Form 10-Q
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2009
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     
 
Commission file number 1-16455
RRI Energy, Inc.
(Exact Name of Registrant as Specified in Its Charter)
     
Delaware   76-0655566
     
(State or Other Jurisdiction of
Incorporation or Organization)
  (I.R.S. Employer Identification No.)
1000 Main Street
Houston, Texas 77002
(Address of Principal Executive Offices) (Zip Code)
(713) 497-3000
(Registrant’s Telephone Number, Including Area Code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o (Do not check if a smaller reporting company)   Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
As of July 28, 2009, the latest practicable date for determination, RRI Energy, Inc. had 351,482,149 shares of common stock outstanding and no shares of treasury stock.
 
 

 

 


 

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 Exhibit 3.2
 Exhibit 10.1
 Exhibit 10.2
 Exhibit 10.3
 Exhibit 10.4
 Exhibit 10.5
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 32.1
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT

 

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FORWARD-LOOKING INFORMATION
This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are statements that contain projections, assumptions or estimates about our revenues, income, capital structure and other financial items, our plans and objectives for future operations or about our future economic performance, economic and market conditions, possible transactions and dispositions, financings or offerings. In many cases, you can identify forward-looking statements by terminology such as “anticipate,” “estimate,” “believe,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “will,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and other similar words. However, the absence of these words does not mean that the statements are not forward-looking.
Actual results may differ materially from those expressed or implied by the forward-looking statements as a result of many factors or events, including, but not limited to, the following:
    Demand and market prices for electricity, purchased power and fuel and emission allowances;
    Limitations on our ability to set rates at market prices;
    Legislative, regulatory and/or market developments;
    Our ability to obtain adequate fuel supply and/or transmission and distribution services;
    Interruption or breakdown of our generating equipment and processes;
    Failure of third parties to perform contractual obligations;
    Changes in environmental regulations that constrain our operations or increase our compliance costs;
    Failure by transmission system operators to communicate operating and system information properly and timely;
    Failure to meet our debt service, restrictive covenants or collateral postings;
    Ineffective hedging and other risk management activities;
    Changes in the wholesale energy market or in our evaluation of our generation assets;
    The outcome of pending or threatened lawsuits, regulatory proceedings, tax proceedings and investigations;
    Weather-related events or other events beyond our control;
    The timing and extent of changes in commodity prices or interest rates; and
    Financial and economic market conditions and our access to capital.
Other factors that could cause our actual results to differ from our projected results are discussed or referred to in the “Risk Factors” section of our most recent Annual Report on Form 10-K filed with the Securities and Exchange Commission.
Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Our filings and other important information are also available on our investor page at www.rrienergy.com.

 

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PART I.
FINANCIAL INFORMATION
ITEM 1.   FINANCIAL STATEMENTS
RRI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
    (thousands of dollars, except per share amounts)  
Revenues:
                               
Revenues (including $(21,842), $5,465, $(26,130) and $(6,737) unrealized gains (losses)) (including $0, $145,592, $0 and $253,001 from affiliates)
  $ 389,777     $ 1,013,564     $ 855,961     $ 1,893,362  
 
                       
Expenses:
                               
Cost of sales (including $28,486, $62,051, $(10,969) and $105,053 unrealized gains (losses)) (including $0, $34,593, $0 and $70,306 from affiliates)
    280,067       568,876       604,741       1,077,715  
Operation and maintenance
    156,964       165,733       314,110       321,178  
General and administrative
    27,645       32,627       56,659       61,841  
Western states litigation and similar settlements
                      34,000  
Gains on sales of assets and emission and exchange allowances, net
    (1,241 )     (22,312 )     (20,171 )     (22,923 )
Depreciation and amortization
    67,646       82,909       135,504       165,706  
 
                       
Total operating expense
    531,081       827,833       1,090,843       1,637,517  
 
                       
Operating Income (Loss)
    (141,304 )     185,731       (234,882 )     255,845  
 
                       
Other Income (Expense):
                               
Income (loss) of equity investment, net
    (690 )     988       (149 )     1,195  
Debt extinguishments gains (losses)
    844             844       (1,353 )
Other, net
    160       90       211       26  
Interest expense
    (45,067 )     (51,094 )     (91,986 )     (102,510 )
Interest income
    721       8,226       969       14,651  
 
                       
Total other expense
    (44,032 )     (41,790 )     (90,111 )     (87,991 )
 
                       
Income (Loss) from Continuing Operations Before Income Taxes
    (185,336 )     143,941       (324,993 )     167,854  
Income tax expense (benefit)
    (81,644 )     61,963       (115,520 )     72,940  
 
                       
Income (Loss) from Continuing Operations
    (103,692 )     81,978       (209,473 )     94,914  
Income from discontinued operations
    907,258       276,710       861,626       640,986  
 
                       
Net Income
  $ 803,566     $ 358,688     $ 652,153     $ 735,900  
 
                       
 
                               
Basic Earnings (Loss) per Share:
                               
Income (loss) from continuing operations
  $ (0.30 )   $ 0.24     $ (0.60 )   $ 0.27  
Income from discontinued operations
    2.59       0.79       2.46       1.86  
 
                       
Net income
  $ 2.29     $ 1.03     $ 1.86     $ 2.13  
 
                       
 
                               
Diluted Earnings (Loss) per Share:
                               
Income (loss) from continuing operations
  $ (0.30 )   $ 0.23     $ (0.60 )   $ 0.27  
Income from discontinued operations
    2.59       0.78       2.46       1.81  
 
                       
Net income
  $ 2.29     $ 1.01     $ 1.86     $ 2.08  
 
                       
See Notes to our Unaudited Consolidated Interim Financial Statements

 

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RRI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
                 
    June 30, 2009     December 31, 2008  
    (thousands of dollars, except per share amounts)  
ASSETS
               
Current Assets:
               
Cash and cash equivalents
  $ 1,486,965     $ 1,004,367  
Restricted cash
    2,778       2,721  
Accounts and notes receivable, principally customer
    127,479       249,871  
Inventory
    303,984       314,999  
Derivative assets
    157,023       161,340  
Margin deposits
    18,078       32,676  
Investment in and receivables from Channelview, net
    24,569       58,703  
Prepayments and other current assets
    105,146       124,449  
Current assets of discontinued operations ($152,000 and $295,477 of margin deposits)
    271,538       2,506,340  
 
           
Total current assets
    2,497,560       4,455,466  
 
           
Property, plant and equipment, gross
    6,510,780       6,417,268  
Accumulated depreciation
    (1,722,634 )     (1,597,479 )
 
           
Property, Plant and Equipment, net
    4,788,146       4,819,789  
 
           
Other Assets:
               
Other intangibles, net
    373,773       380,554  
Derivative assets
    84,004       78,879  
Prepaid lease
    264,893       273,374  
Other ($31,888 and $29,012 accounted for at fair value)
    238,142       219,552  
Long-term assets of discontinued operations
    25,717       494,781  
 
           
Total other assets
    986,529       1,447,140  
 
           
Total Assets
  $ 8,272,235     $ 10,722,395  
 
           
 
               
LIABILITIES AND EQUITY
               
Current Liabilities:
               
Current portion of long-term debt and short-term borrowings
  $ 410,799     $ 12,517  
Accounts payable, principally trade
    137,239       156,604  
Derivative liabilities
    234,906       202,206  
Margin deposits
    28,000       93,000  
Other
    206,698       199,026  
Current liabilities of discontinued operations ($42,250 and $0 of margin deposits)
    187,391       2,375,895  
 
           
Total current liabilities
    1,205,033       3,039,248  
 
           
Other Liabilities:
               
Derivative liabilities
    115,596       140,493  
Other
    305,407       272,079  
Long-term liabilities of discontinued operations
    29,872       873,190  
 
           
Total other liabilities
    450,875       1,285,762  
 
           
Long-term Debt
    2,160,501       2,610,737  
 
           
Commitments and Contingencies
               
Temporary Equity Stock-based Compensation
    4,934       9,004  
 
           
Stockholders’ Equity:
               
Preferred stock; par value $0.001 per share (125,000,000 shares authorized; none outstanding)
           
Common stock; par value $0.001 per share (2,000,000,000 shares authorized; 350,711,802 and 349,812,537 issued)
    112       111  
Additional paid-in capital
    6,248,060       6,238,639  
Accumulated deficit
    (1,723,048 )     (2,375,201 )
Accumulated other comprehensive loss
    (74,232 )     (85,905 )
 
           
Total stockholders’ equity
    4,450,892       3,777,644  
 
           
Total Liabilities and Equity
  $ 8,272,235     $ 10,722,395  
 
           
See Notes to our Unaudited Consolidated Interim Financial Statements

 

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RRI ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
                 
    Six Months Ended June 30,  
    2009     2008  
    (thousands of dollars)  
Cash Flows from Operating Activities:
               
Net income
  $ 652,153     $ 735,900  
Income from discontinued operations
    (861,626 )     (640,986 )
 
           
Net income (loss) from continuing operations
    (209,473 )     94,914  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization
    135,504       165,706  
Deferred income taxes
    (115,850 )     71,419  
Net changes in energy derivatives
    37,099       (98,316 )
Amortization of deferred financing costs
    4,292       4,206  
Gains on sales of assets and emission and exchange allowances, net
    (20,171 )     (22,923 )
Western states litigation and similar settlements
          34,000  
Other, net
    7,450       (1,268 )
Changes in other assets and liabilities:
               
Accounts and notes receivable, net
    126,059       (158,758 )
Changes in notes, receivables and payables with affiliate, net
    (1,230 )     (5,440 )
Inventory
    12,610       (42,445 )
Margin deposits, net
    (50,402 )     (54,644 )
Net derivative assets and liabilities
    (21,965 )     (9,519 )
Accounts payable
    (7,453 )     88,399  
Other current assets
    3,759       (6,819 )
Other assets
    9,073       19,190  
Taxes payable/receivable
    (4,936 )     19,971  
Other current liabilities
    (4,207 )     (8,100 )
Other liabilities
    3,322       (1,242 )
 
           
Net cash provided by (used in) continuing operations from operating activities
    (96,519 )     88,331  
Net cash provided by discontinued operations from operating activities
    508,602       102,531  
 
           
Net cash provided by operating activities
    412,083       190,862  
 
           
Cash Flows from Investing Activities:
               
Capital expenditures
    (114,964 )     (102,930 )
Proceeds from sales of assets, net
    35,931        
Proceeds from sales of emission and exchange allowances
    19,175       28,420  
Purchases of emission allowances
    (5,662 )     (17,644 )
Restricted cash
    (57 )     (3,835 )
Other, net
    1,500       1,435  
 
           
Net cash used in continuing operations from investing activities
    (64,077 )     (94,554 )
Net cash provided by (used in) discontinued operations from investing activities
    299,004       (14,200 )
 
           
Net cash provided by (used in) investing activities
    234,927       (108,754 )
 
           
Cash Flows from Financing Activities:
               
Payments of long-term debt
    (44,780 )     (45,193 )
Payments of debt extinguishments expenses
          (423 )
Proceeds from issuances of stock
    2,309       5,769  
 
           
Net cash used in continuing operations from financing activities
    (42,471 )     (39,847 )
Net cash used in discontinued operations from financing activities
    (225,300 )      
 
           
Net cash used in financing activities
    (267,771 )     (39,847 )
 
           
Net Change in Cash and Cash Equivalents, Total Operations
    379,239       42,261  
Less: Net Change in Cash and Cash Equivalents, Discontinued Operations
    (103,359 )     (325 )
Cash and Cash Equivalents at Beginning of Period, Continuing Operations
    1,004,367       524,070  
 
           
Cash and Cash Equivalents at End of Period, Continuing Operations
  $ 1,486,965     $ 566,656  
 
           
Supplemental Disclosure of Cash Flow Information:
               
Cash Payments:
               
Interest paid (net of amounts capitalized) for continuing operations
  $ 95,105     $ 104,797  
Income taxes paid (net of income tax refunds) for continuing operations
    3,582       (13,449 )
See Notes to our Unaudited Consolidated Interim Financial Statements

 

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RRI ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
(1) Background and Basis of Presentation
(a) Background.
“RRI Energy” refers to RRI Energy, Inc. and “we,” “us” and “our” refer to RRI Energy, Inc. and its consolidated subsidiaries. Our business consists primarily of one business segment, wholesale energy. See note 13. Our 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 Form 10-K.
On May 1, 2009, we sold our interests in the affiliates that operated our Texas retail business. In connection with this sale, we changed our name to RRI Energy, Inc. from Reliant Energy, Inc. effective May 2, 2009. See note 15.
(b) Basis of Presentation.
Estimates. Management makes estimates and assumptions to prepare financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) that affect:
    the reported amounts of assets, liabilities and equity;
    the reported amounts of revenues and expenses; and
    our disclosure of contingent assets and liabilities at the date of the financial statements.
We evaluate our estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which we believe to be reasonable under the circumstances. We adjust such estimates and assumptions when facts and circumstances dictate. We have evaluated subsequent events for recording and disclosure to August 3, 2009, the date the interim financial statements were issued.
Adjustments and Reclassifications. 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, however, may not be indicative of a full year period due to 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. We have reclassified certain amounts reported in these interim financial statements from prior periods to conform to the 2009 presentation. We reclassified amounts on our December 31, 2008 consolidated balance sheet relating primarily to continuing versus discontinued margin deposits, which increased our total assets and total liabilities by $93 million. These reclassifications had no impact on reported earnings/losses.
Deconsolidation of Channelview. On August 20, 2007, four of our wholly-owned subsidiaries, RRI Energy Channelview LP (Channelview LP), RRI Energy Channelview (Texas) LLC, RRI Energy Channelview (Delaware) LLC and RRI Energy Services Channelview LLC (collectively, Channelview), filed for reorganization under Chapter 11 of the Bankruptcy Code. As Channelview is currently subject to the supervision of the bankruptcy court, we deconsolidated Channelview’s financial results beginning August 20, 2007 and began reporting our investment in Channelview using the cost method. The Channelview plant was sold on July 1, 2008. See note 14 for further discussion of Channelview.
Inventory. We value fuel inventories at the lower of average cost or market. We reduce these inventories as they are used in the production of electricity or sold. We recorded $35 million and $1 million during the three months ended June 30, 2009 and 2008, respectively, for lower of average cost or market adjustments in cost of sales and recorded $59 million and $1 million during the six months ended June 30, 2009 and 2008, respectively.
FASB Codification. The Financial Accounting Standards Board’s (FASB) Accounting Standards Codification became effective for us in the third quarter of 2009. The Codification brings together in one place all authoritative GAAP and substantially retains existing GAAP. This change will not affect our consolidated financial statements.

 

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New Accounting Pronouncement Adopted — Interim Disclosures about Fair Value of Financial Instruments. The FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which is effective for our June 30, 2009 interim financial statements. The FSP amends Statement of Financial Accounting Standards (SFAS) No. 107, “Disclosures about Fair Value of Financial Instruments” and requires us to provide information about the fair value of our financial instruments, including methods and significant assumptions used to estimate the fair value, in interim financial statements. See note 3.
New Accounting Pronouncement Adopted — Fair Value Measurements. The FASB issued FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which is effective for our June 30, 2009 interim financial statements. The FSP provides guidance on how to determine the fair value of assets and liabilities under SFAS No. 157, “Fair Value Measurements” when there has been a significant decrease in the volume and level of activity for an asset or liability compared with normal market activity for the asset or liability. This FSP did not have a significant impact on our consolidated financial statements since the markets in which we purchase and sell commodities and derivative instruments are not distressed. See notes 3 and 4.
New Accounting Pronouncement Not Yet Adopted — Disclosures about Plan Assets. The FASB issued FSP FAS 132(R)-1, “Employer’s Disclosures about Postretirement Benefit Plan Assets,” which is effective for 2009. In addition to enhanced disclosures regarding investment policies and strategies, this FSP will require us to disclose in our 2009 Annual Report on Form 10-K information about fair value measurements of plan assets that would be similar to the disclosures about fair value measurements required by SFAS No. 157, “Fair Value Measurements.”
(2) Stock-based Compensation and Other Employee Matters
Stock-based Compensation. Our compensation expense for our stock-based incentive plans was:
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
    (in millions)  
 
                               
Stock-based incentive plans compensation expense (pre-tax)(1)
  $ 1     $ 4     $ 4     $ 8  
 
                       
 
     
(1)   See note 10(a) to our consolidated financial statements in our Form 10-K for information about our stock-based incentive plans compensation expense.
During June 2009, the compensation committee of our board of directors granted 817,030 time-based restricted stock units and 817,030 time-based cash units to employees under our stock and incentive plans. The awards will vest in June 2012. No tax benefits related to stock-based compensation were realized during the three and six months ended June 30, 2009 and 2008 due to our net operating loss carryforwards.
Other Employee Matters. As of June 30, 2009, approximately 45% of our employees are subject to collective bargaining arrangements. Approximately 35% of our employees are subject to collective bargaining arrangements that will expire by June 30, 2010. We intend to negotiate the renewal of these agreements.
(3) Fair Value Measurements
Fair Value Hierarchy and Valuation Techniques. We apply recurring fair value measurements to our financial assets and liabilities. In determining fair value, we generally use the 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. These inputs can be readily observable, market corroborated, or generally unobservable internally-developed inputs. Based on the observability of the inputs used in our valuation techniques, our financial assets and liabilities are classified as follows:
     
Level 1:
  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 our energy derivative instruments that are exchange-traded or that are cleared and settled through the exchange. It also includes our available-for-sale and trading securities.
 
   
Level 2:
  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 includes emission allowances futures that are exchange-traded and over-the-counter (OTC) derivative instruments such as generic swaps, forwards and options.

 

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Level 3:
  This category includes our energy derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from objective sources (such as implied volatilities and correlations). Our 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, longer term natural gas contracts and options valued using implied or internally-developed inputs.
We value some of our OTC, complex or structured derivative instruments using valuation models, which utilize inputs that may not be corroborated by market data, such as market prices for power and fuel, price shapes, volatilities and correlations as well as other relevant factors. When such inputs are significant to the fair value measurement, the derivative assets or liabilities are classified as Level 3 when we do not have corroborating market evidence to support significant valuation model inputs and cannot verify the model to market transactions. We believe the transaction price is the best estimate of fair value at inception under the exit price methodology. Accordingly, when a pricing model is used to value such an instrument, the resulting value is adjusted so the model value at inception equals the transaction price. Valuation models are typically impacted by Level 1 or Level 2 inputs that can be observed in the market, as well as unobservable Level 3 inputs. Subsequent to initial recognition, we update Level 1 and Level 2 inputs to reflect observable market changes. Level 3 inputs are updated when corroborated by available market evidence. In the absence of such evidence, management’s best estimate is used.
Fair Value of Derivative Instruments and Certain Other Assets. We apply recurring fair value measurements to our financial assets and liabilities. Fair value measurements of our financial assets and liabilities are as follows:
                                         
    June 30, 2009  
                                    Total  
    Level 1     Level 2     Level 3     Reclassification     Fair Value  
    (in millions)  
 
                                       
Total derivative assets
  $ 172     $ 68     $ 1     $ (1)   $ 241  
Total derivative liabilities
    53       179       118       (1)     350  
Other assets(2)
    32                         32  
 
     
(1)   Reclassifications are required to reconcile to our consolidated balance sheet presentation. Amounts are insignificant as of June 30, 2009.
 
(2)   Includes $12 million in available-for-sale securities (shares in a public exchange) and $20 million in trading securities (rabbi trust investments (which is comprised of mutual funds) associated with our non-qualified deferred compensation plans for key and highly compensated employees).
                                         
    December 31, 2008  
                                    Total  
    Level 1     Level 2     Level 3     Reclassifications     Fair Value  
    (in millions)  
 
                                       
Total derivative assets
  $ 125     $ 111     $ 7     $ (3 )(1)   $ 240  
Total derivative liabilities
    17       208       121       (3 )(1)     343  
Other assets(2)
    29                         29  
 
     
(1)   Reclassifications are required to reconcile to our consolidated balance sheet presentation.
 
(2)   Includes $8 million in available-for-sale securities (shares in a public exchange) and $21 million in trading securities (rabbi trust investments (which is comprised of mutual funds) associated with our non-qualified deferred compensation plans for key and highly compensated employees).

 

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The fair values of cash and cash equivalents, accounts receivable and payable, margin deposits, available-for-sale securities, trading securities and derivative assets and liabilities approximate their carrying amounts. Values of our debt for continuing operations (see note 7) are:
                                 
    June 30, 2009     December 31, 2008  
    Carrying     Fair     Carrying     Fair  
    Value     Value(1)     Value     Value(1)  
    (in millions)  
 
                               
Fixed rate debt
  $ 2,572     $ 2,421     $ 2,623     $ 2,168  
 
                       
Total debt
  $ 2,572     $ 2,421     $ 2,623     $ 2,168  
 
                       
 
     
(1)   We based the fair values of our fixed rate debt on market prices and quotes from an investment bank.
The following is a reconciliation of changes in fair value of net derivative assets and liabilities classified as Level 3:
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
    Net Derivatives (Level 3)     Net Derivatives (Level 3)  
    (in millions)  
 
                               
Balance, beginning of period
  $ (153 )   $ 85     $ (114 )   $ 21  
Total gains (losses) realized/unrealized:
                               
Included in earnings
    (12 )(1)     127 (1)     (79 )(1)     141 (1)
Purchases, issuances and settlements (net)
    48       (36 )     76       14  
Transfers in and/or out of Level 3 (net)
    (2)     (3)     (4)     (5)
 
                       
Balance, end of period
  $ (117 )   $ 176     $ (117 )   $ 176  
 
                       
 
                               
Changes in unrealized gains (losses) relating to derivative assets and liabilities still held at June 30, 2009 and 2008:
                               
Revenues
  $     $ (2 )   $ (2 )   $ (1 )
Cost of sales
    (5 )     124       (54 )     102  
 
                       
Total
  $ (5 )   $ 122     $ (56 )   $ 101  
 
                       
 
     
(1)   Recorded in revenues and cost of sales.
 
(2)   Represents fair value as of March 31, 2009.
 
(3)   Represents fair value as of March 31, 2008.
 
(4)   Represents fair value as of December 31, 2008.
 
(5)   Represents fair value as of December 31, 2007.
See note 2(e) to our consolidated financial statements in our Form 10-K for additional information about fair value measurements.
(4) Derivative Instruments and Hedging Activities
We account for our derivative instruments and hedging activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133). Effective January 1, 2009, we adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (SFAS No. 161).
Changes in commodity prices prior to the energy delivery period are inherent in our business. However, we believe the benefits of generally hedging our generation assets do not justify the costs, including collateral postings. Accordingly, we may enter selective hedges, including originated transactions, based on our assessment of (a) operational and market limitations requiring us to enter into power, fuel, capacity and emissions transactions to manage our generation assets, (b) the near term economic environment and volatile commodity markets and the benefits of hedging some of the downside risk to our earnings and cash flows and (c) market fundamentals and the opportunity to increase the return from our generation assets. For our risk management activities, we use derivative and non-derivative contracts that provide for settlement in cash or by delivery of a commodity. We use derivative instruments such as futures, forwards, swaps and options to execute our wholesale hedge strategy. We may also enter into derivatives to manage our exposure to changes in prices of emission and exchange allowances.

 

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We account for our derivatives under one of three accounting methods (mark-to-market, accrual (under the normal purchase/normal sale exception to fair value accounting) or cash flow hedge accounting) based on facts and circumstances. The fair values of our derivative activities are determined by (a) prices actively quoted, (b) prices provided by other external sources or (c) prices based on models and other valuation methods. See note 5 for discussion on fair value measurements.
A derivative is recognized at fair value in the balance sheet whether or not it is designated as a hedge, except for derivative contracts designated as normal purchase/normal sale exceptions, which are not in our consolidated balance sheet or results of operations prior to settlement resulting in accrual accounting treatment.
Realized gains and losses on derivative contracts used for risk management purposes and not held for trading purposes are reported either on a net or gross basis based on the relevant facts and circumstances. Hedging transactions that do not physically flow are included in the same caption as the items being hedged.
A summary of our derivative activities and classification in our results of operations is:
                 
    Primary       Transactions that    
    Risk   Purpose for Holding or   Physically   Transactions that
Instrument   Exposure   Issuing Instrument(1)   Flow/Settle   Financially Settle(2)
 
               
Power futures, forward, swap and option contracts
  Price risk   Power sales to customers   Revenues   Revenues
 
      Power purchases related to operations   Cost of sales   Revenues
 
      Power purchases/sales related to legacy trading and non-core asset management positions(3)   Revenues   Revenues
 
               
Natural gas and fuel futures, forward, swap and option contracts
  Price risk   Natural gas and fuel sales related to operations   Revenues/Cost of sales   Cost of sales
 
      Natural gas sales related to power generation(4)   N/A(5)   Revenues
 
      Natural gas and fuel purchases related to operations   Cost of sales   Cost of sales
 
      Natural gas and fuel purchases/sales related to legacy trading and non-core asset management positions(3)   Cost of sales   Cost of sales
 
               
Emission and exchange allowances futures(6)
  Price risk   Purchases/sales of emission and exchange allowances   N/A(5)   Revenues/Cost of sales
 
     
(1)   The purpose for holding or issuing does not impact the accounting method elected for each instrument.
 
(2)   Includes classification for mark-to-market derivatives and amounts reclassified from accumulated other comprehensive income (loss) related to cash flow hedges.
 
(3)   See discussion below regarding trading activities.
 
(4)   Natural gas financial swaps and options transacted to economically hedge generation in the PJM region.
 
(5)   N/A is not applicable.
 
(6)   Includes emission and exchange allowances futures for sulfur dioxide (SO2), nitrogen oxide (NOX) and carbon dioxide (CO2).
In addition to market risk, we are exposed to credit and operational risk. We have a risk control framework to manage these risks, which include: (a) measuring and monitoring these risks, (b) review and approval of new transactions relative to these risks, (c) transaction validation and (d) portfolio valuation and reporting. We use mark-to-market valuation, value-at-risk and other metrics in monitoring and measuring risk. Our risk control framework includes a variety of separate but complementary processes, which involve commercial and senior management and our Board of Directors. See note 5 for further discussion of our credit policy.
Earnings Volatility from Derivative Instruments. We procure natural gas, coal, oil, natural gas transportation and storage capacity and other energy-related commodities to support our business. Some types of transactions may cause us to experience volatility in our earnings due to natural gas inventory related to transportation and storage generally receiving accrual treatment while the related derivative instruments are marked to market through earnings.

 

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Unrealized gains and losses on energy derivatives consist of both gains and losses on energy derivatives during the current reporting period for derivative assets or liabilities that have not settled as of the balance sheet date and the reversal of unrealized gains and losses from prior periods for derivative assets or liabilities that settled prior to the balance sheet date but during the current reporting period.
Cash Flow Hedges. If certain conditions are met, a derivative instrument may be designated as a cash flow hedge. Derivatives designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item. The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive income (loss), net of tax, to the extent the contracts are, or have been, effective as hedges, until the forecasted transactions affect earnings. At the time the forecasted transactions affect earnings, we reclassify the amounts in accumulated other comprehensive income (loss) into earnings. We record the ineffective portion of changes in fair value of cash flow hedges immediately into earnings. For all other derivatives, changes in fair value are recorded as unrealized gains or losses in our results of operations.
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. The associated hedging instrument is then marked to market through our results of operations for the remainder of the contract term unless a new hedging relationship is redesignated.
Over the past several years, we have substantially decreased derivatives accounted for as cash flow hedges, in favor of utilizing the mark-to-market method of accounting or the normal purchase/normal sale exception for these derivatives. During the first quarter of 2007, we de-designated our remaining cash flow hedges; therefore, as of June 30, 2009 and December 31, 2008, we do not have any designated cash flow hedges.
Presentation of Derivative Assets and Liabilities. We present our derivative 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.
As of June 30, 2009, our commodity derivative assets and liabilities include amounts for non-trading and trading activities as follows:
                                         
    Derivative Assets     Derivative Liabilities     Net Derivative  
    Current     Long-Term     Current     Long-Term     Assets (Liabilities)  
    (in millions)  
Non-trading
  $ 95     $ 64     $ (194 )   $ (102 )   $ (137 )
Trading
    62       20       (41 )     (13 )     28  
 
                             
Total derivatives
  $ 157     $ 84     $ (235 )   $ (115 )   $ (109 )
 
                             
We have the following derivative commodity contracts outstanding as of June 30, 2009:
                         
            Notional Volumes  
Commodity   Unit     Current     Long-term  
          (in millions)  
Power
  MWh(1)     (3 )(2)     (5 )(2)
Natural gas
  MMBTU(3)     7       25  
Natural gas basis
  MMBTU(3)           1  
Coal
  MMBTU(3)     109       235  
 
     
(1)   MWh is megawatt hours.
 
(2)   Negative amounts indicate net forward sales.
 
(3)   MMBTU is million British thermal units.

 

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The income (loss) associated with our energy derivatives is:
                 
    Three Months Ended June 30, 2009  
Derivatives Not Designated as Hedging Instruments Under SFAS No. 133(1)   Revenues     Cost of Sales  
    (in millions)  
 
               
Non-Trading Commodity Contracts:
               
Unrealized(2)
  $ (22 )   $ 31  
Realized(3)(4)(5)
    81       (66 )
 
           
Total non-trading
  $ 59     $ (35 )
 
           
 
               
Trading Commodity Contracts:
               
Unrealized
  $     $ (2 )
Realized(3)
          1  
 
           
Total trading
  $     $ (1 )
 
           
                 
    Six Months Ended June 30, 2009  
Derivatives Not Designated as Hedging Instruments Under SFAS No. 133(1)   Revenues     Cost of Sales  
    (in millions)  
 
               
Non-Trading Commodity Contracts:
               
Unrealized(2)
  $ (26 )   $ (9 )
Realized(3)(4)(5)
    187       (74 )
 
           
Total non-trading
  $ 161     $ (83 )
 
           
 
               
Trading Commodity Contracts:
               
Unrealized
  $     $ (2 )
Realized(3)
          20  
 
           
Total trading
  $     $ 18  
 
           
 
     
(1)   Interest rate swap instruments were liquidated in 2002 and the related deferred losses in accumulated other comprehensive loss are being amortized into interest expense through 2012. An immaterial amount was amortized during the three and six months ended June 30, 2009 and 2008, which was included in interest expense under other operations.
 
(2)   During 2007, we de-designated our remaining cash flow hedges. During the three and six months ended June 30, 2009, previously measured ineffectiveness gains (losses) reversing due to settlement of the derivative contracts was insignificant.
 
(3)   Does not include realized gains or losses associated with cash month transactions, non-derivative transactions or derivative transactions that qualify for the normal purchase/normal sale exception.
 
(4)   Excludes settlement value of fuel contracts classified as inventory upon settlement.
 
(5)   Includes gains or losses from de-designated cash flow hedges reclassified from accumulated other comprehensive loss due to settlement of the derivative contracts. See note 6.
As of June 30, 2009 and December 31, 2008, we do not have any designated cash flow hedges. Amounts included in accumulated other comprehensive loss are:
                 
    June 30, 2009  
            Expected to be  
            Reclassified into  
            Results of  
    At the End of the     Operations  
    Period     in Next 12 Months  
    (in millions)  
 
               
De-designated cash flow hedges(1)(2)(3)
  $ 41     $ 15  
 
           
 
     
(1)   No component of the derivatives’ gain or loss was excluded from the assessment of effectiveness.
 
(2)   During the three and six months ended June 30, 2008, previously measured ineffectiveness gains (losses) in revenues of $1 million and $0, respectively, reversed due to settlement of the derivative contracts.
 
(3)   During the three and six months ended June 30, 2009 and 2008, $0 was recognized in our results of operations as a result of the discontinuance of cash flow hedges because it was probable that the forecasted transaction would not occur.

 

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Trading Activities. Prior to March 2003, we engaged in proprietary trading activities. Trading positions entered into prior to our decision to exit this business are being closed on economical terms or are being retained and settled over the contract terms. In addition, we have current transactions relating to non-core asset management, such as gas storage and transportation contracts not tied to generation assets, which are classified as trading activities. The income (loss) associated with these transactions is:
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
          (in millions)        
 
                               
Revenues
  $     $     $     $  
Cost of sales
    5       (13 )     16       (17 )
 
                       
Total(1)
  $ 5     $ (13 )   $ 16     $ (17 )
 
                       
 
     
(1)   Includes realized and unrealized gains and losses on both derivative instruments and non-derivative instruments.
     
(5)   Credit Risk
We have a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and specific transaction approvals. Credit risk is monitored daily and the financial condition of our counterparties is reviewed periodically. We try to mitigate credit risk by entering into contracts that permit netting and allow us to terminate upon the occurrence of certain events of default. We measure credit risk as the replacement cost for our derivative positions plus amounts owed for settled transactions.
Our credit exposure is based on our derivative assets and accounts receivable from our wholesale energy counterparties, after taking into consideration netting within each contract and any master netting contracts with counterparties. We believe this represents the maximum potential loss we would incur if our counterparties failed to perform according to their contract terms. In determining the fair value of our derivative assets, we include assumptions for counterparty non-performance risk. See note 3 above and note 2(e) to our consolidated financial statements in our Form 10-K for additional information about fair value measurements. Additionally, we provide an allowance for doubtful accounts for outstanding receivable balances.
As of June 30, 2009, our derivative assets and accounts receivable from our wholesale energy counterparties, after taking into consideration netting within each contract and any master netting contracts with counterparties, are:
                                         
    Exposure     Credit             Number of     Net Exposure of  
    Before     Collateral     Exposure     Counterparties     Counterparties  
Credit Rating Equivalent   Collateral(1) (2)     Held(3)     Net of Collateral     >10%     >10%  
    (dollars in millions)  
 
Investment grade
  $ 224     $ 45     $ 179       2 (4)   $ 145  
Non-investment grade
    2             2              
No external ratings:
                                       
Internally rated — Investment grade
    66             66       1 (5)     65  
Internally rated — Non-investment grade
    7       6       1              
 
                             
Total
  $ 299     $ 51     $ 248       3     $ 210  
 
                             
 
     
(1)   The table includes amounts related to certain contracts classified as discontinued operations in our consolidated balance sheets. These contracts settle through the expiration date in 2010.
 
(2)   The table excludes amounts related to contracts classified as normal purchase/normal sale and non-derivative contractual commitments that are not recorded in our consolidated balance sheets, except for any related accounts receivable. Such contractual commitments contain credit and economic risk if a counterparty does not perform. Nonperformance could have a material adverse impact on our future results of operations, financial condition and cash flows.
 
(3)   Collateral consists of cash, standby letters of credit and other forms approved by management.
 
(4)   These counterparties are a power grid operator and an energy merchant.
 
(5)   This counterparty is a financial institution.
As of December 31, 2008, three investment grade counterparties (a financial institution and two power grid operators) represented 63% ($156 million) of our credit exposure.
Based on our current credit ratings, any additional collateral postings that would be required from us due to a credit downgrade would be immaterial. As of June 30, 2009 and December 31, 2008, we have posted cash margin deposits of $122 million and $70 million, respectively, as collateral for our derivative liabilities receiving mark-to-market accounting treatment and our accounts payable (classified either as continuing or discontinued operations). Additionally, as of June 30, 2009 and December 31, 2008, we have $95 million and $103 million, respectively, in letters of credit issued as collateral for our derivative liabilities receiving mark-to-market accounting treatment and our accounts payable (classified either as continuing or discontinued operations). See note 7.

 

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(6) Comprehensive Income
The components of total comprehensive income are:
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
    (in millions)  
 
                               
Net income
  $ 803     $ 359     $ 652     $ 736  
Other comprehensive income, net of tax:
                               
Reclassification of net deferred loss from cash flow hedges realized into net income/loss (net of tax)
    3       6       8       16  
Unrealized gain on available-for-sale securities (net of tax)(1)
    2             3        
Reclassification of benefits actuarial net loss into net income/loss (net of tax)
    1             1        
 
                       
Comprehensive income
  $ 809     $ 365     $ 664     $ 752  
 
                       
 
     
(1)   As of June 30, 2009 and December 31, 2008, $12 million and $8 million, respectively, of unrealized net gains (excluding taxes) are included in accumulated other comprehensive loss for available-for-sale securities.
     
(7)   Debt
                                                 
    June 30, 2009     December 31, 2008  
    Weighted                     Weighted              
    Average                     Average              
    Stated                     Stated              
    Interest                     Interest              
    Rate(1)     Long-term     Current     Rate(1)     Long-term     Current  
    (in millions, except interest rates)  
 
                                               
Facilities, Bonds and Notes:
                                               
RRI Energy:
                                               
Senior secured revolver due 2012
    2.35 %   $     $       3.18 %   $     $  
Senior secured notes due 2014(2)(3)
    6.75       453             6.75       498        
Senior unsecured notes due 2014
    7.625       575             7.625       575        
Senior unsecured notes due 2017
    7.875       725             7.875       725        
Subsidiary Obligations:
                                               
Orion Power Holdings, Inc. senior notes due 2010 (unsecured)
    12.00             400       12.00       400        
PEDFA(4) fixed-rate bonds due 2036(5)
    6.75       408             6.75       408        
 
                                       
Total facilities, bonds and notes
            2,161       400               2,606        
 
                                       
Other:
                                               
Adjustment to fair value of debt(6)
                  11               4       13  
 
                                       
Total other debt
                  11               4       13  
 
                                       
Total debt(7)
          $ 2,161     $ 411             $ 2,610     $ 13  
 
                                       
 
     
(1)   The weighted average stated interest rates are as of June 30, 2009 or December 31, 2008.
 
(2)   We repurchased $45 million during the three months ended June 30, 2009. See note 15.
 
(3)   Excludes $22 million and $169 million classified as discontinued operations as of June 30, 2009 and December 31, 2008, respectively. See note 15.
 
(4)   PEDFA is the Pennsylvania Economic Development Financing Authority. These bonds were issued for our Seward plant.
 
(5)   Excludes $14 million and $92 million classified as discontinued operations as of June 30, 2009 and December 31, 2008, respectively. See note 15.
 
(6)   Debt acquired in the Orion Power acquisition was adjusted to fair value as of the acquisition date. Included in interest expense is amortization of $3 million and $3 million for valuation adjustments for debt during the three months ended June 30, 2009 and 2008, respectively, and $6 million and $6 million during the six months ended June 30, 2009 and 2008, respectively.
 
(7)   Excludes $36 million and $261 million classified as discontinued operations as of June 30, 2009 and December 31, 2008, respectively. See note 15.

 

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Amounts borrowed and available for borrowing under our revolving credit agreements as of June 30, 2009 are:
                                 
    Total Committed     Drawn     Letters     Unused  
    Credit     Amount     of Credit     Amount  
    (in millions)  
 
                               
RRI Energy senior secured revolver due 2012
  $ 500     $     $ 39     $ 461  
RRI Energy letter of credit facility due 2014
    250             250        
 
                       
Total
  $ 750     $     $ 289     $ 461  
 
                       
(8) Earnings (Loss) Per Share
The amounts used in the basic and diluted earnings (loss) per common share computations are the same.
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
    (in millions)  
 
                               
Income (loss) from continuing operations (basic and diluted)
  $ (103 )   $ 82     $ (209 )   $ 95  
 
                       
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
    (shares in thousands)  
 
                               
Diluted Weighted Average Shares Calculation:
                               
Weighted average shares outstanding (basic)
    350,665       346,616       350,577       346,017  
Plus: Incremental shares from assumed conversions:
                               
Stock options
    (1)     4,317       (1)     4,285  
Restricted stock
    (1)     575       (1)     559  
Employee stock purchase plan
    (1)     47       (1)     23  
5.00% convertible senior subordinated notes
    N/A (2)     18       N/A (2)     115  
Warrants
    N/A (3)     2,481       N/A (3)     3,079  
 
                       
Weighted average shares outstanding assuming conversion (diluted)
    350,665       354,054       350,577       354,078  
 
                       
 
     
(1)   As we incurred a loss from continuing operations for this period, diluted loss per share is calculated the same as basic loss per share.
 
(2)   In December 2006, we converted 99.2% of our convertible senior subordinated notes to common stock. During 2008, the remaining outstanding notes were converted to common stock.
 
(3)   All unexercised warrants expired in August 2008.
We excluded the following items from diluted earnings (loss) per common share due to the anti-dilutive effect:
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
    (shares in thousands, dollars in millions)  
 
                               
Shares excluded from the calculation of diluted earnings (loss) per share
    438 (1)     N/A (2)     442 (1)     N/A (2)
Shares excluded from the calculation of diluted earnings (loss) per share because the exercise price exceeded the average market price
    6,217 (3)     1,833 (3)     7,086 (3)     1,849 (3)
 
     
(1)   Potential shares excluded consist of stock options, restricted stock and shares related to the employee stock purchase plan.
 
(2)   Not applicable as we included the item in the calculation of diluted earnings/loss per share.
 
(3)   Includes stock options.

 

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(9) Income Taxes
(a) Tax Rate Reconciliation.
A reconciliation of the federal statutory income tax rate to the effective income tax rate for our continuing operations is:
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
 
                               
Federal statutory rate
    (35 )%     35 %     (35 )%     35 %
Additions (reductions) resulting from:
                               
Federal valuation allowance
    (8 )                  
State income taxes, net of federal income taxes
    (1 )(1)     5 (2)     (1 )(3)     6 (4)
Other
          3             2  
 
                       
Effective rate
    (44 )%     43 %     (36 )%     43 %
 
                       
 
     
(1)   Of this percentage, $9 million relates to additional valuation allowance.
 
(2)   Of this percentage, $3 million relates to additional valuation allowance.
 
(3)   Of this percentage, $15 million relates to additional valuation allowance.
 
(4)   Of this percentage, $4 million relates to additional valuation allowance.
(b) Tax Attributes Carryovers.
Our tax attributes carryovers were substantially not affected by the Texas retail sale to the subsidiary of NRG Energy, Inc. See note 15.
(c) Valuation Allowances.
We assess our future ability to use federal, state and foreign net operating loss carryforwards, capital loss carryforwards and other deferred tax assets using the more-likely-than-not criteria. These assessments include an evaluation of our recent history of earnings and losses, future reversals of temporary differences and identification of other sources of future taxable income, including the identification of tax planning strategies in certain situations.
Our valuation allowances for continuing deferred tax assets are:
                         
                    Capital, Foreign  
    Federal     State     and Other, Net  
    (in millions)  
 
                       
As of December 31, 2008
  $ 49     $ 103     $ 14  
Changes in valuation allowance
    16       6        
 
                 
As of March 31, 2009
    65       109       14  
Changes in valuation allowance
    (16 )     9       1  
 
                 
As of June 30, 2009
  $ 49     $ 118     $ 15  
 
                 
(d) FIN 48 and Income Tax Uncertainties.
We may only recognize the tax benefit for financial reporting purposes from an uncertain tax position when it is more-likely-than-not that, based on the technical merits, the position will be sustained by taxing authorities or the courts. The recognized tax benefits are measured as the largest benefit having a greater than fifty percent likelihood of being realized upon settlement with a taxing authority. We classify accrued interest and penalties related to uncertain income tax positions in income tax expense/benefit.

 

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Our unrecognized federal and state tax benefits did not change significantly during the three and six months ended June 30, 2009 and 2008.
We expect to continue discussions with taxing authorities regarding tax positions related to the following, and believe it is reasonably possible some of these matters could be resolved in the next 12 months; however, we cannot estimate the range of changes that might occur:
    $177 million payment to CenterPoint during 2004 related to our residential customers;
    $351 million charge during 2005 to settle certain civil litigation and claims relating to the Western states energy crisis; and
    the timing of tax deductions as a result of negotiations with respect to California-related revenue, depreciation, emission allowances and certain employee benefits.
We are in ongoing discussions with the Internal Revenue Service (IRS) regarding the timing of revenue recognition and tax deductions with respect to certain California-related items in our 2002 short taxable period return (subsequent to our separation from CenterPoint Energy, Inc.). The IRS has informed us it expects to issue a notice of denial of our administrative claim for refund involving these California-related items and we expect to institute refund litigation with respect to this claim in the U.S. District Court or U.S. Court of Federal Claims. In order to set a jurisdictional prerequisite to institute such a refund suit, we expect to make a payment of approximately $60 million to $65 million (which includes an asserted tax liability of $38 million plus interest) some time during 2009. If the IRS were to ultimately prevail in this matter, there would be no impact on the effective tax rate except for interest. The payment is refundable with interest if we are successful in the litigation.
(10) Guarantees and Indemnifications
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 approximately $53 million as of June 30, 2009 and no liability is recorded in our consolidated balance sheet for this item.
We also guarantee the $500 million PEDFA bonds, which are included in our consolidated balance sheet as either outstanding debt or liabilities of discontinued operations ($422 million and $500 million are in our consolidated balance sheet as of June 30, 2009 and December 31, 2008, respectively). Our guarantees are secured by the same collateral as our 6.75% senior secured notes. The guarantees require us to comply with covenants similar to those in the 6.75% senior secured notes indenture. The PEDFA bonds will become secured by certain assets of our Seward power plant if the collateral supporting both the 6.75% senior secured notes and our guarantees are released. Our maximum potential obligation under the guarantees is for payment of the principal of $500 million and related interest charges at a fixed rate of 6.75%. During June and July 2009, we purchased $78 million and $14 million, respectively, of the PEDFA bonds and are the holder of these repurchased bonds. Therefore, the net amount payable by us would not exceed the amount of PEDFA bonds outstanding, excluding the PEDFA bonds we hold.
We have guaranteed payments to a third party relating to energy sales from El Dorado Energy, LLC, a former investment. The estimated maximum potential amount of future payments under this guarantee is approximately $21 million as of June 30, 2009 and no liability is recorded in our consolidated balance sheet for this item.
We enter into contracts that include indemnification and guarantee provisions. In general, we enter into contracts with indemnities for matters such as breaches of representations and warranties and covenants contained in the contract and/or against certain specified liabilities. Examples of these contracts include asset purchase and sales agreements, service agreements and procurement agreements.
In our debt agreements, we typically indemnify against liabilities that arise from the preparation, entry into, administration or enforcement of the agreement.
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.

 

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(11) Contingencies
We are party to many legal proceedings, some of which may involve substantial amounts. Unless otherwise noted, we cannot predict the outcome of the matters described below.
(a) Pending Natural Gas Litigation.
The following proceedings relate to alleged conduct in the natural gas markets. We have settled a number of proceedings that were pending in California and other Western states; however, some other proceedings remain pending.
We are party to 13 lawsuits, several of which are class action lawsuits, in state and federal courts in California, Kansas, Missouri, Nevada, Tennessee and Wisconsin. These lawsuits 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.
Recent developments in these cases include:
    In January 2009, we reached an agreement to settle the five California-related cases pending in federal court in Nevada. The settlement is subject to approval of the court. The charges anticipated to be incurred in connection with the settlement were expensed in the third quarter of 2008. This settlement will resolve all of the remaining California gas cases.
    In January 2009, the Circuit Court of Jackson County, Missouri dismissed the case filed by the Missouri Public Service Commission for lack of standing to bring the action. An appeal was filed in February 2009.
(b) Merrill Lynch Action.
In December 2008, we terminated our $300 million retail working capital facility agreement with Merrill Lynch in order to address any issue that might be asserted regarding the minimum adjusted retail EBITDA covenant in that facility. On December 24, 2008, Merrill Lynch filed an action in the Supreme Court of the State of New York seeking a judgment declaring that under our credit sleeve and reimbursement agreement (the agreement), we did not have the right to terminate the working capital facility without their consent and that such termination is an event of default under the agreement. On May 1, 2009, we and Merrill Lynch filed to dismiss this lawsuit and the agreement was transferred in connection with the closing of the sale of our Texas retail business. The Court granted an order dismissing the action with prejudice on May 4, 2009. See note 15.
(c) Environmental Matters.
New Source Review Matters. The United States Environmental Protection Agency (EPA) and various states are investigating compliance of coal-fueled electric generating stations with the pre-construction permitting requirements of the Clean Air Act known as “New Source Review.” In 2000 and 2001, we responded to the EPA’s information requests related to five of our stations, and in December 2007, we received supplemental requests for two of those stations. In September 2008, we received an EPA request for information related to two additional stations. The EPA agreed to share information relating to its investigations with state environmental agencies. In January 2009, we received a Notice of Violation (NOV) from the EPA alleging that past work at our Shawville, Portland and Keystone generation facilities violated the agency’s regulations regarding New Source Review. We believe that the projects listed by the EPA were conducted in compliance with applicable regulations.
In December 2007, the New Jersey Department of Environmental Protection (NJDEP) filed suit against us in the United States District Court in Pennsylvania, alleging that New Source Review violations occurred at one of our power plants located in Pennsylvania. The suit seeks installation of “best available” control technologies for each pollutant, to enjoin us from operating the plant 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 are unable to predict the ultimate outcome of the EPA’s NOV or the NJDEP’s suit, but a final finding that we violated the New Source Review requirements could result in significant capital expenditures associated with the implementation of emissions reductions on an accelerated basis and possible penalties. Most of these work projects were undertaken before our ownership of those facilities. We believe we are indemnified by or have the right to seek indemnification from the prior owners for certain losses and expenses that we may incur from activities occurring prior to our ownership.

 

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Ash Disposal Landfill Closures. We are responsible for environmental costs related to the future closures of seven ash disposal landfills. We recorded the estimated discounted costs ($12 million as of June 30, 2009 and December 31, 2008) associated with these environmental liabilities as part of our asset retirement obligations. See note 2(q) to our consolidated financial statements in our Form 10-K.
Remediation Obligations. We are responsible for environmental costs related to site contamination investigations and remediation requirements at four power plants in New Jersey. We recorded the estimated long-term liability for the remediation costs of $8 million as of June 30, 2009 and December 31, 2008.
Conemaugh Action. In April 2007, PennEnvironment and the Sierra Club filed a citizens’ suit against us in the United States District Court, Western District of Pennsylvania to enforce provisions of the water discharge permit for the Conemaugh plant, of which we are the operator and have a 16.45% interest. PennEnvironment and the Sierra Club seek civil penalties, remediation and an injunction against further violations. We are confident that the Conemaugh plant has operated and will continue to operate in material compliance with its water discharge permit, its consent order agreement with the Pennsylvania Department of Environmental Protection, and related state and federal laws. However, if PennEnvironment and the Sierra Club are successful, we could incur additional capital expenditures associated with the implementation of discharge reductions and penalties, which we do not believe would be material.
Mandalay Notice of Violation. In November 2008, the California State Water Resources Control Board — Los Angeles Region proposed a settlement payment in the amount of $192,000 relating to alleged violations of our wastewater discharge permit for our Mandalay plant. We are reviewing the Board’s proposal and we believe that there are reasonable grounds for reduction of the amount of the settlement proposed by the Board.
Global Warming. In February 2008, the Native Village of Kivalina and the City of Kivalina filed a suit in the United States District Court for the Northern District of California against us 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. We believe this claim lacks legal merit.
(d) Other.
Excess Mitigation Credits. From January 2002 to April 2005, CenterPoint applied excess mitigation credits (EMCs) to its monthly charges to retail energy providers. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail energy providers’ monthly charges payable to CenterPoint. CenterPoint represents that the portion of those EMCs credited to our Texas retail business totaled $385 million. In its stranded cost case, CenterPoint sought recovery of all EMCs credited to all retail electric providers, including our Texas retail business, and the PUCT ordered that relief. On appeal, the Texas Third Court of Appeals ruled that CenterPoint’s stranded cost recovery should exclude EMCs credited to our Texas retail business for price-to-beat customers. The case is now before the Texas Supreme Court. In November 2008, CenterPoint asked us to agree to suspend any limitations periods that might exist for possible claims against us or our Texas retail business if it is ultimately not allowed to include in its stranded cost calculation EMCs credited to our Texas retail business. We agreed to suspend only unexpired deadlines, if any, that may apply to a CenterPoint claim relating to EMCs credited to our Texas retail business. Regardless of the outcome of the Texas Supreme Court proceeding, we believe that any claim by CenterPoint that we are liable to it for any EMCs credited to our Texas retail business lacks legal merit and is unsupported by our Master Separation Agreement with CenterPoint. In addition, CenterPoint has publicly stated that it has no legal recourse against us or our Texas retail business for any reduction in the amount of its recoverable stranded costs should EMCs credited to our Texas retail business be excluded.
CenterPoint Indemnity. We have agreed to indemnify CenterPoint against certain losses relating to the lawsuits described in note 11(a) under “Pending Natural Gas Litigation.”
Texas Franchise Audit. The state of Texas has issued assessment orders indicating an estimated tax liability of approximately $58 million (including interest and penalties of $20 million) relating primarily to the sourcing of receipts for 2000 through 2005. We are contesting the audit assessments related to this issue.
Sales Tax Contingencies. Some of our sales tax computations are subject to challenge under audit. As of June 30, 2009 and December 31, 2008, we have $13 million accrued in current and long-term liabilities relating to these contingencies.

 

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Refund Contingency Related to Transportation Rates. In September 2008, Kern River Gas Transmission Company (Kern), a natural gas pipeline company, and certain of its shippers entered into a settlement agreement to which we were a party. The agreement set Kern’s transportation rates as of November 2004 at 12.5% return on equity, which resulted in a refund to us of $30 million during the fourth quarter of 2008 (recorded as a current liability). In January 2009, FERC rejected the settlement and directed Kern to recalculate the refunds based on a rate of 11.55% return on equity. Accordingly, we expect to receive an additional approximately $4 million in 2009. If the settlement is appealed, that amount may be subject to adjustment on resolution of the appeal.
(12) Supplemental Guarantor Information
Our wholly-owned subsidiaries are either (a) full and unconditional guarantors, jointly and severally, or (b) non-guarantors of the senior secured notes.

 

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Condensed Consolidating Statements of Operations.
                                         
    Three Months Ended June 30, 2009  
    RRI Energy     Guarantors     Non-Guarantors     Adjustments (1)     Consolidated  
    (in millions)  
 
                                       
Revenues
  $     $ 385     $ 186     $ (181 )   $ 390  
 
                             
Cost of sales
          318       142       (179 )     281  
Operation and maintenance
          47       112       (2 )     157  
General and administrative
          1       27             28  
Gains on sales of assets and emission and exchange allowances, net
          (2 )                 (2 )
Depreciation and amortization
          32       35             67  
 
                             
Total
          396       316       (181 )     531  
 
                             
Operating loss
          (11 )     (130 )           (141 )
 
                             
Loss of equity investment, net
          (1 )                 (1 )
Loss of equity investments of consolidated subsidiaries
    (70 )     (37 )           107        
Debt extinguishments gain
    1                         1  
Interest expense
    (36 )     (7 )     (2 )           (45 )
Interest income
    1                         1  
Interest income (expense) — affiliated companies, net
    18       (3 )     (15 )            
 
                             
Total other expense
    (86 )     (48 )     (17 )     107       (44 )
 
                             
Loss from continuing operations before income taxes
    (86 )     (59 )     (147 )     107       (185 )
Income tax benefit
    (18 )     (11 )     (54 )     1       (82 )
 
                             
Loss from continuing operations
    (68 )     (48 )     (93 )     106       (103 )
Income (loss) from discontinued operations
    871       (2 )     37             906  
 
                             
Net income (loss)
  $ 803     $ (50 )   $ (56 )   $ 106     $ 803  
 
                             
                                         
    Three Months Ended June 30, 2008  
    RRI Energy     Guarantors     Non-Guarantors     Adjustments (1)     Consolidated  
    (in millions)  
 
                                       
Revenues
  $     $ 990     $ 415     $ (391 )   $ 1,014  
 
                             
Cost of sales
          825       132       (388 )     569  
Operation and maintenance
          51       116       (2 )     165  
General and administrative
          6       28       (1 )     33  
Gains on sales of assets and emission and exchange allowances, net
          (20 )     (2 )           (22 )
Depreciation and amortization
          33       50             83  
 
                             
Total
          895       324       (391 )     828  
 
                             
Operating income
          95       91             186  
 
                             
Income of equity investment, net
          1                   1  
Income of equity investments of consolidated subsidiaries
    353       35             (388 )      
Interest expense
    (38 )     (7 )     (6 )           (51 )
Interest income
    4       4                   8  
Interest income (expense) — affiliated companies, net
    44       (28 )     (16 )            
 
                             
Total other income (expense)
    363       5       (22 )     (388 )     (42 )
 
                             
Income from continuing operations before income taxes
    363       100       69       (388 )     144  
Income tax expense
    4       27       28       3       62  
 
                             
Income from continuing operations
    359       73       41       (391 )     82  
Income (loss) from discontinued operations
          (15 )     291       1       277  
 
                             
Net income
  $ 359     $ 58     $ 332     $ (390 )   $ 359  
 
                             

 

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    Six Months Ended June 30, 2009  
    RRI Energy     Guarantors     Non-Guarantors     Adjustments (1)     Consolidated  
    (in millions)  
 
                                       
Revenues
  $     $ 836     $ 443     $ (423 )   $ 856  
 
                             
Cost of sales
          660       365       (420 )     605  
Operation and maintenance
          109       208       (3 )     314  
General and administrative
          4       53             57  
Gains on sales of assets and emission and exchange allowances, net
          (17 )     (3 )           (20 )
Depreciation and amortization
          64       71             135  
 
                             
Total
          820       694       (423 )     1,091  
 
                             
Operating income (loss)
          16       (251 )           (235 )
 
                             
Loss of equity investments of consolidated subsidiaries
    (177 )     (59 )           236        
Debt extinguishments gain
    1                         1  
Interest expense
    (74 )     (14 )     (4 )           (92 )
Interest income
    1                         1  
Interest income (expense) — affiliated companies, net
    35       (6 )     (29 )            
 
                             
Total other expense
    (214 )     (79 )     (33 )     236       (90 )
 
                             
Loss from continuing operations before income taxes
    (214 )     (63 )     (284 )     236       (325 )
Income tax benefit
    (11 )     (2 )     (106 )     3       (116 )
 
                             
Loss from continuing operations
    (203 )     (61 )     (178 )     233       (209 )
Income (loss) from discontinued operations
    855       7       (1 )           861  
 
                             
Net income (loss)
  $ 652     $ (54 )   $ (179 )   $ 233     $ 652  
 
                             
                                         
    Six Months Ended June 30, 2008  
    RRI Energy     Guarantors     Non-Guarantors     Adjustments (1)     Consolidated  
    (in millions)  
 
                                       
Revenues
  $     $ 1,851     $ 832     $ (789 )   $ 1,894  
 
                             
Cost of sales
          1,597       266       (785 )     1,078  
Operation and maintenance
          112       211       (2 )     321  
General and administrative
          13       51       (2 )     62  
Western states litigation and similar settlements
    34                         34  
Gains on sales of assets and emission and exchange allowances, net
          (21 )     (2 )           (23 )
Depreciation and amortization
          69       97             166  
 
                             
Total
    34       1,770       623       (789 )     1,638  
 
                             
Operating income (loss)
    (34 )     81       209             256  
 
                             
Income of equity investment, net
          1                   1  
Income of equity investments of consolidated subsidiaries
    739       79             (818 )      
Debt extinguishment loss
    (1 )                       (1 )
Interest expense
    (76 )     (14 )     (12 )           (102 )
Interest income
    10       4                   14  
Interest income (expense) — affiliated companies, net
    98       (65 )     (33 )            
 
                             
Total other income (expense)
    770       5       (45 )     (818 )     (88 )
 
                             
Income from continuing operations before income taxes
    736       86       164       (818 )     168  
Income tax expense (benefit)
    (1 )     8       66             73  
 
                             
Income from continuing operations
    737       78       98       (818 )     95  
Income (loss) from discontinued operations
    (1 )     (16 )     661       (3 )     641  
 
                             
Net income
  $ 736     $ 62     $ 759     $ (821 )   $ 736  
 
                             
 
     
(1)   These amounts relate to either (a) eliminations and adjustments recorded in the normal consolidation process or (b) reclassifications recorded due to differences in classifications at the subsidiary levels compared to the consolidated level.

 

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Condensed Consolidating Balance Sheets.
                                         
    June 30, 2009  
    RRI Energy     Guarantors     Non-Guarantors     Adjustments (1)     Consolidated  
    (in millions)  
 
                                       
ASSETS
                                       
Current Assets:
                                       
Cash and cash equivalents
  $ 1,477     $ 1     $ 9     $     $ 1,487  
Restricted cash
                3             3  
Accounts and notes receivable, principally customer
    8       110       17       (8 )     127  
Accounts and notes receivable — affiliated companies
    983       310       148       (1,441 )      
Inventory
          141       163             304  
Derivative assets
          123       34             157  
Investment in and receivables from Channelview, net
    1       24                   25  
Other current assets
    72       34       97       (81 )     122  
Current assets of discontinued operations
    135       262       5       (130 )     272  
 
                             
Total current assets
    2,676       1,005       476       (1,660 )     2,497  
 
                             
Property, Plant and Equipment, net
          2,304       2,484             4,788  
 
                             
Other Assets:
                                       
Other intangibles, net
          114       260             374  
Notes receivable — affiliated companies
    2,383       604       1       (2,988 )      
Equity investments of consolidated subsidiaries
    1,787       273             (2,060 )      
Derivative assets
          61       23             84  
Other long-term assets
    42       800       348       (687 )     503  
Long-term assets of discontinued operations
          25       1             26  
 
                             
Total other assets
    4,212       1,877       633       (5,735 )     987  
 
                             
Total Assets
  $ 6,888     $ 5,186     $ 3,593     $ (7,395 )   $ 8,272  
 
                             
 
                                       
LIABILITIES AND EQUITY
                                       
Current Liabilities:
                                       
Current portion of long-term debt and short-term borrowings
  $     $     $ 411     $     $ 411  
Accounts payable, principally trade
          22       117       (2 )     137  
Accounts and notes payable — affiliated companies
          1,117       324       (1,441 )      
Derivative liabilities
          62       173             235  
Other current liabilities
    79       244       35       (123 )     235  
Current liabilities of discontinued operations
    48       258       11       (130 )     187  
 
                             
Total current liabilities
    127       1,703       1,071       (1,696 )     1,205  
 
                             
Other Liabilities:
                                       
Notes payable — affiliated companies
          2,227       761       (2,988 )      
Derivative liabilities
          19       96             115  
Other long-term liabilities
    549       147       257       (648 )     305  
Long-term liabilities of discontinued operations
    3       23       4             30  
 
                             
Total other liabilities
    552       2,416       1,118       (3,636 )     450  
 
                             
Long-term Debt
    1,753       408                   2,161  
 
                             
Commitments and Contingencies
                                       
Temporary Equity Stock-based Compensation
    5                         5  
 
                             
Total Stockholders’ Equity
    4,451       659       1,404       (2,063 )     4,451  
 
                             
Total Liabilities and Equity
  $ 6,888     $ 5,186     $ 3,593     $ (7,395 )   $ 8,272  
 
                             

 

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    December 31, 2008  
    RRI Energy     Guarantors     Non-Guarantors     Adjustments (1)     Consolidated  
    (in millions)  
 
                                       
ASSETS
                                       
Current Assets:
                                       
Cash and cash equivalents
  $ 970     $     $ 34     $     $ 1,004  
Restricted cash
          1       2             3  
Accounts and notes receivable, principally customer
    15       216       33       (14 )     250  
Accounts and notes receivable — affiliated companies
    1,100       268       183       (1,551 )      
Inventory
          153       162             315  
Derivative assets
          127       34             161  
Investment in and receivables from Channelview, net
    1       58                   59  
Other current assets
    5       56       126       (30 )     157  
Current assets of discontinued operations
    272       211       2,661       (638 )     2,506  
 
                             
Total current assets
    2,363       1,090       3,235       (2,233 )     4,455  
 
                             
Property, Plant and Equipment, net
          2,369       2,451             4,820  
 
                             
Other Assets:
                                       
Other intangibles, net
          150       264       (34 )     380  
Notes receivable — affiliated companies
    2,260       578       54       (2,892 )      
Equity investments of consolidated subsidiaries
    1,731       332             (2,063 )      
Derivative assets
          37       42             79  
Other long-term assets
    45       749       344       (645 )     493  
Long-term assets of discontinued operations
    2       12       686       (205 )     495  
 
                             
Total other assets
    4,038       1,858       1,390       (5,839 )     1,447  
 
                             
Total Assets
  $ 6,401     $ 5,317     $ 7,076     $ (8,072 )   $ 10,722  
 
                             
 
                                       
LIABILITIES AND EQUITY
                                       
Current Liabilities:
                                       
Current portion of long-term debt and short-term borrowings
  $     $     $ 13     $     $ 13  
Accounts payable, principally trade
          31       132       (6 )     157  
Accounts and notes payable — affiliated companies
          1,307       244       (1,551 )      
Derivative liabilities
          29       173             202  
Other current liabilities
    10       306       47       (72 )     291  
Current liabilities of discontinued operations
    61       147       2,805       (637 )     2,376  
 
                             
Total current liabilities
    71       1,820       3,414       (2,266 )     3,039  
 
                             
Other Liabilities:
                                       
Notes payable — affiliated companies
          2,132       760       (2,892 )      
Derivative liabilities
          4       137             141  
Other long-term liabilities
    547       119       251       (645 )     272  
Long-term liabilities of discontinued operations
    198       103       778       (206 )     873  
 
                             
Total other liabilities
    745       2,358       1,926       (3,743 )     1,286  
 
                             
Long-term Debt
    1,798       408       404             2,610  
 
                             
Commitments and Contingencies
                                       
Temporary Equity Stock-based Compensation
    9                         9  
 
                             
Total Stockholders’ Equity
    3,778       731       1,332       (2,063 )     3,778  
 
                             
Total Liabilities and Equity
  $ 6,401     $ 5,317     $ 7,076     $ (8,072 )   $ 10,722  
 
                             
 
     
(1)   These amounts relate to either (a) eliminations and adjustments recorded in the normal consolidation process or (b) reclassifications recorded due to differences in classifications at the subsidiary levels compared to the consolidated level.

 

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Condensed Consolidating Statements of Cash Flows.
                                         
    Six Months Ended June 30, 2009  
    RRI Energy     Guarantors     Non-Guarantors     Adjustments(1)     Consolidated  
    (in millions)  
 
                                       
Cash Flows from Operating Activities:
                                       
Net cash provided by (used in) continuing operations from operating activities
  $ (75 )   $ 88     $ (109 )   $     $ (96 )
Net cash provided by discontinued operations from operating activities
    135       22       351             508  
 
                             
Net cash provided by operating activities
    60       110       242             412  
 
                             
Cash Flows from Investing Activities:
                                       
Capital expenditures
          (11 )     (104 )           (115 )
Investments in, advances to and from and distributions from subsidiaries, net(2)
    (64 )                 64        
Proceeds from sales of assets, net
          36                   36  
Proceeds from sales (purchases) of emission allowances
          46       (32 )           14  
Other, net
          1                   1  
 
                             
Net cash provided by (used in) continuing operations from investing activities
    (64 )     72       (136 )     64       (64 )
Net cash provided by (used in) discontinued operations from investing activities
    701       4       (418 )     12       299  
 
                             
Net cash provided by (used in) investing activities
    637       76       (554 )     76       235  
 
                             
Cash Flows from Financing Activities:
                                       
Payments of long-term debt
    (45 )                       (45 )
Changes in notes with affiliated companies, net(3)
          (122 )     186       (64 )      
Proceeds from issuances of stock
    2                         2  
 
                             
Net cash provided by (used in) continuing operations from financing activities
    (43 )     (122 )     186       (64 )     (43 )
Net cash used in discontinued operations from financing activities
    (147 )     (63 )     (3 )     (12 )     (225 )
 
                             
Net cash provided by (used in) financing activities
    (190 )     (185 )     183       (76 )     (268 )
 
                             
Net Change in Cash and Cash Equivalents, Total Operations
    507       1       (129 )           379  
Less: Net Change in Cash and Cash Equivalents, Discontinued Operations
                (104 )           (104 )
Cash and Cash Equivalents at Beginning of Period, Continuing Operations
    970             34             1,004  
 
                             
Cash and Cash Equivalents at End of Period, Continuing Operations
  $ 1,477     $ 1     $ 9     $     $ 1,487  
 
                             

 

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    Six Months Ended June 30, 2008  
    RRI Energy     Guarantors     Non-Guarantors     Adjustments(1)     Consolidated  
    (in millions)  
 
                                       
Cash Flows from Operating Activities:
                                       
Net cash provided by (used in) continuing operations from operating activities
  $ 43     $ (172 )   $ 217     $     $ 88  
Net cash provided by (used in) discontinued operations from operating activities
    (4 )     39       68             103  
 
                             
Net cash provided by (used in) operating activities
    39       (133 )     285             191  
 
                             
Cash Flows from Investing Activities:
                                       
Capital expenditures
          (13 )     (90 )           (103 )
Investments in, advances to and from and distributions from subsidiaries, net(2)
    (40 )     8       (8 )     40        
Proceeds from sales (purchases) of emission allowances
          59       (48 )           11  
Restricted cash
                (4 )           (4 )
Other, net
          1                   1  
 
                             
Net cash provided by (used in) continuing operations from investing activities
    (40 )     55       (150 )     40       (95 )
Net cash provided by (used in) discontinued operations from investing activities
    70             (89 )     5       (14 )
 
                             
Net cash provided by (used in) investing activities
    30       55       (239 )     45       (109 )
 
                             
Cash Flows from Financing Activities:
                                       
Payments of long-term debt
    (45 )                       (45 )
Changes in notes with affiliated companies, net(3)
          94       (54 )     (40 )      
Proceeds from issuances of stock
    6                         6  
 
                             
Net cash provided by (used in) continuing operations from financing activities
    (39 )     94       (54 )     (40 )     (39 )
Net cash provided by (used in) discontinued operations from financing activities
          (17 )     22       (5 )      
 
                             
Net cash provided by (used in) financing activities
    (39 )     77       (32 )     (45 )     (39 )
 
                             
Net Change in Cash and Cash Equivalents, Total Operations
    30       (1 )     14             43  
Less: Net Change in Cash and Cash Equivalents, Discontinued Operations
                             
Cash and Cash Equivalents at Beginning of Period, Continuing Operations
    490       1       33             524  
 
                             
Cash and Cash Equivalents at End of Period, Continuing Operations
  $ 520     $     $ 47     $     $ 567  
 
                             
 
     
(1)   These amounts relate to either (a) eliminations and adjustments recorded in the normal consolidation process or (b) reclassifications recorded due to differences in classifications at the subsidiary levels compared to the consolidated level.
 
(2)   Net investments in, advances to and from and distributions from subsidiaries are classified as investing activities.
 
(3)   Net changes in notes with affiliated companies are classified as financing activities for subsidiaries of RRI Energy and as investing activities for RRI Energy.

 

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(13) Reportable Segment
Financial data for our wholesale energy segment, other operations, discontinued operations and consolidated are as follows:
                                         
    Wholesale     Other     Discontinued              
    Energy     Operations     Operations     Eliminations     Consolidated  
    (in millions)  
 
                                       
Three months ended
June 30, 2009:
                                       
Revenues from external customers
  $ 389 (1)   $ 1     $     $     $ 390  
Contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives(2)
    (48 )(3) (4)                       (48 )(3)
 
                                       
Three months ended
June 30, 2008:
                                       
Revenues from external customers
  $ 1,014 (5)   $     $     $     $ 1,014  
Intersegment revenues
          1             (1 )      
Contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives(2)
    279 (6) (7)     1             (1 )     279 (6)
 
                                       
Six months ended
June 30, 2009 (except as denoted):
                                       
Revenues from external customers
  $ 854 (8)   $ 2     $     $     $ 856  
Intersegment revenues
          1             (1 )      
Contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives(2)
    (63 )(9) (10)     2             (1 )     (62 )(9)
Total assets as of June 30, 2009
    7,152       862       298       (40 )     8,272  
 
                                       
Six months ended
June 30, 2008 (except as denoted):
                                       
Revenues from external customers
  $ 1,893 (11)   $ 1     $     $     $ 1,894  
Intersegment revenues
          2             (2 )      
Contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives(2)
    496 (12) (13)     2             (2 )     496 (12)
Total assets as of December 31, 2008
    7,458       397       3,001       (134 )     10,722  
 
     
(1)   Includes $44 million in revenues from a single counterparty, which represented 11% of our consolidated and wholesale energy segment’s revenues. As of June 30, 2009, $4 million was outstanding from this counterparty.
 
(2)   Revenues less (a) cost of sales, (b) operation and maintenance and (c) bad debt expense.
 
(3)   Includes $7 million in wholesale energy and consolidated results relating to unrealized gains on energy derivatives, which is a non-cash item.
 
(4)   Includes $(70) million relating to wholesale hedges.
 
(5)   Includes $146 million from affiliates.
 
(6)   Includes $68 million in wholesale energy and consolidated results relating to unrealized gains on energy derivatives, which is a non-cash item.
 
(7)   Includes $44 million relating to wholesale hedges.
 
(8)   Includes $99 million in revenues from a single counterparty, which represented 12% of our consolidated and wholesale energy segment’s revenues.
 
(9)   Includes $(37) million in wholesale energy and consolidated results relating to unrealized losses on energy derivatives, which is a non-cash item.
 
(10)   Includes $(74) million relating to wholesale hedges.
 
(11)   Includes $253 million from affiliates.
 
(12)   Includes $98 million in wholesale energy and consolidated results relating to unrealized gains on energy derivatives, which is a non-cash item.
 
(13)   Includes $79 million relating to wholesale hedges.

 

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    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
    (in millions)  
 
                               
Contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives
  $ (48 )   $ 279     $ (62 )   $ 496  
Operation and maintenance
          (1 )     1       2  
General and administrative
    28       33       57       61  
Western states litigation and similar settlements
                      34  
Gains on sales of assets and emission allowances, net
    (2 )     (22 )     (20 )     (23 )
Depreciation
    60       63       119       125  
Amortization
    7       20       16       41  
 
                       
Operating income (loss)
    (141 )     186       (235 )     256  
Income (loss) of equity investment, net
    (1 )     1             1  
Debt extinguishments gains (losses)
    1             1       (1 )
Interest expense
    (45 )     (51 )     (92 )     (102 )
Interest income
    1       8       1       14  
 
                       
Income (loss) from continuing operations before income taxes
    (185 )     144       (325 )     168  
Income tax expense (benefit)
    (82 )     62       (116 )     73  
 
                       
Income (loss) from continuing operations
    (103 )     82       (209 )     95  
Income from discontinued operations
    906       277       861       641  
 
                       
Net income
  $ 803     $ 359     $ 652     $ 736  
 
                       
(14) Sale of Channelview’s Plant and the Bankruptcy Filings
On August 20, 2007, Channelview filed voluntary petitions in the United States Bankruptcy Court for the District of Delaware for reorganization under Chapter 11 of the Bankruptcy Code. Channelview filed for bankruptcy protection to prevent the lenders from exercising their remedies, including foreclosing on the project. The bankruptcy cases have been jointly administered, with Channelview managing its business in the ordinary course as debtors-in-possession subject to the supervision of the bankruptcy court.
In July 2008, Channelview sold its plant and related contracts for $500 million and paid off its secured lenders. During 2008, we recognized a $6 million gain relating to our net investment in and receivables from Channelview and incurrence of sale-related costs (classified in gains (losses) on sales of assets and emission and exchange allowances, net). As of June 30, 2009 and December 31, 2008, our net investment in and receivables from Channelview was $25 million and $59 million, respectively, classified as a current asset.
Channelview expects to distribute funds to us relating primarily to net proceeds from the sale, pre-petition sales of fuel to Channelview, funds from operations and funds escrowed for potential indemnification claims of approximately $60 million to $70 million in the aggregate through 2009. Of this amount, $25 million was distributed to us during 2008 and $35 million was distributed to us during the second quarter of 2009.
As a result of the bankruptcies, we deconsolidated Channelview’s financial results beginning August 20, 2007, and began reporting our investment in Channelview using the cost method. We will continue to account for Channelview as a cost method investment until it emerges from bankruptcy, which is expected later in 2009. The following table describes the assets we expect to consolidate upon the emergence from bankruptcy of Channelview:
         
    June 30, 2009  
    (in millions)  
 
       
Cash
  $ 7  
Deferred tax assets relating to federal and state net operating loss carryforwards
    18  

 

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(15) Discontinued Operations
(a) Retail Energy Segment.
General. On May 1, 2009, we sold our Texas retail business to a subsidiary (the buyer) of NRG Energy, Inc. (NRG) for $287.5 million in cash plus the value of the net working capital. We currently estimate the net working capital to be $78 million. We estimate our net proceeds will be $312 million after certain expenses. In connection with the sale, we received net proceeds of $297 million during primarily the second quarter of 2009 and expect to receive an additional $15 million later in 2009. This sale also included the rights to the Reliant Energy name. Accordingly, we changed our name to RRI Energy, Inc. on May 2, 2009. In connection with the sale, the lawsuit against our former retail affiliates related to the termination of the retail working capital facility has been dismissed. See note 11(b).
In connection with the sale transaction, we entered into a two-year sublease on our corporate office building with the buyer, with sublease rental income totaling $17 million over that period. We also entered a one-year transition services agreement with the buyer, which includes terms and conditions for information technology services, accounting services and human resources.
Estimated Pre-Tax Gain on Sale. We currently estimate and recognized a pre-tax gain on this sale of $1.2 billion, which is primarily due to the net derivative liability balance of $1.1 billion included in the transaction. This amount is subject to change due to various factors, such as the estimated net working capital.
Federal Valuation Allowance. As a result of the sale, we released $50 million of our discontinued federal valuation allowance for deferred tax assets in discontinued operations during the three months ended June 30, 2009.
Use of Proceeds and Assumptions Related to Debt, Deferred Financing Costs and Interest Expense on Discontinued Operations. As required by our debt agreements, offers to purchase secured notes and PEDFA bonds at par were made with a portion of the net proceeds. We purchased $225 million of the outstanding debt ($147 million of the secured notes and $78 million of the PEDFA bonds) in June 2009 and an additional $36 million ($22 million of the secured notes and $14 million of PEDFA bonds) in July 2009. These amounts and activity have been classified in discontinued operations. See note 7. We have also classified as discontinued operations the related deferred financing costs and interest expense on this debt. We allocated $4 million of related interest expense during the three months ended June 30, 2009 and 2008 to discontinued operations. We allocated $8 million of related interest expense during the six months ended June 30, 2009 and 2008 to discontinued operations.
Other Retail Energy Segment Discontinued Operations. We sold our C&I contracts in the PJM (excluding Illinois) and New York areas (collectively, Northeast) in December 2008. As this was a part of our retail energy segment, we have included this activity in our discontinued operations. We have also included our Illinois C&I activity in discontinued operations as it was a part of our retail energy segment and is held-for-sale.
(b) Other Discontinued Operations.
Subsequent to the sale of our New York plants in February 2006, we continue to have (a) insignificant settlements with the independent system operator and (b) property tax and sales and use tax settlements. In addition, we periodically record amounts for contingent consideration received for the 2003 sale of our European energy operations. These amounts are classified as discontinued operations in our results of operations and balance sheets, as applicable.

 

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(c) All Discontinued Operations.
The following summarizes certain financial information of the businesses reported as discontinued operations:
                                 
    Retail Energy     New York              
    Segment     Plants     European Energy     Total  
    (in millions)  
 
                               
Three Months Ended June 30, 2009
                               
Revenues
  $ 499 (1)   $     $     $ 499  
Income before income tax expense/benefit
    1,314 (2)(3)           9       1,323  
 
                               
Three Months Ended June 30, 2008
                               
Revenues
  $ 2,410 (4)   $     $     $ 2,410  
Income (loss) before income tax expense/benefit
    438 (5)     (3 )     1       436  
 
                               
Six Months Ended June 30, 2009
                               
Revenues
  $ 2,014 (6)   $ 2     $     $ 2,016  
Income before income tax expense/benefit
    1,257 (3)(7)     3       9       1,269  
 
                               
Six Months Ended June 30, 2008
                               
Revenues
  $ 4,346 (8)   $     $     $ 4,346  
Income (loss) before income tax expense/benefit
    1,014 (9)     (3 )     7       1,018  
 
     
(1)   Includes $13 million related to our Illinois C&I activity.
 
(2)   Includes $35 million of unrealized gains on energy derivatives.
 
(3)   Includes $1.2 billion gain on sale (of which $1.1 billion relates to derivatives).
 
(4)   Includes $14 million related to our Illinois C&I activity.
 
(5)   Includes $502 million of unrealized gains on energy derivatives.
 
(6)   Includes $38 million related to our Illinois C&I activity.
 
(7)   Includes $189 million of unrealized losses on energy derivatives.
 
(8)   Includes $20 million related to our Illinois C&I activity.
 
(9)   Includes $1.0 billion of unrealized gains on energy derivatives.

 

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The following summarizes the assets and liabilities related to our discontinued operations:
                 
    June 30,     December 31,  
    2009     2008  
    (in millions)  
 
               
Current Assets:
               
Cash and cash equivalents
  $ 2     $ 105  
Accounts receivable, principally customer, net
    31       870  
Derivative assets
    86       1,010  
Margin deposits
    152       295  
Accumulated deferred income taxes
          217  
Other current assets
    1       9  
 
           
Total current assets
    272       2,506  
Property, Plant and Equipment, net
          57  
Other Assets:
               
Goodwill and other intangibles, net
          59  
Derivative assets
    14       324  
Accumulated deferred income taxes
    11       48  
Other
    1       7  
 
           
Total long-term assets
    26       495  
 
           
Total Assets
  $ 298     $ 3,001  
 
           
 
               
Current Liabilities:
               
Current portion of long-term debt
  $ 36     $  
Accounts payable, principally trade
    1       480  
Derivative liabilities
    94       1,637  
Margin deposits
    42        
Other current liabilities
    14       259  
 
           
Total current liabilities
    187       2,376  
Other Liabilities:
               
Derivative liabilities
    21       612  
Other liabilities
    9        
 
           
Total other liabilities
    30       612  
Long-term Debt
          261  
 
           
Total long-term liabilities
    30       873  
 
           
Total Liabilities
  $ 217     $ 3,249  
 
           

 

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ITEM 2.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with our Form 10-K. This includes non-GAAP financial measures, which are not standardized; therefore it may not be possible to compare these financial measures with other companies’ non-GAAP financial measures having the same or similar names. These non-GAAP financial measures, which are discussed further in “— Consolidated Results of Operations,” reflect an additional way of viewing aspects of our operations that, when viewed with our GAAP results, may provide a more complete understanding of factors and trends affecting our business. Investors should review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.
Business Overview
We provide electricity and energy services to wholesale customers in competitive power generation energy markets in the United States through our ownership and operation of and contracting for power generation capacity. We have over 14,000 MW of power generation capacity.
We believe the power generation industry is deeply cyclical and capital intensive. Given the nature of the industry, we believe scale and diversity are important long term. Given these beliefs, our strategy is to:
    Maintain a capital structure that positions us to manage through the cycles
    Intensely focus on operational excellence
    Employ a flexible operating model through the cycle
    Utilize a disciplined capital investment approach
    Create value from industry consolidation
The current market environment is challenging given the ongoing turmoil in the financial markets, uncertainty in the direction of the overall economy and declining power demand. Additionally, current commodity prices and spreads are near trough levels. While we believe these conditions will improve, the timing is uncertain.
We have taken a number of actions to navigate the current market challenges and position us for the longer term market recovery, with a focus on maximizing cash flow and building ample liquidity. Some of these actions include:
    Selling the Texas retail business
    Implementing a modest hedging program to achieve a high probability of achieving free cash flow breakeven or better even if market conditions deteriorate further
    Intensely focusing on operating efficiency and effectiveness
    Implementing flexible plant-specific operating models
    Realigning corporate support costs
We are regularly assessing the impact on our business of a wide variety of economic and commodity price scenarios, and believe we have the ability to operate through a significant downturn.
Key Earnings Drivers. Our earnings are significantly impacted by supply and demand fundamentals in the regions in which we operate as well as the spread between gas and coal prices. Our margins are driven by a number of factors, including the prices of power, capacity, natural gas, coal and fuel oil, the cost of emissions and transmission, as well as weather and global macro-economic factors, many of which are volatile. Our ability to control these factors is limited, and in most instances, the factors are beyond our control. We have the most control over the percentage of time that our generating assets are available to run when it is economical for them to do so (commercial capacity factor). Our key earnings drivers and various factors that affect these earnings drivers include:
Economic generation (amount of time our plants are economical to operate)
    Supply and demand fundamentals
    Generation asset fuel type and efficiency
    Absolute and relative cost of fuels used in power generation
Commercial capacity factor (generation as a percentage of economic generation)
    Operations excellence — effectiveness
    Maintenance practices
    Planned and unplanned outages

 

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Unit margin
    Supply and demand fundamentals
    Commodity prices and spreads
    Generation asset fuel type and efficiency
Other margin
    Capacity prices and payments
    Power purchase agreements sold to others
    Ancillary services
    Equipment performance
Costs
    Operating efficiency
    Maintenance practices
    Generation asset fuel type
    Planned and unplanned outages
Hedges
    Hedging strategy
    Volumes
    Commodity prices
    Effectiveness
Flexible Plant-Specific Operating Model. We have different operating approaches for our power generation facilities. These operating approaches are determined by each facility’s condition, environmental controls, profitability, market rules, upside availability and value drivers. We have separated our facilities into four general groups for the purposes of developing an operating model.
    Long-term value — This part of our fleet is well positioned to generate revenue for the forseeable future, and we would expect that little environmental investments will be needed in future years. We plan to invest and manage these plants, representing approximately 2,500 MW, for current and long-term profitability for both capacity and energy revenues.
    Long-term capacity resource — These plants, representing approximately 4,400 MW, are also well positioned to generate revenue for the forseeable future, and we expect little future environmental investment. We plan to invest in this part of our fleet for long-term profitability from capacity and/or power purchase and sale agreements.
    Near-term profit/controls — These plants, representing approximately 5,400 MW, are well positioned to generate revenue in the current environment but do not have S02, NOx or mercury emission controls. We expect to maintain near-term profitability and preserve the option for supply/demand recovery and/or improved gas-coal spreads in this group of plants. We may install emission controls in the future depending on environmental regulations and market conditions. See “—Recent Events.”
    Restore profit — This part of our fleet, representing approximately 1,600 MW, faces lower levels of profitability in the current environment. We will minimize spending, improve profitability and preserve our options for supply/demand recovery and/or improved gas-coal spreads in these plants.

 

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Recent Events
In this section, we present recent and potential events that have impacted or could in the future impact our results of operations, financial condition or liquidity. In addition to the events described below, a number of other factors could affect our future results of operations, financial condition or liquidity, including changes in natural gas prices, plant availability, weather and other factors (see “Risk Factors” in Item 1A of our Form 10-K).
Review of Strategic Alternatives Lead to Exit of Retail Business. In October 2008, our Board of Directors initiated a process to review strategic alternatives and formed a special committee to oversee this process. In late 2008, we sold our Northeast retail C&I contracts. On May 1, 2009, we sold our Texas retail business. The sale of the retail business achieved a number of important strategic objectives for us:
    eliminated the need for approximately $2.0 billion of credit support and removed capital requirements associated with contingent collateral requirements, which lowered our overall risk profile; and
    enhanced our consolidated balance sheet and improved our liquidity position.
In connection with the sale, the lawsuit related to the termination of the retail working capital facility has been dismissed. Our Board of Directors has concluded its review of strategic alternatives. See “— Liquidity and Capital Resources” and notes 11(b) and 15 to our interim financial statements.
Environmental Matters- Near-term profit/controls group. In April 2009, the New Jersey Department of Environmental Protection finalized a regulation requiring a two-phase reduction in NOx emissions from industrial sources, including combustion turbines in New Jersey. Phase I requires reductions during high electricity demand days and runs from May 2009 through 2014. Under our initial filed compliance plan, we are installing improved NOx controls at one of our Pennsylvania facilities (upwind from New Jersey) and modifying dispatch practices as necessary at our New Jersey facilities by October 2009. Phase II requires the installation of emission controls on nearly all of our New Jersey combustion turbines by May 1, 2015. If we elect to install these controls, we could incur capital expenditures of up to approximately $157 million primarily during 2013 to 2015. Our initial Phase II control plan must be filed by May 1, 2010.
The Pennsylvania mercury rule generally requires mercury reductions on a facility basis in two phases, with 80% reductions by 2010 and 90% reductions by 2015. In January 2009, following a court decision overturning the less-stringent federal mercury rule, a Pennsylvania state court declared the Pennsylvania rule unlawful. The Pennsylvania Department of Environmental Protection appealed to the Pennsylvania Supreme Court, which held in June 2009 that the state rule would continue to be invalid throughout the appeal. Our capital investment plan was based on compliance with the state rule and our estimate of capital expenditures to comply primarily with the first phase of the rule was $53 million. In light of the Pennsylvania Supreme Court ruling, we have suspended work on mercury-specific control installations, except at our Shawville facility. We are continuing to evaluate our plan given that regulation of mercury at both federal and state levels is uncertain.
As we reported in our Form 10-K, the EPA is required to modify the Clean Air Act (CAIR) to cure defects in the rule identified by the District of Columbia Circuit Court of Appeals. We do not expect CAIR to be finalized until 2012 or 2013. Any spending for SO2 or NOx would occur over several years following finalization of these rules and would depend on market conditions.
For a discussion of other existing environmental regulations impacting our fleet, see “Business — Regulation — Environmental Matters” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Items 1 and 7, respectively, of our Form 10-K. For a discussion of pending and contingent matters related to environmental regulations, see note 11(c) to our interim financial statements.

 

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Consolidated Results of Operations
Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008
We reported $803 million consolidated net income, or $2.29 income per share, for the three months ended June 30, 2009 compared to $359 million consolidated net income, or $1.01 income per diluted share, for the same period in 2008. We reported $103 million consolidated net loss from continuing operations, or $0.30 loss per share, for the three months ended June 30, 2009 compared to $82 million consolidated net income from continuing operations, or $0.23 income per diluted share, for the same period in 2008.
                         
    Three Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Wholesale energy contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives
  $ (48 )   $ 279     $ (327 )
Operation and maintenance(1)
          1       (1 )
General and administrative
    (28 )     (33 )     5  
Gains on sales of assets and emission allowances, net
    2       22       (20 )
Depreciation and amortization
    (67 )     (83 )     16  
Income (loss) of equity investment, net
    (1 )     1       (2 )
Debt extinguishments gains
    1             1  
Interest expense
    (45 )     (51 )     6  
Interest income
    1       8       (7 )
Income tax (expense) benefit
    82       (62 )     144  
 
                 
Income (loss) from continuing operations
    (103 )     82       (185 )
Income from discontinued operations
    906       277       629  
 
                 
Net income
  $ 803     $ 359     $ 444  
 
                 
 
     
(1)   Relates primarily to general costs, which historically were allocated to our discontinued retail energy segment.
Wholesale Energy Segment.
In analyzing the results of our wholesale energy segment and in communications with investors, analysts, rating agencies, banks and other parties, we use the non-GAAP financial measures “open energy gross margin,” “open wholesale gross margin” and “open wholesale contribution margin,” which exclude the items described below, as well as our wholesale energy segment profit and loss measure, “contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives.” Open wholesale contribution margin excludes severance charges incurred due to repositioning the company in connection with the sale of our retail business. Because the level of these costs is not representative of our ongoing business operations, our management believes that excluding these costs is useful in that it provides a more meaningful representation of our results of operations on an ongoing basis. Open energy gross margin, open wholesale gross margin and open wholesale contribution margin should not be relied upon without considering the GAAP financial measures.
Wholesale Hedges. We exclude the recurring effect of certain wholesale hedges that were entered into primarily to mitigate (a) certain operational and market risks at our generation assets and (b) some of the downside risk to our earnings and cash flow. These amounts primarily relate to settlements of power and fuel hedges, long-term natural gas transportation contracts and storage contracts. The wholesale hedges described above are derived based on methodology consistent with the calculation of open energy gross margin. We also exclude the recurring effect of certain historical wholesale hedges that were entered into in order to hedge the economics of a portion of our wholesale operations. These amounts primarily relate to settlements of forward power hedges, long-term tolling purchases, long-term natural gas transportation contracts not serving our generation assets and our legacy energy trading. We believe that it is useful to us, investors, analysts and others to show our results in the absence of hedges. The impact of these hedges on our financial results is not a function of the operating performance of our generation assets, and excluding the impact better reflects the potential operating performance of our generation assets based on prevailing market conditions.

 

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Unrealized Gains/Losses on Energy Derivatives. We use derivative instruments to manage operational or market constraints and to increase the return on our generation assets. We are required to record in our consolidated statement of operations non-cash gains/losses related to future periods based on current changes in forward commodity prices for derivative instruments receiving mark-to-market accounting treatment. We refer to these gains and losses prior to settlement, as well as ineffectiveness on cash flow hedges, as “unrealized gains/losses on energy derivatives.” In some cases, the underlying transactions being hedged receive accrual accounting treatment, resulting in a mismatch of accounting treatments. Since the application of mark-to-market accounting has the effect of pulling forward into current periods non-cash gains/losses relating to and reversing in future delivery periods, analysis of results of operations from one period to another can be difficult. We believe that excluding these unrealized gains/losses on energy derivatives provides a more meaningful representation of our economic performance in the reporting period and is therefore useful to us, investors, analysts and others in facilitating the analysis of our results of operations from one period to another. These gains/losses are also not a function of the operating performance of our generation assets, and excluding their impact helps isolate the operating performance of our generation assets under prevailing market conditions.
Our wholesale energy segment’s contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives was $(48) million during the three months ended June 30, 2009 compared to $279 million in the same period of 2008. The $327 million decrease was primarily due to (a) $162 million decrease in open wholesale gross margin due to lower spark and dark spreads as a result of lower power prices, (b) $114 million change in wholesale hedges primarily due to $100 million decline on fuel hedges and (c) $61 million net change in unrealized gains/losses on energy derivatives. Our margins are significantly impacted by coal prices and related spreads. See “— Wholesale Energy Margins” below for further explanations.

 

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Wholesale Energy Operational and Financial Data.
                                 
    Three Months Ended June 30,  
    2009     2008  
    GWh     % Economic(1)     GWh     % Economic(1)  
 
                               
Economic Generation(2)(3):
                               
PJM Coal
    4,890.4       68 %     5,316.6       73 %
MISO Coal
    1,263.5       46 %     1,359.3       49 %
PJM/MISO Gas
    509.0       6 %     352.0       5 %
West
    139.4       2 %     308.6       4 %
Other
    63.1       3 %     7.0       1 %
 
                       
Total
    6,865.4       26 %     7,343.5       29 %
 
                       
 
                               
Commercial Capacity Factor(4):
                               
PJM Coal
    73.5 %             83.7 %        
MISO Coal
    85.9 %             90.8 %        
PJM/MISO Gas
    93.9 %             91.6 %        
West
    69.6 %             94.1 %        
Other
    98.7 %             81.4 %        
 
                           
Total
    77.5 %             85.9 %        
 
                           
 
                               
Generation (3):
                               
PJM Coal
    3,596.5               4,452.3          
MISO Coal
    1,085.8               1,233.9          
PJM/MISO Gas
    477.8               322.6          
West
    97.0               290.4          
Other
    62.3               5.7          
 
                           
Total
    5,319.4               6,304.9          
 
                           
 
                               
Open Energy Unit Margin ($/MWh)(5):
                               
PJM Coal
  $ 8.90             $ 40.88          
MISO Coal
    10.13               23.50          
PJM/MISO Gas
    10.46               46.50          
West
    82.47             NM(6)        
 
                           
Total weighted average
  $ 10.53             $ 35.37          
 
                           
 
     
(1)   Represents economic generation (hours) divided by maximum generation hours (maximum plant capacity multiplied by 8,760 hours).
 
(2)   Estimated generation at 100% plant availability based on an hourly analysis of when it is economical to generate based on the price of power, fuel, emission allowances and variable operating costs.
 
(3)   Excludes generation related to power purchase agreements, including tolling agreements.
 
(4)   Generation divided by economic generation.
 
(5)   Represents open energy gross margin divided by generation.
 
(6)   NM is not meaningful.
Wholesale Energy Revenues.
                         
    Three Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
Wholesale energy third-party revenues
  $ 411     $ 862     $ (451 )(1)
Revenues — affiliates
          146 (2)     (146 )
Unrealized gains (losses) on energy derivatives
    (22 )     6       (28 )(3)
 
                 
Total wholesale energy revenues
  $ 389     $ 1,014     $ (625 )
 
                 
 
     
(1)   Decrease primarily due to (a) lower power and natural gas sales prices and (b) lower power sales volumes.
 
(2)   We deconsolidated Channelview on August 20, 2007. These revenues represent sales of fuel to Channelview prior to the assets being sold.
 
(3)   See footnote 10 under “— Wholesale Energy Margins.”

 

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Wholesale Energy Cost of Sales.
                         
    Three Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
Wholesale energy third-party costs
  $ 310     $ 597     $ (287 )(1)
Cost of sales — affiliates
          34 (2)     (34 )
Unrealized gains on energy derivatives
    (29 )     (62 )     33 (3)
 
                 
Total wholesale energy cost of sales
  $ 281     $ 569     $ (288 )
 
                 
 
     
(1)   Decrease primarily due to (a) lower prices paid for natural gas and (b) lower natural gas volumes purchased.
 
(2)   We deconsolidated Channelview on August 20, 2007. These cost of sales represent purchases of power from Channelview prior to the assets being sold.
 
(3)   See footnote 10 under “— Wholesale Energy Margins.”

 

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Wholesale Energy Margins.
                         
    Three Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Open energy gross margin(1):
                       
PJM Coal
  $ 32     $ 182     $ (150 )(2)
MISO Coal
    11       29       (18 )(2)
PJM/MISO Gas
    5       15       (10 )
West
    8       (3 )     11 (3)
Other
                 
 
                 
Total
    56       223       (167 )
 
                       
Other margin(4):
                       
PJM Coal
    38       26       12 (5)
MISO Coal
    3       3        
PJM/MISO Gas
    44       33       11 (6)
West
    17       34       (17 )(7)
Other
    13       14       (1 )
 
                 
Total
    115       110       5  
 
                 
 
                       
Open wholesale gross margin
    171       333       (162 )
 
                 
 
                       
Operation and maintenance, excluding severance
    (153 )     (166 )     13 (8)
Other
                 
 
                 
Open wholesale contribution margin
    18       167       (149 )
Wholesale hedges
    (70 )     44       (114 )(9)
Unrealized gains on energy derivatives
    7       68       (61 )(10)
Operation and maintenance — severance
    (3 )           (3 )
 
                 
Total wholesale energy contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives(11)
  $ (48 )   $ 279     $ (327 )
 
                 
 
     
(1)   Open energy gross margin is calculated using the power sales prices received by the plants less delivered spot fuel prices. This figure excludes the effects of other margin, our wholesale hedges and unrealized gains/losses on energy derivatives.
 
(2)   Decrease primarily due to lower unit margins (lower power prices partially offset by lower fuel costs).
 
(3)   Increase primarily due to higher unit margins (lower fuel expense and higher power prices). This increase was partially offset by a decrease in economic generation.
 
(4)   Other margin represents power purchase agreements, capacity payments, ancillary services revenues and selective commercial hedge strategies.
 
(5)   Increase primarily due to higher RPM capacity payments. This increase was partially offset by lower ancillary payments. RPM is the model utilized by the PJM Interconnection, LLC to meet load serving entities’ forecasted capacity obligations via a forward-looking commitment of capacity resources.
 
(6)   Increase primarily due to higher RPM capacity payments.
 
(7)   Decrease primarily due to reduced selective commercial hedge activities.
 
(8)   Decrease primarily due to (a) $5 million decrease in planned outages and maintenance spending, (b) $5 million decrease in services and support, (c) $4 million decrease from reduced operations activity and (d) $4 million decrease due to the sale of Bighorn in October 2008.
 
(9)   Decrease primarily due to (a) $100 million decline on fuel hedges and (b) $35 million loss on market adjustments to inventory. These decreases were partially offset by (a) $28 million gain on a hedge of generation.
 
(10)   Decrease primarily due to $100 million in losses from changes in prices on our energy derivatives marked to market partially offset by $39 million in gains due to reversal of previously recognized unrealized losses on energy derivatives which settled during the period.
 
(11)   Wholesale energy segment profit and loss measure.

 

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General and Administrative.
                         
    Three Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Salaries and benefits
  $ 15     $ 19     $ (4 )
Professional fees, contract services and information systems maintenance
    6       8       (2 )
Rent and utilities
    3       3        
Legal costs
    1       2       (1 )
Other, net
    3       1       2  
 
                 
General and administrative
  $ 28     $ 33     $ (5 )
 
                 
Gains on Sales of Assets and Emission and Exchange Allowances, Net.
                         
    Three Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Bighorn plant
  $ 1     $     $ 1  
CO2 exchange allowances
          26       (26 )
SO2 and NOx emission allowances
          1       (1 )
Investments in and receivables from Channelview
          (5 )     5  
Other, net
    1             1  
 
                 
Gains on sales of assets and emission and exchange allowances, net
  $ 2     $ 22     $ (20 )
 
                 
Depreciation and Amortization.
                         
    Three Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Depreciation on plants
  $ 56     $ 59     $ (3 )
Other, net — depreciation
    4       4        
 
                 
Depreciation
    60       63       (3 )
 
                 
Amortization of emission allowances
    6       19       (13 )(1)
Other, net — amortization
    1       1        
 
                 
Amortization
    7       20       (13 )
 
                 
Depreciation and amortization
  $ 67     $ 83     $ (16 )
 
                 
 
     
(1)   Decrease primarily due to (a) lower weighted average cost of SO2 allowances and (b) decrease in SO2 allowances used.
Income (Loss) of Equity Investment, Net. This represents income/loss, which did not change significantly, from our equity method investment in Sabine Cogen, LP.
Debt Extinguishments Gains (Losses).
                         
    Three Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Senior secured notes — debt extinguishments gains
  $ 2     $     $ 2  
Deferred financing costs — accelerated amortization due to extinguishments
    (1 )           (1 )
 
                 
Debt extinguishments gains
  $ 1     $     $ 1  
 
                 
Other, Net. Other, net did not change significantly.

 

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Interest Expense.
                         
    Three Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Fixed-rate debt
  $ 52     $ 53     $ (1 )
Deferred financing costs
    1       1        
Financing fees expensed
    1       2       (1 )
Amortization of fair value adjustment of acquired debt
    (3 )     (3 )      
Capitalized interest(1)
    (7 )     (4 )     (3 )
Other, net
    1       2       (1 )
 
                 
Interest expense
  $ 45 (2)   $ 51 (2)   $ (6 )
 
                 
 
     
(1)   Relates primarily to scrubber projects at our Cheswick and Keystone plants.
 
(2)   See notes 7 and 15 to our interim financial statements regarding certain debt and related interest expense classified in discontinued operations.
Interest Income.
                         
    Three Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Interest on temporary cash investments
  $ 1     $ 5     $ (4 )
Net margin deposits
          3       (3 )
 
                 
Interest income
  $ 1     $ 8     $ (7 )
 
                 
Income Tax Expense (Benefit). See note 9 to our interim financial statements.
Income from Discontinued Operations. See note 15 to our interim financial statements.
Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008
We reported $652 million consolidated net income, or $1.86 income per share, for the six months ended June 30, 2009 compared to $736 million consolidated net income, or $2.08 income per diluted share, for the same period in 2008. We reported $209 million consolidated net loss from continuing operations, or $0.60 loss per share, for the six months ended June 30, 2009 compared to $95 million consolidated net income from continuing operations, or $0.27 income per diluted share, for the same period in 2008.
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Wholesale energy contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives
  $ (63 )   $ 496     $ (559 )
Other contribution margin
    1             1  
Operation and maintenance(1)
    (1 )     (2 )     1  
General and administrative
    (57 )     (61 )     4  
Western states litigation and similar settlements
          (34 )     34  
Gains on sales of assets and emission allowances, net
    20       23       (3 )
Depreciation and amortization
    (135 )     (166 )     31  
Income of equity investment, net
          1       (1 )
Debt extinguishments gains (losses)
    1       (1 )     2  
Interest expense
    (92 )     (102 )     10  
Interest income
    1       14       (13 )
Income tax (expense) benefit
    116       (73 )     189  
 
                 
Income (loss) from continuing operations
    (209 )     95       (304 )
Income from discontinued operations
    861       641       220  
 
                   
Net income
  $ 652     $ 736     $ (84 )
 
                 
 
     
(1)   Relates primarily to general costs, which historically were allocated to our discontinued retail energy segment.

 

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Wholesale Energy Segment.
Our wholesale energy segment’s contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives was $(63) million during the six months ended June 30, 2009 compared to $496 million in the same period of 2008. The $559 million decrease was primarily due to (a) $278 million decrease in open wholesale gross margin due to lower spark and dark spreads as a result of lower power prices, (b) $153 million change in wholesale hedges primarily due to $149 million decline on fuel hedges and (c) $135 million net change in unrealized gains/losses on energy derivatives. Our margins are significantly impacted by coal prices and related spreads. See “— Wholesale Energy Margins” below for further explanations.
Wholesale Energy Operational and Financial Data.
                                 
    Six Months Ended June 30,  
    2009     2008  
    GWh     % Economic     GWh     % Economic  
 
                               
Economic Generation:
                               
PJM Coal
    9,950.3       69 %     11,280.8       77 %
MISO Coal
    2,411.5       44 %     3,407.7       62 %
PJM/MISO Gas
    673.1       4 %     412.7       3 %
West
    288.2       3 %     547.0       4 %
Other
    63.1       2 %     7.0       1 %
 
                       
Total
    13,386.2       26 %     15,655.2       31 %
 
                       
 
                               
Commercial Capacity Factor:
                               
PJM Coal
    77.6 %             84.3 %        
MISO Coal
    85.0 %             81.5 %        
PJM/MISO Gas
    94.2 %             92.0 %        
West
    78.1 %             86.3 %        
Other
    98.7 %             81.4 %        
 
                           
Total
    79.9 %             84.0 %        
 
                           
 
                               
Generation:
                               
PJM Coal
    7,719.4               9,515.1          
MISO Coal
    2,048.6               2,776.1          
PJM/MISO Gas
    634.1               379.5          
West
    225.1               472.2          
Other
    62.3               5.7          
 
                           
Total
    10,689.5               13,148.6          
 
                           
 
                               
Open Energy Unit Margin ($/MWh):
                               
PJM Coal
  $ 14.64             $ 38.04          
MISO Coal
    10.74               27.02          
PJM/MISO Gas
    9.46               52.70          
West
    39.98               NM (1)        
 
                           
Total weighted average
  $ 14.03             $ 34.15          
 
                           
 
     
(1)   NM is not meaningful.
Wholesale Energy Revenues.
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Wholesale energy third-party revenues
  $ 880     $ 1,647     $ (767 )(1)
Revenues — affiliates
          253 (2)     (253 )
Unrealized losses on energy derivatives
    (26 )     (7 )     (19 )(3)
 
                 
Total wholesale energy revenues
  $ 854     $ 1,893     $ (1,039 )
 
                 
 
     
(1)   Decrease primarily due to (a) lower power and natural gas sales prices and (b) lower power sales volumes.
 
(2)   We deconsolidated Channelview on August 20, 2007. These revenues represent sales of fuel to Channelview prior to the assets being sold.
 
(3)   See footnote 8 under “— Wholesale Energy Margins.”

 

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Wholesale Energy Cost of Sales.
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Wholesale energy third-party costs
  $ 594     $ 1,113     $ (519 )(1)
Cost of sales — affiliates
          70 (2)     (70 )
Unrealized (gains) losses on energy derivatives
    11       (105 )     116 (3)
 
                 
Total wholesale energy cost of sales
  $ 605     $ 1,078     $ (473 )
 
                 
 
     
(1)   Decrease primarily due to (a) lower prices paid for natural gas and (b) lower natural gas volumes purchased.
 
(2)   We deconsolidated Channelview on August 20, 2007. These cost of sales represent purchases of power from Channelview prior to the assets being sold.
 
(3)   See footnote 8 under “— Wholesale Energy Margins.”
Wholesale Energy Margins.
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Open energy gross margin:
                       
PJM Coal
  $ 113     $ 362     $ (249 )(1)
MISO Coal
    22       75       (53 )(1)
PJM/MISO Gas
    6       20       (14 )(1)
West
    9       (8 )     17 (2)
 
                 
Total
    150       449       (299 )
 
                       
Other margin:
                       
PJM Coal
    72       44       28 (3)
MISO Coal
    5       5        
PJM/MISO Gas
    82       60       22 (4)
West
    24       56       (32 )(5)
Other
    27       24       3  
 
                 
Total
    210       189       21  
 
                 
 
                       
Open wholesale gross margin
    360       638       (278 )
 
                 
 
                       
Operation and maintenance, excluding severance
    (308 )     (318 )     10 (6)
Other
          (1 )     1  
 
                 
Open wholesale contribution margin
    52       319       (267 )
Wholesale hedges
    (74 )     79       (153 )(7)
Unrealized gains (losses) on energy derivatives
    (37 )     98       (135 )(8)
Operation and maintenance — severance
    (4 )           (4 )
 
                 
Total wholesale energy contribution margin, including wholesale hedges and unrealized gains/losses on energy derivatives
  $ (63 )   $ 496     $ (559 )
 
                 
 
     
(1)   Decrease primarily due to lower unit margins (lower power prices partially offset by lower fuel costs).
 
(2)   Increase primarily due to higher unit margins (lower fuel expense and higher power prices).
 
(3)   Increase primarily due to higher RPM capacity payments. This increase was partially offset by lower ancillary payments.
 
(4)   Increase primarily due to higher RPM capacity payments.
 
(5)   Decrease primarily due to (a) reduced selective commercial hedge activities and (b) lower capacity payments.
 
(6)   Decrease primarily due to (a) $7 million decrease due to the sale of Bighorn in October 2008, (b) $5 million decrease from reduced operations activity and (c) $5 million decrease in services and support. These decreases were partially offset by a $5 million increase in primarily employee-related costs.
 
(7)   Decrease primarily due to (a) $149 million decline on fuel hedges, (b) $59 million loss on market adjustments to inventory and (c) $26 million loss primarily related to payments to reduce fixed price coal commitments for future periods. These decreases were partially offset by (a) $51 million gain on a hedge of generation and (b) $15 million decrease of losses on closed hedges.
 
(8)   Decrease primarily due to $142 million in losses from changes in prices on our energy derivatives marked to market partially offset by $7 million in gains due to reversal of previously recognized unrealized losses on energy derivatives which settled during the period.

 

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General and Administrative.
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Salaries and benefits
  $ 32     $ 33     $ (1 )
Professional fees, contract services and information systems maintenance
    12       15       (3 )
Rent and utilities
    7       7        
Legal costs
    2       3       (1 )
Other, net
    4       3       1  
 
                 
General and administrative
  $ 57     $ 61     $ (4 )
 
                 
Western States Litigation and Similar Settlements. See note 11(a) to our consolidated financial statements in our Form 10-K.
Gains on Sales of Assets and Emission and Exchange Allowances, Net.
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
CO2 exchange allowances
  $ 10     $ 26     $ (16 )
SO2 and NOx emission allowances
    7       1       6  
Bighorn Plant
    3             3  
Investments in and receivables from Channelview
          (5 )     5  
Other, net
          1       (1 )
 
                 
Gains on sales of assets and emission and exchange allowances, net
  $ 20     $ 23     $ (3 )
 
                 
Depreciation and Amortization.
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Depreciation on plants
  $ 111     $ 117     $ (6 )
Other, net — depreciation
    8       8        
 
                 
Depreciation
    119       125       (6 )
 
                 
Amortization of emission allowances
    14       39       (25 )(1)
Other, net — amortization
    2       2        
 
                 
Amortization
    16       41       (25 )
 
                 
Depreciation and amortization
  $ 135     $ 166     $ (31 )
 
                 
 
     
(1)   Decrease primarily due to (a) lower weighted average cost of SO2 allowances and (b) decrease in SO2 allowances used.
Income (Loss) of Equity Investment, Net. This represents income/loss, which did not change significantly, from our equity method investment in Sabine Cogen, LP.
Debt Extinguishments Gains (Losses).
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Senior secured notes — debt extinguishments gains
  $ 2     $     $ 2  
Deferred financing costs — accelerated amortization due to extinguishments
    (1 )     (1 )      
 
                 
Debt extinguishments gains (losses)
  $ 1     $ (1 )   $ 2  
 
                 

 

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Other, Net. Other, net did not change significantly.
Interest Expense.
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Fixed-rate debt
  $ 105     $ 106     $ (1 )
Deferred financing costs
    3       3        
Financing fees expensed
    3       4       (1 )
Amortization of fair value adjustment of acquired debt
    (6 )     (6 )      
Capitalized interest(1)
    (14 )     (7 )     (7 )
Other, net
    1       2       (1 )
 
                 
Interest expense
  $ 92 (2)   $ 102 (2)   $ (10 )
 
                 
 
     
(1)   Relates primarily to scrubber projects at our Cheswick and Keystone plants.
 
(2)   See notes 7 and 15 to our interim financial statements regarding certain debt and related interest expense classified in discontinued operations.
Interest Income.
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Interest on temporary cash investments
  $ 2     $ 10     $ (8 )
Net margin deposits
          4       (4 )
Other, net
    (1 )           (1 )
 
                 
Interest income
  $ 1     $ 14     $ (13 )
 
                 
Income Tax Expense (Benefit). See note 9 to our interim financial statements.
Income from Discontinued Operations. See note 15 to our interim financial statements.
Liquidity and Capital Resources
Our goal of establishing and maintaining financial flexibility remains unchanged. We are committed to a strong balance sheet and ample liquidity that will enable us to avoid distress in cyclical troughs and to access capital markets throughout the cycle for value-creation opportunities.
We believe our liquidity exceeds the level required to achieve this goal. Therefore, we expect to use some of our cash and cash equivalents to reduce debt. Our goal for gross debt (total GAAP debt plus our RRI Energy Mid-Atlantic Power Holdings, LLC (REMA) operating leases) is $1.25 billion to $1.75 billion. The comparable target for total GAAP debt, based on the current balance for our REMA leases of $443 million, is approximately $800 million to $1.3 billion. We believe that the non-GAAP measure gross debt is a useful and relevant measure of our financial obligations and the strength and flexibility of our capital structure.
On May 1, 2009, we sold our Texas retail business for $287.5 million in cash plus the value of the net working capital (currently estimated at $78 million). We offered a portion of the net proceeds to holders of our senior secured notes and PEDFA bonds and purchased $261 million at par in the second and third quarters of 2009. See “—Recent Events” and notes 11(b) and 15 to our interim financial statements. During the second quarter of 2009, we also purchased $45 million of our senior secured notes at a discount. In the future, we could use a variety of means to achieve our gross debt goal, including the retirement of Orion Power Holdings, Inc.’s $400 million senior unsecured notes due in May 2010.
As of July 28, 2009, we had total available liquidity of $1.9 billion, comprised of unused borrowing capacity, letters of credit capacity and cash and cash equivalents. During the six months ended June 30, 2009, we used $96 million in operating cash flows from continuing operations, including the changes in margin deposits of $50 million (cash outflow). See “—Historical Cash Flows” for further detail of our cash flows from operating activities and explanation of our $64 million and $43 million use of cash from investing activities from continuing operations and use of cash from financing activities from continuing operations, respectively, during the six months ended June 30, 2009.

 

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See note 9 to our interim financial statements regarding an expected income tax cash payment of approximately $60 to $65 million relating to California-related matters.
Based on our assessment of the economic environment and volatility in commodity markets, we have hedged approximately 25% of our estimated power generation for 2010 and 2011 (based on MWh). We expect these hedges will reduce the effect of commodity volatility on our 2010 and 2011 cash flows. We continue to monitor our business and hedging with the goal of providing adequate cash flows in the event of a sustained depressed environment.
See “Risk Factors” in Item 1A and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in Item 7 of our Form 10-K, notes 6 and 12(a) to our consolidated financial statements in our Form 10-K and note 7 to our interim financial statements.
Credit Risk
By extending credit to our counterparties, we are exposed to credit risk. For discussion of our credit risk policy and exposures, see note 5 to our interim financial statements.
Off-Balance Sheet Arrangements
As of June 30, 2009, we have no off-balance sheet arrangements.
Historical Cash Flows
Cash Flows — Operating Activities
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Operating income (loss)
  $ (235 )   $ 256     $ (491 )
Depreciation and amortization
    135       166       (31 )
Gains on sales of assets and emission allowances, net
    (20 )     (23 )     3  
Net changes in energy derivatives
    37 (1)     (98 )(2)     135  
Western states litigation and similar settlements
          34       (34 )
Margin deposits, net
    (50 )     (55 )     5  
Change in accounts and notes receivable and accounts payable, net
    119       (70 )     189  
Change in inventory
    13       (42 )     55  
Net option premiums purchased
    (24 )     (1 )     (23 )
Interest payments, net of capitalized interest
    (95 )     (105 )     10  
Income tax payments, net of refunds
    (4 )     13       (17 )
Prepaid lease obligation
    8       8        
Construction deposit refund
    15             15  
Other, net
    5       5        
 
                 
Net cash provided by (used in) continuing operations from operating activities
    (96 )     88       (184 )
Net cash provided by discontinued operations from operating activities
    508       103       405  
 
                 
Net cash provided by operating activities
  $ 412     $ 191     $ 221  
 
                 
 
     
(1)   Includes unrealized losses on energy derivatives of $37 million.
 
(2)   Includes unrealized gains on energy derivatives of $98 million.

 

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Cash Flows — Investing Activities
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Capital expenditures
  $ (115 )   $ (103 )   $ (12 )
Proceeds from sales of assets
    36 (1)           36  
Proceeds from sales of emission allowances
    19       29       (10 )
Purchases of emission allowances
    (5 )     (18 )     13  
Restricted cash
          (4 )     4  
Other, net
    1       1        
 
                 
Net cash used in continuing operations from investing activities
    (64 )     (95 )     31  
Net cash provided by (used in) discontinued operations from investing activities
    299       (14 )     313  
 
                 
Net cash provided by (used in) investing activities
  $ 235     $ (109 )   $ 344  
 
                 
 
     
(1)   Includes $35 million previously held in escrow and released to us relating to the sale of the Channelview plant in July 2008.
Cash Flows — Financing Activities
                         
    Six Months Ended June 30,  
    2009     2008     Change  
    (in millions)  
 
                       
Purchases of senior secured notes
  $ (45 )   $ (45 )   $  
Proceeds from issuance of stock
    2       6       (4 )
 
                 
Net cash used in continuing operations from financing activities
    (43 )     (39 )     (4 )
Net cash used in discontinued operations from financing activities
    (225 )           (225 )
 
                 
Net cash used in financing activities
  $ (268 )   $ (39 )   $ (229 )
 
                 
New Accounting Pronouncements, Significant Accounting Policies and Critical Accounting Estimates
New Accounting Pronouncements
See notes 1 and 3 to our interim financial statements.
Significant Accounting Policies
See note 2 to our consolidated financial statements in our Form 10-K.
Critical Accounting Estimates
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Accounting Estimates — New Accounting Pronouncements, Significant Accounting Policies and Critical Accounting Estimates — Critical Accounting Estimates” in Item 7 in our Form 10-K and note 2 to our consolidated financial statements in our Form 10-K.

 

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ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risks and Risk Management
Our primary market risk exposure relates to fluctuations in commodity prices. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of our Form 10-K and notes 3 and 4 to our interim financial statements.
Non-Trading Market Risks
Commodity Price Risk
As of June 30, 2009, the fair values of the contracts related to our net non-trading derivative assets and liabilities are:
                                                         
    Twelve                                            
    Months                                            
    Ending                                            
    June 30,     Remainder                             2014 and     Total fair  
Source of Fair Value   2010     of 2010     2011     2012     2013     thereafter     value  
    (in millions)  
 
                                                       
Prices actively quoted (Level 1)
  $ 55     $ 5     $ 27     $     $     $     $ 87  
Prices provided by other external sources (Level 2)
    (44 )     (18 )     (37 )     (13 )                 (112 )
Prices based on models and other valuation methods (Level 3)
    (110 )     (2 )                             (112 )
 
                                         
Total mark-to-market non-trading derivatives
  $ (99 )   $ (15 )   $ (10 )   $ (13 )   $     $     $ (137 )
 
                                         
The fair values shown in the table above are subject to significant changes due to fluctuating commodity forward market prices, volatility and credit risk. Market prices assume a functioning market with an adequate number of buyers and sellers to provide liquidity. Insufficient market liquidity could significantly affect the values that could be obtained for these contracts, as well as the costs at which these contracts could be hedged. In addition, we have committed volumes under some coal contracts through 2010 and 2011 for which the contract prices are subject to negotiation prior to the beginning of each year. For further discussion of how we arrive at these fair values, see note 2(d) to our consolidated financial statements in our Form 10-K, note 3 to our interim financial statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—New Accounting Pronouncements, Significant Accounting Policies and Critical Accounting Estimates—Critical Accounting Estimates” in Item 7 of our Form 10-K.
A hypothetical 10% movement in the underlying energy prices would have the following potential loss impacts on our non-trading derivatives:
                         
As of   Market Prices     Earnings Impact     Fair Value Impact  
    (in millions)  
 
                       
June 30, 2009
  10% increase   $ (45 )   $ (45 )
December 31, 2008
  10% decrease     (5 )     (5 )
Interest Rate Risk
As of June 30, 2009 and December 31, 2008, we have no variable rate debt outstanding. We earn interest income, for which the interest rates vary, on our cash and cash equivalents and net margin deposits. During the six months ended June 30, 2009 and twelve months ended December 31, 2008, we had no variable rate interest expense and our interest income was $2 million and $20 million, respectively.
If interest rates decreased by one percentage point from their June 30, 2009 and December 31, 2008 levels, the fair values of our fixed rate debt from continuing operations would have increased by $134 million and $110 million, respectively.

 

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Trading Market Risks
As of June 30, 2009, the fair values of the contracts related to our legacy trading and non-core asset management positions and recorded as net derivative assets and liabilities are:
                                                         
    Twelve                                            
    Months                                            
    Ending                                            
    June 30,     Remainder                             2014 and     Total fair  
Source of Fair Value   2010     of 2010     2011     2012     2013     thereafter     value  
    (in millions)  
 
                                                       
Prices actively quoted (Level 1)
  $ 24     $ 8     $     $     $     $     $ 32  
Prices provided by other external sources (Level 2)
    1                                     1  
Prices based on models and other valuation methods (Level 3)
    (4 )     (1 )                             (5 )
 
                                         
Total
  $ 21     $ 7     $     $     $     $     $ 28  
 
                                         
The fair values in the above table are subject to significant changes based on fluctuating market prices and conditions. See the discussion above related to non-trading derivative assets and liabilities for further information on items that impact our portfolio of trading contracts.
Our consolidated realized and unrealized margins relating to trading activities, including both derivative and non-derivative instruments, are (income (loss)):
                                 
    Three Months Ended June 30,     Six Months Ended June 30,  
    2009     2008     2009     2008  
    (in millions)  
 
                               
Realized
  $ 7     $ 2     $ 18     $ 9  
Unrealized
    (2 )     (15 )     (2 )     (26 )
 
                       
Total
  $ 5     $ (13 )   $ 16     $ (17 )
 
                       
An analysis of these net derivative assets and liabilities is:
                 
    Six Months Ended June 30,  
    2009     2008  
    (in millions)  
 
Fair value of contracts outstanding, beginning of period
  $ 30     $ 19  
Contracts realized or settled
    (18 )(1)     (15 )(2)
Changes in fair values attributable to market price and other market changes
    16       (6 )
 
           
Fair value of contracts outstanding, end of period
  $ 28     $ (2 )
 
           
 
     
(1)   Amount includes realized gain of $18 million.
 
(2)   Amount includes realized gain of $10 million and deferred settlements of $5 million.

 

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The daily value-at-risk for our legacy trading and non-core asset management positions is:
                 
    2009(1)     2008  
    (in millions)  
 
               
As of June 30
  $ 1     $ 11  
Three months ended June 30:
               
Average
    2       5  
High
    2       13  
Low
    1       1  
Six months ended June 30:
               
Average
    2       3  
High
    4       13  
Low
    1        
 
     
(1)   The major parameters for calculating daily value-at-risk remain the same during 2009 as disclosed in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of our Form 10-K.
Fair Value Measurements
We apply recurring fair value measurements to our derivatives assets and liabilities. See note 3 to our interim financial statements. Derivative instruments classified as Level 2 primarily include over-the-counter (OTC) derivative instruments such as generic swaps and forwards. The fair value measurements of these derivative assets and liabilities are based largely on unadjusted indicative quoted prices from independent brokers in active markets. An active market is considered to have transactions with sufficient frequency and volume to provide pricing information on an ongoing basis. Derivative instruments for which fair value is calculated using quoted prices that are deemed not active or that have been extrapolated from quoted prices in active markets are classified as Level 3. For certain natural gas and power contracts, we adjust seasonal or calendar year quoted prices based on historical observations to represent fair value for each month in the season or calendar year, such that the average of all months is equal to the quoted price. A derivative instrument that has a tenor that does not span the quoted period is considered an unobservable Level 3 measurement.
We evaluate and validate the inputs we use to estimate fair value by a number of methods, including validating against market published prices and daily broker quotes obtainable from multiple pricing services. For OTC derivative instruments classified as Level 2, indicative quotes obtained from brokers in liquid markets generally represent fair value of these instruments. Adjustments to the quotes are adjustments to the bid or ask price depending on the nature of the position to appropriately reflect exit pricing and are considered a Level 3 input to the fair value measurement. In less liquid markets such as coal, in which a single broker’s view of the market is used to estimate fair value, we consider such inputs to be unobservable Level 3 inputs.
Fair value for energy derivatives is further derived from credit adjustments. Derivative assets are discounted using a yield curve representative of the counterparty’s probability of default. The counterparty’s default probability is based on a modified version of published default rates, taking 20-year historical default rates from Standard & Poor’s and Moody’s and adjusting them to reflect a rolling five-year average. For derivative liabilities, fair value measurement reflects the nonperformance risk related to that liability, which is our own credit risk. We derive our nonperformance risk by applying our credit default swap spread against the respective derivative liability.
To determine the fair value for Level 3 energy derivatives where there are no market quotes or external valuation services, we rely on various modeling techniques. We use a variety of valuation models, which vary in complexity depending on the contractual terms of, and inherent risks in, the instrument being valued. We use both industry-standard models as well as internally developed proprietary valuation models that consider various assumptions such as market prices for power and fuel, price shapes, volatilities and correlations as well as other relevant factors as may be deemed appropriate. There is inherent risk in valuation modeling given the complexity and volatility of energy markets. Therefore, it is possible that results in future periods may be materially different as contracts are ultimately settled.

 

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ITEM 4.   CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our chief executive officer and chief financial officer, have evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (1934 Act)) as of June 30, 2009, the end of the period covered by this Form 10-Q. Based on this evaluation, our chief executive officer and chief financial officer concluded that, as of June 30, 2009, our disclosure controls and procedures were effective.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the 1934 Act) during the period ended June 30, 2009, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II.
OTHER INFORMATION
ITEM 1.   LEGAL PROCEEDINGS
See note 11 to our interim financial statements in this Form 10-Q.
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
We held our annual meeting of stockholders on June 18, 2009. Our stockholders voted on the following proposals:
  1.   To elect the five directors nominated by our Nominating & Governance Committee to our Board of Directors to serve until the next annual meeting of stockholders; and
  2.   To ratify the Audit Committee’s selection of KPMG LLP as our independent auditors for fiscal year 2009.
The voting results were:
E. William Barnett was re-elected to serve as a director:
         
For   Against   Abstain
267,014,517
  26,030,276   879,019
Mark M. Jacobs was re-elected to serve as a director:
         
For   Against   Abstain
266,634,744   26,269,718   1,019,349
Steven L. Miller was re-elected to serve as a director:
         
For   Against   Abstain
262,503,102   30,520,129   900,580
Laree E. Perez was re-elected to serve as a director:
         
For   Against   Abstain
267,217,045   25,730,457   976,310
Evan J. Silverstein was re-elected to serve as a director:
         
For   Against   Abstain
273,366,731   19,616,453   940,627

 

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The Audit Committee’s selection of KPMG LLP as our independent auditors for the fiscal year ended December 31, 2009 was ratified:
         
For   Against   Abstain
288,939,553   4,073,259   911,000
We did not receive any broker non-votes on the proposals.
ITEM 6.   EXHIBITS
Exhibits.
See Index of Exhibits.

 

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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
             
    RRI ENERGY, INC.    
    (Registrant)    
 
           
August 3, 2009
  By:   /s/ Thomas C. Livengood
 
Thomas C. Livengood
   
 
      Senior Vice President and Controller    
 
      (Duly Authorized Officer and Chief Accounting Officer)    

 

 


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INDEX OF EXHIBITS
Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated herein by reference to a prior filing as indicated. The exhibits with the asterisk symbol (*) are compensatory arrangements filed pursuant to Item 601(b)(10)(iii) of Regulation S-K. The representations, warranties and covenants contained in the exhibits were made only for purposes of such exhibits, as of specific dates, solely for the benefit of the parties thereto, may be subject to limitations agreed upon by those parties, and may be subject to standards of materiality that differ from those applicable to investors. Investors should read such representations, warranties and covenants (or any descriptions thereof contained in the exhibits) in conjunction with information provided elsewhere in this filing and in our other filings and should not rely solely on such information as characterizations of our actual state of facts.
                         
                SEC File or    
            Report or Registration   Registration   Exhibit
Exhibit Number   Document Description   Statement   Number   Reference
       
 
               
  3.1    
Third Restated Certificate of Incorporation
  RRI Energy, Inc.’s Quarterly Report on Form 10-Q for the period ended June 30, 2007   1-16455     3.1  
       
 
               
  +3.2    
Sixth Amended and Restated Bylaws
               
       
 
               
  3.3    
Certificate of Ownership and Merger merging a wholly-owned subsidiary into registrant pursuant to Section 253 of the General Corporation Law of the State of Delaware, effective as of May 2, 2009
  RRI Energy, Inc.’s Quarterly Report on Form 10-Q for the period ended March 31, 2009   1-16455     3.3  
       
 
               
  4.1    
Registrant has omitted instruments with respect to long-term debt in an amount that does not exceed 10% of the registrant’s total assets and its subsidiaries on a consolidated basis and hereby undertakes to furnish a copy of any such agreement to the Securities and Exchange Commission upon request
               
       
 
               
  *+10.1    
2009 Long Term Incentive Award Program for Officers and Form of Award Agreement
               
       
 
               
  *+10.2    
2002 Long Term Incentive Plan Director Common Stock Award for Evan J. Silverstein
               
       
 
               
  *+10.3    
2002 Long Term Incentive Plan Form of Director Annual Award Agreement
               
       
 
               
  *+10.4    
2002 Long Term Incentive Plan Form of Quarterly Common Stock and Premium Restricted Stock Award for Directors
               
       
 
               
  *+10.5    
Non-Employee Directors’ Compensation Program, effective as of June 19, 2009
               
       
 
               
  +31.1    
Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
               
       
 
               
  +31.2    
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
               
       
 
               
  +32.1    
Certification of Chief Executive Officer and Chief Financial Officer pursuant to Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
               
       
 
               
  +101.1    
Interactive Data File