EXHIBIT 99.5
The information provided in this Exhibit is presented only in connection with the reporting changes described in the accompanying Form 8-K. This information does not reflect events occurring after February 28, 2012, the date we filed our 2011 Form 10-K, and does not modify or update the disclosures therein in any way, other than as required to reflect the change in reportable segments and the adoption of a new accounting standard, as described in the Form 8-K and set forth in Exhibits 99.1 through 99.5 attached thereto. You should therefore read this information in conjunction with the 2011 Form 10-K and any subsequent amendments on Form 10-K/A and with our reports filed with the Securities and Exchange Commission after February 28, 2012.
Part II, Item 8 — Financial Statements and Supplementary Data
The financial statements and schedules are listed in Part IV, Item 15 of this Form 8-K.
Part IV, Item 15 — Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the reports thereon of KPMG LLP, are included herein:
Consolidated Statements of Operations - Years ended December 31, 2011, 2010, and 2009
Consolidated Statements of Comprehensive (Loss)/Income - Years ended December 31, 2011, 2010, and 2009
Consolidated Balance Sheets - December 31, 2011 and 2010
Consolidated Statements of Cash Flows - Years ended December 31, 2011, 2010, and 2009
Consolidated Statement of Stockholders' Equity - Years ended December 31, 2011, 2010, and 2009
Notes to Consolidated Financial Statements
(a)(2) Financial Statement Schedule
The following Consolidated Financial Statement Schedule of NRG Energy, Inc. is filed as part of Item 15(d) of this report and should be read in conjunction with the Consolidated Financial Statements.
Schedule II - Valuation and Qualifying Accounts
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.
1
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
NRG Energy Inc.'s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company's management, including its principal executive officer, principal financial officer and principal accounting officer, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company's evaluation under the framework in Internal Control — Integrated Framework, the Company's management concluded that its internal control over financial reporting was effective as of December 31, 2011.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2011, has been audited by KPMG LLP, the Company's independent registered public accounting firm, as stated in its report which is included herein.
2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
NRG Energy, Inc.:
We have audited NRG Energy, Inc.'s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). NRG Energy, Inc.'s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, NRG Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of NRG Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive (loss)/income, cash flows, and stockholders' equity for each of the years in the three-year period ended December 31, 2011, and our report dated February 28, 2012 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP | |
KPMG LLP | |
Philadelphia, Pennsylvania | |
February 28, 2012 |
3
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
NRG Energy, Inc.:
We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive (loss)/income, cash flows, and stockholders' equity for each of the years in the three-year period ended December 31, 2011. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule “Schedule II Valuation and Qualifying Accounts.” These consolidated financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NRG Energy, Inc. and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
The accompanying consolidated financial statements and financial statement schedule have been retroactively adjusted, as applicable, for the update in segment structure and the change in method of presenting comprehensive income as described in Note 2 to the consolidated financial statements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of NRG Energy, Inc. and subsidiaries internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2012 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.
/s/ KPMG LLP | |
KPMG LLP | |
Philadelphia, Pennsylvania | |
February 28, 2012, except as to the effects of the update in segment structure and the method of presenting comprehensive income as described in Note 2 to the consolidated financial statements, as to which the date is July 23, 2012. |
4
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Year Ended December 31, | |||||||||||
(In millions, except per share amounts) | 2011 | 2010 | 2009 | ||||||||
Operating Revenues | |||||||||||
Total operating revenues | $ | 9,079 | $ | 8,849 | $ | 8,952 | |||||
Operating Costs and Expenses | |||||||||||
Cost of operations | 6,675 | 6,073 | 5,323 | ||||||||
Depreciation and amortization | 896 | 838 | 818 | ||||||||
Impairment charge on emission allowances | 160 | — | — | ||||||||
Selling, general and administrative | 668 | 598 | 550 | ||||||||
Reliant Energy acquisition-related transaction and integration costs | — | — | 54 | ||||||||
Development costs | 45 | 55 | 48 | ||||||||
Total operating costs and expenses | 8,444 | 7,564 | 6,793 | ||||||||
Gain on sale of assets | — | 23 | — | ||||||||
Operating Income | 635 | 1,308 | 2,159 | ||||||||
Other Income/(Expense) | |||||||||||
Equity in earnings of unconsolidated affiliates | 35 | 44 | 41 | ||||||||
Gain on sale of equity method investments | — | — | 128 | ||||||||
Impairment charge on investment | (495 | ) | — | — | |||||||
Other income/(expense), net | 19 | 33 | (5 | ) | |||||||
Loss on debt extinguishment and refinancing expense | (175 | ) | (2 | ) | (20 | ) | |||||
Interest expense | (665 | ) | (630 | ) | (634 | ) | |||||
Total other expense | (1,281 | ) | (555 | ) | (490 | ) | |||||
(Loss)/Income Before Income Taxes | (646 | ) | 753 | 1,669 | |||||||
Income tax (benefit)/expense | (843 | ) | 277 | 728 | |||||||
Net Income | 197 | 476 | 941 | ||||||||
Less: Net loss attributable to noncontrolling interest | — | (1 | ) | (1 | ) | ||||||
Net Income Attributable to NRG Energy, Inc. | 197 | 477 | 942 | ||||||||
Dividends for preferred shares | 9 | 9 | 33 | ||||||||
Income Available for Common Stockholders | $ | 188 | $ | 468 | $ | 909 | |||||
Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders | |||||||||||
Weighted average number of common shares outstanding — basic | 240 | 252 | 246 | ||||||||
Net Income per Weighted Average Common Share — Basic | $ | 0.78 | $ | 1.86 | $ | 3.70 | |||||
Weighted average number of common shares outstanding — diluted | 241 | 254 | 271 | ||||||||
Net Income per Weighted Average Common Share — Diluted | $ | 0.78 | $ | 1.84 | $ | 3.44 | |||||
See notes to Consolidated Financial Statements.
5
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
For the Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions) | |||||||||||
Net Income | $ | 197 | $ | 476 | $ | 941 | |||||
Other comprehensive (loss)/income, net of tax | |||||||||||
Foreign currency translation adjustments, net of income tax benefit/(expense) of $1, $1, and $(21) | (2 | ) | (3 | ) | 35 | ||||||
Reclassification adjustment for translation loss realized upon sale of MIBRAG, net of income tax benefit of $0, $0, and $13 | — | — | (22 | ) | |||||||
Unrealized (loss)/gain on derivatives, net of income tax benefit/(expense) of $181, ($20), and ($53) | (309 | ) | 35 | 91 | |||||||
Available-for-sale securities, net of income tax expense of $0, $0, and $2 | (1 | ) | — | 4 | |||||||
Defined benefit plan, net of income tax benefit of $27, $9, and $1 | (46 | ) | (16 | ) | (2 | ) | |||||
Other comprehensive (loss)/income | (358 | ) | 16 | 106 | |||||||
Comprehensive (loss)/income | (161 | ) | 492 | 1,047 | |||||||
Less: Comprehensive loss attributable to noncontrolling interest | — | (1 | ) | (1 | ) | ||||||
Comprehensive (loss)/income attributable to NRG Energy, Inc. | (161 | ) | 493 | 1,048 | |||||||
Dividends for preferred shares | 9 | 9 | 33 | ||||||||
Comprehensive (loss)/income available for common stockholders | $ | (170 | ) | $ | 484 | $ | 1,015 | ||||
See notes to Consolidated Financial Statements.
6
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
As of December 31, | |||||||
2011 | 2010 | ||||||
(In millions) | |||||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | $ | 1,105 | $ | 2,951 | |||
Funds deposited by counterparties | 258 | 408 | |||||
Restricted cash | 292 | 8 | |||||
Accounts receivable — trade, less allowance for doubtful accounts of $23 and $25 | 834 | 734 | |||||
Inventory | 308 | 453 | |||||
Derivative instruments | 4,216 | 1,964 | |||||
Cash collateral paid in support of energy risk management activities | 311 | 323 | |||||
Prepayments and other current assets | 273 | 296 | |||||
Total current assets | 7,597 | 7,137 | |||||
Property, Plant and Equipment | |||||||
In service | 15,704 | 14,913 | |||||
Under construction | 2,487 | 1,400 | |||||
Total property, plant and equipment | 18,191 | 16,313 | |||||
Less accumulated depreciation | (4,570 | ) | (3,796 | ) | |||
Net property, plant and equipment | 13,621 | 12,517 | |||||
Other Assets | |||||||
Equity investments in affiliates | 640 | 536 | |||||
Capital leases and notes receivable, less current portion | 342 | 384 | |||||
Goodwill | 1,886 | 1,868 | |||||
Intangible assets, net of accumulated amortization of $1,452 and $1,064 | 1,419 | 1,776 | |||||
Nuclear decommissioning trust fund | 424 | 412 | |||||
Derivative instruments | 450 | 758 | |||||
Restricted cash supporting funded letter of credit facility | — | 1,300 | |||||
Other non-current assets | 336 | 208 | |||||
Total other assets | 5,497 | 7,242 | |||||
Total Assets | $ | 26,715 | $ | 26,896 |
See notes to Consolidated Financial Statements.
7
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued)
As of December 31, | |||||||
2011 | 2010 | ||||||
(In millions, except share data) | |||||||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current Liabilities | |||||||
Current portion of long-term debt and capital leases | $ | 87 | $ | 463 | |||
Accounts payable | 808 | 783 | |||||
Derivative instruments | 3,751 | 1,685 | |||||
Deferred income taxes | 127 | 108 | |||||
Cash collateral received in support of energy risk management activities | 258 | 408 | |||||
Accrued interest expense | 165 | 192 | |||||
Other accrued expenses | 281 | 307 | |||||
Other current liabilities | 194 | 274 | |||||
Total current liabilities | 5,671 | 4,220 | |||||
Other Liabilities | |||||||
Long-term debt and capital leases | 9,745 | 8,748 | |||||
Funded letter of credit | — | 1,300 | |||||
Nuclear decommissioning reserve | 335 | 317 | |||||
Nuclear decommissioning trust liability | 254 | 272 | |||||
Postretirement and other benefit obligations | 400 | 322 | |||||
Deferred income taxes | 1,389 | 1,989 | |||||
Derivative instruments | 464 | 365 | |||||
Out-of-market commodity contracts | 183 | 223 | |||||
Other non-current liabilities | 356 | 820 | |||||
Total non-current liabilities | 13,126 | 14,356 | |||||
Total Liabilities | 18,797 | 18,576 | |||||
3.625% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding (at liquidation value of $250, net of issuance costs) | 249 | 248 | |||||
Commitments and Contingencies | |||||||
Stockholders' Equity | |||||||
Common stock; $0.01 par value; 500,000,000 shares authorized; 304,183,720 and 304,006,027 shares issued and 227,519,521 and 247,197,355 shares outstanding at December 31, 2011 and 2010 | 3 | 3 | |||||
Additional paid-in capital | 5,346 | 5,323 | |||||
Retained earnings | 3,987 | 3,800 | |||||
Less treasury stock, at cost — 76,664,199 and 56,808,672 shares at December 31, 2011 and 2010 | (1,924 | ) | (1,503 | ) | |||
Accumulated other comprehensive income | 74 | 432 | |||||
Noncontrolling interest | 183 | 17 | |||||
Total Stockholders' Equity | 7,669 | 8,072 | |||||
Total Liabilities and Stockholders' Equity | $ | 26,715 | $ | 26,896 |
See notes to Consolidated Financial Statements.
8
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
(In millions) | ||||||||||||
Cash Flows from Operating Activities | ||||||||||||
Net income | $ | 197 | $ | 476 | $ | 941 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Distributions and equity in earnings of unconsolidated affiliates | 9 | (19 | ) | (41 | ) | |||||||
Depreciation and amortization | 896 | 838 | 818 | |||||||||
Provision for bad debts | 59 | 54 | 61 | |||||||||
Amortization of nuclear fuel | 39 | 40 | 36 | |||||||||
Amortization of financing costs and debt discount/premiums | 32 | 32 | 44 | |||||||||
Loss on debt extinguishment | 58 | — | — | |||||||||
Amortization of intangibles and out-of-market commodity contracts | 167 | 4 | 153 | |||||||||
Amortization of unearned equity compensation | 28 | 30 | 26 | |||||||||
Loss on disposals and sales of assets | 14 | 4 | 13 | |||||||||
Impairment charges and asset write downs | 657 | 25 | — | |||||||||
Changes in derivative instruments | (138 | ) | (114 | ) | (225 | ) | ||||||
Changes in deferred income taxes and liability for uncertain tax benefits | (859 | ) | 255 | 689 | ||||||||
Gain on sale of equity method investment | — | — | (128 | ) | ||||||||
Gain recognized on settlement of pre-existing relationship | — | — | (31 | ) | ||||||||
Changes in nuclear decommissioning trust liability | 20 | 34 | 26 | |||||||||
Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects: | ||||||||||||
Accounts receivable - trade | (119 | ) | 138 | 88 | ||||||||
Inventory | 145 | 91 | (83 | ) | ||||||||
Prepayments and other current assets | 59 | (51 | ) | 26 | ||||||||
Accounts payable | 9 | (261 | ) | (176 | ) | |||||||
Accrued expenses and other current liabilities | (111 | ) | (48 | ) | 48 | |||||||
Other assets and liabilities | 4 | 95 | (179 | ) | ||||||||
Net Cash Provided by Operating Activities | 1,166 | 1,623 | 2,106 | |||||||||
Cash Flows from Investing Activities | ||||||||||||
Acquisition of businesses, net of cash acquired | (377 | ) | (1,006 | ) | (427 | ) | ||||||
Capital expenditures | (2,310 | ) | (706 | ) | (734 | ) | ||||||
(Increase)/decrease in restricted cash, net | (35 | ) | (4 | ) | 14 | |||||||
Increase in restricted cash to support equity requirements for U.S. DOE funded projects | (215 | ) | — | — | — | |||||||
Decrease/(increase) in notes receivable | 12 | 39 | (22 | ) | ||||||||
Proceeds from renewable energy grants | — | 102 | — | |||||||||
Purchases of emission allowances, net of proceeds | (19 | ) | (34 | ) | (38 | ) | ||||||
Investments in nuclear decommissioning trust fund securities | (406 | ) | (341 | ) | (305 | ) | ||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 385 | 307 | 279 | |||||||||
Proceeds from sale of assets, net | 7 | 43 | 6 | |||||||||
(Investments in)/proceeds from sales of unconsolidated affiliates, net | (66 | ) | (23 | ) | 278 | |||||||
Other | (23 | ) | — | (5 | ) | |||||||
Net Cash Used by Investing Activities | (3,047 | ) | (1,623 | ) | (954 | ) | ||||||
Cash Flows from Financing Activities | ||||||||||||
Payment of dividends to preferred stockholders | (9 | ) | (9 | ) | (33 | ) | ||||||
(Payments for)/net receipts from settlement of acquired derivatives that include financing elements | (83 | ) | 137 | (79 | ) | |||||||
Payment for treasury stock | (430 | ) | (180 | ) | (500 | ) | ||||||
Cash proceeds from noncontrolling interest in subsidiary | 29 | 50 | 50 | |||||||||
Proceeds from issuance of common stock | 2 | 2 | 2 | |||||||||
Proceeds from issuance of long-term debt | 6,224 | 1,484 | 892 | |||||||||
(Payments for)/proceeds from term loan for funded letter of credit facility | (1,300 | ) | 1,300 | — | ||||||||
Decrease/(increase) in restricted cash supporting funded letter of credit facility | 1,300 | (1,300 | ) | — | ||||||||
Payment of debt issuance and hedging costs | (207 | ) | (75 | ) | (31 | ) | ||||||
Payments for short and long-term debt | (5,493 | ) | (758 | ) | (644 | ) | ||||||
Net Cash Provided By/(Used by) Financing Activities | 33 | 651 | (343 | ) | ||||||||
Effect of exchange rate changes on cash and cash equivalents | 2 | (4 | ) | 1 | ||||||||
Net (Decrease)/Increase in Cash and Cash Equivalents | (1,846 | ) | 647 | 810 | ||||||||
Cash and Cash Equivalents at Beginning of Period | 2,951 | 2,304 | 1,494 | |||||||||
Cash and Cash Equivalents at End of Period | $ | 1,105 | $ | 2,951 | $ | 2,304 |
See notes to Consolidated Financial Statements.
9
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Preferred Stock | Common Stock | Additional Paid-In Capital | Retained Earnings | Treasury Stock | Accumulated Other Comprehensive Income/(Loss) | Noncon-trolling Interest | Total Stockholders' Equity | ||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||||||
Balances at December 31, 2008 | $ | 853 | $ | 3 | $ | 4,350 | $ | 2,423 | $ | (823 | ) | $ | 310 | $ | 7 | $ | 7,123 | ||||||||||||||
Net income/(loss) | 942 | (1 | ) | 941 | |||||||||||||||||||||||||||
Other comprehensive income | 106 | 106 | |||||||||||||||||||||||||||||
Equity-based compensation | 26 | 26 | |||||||||||||||||||||||||||||
Purchase of treasury stock | (500 | ) | (500 | ) | |||||||||||||||||||||||||||
Preferred stock dividends | (33 | ) | (33 | ) | |||||||||||||||||||||||||||
ESPP share purchases | 2 | 2 | |||||||||||||||||||||||||||||
NINA contribution, net of $16 tax | 28 | 6 | 34 | ||||||||||||||||||||||||||||
5.75% preferred stock conversion to common stock | (447 | ) | 447 | — | |||||||||||||||||||||||||||
4.00% preferred stock conversion to common stock | (257 | ) | 257 | — | |||||||||||||||||||||||||||
Shares loaned to affiliate of CS | (291 | ) | 291 | — | |||||||||||||||||||||||||||
Shares returned from affiliate of CS | 131 | (131 | ) | — | |||||||||||||||||||||||||||
Other | (2 | ) | (2 | ) | |||||||||||||||||||||||||||
Balances at December 31, 2009 | $ | 149 | $ | 3 | $ | 4,948 | $ | 3,332 | $ | (1,163 | ) | $ | 416 | $ | 12 | $ | 7,697 | ||||||||||||||
Net income/(loss) | 477 | (1 | ) | 476 | |||||||||||||||||||||||||||
Other comprehensive income | 16 | 16 | |||||||||||||||||||||||||||||
Equity-based compensation | 28 | 28 | |||||||||||||||||||||||||||||
Purchase of treasury stock | (180 | ) | (180 | ) | |||||||||||||||||||||||||||
Preferred stock dividends | (9 | ) | (9 | ) | |||||||||||||||||||||||||||
ESPP share purchases | 3 | 3 | |||||||||||||||||||||||||||||
NINA contribution, net of $17 tax | 27 | 6 | 33 | ||||||||||||||||||||||||||||
4.00% preferred stock conversion to common stock | (149 | ) | 149 | — | |||||||||||||||||||||||||||
Shares returned from affiliate of CS | 160 | (160 | ) | — | |||||||||||||||||||||||||||
Other | 8 | 8 | |||||||||||||||||||||||||||||
Balances at December 31, 2010 | $ | — | $ | 3 | $ | 5,323 | $ | 3,800 | $ | (1,503 | ) | $ | 432 | $ | 17 | $ | 8,072 | ||||||||||||||
Net income | 197 | 197 | |||||||||||||||||||||||||||||
Other comprehensive loss | (358 | ) | (358 | ) | |||||||||||||||||||||||||||
Equity-based compensation | 28 | 28 | |||||||||||||||||||||||||||||
Purchase of treasury stock | (430 | ) | (430 | ) | |||||||||||||||||||||||||||
Preferred stock dividends | (9 | ) | (9 | ) | |||||||||||||||||||||||||||
ESPP share purchases | (5 | ) | (1 | ) | 9 | 3 | |||||||||||||||||||||||||
NINA contribution | (17 | ) | (17 | ) | |||||||||||||||||||||||||||
Ivanpah contribution | 183 | 183 | |||||||||||||||||||||||||||||
Balances at December 31, 2011 | $ | — | $ | 3 | $ | 5,346 | $ | 3,987 | $ | (1,924 | ) | $ | 74 | $ | 183 | $ | 7,669 |
See notes to Consolidated Financial Statements.
10
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Nature of Business
General
NRG Energy, Inc., or NRG or the Company, is an integrated wholesale power generation and retail electricity company in the United States. First, NRG is a wholesale power generator engaged in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; and the transacting in and trading of fuel and transportation services. Second, NRG is a retail electricity company engaged in the supply of electricity, energy services, and cleaner energy products to retail electricity customers in deregulated markets through Reliant Energy, Green Mountain Energy, and Energy Plus, (collectively, the Retail Businesses). Finally, NRG is focused on the deployment and commercialization of potential disruptive technologies, like electric vehicles, Distributed Solar and smart meter technology, which have the potential to change the nature of the power supply industry.
NRG's domestic generation facilities consist of intermittent, baseload, intermediate, and peaking power generation facilities. The following table summarizes NRG's global generation portfolio by operating segment, which includes 47 fossil fuel plants, three Utility Scale Solar facilities and four wind farms, as well as Distributed Solar facilities. Also included are one natural gas plant, six Utility Scale Solar facilities and additional Distributed Solar facilities currently under construction. All Utility Scale Solar and Distributed Solar facilities are described in megawatts on an alternating current, or AC, basis:
Fossil Fuel, Nuclear, and Renewable | |||||||||||||||||||||||||||
(In MW) | |||||||||||||||||||||||||||
Generation Type | Texas | Northeast | South Central | West | Other (Thermal) | Alter- native Energy | Total Domestic | Other (Inter-national) | Total Global | ||||||||||||||||||
Natural gas | 4,930 | 1,300 | 2,630 | 2,130 | 105 | — | 11,095 | — | 11,095 | ||||||||||||||||||
Coal | 4,190 | 1,600 | 1,495 | — | 15 | — | 7,300 | 1,005 | 8,305 | ||||||||||||||||||
Oil | — | 4,015 | — | — | — | — | 4,015 | — | 4,015 | ||||||||||||||||||
Nuclear | 1,175 | — | — | — | — | — | 1,175 | — | 1,175 | ||||||||||||||||||
Wind | — | — | — | — | — | 450 | 450 | — | 450 | ||||||||||||||||||
Utility Scale Solar | — | — | — | — | — | 65 | 65 | — | 65 | ||||||||||||||||||
Distributed Solar | — | — | — | — | — | 30 | 30 | — | 30 | ||||||||||||||||||
Total generation capacity | 10,295 | 6,915 | 4,125 | 2,130 | 120 | 545 | 24,130 | 1,005 | 25,135 | ||||||||||||||||||
Under Construction | |||||||||||||||||||||||||||
Natural gas | — | — | — | 550 | — | — | 550 | — | 550 | ||||||||||||||||||
Utility Scale Solar (a) | — | — | — | — | — | 855 | 855 | — | 855 | ||||||||||||||||||
Distributed Solar | — | — | — | — | — | 5 | 5 | — | 5 | ||||||||||||||||||
Total under construction | — | — | — | 550 | — | 860 | 1,410 | — | 1,410 |
(a) Includes 142 MW, representing 49% of Agua Caliente's capacity, which was sold to a partner on January 18, 2012
In addition, the Company's thermal assets provide steam and chilled water capacity of approximately 1,170 megawatts thermal equivalent, or MWt, through its district energy business.
NRG sells power from its generation portfolio and offers capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.
NRG's Retail Businesses arrange for the transmission and delivery of electricity to customers, bill customers, collect payments for electricity sold and maintain call centers to provide customer service. Based on metered locations, as of December 31, 2011, the Retail Businesses combined to serve approximately 2.1 million residential, small business, commercial and industrial customers.
NRG was incorporated as a Delaware corporation on May 29, 1992. NRG's common stock is listed on the New York Stock Exchange under the symbol "NRG". The Company's headquarters and principal executive offices are located at 211 Carnegie Center, Princeton, New Jersey 08540. NRG's telephone number is (609) 524-4500. The address of the Company's website is www.nrgenergy.com. NRG's recent annual reports, quarterly reports, current reports, and other periodic filings are available free of charge through the Company's website.
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Note 2 — Summary of Significant Accounting Policies
Principles of Consolidation and Basis of Presentation
The Company's consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S., or U.S. GAAP. The Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, is the source of authoritative U.S. GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative releases of the SEC under authority of federal securities laws are also sources of authoritative U.S. GAAP for SEC registrants.
The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation. The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or not controlled through its voting interests, referred to as a variable interest entity, or VIE, should be consolidated.
2012 Business Segment Realignment
Effective in fiscal year 2012, NRG's segment structure and its allocation of corporate expenses were updated to reflect how management currently makes financial decisions and allocates resources. The Company has recast the data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are primarily segregated based on the Retail businesses, conventional power generation, alternative energy businesses and corporate activities. Within NRG's conventional power generation operations, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, Northeast, South Central, West, and Other, which includes its international businesses, thermal and chilled water business and maintenance services. The Company's alternative energy businesses include solar and wind assets, electric vehicle services and carbon capture business.
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of purchase.
Funds Deposited by Counterparties
Funds deposited by counterparties consist of cash held by NRG as a result of collateral posting obligations from the Company's counterparties with positions in NRG's hedging program. These amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of NRG's general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities. Changes in funds deposited by counterparties are closely associated with the Company's operating activities, and are classified as an operating activity in the Company's consolidated statements of cash flows.
Restricted Cash
Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within the Company's projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments as well as to fund required equity contributions, per the restrictions of the debt agreements.
Trade Receivables and Allowance for Doubtful Accounts
Trade receivables are reported in the balance sheet at outstanding principal adjusted for any write-offs and the allowance for doubtful accounts. For its Retail Businesses, the Company accrues an allowance for doubtful accounts based on estimates of uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections, accounts receivable aging and other factors. These businesses write-off accounts receivable balances against the allowance for doubtful accounts when it determines a receivable is uncollectible.
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Inventory
Inventory is valued at the lower of weighted average cost or market, and consists principally of fuel oil, coal and raw materials used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or steam. Spare parts inventory is valued at a weighted average cost, since the Company expects to recover these costs in the ordinary course of business. The Company removes these inventories when they are used for repairs, maintenance or capital projects. Sales of inventory are classified as an operating activity in the consolidated statements of cash flows.
Property, Plant and Equipment
Property, plant and equipment are stated at cost; however impairment adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable. NRG also classifies nuclear fuel related to the Company's 44% ownership interest in South Texas Project, or STP, as part of the Company's property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation other than nuclear fuel is computed using the straight-line method, while nuclear fuel is amortized based on units of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of operations.
Asset Impairments
Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360, Property, Plant, and Equipment, or ASC 360. An impairment loss is recognized if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs and expenses in the statements of operations. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.
Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-Equity Method and Joint Ventures, or ASC 323, which requires that a loss in value of an investment that is other than a temporary decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon a comparison of fair value to carrying value.
Discontinued Operations
Long-lived assets or disposal groups are classified as discontinued operations when all of the required criteria specified in ASC 360 are met. These criteria include, among others, existence of a qualified plan to dispose of an asset or disposal group, an assessment that completion of a sale within one year is probable and approval of the appropriate level of management. In addition, upon completion of the transaction, the operations and cash flows of the disposal group must be eliminated from ongoing operations of the Company, and the disposal group must not have any significant continuing involvement with the Company. Discontinued operations are reported at the lower of the asset's carrying amount or fair value less cost to sell. The Company had no discontinued operations for the three years ended December 31, 2011.
Project Development Costs and Capitalized Interest
Project development costs are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset.
Interest incurred on funds borrowed to finance capital projects is capitalized, until the project under construction is ready for its intended use. The amount of interest capitalized for the years ended December 31, 2011, 2010, and 2009, was $80 million, $36 million, and $37 million, respectively.
When a project is available for operations, capitalized interest and project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.
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Debt Issuance Costs
Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest method over the term of the related debt.
Intangible Assets
Intangible assets represent contractual rights held by NRG. The Company recognizes specifically identifiable intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, development rights, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. In addition, NRG also established values for emission allowances and power contracts upon adoption of Fresh Start reporting. These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows, straight line or units of production basis.
Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to have finite lives and should now be amortized over their useful lives. NRG had no intangible assets with indefinite lives recorded as of December 31, 2011.
Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC 360.
Goodwill
In accordance with ASC 350, Goodwill - Intangibles and Others, or ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter, and when events or changes in circumstances indicate that the carrying value may not be recoverable.
In September 2011, the FASB issued ASU No. 2011-08, Intangibles - Goodwill and Other (Topic 350) Testing Goodwill for Impairment, or ASU No. 2011-08. The objective of ASU 2011-08 is to simplify how entities test goodwill for impairment. The amendments in ASU No. 2011-08 permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent. ASU No. 2011-08 is effective for annual and interim goodwill impairment tests performed in fiscal years beginning after December 15, 2011. Early adoption is permitted. The Company adopted the provisions of ASU No. 2011-08, effective January 1, 2011, with no impact on its results of operations, financial position or cash flows.
In the absence of sufficient qualitative factors, goodwill impairment is determined using a two step process:
Step one — | Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two. | |
Step two — | Compare the implied fair value of the reporting unit's goodwill to the book value of the reporting unit goodwill. If the book value of goodwill exceeds fair value, an impairment charge is recognized for the sum of such excess. |
Income Taxes
NRG accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.
NRG has two categories of income tax expense or benefit — current and deferred, as follows:
• | Current income tax expense or benefit consists solely of tax less applicable tax credits, and |
• | Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income. |
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NRG reports some of the Company's revenues and expenses differently for financial statement purposes than for income tax return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax liabilities in the Company's consolidated balance sheets. NRG measures the Company's deferred income tax assets and deferred income tax liabilities using income tax rates that are currently in effect. A valuation allowance is recorded to reduce the Company's net deferred tax assets to an amount that is more-likely-than-not to be realized.
The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and penalties accrued related to uncertain tax benefits as a component of income tax expense.
In accordance with ASC 805 and as discussed further in Note 19, Income Taxes, changes to existing net deferred tax assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.
Revenue Recognition
Energy — Both physical and financial transactions are entered into to optimize the financial performance of NRG's generating facilities. Electric energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815, Derivatives and Hedging, or ASC 815.
Capacity — Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity and reliability requirements.
Sale of Emission Allowances — NRG records the Company's bank of emission allowances as part of the Company's intangible assets. From time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission bank to intangible assets held-for-sale for trading purposes. NRG records the sale of emission allowances on a net basis within operating revenue in the Company's consolidated statements of operations.
Contract Amortization — Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation and/or contracted volumes.
Retail revenues — Gross revenues for energy sales and services to retail customers are recognized upon delivery under the accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues also includes energy revenues from resales of purchased power, which were $186 million and $158 million for the years ended December 31, 2011, and 2010, respectively, and $251 million for the eight-month period ended December 31, 2009. These revenues represent the sale of excess supply to third parties in the market.
Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed. NRG recorded receivables for unbilled revenues of $318 million and $282 million as of December 31, 2011 and 2010, respectively, for retail energy sales and services.
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Cost of Energy for Retail Operations
The cost of energy for electricity sales and services to retail customers is based on estimated supply volumes for the applicable reporting period. A portion of the cost of energy ($87 million and $61 million as of December 31, 2011, and 2010, respectively) was accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, Independent System Operator, or ISO, fees are estimated based on historical trends, estimated supply volumes and initial Electric Reliability Council of Texas, or ERCOT, ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.
Derivative Financial Instruments
NRG accounts for derivative financial instruments under ASC 815, Derivatives and Hedging, or ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value unless they qualify for a Normal Purchase Normal Sale, or NPNS, exception. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as hedges, if elected for hedge accounting, are either:
• | Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or |
• | Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings. |
NRG's primary derivative instruments are power sales contracts, fuels purchase contracts, other energy related commodities, and interest rate instruments used to mitigate variability in earnings due to fluctuations in market prices and interest rates. On an ongoing basis, NRG assesses the effectiveness of all derivatives that are designated as hedges for accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated hedged item determine the effectiveness of such an energy contract designated as a hedge. If it is determined that the derivative instrument is not highly effective as a hedge, hedge accounting will be discontinued prospectively. Hedge accounting will also be discontinued on contracts related to commodity price risk previously accounted for as cash flow hedges when it is probable that delivery will not be made against these contracts. In this case, the gain or loss previously deferred in accumulated OCI would be immediately reclassified into earnings. If the derivative instrument is terminated, the effective portion of this derivative deferred in accumulated OCI will be frozen until the underlying hedged item is delivered.
Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.
NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
Foreign Currency Translation and Transaction Gains and Losses
The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's statements of operations for the period, but are accumulated and reported as a separate component of stockholders' equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign currency transaction gains or losses are reported within other income/(expense) in the Company's statements of operations. For the years ended December 31, 2011, 2010, and 2009, amounts recognized as foreign currency transaction gains (losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2011, and 2010 were $72 million and $76 million, respectively.
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Concentrations of Credit Risk
Financial instruments which potentially subject NRG to concentrations of credit risk consist primarily of cash, trust funds, accounts receivable, notes receivable, derivatives, and investments in debt securities. Cash and cash equivalents and funds deposited by counterparties are predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt. Trust funds are held in accounts managed by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling agreements. However, NRG believes that the credit risk posed by industry concentration is offset by the diversification and creditworthiness of the Company's customer base. See Note 5, Fair Value of Financial Instruments, for a further discussion of derivative concentrations.
Fair Value of Financial Instruments
The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payables, and accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 5, Fair Value of Financial Instruments for a further discussion of fair value of financial instruments.
Asset Retirement Obligations
NRG accounts for its asset retirement obligations, or AROs, in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can be made.
Upon initial recognition of a liability for an ARO, NRG capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the capitalized cost is depreciated over the useful life of the related asset. See Note 13, Asset Retirement Obligations, for a further discussion of AROs.
Pensions
NRG offers pension benefits through either a defined benefit pension plan or a cash balance plan. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. NRG accounts for pension and other postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits. NRG recognizes the funded status of the Company's defined benefit plans in the statement of financial position and records an offset to other comprehensive income. In addition, NRG also recognizes on an after-tax basis, as a component of other comprehensive income, gains and losses as well as all prior service costs that have not been included as part of the Company's net periodic benefit cost. The determination of NRG's obligation and expenses for pension benefits is dependent on the selection of certain assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets and the rate of future compensation increases. NRG's actuarial consultants determine assumptions for such items as retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the amount of pension obligation or expense recorded by the Company.
NRG measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820.
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Stock-Based Compensation
NRG accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock Compensation, or ASC 718. The fair value of the Company's non-qualified stock options and performance units are estimated on the date of grant using the Black-Scholes option-pricing model and the Monte Carlo valuation model, respectively. NRG uses the Company's common stock price on the date of grant as the fair value of the Company's restricted stock units and deferred stock units. Forfeiture rates are estimated based on an analysis of NRG's historical forfeitures, employment turnover, and expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award.
Investments Accounted for by the Equity Method
NRG has investments in various international and domestic energy projects. The equity method of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership structure prevents NRG from exercising a controlling influence over the operating and financial policies of the projects. Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of international projects, are reflected as equity in earnings of unconsolidated affiliates.
Gross Receipts and Sales Taxes
In connection with its Retail Businesses, the Company records gross receipts taxes on a gross basis in revenues and cost of operations in its consolidated statements of operations. During the years ended December 31, 2011, 2010, and the eight-month period ended December 31, 2009, NRG's revenues and cost of operations included gross receipts taxes of $64 million, $67 million, and $55 million, respectively. Additionally, the Retail Businesses record sales taxes collected from their taxable customers and remitted to the various governmental entities on a net basis, thus, there is no impact on the Company's consolidated statement of operations.
Marketing and Advertising Costs
The Company expenses its advertising and marketing costs as incurred. The costs of tangible assets used in advertising campaigns are recorded as fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements are deferred and expensed over the term of the arrangement. Marketing and advertising expenses included within selling, general and administrative expense for the years ended December 31, 2011, 2010, and 2009 were $127 million, $81 million, and $47 million, respectively.
Business Combinations
The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805. ASC 805 requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition, transaction costs are expensed as incurred.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
In recording transactions and balances resulting from business operations, NRG uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially determined benefit costs, and the valuation of energy commodity contracts, environmental liabilities, and legal costs incurred in connection with recorded loss contingencies, among others. In addition, estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
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Reclassifications
Certain prior-year amounts have been reclassified for comparative purposes.
Recent Accounting Developments
ASU 2011-05 — In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220) Presentation of Comprehensive Income, or ASU No. 2011-05, which was further amended by ASU No. 2011-12, Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05, issued in December 2011. The amendments in ASU No. 2011-05 require the Company to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single statement of comprehensive income or in two separate but consecutive statements. The Company is required to present, in either option, each component of net income, total net income, each component of other comprehensive income, total other comprehensive income and total comprehensive income. The provisions of ASU No. 2011-05 are required to be adopted retroactively. The Company adopted the provisions of ASU No. 2011-05 on January 1, 2012 and began presenting the total of comprehensive income, the components of net income and the components of other comprehensive income in two separate but consecutive statements. As this guidance provides only presentation requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.
ASU 2011-11 — In December 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities, or ASU No. 2011-11. The guidance provides enhanced disclosure requirements to evaluate the effect or potential effect of netting arrangements on an entity's financial position by improving information about financial instruments and derivative instruments that either (1) offset in accordance with either ASC 210-20-45 or ASC 810-20-45 or (2) are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. Reporting entities will be required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The disclosures required by ASU No. 2011-10 are required to be adopted retroactively. ASU No. 2011-11 is effective for annual and interim periods in fiscal years beginning on or after January 1, 2013, and early adoption is permitted. As this guidance provides only disclosure requirements, the adoption of this standard will not impact the Company's results of operations, cash flows or financial position.
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Note 3 — Business Acquisitions and Dispositions
2011 Acquisitions
Energy Plus — On September 30, 2011, NRG acquired Energy Plus Holdings LLC, or Energy Plus, for $194 million in cash, net of $5 million cash acquired, funded from cash on hand. Energy Plus is a retail electricity provider with 188,000 customers as of December 31, 2011, a Northeast concentration and a unique sales channel involving exclusive loyalty and affinity program partnerships. Energy Plus will be run as a standalone retail business within NRG. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was primarily allocated to customer relationships of $63 million, marketing partnerships of $88 million, trade names of $10 million and goodwill of $29 million. The initial accounting for the business combination is not complete because the evaluations necessary to assess the fair values of certain net assets acquired and the amount of goodwill to be recognized are still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments will affect the acquisition-date fair value of goodwill. The factors that resulted in goodwill arising from the acquisition include the revenues associated with expanding the Energy Plus retail business and its unique sales channel in new regions, expanding its loyalty and affinity program partnerships and the synergies associated with combining the business with NRG's generation assets.
The provisional fair values of the intangible assets and liabilities at the acquisition date were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. Significant inputs were as follows:
• | Customer relationships — The customer relationships, which reflect Energy Plus' residential and commercial customer base, were valued using a variation of the income approach. Under this approach, the present value of expected future cash flows resulting from the existing customer relationships, considering attrition and charges for contributory assets (such as net working capital, fixed assets, workforce and trade names) utilized in the business were estimated and then discounted at an integrated utility peer group's weighted average cost of capital adjusted to be consistent with the risk inherent in the cash flows. The customer relationships are amortized to depreciation and amortization expense, over a weighted-average amortization period of five years, based on the expected discounted future net cash flows by year. |
• | Loyalty and affinity program partnerships — The marketing partnerships, which reflect Energy Plus' loyalty and affinity program partnerships, were valued using a variation of the income approach. These partnerships are based on contractual relationships typically structured for three to five year periods with options for renewal. Under this approach, the present value of expected future cash flows resulting from the existing marketing partnerships, including renewal expectations and charges for contributory assets (such as working capital, fixed assets, marketing costs, workforce and trade names) utilized in the business, were estimated and then discounted at an integrated utility peer group's weighted average cost of capital adjusted to be consistent with the risk inherent in the cash flows. The marketing partnerships are amortized to depreciation and amortization expense, over a weighted-average amortization period of 18 years, based on the expected discounted net cash flows by year. |
• | Trade names — The trade names were valued using a “relief from royalty” method, an approach under which fair value is estimated to be the present value of royalties saved because NRG owns the intangible asset and therefore does not have to pay a royalty for its use. The avoided royalty revenues were discounted at an integrated utility peer group's weighted average cost of capital adjusted to be consistent with the risk inherent in the cash flows. The remaining useful life of the trade names were determined by considering various factors, such as turnover and name changes in the independent power producer and utility industries, the current age of the Energy Plus brand, management's intent to continue using the name at the current time, and feedback from external consultants regarding their experience with similar trade names. The trade names are amortized to depreciation and amortization expense, on a straight-line basis, over five years. |
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Solar Acquisitions — During the year ended December 31, 2011, NRG acquired stakes in three Utility Scale Solar facilities for approximately $165 million in cash consideration, as part of the Company's initiative to capture opportunities for future growth in renewables. During 2011, subsequent to the acquisition dates, NRG made capital contributions into these projects of $420 million. In addition, NRG has a commitment to contribute additional amounts into the projects, comprised of $216 million in restricted cash and $815 million in letters of credit as of December 31, 2011. The Company may increase its letters of credit to replace the restricted cash at its discretion. In addition, the projects had $49 million in restricted cash for various agreements. NRG's minority partners had contributed approximately $29 million of equity during 2011, subsequent to the acquisition date, and had additional equity commitments of $115 million as of December 31, 2011. These acquisitions were recorded as business combinations under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date.
The acquisitions of these three solar facilities are further described below:
California Valley Solar Ranch — On September 30, 2011, NRG Solar LLC, a wholly-owned subsidiary of NRG, acquired 100% of the 250 MW California Valley Solar Ranch project, or CVSR, in eastern San Luis Obispo County, California. Power generated from CVSR will be sold to Pacific Gas and Electric under a 25 year Power Purchase Agreement, or PPA. In connection with the acquisition, High Plains Ranch II, LLC, a wholly-owned subsidiary of NRG, entered into the California Valley Solar Ranch Financing Agreement with the Federal Financing Bank, or FFB, which is guaranteed by the United States Department of Energy, or U.S. DOE, to borrow up to $1.2 billion to fund the costs of constructing this solar facility, or the CVSR Financing Agreement. The terms of the borrowings, which are non-recourse to NRG, are described further in Note 12, Debt and Capital Leases. The Company continues to work with its partners and the U.S. DOE to satisfy all of the U.S. DOE loan disbursement requirements and funding is anticipated by the end of the first quarter of 2012. Operations are expected to commence in phases beginning in the third quarter of 2012 through the fourth quarter of 2013.
Agua Caliente — On August 5, 2011, NRG, through its wholly-owned subsidiary, NRG Solar PV LLC, acquired 100% of the 290 MW Agua Caliente solar project, or Agua Caliente, in Yuma, AZ. Operations are scheduled to commence in phases beginning in the third quarter of 2012 through the first quarter of 2014. Power generated from Agua Caliente will be sold to Pacific Gas and Electric under a 25 year PPA. In connection with the acquisition, Agua Caliente Solar, LLC, a wholly-owned subsidiary of NRG, entered into the Agua Caliente Financing Agreement with the FFB, which is guaranteed by the U.S. DOE, to borrow up to $967 million to fund the construction of this solar facility, or the Agua Caliente Financing Agreement. The terms of the borrowings, which are non-recourse to NRG, are described further in Note 12, Debt and Capital Leases.
In addition, on January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of the Agua Caliente project entity, to MidAmerican Energy Holdings Company, or MidAmerican. A portion of the cash consideration received at closing represented 49% of construction costs funded by NRG's equity contributions. MidAmerican will fund its proportionate share of future equity contributions and other credit support for the project. NRG will continue to hold a majority interest in the project, which will continue to be consolidated. MidAmerican's non-controlling interest on the Company's balance sheet will represent the fair value of their capital contributions.
Ivanpah — On April 5, 2011, NRG acquired a 50.1% stake in the 392 MW Ivanpah Solar Electric Generation System, or Ivanpah, from BrightSource Energy, Inc., or BSE. BSE maintained a 21.8% interest in Ivanpah and the remaining 28.1% was acquired by a wholly-owned subsidiary of Google. Ivanpah is composed of three separate facilities - Ivanpah 1 (126 MW), Ivanpah 2 (133 MW), and Ivanpah 3 (133 MW), all of which are expected to be fully operational by the end of 2013. Power generated from Ivanpah will be sold to Southern California Edison and Pacific Gas and Electric, under multiple 20 to 25 year PPAs. The non-controlling interest represents the fair value of the capital contributions from the minority investors in Ivanpah. Ivanpah has entered into the Ivanpah Credit Agreement with the FFB, which is guaranteed by the U.S. DOE, to borrow up to $1.6 billion to fund the construction of this solar facility, or the Ivanpah Credit Agreement. The terms of the borrowings, which are non-recourse to NRG, are described further in Note 12, Debt and Capital Leases.
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The purchase price for these acquisitions, considered business combinations, was provisionally allocated as follows:
(In millions) | |||
Assets | |||
Restricted cash | $ | 25 | |
Property, plant and equipment | 767 | ||
Other current and non-current assets | 35 | ||
Total assets | $ | 827 | |
Liabilities | |||
Accrued expenses | $ | 489 | |
Long-term debt | 4 | ||
Other non-current liabilities | 15 | ||
Total liabilities | 508 | ||
Less: Non-controlling interest (Ivanpah) | 154 | ||
Net assets acquired | $ | 165 |
Significant considerations in determining fair value measurements as defined in ASC 820 of the assets acquired and liabilities assumed are as follows:
• | Property, plant & equipment — The fair values of property, plant and equipment acquired were valued utilizing the cost approach. Under this approach, the fair value approximates the current cost of replacing an asset with another of equivalent economic utility adjusted for functional obsolescence and physical depreciation. The assets acquired have been classified as construction in progress and will commence depreciation upon the commercial operation date of each respective facility. |
• | Power purchase agreements — The fair values of the power purchase agreements acquired were determined utilizing a variation of the income approach and were determined to be zero for each facility. Under this approach, the expected future cash flows resulting from the acquired power purchase agreements, considering operating costs of the solar facility and charges for contributory assets utilized in the business, including working capital and property, plant and equipment were estimated and then discounted to present value at the weighted average cost of capital of an integrated utility peer group adjusted for project-specific financing attributes. Charges for contributory assets are largely driven by costs incurred to construct the facilities under the related Engineering, Procurement & Construction, or EPC, agreements. Since the expected contracted revenues to be recognized over the term of the acquired PPAs are largely offset by the costs to operate the facility and a return of and on the investment in the property, plant and equipment, the acquisition date fair value for each of these PPAs was determined to be zero. To corroborate this outcome, the Company examined available market data and concluded that an appropriate benchmark for fair value of the acquired PPAs would be a similar PPA with a delivery date consistent with the expected commercial operations date of each facility, which would likely have been negotiated during the same period as the PPAs acquired. Accordingly, the acquired PPAs are considered to be at market, which is consistent with the outcome of the income approach. |
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2010 Acquisitions
The Company made several acquisitions in 2010, which were recorded as business combinations under ASC 805. Those acquisitions for which purchase accounting was not finalized as of December 31, 2010, are briefly summarized below. See Note 3, Business Acquisitions and Dispositions and Note 12, Debt and Capital Leases, in the Company's 2010 Form 10-K for additional information related to these acquisitions.
Green Mountain Energy — On November 5, 2010, NRG acquired Green Mountain Energy for $357 million in cash, net of $75 million cash acquired, funded from cash on hand. The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The purchase price was primarily allocated to customer relationships of $158 million, trade names of $130 million, favorable commercial customer contracts of $54 million, net deferred tax liabilities of $78 million, net derivative liabilities of $60 million, and goodwill of $155 million. The factors that resulted in goodwill arising from the acquisition include the revenues associated with expanding the Green Mountain Energy business of providing renewable energy products and services to new customers in new regions and through new providers and the synergies associated with combining a renewable retail business with NRG's renewable generation assets. The accounting for the Green Mountain Energy acquisition was completed as of September 30, 2011, at which point the provisional fair values became final with no material changes.
Cottonwood — On November 15, 2010, NRG acquired the Cottonwood Generating Station, or Cottonwood, a 1,265 MW combined cycle natural gas plant in the Entergy zone of east Texas for $507 million in cash, funded from cash on hand. The acquisition was recorded as a business combination under ASC 805 and the purchase price was allocated to the assets acquired and liabilities assumed, which were recorded at provisional fair value on the acquisition date. The purchase price was primarily allocated to fixed assets. The accounting for the Cottonwood acquisition was completed as of March 31, 2011, at which point the provisional fair values became final with no material changes.
2010 Disposition
Padoma — On January 11, 2010, NRG sold its terrestrial wind development company, Padoma Wind Power LLC, or Padoma to Enel North America, Inc. NRG recognized a gain on the sale of Padoma of $23 million, which was recorded as a component of operating income in the statement of operation during the year ended December 31, 2010.
2009 Disposition
MIBRAG — On June 10, 2009, NRG completed the sale of its 50% ownership interest in MIBRAG, which owned and managed a coal mining operation, three lignite-fueled power generation facilities and other related businesses in Germany. For its share, NRG received €203 million ($284 million), net of transaction costs, and recognized an after-tax gain of $128 million for the year ended December 31, 2009. In addition, NRG entered into a foreign currency forward contract to hedge the impact of exchange rate fluctuations on the sale proceeds. and recorded an exchange loss of $24 million on the contract within Other (loss)/income, net for the year ended December 31, 2009.
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Note 4 — Nuclear Innovation North America LLC Developments, Including Impairment Charge
Nuclear Innovation North America LLC, or NINA, which is majority-owned by NRG, was established in May 2008 to focus on marketing, siting, developing, financing and investing in new advanced design nuclear projects in select markets across North America, including the planned South Texas Project Units 3 and 4 Project, or STP 3 & 4. Toshiba America Nuclear Energy Corporation, or TANE, a wholly-owned subsidiary of Toshiba Corporation, is the minority owner of NINA. NINA is a bankruptcy remote entity under NRG's corporate structure and designated as an Excluded Project Subsidiary under NRG's 2011 Senior Credit Facility and senior unsecured notes, which require that NRG not be obligated to contribute any capital to service NINA's debt or fund the repayment of any NINA debt in the event of a default. Furthermore, NRG is not required to continue the funding of NINA and any capital provided to NINA by any other equity partner could result in the dilution of NRG's equity interest.
On March 11, 2011, Japan was hit by a devastating earthquake and tsunami which, in turn, triggered a nuclear incident at the Fukushima Daiichi Nuclear Power Station owned by The Tokyo Electric Power Company of Japan, Inc., or TEPCO. The nuclear incident in Japan introduced multiple and substantial uncertainties around new nuclear development in the United States and the availability of debt and equity financing to NINA. Consequently, NINA announced, on March 21, 2011, that it was reducing the scope of development at the STP 3 & 4 expansion to allow time for the U.S. Nuclear Regulatory Commission, or NRC, and other nuclear stakeholders to assess the impacts from the events in Japan. NINA suspended indefinitely all detailed engineering work and other pre-construction activities and, as a result, dramatically reduced the project workforce. The decision to reduce the scope of activities was made jointly by NINA, NRG and Toshiba. Further, on April 19, 2011, NRG announced that, while it will cooperate with and support its current partners and any prospective future partners in attempting to develop STP 3 & 4 successfully, NRG was withdrawing from further financial participation in NINA's development of STP 3 & 4. NINA, going forward, will be focused solely on securing a combined operating license from the NRC and on obtaining the loan guarantee from the U.S. DOE, two items that are essential to the success of any future project development. TANE agreed, for the time being, to assume responsibility for NINA's ongoing costs associated with continuation of the licensing process.
Due to the events described above, NRG evaluated its investment in NINA for impairment. As part of this process, NRG evaluated the contractual rights and economic interests held by the various stakeholders in NINA, and concluded that while it continues to hold majority legal ownership, NRG ceased to have a controlling financial interest in NINA at the end of the first quarter of 2011. Consequently, NRG deconsolidated NINA as of March 31, 2011, in accordance with ASC 810. This resulted in the removal of the following amounts from NRG's consolidated balance sheet: $930 million of construction in progress; $154 million of accounts payable and accrued expenses; $297 million of long-term debt; $17 million of non-controlling interest; and $19 million of other assets and liabilities. Furthermore, NRG assessed the impact of the diminished prospects for the STP 3 & 4 project on the fair value of NINA's assets relative to NINA's existing liabilities as well as NINA's potential contingent liabilities. Based on this assessment, the Company concluded it was remote that NRG would recover any portion of the carrying amount of its equity investment in NINA and, consequently, recorded an impairment charge of $481 million as of March 31, 2011 for the full amount of its investment. In concurrence with the substantial reduction in NINA's project workforce, and to support NINA's reduced scope of work, NRG contributed an additional $14 million during the remainder of 2011, bringing the total impairment charge to $495 million for the year ended December 31, 2011. NRG expects to incur additional one-time costs, related to contributions to NINA in future periods, of up to $6 million, bringing these total expected costs to $20 million. These additional contributions are expensed as incurred to "Impairment charge on investment." This impairment charge included net assets contributed from all of NINA's equity investors, both NRG and TANE, which the Company previously consolidated.
As part of a March 1, 2010, settlement of litigation with CPS Energy, or CPS, NRG had agreed to pay $80 million to CPS, subject to the U.S. DOE's approval of a fully executed term sheet for a conditional U.S. DOE loan guarantee for STP 3 & 4. NRG also had agreed to donate an additional $10 million, unconditionally, over four years in annual payments of $2.5 million to the Residential Energy Assistance Partnership, or REAP, in San Antonio. Payments of $5 million were made to REAP through December 31, 2011. As a result of the events stemming from the nuclear incident in Japan, the Company no longer believes it probable that the conditional U.S. DOE loan guarantee will be received or accepted. Therefore, as of March 31, 2011, the Company reversed the $80 million contingent liability to CPS previously recorded within other current liabilities, along with the $80 million of associated amounts capitalized to construction in progress within property, plant and equipment. At December 31, 2011, $5 million in liabilities remains on the condensed consolidated balance sheet for the obligations to REAP.
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Note 5 — Fair Value of Financial Instruments
For cash and cash equivalents, funds deposited by counterparties, restricted cash, cash collateral paid and received in support of energy risk management activities, and restricted cash supporting the funded letter of credit facility, the carrying amount approximates fair value because of the short-term maturity of those instruments. Debt securities, equity securities, trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities are carried at fair market value.
The estimated carrying values and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:
As of December 31, | |||||||||||||||
2011 | 2010 | ||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
(In millions) | |||||||||||||||
Assets | |||||||||||||||
Notes receivable | $ | 156 | $ | 161 | $ | 177 | $ | 190 | |||||||
Liabilities | |||||||||||||||
Long-term debt, including current portion | 9,729 | 9,716 | 9,104 | 9,236 | |||||||||||
Funded letter of credit | — | — | 1,300 | 1,295 |
The fair value of notes receivable, debt securities and certain long-term debt are based on expected future cash flows discounted at market interest rates. The fair value of the remaining long-term debt and the funded letter of credit is based on quoted market prices for these instruments that are publicly traded, or estimated based on the income approach valuation technique for non-publicly traded debt using current interest rates for similar instruments with equivalent credit quality.
Fair Value Accounting under ASC 820
ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
• | Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments. |
• | Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forward contracts. |
• | Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models. |
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.
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Recurring Fair Value Measurements
For cash and cash equivalents, funds deposited by counterparties, restricted cash, cash collateral paid and received in support of energy risk management activities, and restricted cash supporting the funded letter of credit facility, the carrying amount approximates fair value because of the nature and short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:
As of December 31, 2011 | |||||||||||||||
Fair Value | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(In millions) | |||||||||||||||
Investment in available-for-sale securities (classified within other non-current assets): | |||||||||||||||
Debt securities | $ | — | $ | — | $ | 7 | $ | 7 | |||||||
Marketable equity securities | 1 | — | — | 1 | |||||||||||
Trust fund investments: | |||||||||||||||
Cash and cash equivalents | 2 | — | — | 2 | |||||||||||
U.S. government and federal agency obligations | 44 | — | — | 44 | |||||||||||
Federal agency mortgage-backed securities | — | 63 | — | 63 | |||||||||||
Commercial mortgage-backed securities | — | 7 | — | 7 | |||||||||||
Corporate debt securities | — | 54 | — | 54 | |||||||||||
Equity securities | 209 | — | 42 | 251 | |||||||||||
Foreign government fixed income securities | — | 4 | — | 4 | |||||||||||
Derivative assets: | |||||||||||||||
Commodity contracts | 2,661 | 1,930 | 75 | 4,666 | |||||||||||
Total assets | $ | 2,917 | $ | 2,058 | $ | 124 | $ | 5,099 | |||||||
Derivative liabilities: | |||||||||||||||
Commodity contracts | $ | 2,757 | $ | 1,283 | $ | 67 | $ | 4,107 | |||||||
Interest rate contracts | — | 108 | — | 108 | |||||||||||
Total liabilities | $ | 2,757 | $ | 1,391 | $ | 67 | $ | 4,215 |
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As of December 31, 2010 | |||||||||||||||
Fair Value | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(In millions) | |||||||||||||||
Investment in available-for-sale securities (classified within other non-current assets): | |||||||||||||||
Debt securities | $ | — | $ | — | $ | 8 | $ | 8 | |||||||
Marketable equity securities | 3 | — | — | 3 | |||||||||||
Trust fund investments: | |||||||||||||||
Cash and cash equivalents | 9 | — | — | 9 | |||||||||||
U.S. government and federal agency obligations | 27 | — | — | 27 | |||||||||||
Federal agency mortgage-backed securities | — | 57 | — | 57 | |||||||||||
Commercial mortgage-backed securities | — | 11 | — | 11 | |||||||||||
Corporate debt securities | — | 56 | — | 56 | |||||||||||
Equity securities | 213 | — | 39 | 252 | |||||||||||
Foreign government fixed income securities | — | 2 | — | 2 | |||||||||||
Derivative assets: | |||||||||||||||
Commodity contracts | 652 | 2,046 | 24 | 2,722 | |||||||||||
Total assets | $ | 904 | $ | 2,172 | $ | 71 | $ | 3,147 | |||||||
Derivative liabilities: | |||||||||||||||
Commodity contracts | $ | 660 | $ | 1,251 | $ | 51 | $ | 1,962 | |||||||
Interest rate contracts | — | 88 | — | 88 | |||||||||||
Total liabilities | $ | 660 | $ | 1,339 | $ | 51 | $ | 2,050 |
There have been no transfers during the year ended December 31, 2011, between Levels 1 and 2. The following tables reconcile, for the years ended December 31, 2011, and 2010, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:
For the Year Ended December 31, 2011 | |||||||||||||||
Fair Value Measurement Using Significant Unobservable Inputs (Level 3) | |||||||||||||||
Debt Securities | Trust Fund Investments | Derivatives (a) | Total | ||||||||||||
(In millions) | |||||||||||||||
Beginning balance as of January 1, 2011 | $ | 8 | $ | 39 | $ | (27 | ) | $ | 20 | ||||||
Total gains and losses (realized/unrealized): | |||||||||||||||
Included in OCI | (1 | ) | — | — | (1 | ) | |||||||||
Included in earnings | — | — | 28 | 28 | |||||||||||
Included in nuclear decommissioning obligations | — | (6 | ) | — | (6 | ) | |||||||||
Purchases | — | 9 | 4 | 13 | |||||||||||
Transfers into Level 3 (b) | — | — | (3 | ) | (3 | ) | |||||||||
Transfers out of Level 3 (b) | — | — | 6 | 6 | |||||||||||
Ending balance as of December 31, 2011 | $ | 7 | $ | 42 | $ | 8 | $ | 57 | |||||||
The amount of the total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held as of December 31, 2011 | $ | — | $ | — | $ | 3 | $ | 3 |
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For the Year Ended December 31, 2010 | |||||||||||||||
Fair Value Measurement Using Significant Unobservable Inputs (Level 3) | |||||||||||||||
Debt Securities | Trust Fund Investments | Derivatives (a) | Total | ||||||||||||
(In millions) | |||||||||||||||
Beginning balance as of January 1, 2010 | $ | 9 | $ | 37 | $ | (13 | ) | $ | 33 | ||||||
Total gains and losses (realized/unrealized): | |||||||||||||||
Included in OCI | 1 | — | — | 1 | |||||||||||
Included in earnings | 3 | — | 28 | 31 | |||||||||||
Included in nuclear decommissioning obligations | — | 2 | — | 2 | |||||||||||
Purchases | — | — | (8 | ) | (8 | ) | |||||||||
Sales | (5 | ) | — | — | (5 | ) | |||||||||
Transfers into Level 3 (b) | — | — | (26 | ) | (26 | ) | |||||||||
Transfer out of Level 3 (b) | — | — | (8 | ) | (8 | ) | |||||||||
Ending balance as of December 31, 2010 | $ | 8 | $ | 39 | $ | (27 | ) | $ | 20 | ||||||
The amount of the total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held as of December 31, 2010 | $ | — | $ | — | $ | 5 | $ | 5 |
(a) | Consists of derivatives assets and liabilities, net. |
(b) | Transfers in/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers in/out are with Level 2. |
Realized and unrealized gains and losses included in earnings that are related to the energy derivatives are recorded in operating revenues and cost of operations.
Non-derivative fair value measurements
NRG's investments in debt securities are classified as Level 3 and consist of non-traded debt instruments that are valued based on third-party market value assessments.
The trust fund investments are held primarily to satisfy NRG's nuclear decommissioning obligations. These trust fund investments hold debt and equity securities directly and equity securities indirectly through commingled funds. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. In addition, U.S. government and federal agency obligations are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of corporate debt securities, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in Level 2. Certain equity securities, classified as commingled funds, are analogous to mutual funds, are maintained by investment companies, and hold certain investments in accordance with a stated set of fund objectives. The fair value of the equity securities classified as commingled funds are based on net asset values per fund share (the unit of account), derived from the quoted prices in active markets of the underlying equity securities. However, because the shares in the commingled funds are not publicly quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled funds are categorized in Level 3. See also Note 7, Nuclear Decommissioning Trust Fund.
Derivative fair value measurements
A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. The majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. The remainder of the assets and liabilities represents contracts for which external sources or observable
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market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Contracts valued with prices provided by models and other valuation techniques make up 2% of the total fair value of all derivative contracts. The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. To the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of December 31, 2011, the credit reserve resulted in a $4 million decrease in fair value which is composed of a $2 million loss in operating revenue and cost of operations and a $2 million decrease in OCI.
The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2011, and may change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be material.
Under the guidance of ASC 815, entities may choose to offset cash collateral paid or received against the fair value of derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen not to offset positions as defined in ASC 815. As of December 31, 2011, the Company recorded $311 million of cash collateral paid and $258 million of cash collateral received on its balance sheet.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, the following item is a discussion of the concentration of credit risk for the Company's financial instruments. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits (iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.
As of December 31, 2011, counterparty credit exposure to a significant portion of the Company's counterparties was $1.2 billion and NRG held collateral (cash and letters of credit) against those positions of $261 million, resulting in a net exposure of $919 million. Counterparty credit exposure is discounted at the risk free rate. The following table highlights the counterparty credit quality and the net counterparty credit exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure as of December 31, 2011 is shown net of collateral held, and includes amounts net of receivables or payables.
Category | Net Exposure (a) (% of Total) | |
Financial institutions | 57 | % |
Utilities, energy merchants, marketers and other | 39 | |
Coal and emissions | 1 | |
ISOs | 3 | |
Total | 100 | % |
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Category | Net Exposure (a) (% of Total) | |
Investment grade | 70 | % |
Non-rated (b) | 27 | |
Non-Investment grade | 3 | |
Total | 100 | % |
(a) | Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices. |
(b) | For non-rated counterparties, the majority of the exposure is related to ISO and municipal public power entities, which are considered investment grade equivalent ratings based on NRG's internal credit ratings. |
NRG has counterparty credit risk exposure to certain counterparties representing more than 10% of total net exposure discussed above and the aggregate of such counterparties was $265 million. Approximately 89% of NRG's positions relating to this credit risk roll-off by the end of 2013. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.
Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations, solar PPAs, and a coal supply agreement. As external sources or observable market quotes are not available to estimate such exposure, the Company valued these contracts based on various techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of December 31, 2011, credit risk exposure to these counterparties is approximately $866 million for the next five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial operations. Many of these power contracts are with utilities or public power entities that have strong credit quality and specific public utility commission or other regulatory support. In the case of the coal supply agreement, NRG holds a lien against the underlying asset. These factors significantly reduce the risk of loss.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through the Company's retail electricity providers, which serve C&I customers and the Mass market. Retail credit risk results when a customer fails to pay for services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.
As of December 31, 2011, the Company's retail customer credit exposure to C&I customers was diversified across many customers and various industries, with a significant portion of the exposure with government entities.
NRG is also exposed to retail customer credit risk relating to its Mass customers, which may result in a write-off of bad debt. During 2011, the Company continued to experience improved customer payment behavior, but current economic conditions may affect the Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.
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Note 6 — Accounting for Derivative Instruments and Hedging Activities
ASC 815 requires NRG to recognize all derivative instruments on the balance sheet as either assets or liabilities and to measure them at fair value each reporting period unless they qualify for a NPNS exception. NRG may elect to designate certain derivatives as cash flow hedges, if certain conditions are met, and defer the effective portion of the change in fair value of the derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is immediately recognized in earnings.
For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivative and the hedged transaction are recorded in current earnings.
For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Certain derivative instruments may qualify for the NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG's energy related commodity contracts, interest rate swaps, and foreign exchange contracts.
As the Company engages principally in the trading and marketing of its generation assets and retail business, some of NRG's commercial activities qualify for hedge accounting. In order for the generation assets to qualify, the physical generation and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with the Company's baseload plants. For this reason, many trades in support of NRG's baseload units normally qualify for NPNS or cash flow hedge accounting treatment, and trades in support of NRG's peaking unit's asset optimization will generally not qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on a mark-to-market basis in the statement of operations. Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of the retail supply and fuels supply contracts are recorded under mark-to-market accounting. All of NRG's hedging and trading activities are subject to limits within the Company's Risk Management Policy.
Energy-Related Commodities
To manage the commodity price risk associated with the Company's competitive supply activities and the price risk associated with wholesale power sales from the Company's electric generation facilities and retail power sales from Retail Businesses, NRG enters into a variety of derivative and non-derivative hedging instruments, utilizing the following:
• | Forward contracts, which commit NRG to purchase or sell energy commodities or purchase fuels in the future. |
• | Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument. |
• | Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity. |
• | Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity. |
• | Extendable swaps, which include a combination of swaps and options executed simultaneously for different periods. This combination of instruments allows NRG to sell out-year volatility through call options in exchange for natural gas swaps with fixed prices in excess of the market price for natural gas at that time. The above-market swap combined with its later-year call option are priced in aggregate at market at the trade's inception. |
• | Weather and hurricane derivative products used to mitigate a portion of Reliant Energy's lost revenue due to weather. |
The objectives for entering into derivative contracts designated as hedges include:
• | Fixing the price for a portion of anticipated future electricity sales that provides an acceptable return on the Company's electric generation operations. |
• | Fixing the price of a portion of anticipated fuel purchases for the operation of NRG's power plants. |
• | Fixing the price of a portion of anticipated power purchases for the Company's retail sales. |
As of December 31, 2011, NRG had cash flow hedge energy-related derivative financial instruments extending through December 2013.
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NRG's trading and hedging activities are subject to limits within the Company's Risk Management Policy. These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.
As of December 31, 2011, NRG had energy-related derivative financial instruments, and other energy-related contracts that did meet the definition of derivative instruments extending through December 2039. As of December 31, 2011, NRG's derivative assets and liabilities consisted primarily of the following:
• | Forward and financial contracts for the purchase/sale of electricity and related products economically hedging NRG's generation assets' forecasted output or NRG's retail load obligations through 2017. |
• | Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation assets through 2017. |
Also, as of December 31, 2011, NRG had other energy-related contracts that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment as follows:
• | Power sales and capacity contracts extending through 2025. |
Also, as of December 31, 2011, NRG had other energy-related contracts that did not meet the definition of derivatives as follows:
• | Load-following forward electric sale contracts extending through 2026; |
• | Power Tolling contracts through 2039; |
• | Lignite purchase contract through 2018; |
• | Power transmission contracts through 2015; |
• | Natural gas transportation contracts and storage agreements through 2018; and |
• | Coal transportation contracts through 2016. |
Interest Rate Swaps
NRG is exposed to changes in interest rates through the Company's issuance of variable and fixed rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of December 31, 2011, NRG had interest rate derivative instruments on recourse debt extending through 2013 and on non-recourse debt extending through 2029, the majority of which are designated as cash flow hedges.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2011, and December 31, 2010. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.
Total Volume | ||||||||
Commodity | Units | December 31, 2011 | December 31, 2010 | |||||
(In millions) | ||||||||
Emissions | Short Ton | (2 | ) | — | ||||
Coal | Short Ton | 37 | 34 | |||||
Natural Gas | MMBtu | 13 | (175 | ) | ||||
Oil | Barrel | 1 | 1 | |||||
Power | MWh | 4 | 5 | |||||
Capacity | MW/Day | — | (1 | ) | ||||
Interest | Dollars | $ | 2,121 | $ | 2,782 |
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Fair Value of Derivative Instruments
The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The Company has chosen not to offset positions as permitted in ASC 815. As of December 31, 2011, the Company recorded $311 million of cash collateral paid and $258 million of cash collateral received on its balance sheet.
The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:
Fair Value | |||||||||||||||
Derivative Assets | Derivative Liabilities | ||||||||||||||
(In millions) | December 31, 2011 | December 31, 2010 | December 31, 2011 | December 31, 2010 | |||||||||||
Derivatives Designated as Cash Flow or Fair Value Hedges: | |||||||||||||||
Interest rate contracts current | $ | — | $ | — | $ | 39 | $ | 17 | |||||||
Interest rate contracts long-term | — | — | 68 | 71 | |||||||||||
Commodity contracts current | 318 | 392 | — | 2 | |||||||||||
Commodity contracts long-term | — | 217 | 1 | — | |||||||||||
Total Derivatives Designated as Cash Flow or Fair Value Hedges | 318 | 609 | 108 | 90 | |||||||||||
Derivatives Not Designated as Cash Flow or Fair Value Hedges: | |||||||||||||||
Interest rate contracts long-term | — | — | 1 | — | |||||||||||
Commodity contracts current | 3,898 | 1,572 | 3,712 | 1,666 | |||||||||||
Commodity contracts long-term | 450 | 541 | 394 | 294 | |||||||||||
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges | 4,348 | 2,113 | 4,107 | 1,960 | |||||||||||
Total Derivatives | $ | 4,666 | $ | 2,722 | $ | 4,215 | $ | 2,050 |
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Accumulated Other Comprehensive Income
The following tables summarize the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:
Year Ended December 31, 2011 | |||||||||||
Energy Commodities | Interest Rate | Total | |||||||||
(In millions) | |||||||||||
Accumulated OCI balance at December 31, 2010 | $ | 488 | $ | (47 | ) | $ | 441 | ||||
Reclassified from accumulated OCI to income: | |||||||||||
- Due to realization of previously deferred amounts | (374 | ) | 12 | (362 | ) | ||||||
Mark-to-market of cash flow hedge accounting contracts | 74 | (21 | ) | 53 | |||||||
Accumulated OCI balance at December 31, 2011, net of $87 tax | $ | 188 | $ | (56 | ) | $ | 132 | ||||
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $71 tax | $ | 145 | $ | (23 | ) | $ | 122 | ||||
Gains recognized in income from the ineffective portion of cash flow hedges | $ | 28 | $ | 3 | $ | 31 |
Year Ended December 31, 2010 | |||||||||||
Energy Commodities | Interest Rate | Total | |||||||||
(In millions) | |||||||||||
Accumulated OCI balance at December 31, 2009 | $ | 461 | $ | (55 | ) | $ | 406 | ||||
Reclassified from accumulated OCI to income: | |||||||||||
- Due to realization of previously deferred amounts | (474 | ) | 1 | (473 | ) | ||||||
Mark-to-market of cash flow hedge accounting contracts | 501 | 7 | 508 | ||||||||
Accumulated OCI balance at December 31, 2010, net of $268 tax | $ | 488 | $ | (47 | ) | $ | 441 | ||||
Gains recognized in income from the ineffective portion of cash flow hedges | $ | — | $ | 1 | $ | 1 |
Year Ended December 31, 2009 | |||||||||||
Energy Commodities | Interest Rate | Total | |||||||||
(In millions) | |||||||||||
Accumulated OCI balance at December 31, 2008 | $ | 406 | $ | (91 | ) | $ | 315 | ||||
Reclassified from accumulated OCI to income: | |||||||||||
- Due to realization of previously deferred amounts | (335 | ) | 1 | (334 | ) | ||||||
- Due to discontinuance of cash flow hedge accounting | (137 | ) | — | (137 | ) | ||||||
Mark-to-market of cash flow hedge accounting contracts | 527 | 35 | 562 | ||||||||
Accumulated OCI balance at December 31, 2009, net of $247 tax | $ | 461 | $ | (55 | ) | $ | 406 | ||||
Gains/(losses) recognized in income from the ineffective portion of cash flow hedges | $ | 45 | $ | (4 | ) | $ | 41 |
Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts.
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Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of July 31, 2011, the Company's regression analysis for natural gas prices to ERCOT power prices, while positively correlated, did not meet the required threshold for cash flow hedge accounting for calendar years 2011. As a result, the Company de-designated its 2011 ERCOT cash flow hedges as of July 31, 2011, and prospectively marked these derivatives to market through the income statement.
The following table summarizes the amount of unrealized gain/(loss) resulting from fair value hedges reflected in interest income/(expense) for interest rate contracts:
Year Ended December 31, | |||||||||||
(In millions) | 2011 | 2010 | 2009 | ||||||||
Derivative | $ | — | $ | (8 | ) | $ | (6 | ) | |||
Senior Notes (hedged item) | — | 11 | 6 |
Impact of Derivative Instruments on the Statement of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges and ineffectiveness of hedge derivatives are reflected in current period earnings.
The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges, and trading activity on NRG's statement of operations. These amounts are included within operating revenues and cost of operations.
Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions) | |||||||||||
Unrealized mark-to-market results | |||||||||||
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 54 | $ | (171 | ) | $ | (68 | ) | |||
Reversal of loss positions acquired as part of the Reliant Energy acquisition as of May 1, 2009 | 72 | 223 | 656 | ||||||||
Reversal of previously recognized unrealized losses due to the termination of positions related to the CSRA unwind | — | — | 80 | ||||||||
Reversal of loss positions acquired as part of the Green Mountain Energy acquisition as of November 5, 2010 | 35 | 13 | — | ||||||||
Net unrealized (losses)/gains on open positions related to economic hedges | (33 | ) | (153 | ) | 22 | ||||||
Gains on ineffectiveness associated with open positions treated as cash flow hedges | 28 | — | 45 | ||||||||
Total unrealized mark-to-market gains/(losses) for economic hedging activities | 156 | (88 | ) | 735 | |||||||
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity | 21 | 68 | (157 | ) | |||||||
Net unrealized gains/(losses) on open positions related to trading activity | 42 | (5 | ) | (26 | ) | ||||||
Total unrealized mark-to-market gains/(losses) for trading activity | 63 | 63 | (183 | ) | |||||||
Total unrealized gains/(losses) | $ | 219 | $ | (25 | ) | $ | 552 |
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Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions) | |||||||||||
Revenue from operations — energy commodities | $ | 388 | $ | (136 | ) | $ | (290 | ) | |||
Cost of operations | (169 | ) | 111 | 842 | |||||||
Total impact to statement of operations | $ | 219 | $ | (25 | ) | $ | 552 |
Reliant Energy's loss positions were acquired as of May 1, 2009, and valued using forward prices on that date. Green Mountain Energy's loss positions were acquired as of November 5, 2010, and valued using forward prices on that date. The roll-off amounts were offset by realized losses at the settled prices and are reflected in the cost of operations during the same period.
For the year ended December 31, 2011, the $33 million loss from economic hedge positions was the result of a decrease in value of forward purchases and sales of natural gas, electricity and fuel due to a decrease in forward power and gas prices.
For the year ended December 31, 2010, the $153 million loss from economic hedge positions was the result of forward purchases and sales of natural gas, electricity and fuel due to decrease in forward power and gas prices.
Credit Risk Related Contingent Features
Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts that have adequate assurance clauses that are in net liability positions as of December 31, 2011, was $69 million. The collateral required for contracts with credit rating contingent features that are in a net liability position as of December 31, 2011, was $35 million. The Company is also a party to certain marginable agreements where NRG has a net liability position, but the counterparty has not called for the collateral due, which is approximately $15 million as of December 31, 2011.
See Note 5, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.
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Note 7 — Nuclear Decommissioning Trust Fund
NRG's nuclear decommissioning trust fund assets, which are for the decommissioning of STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. Although NRG is responsible for managing the decommissioning of its 44% interest in STP, the predecessor utilities that owned STP are authorized by the Public Utility Commission of Texas, or PUCT, to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. NRC requirements determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the STP facilities, the utilities will be required to collect through rates charged to rate payers all additional amounts, with no obligation from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the respective ratepayers of the utilities.
NRG accounts for the nuclear decommissioning trust fund in accordance with ASC 980, Regulated Operations, or ASC 980 because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear Decommissioning Trust Liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.
The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.
As of December 31, 2011 | As of December 31, 2010 | ||||||||||||||||||||||||||||
(In millions, except otherwise noted) | Fair Value | Unrealized Gains | Unrealized Losses | Weighted- average maturities (in years) | Fair Value | Unrealized Gains | Unrealized Losses | Weighted- average maturities (in years) | |||||||||||||||||||||
Cash and cash equivalents | $ | 2 | $ | — | $ | — | — | $ | 9 | $ | — | $ | — | — | |||||||||||||||
U.S. government and federal agency obligations | 43 | 3 | — | 10 | 25 | 1 | — | 9 | |||||||||||||||||||||
Federal agency mortgage-backed securities | 63 | 3 | — | 23 | 57 | 2 | — | 24 | |||||||||||||||||||||
Commercial mortgage-backed securities | 7 | — | — | 28 | 11 | — | — | 29 | |||||||||||||||||||||
Corporate debt securities | 54 | 3 | 1 | 10 | 56 | 3 | 1 | 10 | |||||||||||||||||||||
Equity securities | 251 | 113 | 1 | — | 252 | 117 | 1 | — | |||||||||||||||||||||
Foreign government fixed income securities | 4 | — | — | 8 | 2 | — | — | 8 | |||||||||||||||||||||
Total | $ | 424 | $ | 122 | $ | 2 | $ | 412 | $ | 123 | $ | 2 |
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.
Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions) | |||||||||||
Realized gains | $ | 4 | $ | 8 | $ | 2 | |||||
Realized losses | (3 | ) | (5 | ) | (1 | ) | |||||
Proceeds from sale of securities | 385 | 307 | 279 |
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Note 8 — Inventory
Inventory consisted of:
As of December 31, | |||||||
2011 | 2010 | ||||||
(In millions) | |||||||
Fuel oil | $ | 59 | $ | 72 | |||
Coal/Lignite | 82 | 215 | |||||
Natural gas | 10 | 8 | |||||
Spare parts | 157 | 157 | |||||
Other | — | 1 | |||||
Total Inventory | $ | 308 | $ | 453 |
Note 9 — Capital Leases and Notes Receivable
Notes receivable primarily consisted of fixed and variable rate notes secured by equity interests in partnerships and joint ventures. NRG's notes receivable and capital leases were as follows:
As of December 31, | |||||||
2011 | 2010 | ||||||
(In millions) | |||||||
Capital Leases Receivable — non-affiliates | |||||||
Vattenfall Europe Generation AG & Co. KG., due August 31, 2021, 11.00% (a) | $ | 199 | $ | 233 | |||
Other | 1 | 3 | |||||
Capital Leases — non-affiliates | 200 | 236 | |||||
Notes Receivable — non-affiliates (b) | 36 | — | |||||
Notes Receivable — affiliates | |||||||
Kraftwerke Schkopau GBR, indefinite maturity date, 6.91%-7.00% (c) | 112 | 115 | |||||
GCE Holding LLC which wholly-owns GenConn Energy LLC, indefinite maturity date, LIBOR +3% (d) | — | 62 | |||||
Avenal Solar Holdings LLC, indefinite maturity date, 4.5% (e) | 8 | — | |||||
Notes receivable — affiliates | 120 | 177 | |||||
Subtotal — Capital leases and notes receivable | 356 | 413 | |||||
Less current maturities: | |||||||
Capital leases (f) | 14 | 29 | |||||
Total Capital leases and notes receivable — noncurrent | $ | 342 | $ | 384 |
(a) | Saale Energie GmbH, or SEG, has sold 100% of its share of capacity from the Schkopau power plant to Vattenfall Europe Generation AG & Co. KG under a 25-year contract, which is more than 83% of the useful life of the plant. This direct financing lease receivable amount was calculated based on the present value of the income to be received over the life of the contract. |
(b) | Agua Caliente and CVSR have entered into agreements with their respective transmission owners to provide financing for required network upgrades. The notes will be repaid within a five year period following the date each facility reaches commercial operations. |
(c) | SEG entered into a note receivable with Kraftwerke Schkopau GBR, a partnership between SEG and E.On Kraftwerke GmbH. The note was used to fund SEG's initial capital contribution to the partnership and to cover project liquidity shortfalls during construction of the Schkopau power plant. The note is subject to repayment upon the disposition of the Schkopau plant. |
(d) | NRG entered into a long-term $122 million note receivable facility with GCE Holding LLC to fund project liquidity needs in 2009. Per the terms of the facility, $63 million of the outstanding balance, including accrued interest was converted into equity in GenConn Energy LLC when the Middletown project reached commercial operations in 2011. See Note 12, Debt and Capital Leases for further discussion. |
(e) | NRG entered into a long-term $35 million note receivable facility with Avenal Solar Holdings LLC, to fund project liquidity needs in 2011. |
(f) | The current portion of capital leases is recorded in Prepayments and other current assets on the Consolidated Balance Sheet. |
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Note 10 — Property, Plant, and Equipment
NRG's major classes of property, plant, and equipment were as follows:
As of December 31, | Depreciable | ||||||||
2011 | 2010 | Lives | |||||||
(In millions) | |||||||||
Facilities and equipment | $ | 14,483 | $ | 13,820 | 1-40 Years | ||||
Land and improvements | 602 | 580 | |||||||
Nuclear fuel | 365 | 314 | 5 Years | ||||||
Office furnishings and equipment | 254 | 199 | 2-10 Years | ||||||
Construction in progress | 2,487 | 1,400 | |||||||
Total property, plant, and equipment | 18,191 | 16,313 | |||||||
Accumulated depreciation | (4,570 | ) | (3,796 | ) | |||||
Net property, plant, and equipment | $ | 13,621 | $ | 12,517 |
Note 11 — Goodwill and Other Intangibles
Goodwill — NRG's goodwill balance was $1.9 billion as of both December 31, 2011, and 2010. The Company recorded approximately $1.7 billion of goodwill in connection with the acquisition of Texas Genco in 2006. The Company recorded $144 million of goodwill in connection with the 2010 acquisition of Green Mountain Energy and $29 million in connection with the 2011 acquisition of Energy Plus. The Green Mountain Energy and Energy Plus acquisitions are discussed further in Note 3, Business Acquisitions and Dispositions. As of December 31, 2011, there was no impairment to goodwill. As of December 31, 2011, and 2010, NRG had approximately $594 million and $660 million, respectively, of goodwill that is deductible for U.S. income tax purposes in future periods.
Intangible Assets — The Company's intangible assets as of December 31, 2011, primarily reflect intangible assets established with the acquisitions of various companies in 2011, 2010, 2009, and 2006, and are comprised of the following:
• | Emission Allowances — These intangibles primarily consist of SO2 and NOx emission allowances established with the 2006 Texas Genco acquisition and also include RGGI emission credits which NRG began purchasing in 2009. These emission allowances are held-for-use and are amortized to cost of operations, with NOx allowances amortized on a straight-line basis and SO2 allowances and Regional Greenhouse Gas Initiative, or RGGI, credits amortized based on units of production. During the year ended December 31, 2011, the Company recorded an impairment charge of $160 million on the Company's Acid Rain Program SO2 emission allowances in order to comply with the Acid Rain Program as discussed in Note 24, Environmental Matters. |
• | Development rights — Arising primarily from the acquisition of solar businesses in 2010 and 2011, these intangibles are amortizable to depreciation and amortization expense on a straight-line basis over the estimated life of the related project portfolio. |
• | Energy supply contracts — Established with the acquisitions of Reliant Energy and Green Mountain Energy, these represent the fair value at the acquisition date of in-market contracts for the purchase of energy to serve retail electric customers. The contracts are amortized to cost of operations based on the expected delivery under the respective contracts. |
• | In-market fuel (gas and nuclear) contracts — These intangibles were established with the Texas Genco acquisition in 2006 and are amortized to cost of operations over expected volumes over the life of each contract. |
• | Customer contracts — Established with the acquisitions of Reliant Energy, Green Mountain Energy, and Northwind Phoenix, these intangibles represent the fair value at the acquisition date of contracts that primarily provide electricity to Reliant Energy's and Green Mountain Energy's C&I customers. These contracts are amortized to revenues based on expected volumes to be delivered for the portfolio. |
• | Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer base, primarily for Energy Plus, Reliant Energy and Green Mountain Energy. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year. |
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• | Marketing partnerships — Established with the acquisition of Energy Plus, as further discussed in Note 3, Business Acquisitions and Dispositions, these intangibles represent the fair value at the acquisition date of existing agreements with loyalty and affinity partners. The marketing partnerships are amortized to depreciation and amortization expense based on the expected discounted future net cash flows by year. |
• | Trade names — Established with the Energy Plus, Reliant Energy and Green Mountain Energy acquisitions, these intangibles are amortized to depreciation and amortization expense, on a straight-line basis. |
• | Other — Consists of renewable energy credits, wind intangible assets, costs to extend the operating license for STP Units 1 and 2, the intangible asset related to a purchased ground lease and the value of acquired power purchase agreements. |
The following tables summarize the components of NRG's intangible assets subject to amortization:
Contracts | |||||||||||||||||||||||||||||||||||||||
Year Ended December 31, 2011 | Emission Allowances | Development Rights | Energy Supply | Fuel | Customer | Customer Relationships | Marketing Partnerships | Trade Names | Other | Total | |||||||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||||||||||||||
January 1, 2011 | $ | 935 | $ | 18 | $ | 54 | $ | 72 | $ | 859 | $ | 571 | $ | — | $ | 308 | $ | 23 | $ | 2,840 | |||||||||||||||||||
Purchases | 8 | 6 | — | — | — | — | — | — | 26 | 40 | |||||||||||||||||||||||||||||
Acquisition of businesses | — | — | — | — | — | 63 | 88 | 10 | 13 | 174 | |||||||||||||||||||||||||||||
Usage | — | — | — | — | — | — | — | — | (19 | ) | (19 | ) | |||||||||||||||||||||||||||
Impairment charge on emission allowances | (160 | ) | — | — | — | — | — | — | — | — | (160 | ) | |||||||||||||||||||||||||||
Other | — | — | — | — | — | — | — | — | (4 | ) | (4 | ) | |||||||||||||||||||||||||||
Adjusted gross amount | 783 | 24 | 54 | 72 | 859 | 634 | 88 | 318 | 39 | 2,871 | |||||||||||||||||||||||||||||
Less accumulated amortization | (335 | ) | — | (25 | ) | (57 | ) | (675 | ) | (317 | ) | — | (42 | ) | (1 | ) | (1,452 | ) | |||||||||||||||||||||
Net carrying amount | $ | 448 | $ | 24 | $ | 29 | $ | 15 | $ | 184 | $ | 317 | $ | 88 | $ | 276 | $ | 38 | $ | 1,419 |
Contracts | |||||||||||||||||||||||||||||||||||
Year Ended December 31, 2010 | Emission Allowances | Development Rights | Energy Supply | Fuel | Customer | Customer Relationships | Trade Names | Other | Total | ||||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||||||||||
January 1, 2010 | $ | 919 | $ | — | $ | 54 | $ | 71 | $ | 790 | $ | 399 | $ | 178 | $ | 14 | $ | 2,425 | |||||||||||||||||
Purchases | 19 | — | — | — | — | — | — | 20 | 39 | ||||||||||||||||||||||||||
Acquisition of businesses | — | 18 | — | — | 69 | 172 | 130 | 4 | 393 | ||||||||||||||||||||||||||
Usage | — | — | — | — | — | — | — | (15 | ) | (15 | ) | ||||||||||||||||||||||||
Other | (3 | ) | — | — | 1 | — | — | — | — | (2 | ) | ||||||||||||||||||||||||
Adjusted gross amount | 935 | 18 | 54 | 72 | 859 | 571 | 308 | 23 | 2,840 | ||||||||||||||||||||||||||
Less accumulated amortization | (269 | ) | — | (21 | ) | (55 | ) | (490 | ) | (208 | ) | (20 | ) | (1 | ) | (1,064 | ) | ||||||||||||||||||
Net carrying amount | $ | 666 | $ | 18 | $ | 33 | $ | 17 | $ | 369 | $ | 363 | $ | 288 | $ | 22 | $ | 1,776 |
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The following table presents NRG's amortization of intangible assets for each of the past three years:
Years Ended December 31, | |||||||||||
Amortization | 2011 | 2010 | 2009 | ||||||||
(In millions) | |||||||||||
Emission allowances | $ | 66 | $ | 70 | $ | 63 | |||||
Energy supply contracts | 4 | 3 | 18 | ||||||||
Fuel contracts | 2 | 7 | 15 | ||||||||
Customer contracts | 185 | 232 | 258 | ||||||||
Customer relationships | 109 | 91 | 117 | ||||||||
Trade names | 22 | 12 | 8 | ||||||||
Other | — | 1 | — | ||||||||
Total amortization | $ | 388 | $ | 416 | $ | 479 |
The following table presents estimated amortization of NRG's intangible assets for each of the next five years:
Contracts | |||||||||||||||||||||||||||||||||||
Year Ended December 31, | Emission Allowances | Development Rights | Energy Supply | Fuel | Customer | Customer Relationships | Marketing Partnerships | Trade Names | Total | ||||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||||||||||
2012 | $ | 50 | $ | 1 | $ | 5 | $ | 2 | $ | 119 | $ | 98 | $ | 3 | $ | 23 | $ | 301 | |||||||||||||||||
2013 | 54 | 1 | 6 | 2 | 53 | 68 | 9 | 23 | 216 | ||||||||||||||||||||||||||
2014 | 33 | 1 | 6 | 2 | 1 | 48 | 15 | 23 | 129 | ||||||||||||||||||||||||||
2015 | 41 | 1 | 6 | 2 | 1 | 36 | 14 | 23 | 124 | ||||||||||||||||||||||||||
2016 | 46 | 1 | 6 | 2 | 1 | 26 | 9 | 22 | 113 |
The following table presents the weighted average remaining amortization period related to NRG's intangible assets purchased in 2011 business acquisitions:
As of December 31, 2011 | Marketing Partnerships | Trade Names | Customer Relationships | Other | Total | ||||||||||
(In years) | |||||||||||||||
Weighted average remaining amortization period | 18 | 5 | 5 | 18 | 11 |
Intangible assets held for sale — From time to time, management may authorize the transfer from the Company's emission bank of emission allowances held-for-use to intangible assets held-for-sale. Emission allowances held-for-sale are included in other non current assets on the Company's consolidated balance sheet and are not amortized, but rather expensed as sold. As of December 31, 2011, the value of emission allowances held-for-sale is $19 million and is managed within the Corporate segment. Once transferred to held-for-sale, these emission allowances are prohibited from moving back to held-for-use.
Out-of-market contracts — Due to business acquisitions and upon the adoption of Fresh Start accounting, NRG acquired certain out-of-market contracts, which are classified as non-current liabilities on NRG's consolidated balance sheet. The power and customer contracts are amortized to revenues, while the energy supply contracts are amortized to cost of operations.
The following table summarizes the estimated amortization related to NRG's out-of-market contracts:
Contracts | |||||||||||||||
Year Ended December 31, | Customer | Energy Supply | Power | Total | |||||||||||
(In millions) | |||||||||||||||
2012 | $ | 2 | $ | 6 | $ | 21 | $ | 29 | |||||||
2013 | 1 | 2 | 19 | 22 | |||||||||||
2014 | — | — | 17 | 17 | |||||||||||
2015 | — | — | 17 | 17 | |||||||||||
2016 | — | — | 17 | 17 |
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Note 12 — Debt and Capital Leases
Long-term debt and capital leases consisted of the following:
As of December 31, | |||||||||||
2011 | 2010 | Interest Rate | |||||||||
(In millions except rates) | |||||||||||
NRG Recourse Debt: | |||||||||||
Senior notes, due 2021 | $ | 1,200 | $ | — | 7.875 | ||||||
Senior notes, due 2020 | 1,100 | 1,100 | 8.250 | ||||||||
Senior notes, due 2019 | 800 | — | 7.625 | ||||||||
Senior notes, due 2019 (a) | 691 | 690 | 8.500 | ||||||||
Senior notes, due 2018 | 1,200 | — | 7.625 | ||||||||
Senior notes, due 2017 | 1,090 | 1,100 | 7.375 | ||||||||
Senior notes, due 2016 | — | 2,400 | 7.375 | ||||||||
Senior notes, due 2014 (b) | — | 1,205 | 7.250 | ||||||||
Term loan facility, due 2018 (c) | 1,588 | — | L+3.00 | (f) | |||||||
Term loan facility, due 2013-2015 | — | 1,759 | L+3.25/L+1.75 | (f) | |||||||
Indian River Power LLC, tax exempt bonds, due 2040 | 57 | 1 | 6.000 | ||||||||
Indian River Power LLC, tax exempt bonds, due 2045 | 148 | 66 | 5.375 | ||||||||
Dunkirk Power LLC, tax exempt bonds, due 2042 | 59 | 59 | 5.875 | ||||||||
Subtotal NRG Recourse Debt | 7,933 | 8,380 | |||||||||
NRG Non-Recourse Debt: | |||||||||||
Ivanpah financing: | |||||||||||
Solar Partners I, due 2014 and 2033 | 290 | — | 1.126 - 3.991 | ||||||||
Solar Partners II, due 2014 and 2038 | 314 | — | 1.116 - 4.195 | ||||||||
Solar Partners VIII, due 2014 and 2038 | 270 | — | 1.381 - 4.256 | ||||||||
NRG Peaker Finance Co. LLC, bonds, due 2019 (d) | 190 | 206 | L+1.07 | (f) | |||||||
Agua Caliente Solar, LLC, due 2037 | 181 | — | 2.730 - 3.256 | ||||||||
NRG West Holdings LLC, term loan, due 2023 | 159 | — | L+2.25 - 2.75 | (f) | |||||||
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017, and 2025 (e) | 151 | 163 | 5.95 - 7.31 | ||||||||
South Trent Wind LLC, financing agreement, due 2020 | 75 | 78 | L+ 2.50 | (f) | |||||||
Solar Power Partners - SPP Fund II/IIB LLC term loans, due 2017 | 17 | — | L+3.50 | (f) | |||||||
Solar Power Partners - SPP Fund III LLC term loan, due 2024 | 42 | — | L+3.50 | (f) | |||||||
NRG Roadrunner LLC, due 2031 | 61 | — | L+2.01 | (f) | |||||||
NRG Solar Blythe LLC, credit agreement, due 2028 | 27 | 29 | L+ 2.50 | (f) | |||||||
NRG Connecticut Peaking Development LLC, equity bridge loan facility, due 2010 and 2011 | — | 61 | L + 2.00 | (f) | |||||||
NINA TANE and Shaw facilities, due 2012 and 2013 | — | 167 | L+2.00 - 6.00 | (f) | |||||||
Other | 19 | 20 | various | ||||||||
Subtotal NRG Non-Recourse Debt | 1,796 | 724 | |||||||||
Subtotal | 9,729 | 9,104 | |||||||||
Capital leases: | |||||||||||
Saale Energie GmbH, Schkopau capital lease, due 2021 | 103 | 107 | |||||||||
Subtotal | 9,832 | 9,211 | |||||||||
Less current maturities (g) | 87 | 463 | |||||||||
Total long-term debt and capital leases | $ | 9,745 | $ | 8,748 | |||||||
Funded letter of credit | $ | — | $ | 1,300 | L+1.75-L+3.25 | (f) |
(a) | Includes discount of $(9) million and $(10) million as of December 31, 2011, and 2010, respectively. On June 5, 2009, NRG issued these $700 million aggregate principal amount bonds at a yield of 8.75%. |
(b) | Includes fair value adjustment of $5 million as of December 31, 2010, reflecting an adjustment for an interest rate swap. |
(c) | Includes discount of $(3) million as of December 31, 2011. |
(d) | Includes discount of $(20) million and $(25) million as of December 31, 2011, and 2010, respectively. |
(e) | Includes premium of $1 million and $1 million as of December 31, 2011, and 2010, respectively. |
(f) | L+ equals LIBOR plus x%. |
(g) | Includes discount of $(5) million and $(5) million on the NRG Peaker Finance debt as of December 31, 2011, and 2010, respectively. |
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Senior Notes
Redemption of Senior Notes
On January 26, 2011, the Company redeemed $945 million of the 2014 Senior Notes through a tender offer, at an early redemption percentage of 102.063%. An additional $2 million was tendered at a redemption percentage of 100.063% and the remaining $253 million of 2014 Senior Notes were called on February 25, 2011, at a redemption percentage of 101.813% A $28 million loss on the extinguishment of the 2014 Senior Notes was recorded, which primarily consisted of the premiums paid on the redemption and the write-off of previously deferred financing costs.
On May 24, 2011, the Company redeemed $1.7 billion of the 2016 Senior Notes through a tender offer, at an early redemption percentage of 103.938%. An additional $0.4 million was tendered at a redemption percentage of 102.938% and the remaining $666 million of 2016 Senior Notes was called on June 23, 2011, at a redemption percentage of 103.688% A $115 million loss on the extinguishment of the 2016 Senior Notes was recorded, which primarily consisted of the premiums paid on the redemption and the write-off of previously deferred financing costs.
Senior Notes Outstanding
As of December 31, 2011, NRG had six outstanding issuances of senior notes, or Senior Notes, under an Indenture, dated February 2, 2006, or the Indenture, between NRG and Law Debenture Trust Company of New York, as trustee:
(i.)7.375% senior notes, issued November 21, 2006 and due January 15, 2017, or the 2017 Senior Notes;
(ii.)8.500% senior notes, issued June 5, 2009 and due June 15, 2019, or the 2019 Senior Notes;
(iii.)8.250% senior notes, issued August 20, 2010 and due September 1, 2020, or the 2020 Senior Notes;
(iv.)7.625% senior notes, issued January 26, 2011 and due January 15, 2018, or the 2018 Senior Notes;
(v.)7.625% senior notes, issued May 24, 2011 and due May 15, 2019, or the 7.625% 2019 Senior Notes; and
(vi.)7.875% senior notes, issued May 24, 2011 and due May 15, 2021, or the 2021 Senior Notes.
The Company periodically enters into supplemental indentures for the purpose of adding entities under the Senior Notes as guarantors.
The Indentures and the form of notes provide, among other things, that the Senior Notes will be senior unsecured obligations of NRG. The Indentures also provide for customary events of default, which include, among others: nonpayment of principal or interest; breach of other agreements in the Indentures; defaults in failure to pay certain other indebtedness; the rendering of judgments to pay certain amounts of money against NRG and its subsidiaries; the failure of certain guarantees to be enforceable; and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the Holders of at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be due and payable immediately. The terms of the Indentures, among other things, limit NRG's ability and certain of its subsidiaries' ability to return capital to stockholders, grant liens on assets to lenders and incur additional debt. Interest is payable semi-annually on the Senior Notes until their maturity dates.
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2017 Senior Notes
On or after January 15, 2012, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth below, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Redemption Period | Redemption Percentage | |
February 1, 2012 to January 31, 2013 | 103.688 | % |
February 1, 2013 to January 31, 2014 | 102.458 | % |
February 1, 2014 to January 31, 2015 | 101.229 | % |
February 1, 2015 and thereafter | 100.000 | % |
2019 Senior Notes
Prior to June 15, 2012, NRG may redeem up to 35% of the aggregate principal amount of the 2019 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.5% of the principal amount. Prior to June 15, 2014, NRG may redeem all or a portion of the 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 104.25% of the note, plus interest payments due on the note from the date of redemption through June 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after June 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Redemption Period | Redemption Percentage | |
June 15, 2014 to June 14, 2015 | 104.250 | % |
June 15, 2015 to June 14, 2016 | 102.830 | % |
June 15, 2016 to June 14, 2017 | 101.420 | % |
June 15, 2017 and thereafter | 100.000 | % |
2020 Senior Notes
Prior to September 1, 2013, NRG may redeem up to 35% of the aggregate principal amount of the 2020 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.25% of the principal amount. Prior to September 1, 2015, NRG may redeem all or a portion of the 2020 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note; or (ii) the excess of the principal amount of the note over the following: the present value of 104.125% of the note, plus interest payments due on the note from the date of redemption through September 1, 2015, discounted at a Treasury rate plus 0.50%. In addition, on or after September 1, 2015, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Redemption Period | Redemption Percentage | |
On or after September 1, 2015 | 104.125 | % |
On or after September 1, 2016 | 102.750 | % |
On or after September 1, 2017 | 101.375 | % |
September 1, 2018 and thereafter | 100.000 | % |
2018 Senior Notes
On January 26, 2011, NRG issued $1.2 billion aggregate principal amount at par of 7.625% Senior Notes due 2018, or the 2018 Senior Notes. The 2018 Senior Notes were issued under the Indenture. The Indenture and the form of the notes provide, among other things, that the 2018 Senior Notes will be senior unsecured obligations of NRG. The net proceeds of $1.195 billion were used primarily to complete the tender offer of the 2014 Senior Notes. Interest is payable semi-annually beginning on July 15, 2011, until their maturity date of January 15, 2018.
44
Prior to maturity, NRG may redeem all or a portion of the 2018 Senior Notes at a redemption price equal to 100% of the principal amount of the notes redeemed plus a premium and accrued and unpaid interest. The premium is the greater of (i) 1% of the principal amount of the note or (ii) the excess of the present value of the principal amount at maturity plus all required interest payments due on the note through the maturity date discounted at a Treasury rate plus 0.50%.
7.625% 2019 Senior Notes and 2021 Senior Notes
On May 24, 2011, NRG issued $800 million aggregate principal amount at par of 7.625% Senior Notes due 2019, or the 7.625% 2019 Senior Notes, and $1.2 billion aggregate principal amount at par of 7.875% Senior Notes due 2021, or the 2021 Senior Notes.
The net proceeds of $2 billion for both the 7.625% 2019 Senior Notes and the 2021 Senior Notes were used to complete the tender offer of the 2016 Senior Notes. Interest is payable semi-annually beginning on November 15, 2011, until their maturity dates of May 15, 2019, and May 15, 2021, respectively.
Prior to May 15, 2014, NRG may redeem up to 35% of the aggregate principal amount of the 7.625% 2019 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.625% of the principal amount. Prior to May 15, 2014, NRG may redeem all or a portion of the 7.625% 2019 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.813% of the note, plus interest payments due on the note from the date of redemption through May 15, 2014, discounted at a Treasury rate plus 0.50%. In addition, on or after May 15, 2014, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Redemption Period | Redemption Percentage | |
May 15, 2014 to May 14, 2015 | 103.813 | % |
May 15, 2015 to May 14, 2016 | 101.906 | % |
May 15, 2016 and thereafter | 100.000 | % |
Prior to May 15, 2016, NRG may redeem up to 35% of the aggregate principal amount of the 2021 Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 107.875% of the principal amount. Prior to May 15, 2016, NRG may redeem all or a portion of the 2021 Senior Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid interest. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess of the principal amount of the note over the following: the present value of 103.938% of the note, plus interest payments due on the note from the date of redemption through May 15, 2016, discounted at a Treasury rate plus 0.50%. In addition, on or after May 15, 2016, NRG may redeem some or all of the notes at redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Redemption Period | Redemption Percentage | |
May 15, 2016 to May 14, 2017 | 103.938 | % |
May 15, 2017 to May 14, 2018 | 102.625 | % |
May 15, 2018 to May 14, 2019 | 101.313 | % |
May 15, 2019 and thereafter | 100.000 | % |
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Senior Credit Facility
On July 1, 2011, NRG replaced its Senior Credit Facility, consisting of its Term Loan Facility, Revolving Credit Facility and Funded Letter of Credit Facility, with a new senior secured facility, or the 2011 Senior Credit Facility, which includes the following:
• | A $2.3 billion revolving credit facility, or the 2011 Revolving Credit Facility, with a maturity date of July 1, 2016, which will pay interest on amounts drawn at a rate of LIBOR plus 2.75%. In addition, the related Funded Letter of Credit loan was repaid, the non-current restricted cash balance was returned to the lenders and the related balances were removed from NRG's balance sheet. A $13 million loss on extinguishment of the Revolving Credit Facility and Funded Letter of Credit Facility was recorded, which consisted of the write-off of previously deferred financing costs. As of December 31, 2011, a total of $1.627 billion letters of credit were issued under the 2011 Revolving Credit Facility, with $673 million remaining available to be issued. Commitment fees of 0.50% are charged on the unused portion of the 2011 Revolving Credit Facility. |
• | A $1.6 billion term loan facility, or the 2011 Term Loan Facility, with a maturity date of July 1, 2018, which will pay interest at a rate of LIBOR plus 3.00%, with a LIBOR floor of 1.00%. The debt was issued at 99.75% of face value; the discount will be amortized to interest expense over the life of the loan. Repayments under the 2011Term Loan Facility will consist of 0.25% per quarter, with the remainder due at maturity. The proceeds of the new term loan facility were used to repay the existing Term Loan Facility balance outstanding. A $19 million loss on extinguishment of the Term Loan Facility was recorded, which consisted of the write-off of previously deferred financing costs. |
The 2011 Senior Credit Facility is guaranteed by substantially all of NRG's existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, project subsidiaries, and certain other subsidiaries. The capital stock of substantially all of NRG's subsidiaries, with certain exceptions for unrestricted subsidiaries, foreign subsidiaries, and project subsidiaries, has been pledged for the benefit of the 2011 Senior Credit Facility's lenders.
The 2011 Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property and assets owned or acquired by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets of certain unrestricted subsidiaries, equity interests in certain of NRG's project affiliates that have non-recourse debt financing, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of NRG's foreign subsidiaries.
The 2011 Senior Credit Facility contains customary covenants, which, among other things, require NRG to meet certain financial tests, including minimum interest coverage ratio and a maximum leverage ratio on a consolidated basis, and limit NRG's ability to:
• | incur indebtedness and liens and enter into sale and lease-back transactions; |
• | make investments, loans and advances; and |
• | return capital to stockholders. |
Interest Rate Swaps - NRG entered into interest rate swaps, which became effective on April 1, 2011, and are intended to hedge the risks associated with floating interest rates. The Company pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the monthly equivalent of a floating interest payment based on a 1-month LIBOR calculated on the same notional value. All interest rate swap payments by NRG and its counterparty are made monthly and the LIBOR is determined in advance of each interest period. The total notional amount of the swaps, which mature on February 1, 2013, is $900 million with changes in the fair value through June 30, 2011 recorded in OCI and subsequent changes in the fair value reported in interest expense.
46
Indian River Power LLC Tax-Exempt Bonds
On October 12, 2010, NRG executed a $190 million tax-exempt bond financing through its wholly-owned subsidiary, Indian River Power LLC. The bonds were issued by the Delaware Economic Development Authority and will be used for construction of emission control equipment on the Indian River Generating Station in Millsboro, DE, or Indian River. The bonds were issued at a rate of 5.375%, have a maturity date of October 1, 2045, and are supported by an NRG guarantee. The proceeds received through December 31, 2011, were $148 million, and the remaining balance will be received over time as construction costs are paid.
On December 10, 2010, NRG executed an additional $57 million tax-exempt bond financing through Indian River Power LLC. The bonds were issued by Sussex County, Delaware, and will be used for construction of emission control equipment on Indian River. The bonds were issued at a rate of 6.0%, have a maturity date of October 1, 2040, and are supported by an NRG guarantee. The proceeds received through December 31, 2011, were $57 million, and the remaining balance will be received over time as construction costs are paid.
Dunkirk Power LLC Tax-Exempt Bonds
On April 15, 2009, NRG executed a $59 million tax-exempt bond financing, or the Dunkirk bonds, through its wholly-owned subsidiary, Dunkirk Power LLC, whereby all the proceeds were received as of December 31, 2011. The bonds were issued by the County of Chautauqua Industrial Development Agency and are being used for the construction of emission control equipment on the Dunkirk Generating Station in Dunkirk, NY. The bonds initially bore weekly interest based on the Securities Industry and Financial Markets Association, or SIFMA, rate, and on February 1, 2010, the Company fixed the rate on the bonds at 5.875%, with interest payable semiannually. The bonds have a maturity date of April 1, 2042, and are supported by an NRG guarantee.
NRG Non-Recourse Debt
Project Financings
The following are descriptions of certain indebtedness of NRG's project subsidiaries that are outstanding as of December 31, 2011. The indebtedness described below is non-recourse to NRG, unless otherwise noted.
Ivanpah Financing
On April 5, 2011, NRG acquired a majority interest in Ivanpah, as discussed in Note 3, Business Acquisitions and Dispositions. On April 5, 2011, Ivanpah entered into the Ivanpah Credit Agreement with the FFB to borrow up to $1.6 billion to finance the costs of constructing the Ivanpah solar facilities. Each phase of the project is governed by a separate financing agreement and is non recourse to both the other projects and to NRG. Funding requests are submitted to the FFB on a monthly basis and the loans provided by the FFB are guaranteed by the U.S. DOE. Amounts borrowed under the Ivanpah Credit Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375% and are secured by all the assets of Ivanpah. Ivanpah intends to submit an application to the U.S. Department of Treasury for a cash grant; any proceeds received will be utilized to repay the borrowings that mature in 2014.
The following table reflects the borrowings under the Ivanpah Credit Agreement as of December 31, 2011:
Maximum borrowings available under Ivanpah Credit Agreement | Amounts borrowed | Weighted average interest rate on amounts borrowed | ||||||||
(In millions, except rates) | ||||||||||
Solar Partners I, due June 27, 2014 (a) | $ | 159 | $ | 154 | 1.678 | % | ||||
Solar Partners I, due June 27, 2033 | 392 | 136 | 3.181 | % | ||||||
Solar Partners II, due February 27, 2014 (a) | 132 | 129 | 1.609 | % | ||||||
Solar Partners II, due February 27, 2038 | 387 | 185 | 3.458 | % | ||||||
Solar Partners VIII, due October 27, 2014 (a) | 117 | 111 | 1.997 | % | ||||||
Solar Partners VIII, due October 27, 2038 | 440 | 159 | 3.561 | % | ||||||
$ | 1,627 | $ | 874 |
(a) The cash portion of the loan is fully drawn; additional amounts will be utilized for capitalized interest.
47
Peakers
In June 2002, NRG Peaker Finance Company LLC, or Peakers, an indirect wholly-owned subsidiary, issued $325 million in floating rate bonds due June 2019. Peakers subsequently swapped such floating rate debt for fixed rate debt at an all-in cost of 6.67% per annum. Principal, interest, and swap payments were originally guaranteed by Syncora Guarantee Inc., successor in interest to XL Capital Assurance, through a financial guaranty insurance policy. In 2009, Assured Guaranty Mutual Corp assumed the responsibility as the bond insurer and controlling party. Syncora Guarantee Inc. continues to be the swap insurer. These notes are also secured by, among other things, substantially all of the assets of and membership interests in Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG Rockford II LLC, and NRG Rockford Equipment LLC. As of December 31, 2011, $210 million in principal remained outstanding on these bonds. Upon emergence from bankruptcy, NRG issued a $36 million letter of credit to Peakers' collateral agent. The letter of credit may be drawn if the project is unable to meet principal or interest payments. There are no provisions requiring NRG to replenish the letter of credit if it is drawn. On December 31, 2011, the collateral agent drew $18 million on the letter of credit to meet the debt service requirements and as of December 31, 2011, $4 million remains available for additional letters of credit issuances.
Agua Caliente Financing
On August 5, 2011, NRG acquired Agua Caliente, as discussed in Note 3, Business Acquisitions and Dispositions. In connection with the acquisition, Agua Caliente Solar LLC, a wholly-owned subsidiary of NRG, entered into the Agua Caliente Financing Agreement with the FFB, to borrow up to $967 million to finance the costs of constructing this solar facility. The Agua Caliente Financing Agreement, which matures in 2037, is non-recourse to NRG. Funding requests will be submitted to the FFB on a monthly basis and the loans provided by the FFB are guaranteed by the U.S. DOE. Amounts borrowed under the Agua Caliente Financing Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375%, and are secured by the assets of Agua Caliente. As of December 31, 2011, $181 million had been drawn under this agreement.
NRG West Holdings Credit Agreement
On August 23, 2011, NRG, through its wholly-owned subsidiary, NRG West Holdings LLC, or West Holdings, entered into a credit agreement with a group of lenders in respect to the El Segundo Energy Center, or the West Holdings Credit Agreement. The West Holdings Credit Agreement, which establishes a $540 million, two tranche construction loan facility with additional facilities for the issuance of letters of credit or working capital loans, is secured by the assets of West Holdings.
The two tranche construction loan facility consists of the $480 million Tranche A Construction Facility, or the Tranche A Facility, and the $60 million Tranche B Construction Facility, or the Tranche B Facility. The Tranche A and Tranche B Facilities, which mature in August 2023, convert to a term loan and have an interest rate of LIBOR, plus an applicable margin which increases by 0.125% periodically from conversion through year eight for the Tranche A Facility and increases by 0.125% upon term conversion and on the third and sixth anniversary of the term conversion and by 0.250% on the eighth anniversary of the term conversion for the Tranche B Facility. The Tranche A and Tranche B Facilities amortize based upon a predetermined schedule over the term of the loan with the balance payable at maturity.
The West Holdings Credit Agreement also provides for the issuance of letters of credit and working capital loans to support the El Segundo Energy Center collateral needs. This includes letter of credit facilities on behalf of West Holdings of up to $90 million in support of the PPA, up to $48 million in support of the collateral agent, and a working capital facility which permits loans or the issuance of letters of credit of up to $10 million.
As of December 31, 2011, under the West Holdings Credit Agreement, West Holdings borrowed $159 million under the Tranche A Facility, issued a $30 million letter of credit in support of the PPA, and issued a $6 million letter of credit under the working capital facility.
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NRG Thermal
NRG owns and operates its thermal business through a wholly-owned subsidiary holding company, NRG Thermal LLC, or NRG Thermal. In 1993, the predecessor entity to NRG Thermal's largest subsidiary, NRG Energy Center Minneapolis LLC, or NRG Thermal Minneapolis, issued $84 million of 7.31% senior secured notes due June 2013, of which $12 million remained outstanding as of December 31, 2011. In 2002, NRG Thermal Minneapolis issued an additional $55 million of 7.25% Series A notes due August 2017, of which $29 million remained outstanding as of December 31, 2011, and $20 million of 7.12% Series B notes due August 2017, of which $10 million remained outstanding as of December 31, 2011. In 2010, NRG Thermal Minneapolis issued $100 million of 5.95% Series C notes due June 23, 2025, of which $100 million remained outstanding as of December 31, 2011.
The indebtedness under these notes is secured by substantially all of the assets of NRG Thermal Minneapolis. NRG Thermal has guaranteed the indebtedness, and its guarantee is secured by a pledge of the equity interests in all of NRG Thermal's subsidiaries.
South Trent Financing Agreement
In connection with the acquisition, on June 14, 2010, South Trent Wind LLC entered into a financing agreement, or the South Trent Financing Agreement, with a group of lenders, which matures on June 14, 2020. The South Trent Financing Agreement includes a $79 million term loan, as well as a $10 million letter of credit facility in support of the PPA. The South Trent Financing Agreement also provides for up to $7 million in additional letter of credit facilities. The term loan accrues interest at LIBOR plus a margin based upon a grid, which is initially 2.5% and increases every two years by 12.5 basis points. The term loan amortizes quarterly based upon a predetermined schedule with the unamortized portion due at maturity. As of December 31, 2011, $75 million was outstanding under the term loan and $10 million was issued under the letter of credit facility.
Solar Power Partners Financing
NRG acquired Solar Power Partners, or SPP, on November 7, 2011. The following is a description of the long-term debt acquired in connection with the acquisition.
SPP Fund II/II-B — In order to finance the construction of solar assets, SPP Fund II entered into a term loan agreement with a bank. Under the agreement, SPP Fund II borrowed $20 million, which matures on June 30, 2024, and bears interest at LIBOR plus 3.50% and SPP Fund II-B borrowed $3 million, which matures on September 30, 2024 and bears interest at LIBOR plus 3.50%. The term loans are secured by substantially all of the assets of the respective fund and contain certain non-financial reporting covenants. The outstanding balance under the Fund II term loan was $15 million and under the Fund II-B term loan was $2 million as of the acquisition date and as of December 31, 2011.
SPP Fund III — In order to finance the construction of solar assets, SPP Fund III entered into a credit facility for a $75 million construction loan with two banks. The construction phase was completed in 2011 with the Company having borrowed $44 million. In June 2011 the construction loan converted to a term loan which amortizes quarterly with the remaining balance due on March 31, 2017, and bears interest at LIBOR plus 3.50%. SPP Fund III also issued a $1 million letter of credit in support of its agreements with one of its customers. The term loans are secured by substantially all of the assets of the respective fund and contain certain nonfinancial reporting covenants. As of the acquisition date and as of December 31, 2011, $42 million was outstanding under the credit facility.
Roadrunner Financing
On May 25, 2011, NRG, through its wholly-owned subsidiary, NRG Roadrunner LLC, or Roadrunner, entered into a credit agreement with a bank, or the Roadrunner Financing Agreement, for a $47 million construction loan that converted to a term loan on January 10, 2012 and a $21 million cash grant loan, both of which have an interest rate of LIBOR plus an applicable margin of 2.01%. The term loan has an interest rate of LIBOR plus an applicable margin which escalates 0.25% every five years and ranges from 2.10% at closing to 2.76% in year fifteen through maturity. The term loan, which is secured by all the assets of Roadrunner, matures on September 30, 2031, and amortizes based upon a predetermined schedule. The cash grant loan matures upon the earlier of the receipt of the cash grant or March 31, 2012. The Roadrunner Financing Agreement also includes a letter of credit facility on behalf of Roadrunner of up to $5 million. Roadrunner pays an availability fee of 100% of the applicable margin on issued letters of credit. As of December 31, 2011, $47 million was outstanding under the construction loan, $14 million was outstanding under the cash grant loans and $2 million in letters of credit in support of the PPA were issued. On January 10, 2012, in connection with the conversion of the construction loan to a term loan, the Company borrowed an additional $4 million of cash grant loans and issued a $3 million letter of credit in support of debt service.
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Blythe Credit Agreement
On June 24, 2010, NRG Solar Blythe LLC, or Blythe, entered into a credit agreement with a bank, or the Blythe Credit Agreement, for a $30 million term loan which has an interest rate of LIBOR plus an applicable margin which escalates 0.25% every three years and ranges from 2.5% at closing to 3.75% in year fifteen. The term loan matures in June 2028, amortizes based upon a predetermined schedule, and is secured by all of the assets of Blythe. The bank has also issued two letters of credit on behalf of Blythe, totaling $6 million. Blythe pays an availability fee of 100% of the applicable margin on these issued letters of credit. As of December 31, 2011, $27 million was outstanding under the term loan and $6 million in letters of credit were issued.
CVSR Financing
On September 30, 2011, NRG acquired CVSR, as discussed in Note 3, Business Acquisitions and Dispositions. In connection with the acquisition, High Plains Ranch II LLC, a wholly-owned subsidiary of NRG, entered into the CVSR Financing Agreement with the FFB, to borrow up to $1.2 billion to finance the costs of constructing this solar facility. The CVSR Financing Agreement, which matures in 2037, is non-recourse to NRG. Funding requests will be submitted to the FFB on a monthly basis and the loans provided by the FFB are guaranteed by the U.S. DOE. Amounts borrowed under the CVSR Financing Agreement accrue interest at a fixed rate based on U.S. Treasury rates plus a spread of 0.375%, and are secured by the assets of CVSR. As of December 31, 2011, no amounts were drawn under this agreement. CVSR intends to submit an application to the U.S. Department of Treasury for a cash grant; any proceeds received will be utilized to repay borrowings under the CVSR Financing Agreement.
Under the terms of the CVSR Financing Agreement, on November 17, 2011, CVSR entered into a series of swaptions with a notional value of $686 million, or 80% of the guaranteed term loan amount, in order to hedge the project interest rate risk. These swaptions mature over a series of seven scheduled settlement dates to correspond with the completion dates of the project.
GenConn Energy LLC related financings
NRG Connecticut Peaking Development LLC, or NRG Connecticut Peaking, a wholly-owned subsidiary of NRG, had an equity bridge loan facility, or EBL, in the amount of $122 million from a syndicate of banks. The purpose of the EBL was to fund the Company's proportionate share of the project construction costs required to be contributed into GenConn Energy LLC, or GenConn, a 50% equity method investment of the Company. The EBL bore interest at a rate of LIBOR +2% on drawn amounts, and was backed by a letter of credit issued by NRG under its Funded Letter of Credit Facility equal to at least 104% of amounts outstanding under the EBL. On September 29, 2010, GenConn's Devon project reached its commercial operations date, or COD, as defined in the financing documents and NRG Connecticut Peaking repaid the $55 million portion of the EBL used to fund the Devon project, and converted $56 million of a promissory note from GenConn into equity. On June 29, 2011, when GenConn's Middletown project reached COD, as defined in the financing documents, NRG Connecticut Peaking repaid the remaining $61 million outstanding under the EBL. The commitment was terminated and the collateral held under the EBL, including the letter of credit issued by NRG under the Funded Letter of Credit Facility, was returned.
NRG Repowering Holdings LLC
NRG Repowering Holdings LLC, or NRG Repowering, had $5 million outstanding under a revolving credit facility as of December 31, 2011. On January 25, 2012, the facility was repaid and terminated and a supporting letter of credit issued by NRG was returned.
On January 25, 2012, NRG Repowering entered into a Credit and Reimbursement Agreement which provides for a $10 million working capital facility that can be used for general corporate purposes or to issue letters of credit, and an $80 million letter of credit facility. Interest on the letters of credit accrues at 3.5% and on loans under the working capital facility at LIBOR plus 3.5%. The facility is secured by NRG Repowering's investments in GenConn and South Trent Wind LLC, and matures January 25, 2015. As of January 23, 2012, NRG Repowering had issued a $10 million letter of credit under the working capital facility and $80 million in letters of credit under the letter of credit facility.
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NINA Financing Arrangements
TANE and Shaw Facilities — NINA and TANE entered into a credit facility, wherein TANE committed up to $500 million to finance purchases of long-lead materials and equipment for the construction of STP Units 3 and 4. NINA also entered into a credit facility with Shaw, wherein Shaw committed up to $100 million to finance working capital needs and the expenses of Shaw related to the construction of STP Units 3 and 4. As described further in Note 4, Nuclear Innovation North America LLC Developments, Including Impairment Charge, NRG deconsolidated NINA as of March 31, 2011; therefore any amounts outstanding under these facilities are no longer consolidated into NRG's financial statements.
Interest Rate Swaps — Project Financings
Many of NRG's project subsidiaries entered into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. These swaps amortize in proportion to their respective loans and are floating for fixed where the project subsidiary pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value and will receive quarterly the equivalent of a floating interest payment based on the same notional value. All interest rate swap payments by the project subsidiary and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period. The following table summarizes the swaps, some of which are forward starting as indicated, related to NRG's project level debt as of December 31, 2011.
Non-Recourse Debt | % of Principal | Fixed Interest Rate | Floating Interest Rate | Notional Amount at December 31, 2011 (In millions) | Effective Date | Maturity Date | ||||||||||
NRG Peaker Finance Co. LLC | 100 | % | 6.673 | % | 3-mo. LIBOR + 1.07% | $ | 210 | June 18, 2002 | June 10, 2019 | |||||||
NRG West Holdings LLC | 75 | % | 2.4165 | % | 3-mo. LIBOR | 135 | November 30, 2011 | August 31, 2023 | ||||||||
South Trent Wind LLC | 75 | % | 3.265 | % | 3-mo. LIBOR | 56 | June 14, 2010 | June 14, 2020 | ||||||||
South Trent Wind LLC | 75 | % | 4.95 | % | 3-mo. LIBOR | 21 | June 14, 2020 | June 14, 2028 | ||||||||
NRG Solar Roadrunner LLC | 75 | % | 4.313 | % | 3-mo. LIBOR | 36 | September 30, 2011 | December 31, 2029 | ||||||||
NRG Solar Blythe LLC | 75 | % | 3.563 | % | 3-mo. LIBOR | 20 | June 25, 2010 | June 25, 2028 | ||||||||
Solar Power Partners II | 75 | % | 7.14 | % | 3-mo. LIBOR + 3.5% | 11 | June 30, 2009 | June 30, 2024 | ||||||||
Solar Power Partners II-B | 75 | % | 6.72 | % | 3-mo. LIBOR + 3.5% | 2 | October 1, 2009 | September 30, 2024 | ||||||||
Solar Power Partners III | 100 | % | 3.67 | % | 3-mo. LIBOR | 42 | April 30, 2010 | September 30, 2026 |
Capital Leases
Saale Energie GmbH
Saale Energie GmbH, or SEG, an NRG wholly-owned subsidiary, has a 41.9% participation in Schkopau through NRG's interest in the Kraftwerke Schkopau GbR, or KSGbR, partnership. Under the terms of a Use and Benefit Fee Agreement, SEG and the other partner to the project, E.ON Kraftwerke GmbH, are required to fund debt service and certain other costs resulting from the construction and financing of Schkopau. The Use and Benefit Fee Agreement is treated as a capital lease under U.S. GAAP. Calls for funds are made to the partners based on their participation interest as cash is needed. As of December 31, 2011, the capital lease obligation at SEG was $103 million.
The KSGbR issued debt to fund Schkopau pursuant to multiple facilities totaling €785 million. As of December 31, 2011, €117 million (approximately $152 million) remained outstanding at Schkopau. Interest accrues on the individual loans at fixed rates averaging 6.70% per annum, with maturities occurring between 2012 and 2020. SEG remains liable to the lenders as a partner in KSGbR, but there is no recourse to NRG.
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Consolidated Annual Maturities and Future Minimum Lease Payments
Annual payments based on the maturities of NRG's debt and capital leases, for the years ending after December 31, 2011 are as follows:
(In millions) | |||
2012 | $ | 87 | |
2013 | 71 | ||
2014 | 496 | ||
2015 | 129 | ||
2016 | 137 | ||
Thereafter | 8,912 | ||
Total | $ | 9,832 |
NRG's future minimum lease payments for capital leases included above as of December 31, 2011, are as follows:
(In millions) | |||
2012 | $ | 11 | |
2013 | 10 | ||
2014 | 8 | ||
2015 | 7 | ||
2016 | 5 | ||
Thereafter | 82 | ||
Total minimum obligations | 123 | ||
Interest | 20 | ||
Present value of minimum obligations | 103 | ||
Current portion | 8 | ||
Long-term obligations | $ | 95 |
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Note 13 — Asset Retirement Obligations
NRG's AROs are primarily related to the future dismantlement of equipment on leased property and environmental obligations related to nuclear decommissioning, ash disposal, site closures, and fuel storage facilities. In addition, NRG has also identified conditional AROs for asbestos removal and disposal, which are specific to certain power generation operations.
See Note 7, Nuclear Decommissioning Trust Fund, for a further discussion of NRG's nuclear decommissioning obligations. Consequently, accretion for the nuclear decommissioning ARO and amortization of the related ARO asset are recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in net income, consistent with regulatory treatment.
The following table represents the balance of ARO obligations as of December 31, 2011, and 2010, along with the additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2011:
(In millions) | |||
Balance as of December 31, 2010 | $ | 432 | |
Revisions in estimates for current obligations | (10 | ) | |
Spending for current obligations | (5 | ) | |
Accretion — Expense | 8 | ||
Accretion — Nuclear decommissioning | 18 | ||
Balance as of December 31, 2011 | $ | 443 |
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Note 14 — Benefit Plans and Other Postretirement Benefits
NRG sponsors and operates three defined benefit pension and other postretirement plans. The NRG Plan for Bargained Employees and the NRG Plan for Non-bargained Employees are maintained solely for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained for participation by eligible Texas based employees. NRG expects to contribute $23 million to the Company's three pension plans in 2012.
NRG Plans for Bargained and Non-bargained Employees — Substantially all employees hired prior to December 5, 2003, were eligible to participate in NRG's legacy defined benefit pension plans. The Company initiated a noncontributory, defined benefit pension plan effective January 1, 2004, with credit for service from December 5, 2003. In addition, the Company provides postretirement health and welfare benefits for certain groups of employees. Generally, these are groups that were acquired prior to 2004 and for whom prior benefits are being continued (at least for a certain period of time or as required by union contracts). Cost sharing provisions vary by acquisition group and terms of any applicable collective bargaining agreements.
Texas Genco Retirement Plan — The Texas region's pension plan is a noncontributory defined benefit pension plan that provides a final average pay benefit or cash balance benefit, where the participant receives the more favorable of the two formulas, based on all years of service. In addition, employees who were hired prior to 1999 are also eligible for grandfathered benefits under a final average pay formula. In most cases, the benefits under the grandfathered formula were frozen on December 31, 2008. NRG's Texas region employees are also covered under an unfunded postretirement health and welfare plan. Each year, employees receive a fixed credit of $750 to their account plus interest. At retirement, the employees may use their accounts to purchase retiree medical and dental benefits from NRG. NRG's costs are limited to the amounts earned in the employee's account; all other costs are paid by the participant.
NRG Defined Benefit Plans
The net annual periodic pension cost related to NRG domestic pension and other postretirement benefit plans include the following components:
Year Ended December 31, | |||||||||||
Pension Benefits | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions) | |||||||||||
Service cost benefits earned | $ | 14 | $ | 14 | $ | 12 | |||||
Interest cost on benefit obligation | 21 | 21 | 20 | ||||||||
Expected return on plan assets | (21 | ) | (20 | ) | (16 | ) | |||||
Amortization of unrecognized net gain | — | — | 1 | ||||||||
Net periodic benefit cost | $ | 14 | $ | 15 | $ | 17 |
Year Ended December 31, | |||||||||||
Other Postretirement Benefits | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions) | |||||||||||
Service cost benefits earned | $ | 2 | $ | 2 | $ | 2 | |||||
Interest cost on benefit obligation | 6 | 6 | 6 | ||||||||
Amortization of unrecognized prior service cost | — | — | 1 | ||||||||
Net periodic benefit cost | $ | 8 | $ | 8 | $ | 9 |
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A comparison of the pension benefit obligation, other postretirement benefit obligations, and related plan assets for NRG's plans on a combined basis is as follows:
As of December 31, | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(In millions) | |||||||||||||||
Benefit obligation at January 1 | $ | 404 | $ | 357 | $ | 106 | $ | 104 | |||||||
Service cost | 14 | 14 | 2 | 2 | |||||||||||
Interest cost | 21 | 21 | 6 | 6 | |||||||||||
Plan amendments | — | — | — | (5 | ) | ||||||||||
Actuarial loss | 34 | 24 | 9 | — | |||||||||||
Employee and retiree contributions | — | — | 1 | 1 | |||||||||||
Benefit payments | (17 | ) | (12 | ) | (2 | ) | (2 | ) | |||||||
Benefit obligation at December 31 | 456 | 404 | 122 | 106 | |||||||||||
Fair value of plan assets at January 1 | 297 | 263 | — | — | |||||||||||
Actual return on plan assets | 10 | 30 | — | — | |||||||||||
Employee contributions | — | — | 1 | 1 | |||||||||||
Employer contributions | 18 | 16 | 1 | 1 | |||||||||||
Benefit payments | (17 | ) | (12 | ) | (2 | ) | (2 | ) | |||||||
Fair value of plan assets at December 31 | 308 | 297 | — | — | |||||||||||
Funded status at December 31 — excess of obligation over assets | $ | (148 | ) | $ | (107 | ) | $ | (122 | ) | $ | (106 | ) |
Amounts recognized in NRG's balance sheets were as follows:
As of December 31, | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(In millions) | |||||||||||||||
Current liabilities | $ | — | $ | — | $ | 3 | $ | 2 | |||||||
Non-current liabilities | 148 | 107 | 119 | 104 |
Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit cost were as follows:
As of December 31, | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(In millions) | |||||||||||||||
Unrecognized loss | $ | 88 | $ | 42 | $ | 11 | $ | 1 | |||||||
Prior service (credit)/cost | (2 | ) | (2 | ) | (1 | ) | — |
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Other changes in plan assets and benefit obligations recognized in other comprehensive income were as follows:
Year Ended December 31, | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(In millions) | |||||||||||||||
Unrecognized loss | $ | 46 | $ | 13 | $ | 9 | $ | — | |||||||
Prior service cost/(credit) | — | — | — | (5 | ) | ||||||||||
Amortization for prior service cost/(credit) | — | 1 | — | — | |||||||||||
Total recognized in other comprehensive loss/(gain) | $ | 46 | $ | 14 | $ | 9 | $ | (5 | ) | ||||||
Total recognized in net periodic pension cost and other comprehensive income | $ | 60 | $ | 28 | $ | 17 | $ | 3 |
The Company's estimated unrecognized loss for NRG's domestic pension plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is approximately $4 million. The Company's estimated unrecognized loss for NRG's postretirement plan that will be amortized from accumulated OCI to net periodic cost over the next fiscal year is minimal.
The following table presents the balances of significant components of NRG's domestic pension plan:
As of December 31, | |||||||
Pension Benefits | |||||||
2011 | 2010 | ||||||
(In millions) | |||||||
Projected benefit obligation | $ | 456 | $ | 404 | |||
Accumulated benefit obligation | 392 | 347 | |||||
Fair value of plan assets | 308 | 297 |
NRG's market-related value of its plan assets is the fair value of the assets. The fair values of the Company's pension plan assets by asset category and their level within the fair value hierarchy are as follows:
Fair Value Measurements as of December 31, 2011 | |||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Observable Inputs (Level 2) | Total | |||||||||
(In millions) | |||||||||||
U.S. equity investment | $ | 47 | $ | — | $ | 47 | |||||
International equity investment | 18 | — | 18 | ||||||||
Corporate bond investment-fixed income | 37 | — | 37 | ||||||||
Common/collective trust investment — U.S. equity | — | 78 | 78 | ||||||||
Common/collective trust investment — international equity | — | 32 | 32 | ||||||||
Common/collective trust investment — fixed income | — | 96 | 96 | ||||||||
Total | $ | 102 | $ | 206 | $ | 308 |
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Fair Value Measurements as of December 31, 2010 | |||||||||||
Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Observable Inputs (Level 2) | Total | |||||||||
(In millions) | |||||||||||
U.S. equity investment | $ | 46 | $ | — | $ | 46 | |||||
International equity investment | 19 | — | 19 | ||||||||
Corporate bond investment-fixed income | 31 | — | 31 | ||||||||
Common/collective trust investment — U.S. equity | — | 80 | 80 | ||||||||
Common/collective trust investment — international equity | — | 35 | 35 | ||||||||
Common/collective trust investment — fixed income | — | 85 | 85 | ||||||||
Short-term investment fund | — | 1 | 1 | ||||||||
Total | $ | 96 | $ | 201 | $ | 297 |
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety. The fair value of the U.S. and international equity investments and the corporate bond investment is based on quoted prices in active markets, and is categorized as Level 1. All equity investments are valued at the net asset value of shares held at year end. The fair value of the corporate bond investment is based on the closing price reported on the active market on which the individual securities are traded. The fair value of the common/collective trusts is valued at fair value which is equal to the sum of the market value of all of the fund's underlying investments, and is categorized as Level 2. There are no investments categorized as Level 3.
The following table presents the significant assumptions used to calculate NRG's benefit obligations:
As of December 31, | |||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||
Weighted-Average Assumptions | 2011 | 2010 | 2011 | 2010 | |||||||
Discount rate | 4.98 | % | 5.47 | % | 5.18 | % | 5.77 | % | |||
Rate of compensation increase | 4.00-4.50% | 4.00-4.50% | N/A | N/A | |||||||
Health care trend rate | — | — | 8% grading to 5% in 2019 | 8% grading to 5% in 2019 |
The following table presents the significant assumptions used to calculate NRG's benefit expense:
As of December 31, | |||||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
Weighted-Average Assumptions | 2011 | 2010 | 2009 | 2011 | 2010 | 2009 | |||||||||||
Discount rate | 5.47 | % | 5.93 | % | 6.88 | % | 5.77 | % | 6.14 | % | 6.88 | % | |||||
Expected return on plan assets | 7.25%-7.50% | 7.50 | % | 7.50 | % | — | — | — | |||||||||
Rate of compensation increase | 4.00-4.50% | 4.00-4.50% | 4.00-4.50% | — | — | — | |||||||||||
Health care trend rate | — | — | — | 8.0% grading to 5.0% in 2019 | 9.5% grading to 5.5% in 2016 | 9.5% grading to 5.5% in 2016 |
NRG uses December 31 of each respective year as the measurement date for the Company's pension and other postretirement benefit plans. The Company sets the discount rate assumptions on an annual basis for each of NRG's retirement related benefit plans at their respective measurement date. This rate is determined by NRG's Investment Committee based on information provided by the Company's actuary. The discount rate assumptions reflect the current rate at which the associated liabilities could be effectively settled at the end of the year. The discount rate assumptions used to determine future pension obligations as of December 31, 2011, were based on the Aon Hewitt AA Above Median (AAM) yield curve; which was designed by Aon Hewitt to provide a means for corporate plan sponsors to value the liabilities of defined benefit and other post retirement benefit plans. The AAM is a hypothetical Aa yield curve represented by a series of annualized individual discount rates from 0.5 to 99 years. Each bond issue is required to have an average rating of AA, when averaging all available ratings by Moody's Investor Services, Standard &
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Poor's and Fitch. The discount rate assumptions used to determine future pension obligations as of December 31, 2010, and 2009 were based on the Hewitt Yield Curve, or HYC, which was designed by Hewitt Associates to provide a means for plan sponsors to value the liabilities of their postretirement benefit plans. The HYC is a hypothetical yield curve represented by a series of annualized individual discount rates. Each bond issue underlying the HYC is required to have a rating of Aa or better by Moody's Investor Service, Inc. or a rating of AA or better by Standard & Poor's.
NRG employs a total return investment approach, whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The target allocation of plan assets is 47% to 73% invested in equity securities of which 34% to 51% is invested in U.S. equity securities, with the remainder invested in fixed income securities. The Investment Committee reviews the asset mix periodically and as the plan assets increase in future years, the Investment Committee may examine other asset classes such as real estate or private equity. NRG employs a building block approach to determining the long-term rate of return for plan assets, with proper consideration given to diversification and rebalancing. Historical markets are studied and long-term historical relationships between equities and fixed income are preserved, consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonableness and appropriateness.
Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. equities, as well as among growth, value, small and large capitalization stocks.
NRG's pension plan assets weighted average allocations were as follows:
As of December 31, | |||
2011 | 2010 | ||
U.S. equity | 33.5-50.5% | 33.5-50.5% | |
International equity | 13.5-22.5% | 13.5-22.5% | |
U.S. fixed income | 30-50% | 30-50% |
NRG's expected future benefit payments for each of the next five years, and in the aggregate for the five years thereafter, are as follows:
Other Postretirement Benefit | |||||||||||
Pension Benefit Payments | Benefit Payments | Medicare Prescription Drug Reimbursements | |||||||||
(In millions) | |||||||||||
2012 | $ | 21 | $ | 3 | $ | — | |||||
2013 | 23 | 3 | — | ||||||||
2014 | 24 | 4 | — | ||||||||
2015 | 26 | 4 | — | ||||||||
2016 | 29 | 5 | — | ||||||||
2017-2021 | 182 | 33 | 1 |
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effect:
1-Percentage- Point Increase | 1-Percentage- Point Decrease | ||||||
(In millions) | |||||||
Effect on total service and interest cost components | $ | 1 | $ | (1 | ) | ||
Effect on postretirement benefit obligation | 9 | (7 | ) |
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STP Defined Benefit Plans
NRG has a 44% undivided ownership interest in STP, as discussed further in Note 27, Jointly Owned Plants. South Texas Project Nuclear Operating Company, or STPNOC, which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards its retirement plan obligations. For the years ending December 31, 2011, and 2010 NRG reimbursed STPNOC approximately $12 million and $4 million, respectively, towards its defined benefit plans. In 2012, NRG expects to reimburse STPNOC $15 million for its contributions towards the plans.
The Company has recognized the following in its statement of financial position, statement of operations and accumulated OCI related to its 44% interest in STP:
As of December 31, | |||||||||||||||
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
2011 | 2010 | 2011 | 2010 | ||||||||||||
(In millions) | |||||||||||||||
Funded status — STPNOC benefit plans | $ | (67 | ) | $ | (55 | ) | $ | (49 | ) | $ | (40 | ) | |||
Net periodic benefit costs | 9 | 8 | 6 | 4 | |||||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive income | 15 | 8 | 3 | 7 |
Defined Contribution Plans
NRG's employees have also been eligible to participate in defined contribution 401(k) plans. The Company's contributions to these plans were as follows:
Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions) | |||||||||||
Company contributions to defined contribution plans | $ | 24 | $ | 28 | $ | 22 |
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Note 15 — Capital Structure
For the period from December 31, 2008, to December 31, 2011, the Company had 10,000,000 shares of preferred stock authorized and 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's preferred and common shares issued and outstanding for each period presented:
Preferred Stock Issued and Outstanding | Common | ||||||||||||||||
3.625% | 4% | 5.75% | Issued | Treasury | Outstanding | ||||||||||||
Balance as of December 31, 2008 | 250,000 | 420,000 | 1,841,680 | 263,599,200 | (29,242,483 | ) | 234,356,717 | ||||||||||
Shares issued under ESPP | — | — | — | — | 81,532 | 81,532 | |||||||||||
Shares loaned to affiliates of CS | — | — | — | — | 12,000,000 | 12,000,000 | |||||||||||
Shares returned by affiliate of CS | — | — | — | — | (5,400,000 | ) | (5,400,000 | ) | |||||||||
Capital Allocation Plan repurchases | — | — | — | — | (19,305,500 | ) | (19,305,500 | ) | |||||||||
Shares issued from LTIP | — | — | — | 367,858 | — | 367,858 | |||||||||||
4.00% Preferred Stock conversion | — | (265,870 | ) | — | 13,293,500 | — | 13,293,500 | ||||||||||
4.00% Preferred Stock redeemed for cash | — | (73 | ) | — | — | — | — | ||||||||||
5.75% Preferred Stock conversion | — | — | (1,841,680 | ) | 18,601,201 | — | 18,601,201 | ||||||||||
Balance as of December 31, 2009 | 250,000 | 154,057 | — | 295,861,759 | (41,866,451 | ) | 253,995,308 | ||||||||||
Shares issued under ESPP | — | — | — | — | 120,990 | 120,990 | |||||||||||
Shares returned by affiliate of CS | — | — | — | — | (6,600,000 | ) | (6,600,000 | ) | |||||||||
Capital Allocation Plan repurchases | — | — | — | — | (8,463,211 | ) | (8,463,211 | ) | |||||||||
Shares issued from LTIP | — | — | — | 442,818 | — | 442,818 | |||||||||||
4.00% Preferred Stock conversion | — | (154,029 | ) | — | 7,701,450 | — | 7,701,450 | ||||||||||
4.00% Preferred Stock redeemed for cash | — | (28 | ) | — | — | — | — | ||||||||||
Balance as of December 31, 2010 | 250,000 | — | — | 304,006,027 | (56,808,672 | ) | 247,197,355 | ||||||||||
Shares issued under ESPP | — | — | — | — | 120,127 | 120,127 | |||||||||||
Shares issued under LTIP | — | — | — | 177,693 | — | 177,693 | |||||||||||
Capital Allocation Plan repurchases | — | — | — | — | (19,975,654 | ) | (19,975,654 | ) | |||||||||
Balance as of December 31, 2011 | 250,000 | — | — | 304,183,720 | (76,664,199 | ) | 227,519,521 |
Common Stock
The following table summarizes NRG's common stock reserved for the maximum number of shares potentially issuable based on the conversion and redemption features of outstanding equity instruments and the long-term incentive plan as of December 31, 2011.
Equity Instrument | Common Stock Reserve Balance | |
3.625% Convertible perpetual preferred | 16,000,000 | |
Long-term incentive plan | 18,573,196 | |
Total | 34,573,196 |
Capital Allocation Plan — As part of the Company's Capital Allocation Program, the Company returns capital to shareholders through NRG common stock repurchases under the Capital Allocation Plan. Shares repurchased are included in treasury stock.
Employee Stock Purchase Plan — Under the NRG Energy, Inc. Employee Stock Purchase Plan, or ESPP, eligible employees may elect to withhold up to 10% of their eligible compensation to purchase shares of NRG common stock at 85% of its fair market value on the exercise date. An exercise date occurs each June 30 and December 31. As of December 31, 2011, there remained 177,351 shares of treasury stock reserved for issuance under the ESPP, and in the first quarter of 2012, 76,423 shares of common stock were issued to employee accounts from treasury stock.
Share Lending Agreements — On February 20, 2009, Common Stock Finance, or CSF, I and II entered into Share Lending Agreements, or SLAs, with affiliates of Credit Suisse Group, or CS, relating to the shares of NRG common stock held by CSF I and II in connection with the CSF Debt. CSF I and CSF II loaned 12,000,000 shares of NRG common stock to affiliates of CS in the first quarter 2009. The shares were treated as outstanding for corporate law purposes, but were not considered outstanding for the purpose of computing and reporting the Company's basic or diluted earnings per share, because the CS affiliates were required to return all borrowed shares (or identical shares).
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In the fourth quarter 2009, CS returned 5,400,000 of these shares in connection with the maturity of the CSF II Debt, and 6,600,000 common shares, with a fair value of $156 million, remained outstanding at December 31, 2009. CS returned these 6,600,000 shares of NRG as part of the CSF I Debt unwind on March 2, 2010. The 12,000,000 shares of NRG common stock were returned to treasury stock and are no longer be treated as outstanding for corporate law purposes.
Preferred Stock
5.75% Preferred Stock
On February 2, 2006, NRG completed the issuance of 2,000,000 shares of 5.75% Mandatory Convertible Preferred Stock, or 5.75% Preferred Stock, for net proceeds of $486 million, reflecting an offering price of $250 per share and the deduction of offering expenses and discounts of $14 million. Dividends on the 5.75% Preferred Stock were $14.375 per share per year, and were due and payable on a quarterly basis beginning on March 15, 2006. The 5.75% Preferred Stock agreement provided for automatic conversion into common stock on March 16, 2009, and for earlier conversion under certain circumstances. All conversions and redemptions were completed by March 25, 2009.
4% Preferred Stock
The Company's 4% Convertible Perpetual Preferred Stock, or 4% Preferred Stock, had a liquidation preference of $1,000 per share, and its holders were entitled to receive cash dividends at the rate of 4% per annum, or $40.00 per share per year, payable quarterly in arrears commencing on March 15, 2005. The 4% Preferred Stock was convertible, at the option of the holder, at any time into shares of NRG's common stock at an initial conversion price of $20.00 per share. In addition, NRG had the ability to redeem, on or after December 20, 2009, and subject to certain limitations, some or all of the 4% Preferred Stock with cash at a redemption price equal to 100% of the liquidation preference, plus accumulated but unpaid dividends, including liquidated damages, if any, to the redemption date. In the fourth quarter of 2009, NRG notified the holders of the Company's intention to redeem the 4% Preferred Stock, and the majority of the holders elected to convert their shares in response to this notification. All conversions and redemptions were completed by January 21, 2010.
Redeemable Preferred Stock
3.625% Preferred Stock
On August 11, 2005, NRG issued 250,000 shares of 3.625% Convertible Perpetual Preferred Stock, or 3.625% Preferred Stock, which is treated as Redeemable Preferred Stock, to CS in a private placement. The 3.625% Preferred Stock amount is located after the liabilities but before the stockholders' equity section on the balance sheet, due to the fact that the preferred shares can be redeemed in cash by the stockholder. The 3.625% Preferred Stock has a liquidation preference of $1,000 per share. Holders of the 3.625% Preferred Stock are entitled to receive, out of legally available funds, cash dividends at the rate of 3.625% per annum, or $36.25 per share per year, payable in cash quarterly in arrears commencing on December 15, 2005.
Each share of the 3.625% Preferred Stock is convertible during the 90-day period beginning August 11, 2015, at the option of NRG or the holder. Holders tendering the 3.625% Preferred Stock for conversion shall be entitled to receive, for each share of 3.625% Preferred Stock converted, $1,000 in cash and a number of shares of NRG common stock equal in value to the product of (a) the greater of (i) the difference between the average closing share price of NRG common stock on each of the twenty consecutive scheduled trading days starting on the date thirty exchange business days immediately prior to the conversion date, or the Market Price, and $29.54 and (ii) zero, times (b) 50.77. The number of NRG common stock to be delivered under the conversion feature is limited to 16,000,000 shares. If upon conversion, the Market Price is less than $19.69, then the Holder will deliver to NRG cash or a number of shares of NRG common stock equal in value to the product of (i) $19.69 minus the Market Price, times (ii) 50.77. NRG may elect to make a cash payment in lieu of delivering shares of NRG common stock in connection with such conversion, and NRG may elect to receive cash in lieu of shares of common stock, if any, from the Holder in connection with such conversion. The conversion feature is considered an embedded derivative per ASC 815 that is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815.
If a fundamental change occurs, the holders will have the right to require NRG to repurchase all or a portion of the 3.625% Preferred Stock for a period of time after the fundamental change at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends. The 3.625% Preferred Stock is senior to all classes of common stock, and junior to all of the Company's existing and future debt obligations and all of NRG subsidiaries' existing and future liabilities and capital stock held by persons other than NRG or its subsidiaries.
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Note 16 — Investments Accounted for by the Equity Method and Variable Interest Entities
NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of equity investments can be impacted by impairments, unrealized gains and losses on derivatives and movements in foreign currency exchange rates, as well as other adjustments.
The following table summarizes NRG's equity method investments as of December 31, 2011:
Name | Geographic Area | Economic Interest | |
Avenal Solar Holdings LLC | United States | 50.0 | % |
GenConn Energy LLC | United States | 50.0 | % |
Saguaro Power Company | United States | 50.0 | % |
Sherbino I Wind Farm LLC | United States | 50.0 | % |
Texas Coastal Ventures, LLC | United States | 50.0 | % |
Gladstone Power Station | Australia | 37.5 | % |
Energy Technology Ventures | United States | 33.3 | % |
As of December 31, | |||||||
2011 | 2010 | ||||||
(In millions) | |||||||
Undistributed earnings from equity investments | $ | 150 | $ | 160 |
Variable Interest Entities, or VIEs
NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, but NRG is not the primary beneficiary, under the equity method.
GenConn Energy LLC — Through its subsidiary, NRG Connecticut Peaking, NRG owns a 50% interest in GenConn, a limited liability company formed to construct, own and operate two 200MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. Each of these facilities was constructed pursuant to 30-year cost of service type contracts with the Connecticut Light & Power Company. All four units at the GenConn Devon facility reached commercial operation in 2010 and were released to the ISO-NE by July 2010. In June 2011, the GenConn Middletown facility reached commercial operation and was released to the ISO-NE.
The project was funded through equity contributions from the owners and non-recourse, project level debt. As of December 31, 2010, NRG Connecticut Peaking had $61 million, of outstanding borrowings under an EBL, as described in Note 12, Debt and Capital Leases and had a note receivable due from GenConn for $62 million as discussed in Note 9, Capital Leases and Notes Receivable. When the Middletown project reached its commercial operations date, NRG Connecticut Peaking repaid the $61 million portion of the EBL used to fund the Middletown project, and converted $62 million of the note receivable from GenConn into equity. As of December 31, 2011, NRG had a $131 million equity investment in GenConn. NRG's maximum exposure to loss is limited to its equity investment.
In April 2009, GenConn secured financing for 50% of the Devon and Middletown project construction costs through a seven-year term loan facility, and also entered into a five-year revolving working capital loan and letter of credit facility, which collectively with the term loan is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including $48 million for the working capital facility. GenConn began to draw under the GenConn Facility to cover costs related to the Devon project in August 2009, and the Middletown project in June 2010. During 2011, the GenConn Facility was fully drawn and GenConn repaid $6 million of the GenConn Facility. As of December 31, 2011, $237 million was outstanding for the GenConn facility.
As discussed in Note 21, Related Party Transactions, NRG earned revenues from construction management agreements with Devon and Middletown and interest income from the note receivable with GenConn.
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Sherbino I Wind Farm LLC — NRG owns a 50% interest in Sherbino, a joint venture with BP Wind Energy North America Inc. Sherbino is a 150 MW wind farm, which commenced commercial operations in October 2008. In December 2008, Sherbino entered into a 15-year term loan facility which is non-recourse to NRG. As of December 31, 2011, the outstanding principal balance of the term loan facility was $125 million, and is secured by substantially all of Sherbino's assets and membership interests. NRG's maximum exposure to loss is limited to its equity investment, which was $100 million as of December 31, 2011.
Texas Coastal Ventures, LLC — NRG owns a 50% interest in Texas Coastal Ventures, LLC, or TCV, a joint venture with Hilcorp Energy I, L.P., through its subsidiary Petra Nova LLC. Texas Coastal Ventures was formed by Petra Nova and Hilcorp for the purpose of using carbon dioxide captured from flue gas from certain of NRG's coal-generating power plants in the United States Gulf Coast in an enhanced oil recovery process. TCV is managed by the joint venture participants and operated by Hilcorp. TCV entered into service agreements with Petra Nova LLC, which include a management services agreement for the operation and management of the joint venture's pipeline assets, as well as a CO2 supply agreement having an initial term of twenty years. NRG's maximum exposure to loss is limited to its equity investment, which was $48 million as of December 31, 2011.
Other Equity Investments
Gladstone — Through a joint venture, NRG owns a 37.5% interest in Gladstone, a 1,613 megawatt coal-fueled power generation facility in Queensland, Australia. The power generation facility is managed by the joint venture participants and the facility is operated by NRG. Operating expenses incurred in connection with the operation of the facility are funded by each of the participants in proportion to their ownership interests. Coal is sourced from local mines in Queensland. NRG and the joint venture participants receive their respective share of revenues directly from the off takers in proportion to the ownership interests in the joint venture. Power generated by the facility is primarily sold to an adjacent aluminum smelter, with excess power sold to the Queensland Government owned utility under long term supply contracts.
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Note 17 — Earnings Per Share
Basic earnings per common share is computed by dividing net income less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings per share is computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period. Share borrowed under the SLA (see Note 15, Capital Structure) were not treated as outstanding for earnings per share purposes.
Dilutive effect for equity compensation — The outstanding non-qualified stock options, non-vested restricted stock units, deferred stock units and performance units are not considered outstanding for purposes of computing basic earnings per share. However, these instruments are included in the denominator for purposes of computing diluted earnings per share under the treasury stock method.
Dilutive effect for other equity instruments — Prior to their conversion, NRG's 4% and 5.75% Preferred Stock were not considered outstanding for purposes of computing basic earnings per share. However, these instruments were considered for inclusion in the denominator for purposes of computing diluted earnings per share under the if-converted method. The if-converted method is also used to determine the dilutive effect of embedded derivatives in the Company's 3.625% Preferred Stock.
The reconciliation of NRG's basic earnings per share to diluted earnings per share is shown in the following table:
Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions, except per share amounts) | |||||||||||
Basic earnings per share attributable to NRG common stockholders | |||||||||||
Numerator: | |||||||||||
Net income attributable to NRG Energy, Inc. | $ | 197 | $ | 477 | $ | 942 | |||||
Preferred stock dividends | (9 | ) | (9 | ) | (33 | ) | |||||
Net income attributable to NRG Energy, Inc. available to common stockholders | $ | 188 | $ | 468 | $ | 909 | |||||
Denominator: | |||||||||||
Weighted average number of common shares outstanding | 240 | 252 | 246 | ||||||||
Basic earnings per share: | |||||||||||
Net income attributable to NRG Energy, Inc. | $ | 0.78 | $ | 1.86 | $ | 3.70 | |||||
Diluted earnings per share attributable to NRG common stockholders | |||||||||||
Numerator: | |||||||||||
Net income attributable to NRG Energy, Inc. | $ | 188 | $ | 468 | $ | 909 | |||||
Add preferred stock dividends for dilutive preferred stock | — | — | 23 | ||||||||
Net income attributable to NRG Energy, Inc. available to common stockholders | $ | 188 | $ | 468 | $ | 932 | |||||
Denominator: | |||||||||||
Weighted average number of common shares outstanding | 240 | 252 | 246 | ||||||||
Incremental shares attributable to the issuance of equity compensation (treasury stock method) | 1 | 1 | 1 | ||||||||
Incremental shares attributable to the assumed conversion features of outstanding preferred stock (if-converted method) | — | 1 | 24 | ||||||||
Total dilutive shares | 241 | 254 | 271 | ||||||||
Diluted earnings per share: | |||||||||||
Net income attributable to NRG Energy, Inc. | $ | 0.78 | $ | 1.84 | $ | 3.44 |
The following table summarizes NRG's outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company's diluted earnings per share:
Year Ended December 31, | ||||||||
2011 | 2010 | 2009 | ||||||
(In millions of shares) | ||||||||
Equity compensation — NQSOs and PUs | 7 | 6 | 6 | |||||
Embedded derivative of 3.625% redeemable perpetual preferred stock | 16 | 16 | 16 | |||||
Total | 23 | 22 | 22 |
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Note 18 — Segment Reporting
2012 Business Segment Realignment
Effective in fiscal year 2012, NRG's segment structure and its allocation of corporate expenses were updated to reflect how management currently makes financial decisions and allocates resources. The Company has recast the data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are primarily segregated based on the Retail businesses, conventional power generation, alternative energy businesses and corporate activities. Within NRG's conventional power generation operations, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, Northeast, South Central, West, and Other, which includes its international businesses, thermal and chilled water business and maintenance services. The Company's alternative energy businesses include solar and wind assets, electric vehicle services and carbon capture business. Intersegment sales are accounted for at market.
For the years ended December 31, 2011, 2010, and 2009, there were no customers from whom the Company derived more than 10% of the Company's consolidated revenues.
Year Ended December 31, 2011 | |||||||||||||||||||||||||||||||||||||||
Conventional Power Generation | |||||||||||||||||||||||||||||||||||||||
Retail(a)(b) | Texas(a) | North-east(a) | South Central | West | Other(a) | Alternative Energy(a) | Corporate | Elimination | Total | ||||||||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 5,642 | $ | 2,832 | $ | 924 | $ | 817 | $ | 149 | $ | 323 | $ | 44 | $ | 11 | $ | (1,663 | ) | $ | 9,079 | ||||||||||||||||||
Operating expenses | 5,113 | 1,910 | 858 | 703 | 92 | 282 | 63 | 30 | (1,663 | ) | 7,388 | ||||||||||||||||||||||||||||
Depreciation and amortization | 159 | 463 | 118 | 89 | 10 | 14 | 31 | 12 | — | 896 | |||||||||||||||||||||||||||||
Impairment charge on emission allowances | — | 160 | — | — | — | — | — | — | — | 160 | |||||||||||||||||||||||||||||
Operating income/(loss) | 370 | 299 | (52 | ) | 25 | 47 | 27 | (50 | ) | (31 | ) | — | 635 | ||||||||||||||||||||||||||
Equity in earnings/(loss) of unconsolidated affiliates | — | — | 11 | — | 9 | 9 | 6 | — | — | 35 | |||||||||||||||||||||||||||||
Impairment charge on investment | — | — | — | — | — | — | — | (495 | ) | — | (495 | ) | |||||||||||||||||||||||||||
Other income/(loss), net | — | 1 | 2 | 2 | — | 5 | 3 | 21 | (15 | ) | 19 | ||||||||||||||||||||||||||||
Loss on debt extinguishment and refinancing expense | — | — | — | — | — | — | — | (175 | ) | — | (175 | ) | |||||||||||||||||||||||||||
Interest (expense)/income | (4 | ) | 16 | (47 | ) | (41 | ) | (2 | ) | (15 | ) | (16 | ) | (571 | ) | 15 | (665 | ) | |||||||||||||||||||||
Income/(loss) before income taxes | 366 | 316 | (86 | ) | (14 | ) | 54 | 26 | (57 | ) | (1,251 | ) | — | (646 | ) | ||||||||||||||||||||||||
Income tax expense/(benefit) | (3 | ) | — | — | — | — | 7 | — | (847 | ) | — | (843 | ) | ||||||||||||||||||||||||||
Net income/(loss) | $ | 369 | $ | 316 | $ | (86 | ) | $ | (14 | ) | $ | 54 | $ | 19 | $ | (57 | ) | $ | (404 | ) | $ | — | $ | 197 | |||||||||||||||
Balance sheet | |||||||||||||||||||||||||||||||||||||||
Equity investments in affiliates | $ | — | $ | — | $ | 136 | $ | — | $ | 28 | $ | 308 | $ | 168 | $ | — | $ | — | $ | 640 | |||||||||||||||||||
Capital expenditures (c) | 23 | 99 | 188 | 25 | 281 | 40 | 1,809 | 137 | — | 2,602 | |||||||||||||||||||||||||||||
Goodwill | 173 | 1,713 | — | — | — | — | — | — | — | 1,886 | |||||||||||||||||||||||||||||
Total assets | $ | 2,725 | $ | 13,006 | $ | 2,042 | $ | 1,436 | $ | 669 | $ | 1,006 | $ | 3,154 | $ | 19,694 | $ | (17,017 | ) | $ | 26,715 |
(a) Includes intersegment sales of: | $ | 5 | $ | 1,586 | $ | 43 | $ | — | $ | — | $ | 18 | $ | 16 | $ | — |
(b) Includes Green Mountain Energy results, and Energy Plus results for the period October 1, 2011 to December 31, 2011.
(c) Includes accruals.
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Year Ended December 31, 2010 | |||||||||||||||||||||||||||||||||||||||
Conventional Power Generation | |||||||||||||||||||||||||||||||||||||||
Retail(a)(b) | Texas(a) | North-east | South Central | West | Other(a) | Alternative Energy(a) | Corporate | Elimination | Total | ||||||||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 5,055 | $ | 3,040 | $ | 1,025 | $ | 608 | $ | 138 | $ | 301 | $ | 41 | $ | 1 | $ | (1,360 | ) | $ | 8,849 | ||||||||||||||||||
Operating expenses | 4,547 | 1,749 | 847 | 506 | 98 | 260 | 38 | 41 | (1,360 | ) | 6,726 | ||||||||||||||||||||||||||||
Depreciation and amortization | 127 | 466 | 122 | 67 | 9 | 12 | 27 | 8 | — | 838 | |||||||||||||||||||||||||||||
Gains on sale of asset | — | — | — | — | — | — | — | 23 | — | 23 | |||||||||||||||||||||||||||||
Operating income/(loss) | 381 | 825 | 56 | 35 | 31 | 29 | (24 | ) | (25 | ) | — | 1,308 | |||||||||||||||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | 1 | — | 6 | 24 | 14 | (1 | ) | — | 44 | ||||||||||||||||||||||||||||
Other income/(loss), net | — | 2 | 4 | 1 | 1 | 18 | — | 24 | (17 | ) | 33 | ||||||||||||||||||||||||||||
Loss on debt extinguishment and refinancing expense | — | — | — | — | — | — | — | (2 | ) | — | (2 | ) | |||||||||||||||||||||||||||
Interest (expense)/income | (5 | ) | 79 | (57 | ) | (46 | ) | (2 | ) | (14 | ) | (13 | ) | (589 | ) | 17 | (630 | ) | |||||||||||||||||||||
Income/(loss) before income taxes | 376 | 906 | 4 | (10 | ) | 36 | 57 | (23 | ) | (593 | ) | — | 753 | ||||||||||||||||||||||||||
Income tax expense | — | — | — | — | — | 17 | — | 260 | — | 277 | |||||||||||||||||||||||||||||
Net income/(loss) | 376 | 906 | 4 | (10 | ) | 36 | 40 | (23 | ) | (853 | ) | — | 476 | ||||||||||||||||||||||||||
Less: Net loss attributable to noncontrolling interest | — | (1 | ) | — | — | — | — | — | — | — | (1 | ) | |||||||||||||||||||||||||||
Net income/(loss) attributable to NRG Energy, Inc. | $ | 376 | $ | 907 | $ | 4 | $ | (10 | ) | $ | 36 | $ | 40 | $ | (23 | ) | $ | (853 | ) | $ | — | $ | 477 | ||||||||||||||||
Balance sheet | |||||||||||||||||||||||||||||||||||||||
Equity investments in affiliates | $ | — | $ | — | $ | 67 | $ | — | $ | 42 | $ | 312 | $ | 115 | $ | — | $ | — | $ | 536 | |||||||||||||||||||
Capital expenditures (c) | 12 | 88 | 206 | 18 | 67 | 29 | 33 | 646 | — | 1,099 | |||||||||||||||||||||||||||||
Goodwill | 147 | 1,713 | — | — | — | — | — | 8 | — | 1,868 | |||||||||||||||||||||||||||||
Total assets | $ | 2,190 | $ | 12,695 | $ | 1,891 | $ | 1,350 | $ | 348 | $ | 1,082 | $ | 783 | $ | 29,812 | $ | (23,255 | ) | $ | 26,896 |
(a) Includes intersegment sales of: | $ | 2 | $ | 1,304 | $ | — | $ | — | $ | — | $ | 25 | $ | 23 | $ | — |
(b) Includes Green Mountain Energy results for the period November 5, 2010 to December 31, 2010.
(c) Includes accruals.
Year Ended December 31, 2009 | |||||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | |||||||||||||||||||||||||||||||||||||||
Retail(b) | Texas (a) | North-east (a) | South Central | West | Other | Alternative Energy | Corporate | Elimination | Total | ||||||||||||||||||||||||||||||
(In millions) | |||||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 4,182 | $ | 2,938 | $ | 1,201 | $ | 581 | $ | 150 | $ | 286 | $ | 8 | $ | 28 | $ | (422 | ) | $ | 8,952 | ||||||||||||||||||
Operating expenses | 3,044 | 1,636 | 740 | 508 | 110 | 227 | 8 | 127 | (425 | ) | 5,975 | ||||||||||||||||||||||||||||
Depreciation and amortization | 137 | 459 | 118 | 67 | 8 | 10 | 13 | 6 | — | 818 | |||||||||||||||||||||||||||||
Operating income/(loss) | 1,001 | 843 | 343 | 6 | 32 | 49 | (13 | ) | (105 | ) | 3 | 2,159 | |||||||||||||||||||||||||||
Equity in earnings/(loss) of unconsolidated affiliates | — | — | — | — | 10 | 31 | — | — | — | 41 | |||||||||||||||||||||||||||||
Gains on sales of equity method investments | — | — | — | — | — | 128 | — | — | — | 128 | |||||||||||||||||||||||||||||
Other income, net | — | 3 | 2 | 1 | — | (16 | ) | — | 27 | (22 | ) | (5 | ) | ||||||||||||||||||||||||||
Loss on debt extinguishment and refinancing expense | (1 | ) | — | — | — | — | — | — | (19 | ) | — | (20 | ) | ||||||||||||||||||||||||||
Interest expense | (34 | ) | 6 | (54 | ) | (48 | ) | (2 | ) | (13 | ) | (10 | ) | (497 | ) | 18 | (634 | ) | |||||||||||||||||||||
Income/(loss) before income taxes | 966 | 852 | 291 | (41 | ) | 40 | 179 | (23 | ) | (594 | ) | (1 | ) | 1,669 | |||||||||||||||||||||||||
Income tax expense | — | 171 | — | — | — | 9 | — | 548 | — | 728 | |||||||||||||||||||||||||||||
Net income/(loss) | 966 | 681 | 291 | (41 | ) | 40 | 170 | (23 | ) | (1,142 | ) | (1 | ) | 941 | |||||||||||||||||||||||||
Less: Net loss attributable to noncontrolling interest | — | (1 | ) | — | — | — | — | — | — | — | (1 | ) | |||||||||||||||||||||||||||
Net income/(loss) attributable to NRG Energy, Inc. | $ | 966 | $ | 682 | $ | 291 | $ | (41 | ) | $ | 40 | $ | 170 | $ | (23 | ) | $ | (1,142 | ) | $ | (1 | ) | $ | 942 | |||||||||||||||
(a) Includes intersegment sales of: | $ | — | $ | 381 | $ | 37 | $ | — | $ | — | $ | — | $ | — | $ | — |
(b) Results are for the period May 1, 2009, to December 31, 2009.
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Note 19 — Income Taxes
The income tax provision from continuing operations consisted of the following amounts:
Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions, except percentages) | |||||||||||
Current | |||||||||||
U.S. Federal | $ | (538 | ) | $ | 211 | $ | 99 | ||||
State | 10 | 35 | 20 | ||||||||
Foreign | 16 | 23 | 18 | ||||||||
(512 | ) | 269 | 137 | ||||||||
Deferred | |||||||||||
U.S. Federal | (317 | ) | 23 | 599 | |||||||
State | (5 | ) | (9 | ) | 1 | ||||||
Foreign | (9 | ) | (6 | ) | (9 | ) | |||||
(331 | ) | 8 | 591 | ||||||||
Total income tax | $ | (843 | ) | $ | 277 | $ | 728 | ||||
Effective tax rate | 130.5 | % | 36.8 | % | 43.6 | % |
The following represents the domestic and foreign components of income before income tax expense:
Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions) | |||||||||||
U.S. | $ | (680 | ) | $ | 691 | $ | 1,508 | ||||
Foreign | 34 | 62 | 161 | ||||||||
Total | $ | (646 | ) | $ | 753 | $ | 1,669 |
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A reconciliation of the U.S. federal statutory rate of 35% to NRG's effective rate is as follows:
Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions, except percentages) | |||||||||||
(Loss)/Income Before Income Taxes | $ | (646 | ) | $ | 753 | $ | 1,669 | ||||
Tax at 35% | (226 | ) | 264 | 584 | |||||||
State taxes, net of federal benefit | 15 | 18 | 23 | ||||||||
Foreign operations | (3 | ) | (3 | ) | (53 | ) | |||||
Federal and state tax credits | (1 | ) | (7 | ) | — | ||||||
Valuation allowance | (63 | ) | (34 | ) | 119 | ||||||
Expiration/utilization of capital losses | 45 | — | 249 | ||||||||
Reversal of valuation allowance on expired/utilized capital losses | (45 | ) | — | (249 | ) | ||||||
Change in state effective tax rate | — | — | (5 | ) | |||||||
Foreign earnings | 4 | 17 | 33 | ||||||||
Non-deductible interest | — | 4 | 10 | ||||||||
Interest accrued on uncertain tax positions | 2 | 25 | 9 | ||||||||
Production tax credit | (14 | ) | (11 | ) | (10 | ) | |||||
Reversal of uncertain tax position reserves | (561 | ) | — | — | |||||||
Other | 4 | 4 | 18 | ||||||||
Income tax (benefit)/expense | $ | (843 | ) | $ | 277 | $ | 728 | ||||
Effective income tax rate | 130.5 | % | 36.8 | % | 43.6 | % |
The effective tax rate for the year ended December 31, 2011, differs from the statutory rate of 35% primarily due to a benefit of $633 million resulting from the resolution of the federal tax audit. The benefit is predominantly due to the recognition of previously uncertain tax benefits that were settled upon audit in 2011 and that were mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes.
The effective tax rate for the year ended December 31, 2010, differs from the statutory rate of 35% primarily due to the impact of state and local income taxes and interest on uncertain tax positions, which were partially offset by the reduction in the valuation allowance resulting from realized capital gains as well as federal and state tax credits generated during the current year.
The effective income tax rate for the year ended December 31, 2009, differs from the U.S. statutory rate of 35% primarily due to an increase in the valuation allowance as a result of capital losses generated during the period. In addition, the current earnings in foreign jurisdictions are taxed at rates lower than the U.S. statutory rate, including the sale of the MIBRAG facility which resulted in minimal tax due to the local jurisdiction.
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The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:
As of December 31, | |||||||
2011 | 2010 | ||||||
(In millions) | |||||||
Deferred tax liabilities: | |||||||
Discount/premium on notes | $ | 7 | $ | 9 | |||
Emissions allowances | 92 | 116 | |||||
Difference between book and tax basis of property | 1,604 | 1,652 | |||||
Derivatives, net | 244 | 362 | |||||
Goodwill | 139 | 117 | |||||
Anticipated repatriation of foreign earnings | — | 6 | |||||
Cumulative translation adjustments | 27 | 28 | |||||
Intangibles amortization (excluding goodwill) | 229 | 180 | |||||
Investment in projects | 111 | 71 | |||||
Other | 8 | — | |||||
Total deferred tax liabilities | 2,461 | 2,541 | |||||
Deferred tax assets: | |||||||
Deferred compensation, pension, accrued vacation and other reserves | 80 | 67 | |||||
Differences between book and tax basis of contracts | 225 | 59 | |||||
Pension and other postretirement benefits | 137 | 111 | |||||
Non-depreciable property | — | 19 | |||||
Equity compensation | 36 | 30 | |||||
Bad debt reserve | 15 | 12 | |||||
U.S. capital loss carryforwards | 1 | 92 | |||||
U.S. Federal net operating loss carryforwards | 84 | — | |||||
Foreign net operating loss carryforwards | 70 | 74 | |||||
State net operating loss carryforwards | 53 | 23 | |||||
Foreign capital loss carryforwards | 1 | 1 | |||||
Deferred financing costs | — | 6 | |||||
Federal and state tax credits | 64 | 34 | |||||
Federal benefit on state uncertain tax positions | 20 | 31 | |||||
Contingent liability reserve | — | 30 | |||||
NINA impairment | 183 | — | |||||
Emission allowance impairment | 59 | — | |||||
Other | — | 46 | |||||
Total deferred tax assets | 1,028 | 635 | |||||
Valuation allowance | (83 | ) | (191 | ) | |||
Net deferred tax assets | 945 | 444 | |||||
Net deferred tax liability | $ | 1,516 | $ | 2,097 |
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The following table summarizes NRG's net deferred tax position:
As of December 31, | |||||||
2011 | 2010 | ||||||
(In millions) | |||||||
Current deferred tax liability | $ | 127 | $ | 108 | |||
Non-current deferred tax liability | 1,389 | 1,989 | |||||
Net deferred tax liability | $ | 1,516 | $ | 2,097 |
Tax Receivable and Payable
As of December 31, 2011, NRG recorded a current tax payable of $17 million that represents a tax liability due for domestic state taxes of $14 million, as well as foreign taxes payable of $3 million. NRG has a domestic tax receivable of $56 million, of which $25 million relates to federal cash grants applied for eligible solar energy projects under development in New Mexico and Arizona, $18 million is related to property tax refunds due to the New York State Empire Zone program and $13 million primarily is due to federal refunds on prior year returns. In addition, we have recorded a $49 million non-current asset for Empire Zone credits generated in 2010 and 2011 that are being deferred pursuant to New York State law.
Deferred tax assets and valuation allowance
Net deferred tax balance — As of December 31, 2011, and 2010, NRG recorded a net deferred tax liability of $1.4 billion and $1.9 billion, respectively. However, due to an assessment of positive and negative evidence, including projected capital gains and available tax planning strategies, NRG believes that it is more likely than not that a benefit will not be realized on $83 million and $191 million of tax assets, thus a valuation allowance has remained, resulting in a net deferred tax liability of $1.5 billion and $2.1 billion as of December 31, 2011, and 2010, respectively. NRG believes it is more likely than not that future earnings will be sufficient to utilize the Company's deferred tax assets, net of the existing valuation allowances at December 31, 2011.
NOL carryforwards — At December 31, 2011, the Company had domestic net operating losses, or NOLs, consisting of carryforwards for federal income tax purposes of $84 million and cumulative state NOLs of $53 million. In addition, NRG has cumulative foreign NOL carryforwards of $70 million of which $20 million will expire starting 2012 through 2019 and of which $50 million do not have an expiration date. At December 31, 2010 the Company had state NOLs of $23 million and cumulative foreign NOL carryforwards of $74 million.
Valuation allowance — As of December 31, 2011, the Company's valuation allowance was reduced by $108 million, primarily due to resolution of the federal tax audit.
Uncertain tax benefits
NRG has identified uncertain tax benefits whose after-tax value was $178 million that if recognized, would impact the Company's income tax expense.
As of December 31, 2011, and 2010, NRG has recorded a non-current tax liability of $58 million and $582 million, respectively. As of December 31, 2011, the balance primarily related to positions taken on various state returns, including accrued interest. As of December 31, 2010, the balance primarily related to taxable earnings for the period for which there are no NOLs available to offset for financial statement purposes.
The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense. During the year ended December 31, 2011, the Company recognized a benefit of $32 million in interest and penalties due to the IRS settlement and accrued interest of $2 million. For the year ended December 31, 2010, the Company recognized $25 million in interest and penalties. As of December 31, 2011, and 2010, NRG had accrued interest and penalties related to these uncertain tax benefits of $12 million and $42 million, respectively.
Tax jurisdictions — NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Germany and Australia. The Company is no longer subject to U.S. federal income tax examinations for years prior to 2007. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company's significant foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2004.
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During 2011, the Company settled the Internal Revenue Service's audit examination for the years 2004 through 2006 and recognized a benefit of $633 million. The benefit is predominantly due to the recognition of previously uncertain tax benefits mainly composed of net operating losses of $536 million which had been classified as capital loss carryforwards for financial statement purposes. The Company continues to be under examination for various state jurisdictions for multiple years.
The following table reconciles the total amounts of uncertain tax benefits:
As of December 31, | |||||||
2011 | 2010 | ||||||
(In millions) | |||||||
Balance as of January 1 | $ | 663 | $ | 643 | |||
Increase due to current year positions | 12 | 27 | |||||
Decrease due to current year positions | (6 | ) | (15 | ) | |||
Increase due to prior year positions | 6 | 16 | |||||
Decrease due to prior year positions | (2 | ) | (7 | ) | |||
Decrease due to settlements and payments | (495 | ) | — | ||||
Decrease due to statute expirations | — | (1 | ) | ||||
Uncertain tax benefits as of December 31 | $ | 178 | $ | 663 |
Included in the balance at December 31, 2011, are $30 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductions. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash or use of net operating loss carryforwards to an earlier period.
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Note 20 — Stock-Based Compensation
Long-Term Incentive Plan, or LTIP
As of December 31, 2011, and 2010, a total of 22,000,000 shares of NRG common stock were authorized for issuance under the LTIP, subject to adjustments in the event of reorganization, recapitalization, stock split, reverse stock split, stock dividend, and a combination of shares, merger or similar change in NRG's structure or outstanding shares of common stock. There were 7,957,697 and 10,141,819 shares of common stock remaining available for grants under NRG's LTIP as of December 31, 2011, and 2010, respectively.
Non-Qualified Stock Options, or NQSOs
NQSOs granted under the LTIP typically have three or five-year graded vesting schedules beginning on the grant date and become exercisable at the end of the requisite service period. NRG recognizes compensation costs for NQSOs over the requisite service period for the entire award. The maximum contractual term is ten years for 3.0 million of NRG's outstanding NQSOs, and six years for the remaining 2.6 million NQSOs.
The following table summarizes the Company's NQSO activity and changes during the year:
Shares | Weighted Average Exercise Price | Weighted Average Remaining Contractual Term (In years) | Aggregate Intrinsic Value (In millions) | ||||||||||
(In whole) | |||||||||||||
Outstanding at December 31, 2010 | 5,079,399 | $ | 24.22 | 4 | $ | 8 | |||||||
Granted | 1,168,000 | 19.86 | |||||||||||
Forfeited | (564,433 | ) | 28.21 | ||||||||||
Exercised | (99,777 | ) | 22.28 | ||||||||||
Outstanding at December 31, 2011 | 5,583,189 | 22.93 | 4 | 7 | |||||||||
Exercisable at December 31, 2011 | 3,706,813 | 23.72 | 2 | 7 |
The following table summarizes the weighted average grant date fair value of options granted, the total intrinsic value of options exercised, and the cash received from the exercises of options:
Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions, except for weighted average) | |||||||||||
Weighted average grant date fair value per option granted | $ | 8.73 | $ | 10.22 | $ | 8.64 | |||||
Total intrinsic value of options exercised | 0.2 | 0.3 | 1.4 | ||||||||
Cash received from the exercise of options exercised | 2 | 2 | 2 |
The fair value of the Company's NQSOs is estimated on the date of grant using the Black-Scholes option-pricing model. Significant assumptions used in the fair value model with respect to the Company's NQSOs are summarized below:
Year Ended December 31, | ||||||
2011 | 2010 | 2009 | ||||
Expected volatility | 42.38%-42.57% | 41.28%-42.57% | 44.36%-48.29% | |||
Expected term (in years) | 6 | 6-6.5 | 4 | |||
Risk free rate | 1.42%-2.71% | 1.54%-3.01% | 1.43%-1.93% |
For the years ended December 31, 2011, 2010, and 2009, expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the stock option. Typically, the expected term for the Company's NQSOs is based on the simple average of the contractual term and vesting term. The Company uses this simplified method as it does not have sufficient historical exercise data to provide a reasonable basis upon which to estimate the expected term.
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Restricted Stock Units, or RSUs
Typically, RSUs granted under the Company's LTIP fully vest three years from the date of issuance. Fair value of the RSUs is based on the closing price of NRG common stock on the date of grant. The following table summarizes the Company's non-vested RSU awards and changes during the year:
Units | Weighted Average Grant-Date Fair Value per Unit | |||||
(In whole) | ||||||
Non-vested at December 31, 2010 | 1,439,839 | $ | 26.30 | |||
Granted | 1,186,900 | 21.22 | ||||
Forfeited | (182,880 | ) | 22.97 | |||
Vested | (101,344 | ) | 36.44 | |||
Non-vested at December 31, 2011 | 2,342,515 | 23.54 |
The total fair value of RSUs vested during the years ended December 31, 2011, 2010, and 2009, was $2 million, $9 million and $8 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2011, 2010, and 2009 was $21.22, $22.78, and $26.13, respectively.
Deferred Stock Units, or DSUs
DSUs represent the right of a participant to be paid one share of NRG common stock at the end of a deferral period established under the terms of the award. DSUs granted under the Company's LTIP are fully vested at the date of issuance. Fair value of the DSUs, which is based on the closing price of NRG common stock on the date of grant, is recorded as compensation expense in the period of grant.
The following table summarizes the Company's outstanding DSU awards and changes during the year:
Units | Weighted Average Grant-Date Fair Value per Unit | |||||
(In whole) | ||||||
Outstanding at December 31, 2010 | 334,721 | $ | 19.63 | |||
Granted | 53,896 | 24.31 | ||||
Conversions | (14,933 | ) | 25.41 | |||
Outstanding at December 31, 2011 | 373,684 | 20.07 |
The aggregate intrinsic values for DSUs outstanding as of December 31, 2011, 2010, and 2009 were approximately $8 million, $7 million, and $7 million respectively. The aggregate intrinsic values for DSUs converted to common stock for the years ended December 31, 2011, 2010, and 2009 were $0.4 million, $0.7 million and $0.5 million, respectively. The weighted average grant date fair value of DSUs granted during the years ended December 31, 2011, 2010, and 2009 was $24.31, $22.18 and $22.77, respectively.
Performance Units, or PUs
PUs granted under the Company's LTIP fully vest three years from the date of issuance. PUs granted prior to January 1, 2009, are paid out upon vesting if the closing price of NRG's common stock on the vesting date, or the Measurement Price, is equal to or greater than the Target Price. PUs granted after January 1, 2009, are paid out upon vesting if the Measurement Price is equal to or greater than Threshold Price. The Threshold Price, Target Price and Maximum Price are determined on the date of issuance. The payout for each PU will be equal to: (i) a pro-rata amount between 0.5 and 1 share of common stock, if the Measurement Price is equal to or greater than the target Threshold Price but less than the Target Price, for grants made after January 1, 2009; (ii) one share of common stock, if the Measurement Price equals the Target Price; (iii) a pro-rata amount between one and two shares of common stock, if the Measurement Price is greater than the Target Price but less than the Maximum Price; and (iv) two shares of common stock, if the Measurement Price is equal to, or greater than, the Maximum Price.
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The following table summarizes the Company's non-vested PU awards and changes during the year:
Outstanding Units | Weighted Average Grant-Date Fair Value per Unit | |||||
(In whole) | ||||||
Non-vested at December 31, 2010 | 819,000 | $ | 23.71 | |||
Granted | 504,800 | 20.80 | ||||
Forfeited | (284,300 | ) | 24.98 | |||
Non-vested at December 31, 2011 | 1,039,500 | 21.95 |
The weighted average grant date fair value of PUs granted during the years ended December 31, 2011, 2010, and 2009 was $20.80, $22.70, and $22.91, respectively.
The fair value of PUs is estimated on the date of grant using a Monte Carlo simulation model and expensed over the service period, which equals the vesting period. Significant assumptions used in the fair value model with respect to the Company's PUs are summarized below:
2011 | 2010 | 2009 | ||||
Expected volatility | 46.96%-53.15% | 44.77%-53.81% | 48.48%-53.00% | |||
Expected term (in years) | 3 | 3-5 | 3 | |||
Risk free rate | 0.50%-1.41% | 0.59%-1.66% | 1.14%-1.48% |
For the years ended December 31, 2011, 2010, and 2009, expected volatility is calculated based on NRG's historical stock price volatility data over the period commensurate with the expected term of the PU, which equals the vesting period.
Supplemental Information
The following table summarizes NRG's total compensation expense recognized for the years presented as well as total non-vested compensation costs not yet recognized and the period over which this expense is expected to be recognized as of December 31, 2011, for each of the four types of awards issued under the Company's LTIP. Minimum tax withholdings of $1 million, $4 million, and $3 million during 2011, 2010, and 2009, respectively, are reflected as a reduction to Additional Paid-in Capital on the Company's statement of financial position, and are reflected as operating activities on the Company's statement of cash flows.
Non-vested Compensation Cost | |||||||||||||||||||
Compensation Expense | Unrecognized Total Cost | Weighted Average Recognition Period Remaining (In years) | |||||||||||||||||
Year Ended December 31 | As of December 31 | ||||||||||||||||||
Award | 2011 | 2010 | 2009 | 2011 | 2011 | ||||||||||||||
(In millions, except weighted average data) | |||||||||||||||||||
NQSOs | $ | 8 | $ | 8 | $ | 9 | $ | 10 | $ | 0.6 | |||||||||
RSUs | 12 | 15 | 11 | 28 | 1.9 | ||||||||||||||
DSUs | 2 | 1 | 1 | — | — | ||||||||||||||
PUs | 5 | 6 | 5 | 10 | 1.4 | ||||||||||||||
Total | $ | 27 | $ | 30 | $ | 26 | $ | 48 | |||||||||||
Tax benefit recognized | $ | 1 | $ | 2 | $ | 4 |
Other Compensation Arrangements
NRG also sponsored certain cash-settled equity award programs, under which employees are eligible to receive future cash compensation upon fulfillment of the vesting criteria for the particular program. The aggregate compensation expense for these arrangements was $0.1 million, $1 million, and $2 million for the years ended December 31, 2011, 2010, and 2009, respectively.
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Note 21 — Related Party Transactions
The following table summarizes NRG's material related party transactions with affiliates that are included in the Company's operating revenues, operating costs and other income and expense:
Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions) | |||||||||||
Revenues from Related Parties Included in Operating Revenues | |||||||||||
MIBRAG (a) | $ | — | $ | — | $ | 2 | |||||
Gladstone | 7 | 3 | 2 | ||||||||
GenConn (b)(c) | 3 | 5 | 7 | ||||||||
Total | $ | 10 | $ | 8 | $ | 11 | |||||
Expenses from Related Parties Included in Cost of Operations | |||||||||||
Cost of purchased coal — MIBRAG (a) | $ | — | $ | — | $ | 43 | |||||
Interest income from Related Parties Included in Other Income and Expense | |||||||||||
GenConn (b)(c) | 1 | 3 | 2 | ||||||||
Kraftwerke Schkopau GBR | 4 | 4 | 4 | ||||||||
Total | $ | 5 | $ | 7 | $ | 6 |
(a) | The period in 2009 is from January 1, 2009, to June 10, 2009. |
(b) | The period in 2009 is from April 1, 2009, to December 31, 2009. |
(c) | The period in 2011 is from January 1, 2011 to June 30, 2011. |
Gladstone — NRG provides services to Gladstone, an equity method investment, under an operation and maintenance, or O&M, agreement. Fees for services under this contract primarily include recovery of NRG's costs of operating the plant as approved in the annual budget, as well as a base monthly fee.
GenConn — Under a construction management agreement, or CMA, with GenConn , NRG has received fees for management, design and construction services. The construction at GenConn was completed in June 2011. In addition, NRG entered into a loan agreement with GenConn during 2009, pursuant to which it received interest income, which was converted into equity during 2011. See further discussion in Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities.
MIBRAG — Prior to NRG's sale of its 50% ownership in MIBRAG on June 10, 2009, NRG rendered technical consulting services to MIBRAG under a consulting agreement and had entered into long-term coal purchase agreements with MIBRAG to supply coal to Schkopau. Subsequent to the sale, MIBRAG is no longer a related party.
Kraftwerke Schkopau GBR — A subsidiary of NRG, Saale Energie GmbH, has entered into a loan agreement with Kraftwerke Schkopau GBR, a partnership between Saale and E.ON Kraftwerke GmbH, pursuant to which NRG receives interest income. See further discussion in Note 9, Capital Leases and Notes Receivable.
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Note 22 — Commitments and Contingencies
Operating Lease Commitments
NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses, expiring on various dates through 2040. NRG also has certain tolling arrangements to purchase power which qualifies as operating leases. Certain operating lease agreements over their lease term include provisions such as scheduled rent increases, leasehold incentives, and rent concessions. The Company recognizes the effects of these scheduled rent increases, leasehold incentives, and rent concessions on a straight-line basis over the lease term unless another systematic and rational allocation basis is more representative of the time pattern in which the leased property is physically employed. Lease expense under operating leases was$81 million, $111 million, and $102 million for the years ended December 31, 2011, 2010, and 2009, respectively.
Future minimum lease commitments under operating leases for the years ending after December 31, 2011, are as follows:
Period | (In millions) | ||
2012 | $ | 67 | |
2013 | 63 | ||
2014 | 62 | ||
2015 | 57 | ||
2016 | 49 | ||
Thereafter | 280 | ||
Total | $ | 578 |
Coal, Gas and Transportation Commitments
NRG has entered into long-term contractual arrangements to procure fuel and transportation services for the Company's generation assets and for the years ended December 31, 2011, 2010, and 2009, the Company purchased $1.6 billion, $1.5 billion, and $1.4 billion, respectively, under such arrangements.
As of December 31, 2011, the Company's commitments under such outstanding agreements are estimated as follows:
Period | (In millions) | ||
2012 | $ | 891 | |
2013 | 130 | ||
2014 | 136 | ||
2015 | 103 | ||
2016 | 101 | ||
Thereafter | 484 | ||
Total (a) | $ | 1,845 |
(a) | Includes those coal transportation and lignite commitments for 2012 as no other nominations were made as of December 31, 2011. Natural gas nomination is through February 2016. |
Purchased Power Commitments
NRG has purchased power contracts of various quantities and durations that are not classified as derivative assets and liabilities and do not qualify as operating leases. These contracts are not included in the consolidated balance sheet as of December 31, 2011. Minimum purchase commitment obligations are as follows as of December 31, 2011:
Period | (In millions) | ||
2012 | $ | 37 | |
2013 | 21 | ||
2014 | 11 | ||
2015 | 9 | ||
2016 | 9 | ||
Thereafter | 9 | ||
Total (a) | $ | 96 |
(a) | As of December 31, 2011, the maximum remaining term under any individual purchased power contract is six years. |
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Lignite Contract with Texas Westmoreland Coal Co.
The lignite used to fuel the Texas region's Limestone facility is obtained from a surface mine, or the Jewett mine, adjacent to the Limestone facility under a long-term contract with Texas Westmoreland Coal Co., or TWCC. The contract is based on a cost-plus arrangement with incentives and penalties to ensure proper management of the mine. NRG has the flexibility to increase or decrease lignite purchases from the mine within certain ranges, including the ability to suspend or terminate lignite purchases with adequate notice. The mining period extends through 2018 with an option to further extend the mining period by two five-year intervals.
TWCC is responsible for performing ongoing reclamation activities at the mine until all lignite reserves have been produced. When production is completed at the mine, NRG will be responsible for final mine reclamation obligations. The Railroad Commission of Texas has imposed a bond obligation of $108 million on TWCC for the reclamation of this lignite mine. Pursuant to the contract with TWCC, NRG supports this obligation as follows: $50 million is guaranteed by NRG Energy, Inc., $32 million is supported by letters of credit posted by NRG, and NRG pays the cost of TWCC bonding the remaining $26 million. Additionally, NRG is required to provide additional performance assurance over TWCC's current bond obligations if required by the Railroad Commission of Texas.
First Lien Structure
NRG has granted first liens to certain counterparties on substantially all of the Company's assets to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of December 31, 2011, all hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis.
Nuclear Insurance
STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson Amendment to the Energy Policy Act of 2005, referred to as the Price-Anderson Act. As of December 31, 2011, the current liability limit per incident was $12.6 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be made at least once every five years with the most recent adjustment effective October 29, 2008. Under the Price-Anderson Act, owners of nuclear power plants in the U.S. are required to purchase primary insurance limits of $375 million for each operating site. In addition, the Price-Anderson Act requires an additional layer of protection through mandatory participation in a retrospective rating plan for power reactors resulting in an additional $12.2 billion in funds available for public liability claims. The current maximum assessment per incident, per reactor, is $117.5 million, payable at no more than $17.5 million per year. NRG would be responsible for 44% of the maximum assessment, or $7.7 million per year. In addition, the U.S. Congress retains the ability to impose additional financial requirements on the nuclear industry to pay liability claims that exceed $12.6 billion for a single incident. The liabilities of the co-owners of STP with respect to the retrospective premium assessments for nuclear liability insurance are joint and several.
STP purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Limited, or NEIL, an industry mutual insurance company, of which STP is a member. STP has purchased $2.75 billion in limits, the maximum available from NEIL. The upper $1 billion in limits (excess of the first $1.75 billion in limits) is a single limit blanket policy shared with the DC Cook and Diablo Canyon nuclear reactors, two reactors that have no affiliation with the Company. This shared limit is not subject to automatic reinstatement in the event of a loss. The NEIL policy covers both nuclear and non-nuclear property damage events, and includes coverage for 6 weeks of lost revenue following a property damage event, at a weekly indemnity limit of $3.5 million, subject to a 17 week waiting period. NRG also purchased an Accidental Outage policy from NEIL, which provides additional protection for lost revenue due to an insurable event. This coverage allows for reimbursement up to $3.5 million per week up to a maximum of $473.2 million, and is subject to a 23 week waiting period. Under the terms of the NEIL policies, member companies may be assessed up to 10 times their annual premium if the NEIL Board of Directors determines their surplus has been depleted due to the payment of property losses at any of the licensed reactors in a single policy year. NEIL requires that its members maintain an investment grade credit rating or insure their annual retrospective obligation by providing a financial guarantee, letter of credit, deposit premium, or an insurance policy. NRG has purchased an insurance policy from NEIL to guarantee the Company's obligation; however this insurance will only respond to retrospective premium adjustments assessed within 24 months after the policy term, whereas NEIL's Board of Directors can make such an adjustment up to 6 years after the policy expires.
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Contingencies
Set forth below is a description of the Company's material legal proceedings. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. Pursuant to the requirements of ASC 450, Contingencies and related guidance, NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
California Department of Water Resources
This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the Federal Energy Regulatory Commission, or FERC, abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC's review of the contracts at issue, the FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP's appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller's market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the U.S. Supreme Court affirmed the Ninth Circuit's decision agreeing that the case should be remanded to the FERC to clarify the FERC's 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008, decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008, decision; whether the Mobile-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Court's June 26, 2008, decision.
On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand and on January 28, 2009, WCP and the other seller-defendants filed their reply. At this time, the FERC has not acted on remand.
At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG's financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy's 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy.
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On January 14, 2010, the U.S. Supreme Court issued its decision in an unrelated proceeding involving the Mobile-Sierra doctrine that will affect the standard of review applied to the CDWR contract on remand before the FERC. In NRG Power Marketing v. Maine Public Utilities Commission, the Supreme Court held that the Mobile-Sierra presumption regarding the reasonableness of contract rates does not depend on the identity of the complainant who seeks a FERC investigation/refund.
Louisiana Generating, LLC
On February 11, 2009, the U.S. Department of Justice, or U.S. DOJ, acting at the request of the U.S. Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana Generating, LLC, or LaGen, in federal district court in the Middle District of Louisiana alleging violations of the Clean Air Act, or CAA, at the Big Cajun II power plant. This is the same matter for which Notices of Violation, or NOVs, were issued to LaGen on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990's, several years prior to NRG's acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing the best available control technology, or BACT, to control emissions of nitrogen oxides and/or sulfur dioxides. The relief sought in the complaint includes a request for an injunction to: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA's Prevention of Significant Deterioration program; (vi) award to the U.S. DOJ its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.
On April 27, 2009, LaGen filed an objection in the Cajun Electric Cooperative Power, Inc.'s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle District of Louisiana to seek to prevent the bankruptcy from closing. LaGen also filed a complaint, or adversary proceeding, in the same bankruptcy proceeding, seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric with respect to environmental liabilities arising prior to the acquisition; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for any of the violations alleged in the February 11, 2009, lawsuit to the extent that such claims are determined to have merit. On April 15, 2010, the bankruptcy court signed an order granting LaGen's stipulation of voluntary dismissal without prejudice of the adversary proceeding. The bankruptcy proceeding has since closed.
On August 24, 2009, LaGen filed a motion to dismiss this lawsuit, and on September 25, 2009, the U.S. DOJ filed its opposition to the motion. Thereafter, on February 18, 2010, the Louisiana Department of Environmental Quality, or LDEQ, filed a motion to intervene in the above lawsuit and a complaint against LaGen for alleged violations of Louisiana's Prevention of Significant Deterioration, or PSD, regulations and Louisiana's Title V operating permit program. LDEQ seeks substantially similar relief to that requested by the U.S. DOJ. On February 19, 2010, the district court granted LDEQ's motion to intervene. On April 26, 2010, LaGen filed a motion to dismiss the LDEQ complaint. On July 21, 2010, the motions to dismiss the U.S. DOJ and LDEQ complaints were argued to the district court. On August 20, 2010, the parties submitted proposed findings of fact and conclusions of law, and thereafter submitted additional briefing on emerging jurisprudence from other jurisdictions touching on the issues at stake in the lawsuit. On February 4, 2011, LaGen filed motions for summary judgment requesting that the court dismiss all of the U.S. DOJ's claims. Also on February 4, 2011, the U.S. DOJ filed three motions for partial summary judgment. Additional summary judgment briefing was filed by the parties on April 4, 2011. On November 2, 2011, the court heard oral argument on three motions for summary judgment. On December 1, 2011, the court issued an order denying two of LaGen's motions for summary judgment addressing potential legal defenses to CAA liability. In the same Order, the court also granted, in part, the U.S. DOJ's motion for summary judgment on its successor liability theory. The court held that LaGen could be found to have assumed liability for alleged PSD violations under the terms of the agreement through which LaGen acquired Big Cajun II in 2000, but ruled that the facts necessary to determine whether any such liabilities were actually assumed must be determined at a liability-phase trial, if necessary. In its December 1, 2011, decision, the court also ruled that any potential civil penalties would not be available for the periods prior to the five year period preceding the filing of the lawsuit on February 11, 2009.
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Three additional motions for summary judgment and multiple motions in limine, including motions that could result in dismissal of the governments' claims before trial if resolved in LaGen's favor, remain pending before the court, with some of these motions set to be argued on March 21, 2012. On January 17, 2012, LaGen filed a demand for a jury trial. On January 20, 2012, the court scheduled a liability-phase trial for October 15, 2012, should the case proceed to that stage, and a remedy-phase trial set to occur at a later date to be determined in the event of an adverse decision in a liability-phase trial. Because of the inherent uncertainty of litigation, including the fact that no determination of liability has yet been made by the Court, NRG cannot predict the impact, at this time, that this matter may have on the Company's business, results of operations, financial position, or cash flows.
In a related matter, soon after the filing of the above referenced U.S. DOJ lawsuit, LaGen sought insurance coverage from its insurance carrier, Illinois Union Insurance Company, or ILU. ILU denied coverage and thereafter LaGen filed this lawsuit (which was consolidated with a prior suit filed by ILU) seeking a declaration that ILU must provide coverage to LaGen for the defense costs incurred in defending the U.S. DOJ lawsuit. LaGen and ILU both filed motions for summary judgment and on January 30, 2012, the court issued an order granting LaGen's motion finding that ILU has a duty to defend LaGen.
Excess Mitigation Credits
From January 2002 to April 2005, CenterPoint Energy applied excess mitigation credits, or EMCs, to its monthly charges to retail electric providers as ordered by the PUCT. The PUCT imposed these credits to facilitate the transition to competition in Texas, which had the effect of lowering the retail electric providers' monthly charges payable to CenterPoint Energy. As indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008, CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from RRI Energy, Inc. (formerly Reliant Energy, Inc.), totaled $385 million for RERS's “Price to Beat” Customers. It is unclear what the actual number may be. “Price to Beat” was the rate RERS was required by state law to charge residential and small commercial customers that were transitioned to RERS from the incumbent integrated utility company commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004, CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers, including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on December 17, 2004. After an appeal to state district court, the court entered a final judgment on August 26, 2005, affirming the PUCT's order with regard to EMCs credited to RERS. Various parties filed appeals of that judgment, and on April 17, 2008, the Court of Appeals for the Third District reversed the lower court's decision ruling that CenterPoint Energy's stranded cost recovery should exclude only EMCs credited to RERS for its “Price to Beat” customers. On June 2, 2008, CenterPoint Energy's Petition for Review with the Supreme Court of Texas was accepted. Oral argument occurred on October 6, 2009, and on March 18, 2011, the Texas Supreme Court reversed the Court of Appeals, finding no basis for deducting EMCs credited to RERS. Motions for rehearing were filed on May 4, 2011. On June 10, 2011, the Texas Supreme Court denied all motions for rehearing, thereby ending the matter.
In November 2008, CenterPoint Energy and Reliant Energy Inc., or REI, on behalf of itself and affiliates including RERS, agreed to suspend unexpired deadlines, if any, related to limitations periods that might exist for possible claims against REI and its affiliates if CenterPoint Energy is ultimately not allowed to include in its stranded cost calculation those EMCs previously credited to RERS. The agreed upon suspension of unexpired deadlines ceased on August 29, 2011. NRG believes that any possible future CenterPoint Energy claim against RERS for EMCs credited to RERS would lack legal merit. No such claim has been filed.
Wise v. Energy Plus Holdings, LLC
On October 18, 2011, plaintiff filed a purported class action lawsuit on behalf of New York consumers against Energy Plus in the U.S. District Court for the Southern District of New York. Claiming statutory damages in excess of $5 million, the plaintiff alleges violations of New York business laws as well as unjust enrichment. Specifically, the plaintiff claims that Energy Plus misrepresents that its rates are competitive in the market; fails to disclose that its rates are substantially higher than those in the market and that Energy Plus has engaged in deceptive practices in its marketing of energy services. Plaintiff seeks that this matter be certified as a class action, with treble damages, interest, costs, attorneys fees, and any other relief that the court deems just and proper. On January 11, 2012, plaintiff filed an amended complaint in which they added another co-plaintiff, made additional claims as to how they became customers of Energy Plus and made some additional allegations as to alleged representations on the Energy Plus website. On February 1, 2012, Energy Plus filed a motion to dismiss the amended complaint. Oral argument on the motion to dismiss is scheduled to be heard on March 23, 2012.
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Note 23 — Regulatory Matters
NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and Retail Businesses.
In addition to the regulatory proceedings noted below, NRG and its subsidiaries are a party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
California — On May 4, 2010, in Southern California Edison Company v. FERC, the U.S. Court of Appeals for the D.C. Circuit vacated FERC's acceptance of station power rules for the CAISO market, and remanded the case for further proceedings at FERC. On August 30, 2010, FERC issued an Order on Remand effectively disclaiming jurisdiction over how the states impose retail station power charges. Due to reservation-of-rights language in the California utilities' state-jurisdictional station power tariffs, FERC's ruling arguably requires California generators to pay state-imposed retail charges back to the date of enrollment by the facilities in the CAISO's station period program (February 1, 2009, for the Company's Encina and El Segundo facilities; March 1, 2009, for the Company's Long Beach facility). On February 28, 2011, FERC issued an order denying rehearing. The Company, together with other generators, filed an appeal and briefing of the case is currently underway. On November 18, 2011, Southern California Edison Company filed with the California Public Utilities Commission, or CPUC, seeking authorization to begin charging generators station power charges, and to assess such charges retroactively, which the Company and other generators have challenged. The Company has filed a protest with the CPUC objecting to Southern California Edison's filing. The Company believes it has established an appropriate reserve.
Retail (Replacement Reserve) — On November 14, 2006, Constellation Energy Commodities Group, or Constellation, filed a complaint with the PUCT alleging that ERCOT misapplied the Replacement Reserve Settlement, or RPRS, Formula contained in the ERCOT protocols from April 10, 2006, through September 27, 2006. Specifically, Constellation disputed approximately $4 million in under-scheduling charges for capacity insufficiency asserting that ERCOT applied the wrong protocol. Retail Electric Providers, or REPS, other market participants, ERCOT, and PUCT staff opposed Constellation's complaint. On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied Constellation's complaint. On April 9, 2008, Constellation appealed the PUCT order to the Civil District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other. Under the PUCT ordered formula, Qualified Scheduling Entities, or QSEs, who under-scheduled capacity within any of ERCOT's four congestion zones were assessed under-scheduling charges which defrayed the costs incurred by ERCOT for RPRS that would otherwise be spread among all load-serving QSEs. Under the Court's decision, all RPRS costs would be assigned to all load-serving QSEs based upon their load ratio share without assessing any separate charge to those QSEs who under-scheduled capacity. If under-scheduling charges for capacity insufficient QSEs were not used to defray RPRS costs, REPS's share of the total RPRS costs allocated to QSEs would increase. On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas, thereby staying the effect of the trial court's decision. On October 6, 2010, the parties argued the appeal before the Court of Appeals for the Third District in Austin, Texas. On September 28, 2011, the Court of Appeals reversed the trial court decision, reinstating the PUCT's order, consistent with REPS' position. On January 13, 2012, Constellation filed a Petition for Review in the Supreme Court of Texas asking the Court to grant review of and reverse the Court of Appeals decision.
Retail (Midwest ISO SECA) - Green Mountain Energy previously provided competitive retail energy supply in the Midwest ISO region during the relevant period of January 1, 2002, to December 31, 2005. By order dated November 18, 2004, FERC eliminated certain regional through-and-out transmission rates charged by transmission owners in the regional electric grids operated by the Midwest Independent Transmission Systems Operator, Inc., or MISO, and PJM Interconnection, L.L.C., or PJM. In order to temporarily compensate the transmission owners for revenue lost as a result of the elimination of the through-and-out transmission rates, FERC also ordered MISO, PJM and their respective transmission owners to provide for the recovery of certain Seams Elimination Charge/Cost Adjustments/Assignments, or SECA, charges effective December 1, 2004, through March 31, 2006, based on usage during 2002 and 2003. The tariff amendments filed by MISO and the MISO transmission owners allocated certain SECA charges to various zones and sub-zones within MISO, including a sub-zone called the Green Mountain Energy Company Sub-zone. Over the last several years, there has been extensive litigation before FERC relating to these charges, seeking, among other things, to recover monies from Green Mountain Energy, and before the federal appellate courts. Green Mountain Energy has not paid any asserted SECA charges.
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On May 21, 2010, FERC issued two orders. In its Order on Rehearing, FERC denied all requests for rehearing of its past orders directing and accepting the SECA compliance filings of MISO, PJM, and the transmission owners. In its Order on Initial Decision, FERC: (1) affirmed an order by the Administrative Law Judge granting Green Mountain Energy partial summary judgment and holding Green Mountain Energy not liable for SECA charges for January - March 2006; and (2) reversed an August 2006 determination by the Administrative Law Judge that Green Mountain Energy could be held directly liable for some amount of SECA charges. The Order on Initial Decision also directed that the two RTOs and their respective transmission owners submit further compliance filings, which were filed on August 19, 2010. FERC has not yet ruled on those compliance filings.
With regard to the SECA charges that had been invoiced to Green Mountain Energy, FERC determined that most of those charges, approximately $22 million plus interest, were owed not by Green Mountain Energy but rather by BP Energy — one of Green Mountain Energy's suppliers during the period at issue. On August 19, 2010, the transmission owners and MISO made compliance filings in accordance with FERC's Orders allocating SECA charges to a BP Energy Sub-zone, and making no allocation to a Green Mountain Energy sub-zone. BP Energy has not asserted any contractual claims against Green Mountain Energy. The Company believes it has established an appropriate reserve.
On September 30, 2011, FERC issued orders denying BP Energy's request for rehearing of the May 2010 Order on Rehearing, denying all requests for rehearing of the Order on Initial Decision, and again determined that SECA charges were not owed by Green Mountain Energy. Numerous parties have sought judicial review of FERC's Order on Initial Decision, and BP Energy has sought judicial review of the May 2010 Order on Rehearing. These appeals have been consolidated with previous appeals of orders relating to the SECA before the U.S. Court of Appeals for the DC Circuit. Green Mountain Energy has been granted intervenor status in the consolidated appeals. A briefing schedule has not yet been set.
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Note 24 — Environmental Matters
NRG is subject to a wide range of environmental regulations across a broad number of jurisdictions in the development, ownership, construction and operation of domestic and international projects. These laws and regulations generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Environmental laws have become increasingly stringent and NRG expects this trend to continue. The electric generation industry will face new requirements to address air emissions, climate change, combustion byproducts and water use. In general, future laws and regulations are expected to require the addition of emission controls or other environmental quality equipment or the imposition of certain restrictions on the operations of the Company's facilities. NRG expects that future liability under, or compliance with, environmental requirements could have a material effect on the Company's operations or competitive position.
Environmental Capital Expenditures
Based on current rules, technology and plans as well as preliminary plans based on proposed rules, NRG has estimated that environmental capital expenditures from 2012 through 2016 to meet NRG's regulatory environmental commitments will be approximately $553 million. These costs are primarily associated with mercury controls to satisfy the Mercury and Air Toxics Standards, or MATS, on the Company's Big Cajun II, W.A. Parish and Limestone facilities and a number of intake modification projects across the fleet under state or proposed federal 316(b) rules. NRG continues to explore cost effective compliance alternatives to reduce costs. While this estimate reflects anticipated schedules and controls related to the proposed 316(b) Rule, the full impact on the scope and timing of environmental retrofits from any new or revised regulations cannot be determined until these rules are final. However, NRG believes it is positioned to meet more stringent environmental regulations through its planned capital expenditures, existing controls, and increasing generation from renewable resources.
NRG's current contracts with the Company's rural electric cooperative customers in the South Central region allow for recovery of a portion of the region's environmental capital costs incurred as the result of complying with any change in environmental law. Cost recoveries begin once the environmental equipment becomes operational and include a capital return. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects and the remaining duration of the contracts.
The U.S. EPA released the final Cross-State Air Pollution Rule, or CSAPR, on July 7, 2011, which was scheduled to replace the Clean Air Interstate Rule, or CAIR, on January 1, 2012. On December 30, 2011, the U.S. Court of Appeals for the D.C. Circuit stayed the rule pending resolution of the numerous petitions for judicial review. Under CSAPR, use of discounted Acid Rain SO2 and CAIR NOx allowances would be discontinued and replaced with completely distinct allowance programs. Acid Rain allowances would still be required on a 1:1 basis under the Acid Rain Program. Consequently, in the third quarter 2011, the Company recorded an impairment charge of $160 million on the Company's Acid Rain Program SO2 emission allowances, which were recorded as an intangible asset on the Company's balance sheet. The impairment charge reflects the write-off of the value of emission allowances in excess of those required for compliance with the Acid Rain Program.
Northeast Region
In January 2006, NRG's Indian River Operations, Inc. received a letter of informal notification from Delaware Department of Natural Resources and Environmental Control, or DNREC, stating that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself will require a further Remedial Investigation and Feasibility Study to determine the type and scope of any additional work required. Until the Remedial Investigation and Feasibility Study is approved, the Company is unable to predict the impact of any required remediation. On May 29, 2008, DNREC requested that NRG's Indian River Operations, Inc. participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment phase.
Pursuant to a consent order dated September 25, 2007, and amended July 21, 2010, between NRG and DNREC regarding the Indian River plant, NRG agreed to limit the emissions of NOx and SO2, and to mothball Unit 1. Unit 1 was mothballed as planned on May 1, 2011.
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South Central Region
On February 11, 2009, the U.S. DOJ acting at the request of the U.S. EPA commenced a lawsuit against LaGen in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to LaGen on February 15, 2005, and on December 8, 2006. Further discussion on this matter can be found in Note 22, Commitments and Contingencies - Louisiana Generating, LLC.
The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulation in the U.S. If such laws and regulations become more stringent, or new laws, interpretations or compliance policies apply and NRG's facilities are not exempt from coverage, the Company could be required to make modifications to further reduce potential environmental impacts. In general, the effect of such future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions or additional costs on the Company's operations.
Note 25 — Cash Flow Information
Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:
Year Ended December 31, | |||||||||||
2011 | 2010 | 2009 | |||||||||
(In millions) | |||||||||||
Interest paid, net of amount capitalized | $ | 642 | $ | 609 | $ | 587 | |||||
Income taxes paid (a) | 26 | 20 | 47 | ||||||||
Non-cash investing and financing activities: | |||||||||||
Additions to fixed assets for accrued capital expenditures | 292 | 393 | 44 | ||||||||
Decrease to fixed assets for accrued grants and related tax impact | (32 | ) | — | (132 | ) | ||||||
Decrease to 4.0% preferred stock from conversion to common stock | — | 149 | 257 | ||||||||
Decrease to notes receivable for equity conversion | 63 | 56 | — | ||||||||
Decrease to 5.75% preferred stock from conversion to common stock | — | — | 447 | ||||||||
(Increase)/decrease to treasury stock from the net impact of shares loaned to and returned by affiliates of CS | — | (160 | ) | 160 |
(a) | 2011, 2010, and 2009 income taxes paid are net of $8 million, $14 million, and $3 million, respectively, of income tax refunds received. |
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Note 26 — Guarantees
NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part of the Company's business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. The Company is also obligated with respect to customer deposits associated with the Retail Businesses. In some cases, NRG's maximum potential liability cannot be estimated, since the underlying agreements contain no limits on potential liability. In accordance with ASC 460, Guarantees, or ASC 460, NRG has estimated that the current fair value for issuing these guarantees was $4.5 million as of December 31, 2011, and the liability in this amount is included in the Company's non-current liabilities.
The following table summarizes the maximum potential exposures that can be estimated for NRG's guarantees, indemnities, and other contingent liabilities by maturity:
By Remaining Maturity at December 31, | |||||||||||||||||||||||
2011 | |||||||||||||||||||||||
Guarantees | Under 1 Year | 1-3 Years | 3-5 Years | Over 5 Years | Total | 2010 Total | |||||||||||||||||
(In millions) | |||||||||||||||||||||||
Letters of credit and surety bonds | $ | 1,562 | $ | 108 | $ | — | $ | — | $ | 1,670 | $ | 887 | |||||||||||
Asset sales guarantee obligations | 60 | — | 567 | 8 | 635 | 1,022 | |||||||||||||||||
Commercial sales arrangements | 91 | 100 | 91 | 1,123 | 1,405 | 1,285 | |||||||||||||||||
Other guarantees | 1 | — | — | 460 | 461 | 171 | |||||||||||||||||
Total guarantees | $ | 1,714 | $ | 208 | $ | 658 | $ | 1,591 | $ | 4,171 | $ | 3,365 |
Letters of credit and surety bonds — As of December 31, 2011, NRG and its consolidated subsidiaries were contingently obligated for a total of $1.7 billion under letters of credit and surety bonds. Most of these letters of credit and surety bonds are issued in support of the Company's obligations to perform under commodity agreements and in support of equity contribution requirements for solar projects in construction, as well as for financing or other arrangements. A majority of these letters of credit and surety bonds expire within one year of issuance, and it is typical for the Company to renew them on similar terms.
The material indemnities, within the scope of ASC 460, are as follows:
Asset purchases and divestitures — The purchase and sale agreements which govern NRG's asset or share investments and divestitures customarily contain guarantees and indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a change in tax laws. These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or estimate at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. NRG has no reason to believe that the Company currently has any material liability relating to such routine indemnification obligations.
Commercial sales arrangements — In connection with the purchase and sale of fuel, emission allowances and power generation products to and from third parties with respect to the operation of some of NRG's generation facilities in the United States, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments.
85
Other guarantees — NRG has issued guarantees of obligations that its subsidiaries may incur as a provision for environmental site remediation, payment of debt obligations, rail car leases, performance under purchase, EPC and operating and maintenance agreements. NRG also executed a guarantee with related parties for one of its subsidiary's obligations as construction manager under EPC contracts for the construction of the peaking power plant at GenConn's Middletown site. See Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities, for more information on this equity investment. The Company does not believe that it will be required to perform under these guarantees.
Other indemnities — Other indemnifications NRG has provided cover operational, tax, litigation and breaches of representations, warranties and covenants. NRG has also indemnified, on a routine basis in the ordinary course of business, consultants or other vendors who have provided services to the Company. NRG's maximum potential exposure under these indemnifications can range from a specified dollar amount to an indeterminate amount, depending on the nature of the transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be made or how they will be resolved. NRG does not have any reason to believe that the Company will be required to make any material payments under these indemnity provisions.
Because many of the guarantees and indemnities NRG issues to third parties and affiliates do not limit the amount or duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit the Company's liability exposure, it may not be able to estimate what the Company's liability would be, until a claim is made for payment or performance, due to the contingent nature of these contracts.
Note 27 — Jointly Owned Plants
Certain NRG subsidiaries own undivided interests in jointly-owned plants, as described below. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. NRG is responsible for its subsidiaries' share of operating costs and direct expenses and includes its proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of the Company's consolidated financial statements.
The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities:
As of December 31, 2011 | Ownership Interest | Property, Plant & Equipment | Accumulated Depreciation | Construction in Progress | ||||||||||
(In millions unless otherwise stated) | ||||||||||||||
South Texas Project Units 1 and 2, Bay City, TX | 44.00 | % | $ | 3,101 | $ | (980 | ) | $ | 9 | |||||
Big Cajun II Unit 3, New Roads, LA | 58.00 | % | 175 | (75 | ) | 10 | ||||||||
Cedar Bayou Unit 4, Baytown, TX | 50.00 | % | 213 | (27 | ) | 1 | ||||||||
Keystone, Shelocta, PA | 3.70 | % | 90 | (27 | ) | 1 | ||||||||
Conemaugh, New Florence, PA | 3.72 | % | 79 | (30 | ) | 3 |
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Note 28 — Unaudited Quarterly Financial Data
Summarized unaudited quarterly financial data is as follows:
Quarter Ended | |||||||||||||||
2011 | |||||||||||||||
December 31 | September 30 | June 30 | March 31 | ||||||||||||
(In millions, except per share data) | |||||||||||||||
Operating revenues | $ | 2,132 | $ | 2,674 | $ | 2,278 | $ | 1,995 | |||||||
Operating income | 9 | 43 | 269 | 314 | |||||||||||
Net (loss)/income attributable to NRG Energy, Inc. | $ | (109 | ) | $ | (55 | ) | $ | 621 | $ | (260 | ) | ||||
Weighted average number of common shares outstanding — basic | 229 | 240 | 243 | 247 | |||||||||||
Net (loss)/income per weighted average common share — basic | $ | (0.48 | ) | $ | (0.24 | ) | $ | 2.54 | $ | (1.06 | ) | ||||
Weighted average number of common shares outstanding — diluted | 229 | 240 | 244 | 247 | |||||||||||
Net (loss)/income per weighted average common share — diluted | $ | (0.48 | ) | $ | (0.24 | ) | $ | 2.53 | $ | (1.06 | ) |
Quarter Ended | |||||||||||||||
2010 | |||||||||||||||
December 31 | September 30 | June 30 | March 31 | ||||||||||||
(In millions, except per share data) | |||||||||||||||
Operating revenues | $ | 1,816 | $ | 2,685 | $ | 2,133 | $ | 2,215 | |||||||
Operating income | 152 | 454 | 444 | 258 | |||||||||||
Net (loss)/income attributable to NRG Energy, Inc. | $ | (15 | ) | $ | 223 | $ | 211 | $ | 58 | ||||||
Weighted average number of common shares outstanding — basic | 248 | 252 | 255 | 254 | |||||||||||
Net (loss)/income per weighted average common share — basic | $ | (0.07 | ) | $ | 0.88 | $ | 0.82 | $ | 0.22 | ||||||
Weighted average number of common shares outstanding — diluted | 248 | 253 | 256 | 257 | |||||||||||
Net (loss)/income per weighted average common share — diluted | $ | (0.07 | ) | $ | 0.87 | $ | 0.81 | $ | 0.22 |
87
Note 29 — Condensed Consolidating Financial Information
As of December 31, 2011, the Company had $1.1 billion of 7.375% Senior Notes due 2017, $1.2 billion of 7.625% Senior Notes due 2018, $700 million of 8.50% Senior Notes due 2019, $800 million of 7.625%Senior Notes due 2019, $1.1 billion of 8.25% Senior Notes due 2020, and $1.2 billion of 7.875% Senior Notes due 2021. These notes are guaranteed by certain of NRG's current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of December 31, 2011:
Arthur Kill Power LLC | NEO Power Services Inc. | NRG Retail LLC |
Astoria Gas Turbine Power LLC | New Genco GP, LLC | NRG Rockford Acquisition LLC |
Cabrillo Power I LLC | Norwalk Power LLC | NRG Saguaro Operations Inc. |
Cabrillo Power II LLC | NRG Affiliate Services Inc. | NRG Services Corporation |
Carbon Management Solutions LLC | NRG Artesian Energy LLC | NRG SimplySmart Solutions LLC |
Clean Edge Energy LLC | NRG Arthur Kill Operations Inc. | NRG South Central Affiliate Services Inc. |
Conemaugh Power LLC | NRG Astoria Gas Turbine Operations Inc. | NRG South Central Generating LLC |
Connecticut Jet Power LLC | NRG Bayou Cove LLC | NRG South Central Operations Inc. |
Cottonwood Development LLC | NRG Cabrillo Power Operations Inc. | NRG South Texas LP |
Cottonwood Energy Company LP | NRG California Peaker Operations LLC | NRG Texas LLC |
Cottonwood Generating Partners I LLC | NRG Cedar Bayou Development Company, LLC | NRG Texas C&I Supply LLC |
Cottonwood Generating Partners II LLC | NRG Connecticut Affiliate Services Inc. | NRG Texas Holding Inc. |
Cottonwood Generating Partners III LLC | NRG Construction LLC | NRG Texas Power LLC |
Cottonwood Technology Partners LP | NRG Development Company Inc. | NRG West Coast LLC |
Devon Power LLC | NRG Devon Operations Inc. | NRG Western Affiliate Services Inc. |
Dunkirk Power LLC | NRG Dunkirk Operations Inc. | O'Brien Cogeneration, Inc. II |
Eastern Sierra Energy Company | NRG El Segundo Operations Inc. | ONSITE Energy, Inc. |
Elbow Creek Wind Project LLC | NRG Energy Labor Services LLC | Oswego Harbor Power LLC |
Energy Plus Holdings LLC | NRG Energy Services Group LLC | Pennywise Power LLC |
Energy Plus Natural Gas LLC | NRG Energy Services LLC | RE Retail Receivable LLC |
El Segundo Power LLC | NRG Generation Holdings Inc. | Reliant Energy Northeast LLC |
El Segundo Power II, LLC | NRG Huntley Operations Inc. | Reliant Energy Power Supply LLC |
Energy Protection Insurance Company | NRG Ilion Limited Partnership | Reliant Energy Retail Holdings LLC |
GCP Funding Company LLC | NRG Ilion LP LLC | Reliant Energy Retail Services LLC |
Green Mountain Energy Company | NRG International LLC | Reliant Energy Texas Retail LLC |
Huntley Power LLC | NRG Maintenance Services LLC | RERH Holdings LLC |
Independence Energy Alliance LLC | NRG Mextrans Inc. | Saguaro Power LLC |
Independence Energy Group LLC | NRG MidAtlantic Affiliate Services Inc. | Somerset Operations Inc. |
Independence Energy Natural Gas LLC | NRG Middletown Operations Inc. | Somerset Power LLC |
Indian River Operations Inc. | NRG Montville Operations Inc. | Texas Genco Financing Corp. |
Indian River Power LLC | NRG New Jersey Energy Sales LLC | Texas Genco GP, LLC |
Keystone Power LLC | NRG New Roads Holdings LLC | Texas Genco Holdings, Inc. |
Langford Wind Power, LLC | NRG North Central Operations Inc. | Texas Genco LP, LLC |
Louisiana Generating LLC | NRG Northeast Affiliate Services Inc. | Texas Genco Operating Services LLC |
Meriden Gas Turbines LLC | NRG Norwalk Harbor Operations Inc. | Texas Genco Services, LP |
Middletown Power LLC | NRG Operating Services, Inc. | Vienna Operations, Inc. |
Montville Power LLC | NRG Oswego Harbor Power Operations Inc. | Vienna Power LLC |
NEO Corporation | NRG PacGen Inc. | WCP (Generation) Holdings LLC |
NEO Freehold-Gen LLC | NRG Power Marketing LLC | West Coast Power LLC |
88
The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries. NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under the Company's Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, there may be restrictions for certain non-guarantor subsidiaries.
The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the Securities and Exchange Commission's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.
89
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2011
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. (Note Issuer) | Eliminations (a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
Operating Revenues | |||||||||||||||||||
Total operating revenues | $ | 8,730 | $ | 381 | $ | — | $ | (32 | ) | $ | 9,079 | ||||||||
Operating Costs and Expenses | |||||||||||||||||||
Cost of operations | 6,430 | 266 | — | (21 | ) | 6,675 | |||||||||||||
Depreciation and amortization | 843 | 40 | 13 | — | 896 | ||||||||||||||
Impairment charge on emission allowances | 160 | — | — | — | 160 | ||||||||||||||
Selling, general and administrative | 393 | 27 | 252 | (4 | ) | 668 | |||||||||||||
Development costs | — | (1 | ) | 46 | — | 45 | |||||||||||||
Total operating costs and expenses | 7,826 | 332 | 311 | (25 | ) | 8,444 | |||||||||||||
Operating Income/(Loss) | 904 | 49 | (311 | ) | (7 | ) | 635 | ||||||||||||
Other Income/(Expense) | |||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 24 | (7 | ) | 593 | (610 | ) | — | ||||||||||||
Equity in earnings of unconsolidated affiliates | 10 | 25 | — | — | 35 | ||||||||||||||
Impairment charge on investment | (495 | ) | — | — | — | (495 | ) | ||||||||||||
Other income, net | 2 | 13 | 4 | — | 19 | ||||||||||||||
Loss on debt extinguishment and refinancing | — | — | (175 | ) | — | (175 | ) | ||||||||||||
Interest expense | (59 | ) | (56 | ) | (550 | ) | — | (665 | ) | ||||||||||
Total other expense | (518 | ) | (25 | ) | (128 | ) | (610 | ) | (1,281 | ) | |||||||||
Income/(Loss) Before Income Taxes | 386 | 24 | (439 | ) | (617 | ) | (646 | ) | |||||||||||
Income tax (benefit)/expense | (214 | ) | 7 | (636 | ) | — | (843 | ) | |||||||||||
Net Income/(Loss) attributable to NRG Energy, Inc. | $ | 600 | $ | 17 | $ | 197 | $ | (617 | ) | $ | 197 |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
90
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the Year Ended December 31, 2011
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. (Note Issuer) | Eliminations(a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
Net Income/(Loss) | $ | 600 | $ | 17 | $ | 197 | $ | (617 | ) | $ | 197 | ||||||||
Other comprehensive (loss)/income, net of tax | |||||||||||||||||||
Unrealized (loss)/gain on derivatives, net | (303 | ) | (27 | ) | (345 | ) | 366 | (309 | ) | ||||||||||
Foreign currency translation adjustments, net | — | (2 | ) | — | — | (2 | ) | ||||||||||||
Available-for-sale securities, net | — | — | (1 | ) | — | (1 | ) | ||||||||||||
Defined benefit plan, net | (34 | ) | — | (12 | ) | — | (46 | ) | |||||||||||
Other comprehensive (loss)/income | (337 | ) | (29 | ) | (358 | ) | 366 | (358 | ) | ||||||||||
Comprehensive income/(loss) attributable to NRG Energy, Inc. | 263 | (12 | ) | (161 | ) | (251 | ) | (161 | ) | ||||||||||
Dividends for preferred shares | — | — | 9 | — | 9 | ||||||||||||||
Comprehensive income/(loss) available for common stockholders | $ | 263 | $ | (12 | ) | $ | (170 | ) | $ | (251 | ) | $ | (170 | ) |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
91
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2011
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. | Eliminations (a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
ASSETS | |||||||||||||||||||
Current Assets | |||||||||||||||||||
Cash and cash equivalents | $ | 44 | $ | 85 | $ | 976 | $ | — | $ | 1,105 | |||||||||
Funds deposited by counterparties | 258 | — | — | — | 258 | ||||||||||||||
Restricted cash | 8 | 231 | 53 | — | 292 | ||||||||||||||
Accounts receivable-trade, net | 789 | 45 | — | — | 834 | ||||||||||||||
Inventory | 300 | 8 | — | — | 308 | ||||||||||||||
Derivative instruments | 4,222 | — | — | (6 | ) | 4,216 | |||||||||||||
Cash collateral paid in support of energy risk management activities | 311 | — | — | — | 311 | ||||||||||||||
Prepayments and other current assets | 1,229 | 28 | (983 | ) | (1 | ) | 273 | ||||||||||||
Total current assets | 7,161 | 397 | 46 | (7 | ) | 7,597 | |||||||||||||
Net Property, Plant and Equipment | 10,456 | 3,116 | 67 | (18 | ) | 13,621 | |||||||||||||
Other Assets | |||||||||||||||||||
Investment in subsidiaries | 225 | 491 | 16,169 | (16,885 | ) | — | |||||||||||||
Equity investments in affiliates | 33 | 607 | — | — | 640 | ||||||||||||||
Capital leases and notes receivable, less current portion | 1 | 341 | 172 | (172 | ) | 342 | |||||||||||||
Goodwill | 1,886 | — | — | — | 1,886 | ||||||||||||||
Intangible assets, net | 1,340 | 84 | 33 | (38 | ) | 1,419 | |||||||||||||
Nuclear decommissioning trust fund | 424 | — | — | — | 424 | ||||||||||||||
Derivative instruments | 450 | — | — | — | 450 | ||||||||||||||
Other non-current assets | 55 | 72 | 209 | — | 336 | ||||||||||||||
Total other assets | 4,414 | 1,595 | 16,583 | (17,095 | ) | 5,497 | |||||||||||||
Total Assets | $ | 22,031 | $ | 5,108 | $ | 16,696 | $ | (17,120 | ) | $ | 26,715 | ||||||||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||||||||||||||
Current Liabilities | |||||||||||||||||||
Current portion of long-term debt and capital leases | $ | — | $ | 72 | $ | 15 | $ | — | $ | 87 | |||||||||
Accounts payable | (407 | ) | 122 | 1,093 | — | 808 | |||||||||||||
Derivative instruments | 3,712 | 23 | 22 | (6 | ) | 3,751 | |||||||||||||
Deferred income taxes | 534 | (51 | ) | (356 | ) | — | 127 | ||||||||||||
Cash collateral received in support of energy risk management activities | 258 | — | — | — | 258 | ||||||||||||||
Accrued expenses and other current liabilities | 371 | 23 | 247 | (1 | ) | 640 | |||||||||||||
Total current liabilities | 4,468 | 189 | 1,021 | (7 | ) | 5,671 | |||||||||||||
Other Liabilities | |||||||||||||||||||
Long-term debt and capital leases | 264 | 1,999 | 7,654 | (172 | ) | 9,745 | |||||||||||||
Nuclear decommissioning reserve | 335 | — | — | — | 335 | ||||||||||||||
Nuclear decommissioning trust liability | 254 | — | — | — | 254 | ||||||||||||||
Postretirement and other benefit obligations | 367 | — | 33 | — | 400 | ||||||||||||||
Deferred income taxes | 950 | 273 | 166 | — | 1,389 | ||||||||||||||
Derivative instruments | 394 | 66 | 4 | — | 464 | ||||||||||||||
Out-of-market commodity contracts | 208 | 6 | — | (31 | ) | 183 | |||||||||||||
Other non-current liabilities | 177 | 96 | 83 | — | 356 | ||||||||||||||
Total non-current liabilities | 2,949 | 2,440 | 7,940 | (203 | ) | 13,126 | |||||||||||||
Total liabilities | 7,417 | 2,629 | 8,961 | (210 | ) | 18,797 | |||||||||||||
3.625% Preferred Stock | — | — | 249 | — | 249 | ||||||||||||||
Stockholders' Equity | 14,614 | 2,479 | 7,486 | (16,910 | ) | 7,669 | |||||||||||||
Total Liabilities and Stockholders' Equity | $ | 22,031 | $ | 5,108 | $ | 16,696 | $ | (17,120 | ) | $ | 26,715 |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2011
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. | Eliminations (a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
Cash Flows from Operating Activities | |||||||||||||||||||
Net income | $ | 600 | $ | 17 | $ | 197 | $ | (617 | ) | $ | 197 | ||||||||
Adjustments to reconcile net income to net cash provided/(used) by operating activities: | |||||||||||||||||||
Distributions and equity in earnings of unconsolidated affiliates and consolidated subsidiaries | (11 | ) | 3 | 776 | (759 | ) | 9 | ||||||||||||
Depreciation and amortization | 843 | 40 | 13 | — | 896 | ||||||||||||||
Provision for bad debts | 59 | — | — | — | 59 | ||||||||||||||
Amortization of nuclear fuel | 39 | — | — | — | 39 | ||||||||||||||
Amortization of financing costs and debt discounts/premiums | — | 6 | 26 | — | 32 | ||||||||||||||
Loss on debt extinguishment | — | — | 58 | — | 58 | ||||||||||||||
Amortization of intangibles and out-of-market contracts. | 166 | 1 | — | — | 167 | ||||||||||||||
Changes in deferred income taxes and liability for uncertain tax benefits | (214 | ) | 7 | (652 | ) | — | (859 | ) | |||||||||||
Changes in nuclear decommissioning liability | 20 | — | — | — | 20 | ||||||||||||||
Changes in derivative instruments | (137 | ) | (1 | ) | — | — | (138 | ) | |||||||||||
Impairment charges and asset write downs | 648 | 9 | — | — | 657 | ||||||||||||||
Loss on disposals and sales of assets | 13 | 1 | — | — | 14 | ||||||||||||||
Amortization of unearned equity compensation | — | — | 28 | — | 28 | ||||||||||||||
Other assets and liabilities | (1,405 | ) | 211 | 1,174 | 7 | (13 | ) | ||||||||||||
Net Cash Provided/(Used) by Operating Activities | 621 | 294 | 1,620 | (1,369 | ) | 1,166 | |||||||||||||
Cash Flows from Investing Activities | |||||||||||||||||||
Intercompany loans to subsidiaries | 796 | — | 287 | (1,083 | ) | — | |||||||||||||
Investment in Subsidiaries | — | (1,300 | ) | — | 1,300 | — | |||||||||||||
Acquisition of business, net of cash acquired | — | (115 | ) | (262 | ) | — | (377 | ) | |||||||||||
Capital expenditures | (383 | ) | (1,882 | ) | (45 | ) | — | (2,310 | ) | ||||||||||
Increase in restricted cash, net | (5 | ) | (29 | ) | (1 | ) | — | (35 | ) | ||||||||||
Increase in restricted cash - U.S. DOE projects | — | (162 | ) | (53 | ) | — | (215 | ) | |||||||||||
Decrease in notes receivable | — | 12 | — | — | 12 | ||||||||||||||
Purchases of emission allowances, net of proceeds | (19 | ) | — | — | — | (19 | ) | ||||||||||||
Investments in nuclear decommissioning trust fund securities | (406 | ) | — | — | — | (406 | ) | ||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 385 | — | — | — | 385 | ||||||||||||||
Proceeds/(purchases) from sale of assets, net | 13 | (6 | ) | — | — | 7 | |||||||||||||
Equity investment in unconsolidated affiliates | (2 | ) | (64 | ) | — | — | (66 | ) | |||||||||||
Other | (2 | ) | (8 | ) | (13 | ) | — | (23 | ) | ||||||||||
Net Cash Provided/(Used) by Investing Activities | 377 | (3,554 | ) | (87 | ) | 217 | (3,047 | ) | |||||||||||
Cash Flows from Financing Activities | |||||||||||||||||||
(Payments)/proceeds from intercompany loans | (1,112 | ) | 825 | (796 | ) | 1,083 | — | ||||||||||||
Payment of dividends to preferred stockholders | — | — | (9 | ) | — | (9 | ) | ||||||||||||
Payments of intercompany dividends | (65 | ) | (4 | ) | — | 69 | — | ||||||||||||
Payment for treasury stock | — | — | (430 | ) | — | (430 | ) | ||||||||||||
Net payments to settle acquired derivatives that include financing elements | (83 | ) | — | — | — | (83 | ) | ||||||||||||
Proceeds from issuance of long-term debt | 138 | 1,290 | 4,796 | — | 6,224 | ||||||||||||||
Decrease in restricted cash supporting funded letter of credit facility | — | 1,300 | — | — | 1,300 | ||||||||||||||
Payment for settlement of funded letter of credit | — | — | (1,300 | ) | — | (1,300 | ) | ||||||||||||
Cash proceeds from noncontrolling interest in subsidiaries | — | 29 | — | — | 29 | ||||||||||||||
Proceeds from issuance of common stock | — | — | 2 | — | 2 | ||||||||||||||
Payment of debt issuance and hedging costs | — | (92 | ) | (115 | ) | — | (207 | ) | |||||||||||
Payments for short and long-term debt | — | (116 | ) | (5,377 | ) | — | (5,493 | ) | |||||||||||
Net Cash (Used)/Provided by Financing Activities | (1,122 | ) | 3,232 | (3,229 | ) | 1,152 | 33 | ||||||||||||
Effect of exchange rate changes on cash and cash equivalents | — | 2 | — | — | 2 | ||||||||||||||
Net Decrease in Cash and Cash Equivalents | (124 | ) | (26 | ) | (1,696 | ) | — | (1,846 | ) | ||||||||||
Cash and Cash Equivalents at Beginning of Period | 168 | 111 | 2,672 | — | 2,951 | ||||||||||||||
Cash and Cash Equivalents at End of Period | $ | 44 | $ | 85 | $ | 976 | $ | — | $ | 1,105 |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
93
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2010
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. (Note Issuer) | Eliminations (a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
Operating Revenues | |||||||||||||||||||
Total operating revenues | $ | 8,507 | $ | 374 | $ | — | $ | (32 | ) | $ | 8,849 | ||||||||
Operating Costs and Expenses | |||||||||||||||||||
Cost of operations | 5,849 | 256 | — | (32 | ) | 6,073 | |||||||||||||
Depreciation and amortization | 796 | 32 | 10 | — | 838 | ||||||||||||||
Selling, general and administrative | 325 | 12 | 261 | — | 598 | ||||||||||||||
Development costs | — | 10 | 45 | — | 55 | ||||||||||||||
Total operating costs and expenses | 6,970 | 310 | 316 | (32 | ) | 7,564 | |||||||||||||
Gain on sale of assets | — | — | 23 | — | 23 | ||||||||||||||
Operating Income/(Loss) | 1,537 | 64 | (293 | ) | — | 1,308 | |||||||||||||
Other Income/(Expense) | |||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 38 | (1 | ) | 979 | (1,016 | ) | — | ||||||||||||
Equity in earnings of unconsolidated affiliates | 6 | 38 | — | — | 44 | ||||||||||||||
Other income, net | 4 | 25 | 4 | — | 33 | ||||||||||||||
Loss on debt extinguishment and refinancing expense | — | — | (2 | ) | — | (2 | ) | ||||||||||||
Interest expense | (11 | ) | (52 | ) | (567 | ) | — | (630 | ) | ||||||||||
Total other income/(expense) | 37 | 10 | 414 | (1,016 | ) | (555 | ) | ||||||||||||
Income Before Income Taxes | 1,574 | 74 | 121 | (1,016 | ) | 753 | |||||||||||||
Income tax expense/(benefit) | 593 | 40 | (356 | ) | — | 277 | |||||||||||||
Net Income | 981 | 34 | 477 | (1,016 | ) | 476 | |||||||||||||
Less: Net loss attributable to noncontrolling interest | (1 | ) | — | — | — | (1 | ) | ||||||||||||
Net Income attributable to NRG Energy, Inc. | $ | 982 | $ | 34 | $ | 477 | $ | (1,016 | ) | $ | 477 |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
94
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the Year Ended December 31, 2010
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. (Note Issuer) | Eliminations(a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
Net Income/(Loss) | $ | 981 | $ | 34 | $ | 477 | $ | (1,016 | ) | $ | 476 | ||||||||
Other comprehensive income/(loss), net of tax | |||||||||||||||||||
Unrealized gain/(loss) on derivatives, net | 21 | (11 | ) | 10 | 15 | 35 | |||||||||||||
Foreign currency translation adjustments, net | — | (6 | ) | 3 | — | (3 | ) | ||||||||||||
Defined benefit plan, net | (19 | ) | — | 3 | — | (16 | ) | ||||||||||||
Other comprehensive income/(loss) | 2 | (17 | ) | 16 | 15 | 16 | |||||||||||||
Comprehensive income/(loss) | 983 | 17 | 493 | (1,001 | ) | 492 | |||||||||||||
Less: Comprehensive income attributable to noncontrolling interest | (1 | ) | — | — | — | (1 | ) | ||||||||||||
Comprehensive income/(loss) attributable to NRG Energy, Inc. | 984 | 17 | 493 | (1,001 | ) | 493 | |||||||||||||
Dividends for preferred shares | — | — | 9 | — | 9 | ||||||||||||||
Comprehensive income/(loss) available for common stockholders | $ | 984 | $ | 17 | $ | 484 | $ | (1,001 | ) | $ | 484 |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
95
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2010
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. | Eliminations (a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
ASSETS | |||||||||||||||||||
Current Assets | |||||||||||||||||||
Cash and cash equivalents | $ | 168 | $ | 111 | $ | 2,672 | $ | — | $ | 2,951 | |||||||||
Funds deposited by counterparties | 408 | — | — | — | 408 | ||||||||||||||
Restricted cash | 2 | 6 | — | — | 8 | ||||||||||||||
Accounts receivable-trade, net | 693 | 38 | 3 | — | 734 | ||||||||||||||
Inventory | 445 | 8 | — | — | 453 | ||||||||||||||
Derivative instruments | 1,964 | — | — | — | 1,964 | ||||||||||||||
Cash collateral paid in support of energy risk management activities | 321 | 2 | — | — | 323 | ||||||||||||||
Prepayments and other current assets | 112 | 60 | 1,313 | (1,189 | ) | 296 | |||||||||||||
Total current assets | 4,113 | 225 | 3,988 | (1,189 | ) | 7,137 | |||||||||||||
Net Property, Plant and Equipment | 10,816 | 1,515 | 186 | — | 12,517 | ||||||||||||||
Other Assets | |||||||||||||||||||
Investment in subsidiaries | 811 | 248 | 22,046 | (23,105 | ) | — | |||||||||||||
Equity investments in affiliates | 47 | 489 | — | — | 536 | ||||||||||||||
Notes receivable - affiliate and capital leases, less current portion | 6,507 | 380 | 2,130 | (8,633 | ) | 384 | |||||||||||||
Goodwill | 1,868 | — | — | — | 1,868 | ||||||||||||||
Intangible assets, net | 1,716 | 58 | 33 | (31 | ) | 1,776 | |||||||||||||
Nuclear decommissioning trust fund | 412 | — | — | — | 412 | ||||||||||||||
Derivative instruments | 758 | — | — | — | 758 | ||||||||||||||
Restricted cash supporting funded letter of credit facility | — | 1,300 | — | — | 1,300 | ||||||||||||||
Other non-current assets | 42 | 22 | 144 | — | 208 | ||||||||||||||
Total other assets | 12,161 | 2,497 | 24,353 | (31,769 | ) | 7,242 | |||||||||||||
Total Assets | $ | 27,090 | $ | 4,237 | $ | 28,527 | $ | (32,958 | ) | $ | 26,896 | ||||||||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||||||||||||||
Current Liabilities | |||||||||||||||||||
Current portion of long-term debt and capital leases | $ | 1,150 | $ | 223 | $ | 240 | $ | (1,150 | ) | $ | 463 | ||||||||
Accounts payable | (2,665 | ) | 229 | 3,219 | — | 783 | |||||||||||||
Derivative instruments | 1,665 | 3 | 17 | — | 1,685 | ||||||||||||||
Deferred income taxes | 515 | (51 | ) | (356 | ) | — | 108 | ||||||||||||
Cash collateral received in support of energy risk management activities | 408 | — | — | — | 408 | ||||||||||||||
Accrued expenses and other current liabilities | 399 | 34 | 379 | (39 | ) | 773 | |||||||||||||
Total current liabilities | 1,472 | 438 | 3,499 | (1,189 | ) | 4,220 | |||||||||||||
Other Liabilities | |||||||||||||||||||
Long-term debt and capital leases | 1,857 | 991 | 14,533 | (8,633 | ) | 8,748 | |||||||||||||
Funded letter of credit | — | — | 1,300 | — | 1,300 | ||||||||||||||
Nuclear decommissioning reserve | 317 | — | — | ��� | 317 | ||||||||||||||
Nuclear decommissioning trust liability | 272 | — | — | — | 272 | ||||||||||||||
Postretirement and other benefit obligations | 309 | (1 | ) | 14 | — | 322 | |||||||||||||
Deferred income taxes | 1,464 | 279 | 246 | — | 1,989 | ||||||||||||||
Derivative instruments | 294 | 34 | 37 | — | 365 | ||||||||||||||
Out-of-market commodity contracts | 248 | 6 | — | (31 | ) | 223 | |||||||||||||
Other non-current liabilities | 195 | 30 | 595 | — | 820 | ||||||||||||||
Total non-current liabilities | 4,956 | 1,339 | 16,725 | (8,664 | ) | 14,356 | |||||||||||||
Total liabilities | 6,428 | 1,777 | 20,224 | (9,853 | ) | 18,576 | |||||||||||||
3.625% Preferred Stock | — | — | 248 | — | 248 | ||||||||||||||
Stockholders' Equity | 20,662 | 2,460 | 8,055 | (23,105 | ) | 8,072 | |||||||||||||
Total Liabilities and Stockholders' Equity | $ | 27,090 | $ | 4,237 | $ | 28,527 | $ | (32,958 | ) | $ | 26,896 |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
96
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2010
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. | Eliminations (a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
Cash Flows from Operating Activities | |||||||||||||||||||
Net income | $ | 981 | $ | 34 | $ | 477 | $ | (1,016 | ) | $ | 476 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||||
Distributions and equity (earnings)/losses of unconsolidated affiliates and consolidated subsidiaries | 14 | (12 | ) | (914 | ) | 893 | (19 | ) | |||||||||||
Depreciation and amortization | 796 | 32 | 10 | — | 838 | ||||||||||||||
Provision for bad debts | 54 | — | — | — | 54 | ||||||||||||||
Amortization of nuclear fuel | 40 | — | — | — | 40 | ||||||||||||||
Amortization of financing costs and debt discounts/premiums | — | 6 | 26 | — | 32 | ||||||||||||||
Amortization of intangibles and out-of-market contracts. | 4 | — | — | — | 4 | ||||||||||||||
Impairment charges and asset write downs | 20 | — | 5 | — | 25 | ||||||||||||||
Changes in deferred income taxes and liability for uncertain tax benefits | 593 | 27 | (365 | ) | — | 255 | |||||||||||||
Changes in nuclear decommissioning liability | 34 | — | — | — | 34 | ||||||||||||||
Changes in derivatives | (113 | ) | (1 | ) | — | — | (114 | ) | |||||||||||
Loss/(gain) on disposals and sales of assets | 27 | — | (23 | ) | — | 4 | |||||||||||||
Amortization of unearned equity compensation | — | — | 30 | — | 30 | ||||||||||||||
Other assets and liabilities | (625 | ) | (187 | ) | 776 | — | (36 | ) | |||||||||||
Net Cash Provided/(Used) by Operating Activities | 1,825 | (101 | ) | 22 | (123 | ) | 1,623 | ||||||||||||
Cash Flows from Investing Activities | |||||||||||||||||||
Intercompany (loans to)/receipts from subsidiaries | (1,620 | ) | — | (195 | ) | 1,815 | — | ||||||||||||
Investment in subsidiaries | — | 1,727 | (1,727 | ) | — | — | |||||||||||||
Capital expenditures | (308 | ) | (323 | ) | (75 | ) | — | (706 | ) | ||||||||||
Acquisition of businesses, net of cash acquired | — | (142 | ) | (864 | ) | — | (1,006 | ) | |||||||||||
Decrease/(increase) in restricted cash, net | 1 | (5 | ) | — | — | (4 | ) | ||||||||||||
Decrease in notes receivable | — | 39 | — | — | 39 | ||||||||||||||
Purchases of emission allowances, net of proceeds | (34 | ) | — | — | — | (34 | ) | ||||||||||||
Investments in nuclear decommissioning trust fund securities | (341 | ) | — | — | — | (341 | ) | ||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 307 | — | — | — | 307 | ||||||||||||||
Proceeds from renewable energy grants | 84 | 18 | — | — | 102 | ||||||||||||||
Proceeds from sale of assets, net | 14 | — | 29 | — | 43 | ||||||||||||||
Equity investment in unconsolidated affiliate | 4 | (22 | ) | (5 | ) | — | (23 | ) | |||||||||||
Net Cash (Used)/Provided by Investing Activities | (1,893 | ) | 1,292 | (2,837 | ) | 1,815 | (1,623 | ) | |||||||||||
Cash Flows from Financing Activities | |||||||||||||||||||
Proceeds/(payments) from intercompany loans | 69 | 126 | 1,620 | (1,815 | ) | — | |||||||||||||
Payment of intercompany dividends | (58 | ) | (65 | ) | — | 123 | — | ||||||||||||
Payment of dividends to preferred stockholders | — | — | (9 | ) | — | (9 | ) | ||||||||||||
Net receipts from acquired derivatives that include financing elements | 137 | — | — | — | 137 | ||||||||||||||
Payment for treasury stock | — | — | (180 | ) | — | (180 | ) | ||||||||||||
Installment proceeds from sale of noncontrolling interest in subsidiary | — | 50 | — | — | 50 | ||||||||||||||
Proceeds from issuance of common stock | — | — | 2 | — | 2 | ||||||||||||||
Proceeds from issuance of long-term debt | 73 | 306 | 1,105 | — | 1,484 | ||||||||||||||
Proceeds from issuance of term loan for funded letter of credit facility | — | — | 1,300 | — | 1,300 | ||||||||||||||
Increase in restricted cash supporting funded letter of credit facility | — | (1,300 | ) | — | — | (1,300 | ) | ||||||||||||
Payment of debt issuance and hedging costs | (5 | ) | (9 | ) | (61 | ) | — | (75 | ) | ||||||||||
Payments of short and long-term debt | — | (304 | ) | (454 | ) | — | (758 | ) | |||||||||||
Net Cash Provided/(Used) by Financing Activities | 216 | (1,196 | ) | 3,323 | (1,692 | ) | 651 | ||||||||||||
Effect of exchange rate changes on cash and cash equivalents | — | (4 | ) | — | — | (4 | ) | ||||||||||||
Net Increase/(Decrease) in Cash and Cash Equivalents | 148 | (9 | ) | 508 | — | 647 | |||||||||||||
Cash and Cash Equivalents at Beginning of Period | 20 | 120 | 2,164 | — | 2,304 | ||||||||||||||
Cash and Cash Equivalents at End of Period | $ | 168 | $ | 111 | $ | 2,672 | $ | — | $ | 2,951 |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
97
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2009
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. | Eliminations (a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
Operating Revenues | |||||||||||||||||||
Total operating revenues | $ | 8,584 | $ | 357 | $ | 31 | $ | (20 | ) | $ | 8,952 | ||||||||
Operating Costs and Expenses | |||||||||||||||||||
Cost of operations | 5,110 | 236 | 1 | (24 | ) | 5,323 | |||||||||||||
Depreciation and amortization | 772 | 40 | 6 | — | 818 | ||||||||||||||
Selling, general and administrative | 266 | 11 | 273 | — | 550 | ||||||||||||||
Acquisition-related transaction and integration costs | — | — | 54 | — | 54 | ||||||||||||||
Development costs | 6 | 8 | 34 | — | 48 | ||||||||||||||
Total operating costs and expenses | 6,154 | 295 | 368 | (24 | ) | 6,793 | |||||||||||||
Operating Income/(Loss) | 2,430 | 62 | (337 | ) | 4 | 2,159 | |||||||||||||
Other Income/(Expense) | |||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 166 | — | 1,503 | (1,669 | ) | — | |||||||||||||
Equity in earnings of unconsolidated affiliates | 10 | 31 | — | — | 41 | ||||||||||||||
Gains on sales of equity method investments | — | 128 | — | — | 128 | ||||||||||||||
Other income/(expense), net | 9 | (16 | ) | 6 | (4 | ) | (5 | ) | |||||||||||
Refinancing expense | (1 | ) | — | (19 | ) | — | (20 | ) | |||||||||||
Interest expense | (106 | ) | (86 | ) | (442 | ) | — | (634 | ) | ||||||||||
Total other income/(expense) | 78 | 57 | 1,048 | (1,673 | ) | (490 | ) | ||||||||||||
Income Before Income Taxes | 2,508 | 119 | 711 | (1,669 | ) | 1,669 | |||||||||||||
Income tax expense/(benefit) | 964 | (5 | ) | (231 | ) | — | 728 | ||||||||||||
Net Income | 1,544 | 124 | 942 | (1,669 | ) | 941 | |||||||||||||
Less: Net loss attributable to noncontrolling interest | (1 | ) | — | — | — | (1 | ) | ||||||||||||
Net Income attributable to NRG Energy, Inc. | $ | 1,545 | $ | 124 | $ | 942 | $ | (1,669 | ) | $ | 942 |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
98
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the Year Ended December 31, 2009
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. (Note Issuer) | Eliminations(a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
Net Income/(Loss) | $ | 1,544 | $ | 124 | $ | 942 | $ | (1,669 | ) | $ | 941 | ||||||||
Other comprehensive income/(loss), net of tax | |||||||||||||||||||
Unrealized gain/(loss) on derivatives, net | 64 | 11 | 99 | (83 | ) | 91 | |||||||||||||
Foreign currency translation adjustments, net | — | 29 | 6 | — | 35 | ||||||||||||||
Reclassification adjustment for translation loss realized upon sale of MIBRAG, net | — | (22 | ) | — | — | (22 | ) | ||||||||||||
Available-for-sale securities, net | — | — | 4 | — | 4 | ||||||||||||||
Defined benefit plan, net | 1 | — | (3 | ) | — | (2 | ) | ||||||||||||
Other comprehensive income/(loss) | 65 | 18 | 106 | (83 | ) | 106 | |||||||||||||
Comprehensive income/(loss) | 1,609 | 142 | 1,048 | (1,752 | ) | 1,047 | |||||||||||||
Less: Comprehensive income attributable to noncontrolling interest | (1 | ) | — | — | — | (1 | ) | ||||||||||||
Comprehensive income/(loss) attributable to NRG Energy, Inc. | 1,610 | 142 | 1,048 | (1,752 | ) | 1,048 | |||||||||||||
Dividends for preferred shares | — | — | 33 | — | 33 | ||||||||||||||
Comprehensive income/(loss) available for common stockholders | $ | 1,610 | $ | 142 | $ | 1,015 | $ | (1,752 | ) | $ | 1,015 |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
99
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2009
Guarantor Subsidiaries | Non-Guarantor Subsidiaries | NRG Energy, Inc. | Elimin-ations (a) | Consolidated Balance | |||||||||||||||
(In millions) | |||||||||||||||||||
Cash Flows from Operating Activities | |||||||||||||||||||
Net income | $ | 1,544 | $ | 124 | $ | 942 | $ | (1,669 | ) | $ | 941 | ||||||||
Adjustments to reconcile net income to net cash provided/(used) by operating activities: | |||||||||||||||||||
Distributions and equity (earnings)/losses of unconsolidated affiliates | 154 | (31 | ) | (1,173 | ) | 1,009 | (41 | ) | |||||||||||
Depreciation and amortization | 772 | 40 | 6 | — | 818 | ||||||||||||||
Provision for bad debts | 61 | — | — | 61 | |||||||||||||||
Amortization of nuclear fuel | 36 | — | — | — | 36 | ||||||||||||||
Amortization of financing costs and debt discount/premiums | — | 13 | 31 | — | 44 | ||||||||||||||
Amortization of intangibles and out-of-market contracts | 153 | — | — | — | 153 | ||||||||||||||
Changes in deferred income taxes and liability for uncertain tax benefits | 934 | (16 | ) | (229 | ) | — | 689 | ||||||||||||
Change in nuclear decommissioning trust liability | 26 | — | — | — | 26 | ||||||||||||||
Changes in derivatives | (228 | ) | 3 | — | — | (225 | ) | ||||||||||||
Loss on disposals and sales of assets | 13 | — | — | — | 13 | ||||||||||||||
Gain on sales of equity method investments | — | (128 | ) | — | — | (128 | ) | ||||||||||||
Gain recognized on settlement of pre-existing relationship | — | — | (31 | ) | — | (31 | ) | ||||||||||||
Amortization of unearned equity compensation | — | — | 26 | — | 26 | ||||||||||||||
Other assets and liabilities | (640 | ) | 29 | 335 | — | (276 | ) | ||||||||||||
Net Cash Provided/(Used) by Operating Activities | 2,825 | 34 | (93 | ) | (660 | ) | 2,106 | ||||||||||||
Cash Flows from Investing Activities | |||||||||||||||||||
Intercompany (loans to)/receipts from subsidiaries | (1,755 | ) | — | 159 | 1,596 | — | |||||||||||||
Investment in subsidiaries | 200 | 60 | (260 | ) | — | — | |||||||||||||
Capital expenditures | (507 | ) | (197 | ) | (30 | ) | — | (734 | ) | ||||||||||
Acquisition of business, net of cash acquired | (72 | ) | (67 | ) | (288 | ) | — | (427 | ) | ||||||||||
Increase in restricted cash | 6 | 8 | — | — | 14 | ||||||||||||||
(Increase)/decrease in notes receivable | — | (58 | ) | 36 | — | (22 | ) | ||||||||||||
Purchases of emission allowances, net of proceeds | (38 | ) | — | — | — | (38 | ) | ||||||||||||
Investments in nuclear decommissioning trust fund securities | (305 | ) | — | — | — | (305 | ) | ||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 279 | — | — | — | 279 | ||||||||||||||
Proceeds from sale of assets, net | 6 | — | — | — | 6 | ||||||||||||||
Proceeds from sales of/(investments in) unconsolidated affiliates, net | — | 284 | (6 | ) | — | 278 | |||||||||||||
Other | — | — | (5 | ) | — | (5 | ) | ||||||||||||
Net Cash (Used)/Provided by Investing Activities | (2,186 | ) | 30 | (394 | ) | 1,596 | (954 | ) | |||||||||||
Cash Flows from Financing Activities | |||||||||||||||||||
(Payments)/proceeds from intercompany loans | (258 | ) | 99 | 1,755 | (1,596 | ) | — | ||||||||||||
Payment of intercompany dividends | (330 | ) | (330 | ) | — | 660 | — | ||||||||||||
Payment for dividends to preferred stockholders | — | — | (33 | ) | — | (33 | ) | ||||||||||||
Net payments to settle acquired derivatives including financing elements | (79 | ) | — | — | — | (79 | ) | ||||||||||||
Payment for treasury stock | — | — | (500 | ) | — | (500 | ) | ||||||||||||
Installment proceeds from sale of noncontrolling interest of subsidiary | — | 50 | — | — | 50 | ||||||||||||||
Proceeds from issuance of common stock, net of issuance costs | — | — | 2 | — | 2 | ||||||||||||||
Proceeds from issuance of long-term debt | 77 | 127 | 688 | — | 892 | ||||||||||||||
Payment of deferred debt issuance costs | (2 | ) | (3 | ) | (26 | ) | — | (31 | ) | ||||||||||
Payments of short and long-term debt | (25 | ) | (47 | ) | (572 | ) | — | (644 | ) | ||||||||||
Net Cash (Used)/Provided by Financing Activities | (617 | ) | (104 | ) | 1,314 | (936 | ) | (343 | ) | ||||||||||
Effect of exchange rate changes on cash and cash equivalents | — | 1 | — | — | 1 | ||||||||||||||
Net Increase/(Decrease) in Cash and Cash Equivalents | 22 | (39 | ) | 827 | — | 810 | |||||||||||||
Cash and Cash Equivalents at Beginning of Period | (2 | ) | 159 | 1,337 | — | 1,494 | |||||||||||||
Cash and Cash Equivalents at End of Period | $ | 20 | $ | 120 | $ | 2,164 | $ | — | $ | 2,304 |
(a) | All significant intercompany transactions have been eliminated in consolidation. |
100
SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2011, 2010, and 2009
Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions | Balance at End of Period | |||||||||||||||
(In millions) | |||||||||||||||||||
Allowance for doubtful accounts, deducted from accounts receivable | |||||||||||||||||||
Year Ended December 31, 2011 | $ | 25 | $ | 60 | $ | — | $ | (62 | ) | (a) | $ | 23 | |||||||
Year Ended December 31, 2010 | 29 | 54 | — | (58 | ) | (a) | 25 | ||||||||||||
Year Ended December 31, 2009 | 3 | 61 | — | (35 | ) | (a) | 29 | ||||||||||||
Income tax valuation allowance, deducted from deferred tax assets | |||||||||||||||||||
Year Ended December 31, 2011 | $ | 191 | $ | (63 | ) | $ | (45 | ) | $ | — | $ | 83 | |||||||
Year Ended December 31, 2010 | 233 | (34 | ) | (8 | ) | — | 191 | ||||||||||||
Year Ended December 31, 2009 | 359 | (130 | ) | 4 | — | 233 |
(a) | Represents principally net amounts charged as uncollectible. |
101