 	49	 	—	 	
Proceeds from sale of assets, net of cash disposed of	 	137	 	14	 	
Investments in unconsolidated affiliates	 	—	 	(17	)	
Other	 	(9	)	(29	)	
Net Cash Used by Investing Activities	 	(2,329	)	(2,161	)	
Cash Flows from Financing Activities	 	 	 	 	 	
Payment of dividends to common and preferred stockholders	 	(28	)	(7	)	
Payment for treasury stock	 	—	 	(378	)	
Net payments for settlement of acquired derivatives that include financing elements	 	(65	)	(61	)	
Sale proceeds and other contributions from noncontrolling interests in subsidiaries	 	316	 	—	 	
Proceeds from issuance of long-term debt	 	2,541	 	5,710	 	
Decrease in restricted cash supporting funded letter of credit	 	—	 	1,300	 	
Payment for settlement of funded letter of credit facility	 	—	 	(1,300	)	
Proceeds from issuance of common stock	 	—	 	2	 	
Payment of debt issuance and hedging costs	 	(30	)	(149	)	
Payments for short and long-term debt	 	(955	)	(5,450	)	
Net Cash Provided/(Used) by Financing Activities	 	1,779	 	(333	)	
Effect of exchange rate changes on cash and cash equivalents	 	(3	)	2	 	
Net Increase/(Decrease) in Cash and Cash Equivalents	 	505	 	(1,824	)	
Cash and Cash Equivalents at Beginning of Period	 	1,105	 	2,951	 	
Cash and Cash Equivalents at End of Period	 	$	1,610	 	$	1,127	 	
 
11

 
Appendix Table A-1: Third Quarter 2012 Regional Adjusted EBITDA Reconciliation
 
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/ (loss)
 
(dollars in millions)	 	Retail	 	Texas	 	Northeast	 	South
Central	 	West	 	Other
Conventional	 	Alt.
Energy	 	Corp.	 	Total	 	
Net Income/(Loss)	 	(300	)	299	 	33	 	19	 	35	 	9	 	—	 	(87	)	8	 	
Plus:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income Attributable to Non-Controlling Interest	 	—	 	—	 	—	 	—	 	—	 	—	 	(9	)	—	 	(9	)	
Income Tax	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	(113	)	(113	)	
Interest Expense	 	1	 	—	 	4	 	5	 	1	 	3	 	12	 	137	 	163	 	
Depreciation, Amortization and ARO Expense	 	41	 	116	 	32	 	23	 	4	 	4	 	18	 	4	 	242	 	
Loss on Debt Extinguishment	 	—	 	—	 	—	 	—	 	—	 	—	 	 	 	41	 	41	 	
Amortization of Contracts	 	16	 	13	 	—	 	(6	)	—	 	—	 	—	 	—	 	23	 	
EBITDA	 	(242	)	428	 	69	 	41	 	40	 	16	 	21	 	(18	)	355	 	
Transaction Costs	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	14	 	14	 	
Legal Settlement	 	—	 	—	 	—	 	14	 	—	 	—	 	—	 	—	 	14	 	
Asset and Investment Write-offs	 	—	 	7	 	—	 	—	 	—	 	—	 	—	 	4	 	11	 	
MtM losses/(gains)	 	415	 	(111	)	(11	)	(24	)	(9	)	—	 	3	 	—	 	263	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	 	173	 	324	 	58	 	31	 	31	 	16	 	24	 	—	 	657	 	
 
Appendix Table A-2: Third Quarter 2011 Regional Adjusted EBITDA Reconciliation
 
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/ (loss)
 
(dollars in millions)	 	Retail	 	Texas	 	Northeast	 	South
Central	 	West	 	Other
Conventional	 	Alt.
Energy	 	Corp.	 	Total	 	
Net Income/(Loss)	 	36	 	(45	)	6	 	21	 	27	 	5	 	(12	)	(93	)	(55	)	
Plus:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax	 	—	 	—	 	—	 	—	 	—	 	2	 	—	 	(82	)	(80	)	
Interest Expense	 	1	 	—	 	11	 	11	 	—	 	4	 	5	 	132	 	164	 	
Depreciation, Amortization and ARO Expense	 	48	 	118	 	33	 	23	 	2	 	4	 	7	 	4	 	239	 	
Loss on Debt Extinguishment	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	32	 	32	 	
Amortization of Contracts	 	25	 	14	 	—	 	(6	)	—	 	—	 	—	 	—	 	33	 	
EBITDA	 	110	 	87	 	50	 	49	 	29	 	15	 	—	 	(7	)	333	 	
Asset and Investment Write-offs	 	—	 	168	 	—	 	—	 	—	 	—	 	—	 	3	 	171	 	
MtM losses/(gains)	 	35	 	(67	)	(7	)	(7	)	5	 	—	 	(5	)	—	 	(46	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	 	145	 	188	 	43	 	42	 	34	 	15	 	(5	)	(4	)	458	 	
 
12

 
Appendix Table A-3: YTD Third Quarter 2012 Regional Adjusted EBITDA Reconciliation
 
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/ (loss)
 
(dollars in millions)	 	Retail	 	Texas	 	Northeast	 	South
Central	 	West	 	Other
Conventional	 	Alt. Energy	 	Corp.	 	Total	 	
Net Income/(Loss)	 	504	 	(202	)	(20	)	—	 	42	 	25	 	(22	)	(266	)	61	 	
Plus:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income Attributable to Non-Controlling Interest	 	—	 	—	 	—	 	—	 	—	 	—	 	(18	)	—	 	(18	)	
Income Tax	 	—	 	—	 	—	 	—	 	—	 	4	 	—	 	(250	)	(246	)	
Interest Expense	 	3	 	—	 	13	 	14	 	1	 	10	 	34	 	420	 	495	 	
Depreciation, Amortization and ARO Expense	 	126	 	345	 	97	 	69	 	11	 	12	 	41	 	8	 	709	 	
Loss on Debt Extinguishment	 	—	 	—	 	—	 	—	 	—	 	—	 	 	 	41	 	41	 	
Amortization of Contracts	 	83	 	32	 	—	 	(15	)	—	 	1	 	—	 	—	 	101	 	
EBITDA	 	716	 	175	 	90	 	68	 	54	 	52	 	35	 	(47	)	1,143	 	
Transaction Costs	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	23	 	23	 	
Legal Settlement	 	—	 	—	 	—	 	14	 	20	 	—	 	—	 	—	 	34	 	
Asset and Investment Write-offs	 	—	 	8	 	—	 	—	 	—	 	—	 	—	 	5	 	13	 	
MtM losses/(gains)	 	(212	)	506	 	(7	)	2	 	(6	)	—	 	—	 	—	 	283	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	 	504	 	689	 	83	 	84	 	68	 	52	 	35	 	(19	)	1,496	 	
 
Appendix Table A-4: YTD Third Quarter 2011 Regional Adjusted EBITDA Reconciliation
 
The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income/ (loss)
 
(dollars in millions)	 	Retail	 	Texas	 	Northeast	 	South
Central	 	West	 	Other
Conventional	 	Alt.
Energy	 	Corp.	 	Total	 	
Net Income/(Loss)	 	350	 	193	 	(13	)	46	 	51	 	14	 	(42	)	(293	)	306	 	
Plus:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Tax	 	(3	)	—	 	—	 	—	 	—	 	6	 	—	 	(818	)	(815	)	
Interest Expense	 	3	 	(16	)	38	 	32	 	1	 	12	 	12	 	422	 	504	 	
Depreciation, Amortization and ARO Expense	 	114	 	349	 	90	 	65	 	9	 	11	 	22	 	10	 	670	 	
Loss on Debt Extinguishment	 	—	 	—	 	—	 	—	 	—	 	—	 	—	 	175	 	175	 	
Amortization of Contracts	 	118	 	43	 	—	 	(16	)	—	 	—	 	—	 	—	 	145	 	
EBITDA	 	582	 	569	 	115	 	127	 	61	 	43	 	(8	)	(504	)	985	 	
Asset and Investment Write-offs	 	—	 	168	 	—	 	—	 	—	 	—	 	—	 	495	 	663	 	
MtM losses/(gains)	 	(78	)	(95	)	(21	)	(21	)	(2	)	—	 	(1	)	—	 	(218	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted EBITDA	 	504	 	642	 	94	 	106	 	59	 	43	 	(9	)	(9	)	1,430	 	
 
13

 
Appendix Table A-5: YTD Third Quarter 2012 Free Cash Flow before Growth Investments Reconciliation
 
The following table summarizes the calculation of free cash flow before growth investments and adjusted cash flow from operating activities providing a reconciliation to net cash provided by operating activities
 
($ in millions)	 	Nine months ended September 30, 2012	 	Nine months ended September 30, 2011	 	
Net Cash Provided by Operating Activities	 	1,058	 	668	 	
Less: Reclassifying of net payments for settlement of acquired derivatives that include financing elements	 	(65	)	(61	)	
Adjusted Cash Flow from Operating Activities	 	993	 	607	 	
Maintenance Capital Expenditures	 	(151	)	(163	)	
Environmental Capital Expenditures, net	 	(29	)	(23	)	
Preferred Dividends	 	(7	)	(7	)	
Free Cash Flow — Before Growth Investments	 	806	 	414	 	
 
EBITDA and adjusted EBITDA are non-GAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance. The presentation of adjusted EBITDA should not be construed as an inference that NRG’s future results will be unaffected by unusual or non-recurring items.
 
EBITDA represents net income before interest (including loss on debt extinguishment), taxes, depreciation and amortization. EBITDA is presented because NRG considers it an important supplemental measure of its performance and believes debt-holders frequently use EBITDA to analyze operating performance and debt service capacity. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are:
 
·                 EBITDA does not reflect cash expenditures, or future requirements for capital expenditures, or contractual commitments;
·                 EBITDA does not reflect changes in, or cash requirements for, working capital needs;
·                 EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments;
·                 Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and
·                 Other companies in this industry may calculate EBITDA differently than NRG does, limiting its usefulness as a comparative measure.
 
Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to use to invest in the growth of NRG’s business. NRG compensates for these limitations by relying primarily on our GAAP results and using EBITDA and adjusted EBITDA only supplementally. See the statements of cash flow included in the financial statements that are a part of this news release.
 
Adjusted EBITDA is presented as a further supplemental measure of operating performance. Adjusted EBITDA represents EBITDA adjusted for mark-to-market gains or losses, asset write offs and impairments; and factors which we do not consider indicative of future operating performance. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. As an analytical tool, adjusted EBITDA is subject to all of the limitations applicable to EBITDA. In addition, in evaluating adjusted EBITDA, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release.
 
Adjusted cash flow from operating activities is a non-GAAP measure NRG provides to show cash from operations with the reclassification of net payments of derivative contracts acquired in business combinations from financing to operating cash
 
14

 
flow. The Company provides the reader with this alternative view of operating cash flow because the cash settlement of these derivative contracts materially impact operating revenues and cost of sales, while GAAP requires NRG to treat them as if there was a financing activity associated with the contracts as of the acquisition dates.
 
Free cash flow (before growth investments) is adjusted cash flow from operations less maintenance and environmental capital expenditures and preferred stock dividends and is used by NRG predominantly as a forecasting tool to estimate cash available for debt reduction and other capital allocation alternatives. The reader is encouraged to evaluate each of these adjustments and the reasons NRG considers them appropriate for supplemental analysis. Because we have mandatory debt service requirements (and other non-discretionary expenditures) investors should not rely on free cash flow as a measure of cash available for discretionary expenditures.
 
15

 
 	NRG’s Third Quarter 2012 Results Presentation November 2, 2012	

 	Forward Looking Statements In addition to historical information, the information presented in this report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. These statements involve estimates, expectations, projections, goals, assumptions, known and unknown risks and uncertainties and can typically be identified by terminology such as "may," "will," "should," "could," "objective," "projection," "forecast," "goal," "guidance," "outlook," "expect," "intend," "seek," "plan," "think," "anticipate," "estimate," "predict," "target," "potential" or "continue" or the negative of these terms or other comparable terminology. Such forward-looking statements include, but are not limited to, statements about the anticipated benefits of the proposed transaction between NRG and GenOn, each party's and the combined company's future revenues, income, indebtedness, capital structure, plans, expectations, objectives, projected financial performance and/or business results and other future events, each party's views of economic and market conditions, and the expected timing of the completion of the proposed transaction. Forward-looking statements are not a guarantee of future performance and actual events or results may differ materially from any forward-looking statement as result of various risks and uncertainties, including, but not limited to, those relating to: the ability to satisfy the conditions to the proposed transaction between NRG and GenOn, the ability to successfully complete the proposed transaction (including any financing arrangements in connection therewith) in accordance with its terms and in accordance with expected schedule, the ability to obtain stockholder, regulatory or other approvals for the proposed transaction, or an inability to obtain them on the terms proposed or on the anticipated schedule, diversion of management attention on transaction-related issues, impact of the transaction on relationships with customers, suppliers and employees, the ability to finance the combined business post-closing and the terms on which such financing may be available, the financial performance of the combined company following completion of the proposed transaction, the ability to successfully integrate the businesses of NRG and GenOn, the ability to realize anticipated benefits of the proposed transaction (including expected cost savings and other synergies) or the risk that anticipated benefits may take longer to realize than expected, legislative, regulatory and/or market developments, the outcome of pending or threatened lawsuits, regulatory or tax proceedings or investigations, the effects of competition or regulatory intervention, financial and economic market conditions, access to capital, the timing and extent of changes in law and regulation (including environmental), commodity prices, prevailing demand and market prices for electricity, capacity, fuel and emissions allowances, weather conditions, operational constraints or outages, fuel supply or transmission issues, hedging ineffectiveness. Additional information concerning other risk factors is contained in NRG's and GenOn's most recently filed Annual Reports on Form 10-K, subsequent Quarterly Reports on Form 10-Q, recent Current Reports on Form 8-K, and other SEC filings. Many of these risks, uncertainties and assumptions are beyond NRG's ability to control or predict. Because of these risks, uncertainties and assumptions, you should not place undue reliance on these forward-looking statements. Furthermore, forward-looking statements speak only as of the date they are made, and NRG does not undertake any obligation to update publicly or revise any forward-looking statements to reflect events or circumstances that may arise after the date of this communication. All subsequent written and oral forward-looking statements concerning NRG, GenOn, the proposed transaction, the combined company or other matters and attributable to NRG, GenOn or any person acting on their behalf are expressly qualified in their entirety by the cautionary statements above. Safe Harbor	

 	Additional Information about the Proposed Transaction and Where You Can Find It In connection with the proposed merger between NRG and GenOn, NRG filed with the Securities and Exchange Commission ("SEC") a registration statement on Form S-4 that includes a joint proxy statement of NRG and GenOn and that also constitutes a prospectus of NRG. The registration statement was declared effective by the SEC on October 5, 2012. NRG and GenOn first mailed the joint proxy statement/prospectus to their respective stockholders on or about October 10, 2012. NRG and GenOn may also file other documents with the SEC regarding the proposed transaction. INVESTORS AND SECURITY HOLDERS OF NRG AND GENON ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS THAT ARE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Investors and stockholders may obtain free copies of the joint proxy statement/prospectus and other documents containing important information about NRG and GenOn through the website maintained by the SEC at www.sec.gov. In addition, NRG makes available free of charge at www.nrgenergy.com (in the "Investors" section), copies of materials it files with, or furnish to, the SEC. Participants In The Merger Solicitation NRG, GenOn, and certain of their respective directors and executive officers may be deemed to be participants in the solicitation of proxies from the stockholders of NRG and GenOn in connection with the proposed transaction. Information about the directors and executive officers of NRG is set forth in its proxy statement for its 2012 annual meeting of stockholders, which was filed with the SEC on March 12, 2012. Information about the directors and executive officers of GenOn is set forth in its proxy statement for its 2012 annual meeting of stockholders, which was filed with the SEC on March 30, 2012. Other information regarding the participants in the proxy solicitation can be found in the above-referenced registration statement on Form S-4. These documents can be obtained free of charge from the sources indicated above. Safe Harbor Continued	

 	Agenda Highlights and Strategic Update – D. Crane Operations and Commercial Review – M. Gutierrez Financial Results – K. Andrews Closing Remarks and Q&A – D. Crane	

 	Third Quarter 2012 Highlights Strong Financial Performance $657 MM Q3 2012 adjusted EBITDA, including $173 MM from Retail $35 MM Q3 2012 adjusted EBITDA from solar projects; becoming a material contributor to financial results $806 MM FCF, before growth investments in the first 9 months of year Narrowing 2012 and Reaffirming Standalone 2013-2014 Guidance Ranges Key Strategic Highlights GenOn transaction on track NRG’s integrated wholesale-retail model provides resiliency in an otherwise “normal” Texas summer Successfully refinanced 2017 notes, including $100 MM of deleveraging Accelerated solar construction timetable with ~335 MW online by Q31 Strong Results as a Result of Focused Execution 1Total utility scale project MWAC including partner-owned capacity ($MM) 2012 2013 2014 Adjusted EBITDA $1,875-$1,925 $1,700-$1,900 $1,700-$1,900 Free Cash Flow, before growth $900-$950 $650-$850 $500-$700	

 	Integrated Model Supports Full-Cycle Financial Performance NRG’s Integrated Model: A Strategic Advantage to NRG Texas Wholesale: “Less Robust Conditions” Texas Retail: “Strong Load, but not 2011” Delivering on Results (Adjusted EBITDA) Metric 2011 2012 % Delta TX Q3 CDDs1 2,050 1,708 17% Avg Q3 ERCOT Load2 47.3 GW 44.5 GW 6% Avg Q3 Spot Prices3 $70/MWh $27/MWh 62% NRG TX Retail Volumes Q3 2011 vs Q3 2012 Down ~5% Y-o-Y Q4 2012E ($MM) (TWhs) 1CDDs=Cooling degree days, July-Sept. 2011 and 2012 2Avg ERCOT Net Energy for Load (NEL), July-Sept. 2011 and 2012 3Avg real-time hourly ATC price, July-Sept. 2011 and 2012, Houston Hub Source: NOAA, ERCOT, NRG Research 17.4 16.5 Q3 2011 Q3 2012 $1,825-2,000 $1,875-1,925 Previous 2012 Guidance 2012 YTD Results and Updated Guidance, 11/2/2012	

 	The GenOn Transaction: On Track and On Budget Synergies as Expected Stockholder Approval Special meeting – Nov. 9, 2012 Regulatory Approvals FERC – comment period closed Oct. 9 without protest DOJ – Sept. 24th NY PSC – filed Aug. 2nd Texas PUC – Oct. 25th Required Notices California PUC Nuclear Regulatory Commission – Nov. 1st Approval Process Executing on Synergies Cost Executive and senior management teams identified $175 MM in cost synergies on track Operational Evaluation of opportunities continues; expect acceleration post- close Balance Sheet Efficiencies Refinanced 2017 bonds, $100 MM in deleveraging, $14 MM /year of interest savings	

 	Operations and Commercial Review	

 	Strong Safety and Plant Operations Performance Top decile performance with a record OSHA recordable rate of 0.49 YTD Baseload availability above 90% and record performance for STP Unit 1 Solid Performance of Integrated Platform Despite Normal Weather Increased retail customer count and delivered strong margins Implemented improved risk management strategy Implementing Revised Environmental Capital Plan for 2012-2016 Reduced environmental capex to $440 MM, primarily due to MATS final rule test results in South Central Reached agreement with the EPA on terms of the Big Cajun NSR Settlement Development and Growth Projects Executed EPC agreement for WA Parish peaker project El Segundo and utility scale solar project construction on track Operations Highlights – Third Quarter 2012	

 	Q3 2012 Plant Operations Update 1Top Decile based on Edison Electric Institute 2009 Total Company Survey results. 2009 rate excludes Reliant Safety – Top Decile OSHA Recordable Rate1 Net Production (TWh)2 2All NRG owned domestic generation production Gas/Oil Units Starts and EFOR4 Top Quartile = 1.02 Top Decile = 0.80 3Equivalent Availability Factor 2012 Q3 2011 Q3 EFOR 2011 Starts 2012 Starts Q3 YTD Baseload Availability (EAF3) Q3 YTD 2012 2011 Solid baseload performance and improved gas reliability 4Equivalent Forced Outage Rate 95.43 92.21 83.68 3,501 3,065 7,974 6,289 17% 14% 19% 16% 14.4 2.7 4.5 0.5 22.0 12.3 2.2 4.4 1.2 20.1 TX NE SC West NRG 2009 2010 2011 2012 YTD	

 	Q3 2012 Retail Operations Update Continued strong performance by NRG’s multi-brand retail business Highlights Delivered $504 MM adjusted EBITDA YTD Growth in margins q-over-q; sustained margins Y-over-Y Increased retail presence in non-Texas market: 10% of Q3 load was served outside of ERCOT Over 700K customers using Smart Energy Solutions and 330K using Home Solutions Continued Retail Customer Growth (000s)1 Higher Retail Load Served (GWhs) Sustained Gross Margin ($/MWh) 1Excludes utility partner customers 18,333 17,743 0.0 10.0 20.0 YTD 2011 YTD 2012 2,099 2,129 2,192 Q1 2012 Q2 2012 Q3 2012 Q3 2011 Q3 2012 Mass C&I	

 	New monthly peak loads ERCOT Summer ’12 Review Supply – Summer Installed Capacity Supply increased by less than 1% 1‘Normal’ is 10-year normal weather; CDDs=cooling degree days Market Prices GW 2011 peak: 68.3 GW 2012 peak: 66.6 GW Aug. CDDs, Houston1 2011: 786 (+24%) 2012: 651 (+3%) Normal: 635 Load, top 300 hours ERCOT supply flat year-over-year Record monthly peak loads in June, July, and September with near-normal weather Lack of consistent hot temperatures minimized scarcity pricing But forwards responded when new peaks were reached Demand – Load Duration Curve Summary Source: ERCOT 2011 CDR, ERCOT 2012 SARA Source: ERCOT Record peak loads signal strong fundamentals, but normal weather resulted in lower prices year-over-year 30,000 35,000 40,000 45,000 50,000 55,000 60,000 65,000 70,000 - 50 100 150 200 250 300 350 MW $/MWh Peak load 2012 On Pk RT 2012 On Pk DA Jun Jul Aug Sep 76 75 74 73 72 71 70 GW 73.18 1.71 1.03 73.85	

 	Market Update Natural gas and Texas heat rates improving; ERCOT market design changes continue Large year over year gas storage surplus significantly reduced NAPP Switch PRB Switch Source: EIA, NYMEX and NRG estimates Natural Gas: Rebalancing Continues ERCOT: Spark Spreads Responding to Market Design Changes PUCT additional market design changes: Price caps increase to $5,000/MWh (starting June 1, 2013), $7,000/MWh in 2014, and $9,000/MWh in 2015 Peaker net margin threshold increases from $175 to $300k per year Evaluation of mandated reserve margin requirement Pending long term resource adequacy solutions ‘13 ‘14 ‘15 Cost of New Entry for CCGT1 2011 Actual On-Peak Spark Spread 10/25: PUCT approves price caps leading to moderate price recovery 1NRG estimates. Margin required to justify new build economics for a CCGT based on $800-1,000/kW capital cost net of A/S and O&M. Spark Spread=(Peak Power - 7 heat rate x Henry Hub Gas). 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Jan - 12 Mar - 12 May - 12 Jul - 12 Sep - 12 Nov - 12 Tcf 5 - Year Range Current Year Year Ago 5 - Year Average $1 $2 $3 $4 $5 Jun - 11 Oct - 11 Mar - 12 Aug - 12 $/MMbtu Prompt 10/17 Forwards 4/19 Forwards $10 $15 $20 $25 $30 $35 Feb - 12 Apr - 12 Jun - 12 Aug - 12 Oct - 12 On - Peak Spark Spread ($/MWh) Cal13 Cal14 Cal15	

 	Managing Commodity Price Risk Coal and Transport Hedge Position (1) (4) (1) Portfolio as of 10/12/2012; 2) Retail load includes Reliant, Green Mountain, and Energy Plus for Texas, PJM, ISONE, and NYISO regions. Retail Priced Loads are 100% hedged; (3) Price sensitivity reflects gross margin change from $0.5/MMBtu gas price, 1 mmBtu/MWh heat rate move; (4) Coal position excludes existing coal inventory; (5) Baseload includes coal and nuclear electric power generation capacity normally expected to serve loads on around-the-clock basis throughout the calendar year Baseload Generation and Retail Hedge Position (1) (2) (5) 2013 2014 2015 Baseload Gas Price and Heat Rate Sensitivity (1) (3) (5) Commercial Highlights Change since prior quarter Reached a favorable agreement on coal transportation for Limestone Form C contract extensions approved by Louisiana Public Service Commission Opportunistically increased hedges in 2013 2013 2014 2015 Hedged Gas (NGE) Hedged Heat Rate Priced Load Open Gas Open Heat Rate Un-priced Load Change since prior quarter Hedged Coal Hedged Transport Open Coal Open Transport 2013 2014 2015 83% 100% 38% 100% 43% 83% 96% 43% 49% 42% 46% 24% 30% 7% 88% Gas Up by $0.5/mmBtu Gas Down by $0.5/mmBtu HR Up by 2 mmBtu/MWh HR Down by 1 mmBtu/MWh 8 25 (5) 121 (108) (107) 126 167 145 (159) (125)	

 	GenOn Transaction: Focused on Operational Synergies Extracting the best of NRG and GenOn operating practices to deliver measurable value to shareholders ($MM) Operational Efficiency Synergies Leveraging the Program Reliability, capacity and efficiency improvements Procurement savings to lever economies of scale Centralized inventory management Strategic procurement Asset optimization Expand natural gas capabilities Aggressively reduce fixed costs and property taxes Reorganize to support optimization efforts (mobile workforce/seasonal ops) On track to deliver $7 MM over 2012 plan 1Q12 NRG Plan Pro Forma - GenOn $37 $65 $100 $ - $20 $40 $60 $80 $100 $120 $140 $160 2012 2013 2014 $125 $75	

 	Financial Results	

 	Financial Summary September 30, 2012 Three Months Ended Nine Months Ended Wholesale $449 MM $928 MM Retail $173 MM $504 MM Solar Projects $ 35 MM $ 64 MM Consolidated adjusted EBITDA $657 MM $1,496 MM Free Cash Flow before Growth $393 MM $806 MM $600+ MM improvement in liquidity since year-end after October 24th redemption of the remaining $270 MM outstanding 2017 Senior Notes Capital Allocation Update: $100 MM in deleveraging and approximately $14 MM in annual interest savings achieved via refinancing of the Senior Unsecured Notes due 2017 representing the first step towards achieving a minimum of $1 BN in deleveraging as part of the anticipated GenOn combination Over $110 MM reduction in expected environmental capital expenditures through 2016 Third Quarter Highlights: Texas region benefited from 21% higher realized energy margin year-over-year Customer growth initiatives lead to a 124,000 improvement in customer count since year-end 2011 including 79,000 in the Northeast markets	

 	Guidance Overview ($MM) 2012 2013 2014 Wholesale $1,170-$1,195 $850-$965 $705-$820 Retail $630-$650 $650-$725 $675-$750 Solar Projects1 $75-$80 $200-$210 $320-$330 Consolidated adjusted EBITDA $1,875-$1,925 $1,700-$1,900 $1,700-$1,900 Free Cash Flow – before growth investments $900-$950 $650-$850 $500-$700 Narrowing 2012 guidance while maintaining EBITDA and Free Cash Flow guidance ranges for 2013 and 2014 1 Solar projects include the EBITDA contribution from the projects net of non-controlling interest and excluding development expenses	

 	Committed Growth Investments Growth Investments substantially online by 2014 and significant contributors to EBITDA results ($MM) 2012 2013-2014 Conventional Investments, net 107 147 Solar Investments, net 583 (5) Total Growth Investments $690 $142 Non-DOE Utility Projects Unchanged from Aug. 8, 2012 presentation Change In Solar Investments, net
2012 2013-2014 August 8, 2012 $363 $232 Non-DOE Utility Projects 234 (240) Other (14) 3 November 2, 2012 $583 ($5)	

 	Corporate Liquidity Solar monetization and sale of non-core assets drives significant improvement in liquidity Total liquidity improved over $600 MM since year-end 2011 $270 MM redemption of the remaining 2017 Senior Notes occurred on Oct. 24th Strong adjusted cash from operations of $993 MM; partially offset by $707 MM cash outflow for capital investments Agua Caliente selldown: $304 MM increase in revolver availability $122 MM proceeds from the sell-down of the project $174 MM in proceeds received from the sale of Schkopau Current liquidity position continues to reflect full effect of our remaining equity commitments to Tier 1 solar projects Liquidity Improvement ($MM) Sep 30, Dec 31, ($MM) 2012 2011 Cash and Cash Equivalents $1,610 $1,105 Restricted Cash 237 292 Total Cash $1,847 $1,397 Funds Deposited by Counterparties 76 258 Total Cash and Funds Deposited $1,923 $1,655 Revolver Availability 1,133 673 Total Liquidity $3,056 $2,328 Less: Collateral Funds Deposited (76) (258) Total Current Liquidity $2,980 $2,070 Reserve for 2017 bond redemption (270) - Total Current Liquidity, adjusted $2,710 $2,070	

 	Closing Remarks and Q&A	

 	Enhance Core Generation Proactive asset management for a low gas environment; Texas fleet prepared to operate reliably in a tight market Opportunistic acquisition of strategically located assets Texas fleet operations in line, despite no 2011 events Announced GenOn combination Expand Retail Deliver balanced customer count/margin in core Texas market and successfully coordinate NE expansion Make inroads into the markets for sustainable energy goods and services Retail customer growth of 124k YTD More than 700k customers on Smart Energy Solutions; 330k on Home Solutions Lead Clean Energy Flawless execution of solar build-out Successful expansion of our solar focus to smaller scale C&I and residential solar Accelerated utility scale solar construction; more than 400 MW online by YE 2012 Maintain Prudent Capital Allocation Initiate dividend Reserve excess liquidity for capital allocation Accumulate additional reserves through sell-down of non-core assets Ensure that RP basket does not constrain capital allocation Sold Schkopau for $174 MM Corporate deleveraging of $172 MM1 Refinanced 2017 bonds, extending maturities and reducing interest expense 2012 Report Card: Key Accomplishments Through the 3rd Quarter 1Total corporate deleveraging through Oct. 24th 2012	

 	Appendix	

 	Capital Expenditures and Growth Investments 1 Includes investments, cash grants, restricted cash and network upgrades 2 Includes net debt proceeds and third party contributions 3 Includes investments, cash grants, restricted cash and network upgrades 4 Includes net debt proceeds and third party contributions ($MM) ($MM) 2012 YTD Results Growth investments, net ($MM) Maintenance Environmental Conventional investments, net Solar investments, net Total Capital Expenditures Northeast $ 13 $ 24 $ - $ - $ 37 Texas 89 1 - - 90 South Central 13 5 - - 18 West 4 - 154 - 158 Other Conventional - - 20 - 20 Retail 13 - - - 13 Solar - - - 2,538 2,538 Alternative Energy & Corporate 11 - 25 - 36 Accrued CapEx $ 143 $ 30 $ 199 $ 2,538 $ 2,910 Accrual impact 8 8 (25) (427) (436) Total Cash CapEx $ 151 $ 38 $ 174 $ 2,111 $ 2,474 Other Investments1 - - 18 (72) (54) Project Funding, net of fees:2 Solar - - - (1,569) (1,569) El Segundo Repowering - - (135) - (135) Indian River bonds - (9) - - (9) Other Growth Other Conventional - - - - - Total Capital Expenditures and Growth investments, net $ 151 $ 29 $ 57 $ 470 $ 707 2012 Guidance Growth investments, net ($MM) Maintenance Environmental Conventional investments, net Solar investments, net Total Capital Expenditures Northeast $ 31 $ 32 $ - $ - $ 63 Texas 129 1 - - 130 South Central 29 3 - - 32 West 5 - 220 - 225 Other Conventional 13 - 31 - 44 Retail 18 - - - 18 Solar - - - 3,240 3,240 Alternative Energy & Corporate 12 - 62 - 74 Accrued CapEx $ 237 $ 36 $ 313 $ 3,240 $ 3,826 Accrual impact - 13 - (424) (411) Total Cash CapEx $ 237 $ 49 $ 313 $ 2,816 $ 3,415 Other Investments3 - - 45 (41) 4 Project Funding, net of fees:4 Solar - - - (2,192) (2,192) El Segundo Repowering - - (220) - (220) Hurricane Ike bonds (5) (1) (28) - (34) Indian River bonds - (42) - - (42) Other Conventional - - (3) - (3) Total Capital Expenditures and Growth investments, net $ 232 $ 6 $ 107 $ 583 $ 928	

 	1Equivalent Availability Factor 2Net Capacity Factor Q3 2012 Generation & Operational Performance Metrics 2012 2011 (MWh in thousands) 2012 2011 Change % EAF1 NCF2 EAF1 NCF2 Texas 13,061 14,429 (1,368) (9) 92% 37% 90% 40% Northeast 2,592 3,191 (599) (19) 94 13 94 16 South Central 6,021 5,749 272 5 92 48 93 49 West 863 134 729 544 96 20 97 9 Alternative 469 251 218 87 Total 23,006 23,754 (748) (3) 93% 36% 92% 40% Texas Nuclear 2,579 2,534 45 2 100% 99% 99% 98% Texas Coal 7,386 8,531 (1,145) (13) 90 81 98 93 NE Coal 1,283 1,828 (545) (30) 92 35 86 49 SC Coal 2,854 3,015 (161) (5) 91 85 95 92 Baseload 14,102 15,908 (1,806) (11) 92% 76% 95% 85% Solar 235 24 211 879 n/a n/a n/a n/a Wind 234 227 7 3 n/a 30 n/a 29 Intermittent 469 251 218 87 n/a 30% n/a 29% Oil 23 28 (5) (18) 88% 79% 97% 2% Gas - Texas 1,984 2,925 (941) (32) 92 16 83 24 Gas - NE 834 755 79 10 96 9 96 8 Gas - SC 1,620 1,473 147 10 92 27 92 25 Gas - West 863 134 729 544 96 20 97 9 Intermediate/Peaking 5,324 5,315 9 0 94% 16% 91% 16% Purchased Power 3,111 2,280 831 - Total 23,006 23,754 (748) (3) 1828	

 	1Equivalent Availability Factor 2Net Capacity Factor YTD 2012 Generation & Operational Performance Metrics 2012 2011 (MWh in thousands) 2012 2011 Change % EAF1 NCF2 EAF1 NCF2 Texas 33,935 38,057 (4,122) (11) 82% 40% 88% 50% Northeast 5,494 8,127 (2,633) (32) 89 9 89 13 South Central 14,699 13,223 1,476 11 92 46 91 45 West 1,618 189 1,429 756 89 13 86 6 Alternative 1,434 914 520 57 Total 57,180 60,510 (3,330) (6) 86% 30% 89% 35% Texas Nuclear 6,096 7,164 (1,068) (15) 79% 79% 93% 93% Texas Coal 18,352 23,664 (5,312) (22) 84 67 93 87 NE Coal 2,686 5,044 (2,358) (47) 79 23 87 44 SC Coal 6,778 8,443 (1,665) (20) 90 68 94 86 Baseload 33,912 44,315 (10,403) (23) 84% 61% 92% 80% Solar 527 52 475 913 n/a n/a n/a n/a Wind 907 862 45 5 n/a 37 n/a 35 Intermittent 1,434 914 520 57 n/a 37% n/a 35% Oil 43 68 (25) (37) 89% 57% 91% 1% Gas - Texas 4,348 5,520 (1,172) (21) 80 12 83 16 Gas - NE 1,557 1,410 147 10 92 5 89 5 Gas - SC 5,955 3,704 2,251 61 94 34 90 21 Gas - West 1,618 189 1,429 756 89 13 86 6 Intermediate/Peaking 13,521 10,891 2,630 24 88% 14% 87% 12% Purchased Power 8,313 4,390 3,923 - Total 57,180 60,510 (3,330) (6) 5,520	

 	Fuel Statistics 3rd Quarter Year-to-Date Domestic 2012 2011 2012 2011 Cost of Gas ($/mmBTU) $ 3.07 $ 4.36 $ 2.79 $ 4.41 Coal Consumed (mm Tons) 7.4 8.6 18.0 23.8 PRB Blend 80% 82% 82% 83% Northeast 64% 77% 63% 75% South Central 100% 100% 100% 100% Texas 75% 77% 77% 79% Coal Costs ($/mmBTU) $ 2.19 $ 2.29 $ 2.17 $ 2.22 Coal Costs ($/Tons) $ 35.87 $ 37.26 $ 35.43 $ 36.14 18.0	

 	Recourse / Non-Recourse Debt 9/30/2012 6/30/2012 3/31/2012 12/31/2011 COD Date / Comments ($MM) Recourse debt: Term loan facility 1,580 1,584 1,588 1,592 Unsecured Notes1 6,188 6,018 6,090 6,090 Tax Exempt Bonds 289 274 273 264 Recourse subtotal2 8,057 7,876 7,951 7,946 Non-Recourse debt: Ivanpah 1,310 1,168 1,049 874 2013 Agua Caliente 541 440 233 181 2012-2014 CVSR 548 277 138 - 2012-2013 Other solar non-recourse debt 193 137 141 157 2012 Total Solar Debt 2,592 2,022 1,561 1,212 El Segundo 294 248 198 159 August 2013 Capital Lease - Schkopau - - 103 103 Sold on July 17th Conventional non-recourse debt3 427 438 438 444 Subtotal 3,313 2,708 2,300 1,918 Total Debt $11,370 $10,584 $10,251 $9,864 1 Balance of Unsecured Notes after Oct. 24 redemption was $5,918 MM 2 Includes discount of $12 MM, $11 MM, $12 MM, and $12 MM, for 9/30/12, 6/30/12, 3/31/12 and 12/31/11, respectively 3 Includes discount on NRG Peaker of $16 MM, $17 MM, $18 MM and $20 MM, for 9/30/12, 6/30/12, 3/31/12 and 12/31/11, respectively	

 	Projects Under Construction 2012 2013 2014 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Solar MW 2022 424 437 511 669 768 768 768 Gas MW 0 0 0 75 625 625 625 625 Ivanpah 1, 62 MW Ivanpah 2, 64 MW Ivanpah 3, 64 MW Borrego, 26 MW Alpine, 66 MW Avra Valley, 25 MW 1Represents NRG’s utility scale development projects only; excludes distributed solar. Includes only NRG’s share in solar projects. Construction period to substantial completion dates shown; COD MWs under PPAs shown by quarter; for some projects, COD is achieved prior to overall substantial completion. All figures are MW’s (ac) and are net of station load 2Includes Blythe (21 MW), Avenal (23 MW, net NRG), Roadrunner (20 MW), and first blocks of Agua Caliente (116 MW, net NRG) and CVSR (22 MW) all net NRG ownership share as of end of Q3 2012 Construction Pipeline1 El Segundo CCGT, 550 MW Agua Caliente, 148 MW California Valley Solar Ranch, 250 MW WA Parish Peaker, 75 MW	

 	Capacity Revenue Sources: Generation Asset Overview Region and Plant Zone MW Sources of Capacity Revenues: Market Capacity, PPA, and Tolling Arrangements Tenor NEPOOL (ISO NE): Devon SWCT 135 LFRM/FCM1 Connecticut Jet Power SWCT 140 LFRM/FCM1 Montville CT – ROS 500 FCM GenConn Devon SWCT 95 FCM GenConn Middletown CT – ROS 95 FCM Middletown CT – ROS 770 FCM Norwalk Harbor SWCT 340 FCM PJM: Indian River PJM - East 5804 DPL- South Vienna PJM – East 170 DPL- South Conemaugh PJM – West 65 PJM- MAAC Keystone PJM – West 65 PJM- MAAC New York (NYISO): Oswego Zone C 1,635 UCAP - ROS Huntley Zone A 380 UCAP - ROS Dunkirk Zone A 2002 UCAP - ROS RSS expires 5/31/2013 Astoria Gas Turbines Zone J 515 UCAP - NYC Arthur Kill Zone J 865 UCAP - NYC California (CAISO): Encina SP-15 965 Toll/RA Toll expired 12/31/2011, One Year RA Start 1/1/2012 Cabrillo II SP-15 190 RA Capacity5 El Segundo SP-15 670 RA Capacity RA on portion of the plant8 Long Beach SP-15 260 Toll6 Expires 8/1/2017 Solar under Long-term PPAs CAISO and NM 202 PPA7 20-25 years Thermal: Dover PJM - East 104 DPL- South Paxton Creek PJM - West 12 PJM- MAAC NRG revenues and free cash flows benefit from capacity sources originating from either market clearing capacity prices, Resource Adequacy (RA) contracts, power purchase agreement (PPA) contracts, and tolling arrangements. The ERCOT (Texas) region does not have a capacity market. In South Central,3 NRG earns significant capacity revenue from its long-term contracts. As of December 31, 2011, NRG had long-term all-requirements contracts with 10 Louisiana distribution cooperatives with initial terms ranging from ten to 25 years. Of the 10 contracts, nine expire in 2025 while the remaining contract expires in 2014. In addition, NRG has all-requirements contracts with three Arkansas municipalities that account for over 500 MW of total load obligations for NRG and the South Central region. The table below reflects the plants and relevant capacity revenue sources for the Northeast, West and Thermal business segments: 1. LFRM payments are net of any FCM payments received 2. On August 27, 2012, Dunkirk Power LLC executed an agreement with National Grid to provide reliability support services from two units totaling 200 MW through May 31, 2013. The plant’s remaining 330 MW were be put into mothball status starting in September 2012 for up to three years. If the above contract is not extended then the 200 MW is also expected be mothballed in June 2013. 3. South Central includes Rockford I and II, which is in PJM and receives capacity payments at the RPM wholesale market clearing price for the RPM RTO region 4. On February 3, 2010, NRG and DNREC announced a proposed plan to retire the 155MW unit 3 by December 31, 2013 5. RA contracts cover 88MW of the Cabrillo II portfolio through November 30, 2013. 6. NRG has purchased back energy and ancillary service value of the toll through July 31, 2014. Toll expires August 1, 2017 7. Solar projects include Blythe, Avenal Roadrunner and the partially completed Agua Caliente and CVSR projects. Each project sells all of its of capacity under 20 or 25 year full-requirements PPAs 8. El Segundo includes approximately 596 MW and 530 MW of RA contracts for 2011 and 2012, respectively	

 	Increase/ (Decreases) Revenue Forecast Non-Cash Contract Amortization Schedules: 2011-2014 Reduce Cost Increase Cost Increase Cost Reduce Cost Increase Cost Increase Cost Increase/ (Decreases) Revenue ($MM) 2011 2012 Revenues Q1A Q2A Q3A Q4A Year Q1A Q2A Q3A Q4E Year Power contracts/gas swaps1 (33) (27) (3) (35) (98) (23) (36) (10) (28) (97) Fuel Expense Q1A Q2A Q3A Q4A Year Q1A Q2A Q3A Q4E Year Fuel out-of-market contracts2 6 3 1 2 12 3 2 1 3 9 Fuel in-the-market contracts3 1 1 3 1 6 1 1 2 1 5 Emission Allowances (Nox and SO2) 13 14 15 12 54 8 12 16 9 45 Total Net Expenses 8 12 17 11 48 6 11 17 7 41 ($MM) 2013 2014 Revenues Q1E Q2E Q3E Q4E Year Q1E Q2E Q3E Q4E Year Power contracts/gas swaps1 (16) (12) (3) (1) (32) 0 0 0 0 0 Fuel Expense Q1E Q2E Q3E Q4E Year Q1E Q2E Q3E Q4E Year Fuel out-of-market contracts2 1 1 0 0 2 0 0 0 0 0 Fuel in-the-market contracts3 1 1 3 1 6 2 1 3 1 7 Emissions allowances (Nox and SO2) 9 9 9 9 36 8 9 9 8 34 Total Net Expenses 9 9 12 10 40 10 10 12 9 41 1Amortization of power contracts occurs in the revenue line 2Amortization of fuel and energy supply contracts occurs in the fuel and energy supply cost line; includes coal 3Amortization of fuel and energy supply contracts occurs in the fuel and energy supply cost line; includes coal, nuclear, and gas Note: Detailed discussion of the above referenced in-the-money and out-of-the money contracts can be found in the NRG 2011 10-K	

 	Appendix: Reg. G Schedules	

 	Note: see Appendix slide 23 for a Capital Expenditure reconciliation Reg. G: YTD Q3 2012 Free Cash Flow Before Growth Investments ($MM)	

 	Reg. G: 2012 Guidance 1 Solar projects include the EBITDA contribution from the projects net of non controlling interest and excluding development expenses Note: see Appendix slide 23 for a Capital Expenditure reconciliation ($MM)	

 	Reg. G Appendix Table A-1: Third Quarter 2012 Regional Adjusted EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income South Other Alt. ($ in millions) Retail Texas Northeast Central West Conv. Energy Corp. Total Net Income/(Loss) ($300) $299 $33 $19 $35 $9 - ($87) $8 Plus: Net Income Attributable to Non-Controlling Interest - - - - - - (9) - (9) Income Tax - - - - - - - (113) (113) Interest Expense 1 - 4 5 1 3 12 137 163 Depreciation, Amortization and ARO Expense 41 116 32 23 4 4 18 4 242 Loss on Debt Extinguishment - - - - - - - 41 41 Amortization of Contracts 16 13 - (6) - - - - 23 EBITDA (242) 428 69 41 40 16 21 (18) 355 Transaction Costs - - - - - - - 14 14 Legal Settlement - - - 14 - - - - 14 Asset and Investment Write-offs - 7 - - - - - 4 11 MtM losses/(gains) 415 (111) (11) (24) (9) - 3 - 263 Adjusted EBITDA $173 $324 $58 $31 $31 $16 $24 $- $657	

 	Reg. G Appendix Table A-2: Third Quarter 2011 Regional Adjusted EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income South Other Alt. ($ in millions) Retail Texas Northeast Central West Conv. Energy Corp. Total Net Income/(Loss) 36 $ (45) $ 6 $ 21 $ 27 $ 5 $ (12) $ (93) $ (55) $ Plus: Income Tax - - - - - 2 - (82) (80) Interest Expense 1 - 11 11 - 4 5 132 164 Depreciation, Amortization and ARO Expense 48 118 33 23 2 4 7 4 239 Loss on Debt Extinguishment - - - - - - - 32 32 Amortization of Contracts 25 14 - (6) - - - - 33 EBITDA 110 87 50 49 29 15 - (7) 333 Asset and Investment Write-offs - 168 - - - - - 3 171 MtM losses/(gains) 35 (67) (7) (7) 5 - (5) (46) Adjusted EBITDA 145 $ 188 $ 43 $ 42 $ 34 $ 15 $ (5) $ (4) $ 458 $ 	

 	Reg. G Appendix Table A-1: YTD 2012 Regional Adjusted EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income South Other Alt. ($ in millions) Retail Texas Northeast Central West Conv. Energy Corp. Total Net Income/(Loss) $504 ($202) ($20) - $42 $25 ($22) ($266) $61 Plus: Net Income Attributable to Non-Controlling Interest - - - - - - (18) - (18) Income Tax - - - - - 4 - (250) (246) Interest Expense 3 - 13 14 1 10 34 420 495 Depreciation, Amortization and ARO Expense 126 345 97 69 11 12 41 8 709 Loss on Debt Extinguishment - - - - - - - 41 41 Amortization of Contracts 83 32 - (15) - 1 - - 101 EBITDA 716 175 90 68 54 52 35 (47) 1,143 Transaction Costs - - - - - - - 23 23 Legal Settlement - - - 14 20 - - - 34 Asset and Investment Write-offs - 8 - - - - - 5 13 MtM losses/(gains) (212) 506 (7) 2 (6) - - - 283 Adjusted EBITDA $504 $689 $83 $84 $68 $52 $35 ($19) $1,496	

 	Reg. G Appendix Table A-2: YTD 2011 Regional Adjusted EBITDA Reconciliation The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to net income South Other Alt. ($ in millions) Retail Texas Northeast Central West Conv. Energy Corp. Total Net Income/(Loss) $350 $193 ($13) $46 $51 $14 ($42) ($293) $306 Plus: Income Tax (3) - - - - 6 - (818) (815) Interest Expense 3 (16) 38 32 1 12 12 422 504 Depreciation, Amortization and ARO Expense 114 349 90 65 9 11 22 10 670 Loss on Debt Extinguishment - - - - - - - 175 175 Amortization of Contracts 118 43 - (16) - - - 145 EBITDA 582 569 115 127 61 43 (8) (504) 985 Asset and Investment Write-offs - 168 - - - - - 495 663 MtM losses/(gains) (78) (95) (21) (21) (2) - (1) - (218) Adjusted EBITDA $504 $642 $94 $106 $59 $43 ($9) ($9) $1,430	

 	38 EBITDA and adjusted EBITDA are non-GAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance. The presentation of adjusted EBITDA should not be construed as an inference that NRG’s future results will be unaffected by unusual or non-recurring items. EBITDA represents net income before interest (including loss on debt extinguishment), taxes, depreciation and amortization. EBITDA is presented because NRG considers it an important supplemental measure of its performance and believes debt-holders frequently use EBITDA to analyze operating performance and debt service capacity. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are: EBITDA does not reflect cash expenditures, or future requirements for capital expenditures, or contractual commitments; EBITDA does not reflect changes in, or cash requirements for, working capital needs; EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debt or cash income tax payments; Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and Other companies in this industry may calculate EBITDA differently than NRG does, limiting its usefulness as a comparative measure Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to use to invest in the growth of NRG’s business. NRG compensates for these limitations by relying primarily on our GAAP results and using EBITDA and adjusted EBITDA only supplementally. See the statements of cash flow included in the financial statements that are a part of this news release. Adjusted EBITDA is presented as a further supplemental measure of operating performance. Adjusted EBITDA represents EBITDA adjusted for mark-to-market gains or losses, asset write offs and impairments; and factors which we do not consider indicative of future operating performance. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. As an analytical tool, adjusted EBITDA is subject to all of the limitations applicable to EBITDA. In addition, in evaluating adjusted EBITDA, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release. Adjusted cash flow from operating activities is a non-GAAP measure NRG provides to show cash from operations with the reclassification of net payments of derivative contracts acquired in business combinations from financing to operating cash flow. The Company provides the reader with this alternative view of operating cash flow because the cash settlement of these derivative contracts materially impact operating revenues and cost of sales, while GAAP requires NRG to treat them as if there was a financing activity associated with the contracts as of the acquisition dates. Free cash flow, before growth investments is adjusted cash flow from operations less maintenance and environmental capital expenditures, net of financing for specific environmental projects and preferred stock dividends and is used by NRG predominantly as a forecasting tool to estimate cash available for debt reduction and other capital allocation alternatives. The reader is encouraged to evaluate each of these adjustments and the reasons NRG considers them appropriate for supplemental analysis. Because we have mandatory debt service requirements (and other non-discretionary expenditures) investors should not rely on free cash flow as a measure of cash available for discretionary expenditures. Reg. G