Exhibit 99.2
GENON ENERGY, INC. |
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Condensed Consolidated Statements of Operations (Unaudited) Three and Nine Months Ended September 30, 2012 and 2011 | 1 |
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Condensed Consolidated Statements of Comprehensive Loss (Unaudited) Three and Nine Months Ended September 30, 2012 and 2011 | 2 |
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Condensed Consolidated Balance Sheets (Unaudited) September 30, 2012 and December 31, 2011 | 3 |
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Condensed Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, 2012 and 2011 | 4 |
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Notes to Condensed Consolidated Financial Statements (Unaudited) | 5 |
GENON ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
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| Three Months Ended September 30, |
| Nine Months Ended September 30, |
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| 2012 |
| 2011 |
| 2012 |
| 2011 |
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Operating revenues (including unrealized gains (losses) of $(245), $49, $(204) and $(86), respectively) |
| $ | 755 |
| $ | 1,080 |
| $ | 1,997 |
| $ | 2,706 |
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Cost of fuel, electricity and other products (including unrealized (gains) losses of $(58), $11, $25 and $(27), respectively) |
| 346 |
| 526 |
| 930 |
| 1,317 |
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Gross Margin (excluding depreciation and amortization) |
| 409 |
| 554 |
| 1,067 |
| 1,389 |
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Operating Expenses: |
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Operations and maintenance |
| 268 |
| 286 |
| 840 |
| 963 |
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Depreciation and amortization |
| 91 |
| 96 |
| 269 |
| 272 |
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Impairment losses |
| 47 |
| 133 |
| 47 |
| 133 |
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Gain on sales of assets, net |
| (1 | ) | (6 | ) | (9 | ) | (5 | ) | ||||
Total operating expenses |
| 405 |
| 509 |
| 1,147 |
| 1,363 |
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Operating Income (Loss) |
| 4 |
| 45 |
| (80 | ) | 26 |
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Other Income (Expense), net: |
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Interest expense |
| (86 | ) | (86 | ) | (260 | ) | (291 | ) | ||||
Interest income |
| 1 |
| 1 |
| 1 |
| 1 |
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Other, net |
| — |
| 1 |
| 2 |
| (21 | ) | ||||
Total other expense, net |
| (85 | ) | (84 | ) | (257 | ) | (311 | ) | ||||
Loss Before Income Taxes |
| (81 | ) | (39 | ) | (337 | ) | (285 | ) | ||||
Provision for income taxes |
| 4 |
| 1 |
| 8 |
| 4 |
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Net Loss |
| $ | (85 | ) | $ | (40 | ) | $ | (345 | ) | $ | (289 | ) |
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Basic and Diluted EPS: |
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Basic EPS |
| $ | (0.11 | ) | $ | (0.05 | ) | $ | (0.45 | ) | $ | (0.37 | ) |
Diluted EPS |
| $ | (0.11 | ) | $ | (0.05 | ) | $ | (0.45 | ) | $ | (0.37 | ) |
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Weighted average shares outstanding |
| 774 |
| 772 |
| 774 |
| 771 |
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Effect of dilutive securities |
| — |
| — |
| — |
| — |
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Weighted average shares outstanding assuming dilution |
| 774 |
| 772 |
| 774 |
| 771 |
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The accompanying notes are an integral part of these unaudited condensed consolidated financial statements
GENON ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)
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| Three Months Ended September 30, |
| Nine Months Ended September 30, |
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| 2012 |
| 2011 |
| 2012 |
| 2011 |
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Net Loss |
| $ | (85 | ) | $ | (40 | ) | $ | (345 | ) | $ | (289 | ) |
Other Comprehensive Income (Loss), net of tax of $0: |
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Unrealized losses: |
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Cash flow hedges—interest rate swaps |
| (5 | ) | (39 | ) | (17 | ) | (50 | ) | ||||
Available-for-sale securities |
| — |
| — |
| — |
| (1 | ) | ||||
Pension and other postretirement benefits— actuarial losses, net |
| (9 | ) | — |
| (9 | ) | — |
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Reclassifications to net loss: |
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Cash flow hedges—interest rate swaps |
| (1 | ) | — |
| (1 | ) | — |
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Pension and other postretirement benefits— actuarial losses, net |
| 2 |
| 1 |
| 6 |
| 3 |
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Pension and other postretirement benefits— prior service credit, net |
| — |
| (1 | ) | (2 | ) | (3 | ) | ||||
Other, net |
| — |
| — |
| 1 |
| — |
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Other Comprehensive Loss |
| (13 | ) | (39 | ) | (22 | ) | (51 | ) | ||||
Comprehensive Loss |
| $ | (98 | ) | $ | (79 | ) | $ | (367 | ) | $ | (340 | ) |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements
GENON ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
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| September 30, 2012 |
| December 31, 2011 |
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| (in millions) |
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ASSETS |
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Current Assets: |
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Cash and cash equivalents |
| $ | 1,855 |
| $ | 1,668 |
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Funds on deposit |
| 261 |
| 422 |
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Receivables, net |
| 294 |
| 357 |
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Derivative contract assets |
| 636 |
| 999 |
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Inventories |
| 447 |
| 563 |
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Prepaid rent and other expenses |
| 182 |
| 167 |
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Total current assets |
| 3,675 |
| 4,176 |
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Property, plant and equipment, gross |
| 7,616 |
| 7,351 |
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Accumulated depreciation and amortization |
| (1,351 | ) | (1,160 | ) | ||
Property, Plant and Equipment, net |
| 6,265 |
| 6,191 |
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Noncurrent Assets: |
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Intangible assets, net |
| 44 |
| 48 |
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Derivative contract assets |
| 588 |
| 733 |
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Deferred income taxes |
| 196 |
| 294 |
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Prepaid rent |
| 413 |
| 386 |
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Other |
| 394 |
| 441 |
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Total noncurrent assets |
| 1,635 |
| 1,902 |
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Total Assets |
| $ | 11,575 |
| $ | 12,269 |
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LIABILITIES AND STOCKHOLDERS’ EQUITY |
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Current Liabilities: |
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Current portion of long-term debt |
| $ | 10 |
| $ | 10 |
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Accounts payable and accrued liabilities |
| 690 |
| 790 |
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Derivative contract liabilities |
| 398 |
| 720 |
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Deferred income taxes |
| 196 |
| 294 |
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Other |
| 105 |
| 130 |
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Total current liabilities |
| 1,399 |
| 1,944 |
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Noncurrent Liabilities: |
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Long-term debt, net of current portion |
| 4,361 |
| 4,122 |
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Derivative contract liabilities |
| 184 |
| 131 |
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Pension and postretirement obligations |
| 252 |
| 259 |
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Other |
| 617 |
| 696 |
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Total noncurrent liabilities |
| 5,414 |
| 5,208 |
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Commitments and Contingencies |
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Stockholders’ Equity: |
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Preferred stock, par value $.001 per share, authorized 125,000,000 shares, no shares issued at September 30, 2012 and December 31, 2011 |
| — |
| — |
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Common stock, par value $.001 per share, authorized 2.0 billion shares, issued 772,922,439 shares and 771,692,734 shares at September 30, 2012 and December 31, 2011, respectively |
| 1 |
| 1 |
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Additional paid-in capital |
| 7,461 |
| 7,449 |
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Accumulated deficit |
| (2,508 | ) | (2,163 | ) | ||
Accumulated other comprehensive loss |
| (192 | ) | (170 | ) | ||
Total stockholders’ equity |
| 4,762 |
| 5,117 |
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Total Liabilities and Stockholders’ Equity |
| $ | 11,575 |
| $ | 12,269 |
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The accompanying notes are an integral part of these unaudited condensed consolidated financial statements
GENON ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
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| Nine Months Ended September 30, |
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| 2012 |
| 2011 |
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| (in millions) |
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Cash Flows from Operating Activities: |
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Net loss |
| $ | (345 | ) | $ | (289 | ) |
Adjustments to reconcile net loss and changes in operating assets and liabilities to net cash provided by operating activities: |
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Depreciation and amortization |
| 269 |
| 272 |
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Impairment losses |
| 47 |
| 133 |
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Amortization of acquired contracts |
| (36 | ) | (25 | ) | ||
Gain on sales of assets, net |
| (9 | ) | (5 | ) | ||
Unrealized losses |
| 229 |
| 59 |
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Stock-based compensation expense |
| 15 |
| 11 |
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Excess materials and supplies inventory reserve |
| 35 |
| — |
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Lower of cost or market inventory adjustments |
| 82 |
| 2 |
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Loss on early extinguishment of debt |
| — |
| 23 |
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Advance settlement of out-of-market contract obligation |
| (20 | ) | — |
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Reversal of Potomac River settlement obligation |
| (31 | ) | — |
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Large scale remediation and settlement costs |
| (3 | ) | 30 |
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Other, net |
| 13 |
| 10 |
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Changes in operating assets and liabilities |
| 20 |
| 61 |
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Total adjustments |
| 611 |
| 571 |
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Net cash provided by operating activities |
| 266 |
| 282 |
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Cash Flows from Investing Activities: |
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Capital expenditures |
| (486 | ) | (328 | ) | ||
Proceeds from the sales of assets |
| 14 |
| 18 |
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Restricted funds on deposit and other, net |
| 158 |
| 1,396 |
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Net cash provided by (used in) investing activities |
| (314 | ) | 1,086 |
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Cash Flows from Financing Activities: |
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Proceeds from long-term debt |
| 243 |
| 50 |
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Repayment of long-term debt |
| (8 | ) | (2,075 | ) | ||
Other, net |
| — |
| 1 |
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Net cash provided by (used in) financing activities |
| 235 |
| (2,024 | ) | ||
Net Increase (Decrease) in Cash and Cash Equivalents |
| 187 |
| (656 | ) | ||
Cash and Cash Equivalents, beginning of period |
| 1,668 |
| 2,402 |
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Cash and Cash Equivalents, end of period |
| $ | 1,855 |
| $ | 1,746 |
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Supplemental Disclosures: |
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Cash paid for interest, net of amounts capitalized |
| $ | 174 |
| $ | 225 |
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Cash paid for income taxes (net of refunds received) |
| $ | 12 |
| $ | (6 | ) |
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements
GENON ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. Description of Business and Accounting and Reporting Policies
Background
We are a wholesale generator with approximately 22,000 MW of net electric generating capacity located, in many cases, near major metropolitan load centers in the PJM, MISO, Northeast and Southeast regions, and California. We also operate integrated asset management and proprietary trading operations. See note 2 for a discussion of generating facilities in the Eastern PJM, Western PJM/MISO and California segments that have units we deactivated in 2012 or expect to deactivate in 2013 and 2015.
We were formed as a Delaware corporation in August 2000. “We,” “us,” “our” and “GenOn” refer to GenOn Energy, Inc. and, except where the context indicates otherwise, its subsidiaries, after giving effect to the Mirant/RRI Merger.
Proposed Merger with NRG
On July 20, 2012, we entered into the NRG Merger Agreement with NRG Energy, Inc. and a direct wholly-owned subsidiary of NRG. Upon the terms and subject to the conditions set forth in the NRG Merger Agreement, which has been approved by the boards of directors of GenOn and NRG, a wholly-owned subsidiary of NRG will merge with and into GenOn, with GenOn continuing as the surviving corporation and a wholly owned subsidiary of NRG.
Upon closing of the NRG Merger, each issued and outstanding share of our common stock will automatically convert into the right to receive 0.1216 shares of common stock of NRG based on the exchange ratio. All outstanding stock options (other than options granted in 2012) will immediately vest and all outstanding stock options will generally convert upon completion of the NRG Merger into stock options with respect to NRG common stock, after giving effect to the exchange ratio. In addition, all outstanding restricted stock units (other than restricted stock units granted in 2012) will immediately vest and all outstanding restricted stock units will be exchanged for the NRG Merger consideration. All outstanding stock options and restricted stock units granted in 2012 will vest at the holder’s termination date if the termination is as a result of the NRG Merger and within two years of the closing date. See note 7.
The NRG Merger is intended to qualify as a tax-free reorganization under the IRC, as amended, so that none of GenOn, NRG or any of our stockholders generally will recognize any gain or loss in the transaction, except with respect to cash received in lieu of fractional shares of NRG common stock.
Completion of the NRG Merger is contingent upon, among other things, (a) approvals by NRG stockholders of the issuance of NRG common stock in the NRG Merger and the approval and adoption of the amendment to NRG’s certificate of incorporation to allow the size of NRG’s board of directors to be increased to 16 in connection with the closing of the NRG Merger at a meeting to be held on November 9, 2012, (b) adoption of the NRG Merger Agreement by our stockholders at a meeting to be held on November 9, 2012, (c) effectiveness of an NRG registration statement on Form S-4, which occurred on October 5, 2012, and approval of the New York Stock Exchange listing for the NRG common stock to be issued in the NRG Merger, (d) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, which occurred on September 21, 2012, and (e) receipt of all required regulatory approvals, including approvals from the Public Utility Commission of Texas, which occurred on October 25, 2012, the FERC and the New York Public Service Commission.
We and NRG are also subject to restrictions on our respective ability to solicit alternative acquisition proposals and to provide information to, and engage in discussion with, third parties, except under limited circumstances to permit our or NRG’s board of directors to comply with their respective fiduciary duties. The NRG Merger Agreement contains termination rights for both us and NRG and further provides that, upon termination of the NRG Merger Agreement under specified circumstances, NRG may be required to pay a termination fee of $120 million to us and we may be required to pay NRG a termination fee of $60 million.
In addition, at NRG’s request and upon the terms and subject to the conditions of the NRG Merger Agreement, we will commence a “change of control” tender offer for each series of our outstanding notes due 2014, 2017, 2018 and 2020, conditioned on the completion of the NRG Merger (the Change in Control Offers). In addition, upon the terms and subject to the conditions of the NRG Merger Agreement, NRG may, at its election following consultation with us, commence a tender offer for cash or an exchange offer for securities for all or any portion of our outstanding notes due 2014, 2017, 2018 and 2020, conditioned on the completion of the NRG Merger (together with the Change in Control Offers, the Debt Offers). NRG may, upon the terms and subject to the conditions of the NRG Merger Agreement, elect to also undertake a consent solicitation to alter the terms of any of our remaining notes due 2014, 2017, 2018 and 2020 outstanding after such tender or exchange offers. NRG intends to fund the Debt Offers and the related fees, commissions and expenses with a combination of funds available at each company (including funds available under existing credit facilities) and, to the extent necessary, new financing for which NRG obtained commitment letters from Credit Suisse Securities (USA) LLC and Morgan Stanley Senior Funding, Inc. to fund up to $1.6 billion under a new senior secured term loan facility, to the extent such funds are necessary to consummate the Debt Offers. On October 19, 2012, NRG elected to amend the commitment letters to permanently reduce the aggregate commitment amount to $1.0 billion and NRG indicated its intent to fund additional requirements, if any, from its available liquidity including cash on hand and credit facilities. NRG has agreed to use reasonable best efforts to obtain the financing, to the extent required, and we have agreed to use reasonable best efforts to cooperate in NRG’s efforts to obtain the financing. There are no financing conditions to the NRG Merger and the NRG Merger is not conditioned upon the completion of the Debt Offers or the funding of the financing.
In addition, we will experience an ownership change under the applicable tax rules as a result of the NRG Merger. Immediately following the NRG Merger, we and NRG will be members of the same consolidated federal income tax group. The ability of this consolidated tax group to deduct the pre-NRG Merger NOL carry forwards of GenOn against the post-merger taxable income of the group will be substantially limited as a result of the ownership change.
We anticipate completing the NRG Merger by the first quarter of 2013. Prior to the completion of the NRG Merger, we and NRG will continue to operate as independent companies. Except for specific references to the pending NRG Merger, the disclosures contained in this report on Form 10-Q relate solely to us. Information concerning the proposed NRG Merger is included in a joint proxy statement/prospectus contained in the registration statement on Form S-4, which NRG filed with the Securities and Exchange Commission in connection with the NRG Merger on October 5, 2012.
Basis of Presentation
The consolidated interim financial statements and notes (interim financial statements) are unaudited, omit certain disclosures and should be read in conjunction with our audited consolidated financial statements and notes in our 2011 Annual Report on Form 10-K. These interim financial statements have been prepared in accordance with GAAP from records maintained by us. All significant intercompany accounts and transactions have been eliminated in consolidation. The interim financial statements reflect all normal recurring adjustments necessary, in management’s opinion, to present fairly our financial position and results of operations for the reported periods. Amounts reported for interim periods may not be indicative of a full year period because of seasonal fluctuations in demand for electricity and energy services, changes in commodity prices, and changes in regulations, timing of maintenance and other expenditures, dispositions, changes in interest expense and other factors.
At September 30, 2012 and December 31, 2011, substantially all of our subsidiaries are wholly-owned and located in the United States. We do not consolidate five power generating facilities, which are under operating leases; a 50% equity investment in a cogeneration facility; and a VIE (MC Asset Recovery) for which we are not the primary beneficiary. See note 11 for further discussion of MC Asset Recovery.
The preparation of interim financial statements in conformity with GAAP requires management to make various estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent
assets and liabilities at the date of the interim financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates. Our significant estimates include:
· estimating the fair value of certain derivative contracts;
· estimating the inventory reserve;
· estimating future taxable income in evaluating the deferred tax asset valuation allowance;
· estimating the useful lives of long-lived assets;
· estimating future costs and the valuation of asset retirement obligations;
· estimating future cash flows in determining impairments of long-lived assets and definite-lived intangible assets;
· estimating the fair value and expected return on plan assets, discount rates and other actuarial assumptions used in estimating pension and other postretirement benefit plan liabilities; and
· estimating losses to be recorded for contingent liabilities.
We evaluate events that occur after the balance sheet date but before the financial statements are issued for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed herein.
Our results of operations for the three and nine months ended September 30, 2011 have been retroactively amended for the revisions to the provisional purchase price allocation in connection with the Mirant/RRI Merger.
We had disclosed in our 2011 Annual Report on Form 10-K that it was possible that RRI Energy had experienced an ownership change under the applicable tax rules as a result of the Mirant/RRI Merger. Based on further inquiries, we do not think that RRI Energy experienced an ownership change as a result of the Mirant/RRI Merger or following the Mirant/RRI Merger through December 31, 2011.
Funds on Deposit
Funds on deposit are included in current and noncurrent assets in the consolidated balance sheets. Funds on deposit include the following:
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| September 30, |
| December 31, |
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| 2012 |
| 2011 |
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Cash collateral posted — energy trading and marketing |
| $ | 150 |
| $ | 185 |
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Cash collateral posted — other operating activities(1) |
| 59 |
| 39 |
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Cash collateral posted — surety bonds(2) |
| 34 |
| 34 |
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GenOn Marsh Landing development project cash collateral posted(3) |
| 80 |
| 131 |
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Environmental compliance deposits(4) |
| 35 |
| 34 |
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GenOn Mid-Atlantic restricted cash(5) |
| — |
| 166 |
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Other |
| 36 |
| 16 |
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Total current and noncurrent funds on deposit |
| 394 |
| 605 |
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Less: Current funds on deposit |
| 261 |
| 422 |
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Total noncurrent funds on deposit |
| $ | 133 |
| $ | 183 |
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(1) Includes $32 million related to the Potomac River obligation under the 2008 agreement with the City of Alexandria, which were returned to us in October 2012. See note 2.
(2) Represents cash under surety bonds posted primarily with the PADEP related to environmental obligations.
(3) Represents cash-collateralized letters of credit to support the Marsh Landing development project.
(4) Represents deposits with the State of Pennsylvania to guarantee our obligations related to future closures of coal ash landfill sites and with the State of New Jersey to satisfy our obligations to remediate site contamination. See note 11.
(5) Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation, which was settled in June 2012. See note 11.
Inventories
Inventories were comprised of the following:
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| September 30, |
| December 31, |
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Fuel inventory: |
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Coal |
| $ | 153 |
| $ | 229 |
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Fuel oil |
| 87 |
| 108 |
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Natural gas |
| — |
| 1 |
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Other |
| 3 |
| 5 |
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Materials and supplies(1) |
| 169 |
| 201 |
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Purchased emissions allowances |
| 35 |
| 19 |
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Total inventories |
| $ | 447 |
| $ | 563 |
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(1) Amount is net of an inventory reserve of $35 million and $0 at September 30, 2012 and December 31, 2011, respectively. See note 2.
During the three months ended September 30, 2012 and 2011, we recorded $17 million and $1 million, respectively, and during the nine months ended September 30, 2012 and 2011, we recorded $82 million and $2 million, respectively, for lower of average cost or market valuation adjustments in cost of fuel, electricity and other products.
Capitalization of Interest Cost
We incurred the following interest costs:
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| Three Months Ended September 30, |
| Nine Months Ended September 30, |
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| 2012 |
| 2011 |
| 2012 |
| 2011 |
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Total interest costs |
| $ | 96 |
| $ | 91 |
| $ | 286 |
| $ | 301 |
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Capitalized and included in property, plant and equipment, net |
| (10 | ) | (5 | ) | (26 | ) | (10 | ) | ||||
Interest expense |
| $ | 86 |
| $ | 86 |
| $ | 260 |
| $ | 291 |
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The amounts of capitalized interest above include interest accrued. During the three months ended September 30, 2012 and 2011, cash paid for interest was $17 million and $16 million, respectively, of which $8 million and $4 million, respectively, were capitalized. During the nine months ended September 30, 2012 and 2011, cash paid for interest was $197 million and $234 million, respectively, of which $23 million and $9 million, respectively, were capitalized.
Guarantees and Indemnifications
We generally conduct business through various operating subsidiaries which enter into contracts as part of their business activities. In certain instances, the contractual obligations of such subsidiaries are guaranteed by, or otherwise supported by, us or another of our subsidiaries, including by letters of credit issued under the GenOn credit facilities. See note 5.
In addition, we, including our subsidiaries, enter into various contracts that include indemnification and guarantee provisions. Examples of these contracts include financing and lease arrangements, purchase and sale agreements, agreements to purchase or sell commodities, construction agreements and agreements with vendors. Although the primary obligation under such contracts is to pay money or render performance, such contracts may include obligations to indemnify the counterparty for damages arising from the breach thereof and, in certain instances, other existing or potential liabilities. In many cases, our maximum potential liability cannot be estimated because some of the underlying agreements contain no limits on potential liability.
We have guaranteed some non-qualified benefits of CenterPoint’s existing retirees at September 20, 2002. The estimated maximum potential amount of future payments under the guarantee is $54 million at September 30, 2012 and $3 million is recorded in the consolidated balance sheet for this item.
Recently Adopted Accounting Guidance
Fair Value Measurement and Disclosure. We adopted FASB accounting guidance for the first quarter of 2012 that requires disclosure of the following:
· quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy;
· for those fair value measurements categorized within Level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and
· the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.
See note 4 for these additional disclosures.
Comprehensive Income. We adopted FASB accounting guidance for the first quarter of 2012 that requires companies to report the components of comprehensive income in either (a) a continuous statement of comprehensive income or (b) two separate but consecutive statements. The guidance does not change the items that must be reported in comprehensive income. See the consolidated statements of comprehensive loss and note 9.
New Accounting Guidance Not Yet Adopted at September 30, 2012
Balance Sheet Offsetting. In December 2011, the FASB issued updated guidance to provide enhanced disclosures such that users of the financial statements will be able to better evaluate the effect or potential effect of netting arrangements in the balance sheet. The guidance requires improved information about financial instruments and derivative instruments that are either offset according to specific guidance or subject to an enforceable master netting agreement or similar arrangement. The disclosures will provide both net and gross information for these assets and liabilities. Although we do not currently elect to offset assets and liabilities within the scope of the guidance, expanded disclosures will be required starting for the first quarter of 2013, along with retrospective presentation of prior periods.
2. Retirements, Mothballing or Long-Term Protective Layup of Generating Facilities
Facilities Announced in 2012
We are subject to extensive environmental regulation by federal, state and local authorities under a variety of statutes, regulations and permits that address discharges into the air, water and soil, and the proper handling of solid, hazardous and toxic materials and waste. Complying with increasingly stringent environmental requirements involves significant capital and operating expenses. To the extent forecasted returns on investments necessary to comply with environmental regulations are insufficient for a particular facility, we plan to deactivate that facility. In determining the forecasted returns on investments, we factor in forecasted energy and capacity prices, expected capital expenditures, operating costs, property taxes and other factors. We deactivated the following coal-fired units at the referenced times: Niles unit 2 (108 MW) June 2012, Niles unit 1 (109 MW) October 2012, Elrama units 1-3 (289 MW) mothballed June 2012 (plan to retire in March 2014) and Elrama unit 4 (171 MW) mothballed October 2012 (plan to retire in March 2014). We expect to deactivate the following generating capacity, primarily coal-fired units, at the referenced times: Portland (401 MW) January 2015, Gilbert unit 8 (90 MW) January 2015, Avon Lake (732 MW) April 2015, New Castle (330 MW) April 2015, Titus (243 MW) April 2015, Shawville (597 MW) place in long-term protective layup in April 2015 and Glen Gardner (160 MW) May 2015. We filed for RMR arrangements for Niles unit 1 and Elrama unit 4 that were in effect from June 1 through September 30, 2012. These RMR arrangements are subject to final FERC rulings.
Potomac River Generating Facility
During 2011, we entered into an agreement with the City of Alexandria, Virginia to remove permanently from service our 482 MW Potomac River generating facility. The agreement, which amends our Project Schedule and Agreement, dated July 2008 with the City of Alexandria, provides for the retirement of the Potomac River generating facility on October 1, 2012, subject to the determination of PJM that the retirement of the facility will not affect reliability and the consent of PEPCO. PJM made the necessary determination and in June 2012 PEPCO gave its consent. As a result, the Potomac River generating facility was retired in October 2012. Upon retirement of the Potomac River generating facility, all funds in the escrow account ($32 million) established under the July 2008 agreement were distributed to us in October 2012. We therefore reversed $31 million and $1 million of the previously recorded obligation under the 2008 agreement with the City of Alexandria as a reduction in operations and maintenance expense during the second and fourth quarters of 2012, respectively.
Contra Costa Generating Facility
We entered into an agreement with PG&E in September 2009 for 674 MW at Contra Costa for the period from November 2011 through April 2013. At the end of the agreement, and subject to any necessary regulatory approvals, we have agreed to retire the Contra Costa facility.
Expenses, Property, Plant and Equipment, and Materials and Supplies Inventory Related to Deactivations
In connection with our decision to deactivate the generating facilities, we evaluated our materials and supplies inventory and determined that we have excess inventory. We established a reserve of $35 million (or $(0.04) per basic share) recorded to operations and maintenance expense during the first quarter of 2012 relating to our excess inventory. We will continue to monitor the inventory balances and could make changes to the reserve in the future. At September 30, 2012, the aggregate carrying value of property, plant and equipment, net and materials and supplies inventory, net for the generating facilities with an aggregate of 4,386 MW which we announced would be deactivated between 2012 and 2015 was $129 million and $25 million, respectively. In addition to the excess materials and supplies inventory reserve recorded in the first quarter, we incurred $8 million and $11 million during the three and nine months ended September 30, 2012, respectively for costs to deactivate generating facilities, which is included in operations and maintenance expense. We expect to incur additional costs in the future in connection with the deactivations, such as severance and other plant shutdown costs.
If market conditions and/or environmental and regulatory factors or assumptions change in the future, forecasted returns on investments necessary to comply with environmental regulations could change resulting in possible incremental investments if returns improve or deactivation of additional generating units or facilities if returns deteriorate. Such deactivations could result in additional charges, including impairments, severance costs and other plant shutdown costs.
3. Long-Lived Assets Impairments
Background
On July 20, 2012, we entered into the NRG Merger Agreement with NRG Energy, Inc. and a direct wholly-owned subsidiary of NRG. We viewed the execution of the NRG Merger Agreement as a triggering event under accounting guidance and evaluated our long-lived assets for impairment.
For purposes of impairment testing, a long-lived asset must be grouped at the lowest level of identifiable cash flows. Each of our generating facilities is viewed as an individual asset group. Upon completion of the assessment, we determined that the Portland and Titus generating facilities were impaired at September 30, 2012, as the carrying values exceeded the undiscounted cash flows.
Assumptions and Results
Our review of the long-lived assets included assumptions about the following: (a) electricity, fuel and emissions prices, (b) capacity prices, (c) impact of environmental regulations, including costs of CO2 allowances under a potential cap-and-trade program, (d) timing and extent of generating capacity additions and retirements and (e) future capital expenditure requirements related to the generating facilities.
Our assumptions related to future prices of electricity, fuel, emissions allowances, and capacity were based on observable market prices to the extent available. Longer term power and capacity prices were derived from proprietary fundamental market modeling and analysis. The long-term capacity prices were based on estimated revenue requirements to incentivize new generation when needed to maintain reliability standards. For markets with established capacity markets, such as PJM, these estimates are generally consistent with the current structures. The assumptions regarding electricity demand were based on forecasts available from each ISO or NERC region, as applicable. Assumptions for generating capacity additions and retirements included publicly available announcements, which take into account renewable sources of electricity, as well as the need for capacity to maintain reliability in the longer term. In addition, we previously announced our plans for deactivation of the Portland and Titus generating facilities. See note 2.
We recorded impairment losses of $37 million and $10 million during the three months ended September 30, 2012 in the consolidated statement of operations to reduce the carrying values of the Portland and Titus generating facilities, respectively, to their estimated fair values.
The following table sets forth by level within the fair value hierarchy our assets that were accounted for at fair value on a non-recurring basis. All of our assets that were measured at fair value as a result of impairment losses recorded during the current period were categorized in Level 3 at September 30, 2012:
|
| Fair Value at September 30, 2012 |
| |||||||||||||
|
| Quoted Prices in |
| Significant |
| Significant |
| Total |
| Loss |
| |||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| |||||
Portland |
| $ | — |
| $ | — |
| $ | 17 |
| $ | 17 |
| $ | 37 |
|
Titus |
| — |
| — |
| 15 |
| 15 |
| 10 |
| |||||
Total |
| $ | — |
| $ | — |
| $ | 32 |
| $ | 32 |
| $ | 47 |
|
4. Financial Instruments
Derivatives and Hedging Activities
In connection with the business of generating electricity, we are exposed to energy commodity price risk associated with the acquisition of fuel and emissions allowances needed to generate electricity, the price of electricity produced and sold, and the fair value of fuel inventories. Through our asset management activities, we enter into a variety of exchange-traded and OTC energy and energy-related derivative financial instruments, such as forward contracts, futures contracts, option contracts and financial swap agreements to manage exposure to commodity price risks. These contracts have varying terms and durations, which range from a few days to years, depending on the instrument. Our proprietary trading activities also utilize similar derivative contracts in markets where we have a physical presence to attempt to generate incremental gross margin. Our fuel oil management activities use derivative financial instruments to hedge economically the fair value of physical fuel oil inventories, optimize the approximately two million barrels of storage capacity that we own, and attempt to profit from market opportunities related to timing and/or differences in the pricing of various products. The open positions in our trading activities comprising proprietary trading and fuel oil management activities expose us to risks associated with changes in energy commodity prices.
Derivative financial instruments are recorded in the consolidated balance sheets at fair value, except for derivative contracts that qualify for and for which we have elected the normal purchase or normal sale exceptions, which are not reflected in the consolidated balance sheet or results of operations prior to accrual of the settlement. We present our derivative contract assets and liabilities on a gross basis (regardless of master netting arrangements with the same counterparty). Cash collateral amounts are also presented on a gross basis.
During the second quarter of 2012, we could no longer assert that physical delivery was probable for the remaining coal agreements for which we had elected the normal purchase exception. As such, the normal purchase exception was removed, and we are required to apply fair value accounting to these contracts in the current period and prospectively.
If certain criteria are met, a derivative financial instrument may be designated as a fair value hedge or cash flow hedge. In 2010, GenOn Marsh Landing entered into interest rate protection agreements (interest rate swaps) in connection with its project financing, which have been designated as cash flow hedges. GenOn Marsh Landing entered into the interest rate swaps to reduce the risks with respect to the variability of the interest rates for the term loan. With the exception of these interest rate swaps, we did not have any other derivative financial instruments designated as fair value or cash flow hedges for accounting purposes during the nine months ended September 30, 2012 or 2011.
The changes in fair value of cash flow hedges are deferred in accumulated other comprehensive loss, net of tax, to the extent the contracts are, or have been, effective as hedges, until the forecasted transactions affect earnings. We record immediately into earnings the ineffective portion of changes in fair value of cash flow hedges.
Derivative financial instruments designated as cash flow hedges must have a high correlation between price movements in the derivative and the hedged item. If and when an acceptable level of correlation no longer exists, hedge accounting ceases and changes in fair value are recognized in our results of operations. If it becomes probable that a forecasted transaction will not occur, we immediately recognize the related deferred gains or losses in our results of operations. Changes in fair value of the associated hedging instrument are then recognized immediately in earnings for the remainder of the contract term unless a new hedging relationship is designated.
For our derivative financial instruments that have not been designated as cash flow hedges for accounting purposes, changes in such instruments’ fair values are recognized currently in earnings. Our derivative financial instruments are categorized based on the business objective the instrument is expected to achieve: asset management or trading, which includes proprietary trading and fuel oil management. For asset management activities, changes in fair value and settlement of derivative financial instruments used to hedge electricity economically are reflected in operating revenue and changes in fair value and settlement of derivative financial instruments used to hedge fuel economically are reflected in cost of fuel, electricity and other products in the consolidated statements of operations. Changes in the fair value and settlements of derivative financial instruments for proprietary trading and fuel oil management activities are recorded on a net basis as operating revenue in the consolidated statements of operations.
We also consider risks associated with interest rates, counterparty credit and our own non-performance risk when valuing derivative financial instruments. The nominal value of the derivative contract assets and liabilities is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the transactions being valued.
The following table presents the fair value of derivative financial instruments:
|
| Derivative Contract Assets |
| Derivative Contract Liabilities |
| Net Derivative |
| |||||||||
|
| Current |
| Long-Term |
| Current |
| Long-Term |
| Assets (Liabilities) |
| |||||
|
| (in millions) |
| |||||||||||||
September 30, 2012 |
|
|
|
|
|
|
|
|
|
|
| |||||
Commodity Contracts: |
|
|
|
|
|
|
|
|
|
|
| |||||
Asset management |
| $ | 462 |
| $ | 579 |
| $ | (222 | ) | $ | (129 | ) | $ | 690 |
|
Trading activities |
| 174 |
| 9 |
| (170 | ) | (11 | ) | 2 |
| |||||
Total commodity contracts |
| 636 |
| 588 |
| (392 | ) | (140 | ) | 692 |
| |||||
Interest Rate Contracts |
| — |
| — |
| (6 | ) | (44 | ) | (50 | ) | |||||
Total derivatives |
| $ | 636 |
| $ | 588 |
| $ | (398 | ) | $ | (184 | ) | $ | 642 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
December 31, 2011 |
|
|
|
|
|
|
|
|
|
|
| |||||
Commodity Contracts: |
|
|
|
|
|
|
|
|
|
|
| |||||
Asset management |
| $ | 538 |
| $ | 730 |
| $ | (255 | ) | $ | (97 | ) | $ | 916 |
|
Trading activities |
| 461 |
| 3 |
| (464 | ) | (3 | ) | (3 | ) | |||||
Total commodity contracts |
| 999 |
| 733 |
| (719 | ) | (100 | ) | 913 |
| |||||
Interest Rate Contracts |
| — |
| — |
| (1 | ) | (31 | ) | (32 | ) | |||||
Total derivatives |
| $ | 999 |
| $ | 733 |
| $ | (720 | ) | $ | (131 | ) | $ | 881 |
|
The following table presents the net gains (losses) for derivative financial instruments recognized in income in the consolidated statements of operations:
|
| Three Months Ended September 30, |
| ||||||||||
|
| 2012 |
| 2011 |
| ||||||||
Derivatives Not Designated as Hedging Instruments |
| Operating |
| Cost of Fuel, |
| Operating |
| Cost of Fuel, |
| ||||
|
| (in millions) |
| ||||||||||
Asset Management Commodity Contracts: |
|
|
|
|
|
|
|
|
| ||||
Unrealized |
| $ | (242 | ) | $ | 58 |
| $ | 38 |
| $ | (11 | ) |
Realized(1)(2) |
| 102 |
| (14 | ) | 54 |
| (27 | ) | ||||
Total asset management |
| $ | (140 | ) | $ | 44 |
| $ | 92 |
| $ | (38 | ) |
|
|
|
|
|
|
|
|
|
| ||||
Trading Commodity Contracts: |
|
|
|
|
|
|
|
|
| ||||
Unrealized |
| $ | (3 | ) | $ | — |
| $ | 11 |
| $ | — |
|
Realized(1)(2) |
| 8 |
| — |
| (13 | ) | — |
| ||||
Total trading |
| $ | 5 |
| $ | — |
| $ | (2 | ) | $ | — |
|
|
|
|
|
|
|
|
|
|
| ||||
Total derivatives |
| $ | (135 | ) | $ | 44 |
| $ | 90 |
| $ | (38 | ) |
(1) Represents the total cash settlements of derivative financial instruments during each reporting period (composed of the sum of the quarterly settlements) that existed at the beginning of each respective period.
(2) Excludes settlement value of fuel contracts classified as inventory.
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2012 |
| 2011 |
| ||||||||
Derivatives Not Designated as Hedging Instruments |
| Operating |
| Cost of Fuel, |
| Operating |
| Cost of Fuel, |
| ||||
|
| (in millions) |
| ||||||||||
Asset Management Commodity Contracts: |
|
|
|
|
|
|
|
|
| ||||
Unrealized |
| $ | (205 | ) | $ | (25 | ) | $ | (85 | ) | $ | 27 |
|
Realized(1)(2) |
| 428 |
| (42 | ) | 194 |
| (84 | ) | ||||
Total asset management |
| $ | 223 |
| $ | (67 | ) | $ | 109 |
| $ | (57 | ) |
|
|
|
|
|
|
|
|
|
| ||||
Trading Commodity Contracts: |
|
|
|
|
|
|
|
|
| ||||
Unrealized |
| $ | 1 |
| $ | — |
| $ | (1 | ) | $ | — |
|
Realized(1)(2) |
| 3 |
| — |
| (8 | ) | — |
| ||||
Total trading |
| $ | 4 |
| $ | — |
| $ | (9 | ) | $ | — |
|
|
|
|
|
|
|
|
|
|
| ||||
Total derivatives |
| $ | 227 |
| $ | (67 | ) | $ | 100 |
| $ | (57 | ) |
(1) Represents the total cash settlements of derivative financial instruments during each reporting period (composed of the sum of the quarterly settlements) that existed at the beginning of each respective period.
(2) Excludes settlement value of fuel contracts classified as inventory.
The following table presents the losses on the interest rate swaps designated as cash flow hedges in the consolidated statements of operations and comprehensive income/loss:
|
| Three Months Ended September 30, |
| Nine Months Ended September 30, |
| ||||||||
|
| 2012 |
| 2011 |
| 2012 |
| 2011 |
| ||||
|
| (in millions) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Recognized in earnings on derivatives(1)(2) |
| $ | — |
| $ | — |
| $ | — |
| $ | — |
|
Valuation adjustments(3) |
| — |
| 4 |
| — |
| 4 |
| ||||
(1) Represents the ineffective portion of the interest rate swaps classified as cash flow hedges and recorded in interest expense.
(2) All of the forecasted transactions (future interest payments) were deemed probable of occurring; therefore, no cash flow hedges were discontinued and no amount was recognized in our results of operations as a result of discontinued cash flow hedges.
(3) Represents the default risk of the counterparties to these transactions and our own non-performance risk. The effect of these valuation adjustments is recorded in interest expense.
At September 30, 2012, the maximum length of time we are hedging our exposure to the variability in future cash flows that may result from changes in interest rates is 11 years. Because a significant portion of the interest expense incurred by GenOn Marsh Landing during construction will be capitalized, amounts included in accumulated other comprehensive loss associated with construction period interest payments will be reclassified to property, plant and equipment and depreciated over the expected useful life of the Marsh Landing generating facility once it commences commercial operations in mid-2013. Actual amounts reclassified into earnings could vary from the amounts currently recorded as a result of future changes in interest rates. See note 9 for the effect of the cash flow hedges in comprehensive income/loss.
The following tables present the notional quantity on long (short) positions for derivative financial instruments:
|
| Notional Volumes at September 30, 2012 |
| ||||
Derivative Instruments |
| Derivative |
| Derivative |
| Net |
|
|
| (in millions) |
| ||||
Commodity Contracts (in equivalent MWh): |
|
|
|
|
|
|
|
Power(1) |
| (16 | ) | (53 | ) | (69 | ) |
Natural gas |
| 2 |
| (2 | ) | — |
|
Coal |
| (1 | ) | 18 |
| 17 |
|
Interest Rate Contracts (in dollars)(2) |
| — |
| 475 |
| 475 |
|
(1) Includes MWh equivalent of natural gas transactions used to hedge power economically.
(2) Beginning in mid-2013, the notional amount will increase to $500 million.
|
| Notional Volumes at December 31, 2011 |
| ||||
Derivative Instruments |
| Derivative |
| Derivative |
| Net |
|
|
| (in millions) |
| ||||
Commodity Contracts (in equivalent MWh): |
|
|
|
|
|
|
|
Power(1) |
| (130 | ) | 73 |
| (57 | ) |
Natural gas |
| (8 | ) | 10 |
| 2 |
|
Coal |
| 3 |
| 12 |
| 15 |
|
Interest Rate Contracts (in dollars)(2) |
| — |
| 475 |
| 475 |
|
(1) Includes MWh equivalent of natural gas transactions used to hedge power economically.
(2) Beginning in mid-2013, the notional amount will increase to $500 million.
Fair Value Measurements
Fair Value Hierarchy and Valuation Techniques. We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable prices for exchange-traded instruments to price curves that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:
Level 1: Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes natural gas and crude oil futures traded on the NYMEX and swaps cleared against NYMEX prices. Interest bearing funds and trading securities are also valued using Level 1 inputs.
Level 2: Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. This category primarily includes non-exchange traded derivatives such as OTC forwards, swaps and options, and certain energy derivative instruments that are cleared and settled through exchanges. This category also includes interest rate swaps.
Level 3: Represents commodity derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources (such as implied volatilities and correlations). The OTC, complex or structured derivative instruments that are transacted in less liquid markets with limited pricing information are included in Level 3. Examples are coal contracts, power transmission congestion products, less liquid power and natural gas contracts, and options valued using internally developed inputs.
In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls must be determined based on the lowest level input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and consideration of factors specific to the asset or liability.
A significant amount of the fair value of our derivative contract assets and liabilities is based on observable quoted prices from exchanges and indicative quoted prices from independent brokers in active markets that regularly facilitate our transactions. An active market is considered to have transactions with sufficient frequency and volume to provide pricing information on an ongoing basis. We think that these prices represent the best available information for valuation purposes. In determining the fair value of derivative contract assets and liabilities, we use third-party market pricing where available. For transactions classified in Level 1 of the fair value hierarchy, we use the unadjusted published settled prices on the valuation date. For transactions classified in Level 2 of the fair value hierarchy, we value these transactions using indicative quoted prices from independent brokers or other widely-accepted valuation methodologies. Transactions are classified in Level 2 if substantially all (greater than 90%) of the fair value can be corroborated using observable market inputs such as transactable broker quotes. In accordance with the exit price objective under the fair value measurements accounting guidance, the fair value of our derivative contract assets and liabilities is determined based on the net underlying position of the recorded derivative contract assets and liabilities using bid prices for assets and ask prices for liabilities. The quotes we obtain from brokers are non-binding in nature, but are from brokers that typically transact in the market being quoted and are based on their knowledge of market transactions on the valuation date. We typically obtain multiple broker quotes as of the valuation date that extend for the tenor of the underlying contracts for each delivery location. The number of quotes that we can obtain depends on the relative liquidity of the delivery location on the valuation date. If multiple broker quotes are received for a contract, we use an average of the quoted bid or ask prices. If only one broker quote is received for a delivery location and it cannot be validated through other external sources, we will assign the quote to a lower level within the fair value hierarchy. In some instances, we may combine broker quotes for a liquid delivery hub with broker quotes for the price spread between the liquid delivery hub and the delivery location under the contract. We also may apply interpolation techniques to value monthly strips if broker quotes are only available on a seasonal or annual basis. We perform validation procedures on the broker quotes at least monthly. The validation procedures include reviewing the quotes for accuracy and comparing them to our internal price curves. In certain instances, we may exclude from consideration a broker quote if it is a clear outlier and other quotes are obtained. At September 30, 2012, we obtained broker quotes for 100% of our delivery locations classified in Level 2 of the fair value hierarchy.
Inactive markets are considered to be those markets with few transactions, noncurrent pricing or prices that vary over time or among market makers. Our transactions in Level 3 of the fair value hierarchy may involve transactions whereby observable market data, such as broker quotes, are not available for substantially all of the tenor of the contract or we are only able to obtain indicative broker quotes that cannot be corroborated by observable market data. In such cases, we may apply valuation techniques such as extrapolation and other quantitative methods to determine fair value. Our techniques for fair value estimation include assumptions for market prices, including market price volatility and the volatility of the spread between multiple market prices. Proprietary models may also be used to estimate the fair value of derivative contract assets and liabilities that may be structured or otherwise tailored. The degree of estimation increases for longer duration contracts, contracts with multiple pricing features, option contracts and off-hub delivery points. At September 30, 2012, the assets and liabilities classified as Level 3 in the fair value hierarchy represented 3% of total derivative contract assets and 22% of total derivative contract liabilities.
The fair value of our derivative contract assets and liabilities is also affected by assumptions as to time value, credit risk and non-performance risk. The nominal value of derivatives is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the transaction. Derivative contract assets are reduced to reflect the estimated default risk of counterparties on their contractual obligations. The counterparty default risk for our overall net position is measured based on published spreads on credit default swaps for counterparties, where available, or proxies based upon published spreads, applied to our current exposure and potential loss exposure from the financial commitments in our risk management portfolio. The fair value of derivative contract liabilities is reduced to reflect the estimated risk of default on contractual obligations to counterparties and is measured based on
published default rates of our debt, where available, or proxies based upon published spreads. Credit risk and non-performance risk are calculated with consideration of our master netting agreements with counterparties and our exposure is reduced by cash collateral posted to us against these obligations.
Information about Sensitivity to Changes in Significant Unobservable Inputs. The significant unobservable inputs used in the fair value measure of our commodity instruments categorized within Level 3 of the fair value hierarchy are estimates of future market volatility, estimates of forward congestion power price spreads and estimates of counterparty credit risk and our own non-performance risk. These assumptions are generally independent of each other. Volatility curves and power prices spreads are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price or volatility of the spread on a long position would result in a higher fair value measurement. Increases in the price or volatility of the spread on a short position would result in a lower fair value measurement. A change in the assumption used for the probability of default is accompanied by a directionally similar change in the adjustment to reflect the estimated default risk of counterparties on their contractual obligations, or the estimated risk of default on our own contractual obligations to counterparties.
Risk Management. The Risk and Finance Oversight Committee of the Board of Directors is responsible for oversight of the risk management of our commercial activities and enterprise risk management. In order to ensure proper daily oversight of our commercial risk controls, the Risk and Finance Oversight Committee has established the ROC with membership determined by the Chief Executive Officer. The ROC is responsible for ensuring that the necessary policies, procedures and systems are in place to measure, monitor and report on the risks associated with our commercial activities. The ROC is also responsible for safeguarding proprietary models against the negative impact of inadequate model control by providing oversight and control to model development, back-testing and verification, automation, security and revision control. The ROC must approve new valuation models or fundamental modifications to existing models. Model forecasts are back-tested annually and the results reviewed with the ROC.
Comprehensive, accurate and timely reporting and monitoring is essential to effectively manage market, credit and operational risks and to protect against large unanticipated losses. Management has established reporting and monitoring functions, which include daily and weekly reporting, to inform the ROC and Chief Risk Officer of its activities. The chair of the ROC reports to the Risk and Finance Oversight Committee on a quarterly basis, or more frequently, if events and circumstances dictate.
Fair Value of Derivative Instruments and Certain Other Assets. The fair value measurements of financial assets and liabilities by class are as follows:
|
| September 30, 2012 |
| ||||||||||
|
| Level 1(1) |
| Level 2(1)(2) |
| Level 3 |
| Total |
| ||||
|
| (in millions) |
| ||||||||||
Derivative contract assets: |
|
|
|
|
|
|
|
|
| ||||
Commodity Contracts |
|
|
|
|
|
|
|
|
| ||||
Asset Management: |
|
|
|
|
|
|
|
|
| ||||
Power |
| $ | 120 |
| $ | 903 |
| $ | 12 |
| $ | 1,035 |
|
Fuel |
| — |
| 1 |
| 5 | (3) | 6 |
| ||||
Total Asset Management |
| 120 |
| 904 |
| 17 |
| 1,041 |
| ||||
Trading Activities |
| 16 |
| 150 |
| 17 |
| 183 |
| ||||
Total derivative contract assets |
| $ | 136 |
| $ | 1,054 |
| $ | 34 |
| $ | 1,224 |
|
|
|
|
|
|
|
|
|
|
| ||||
Derivative contract liabilities: |
|
|
|
|
|
|
|
|
| ||||
Commodity Contracts |
|
|
|
|
|
|
|
|
| ||||
Asset Management: |
|
|
|
|
|
|
|
|
| ||||
Power |
| $ | 48 |
| $ | 180 |
| $ | 5 |
| $ | 233 |
|
Fuel |
| 2 |
| 1 |
| 115 | (3) | 118 |
| ||||
Total Asset Management |
| 50 |
| 181 |
| 120 |
| 351 |
| ||||
Trading Activities |
| 18 |
| 154 |
| 9 |
| 181 |
| ||||
Interest Rate Contracts |
| — |
| 50 |
| — |
| 50 |
| ||||
Total derivative contract liabilities |
| $ | 68 |
| $ | 385 |
| $ | 129 |
| $ | 582 |
|
|
|
|
|
|
|
|
|
|
| ||||
Interest-bearing funds(4) |
| $ | 2,004 |
| $ | — |
| $ | — |
| $ | 2,004 |
|
Other assets(5) |
| $ | 20 |
| $ | — |
| $ | — |
| $ | 20 |
|
(1) Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no transfers during the nine months ended September 30, 2012.
(2) Option contracts comprised 1% of net derivative contract assets.
(3) Primarily relates to coal.
(4) Represents investments in money market funds and treasury bills and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet. Of interest-bearing funds, we had $1.845 billion included in cash and cash equivalents, $54 million included in funds on deposit and $105 million included in other noncurrent assets.
(5) Relates to mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees.
|
| December 31, 2011 |
| ||||||||||
|
| Level 1(1) |
| Level 2(1)(2) |
| Level 3 |
| Total |
| ||||
|
| (in millions) |
| ||||||||||
Derivative contract assets: |
|
|
|
|
|
|
|
|
| ||||
Commodity Contracts |
|
|
|
|
|
|
|
|
| ||||
Asset Management: |
|
|
|
|
|
|
|
|
| ||||
Power |
| $ | 102 |
| $ | 1,136 |
| $ | 19 |
| $ | 1,257 |
|
Fuel |
| 2 |
| — |
| 9 | (3) | 11 |
| ||||
Total Asset Management |
| 104 |
| 1,136 |
| 28 |
| 1,268 |
| ||||
Trading Activities |
| 124 |
| 302 |
| 38 |
| 464 |
| ||||
Total derivative contract assets |
| $ | 228 |
| $ | 1,438 |
| $ | 66 |
| $ | 1,732 |
|
|
|
|
|
|
|
|
|
|
| ||||
Derivative contract liabilities: |
|
|
|
|
|
|
|
|
| ||||
Commodity Contracts |
|
|
|
|
|
|
|
|
| ||||
Asset Management: |
|
|
|
|
|
|
|
|
| ||||
Power |
| $ | 45 |
| $ | 206 |
| $ | 2 |
| $ | 253 |
|
Fuel |
| 19 |
| 1 |
| 79 | (3) | 99 |
| ||||
Total Asset Management |
| 64 |
| 207 |
| 81 |
| 352 |
| ||||
Trading Activities |
| 142 |
| 309 |
| 16 |
| 467 |
| ||||
Interest Rate Contracts |
| — |
| 32 |
| — |
| 32 |
| ||||
Total derivative contract liabilities |
| $ | 206 |
| $ | 548 |
| $ | 97 |
| $ | 851 |
|
|
|
|
|
|
|
|
|
|
| ||||
Interest-bearing funds(4) |
| $ | 1,985 |
| $ | — |
| $ | — |
| $ | 1,985 |
|
Other assets(5) |
| $ | 20 |
| $ | — |
| $ | — |
| $ | 20 |
|
(1) Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no significant transfers during 2011.
(2) Option contracts comprised 1% of net derivative contract assets.
(3) Primarily relates to coal.
(4) Represents investments in money market funds and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet. Of interest-bearing funds, we had $1.626 billion included in cash and cash equivalents, $202 million included in funds on deposit and $157 million included in other noncurrent assets.
(5) Relates to mutual funds held in a rabbi trust for non-qualified deferred compensation plans for some key and highly compensated employees.
The following is a reconciliation of changes (comprised of the sum of the quarterly changes) in fair value of net commodity derivative contract assets and liabilities classified as Level 3 during the nine months ended September 30, 2012 and 2011:
|
| Net Derivatives Contracts (Level 3) |
| |||||||
|
| Asset |
| Trading |
| Total |
| |||
|
| (in millions) |
| |||||||
|
|
|
|
|
|
|
| |||
Balance, January 1, 2012 (net asset (liability)) |
| $ | (53 | ) | $ | 22 |
| $ | (31 | ) |
Total gains (losses) realized/unrealized: |
|
|
|
|
|
|
| |||
Included in earnings(1) |
| (112 | ) | 12 |
| (100 | ) | |||
Purchases(2) |
| — |
| — |
| — |
| |||
Issuances(2) |
| — |
| — |
| — |
| |||
Settlements(3) |
| 62 |
| (26 | ) | 36 |
| |||
Transfers into Level 3(4) |
| — |
| — |
| — |
| |||
Transfers out of Level 3(4) |
| — |
| — |
| — |
| |||
Balance, September 30, 2012 (net asset (liability)) |
| $ | (103 | ) | $ | 8 |
| $ | (95 | ) |
|
|
|
|
|
|
|
| |||
Balance, January 1, 2011 (net asset (liability)) |
| $ | (70 | ) | $ | 2 |
| $ | (68 | ) |
Total gains (losses) realized/unrealized: |
|
|
|
|
|
|
| |||
Included in earnings (1) |
| 5 |
| 9 |
| 14 |
| |||
Purchases(2) |
| — |
| — |
| — |
| |||
Issuances(2) |
| — |
| — |
| — |
| |||
Settlements(3) |
| 7 |
| (5 | ) | 2 |
| |||
Transfers into Level 3(4) |
| — |
| — |
| — |
| |||
Transfers out of Level 3(4) |
| 12 |
| — |
| 12 |
| |||
Balance, September 30, 2011 (net asset (liability)) |
| $ | (46 | ) | $ | 6 |
| $ | (40 | ) |
(1) Represents the fair value, as of the end of each reporting period, of Level 3 contracts entered into during each reporting period and the gains and losses attributable to Level 3 contracts that existed as of the beginning of each reporting period and were still held at the end of each reporting period.
(2) Contracts entered into during each reporting period are reported with other changes in fair value.
(3) Represents the reversal of previously recognized unrealized gains and losses from settlement of contracts during each reporting period.
(4) Denotes the total contracts that existed at the beginning of each reporting period and were still held at the end of each reporting period that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during each reporting period. Amounts reflect fair value as of the end of each reporting period.
The following tables present the amounts included in income related to derivative contract assets and liabilities classified as Level 3:
|
| Three Months Ended September 30, |
| ||||||||||||||||
|
| 2012 |
| 2011 |
| ||||||||||||||
|
| Operating |
| Cost of |
| Total |
| Operating |
| Cost of |
| Total |
| ||||||
|
| (in millions) |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Gains (losses) included in income |
| $ | (19 | ) | $ | 55 |
| $ | 36 |
| $ | (3 | ) | $ | (10 | ) | $ | (13 | ) |
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at September 30 |
| $ | (17 | ) | $ | 54 |
| $ | 37 |
| $ | (2 | ) | $ | (11 | ) | $ | (13 | ) |
|
| Nine Months Ended September 30, |
| ||||||||||||||||
|
| 2012 |
| 2011 |
| ||||||||||||||
|
| Operating |
| Cost of |
| Total |
| Operating |
| Cost of |
| Total |
| ||||||
|
| (in millions) |
| ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Gains (losses) included in income |
| $ | (23 | ) | $ | (41 | ) | $ | (64 | ) | $ | 3 |
| $ | 25 |
| $ | 28 |
|
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at September 30 |
| $ | (18 | ) | $ | (81 | ) | $ | (99 | ) | $ | 5 |
| $ | 23 |
| $ | 28 |
|
Information about Sensitivity to Changes in Significant Unobservable Inputs. The following table presents the range of sensitivity of unobservable inputs used in fair value measurements categorized within Level 3 of the fair value hierarchy:
|
| Quantitative Information about Level 3 Fair Value Measurements(1) |
| |||||||
|
| Net Fair Value at |
| Valuation |
| Unobservable Input |
| Range (Weighted |
| |
|
| (in millions) |
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| |
Credit valuation adjustment |
| $ | 1 |
| Internal model |
| Own credit risk |
| 20% to (20)% | (2) |
(1) Excludes immaterial unobservable inputs related to power transmission congestion products, power swaps, spread options, physical gas premiums on transactions and credit valuation adjustment related to counterparty credit risk.
(2) Represents the range of the credit default swap spread curves used in the valuation analysis that we think market participants might use when pricing the contracts.
At September 30, 2012, net fair value asset of $10 million for power transactions and net fair value liability of $110 million for fuel transactions classified as Level 3 were priced based on unadjusted indicative broker quotes that cannot be corroborated by observable market data. Quantitative information is excluded for these fair value measurements.
Counterparty Credit Concentration Risk
We are exposed to the default risk of the counterparties with which we transact. We manage our credit risk by entering into master netting agreements and requiring most counterparties to post cash collateral or other credit enhancements based on the net exposure and the credit standing of the counterparty. We also have non-collateralized power hedges entered into by GenOn Mid-Atlantic. These transactions are senior unsecured obligations of GenOn Mid-Atlantic and the counterparties and have not required either party to post cash collateral for initial margin. Since April 2012, the counterparties, in some cases, have been required to post cash collateral to secure credit exposure above an agreed threshold as a result of changes in power or natural gas prices. At September 30, 2012 and December 31, 2011, $108 million and $4 million, respectively, of cash collateral posted by counterparties under master netting agreements were included in accounts payable and accrued liabilities in the consolidated balance sheets. Our credit valuation adjustment on derivative contract assets was $9 million and $48 million at September 30, 2012 and December 31, 2011, respectively.
We monitor counterparty credit concentration risk on both an individual basis and a group counterparty basis. The following tables highlight the credit quality and the balance sheet settlement exposures related to these activities:
|
| September 30, 2012 |
| ||||||||||||
Credit Rating Equivalent |
| Gross Exposure |
| Net Exposure |
| Collateral(3) |
| Exposure Net |
| % of Net |
| ||||
|
| (dollars in millions) |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||
Clearing and Exchange |
| $ | 432 |
| $ | 159 |
| $ | 159 |
| $ | — |
| — |
|
Investment Grade: |
|
|
|
|
|
|
|
|
|
|
| ||||
Financial institutions |
| 721 |
| 686 |
| 106 |
| 580 |
| 69 | % | ||||
Energy companies |
| 362 |
| 228 |
| — |
| 228 |
| 27 | % | ||||
Non-investment Grade: |
|
|
|
|
|
|
|
|
|
|
| ||||
Energy companies |
| 8 |
| 5 |
| 1 |
| 4 |
| 1 | % | ||||
No External Ratings: |
|
|
|
|
|
|
|
|
|
|
| ||||
Internally-rated investment grade |
| 21 |
| 19 |
| — |
| 19 |
| 2 | % | ||||
Internally-rated non-investment grade |
| 6 |
| 5 |
| — |
| 5 |
| 1 | % | ||||
Total |
| $ | 1,550 |
| $ | 1,102 |
| $ | 266 |
| $ | 836 |
| 100 | % |
|
| December 31, 2011 |
| ||||||||||||
Credit Rating Equivalent |
| Gross Exposure |
| Net Exposure |
| Collateral(3) |
| Exposure Net |
| % of Net |
| ||||
|
| (dollars in millions) |
| ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
| ||||
Clearing and Exchange |
| $ | 724 |
| $ | 223 |
| $ | 223 |
| $ | — |
| — |
|
Investment Grade: |
|
|
|
|
|
|
|
|
|
|
| ||||
Financial institutions |
| 860 |
| 817 |
| — |
| 817 |
| 78 | % | ||||
Energy companies |
| 421 |
| 195 |
| 3 |
| 192 |
| 18 | % | ||||
Non-investment Grade: |
|
|
|
|
|
|
|
|
|
|
| ||||
Energy companies |
| 13 |
| 5 |
| 1 |
| 4 |
| — |
| ||||
No External Ratings: |
|
|
|
|
|
|
|
|
|
|
| ||||
Internally-rated investment grade |
| 18 |
| 18 |
| — |
| 18 |
| 2 | % | ||||
Internally-rated non-investment grade |
| 15 |
| 15 |
| — |
| 15 |
| 2 | % | ||||
Total |
| $ | 2,051 |
| $ | 1,273 |
| $ | 227 |
| $ | 1,046 |
| 100 | % |
(1) Gross exposure before collateral represents credit exposure, including both realized and unrealized transactions, before (a) applying the terms of master netting agreements with counterparties and (b) netting of transactions with clearing brokers and exchanges. The table excludes amounts related to contracts classified as normal purchases/normal sales and non-derivative contractual commitments that are not recorded at fair value in the consolidated balance sheets, except for any related accounts receivable. Such contractual commitments contain credit and economic risk if a counterparty does not perform. Non-performance could have a material adverse effect on our future results of operations, financial condition and cash flows.
(2) Net exposure before collateral represents the credit exposure, including both realized and unrealized transactions, after applying the terms of master netting agreements and the netting of transactions with clearing brokers and exchanges.
(3) Collateral includes cash and letters of credit received from counterparties.
We had credit exposure to three and two investment grade counterparties at September 30, 2012 and December 31, 2011, respectively, each representing an exposure of more than 10% of total credit exposure, net of collateral and totaling $519 million and $664 million at September 30, 2012 and December 31, 2011, respectively.
GenOn Credit Risk
Our standard industry contracts contain credit-risk-related contingent features such as ratings-related thresholds whereby we would be required to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade. Additionally, some of our contracts contain adequate assurance language, which is generally subjective in nature that could require us to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade. However, as a result of our current credit rating, we are typically required to post collateral in the normal course of business to offset either substantially or completely the net liability positions, after applying the terms of master netting agreements. At September 30, 2012, the fair value of financial instruments with credit-risk-related contingent features in a net liability position was $22 million for which we had posted collateral of $18 million, including cash and letters of credit.
At September 30, 2012 and December 31, 2011, we had $98 million and $86 million, respectively, of cash collateral posted with counterparties under master netting agreements that was included in funds on deposit in the consolidated balance sheets.
Fair Values of Other Financial Instruments
The fair values of certain funds on deposit, accounts receivable, notes and other receivables, and accounts payable and accrued liabilities approximate their carrying amounts.
The carrying amounts and fair values of debt are as follows:
|
| Carrying |
| Level 1 |
| Level 2(1) |
| Level 3(2) |
| Total Fair Value |
| |||||
|
| (in millions) |
| |||||||||||||
September 30, 2012 |
|
|
|
|
|
|
|
|
|
|
| |||||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
| |||||
Long and short-term debt |
| $ | 4,371 |
| $ | — |
| $ | 4,349 |
| $ | 324 |
| $ | 4,673 |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
December 31, 2011 |
|
|
|
|
|
|
|
|
|
|
| |||||
Liabilities: |
|
|
|
|
|
|
|
|
|
|
| |||||
Long and short-term debt |
| $ | 4,132 |
| $ | — |
| $ | 3,969 |
| $ | 97 |
| $ | 4,066 |
|
(1) The fair value of long and short-term debt is estimated using broker quotes for instruments that are publicly traded.
(2) The fair value of long and short-term debt is estimated based on the income approach valuation technique for non-publicly traded debt using current interest rates for similar instruments with equivalent credit quality.
5. Long-Term Debt
Outstanding debt was as follows:
|
| September 30, 2012 |
| December 31, 2011 |
| ||||||||||||
|
| Weighted |
| Long-Term |
| Current |
| Weighted |
| Long-Term |
| Current |
| ||||
|
| (in millions, except interest rates) |
| ||||||||||||||
Facilities, Bonds and Notes: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
GenOn: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Senior unsecured notes, due 2014 |
| 7.625 | % | $ | 575 |
| $ | — |
| 7.625 | % | $ | 575 |
| $ | — |
|
Senior unsecured notes, due 2017 |
| 7.875 |
| 725 |
| — |
| 7.875 |
| 725 |
| — |
| ||||
Senior secured term loan, due 2017(2) |
| 6.00 |
| 679 |
| 7 |
| 6.00 |
| 684 |
| 7 |
| ||||
Senior unsecured notes, due 2018 |
| 9.50 |
| 675 |
| — |
| 9.50 |
| 675 |
| — |
| ||||
Senior unsecured notes, due 2020 |
| 9.875 |
| 550 |
| — |
| 9.875 |
| 550 |
| — |
| ||||
Unamortized debt discounts |
|
|
| (22 | ) | (2 | ) |
|
| (24 | ) | (2 | ) | ||||
GenOn Americas Generation: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Senior unsecured notes, due 2021 |
| 8.50 |
| 450 |
| — |
| 8.50 |
| 450 |
| — |
| ||||
Senior unsecured notes, due 2031 |
| 9.125 |
| 400 |
| — |
| 9.125 |
| 400 |
| — |
| ||||
Unamortized debt discounts |
|
|
| (2 | ) | — |
|
|
| (2 | ) | — |
| ||||
GenOn Marsh Landing: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Senior secured term loan, due 2017 |
| 2.75 |
| 109 |
| — |
| 2.76 |
| 33 |
| — |
| ||||
Senior secured term loan, due 2023 |
| 3.00 |
| 241 |
| — |
| 3.01 |
| 74 |
| — |
| ||||
Other: |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||
Capital leases, due 2015 |
| 7.375-8.19 |
| 11 |
| 5 |
| 7.375-8.19 |
| 14 |
| 5 |
| ||||
Adjustment to fair value of debt(3) |
|
|
| (30 | ) | — |
|
|
| (32 | ) | — |
| ||||
Total |
|
|
| $ | 4,361 |
| $ | 10 |
|
|
| $ | 4,122 |
| $ | 10 |
|
(1) The weighted average stated interest rates are at September 30, 2012 and December 31, 2011, respectively.
(2) The debt balance on the term loan facility is recorded at GenOn Americas, a direct subsidiary of GenOn Energy Holdings, because GenOn Americas is a co-borrower.
(3) Debt assumed in the Mirant/RRI Merger was adjusted to fair value on the Mirant/RRI Merger date. The adjustment is amortized to interest expense over various years through 2017.
GenOn Credit Facilities
Availability of borrowings under the GenOn revolving credit facility is reduced by any outstanding letters of credit. At September 30, 2012, outstanding letters of credit were $228 million and availability of borrowings under the revolving credit facility was $560 million.
6. Pension and Other Postretirement Benefit Plans
The components of the net periodic benefit cost (credit) are shown below:
|
| Pension Plans |
| Other Postretirement |
| ||||||||||||||||||||
|
| Three Months Ended |
| Nine Months Ended |
| Three Months Ended |
| Nine Months Ended |
| ||||||||||||||||
|
| 2012 |
| 2011 |
| 2012 |
| 2011 |
| 2012 |
| 2011 |
| 2012 |
| 2011 |
| ||||||||
|
| (in millions) |
| ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Service cost |
| $ | 3 |
| $ | 3 |
| $ | 9 |
| $ | 9 |
| $ | — |
| $ | — |
| $ | 1 |
| $ | — |
|
Interest cost |
| 6 |
| 5 |
| 18 |
| 17 |
| 1 |
| 1 |
| 3 |
| 3 |
| ||||||||
Expected return on plan assets |
| (8 | ) | (7 | ) | (23 | ) | (22 | ) | — |
| — |
| — |
| — |
| ||||||||
Net amortization(1) |
| 3 |
| 1 |
| 7 |
| 3 |
| (1 | ) | (1 | ) | (3 | ) | (3 | ) | ||||||||
Special termination benefit |
| 1 |
| — |
| 1 |
| — |
| — |
| — |
| — |
| — |
| ||||||||
Curtailment |
| — |
| — |
| — |
| — |
| (2 | ) | — |
| (2 | ) | — |
| ||||||||
Net periodic benefit cost (credit) |
| $ | 5 |
| $ | 2 |
| $ | 12 |
| $ | 7 |
| $ | (2 | ) | $ | — |
| $ | (1 | ) | $ | — |
|
(1) Net amortization amounts include actuarial gains/losses and prior service cost/credit.
7. Stock-Based Compensation
Compensation expense for the stock-based incentive plan was:
|
| Three Months Ended |
| Nine Months Ended |
| |||||||||||
|
| 2012 |
| 2011 |
| 2012 |
| 2011 |
| |||||||
|
| (in millions) |
| |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||
Stock-based incentive plan compensation expense (pre-tax)(1) |
| $ | 6 |
| $ | 3 |
| $ | 15 |
| $ | 11 |
| |||
(1) No tax benefits related to stock-based compensation were realized during the three and nine months ended September 30, 2012 and 2011 because of our NOL carryforwards.
During February 2012, we granted long-term incentive awards as follows:
Award Vehicle |
| Awards Granted |
| Vesting Period |
|
|
|
|
|
Time-based Restricted Stock Units |
| 2,821,302 |
| Vest ratably each year over a three-year period; common stock settled |
|
|
|
|
|
Performance-based Restricted Stock Units |
| 2,586,482 |
| Linked to the achievement of the 2012 short-term incentive plan performance goals, with performance measured at the end of the first year; vest ratably each year over a three-year period; common stock settled |
|
|
|
|
|
Stock Options |
| 5,897,990 |
| Vest ratably each year over a three-year period |
Vesting in Connection with the NRG Merger. All outstanding stock options (other than options granted in 2012) will immediately vest (to the extent not already fully vested) and all outstanding stock options will generally convert upon completion of the NRG Merger into stock options with respect to NRG common stock, after giving effect to the exchange ratio. In addition, all outstanding restricted stock units (other than restricted stock units granted in 2012) will immediately vest (to the extent not already fully vested) and all outstanding restricted stock units will be exchanged for the NRG Merger consideration. All outstanding stock options and restricted stock units granted in 2012 will vest (to the extent not already fully vested) at the holder’s termination date if the termination is as a result of the NRG Merger and within two years of the closing date. See note 1.
8. Earnings Per Share
We calculate basic EPS by dividing income/loss available to stockholders by the weighted average number of common shares outstanding. Diluted EPS gives effect to dilutive potential common shares, including unvested restricted stock units and stock options.
The following table shows the computation of basic and diluted EPS:
|
| Three Months Ended |
| Nine Months Ended |
| ||||||||
|
| 2012 |
| 2011 |
| 2012 |
| 2011 |
| ||||
|
| (in millions, except per share data) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Net loss |
| $ | (85 | ) | $ | (40 | ) | $ | (345 | ) | $ | (289 | ) |
|
|
|
|
|
|
|
|
|
| ||||
Basic and diluted shares |
|
|
|
|
|
|
|
|
| ||||
Weighted average shares outstanding—basic |
| 774 |
| 772 |
| 774 |
| 771 |
| ||||
Effect of dilutive securities(1) |
| — |
| — |
| — |
| — |
| ||||
Weighted average shares outstanding—diluted |
| 774 |
| 772 |
| 774 |
| 771 |
| ||||
|
|
|
|
|
|
|
|
|
| ||||
Basic and Diluted EPS |
|
|
|
|
|
|
|
|
| ||||
Basic EPS |
| $ | (0.11 | ) | $ | (0.05 | ) | $ | (0.45 | ) | $ | (0.37 | ) |
Diluted EPS |
| $ | (0.11 | ) | $ | (0.05 | ) | $ | (0.45 | ) | $ | (0.37 | ) |
(1) As we incurred a net loss for the three and nine months ended September 30, 2012 and 2011, diluted loss per share is calculated the same as basic loss per share.
The weighted average number of securities that could potentially dilute basic EPS in the future that were not included in the computation of diluted EPS because to do so would have been antidilutive was as follows:
|
| Three Months Ended |
| Nine Months Ended |
| ||||
|
| 2012 |
| 2011 |
| 2012 |
| 2011 |
|
|
| (in millions) |
| ||||||
|
|
|
|
|
|
|
|
|
|
Stock options |
| 19 |
| 17 |
| 18 |
| 18 |
|
Restricted stock units |
| 9 |
| 5 |
| 8 |
| 5 |
|
Total number of antidilutive shares |
| 28 |
| 22 |
| 26 |
| 23 |
|
9. Accumulated Other Comprehensive Loss
The component balances of accumulated other comprehensive loss, included in the consolidated balance sheets, are as follows:
|
| September 30, |
| December 31, |
| ||
|
| (in millions) |
| ||||
|
|
|
|
|
| ||
Pension and other postretirement benefits—actuarial losses, net |
| $ | (145 | ) | $ | (142 | ) |
Pension and other postretirement benefits—prior service credit, net |
| 5 |
| 7 |
| ||
Cash flow hedges—interest rate swaps |
| (52 | ) | (34 | ) | ||
Other, net |
| — |
| (1 | ) | ||
Accumulated other comprehensive loss |
| $ | (192 | ) | $ | (170 | ) |
10. Segment Reporting
We have five segments: Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations. The segments are determined based on how the business is managed and align with the information provided to the chief operating decision maker for purposes of assessing performance and allocating resources. Generally, our segments are engaged in the sale of electricity, capacity, and ancillary and other energy services from their generating facilities in hour-ahead, day-ahead and forward markets in bilateral and ISO markets. We also engage in proprietary trading, fuel oil management and natural gas transportation and storage activities. Operating
revenues consist of (a) power generation revenues, (b) contracted and capacity revenues, (c) power hedging revenues and (d) fuel sales and proprietary trading revenues.
The Eastern PJM segment consists of seven generating facilities located in Maryland and New Jersey. The Western PJM/MISO segment consists of 22 generating facilities located in Illinois, Ohio and Pennsylvania. The California segment consists of seven generating facilities located in California and includes business development and construction activities for GenOn Marsh Landing. See note 2 for a discussion of generating facilities in the Eastern PJM, Western PJM/MISO and California segments that we expect to retire or place in long-term protective layup in 2015. The Energy Marketing segment consists of proprietary trading, fuel oil management and natural gas transportation and storage activities. Other Operations consists of seven generating facilities located in Florida, Massachusetts, Mississippi, New York and Texas. Other Operations also includes unallocated overhead expenses and other activity that cannot be identified specifically with another segment. All revenues are generated and long-lived assets are located within the United States.
The following table summarizes changes in our net generating capacity by segment:
|
| Eastern |
| Western |
| California |
| Other |
| Total |
|
|
| (in MWs) |
| ||||||||
|
|
|
|
|
|
|
|
|
|
|
|
MWs in service at January 1, 2011 |
| 6,336 |
| 7,483 |
| 5,725 |
| 5,055 |
| 24,599 |
|
Potrero generating facility deactivated in February 2011 |
| — |
| — |
| (362 | ) | — |
| (362 | ) |
Rating changes for generating facilities in 2011 |
| 5 |
| — |
| 28 |
| 13 |
| 46 |
|
MWs in service at December 31, 2011 |
| 6,341 |
| 7,483 |
| 5,391 |
| 5,068 |
| 24,283 |
|
Indian River generating facility sold in January 2012 |
| — |
| — |
| — |
| (586 | ) | (586 | ) |
Vandolah generating facility expiration of tolling agreement in May 2012 |
| — |
| — |
| — |
| (630 | ) | (630 | ) |
Niles unit 2 deactivated in June 2012 |
| — |
| (108 | ) | — |
| — |
| (108 | ) |
Elrama units 1-3 deactivated in June 2012 |
| — |
| (289 | ) | — |
| — |
| (289 | ) |
MWs in service at September 30, 2012 |
| 6,341 |
| 7,086 |
| 5,391 |
| 3,852 |
| 22,670 |
|
Niles unit 1 deactivated in October 2012 |
| — |
| (109 | ) | — |
| — |
| (109 | ) |
Elrama unit 4 deactivated in October 2012 |
| — |
| (171 | ) | — |
| — |
| (171 | ) |
Potomac River generating facility deactivated in October 2012 |
| (482 | ) | — |
| — |
| — |
| (482 | ) |
MWs in service at November 9, 2012 |
| 5,859 |
| 6,806 |
| 5,391 |
| 3,852 |
| 21,908 |
|
The measure of profit or loss for our reportable segments is operating income/loss. This measure represents the lowest level of information that is provided to the chief operating decision maker for our reportable segments.
|
| Eastern PJM |
| Western |
| California |
| Energy |
| Other |
| Eliminations |
| Total |
| |||||||
|
| (in millions) |
| |||||||||||||||||||
Three Months Ended September 30, 2012: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Operating revenues(1) |
| $ | 220 |
| $ | 236 |
| $ | 209 |
| $ | 14 |
| $ | 76 |
| $ | — |
| $ | 755 |
|
Cost of fuel, electricity and other products(2) |
| 107 |
| 154 |
| 20 |
| 30 |
| 35 |
| — |
| 346 |
| |||||||
Gross margin (excluding depreciation and amortization) |
| 113 |
| 82 |
| 189 |
| (16 | ) | 41 |
| — |
| 409 |
| |||||||
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Operations and maintenance |
| 101 |
| 102 |
| 34 |
| 1 |
| 30 |
| — |
| 268 |
| |||||||
Depreciation and amortization |
| 34 |
| 32 |
| 10 |
| — |
| 15 |
| — |
| 91 |
| |||||||
Impairment losses |
| — |
| 47 | (3) | — |
| — |
| — |
| — |
| 47 |
| |||||||
Gain on sales of assets, net |
| (1 | ) | — |
| — |
| — |
| — |
| — |
| (1 | ) | |||||||
Total operating expenses |
| 134 |
| 181 |
| 44 |
| 1 |
| 45 |
| — |
| 405 |
| |||||||
Operating income (loss) |
| $ | (21 | ) | $ | (99 | ) | $ | 145 |
| $ | (17 | ) | $ | (4 | ) | $ | — |
| $ | 4 |
|
(1) Includes unrealized gains (losses) of $(136) million, $(81) million, $2 million, $(29) million and $(1) million for Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations, respectively.
(2) Includes unrealized gains of $46 million, $8 million, $1 million and $3 million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
(3) Represents long-lived assets impairments, see note 3.
|
| Eastern PJM |
| Western |
| California |
| Energy |
| Other |
| Eliminations |
| Total |
| |||||||
|
| (in millions) |
| |||||||||||||||||||
Nine Months Ended September 30, 2012: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Operating revenues(1) |
| $ | 772 |
| $ | 721 |
| $ | 271 |
| $ | 65 |
| $ | 168 |
| $ | — |
| $ | 1,997 |
|
Cost of fuel, electricity and other products(2) |
| 376 |
| 399 |
| 22 |
| 45 |
| 88 |
| — |
| 930 |
| |||||||
Gross margin (excluding depreciation and amortization) |
| 396 |
| 322 |
| 249 |
| 20 |
| 80 |
| — |
| 1,067 |
| |||||||
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Operations and maintenance(3) |
| 292 | (4) | 346 |
| 117 |
| 4 |
| 81 |
| — |
| 840 |
| |||||||
Depreciation and amortization |
| 101 |
| 93 |
| 33 |
| — |
| 42 |
| — |
| 269 |
| |||||||
Impairment losses |
| — |
| 47 | (5) | — |
| — |
| — |
| — |
| 47 |
| |||||||
Gain on sales of assets, net |
| (1 | ) | (1 | ) | — |
| — |
| (7 | ) | — |
| (9 | ) | |||||||
Total operating expenses |
| 392 |
| 485 |
| 150 |
| 4 |
| 116 |
| — |
| 1,147 |
| |||||||
Operating income (loss) |
| $ | 4 |
| $ | (163 | ) | $ | 99 |
| $ | 16 |
| $ | (36 | ) | $ | — |
| $ | (80 | ) |
Total assets at September 30, 2012 |
| $ | 4,438 |
| $ | 3,292 |
| $ | 1,106 |
| $ | 1,546 |
| $ | 3,627 | (6) | $ | (2,434 | ) | $ | 11,575 |
|
(1) Includes unrealized gains (losses) of $(135) million, $(46) million, $1 million, $(15) million and $(9) million for Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations, respectively.
(2) Includes unrealized (gains) losses of $26 million, $10 million, $1 million and $(12) million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
(3) Includes costs to deactivate generating facilities of $11 million, $32 million and $4 million for Eastern PJM, Western PJM/MISO and California, respectively.
(4) Includes $31 million of income related to the reversal of the Potomac River obligation under the 2008 agreement with the City of Alexandria.
(5) Represents long-lived assets impairments, see note 3.
(6) Includes our equity method investment in Sabine Cogen, LP of $20 million.
|
| Eastern PJM |
| Western |
| California |
| Energy |
| Other |
| Eliminations |
| Total |
| |||||||
|
| (in millions) |
| |||||||||||||||||||
Three Months Ended September 30, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Operating revenues(1) |
| $ | 346 |
| $ | 433 |
| $ | 128 |
| $ | 88 |
| $ | 85 |
| $ | — |
| $ | 1,080 |
|
Cost of fuel, electricity and other products(2) |
| 179 |
| 206 |
| 11 |
| 71 |
| 59 |
| — |
| 526 |
| |||||||
Gross margin (excluding depreciation and amortization) |
| 167 |
| 227 |
| 117 |
| 17 |
| 26 |
| — |
| 554 |
| |||||||
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Operations and maintenance |
| 99 |
| 108 |
| 33 |
| — |
| 46 | (3) | — |
| 286 |
| |||||||
Depreciation and amortization |
| 34 |
| 29 |
| 11 |
| 1 |
| 21 |
| — |
| 96 |
| |||||||
Impairment losses(4) |
| 95 |
| 4 |
| 14 |
| — |
| 20 |
| — |
| 133 |
| |||||||
Gain on sales of assets, net |
| — |
| — |
| (5 | ) | — |
| (1 | ) | — |
| (6 | ) | |||||||
Total operating expenses |
| 228 |
| 141 |
| 53 |
| 1 |
| 86 |
| — |
| 509 |
| |||||||
Operating income (loss) |
| $ | (61 | ) | $ | 86 |
| $ | 64 |
| $ | 16 |
| $ | (60 | ) | $ | — |
| $ | 45 |
|
(1) Includes unrealized gains (losses) of $(2) million, $37 million, $1 million, $15 million and $(2) million for Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations, respectively.
(2) Includes unrealized (gains) losses of $10 million, $1 million, $(1) million and $1 million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
(3) Includes $24 million of Mirant/RRI Merger-related costs.
(4) Represents impairment losses for the write-off of excess NOx and SO2 emissions allowances as a result of the CSAPR.
|
| Eastern PJM |
| Western |
| California |
| Energy |
| Other |
| Eliminations |
| Total |
| |||||||
|
| (in millions) |
| |||||||||||||||||||
Nine Months Ended September 30, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Operating revenues(1) |
| $ | 962 |
| $ | 1,050 |
| $ | 200 |
| $ | 292 |
| $ | 202 |
| $ | — |
| $ | 2,706 |
|
Cost of fuel, electricity and other products(2) |
| 433 |
| 526 |
| 14 |
| 222 |
| 122 |
| — |
| 1,317 |
| |||||||
Gross margin (excluding depreciation and amortization) |
| 529 |
| 524 |
| 186 |
| 70 |
| 80 |
| — |
| 1,389 |
| |||||||
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Operations and maintenance |
| 351 | (3) | 368 |
| 111 |
| 2 |
| 131 | (4) | — |
| 963 |
| |||||||
Depreciation and amortization |
| 101 |
| 88 |
| 32 |
| 2 |
| 49 |
| — |
| 272 |
| |||||||
Impairment losses(5) |
| 95 |
| 4 |
| 14 |
| — |
| 20 |
| — |
| 133 |
| |||||||
Gain on sales of assets, net |
| — |
| — |
| (5 | ) | — |
| — |
| — |
| (5 | ) | |||||||
Total operating expenses |
| 547 |
| 460 |
| 152 |
| 4 |
| 200 |
| — |
| 1,363 |
| |||||||
Operating income (loss) |
| $ | (18 | ) | $ | 64 |
| $ | 34 |
| $ | 66 |
| $ | (120 | ) | $ | — |
| $ | 26 |
|
Total assets at December 31, 2011 |
| $ | 4,732 |
| $ | 3,343 |
| $ | 856 |
| $ | 2,173 |
| $ | 3,662 | (6) | $ | (2,497 | ) | $ | 12,269 |
|
(1) Includes unrealized gains (losses) of $(80) million, $2 million, $4 million and $(12) million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
(2) Includes unrealized (gains) losses of $(17) million, $(8) million, $(1) million and $(1) million for Eastern PJM, Western PJM/MISO, Energy Marketing and Other Operations, respectively.
(3) Includes $30 million of expense for large scale remediation and settlement costs.
(4) Includes $61 million of Mirant/RRI Merger-related costs.
(5) Represents impairment losses for the write-off of excess NOx and SO2 emissions allowances as a result of the CSAPR.
(6) Includes our equity method investment in Sabine Cogen, LP of $22 million.
|
| Three Months Ended |
| Nine Months Ended |
| ||||||||
|
| 2012 |
| 2011 |
| 2012 |
| 2011 |
| ||||
|
| (in millions) |
| ||||||||||
|
|
|
|
|
|
|
|
|
| ||||
Operating income (loss) for all segments |
| $ | 4 |
| $ | 45 |
| $ | (80 | ) | $ | 26 |
|
Interest expense, net |
| (85 | ) | (85 | ) | (259 | ) | (290 | ) | ||||
Other, net |
| — |
| 1 |
| 2 |
| (21 | ) | ||||
Loss before income taxes |
| $ | (81 | ) | $ | (39 | ) | $ | (337 | ) | $ | (285 | ) |
11. Litigation and Other Contingencies
We are involved in a number of legal proceedings. In certain cases, plaintiffs seek to recover large or unspecified damages, and some matters may be unresolved for several years. We cannot currently determine the outcome of the proceedings described below or estimate the reasonable amount or range of potential losses, if any, and therefore have not made any provision for such matters unless specifically noted below.
Scrubber Contract Litigation
In January 2011, Stone & Webster, the EPC contractor for the scrubber projects at the Chalk Point, Dickerson and Morgantown generating facilities, filed three suits against us in the United States District Court for the District of Maryland. Stone & Webster claimed that it had not been paid in accordance with the terms of the EPC agreements for the scrubber projects and sought liens against the properties, which the court granted. We disputed Stone & Webster’s allegations and in February 2011 filed a related action against Stone &Webster in the United States District Court for the Southern District of New York. The proceedings in Maryland were stayed pending resolution of the proceeding in New York.
In June 2012, we executed a settlement agreement with Stone & Webster. Under the terms of the settlement agreement GenOn agreed to pay Stone & Webster $107.1 million in settlement of all outstanding invoices and amounts claimed to be owed by Stone & Webster in connection with the construction of the scrubber projects. As part of the settlement, Stone & Webster released the $165.6 million in interlocutory liens that had been filed by Stone & Webster on the Chalk Point, Dickerson and Morgantown generating facilities. As a result of the release of the liens, GenOn Mid-Atlantic released the $165.6 million in reserved cash during June 2012 (previously included as funds on deposit in the consolidated balance sheets). In connection with the settlement agreement, we dismissed our dispute filed in the United States District Court for the Southern District of New York.
We incurred $1.7 billion in capital expenditures from 2007 to 2012 for compliance with the Maryland Healthy Air Act.
Pending Natural Gas Litigation
We are party to five lawsuits, several of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of antitrust and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name a number of unaffiliated energy companies as parties. In July 2011, the judge in the United States District Court for the District of Nevada handling four of the five cases granted the defendants’ motion for summary judgment dismissing all claims against us in those cases. The plaintiffs have appealed to the United States Court of Appeals for the Ninth Circuit. In September 2012, the State of Nevada Supreme Court handling one of the five cases affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs’ claims against us. In October 2012, the plaintiffs indicated that they intend to file a petition for certiorari to the United States Supreme Court. We have agreed to indemnify CenterPoint against certain losses relating to these lawsuits.
Bowline Property Tax Dispute
In 2011, 2010 and 2009 we filed suit against the town of Haverstraw, New York to challenge the property tax assessment of the Bowline generating facility for each respective tax year. Although the assessments for the 2011 and 2010 tax years were reduced significantly from the assessment received in 2009, they continue to exceed significantly the estimated fair value of the generating facility. The tax litigation for all three years has been combined for trial purposes. While we are unable to predict the outcome of this litigation, if we are successful we expect to receive a refund for each of the years under protest.
Environmental Matters
Global Warming. In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a suit in the United States District Court for the Northern District of California against GenOn and 23 other electric generating and oil and gas companies. The lawsuit sought damages of up to $400 million for the cost of relocating the village allegedly because of global warming caused by the greenhouse gas emissions of the defendants. In late 2009, the District Court ordered that the case be dismissed and the plaintiffs appealed. In September 2012, the United States Court of Appeals for the Ninth Circuit dismissed planitiffs’ appeal. In October 2012, the plaintiffs petitioned for en banc rehearing of the case. Although we think claims such as this lack legal merit, it is possible that this trend of climate change litigation may continue.
New Source Review Matters. The EPA and various states are investigating compliance of coal-fueled electric generating facilities with the pre-construction permitting requirements of the Clean Air Act known as “new source review.” Since 2000, the EPA has made information requests concerning the Avon Lake, Chalk Point, Cheswick, Conemaugh, Dickerson, Elrama, Keystone, Morgantown, New Castle, Niles, Portland, Potomac River, Shawville and Titus generating facilities. We are corresponding or have corresponded with the EPA regarding all of these requests. The EPA agreed to share information relating to its investigations with state environmental agencies. In January 2009, we received an NOV from the EPA alleging that past work at our Shawville, Portland and Keystone generating facilities violated regulations regarding new source review. In June 2011, we received an NOV from the EPA alleging that past work at our Niles and Avon Lake generating facilities violated regulations regarding new source review.
In December 2007, the NJDEP filed suit against us in the United States District Court for the Eastern District of Pennsylvania, alleging that new source review violations occurred at the Portland generating facility. The suit seeks installation of “best available” control technologies for each pollutant, to enjoin us from operating the generating facility if it is not in compliance with the Clean Air Act and civil penalties. The suit also names three past owners of the plant as defendants. In March 2009, the Connecticut Department of Environmental Protection became an intervening party to the suit.
We think that the work listed by the EPA and the work subject to the NJDEP suit were conducted in compliance with applicable regulations. However, any final finding that we violated the new source review requirements could result in fines, penalties or significant capital expenditures associated with the implementation of emissions reductions on an accelerated basis. Most of these work projects were undertaken before our ownership or lease of those facilities.
In addition, the NJDEP filed two administrative petitions with the EPA in 2010 alleging that our Portland generating facility’s emissions were significantly contributing to nonattainment and/or interfering with the maintenance of certain NAAQS in New Jersey. In November 2011, the EPA published a final rule in response to one of the petitions that will require us to reduce our maximum allowable SO2 emissions from the two coal-fired units by about 60% starting in January 2013 and by about 80% starting in January 2015. In January 2012, we challenged the rule in the United States Court of Appeals for the Third Circuit. In 2013 and 2014, we have several compliance options that include using lower sulfur coals (although this may at times reduce how much we are able to generate) or running just one unit at a time. Starting in January 2015, these units will be subject to more stringent rate limits, which will require either material capital expenditures and higher operating costs or the retirement of these two units. See note 2 for a discussion of the Portland coal-fired units that we expect to deactivate in 2015.
Cheswick Class Action Complaint. In April 2012, a putative class action lawsuit was filed against us in the Court of Common Pleas of Allegheny County, Pennsylvania alleging that emissions from our Cheswick generating facility have damaged the property of neighboring residents. We dispute these allegations. Plaintiffs have brought nuisance, negligence, trespass and strict liability claims seeking both damages and injunctive relief. Plaintiffs seek to certify a class that consists of people who own property or live within one mile of our plant. In July 2012, we removed the lawsuit to the United States District Court for the Western District of Pennsylvania. In October 2012, the court granted our motion to dismiss. Plaintiffs have 30 days to appeal this order.
Cheswick Monarch Mine NOV. In 2008, the PADEP issued an NOV related to the Monarch mine located near our Cheswick generating facility. It has not been mined for many years. We use it for disposal of low-volume wastewater from the Cheswick generating facility and for disposal of leachate collected from ash disposal facilities. The NOV addresses the alleged requirement to maintain a minimum pumping volume from the mine. The PADEP indicated it may assess a civil penalty in excess of $100,000. We contest the allegations in the NOV and have not agreed to such penalty. We are currently planning capital expenditures in connection with wastewater from Cheswick and leachate from ash disposal facilities.
Conemaugh Alleged Clean Streams Law Violations. In September 2012, the PADEP filed a lawsuit in the Commonwealth Court of Pennsylvania alleging that several violations of the Pennsylvania Clean Streams Law occurred at the Conemaugh generating facility. We have negotiated a proposed consent decree to address the allegations. We expect that the proposed consent decree, which has been lodged with the court, will resolve these issues and obligate us to pay a civil penalty of $500,000. We are responsible for 16.45% of this amount.
Ormond Beach Alleged Federal Clean Water Act Violations. In October 2012, the Wishtoyo Foundation, a California-based cultural and environmental advocacy organization, through its Ventura Coastkeeper Program, filed suit in the United States District Court for the Central District of California regarding alleged violations of the Clean Water Act associated with discharges of stormwater from the Ormond Beach generating facility. The Wishtoyo Foundation alleges that elevated concentrations of pollutants in stormwater discharged from the Ormond Beach generating facility are affecting adjacent aquatic resources in violation of (a) the Statewide General Industrial Stormwater permit (a general National Pollution Discharge Elimination System permit issued by the California State Water Resources Control Board that authorizes stormwater discharges from industrial facilities in California) and (b) the state’s Porter-Cologne Water Quality Control Act. The Wishtoyo Foundation further alleges that we have
not implemented effective stormwater control and treatment measures and that we have not complied with the sampling and reporting requirements of the General Industrial Stormwater permit. We dispute these allegations.
Maryland Fly Ash Facilities. We have three fly ash facilities in Maryland: Faulkner, Westland and Brandywine. We dispose of fly ash from our Morgantown and Chalk Point generating facilities at Brandywine. We dispose of fly ash from our Dickerson generating facility at Westland. We no longer dispose of fly ash at the Faulkner facility. As described below, the MDE has sued us regarding Faulkner and Brandywine and threatened to sue regarding Westland. The MDE also had threatened not to renew the water discharge permits for all three facilities.
Faulkner Litigation. In May 2008, the MDE sued us in the Circuit Court for Charles County, Maryland alleging violations of Maryland’s water pollution laws at Faulkner. The MDE contended that the operation of Faulkner had resulted in the discharge of pollutants that exceeded Maryland’s water quality criteria and without the appropriate NPDES permit. The MDE also alleged that we failed to perform certain sampling and reporting required under an applicable NPDES permit. The MDE complaint requested that the court (a) prohibit continuation of the alleged unpermitted discharges, (b) require us to cease from further disposal of any coal combustion byproducts at Faulkner and close and cap the existing disposal cells and (c) assess civil penalties. In July 2008, we filed a motion to dismiss the complaint, arguing that the discharges are permitted by a December 2000 Consent Order. In January 2011, the MDE dismissed without prejudice its complaint and informed us that it intended to file a similar lawsuit in federal court. In May 2011, the MDE filed a complaint against us in the United States District Court for the District of Maryland alleging violations at Faulkner of the Clean Water Act and Maryland’s Water Pollution Control Law. The MDE contends that (a) certain of our water discharges are not authorized by our existing permit and (b) operation of the Faulkner facility has resulted in discharges of pollutants that violate water quality criteria. The complaint asks the court to, among other things, (a) enjoin further disposal of coal ash; (b) enjoin discharges that are not authorized by our existing permit; (c) require numerous technical studies; (d) impose civil penalties and (e) award MDE attorneys’ fees. We dispute the allegations.
Brandywine Litigation. In April 2010, the MDE filed a complaint against us in the United States District Court for the District of Maryland asserting violations at Brandywine of the Clean Water Act and Maryland’s Water Pollution Control Law. The MDE contends that the operation of Brandywine has resulted in discharges of pollutants that violate Maryland’s water quality criteria. The complaint requests that the court, among other things, (a) enjoin further disposal of coal combustion waste at Brandywine, (b) require us to close and cap the existing open disposal cells within one year, (c) impose civil penalties and (d) award MDE attorneys’ fees. We dispute the allegations. In September 2010, four environmental advocacy groups became intervening parties in the proceeding.
Threatened Westland Litigation. In January 2011, the MDE informed us that it intended to sue us for alleged violations at Westland of Maryland’s water pollution laws. To date, MDE has not sued us regarding our ash disposal.
Permit Renewals. In March 2011, the MDE tentatively determined to deny our application for the renewal of the water discharge permit for Brandywine, which could result in a significant increase in operating expenses for our Chalk Point and Morgantown generating facilities. The MDE also had indicated that it was planning to deny our applications for the renewal of the water discharge permits for Faulkner and Westland. Denial of the renewal of the water discharge permit for the latter facility could result in a significant increase in operating expenses for our Dickerson generating facility.
Stay and Settlement Discussions. In June 2011, the MDE agreed to stay the litigation related to Faulkner and Brandywine while we pursued settlement of allegations related to the three Maryland ash facilities. MDE also agreed not to pursue its tentative denial of our application to renew our water discharge permit at Brandywine and agreed not to act on our renewal applications for Faulkner or Westland while we were discussing settlement. As a condition to obtaining the stay, we agreed in principle to pay a civil penalty of $1.9 million (for alleged past violations) to the MDE if we reach a comprehensive settlement regarding all of the allegations related to the three Maryland ash facilities. We accrued $1.9 million during 2011 and an additional $0.6 million (for agreed prospective penalties while we implement the settlement) during the second quarter of 2012 for a total of $2.5 million. We also developed a technical solution, which includes installing synthetic caps on the closed cells of each of the three ash facilities. During 2011, we accrued $47 million for the estimated cost of the technical solution. We have nearly
concluded our settlement discussions with the MDE. At this time, we cannot reasonably estimate the upper range of our obligations for remediating the sites for the following reasons: (a) we have not finished assessing each site including identifying the full impacts to both ground and surface water and the impacts to the surrounding habitat; (b) we have not finalized with the MDE the standards to which we must remediate; and (c) we have not identified the technologies required, if any, to meet the mandated remediation standards at each site nor the timing of the design and installation of such technologies.
Brandywine Storm Damage and Ash Recovery. As a result of Hurricane Irene and Tropical Storm Lee in August and September 2011, an estimated 8,800 cubic yards of coal fly ash stored in one of the cells at the Brandywine ash disposal site flowed onto 18 acres of private property adjacent to the site. During 2011, we accrued $10 million for the estimated costs to remove and clean up the ash. We have removed the released ash from the private property and completed the remaining clean-up activities. We adjusted our estimate and reversed $4 million during the second quarter of 2012. During the third quarter of 2012, we received $2 million of insurance proceeds in connection with our claims associated with the costs to remove and clean up the ash.
Brandywine Filling of Wetlands. While expanding and installing a liner at the Brandywine ash disposal site, we inadvertently filled wetlands without having all of the requisite permits. The MDE also has alleged that we violated the notice requirements of our sediment and erosion control plan. In July 2012, the MDE filed a complaint in the Circuit Court for Prince George’s County, Maryland for civil penalties and injunctive relief in connection with the storm damage and the filling of the wetlands. We have agreed to settle these matters by paying a fine of $300,000.
Ash Disposal Facility Closures. We are responsible for environmental costs related to the future closures of several ash disposal facilities. We have accrued the estimated discounted costs ($40 million and $38 million at September 30, 2012 and December 31, 2011, respectively) associated with these environmental liabilities as part of the asset retirement obligations. These amounts are exclusive of the $47 million accrual for the technical solution for the three ash facilities in Maryland discussed above.
Remediation Obligations. We are responsible under the Industrial Site Recovery Act for environmental costs related to site contamination investigations and remediation requirements at four generating facilities in New Jersey. We have accrued the estimated long-term liability for the remediation costs of $6 million at September 30, 2012 and December 31, 2011.
Chapter 11 Proceedings
In July 2003, and various dates thereafter, the Mirant Debtors filed voluntary petitions in the Bankruptcy Court for relief under Chapter 11 of the United States Bankruptcy Code. GenOn Energy Holdings and most of the other Mirant Debtors emerged from bankruptcy on January 3, 2006, when the Plan became effective. The remaining Mirant Debtors emerged from bankruptcy on various dates in 2007. Approximately 461,000 of the shares of GenOn Energy Holdings common stock to be distributed under the Plan have not yet been distributed and have been reserved for distribution with respect to claims disputed by the Mirant Debtors that have not been resolved. Upon the Mirant/RRI Merger, those reserved shares converted into a reserve for approximately 1.3 million shares of GenOn common stock. Under the terms of the Plan, upon the resolution of such a disputed claim, the claimant will receive the same pro rata distributions of common stock, cash, or both as previously allowed claims, regardless of the price at which the common stock is trading at the time the claim is resolved. If the aggregate amount of any such payouts results in the number of reserved shares being insufficient, additional shares of common stock may be issued to address the shortfall.
Actions Pursued by MC Asset Recovery
Under the Plan, the rights to certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly-owned subsidiary of GenOn Energy Holdings. MC Asset Recovery is now governed by a manager who is independent of us. Under the Plan, any cash recoveries obtained by MC Asset Recovery from the actions transferred to it, net of fees and costs incurred in prosecuting the actions, are to be paid to the unsecured creditors of GenOn Energy Holdings in the Chapter 11 proceedings and the holders of the equity interests in GenOn Energy Holdings immediately prior to the effective
date of the Plan except where such a recovery results in an allowed claim in the bankruptcy proceedings, as described below. MC Asset Recovery is a disregarded entity for income tax purposes, and GenOn Energy Holdings is responsible for income taxes related to its operations. The Plan provides that GenOn Energy Holdings may not reduce payments to be made to unsecured creditors and former holders of equity interests from recoveries obtained by MC Asset Recovery for the taxes owed by GenOn Energy Holdings, if any, on any net recoveries up to $175 million. If the aggregate recoveries exceed $175 million net of costs, then GenOn Energy Holdings may reduce the payments by the amount of any taxes it will owe or NOLs utilized with respect to taxable income resulting from the amount in excess of $175 million.
The Plan and the MC Asset Recovery Limited Liability Company Agreement also obligate GenOn Energy Holdings to make contributions to MC Asset Recovery as necessary to pay professional fees and certain other costs. In June 2008, GenOn Energy Holdings and MC Asset Recovery, with the approval of the Bankruptcy Court, agreed to limit the total amount of funding to be provided by GenOn Energy Holdings to MC Asset Recovery to $68 million, and the amount of such funding obligation not already incurred by GenOn Energy Holdings at that time was fully accrued. GenOn Energy Holdings was entitled to be repaid the amounts it funded from any recoveries obtained by MC Asset Recovery before any distribution was made from such recoveries to the unsecured creditors of GenOn Energy Holdings and the former holders of equity interests.
In March 2009, Southern Company and MC Asset Recovery entered into a settlement agreement resolving claims asserted by MC Asset Recovery in a suit that was pending in the United States District Court for the Northern District of Georgia. Southern Company paid $202 million to MC Asset Recovery in settlement of all claims asserted in the litigation. MC Asset Recovery used a portion of that payment to pay fees owed to the managers of MC Asset Recovery and other expenses of MC Asset Recovery not previously funded by GenOn Energy Holdings, and it retained $47 million from that payment to fund future expenses and to apply against unpaid expenditures. MC Asset Recovery distributed the remaining $155 million to GenOn Energy Holdings. In accordance with the Plan, GenOn Energy Holdings retained approximately $52 million of that distribution as reimbursement for the funds it had provided to MC Asset Recovery and costs it incurred related to MC Asset Recovery that had not been previously reimbursed. GenOn Energy Holdings recognized the $52 million as a reduction of operations and maintenance expense during 2009. Pursuant to MC Asset Recovery’s Limited Liability Company Agreement and an order of the Bankruptcy Court dated October 31, 2006, GenOn Energy Holdings distributed $2 million to the managers of MC Asset Recovery. In September 2009, the remaining approximately $101 million of the amount recovered by MC Asset Recovery was distributed pursuant to the terms of the Plan. Following these distributions, GenOn Energy Holdings has no further obligation to provide funding to MC Asset Recovery. As a result, GenOn Energy Holdings reversed its remaining accrual of $10 million of funding obligations as a reduction in operations and maintenance expense for 2009. GenOn does not expect to owe any taxes related to the MC Asset Recovery settlement with Southern Company.
Based on a stipulation entered by the Bankruptcy Court in December 2011 and pursuant to the terms of the Plan and the MC Asset Recovery Limited Liability Company Agreement, during March 2012, GenOn Energy Holdings distributed $26 million of the $47 million in funds that had been previously retained by MC Asset Recovery.
One of the two remaining actions transferred to MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks (the Commerzbank Defendants) for alleged fraudulent transfers that occurred prior to the filing of GenOn Energy Holdings’ bankruptcy proceedings. In its amended complaint, MC Asset Recovery alleges that the Commerzbank Defendants in 2002 and 2003 received payments totaling approximately 153 million Euros directly or indirectly from GenOn Energy Holdings under a guarantee provided by GenOn Energy Holdings in 2001 of certain equipment purchase obligations. MC Asset Recovery alleges that at the time GenOn Energy Holdings provided the guarantee and made the payments to the Commerzbank Defendants, GenOn Energy Holdings was insolvent and did not receive fair value for those transactions. In December 2010, the United States District Court for the Northern District of Texas dismissed MC Asset Recovery’s complaint against the Commerzbank Defendants. In January 2011, MC Asset Recovery appealed the United States District Court’s dismissal of its complaint against the Commerzbank Defendants to the United States Court of Appeals for the Fifth Circuit. In March 2012, the United States Court of Appeals for the Fifth Circuit reversed the United States District Court’s dismissal and reinstated MC Asset Recovery’s amended complaint against the Commerzbank Defendants. If MC Asset Recovery succeeds in obtaining any recoveries on these avoidance claims, the Commerzbank
Defendants have asserted that they will seek to file claims in GenOn Energy Holdings’ bankruptcy proceedings for the amount of those recoveries. GenOn Energy Holdings would vigorously contest the allowance of any such claims on the ground that, among other things, the recovery of such amounts by MC Asset Recovery does not reinstate any enforceable pre-petition obligation that could give rise to a claim. If such a claim were to be allowed by the Bankruptcy Court as a result of a recovery by MC Asset Recovery, then the Plan provides that the Commerzbank Defendants are entitled to the same distributions as previously made under the Plan to holders of similar allowed claims. Holders of previously allowed claims similar in nature to the claims that the Commerzbank Defendants would seek to assert have received 43.87 shares of GenOn Energy Holdings common stock for each $1,000 of claim allowed by the Bankruptcy Court. If the Commerzbank Defendants were to receive an allowed claim as a result of a recovery by MC Asset Recovery on its claims against them, the order entered by the Bankruptcy Court in December 2005, confirming the Plan provides that GenOn Energy Holdings would retain from the net amount recovered by MC Asset Recovery an amount equal to the dollar amount of the resulting allowed claim rather than distribute such amount to the unsecured creditors and former equity holders as described above.
Texas Franchise Audit
In 2008 and 2009, the State of Texas, as a result of its audit, issued franchise tax assessments against us indicating an underpayment of franchise tax of $72 million (including interest and penalties through September 30, 2012 of $29 million). These assessments are related primarily to a claim by Texas that would change the sourcing of intercompany receipts for the years 2000 through 2006, thereby increasing the amount of tax due to Texas. We disagree with most of the State’s assessment and its determination of the related tax liability. Given the disagreement with the State’s position, we have accrued a portion of the liability but have protested the entire assessment and are currently in the administrative appeals process. If we do not fully resolve or come to satisfactory settlement of the protested issues, then we could pay up to the entire amount of the assessed tax, penalties and interest. We intend to defend fully our position in the administrative appeals process and if such defense requires litigation, would be required to pay the full assessment and sue for refund.
NRG Merger Litigation
During July and August 2012, we, the members of our board of directors, NRG, and Plus Merger Corporation (a wholly-owned subsidiary of NRG) were named defendants in nine purported class action lawsuits filed in the Court of Chancery of the State of Delaware, one of which has been dismissed and the remainder of which were consolidated into one action (In re GenOn Energy, Inc. Shareholders Litigation, Consolidated C.A. No. 7721-VCN). In October 2012, we signed a memorandum of understanding to settle the Delaware consolidated action based on additional disclosures that were provided to stockholders.
In July 2012, we, the members of our board of directors, NRG, and Plus Merger Corporation were also named defendants in three purported class action lawsuits filed in the 189th District Court of Harris County, Texas, which have been consolidated into one action (Akel, et al. v. GenOn Energy, Inc., et al., Consolidated Case No. 2012-42090) and one purported class action lawsuit filed in the United States District Court for the Southern District of Texas (Bushansky v. GenOn Energy, Inc. et al., No. 4:12-CV-02257). In October 2012, the United States District Court for the Southern District of Texas issued an order granting the parties’ joint motion to stay the action until the later of the resolution of a motion for injunction or the final settlement of the Delaware consolidated action, which is discussed above.
Each case was brought on behalf of proposed classes consisting of holders of our common stock, excluding defendants and their affiliates. The complaints allege, among other things, that (a) the NRG Merger Agreement was the product of breaches of fiduciary duties by the individual defendants, in that it allegedly does not maximize the value for our stockholders and that the individual defendants acted in their own self-interest in negotiating the transaction, (b) the joint proxy statement contains incomplete and misleading disclosures and (c) the other defendants aided and abetted the individual defendants’ breaches of fiduciary duties. The complaints seek, among other things, (a) a declaration that the NRG Merger Agreement was entered into in breach of the defendants’ duties, (b) to enjoin defendants from consummating the NRG Merger, (c) directing the defendants to exercise their duties to obtain a transaction which is in the best interests of our stockholders, (d) granting the class members any benefits allegedly improperly received by the defendants, (e) a rescission of the NRG Merger if it is consummated and/or (f)