EXHIBIT 99.3
NRG NORTHEAST GENERATING LLC
CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 2003, December 6, 2003 and
NRG NORTHEAST GENERATING LLC
INDEX
Page(s) | ||||
Reports of Independent Auditors | 2-3 | |||
Consolidated Financial Statements | ||||
Consolidated Balance Sheets at December 31, 2003, December 6, 2003 and December 31, 2002 | 4 | |||
Consolidated Statements of Operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001 | 5 | |||
Consolidated Statements of Members’ Equity for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001 | 6 | |||
Consolidated Statements of Cash Flows for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001 | 7 | |||
Notes to Consolidated Financial Statements | 8-36 | |||
Reports of Independent Auditors on Financial Statement Schedule | 37-38 | |||
Financial Statement Schedule | 39 |
1
REPORT OF INDEPENDENT AUDITORS
To the Members of
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of members’ equity and of cash flows present fairly, in all material respects, the financial position of NRG Northeast Generating LLC (“Predecessor Company”) and its subsidiaries at December 31, 2002, and the results of their operations and their cash flows for the period from January 1, 2003 to December 5, 2003 and for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries, including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
As discussed in Note 16 to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements for the years ended December 31, 2002 and 2001 to reflect an income tax provision (benefit) and deferred taxes.
/s/ PRICEWATERHOUSECOOPERS LLP | |
PricewaterhouseCoopers LLP |
Minneapolis, Minnesota
2
REPORT OF INDEPENDENT AUDITORS
To the Members of
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of members’ equity and of cash flows present fairly, in all material respects, the financial position of NRG Northeast Generating LLC (“Reorganized Company”) and its subsidiaries at December 31, 2003 and December 6, 2003, and the results of their operations and their cash flows for the period from December 6, 2003 to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America. 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, on May 14, 2003, NRG Energy, Inc. and certain of its subsidiaries, including the Company, filed a petition with the United States Bankruptcy Court for the Southern District of New York for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. NRG Energy, Inc.’s Plan of Reorganization was substantially consummated on December 5, 2003, and Reorganized NRG emerged from bankruptcy. The Company emerged from bankruptcy on December 23, 2003, pursuant to a separate plan of reorganization referred to as the Northeast/ South Central Plan of Reorganization. The impact of NRG Energy, Inc.’s emergence from bankruptcy and fresh start accounting was applied to the Company on December 5, 2003 under push down accounting methodology.
/s/ PRICEWATERHOUSECOOPERS LLP | |
PricewaterhouseCoopers LLP |
Minneapolis, Minnesota
3
NRG NORTHEAST GENERATING LLC
CONSOLIDATED BALANCE SHEETS
Predecessor | ||||||||||||||
Reorganized Company | Company | |||||||||||||
December 31, | December 6, | December 31, | ||||||||||||
2003 | 2003 | 2002 | ||||||||||||
(As Restated) | ||||||||||||||
(In thousands of dollars) | ||||||||||||||
ASSETS | ||||||||||||||
Current assets | ||||||||||||||
Cash and cash equivalents | $ | 6,250 | $ | 5,258 | $ | 14,354 | ||||||||
Restricted cash | 4,198 | 3,608 | — | |||||||||||
Accounts receivable, net of allowance for doubtful accounts of $0, $0 and $50,712, respectively | 306 | 306 | 118,153 | |||||||||||
Accounts receivable — affiliates | 9,665 | 24,349 | — | |||||||||||
Inventory | 107,441 | 108,674 | 123,963 | |||||||||||
Derivative instruments valuation | 611 | — | 23,039 | |||||||||||
Prepayments and other current assets | 33,812 | 29,426 | 38,309 | |||||||||||
Current deferred income tax | — | — | 9,709 | |||||||||||
Total current assets | 162,283 | 171,621 | 327,527 | |||||||||||
Property, plant and equipment, net of accumulated depreciation of $2,911, $0 and $157,534, respectively | 843,832 | 845,872 | 1,333,928 | |||||||||||
Debt issuance costs, net of accumulated amortization of $0, $0, and $1,161, respectively | — | — | 8,995 | |||||||||||
Derivative instruments valuation | — | — | 9,601 | |||||||||||
Intangible assets, net of accumulated amortization of $523, $0 and $2,605, respectively | 213,687 | 214,210 | 23,395 | |||||||||||
Deferred income tax | 91,565 | 91,874 | — | |||||||||||
Other assets | 7,355 | 7,355 | — | |||||||||||
Total assets | $ | 1,318,722 | $ | 1,330,932 | $ | 1,703,446 | ||||||||
LIABILITIES AND MEMBERS’ EQUITY | ||||||||||||||
Current liabilities | ||||||||||||||
Current portion of long-term debt | $ | — | $ | 556,500 | $ | 556,500 | ||||||||
Note payable — affiliate | 30,000 | 30,000 | 30,000 | |||||||||||
Accounts payable | 177 | 64 | 14,607 | |||||||||||
Accounts payable — affiliates | — | — | 11,476 | |||||||||||
Accrued interest | 2,557 | 26,342 | 4,198 | |||||||||||
Other accrued liabilities | 51,225 | 59,344 | 48,881 | |||||||||||
Current deferred income tax | 453 | 442 | — | |||||||||||
Derivative instruments valuation | 190 | 95 | 13,017 | |||||||||||
Total current liabilities | 84,602 | 672,787 | 678,679 | |||||||||||
Derivative instruments valuation | — | — | 7,559 | |||||||||||
Noncurrent deferred income tax | — | — | 68,106 | |||||||||||
Other long-term obligations | 7,528 | 7,493 | 27,936 | |||||||||||
Total liabilities | 92,130 | 680,280 | 782,280 | |||||||||||
Commitments and contingencies | ||||||||||||||
Members’ equity | 1,226,592 | 650,652 | 921,166 | |||||||||||
Total liabilities and members’ equity | $ | 1,318,722 | $ | 1,330,932 | $ | 1,703,446 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
4
NRG NORTHEAST GENERATING LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
Reorganized | |||||||||||||||||
Company | Predecessor Company | ||||||||||||||||
For the | For the | ||||||||||||||||
Period from | Period from | ||||||||||||||||
December 6, | January 1, | For the Years Ended | |||||||||||||||
2003 to | 2003 to | December 31, | |||||||||||||||
December 31, | December 5, | ||||||||||||||||
2003 | 2003 | 2002 | 2001 | ||||||||||||||
(As Restated) | (As Restated) | ||||||||||||||||
(In thousands of dollars) | |||||||||||||||||
Revenues | $ | 60,471 | $ | 730,463 | $ | 693,869 | $ | 1,050,688 | |||||||||
Operating costs | 40,360 | 597,752 | 494,446 | 712,148 | |||||||||||||
Depreciation | 2,911 | 61,271 | 54,227 | 48,900 | |||||||||||||
General and administrative expenses | 4,205 | 40,927 | 44,262 | 24,372 | |||||||||||||
Reorganization items | 241 | 5,148 | — | — | |||||||||||||
Restructuring and impairment charges | — | 230,571 | 50,524 | — | |||||||||||||
Income (loss) from operations | 12,754 | (205,206 | ) | 50,410 | 265,268 | ||||||||||||
Other (expense) income, net | (345 | ) | 441 | 5,273 | 4,624 | ||||||||||||
Interest expense | (2,103 | ) | (50,746 | ) | (51,798 | ) | (58,637 | ) | |||||||||
Income (loss) before income taxes | 10,306 | (255,511 | ) | 3,885 | 211,255 | ||||||||||||
Income tax expense (benefit) | 4,460 | (109,824 | ) | 3,460 | 91,451 | ||||||||||||
Net income (loss) | $ | 5,846 | $ | (145,687 | ) | $ | 425 | $ | 119,804 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
5
NRG NORTHEAST GENERATING LLC
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
Accumulated | ||||||||||||||||||||||||
Members’ | Members’ | Accumulated | Other | Total | ||||||||||||||||||||
Contributions/ | Net Income | Comprehensive | Members’ | |||||||||||||||||||||
Units | Amount | Distributions | (Loss) | Income | Equity | |||||||||||||||||||
(In thousands of dollars) | ||||||||||||||||||||||||
Balances at December 31, 2000 (Predecessor Company) (As Restated) | 1,000 | $ | 1 | $ | 724,036 | $ | — | $ | — | $ | 724,037 | |||||||||||||
Cumulative effect upon adoption of SFAS No. 133 | — | — | — | — | 14,100 | 14,100 | ||||||||||||||||||
Impact of SFAS No. 133 for the year ending December 31, 2001 | — | — | — | — | 93,641 | 93,641 | ||||||||||||||||||
Net income | — | — | — | 119,804 | — | 119,804 | ||||||||||||||||||
Comprehensive income | 227,545 | |||||||||||||||||||||||
Contribution from members | — | — | 83,861 | — | — | 83,861 | ||||||||||||||||||
Distribution to members | — | — | — | (52,727 | ) | — | (52,727 | ) | ||||||||||||||||
Balances at December 31, 2001 (Predecessor Company) (As Restated) | 1,000 | 1 | 807,897 | 67,077 | 107,741 | 982,716 | ||||||||||||||||||
Impact of SFAS No. 133 for the year ending December 31, 2002 | — | — | — | — | (78,906 | ) | (78,906 | ) | ||||||||||||||||
Net income | — | — | — | 425 | — | 425 | ||||||||||||||||||
Comprehensive loss | (78,481 | ) | ||||||||||||||||||||||
Contribution from members | — | — | 16,931 | — | — | 16,931 | ||||||||||||||||||
Balances at December 31, 2002 (Predecessor Company) (As Restated) | 1,000 | 1 | 824,828 | 67,502 | 28,835 | 921,166 | ||||||||||||||||||
Impact of SFAS No. 133 for the period ending December 5, 2003 | — | — | — | — | (28,835 | ) | (28,835 | ) | ||||||||||||||||
Net loss | — | — | — | (145,687 | ) | — | (145,687 | ) | ||||||||||||||||
Comprehensive loss | (174,522 | ) | ||||||||||||||||||||||
Contribution from members | — | — | 15,945 | — | — | 15,945 | ||||||||||||||||||
Distribution to members | — | — | (91,783 | ) | — | — | (91,783 | ) | ||||||||||||||||
Balances at December 5, 2003 (Predecessor Company) | 1,000 | 1 | 748,990 | (78,185 | ) | — | 670,806 | |||||||||||||||||
Push down accounting adjustments | — | — | (98,339 | ) | 78,185 | — | (20,154 | ) | ||||||||||||||||
Balances at December 6, 2003 (Reorganized Company) | 1,000 | 1 | 650,651 | — | — | 650,652 | ||||||||||||||||||
Contribution from members | — | — | 570,094 | — | — | 570,094 | ||||||||||||||||||
Net income and comprehensive income | — | — | — | 5,846 | — | 5,846 | ||||||||||||||||||
Balances at December 31, 2003 (Reorganized Company) | 1,000 | $ | 1 | $ | 1,220,745 | $ | 5,846 | $ | — | $ | 1,226,592 | |||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
6
NRG NORTHEAST GENERATING LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
Reorganized | |||||||||||||||||||
Company | Predecessor Company | ||||||||||||||||||
For the | For the | ||||||||||||||||||
Period from | Period from | ||||||||||||||||||
December 6, | January 1, | For the Years Ended | |||||||||||||||||
2003 to | 2003 to | December 31, | |||||||||||||||||
December 31, | December 5, | ||||||||||||||||||
2003 | 2003 | 2002 | 2001 | ||||||||||||||||
(As Restated) | (As Restated) | ||||||||||||||||||
(In thousands of dollars) | |||||||||||||||||||
Cash flows from operating activities | |||||||||||||||||||
Net income (loss) | $ | 5,846 | $ | (145,687 | ) | $ | 425 | $ | 119,804 | ||||||||||
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities | |||||||||||||||||||
Depreciation | 2,911 | 61,271 | 54,227 | 48,900 | |||||||||||||||
Amortization of debt issuance costs | — | 5,646 | 411 | 409 | |||||||||||||||
Amortization of intangible assets | 523 | 2,172 | — | — | |||||||||||||||
Deferred income taxes | 320 | (125,769 | ) | (13,471 | ) | 7,590 | |||||||||||||
Current tax expense — noncash contribution from members | 4,140 | 15,945 | 16,931 | 83,861 | |||||||||||||||
Asset impairment | — | 230,571 | 49,289 | — | |||||||||||||||
Unrealized (gains) losses on derivatives | (516 | ) | (16,676 | ) | (14,457 | ) | 31,227 | ||||||||||||
Allowance for doubtful accounts | — | — | 50,712 | (8,165 | ) | ||||||||||||||
Loss on disposal of assets | 350 | 1,514 | — | — | |||||||||||||||
Changes in assets and liabilities | |||||||||||||||||||
Accounts receivable | — | 117,841 | (112,840 | ) | 109,800 | ||||||||||||||
Accounts receivable/payable — affiliates | 14,684 | (35,825 | ) | 11,476 | (146,894 | ) | |||||||||||||
Inventories | 1,233 | (7,977 | ) | 48,252 | (64,356 | ) | |||||||||||||
Prepayments and other current assets | (4,386 | ) | 8,883 | (18,193 | ) | 581 | |||||||||||||
Accounts payable | 103 | (14,543 | ) | 12,057 | (1,364 | ) | |||||||||||||
Accrued interest | (23,785 | ) | 22,144 | 2,038 | (391 | ) | |||||||||||||
Other accrued liabilities | (8,109 | ) | 15,468 | (19,396 | ) | (19,716 | ) | ||||||||||||
Changes in other assets and liabilities | 35 | (27,359 | ) | 4,149 | 4,705 | ||||||||||||||
Net cash (used in) provided by operating activities | (6,651 | ) | 107,619 | 71,610 | 165,991 | ||||||||||||||
Cash flows from investing activities | |||||||||||||||||||
Increase in restricted cash | (590 | ) | (3,608 | ) | — | — | |||||||||||||
Capital expenditures | (1,221 | ) | (14,692 | ) | (34,126 | ) | (25,140 | ) | |||||||||||
Net cash used in investing activities | (1,811 | ) | (18,300 | ) | (34,126 | ) | (25,140 | ) | |||||||||||
Cash flows from financing activities | |||||||||||||||||||
Proceeds from debt issuance — affiliate | — | — | 30,000 | — | |||||||||||||||
Contribution from members | 565,954 | — | — | — | |||||||||||||||
Distribution to members | — | (91,783 | ) | — | (52,727 | ) | |||||||||||||
Principal payments on long-term debt | (556,500 | ) | — | (53,500 | ) | (90,000 | ) | ||||||||||||
Debt issuance costs | — | — | — | (198 | ) | ||||||||||||||
Net cash provided by (used in) financing activities | 9,454 | (91,783 | ) | (23,500 | ) | (142,925 | ) | ||||||||||||
Net change in cash and cash equivalents | 992 | (2,464 | ) | 13,984 | (2,074 | ) | |||||||||||||
Cash and cash equivalents | |||||||||||||||||||
Beginning of period | 5,258 | 14,354 | 370 | 2,444 | |||||||||||||||
End of period | $ | 6,250 | $ | 11,890 | $ | 14,354 | $ | 370 | |||||||||||
Supplemental disclosures of cash flow information | |||||||||||||||||||
Interest paid (net of amount capitalized) | $ | 25,888 | $ | 24,786 | $ | 49,760 | $ | 58,541 | |||||||||||
Noncash contribution from members for current tax expense | 4,140 | 15,945 | 16,931 | 83,861 |
The accompanying notes are an integral part of these consolidated financial statements.
7
NRG NORTHEAST GENERATING LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. | Organization |
NRG Northeast Generating LLC (the “Company” or “NRG Northeast”), a wholly owned indirect subsidiary of NRG Energy, Inc. (“NRG Energy”), owns electric power generation plants in the northeastern region of the United States. The Company’s members are Northeast Generation Holding LLC and NRG Eastern LLC, each of which owns a 50% interest in the Company and are directly held wholly owned subsidiaries of NRG Energy. The Company was formed in 1999 for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries and affiliates the power generation facilities owned by Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Connecticut Jet Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC, Oswego Harbor Power LLC and Somerset Power LLC.
Recent Developments |
On May 14, 2003, NRG Energy and 25 of its direct and indirect wholly owned subsidiaries commenced voluntary petitions under Chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. The Company and its direct subsidiaries were included in the Chapter 11 filing. During the bankruptcy proceedings, NRG Energy continued to conduct business and manage the companies as debtors in possession pursuant to sections 1107(a) and 1108 of the bankruptcy code. Two plans of reorganization were filed in connection with the restructuring efforts. The first, filed on May 14, 2003, and referred to as NRG Energy’s Plan of Reorganization, relates to NRG Energy and the other NRG Energy plan debtors. The second plan, relating to the Company, its subsidiaries and the South Central subsidiaries, referred to as the Northeast/ South Central Plan of Reorganization, was filed on September 17, 2003. On November 24, 2003, the bankruptcy court entered an order confirming NRG Energy’s Plan of Reorganization and the plan became effective on December 5, 2003. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on December 23, 2003. In connection with NRG Energy’s emergence from bankruptcy, NRG Energy adopted fresh start accounting in accordance with AICPA Statement of Position 90-7,Financial Reporting by Entities in Reorganization Under the Bankruptcy Code(“SOP 90-7”) on December 5, 2003. NRG Energy’s fresh start accounting was applied to the Company on a push down accounting basis with the financial statement impact recorded as an adjustment to the December 6, 2003, members’ equity in the amount of $20.2 million.
NRG Energy’s Plan of Reorganization |
NRG Energy’s Plan of Reorganization is the result of several months of intense negotiations among NRG Energy, Xcel Energy, Inc. (“Xcel Energy”) and the two principal committees representing NRG Energy creditor groups, referred to as the Global Steering Committee and the Noteholder Committee. A principal component of NRG Energy’s Plan of Reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of NRG Energy’s Plan of Reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and NRG Energy and/or its creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from NRG Energy and its creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003.
Northeast/ South Central Plan of Reorganization |
The Northeast/ South Central Plan of Reorganization was proposed on September 17, 2003, after necessary financing commitments were secured. On November 25, 2003, the bankruptcy court issued an order confirming the Northeast/ South Central Plan of Reorganization and the plan became effective on
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
December 23, 2003. In connection with the order confirming the Northeast/ South Central Plan of Reorganization, the court entered a separate order which provides that the allowed amount of the bondholders’ claims shall equal in the aggregate the sum of (i) $1.3 billion plus (ii) any accrued and unpaid interest at the applicable contract rates through the date of payment to the indenture trustee plus (iii) the reasonable fees, costs or expenses of the collateral agent and indenture trustee (other than reasonable professional fees incurred from October 1, 2003) plus (iv) $19.6 million, ratably, for each holder of bonds based upon the current outstanding principal amount of the bonds and irrespective of (a) the date of maturity of the bonds, (b) the interest rate applicable to such bonds and (c) the issuer of the bonds.
The creditors of Northeast and South Central subsidiaries were unimpaired by the Northeast/ South Central Plan of Reorganization. The creditors holding allowed general secured claims were paid in cash, in full on the effective date of the Northeast/ South Central Plan of Reorganization. Holders of allowed unsecured claims will receive or have received either (i) cash equal to the unpaid portion of their allowed unsecured claim, (ii) treatment that leaves unaltered the legal, equitable and contractual rights to which such unsecured claim entitles the holder of such claim, (iii) treatment that otherwise renders such unsecured claim unimpaired pursuant to section 1124 of the bankruptcy code or (iv) such other, less favorable treatment that is confirmed in writing as being acceptable to such holder and to the applicable debtor.
2. | Summary of Significant Accounting Policies |
Principles of Consolidation |
The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. Accounting policies for all of the Company’s operations are in accordance with the accounting principles generally accepted in the United States of America.
NRG Energy Fresh Start Reporting/Push Down Accounting |
In accordance with SOP 90-7, certain companies qualify for fresh start (“Fresh Start”) reporting in connection with their emergence from bankruptcy. Fresh Start reporting is appropriate on the emergence from Chapter 11 if the reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares of the emerging entity. NRG Energy met these requirements and adopted Fresh Start reporting and applied push down accounting to its various subsidiary operations including the Company. Under push down accounting, the Company’s equity fair value was allocated to the Company’s assets and liabilities based on their estimated fair values as of December 5, 2003, as further described in Note 3.
Under the requirements of Fresh Start, NRG Energy adjusted its assets and liabilities, other than deferred income taxes, to their estimated fair values as of December 5, 2003. As a result of marking the assets and liabilities to their estimated fair values, NRG Energy determined that there was a negative reorganization value that was reallocated back to the tangible and intangible assets. Deferred taxes were determined in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 109,Accounting for Income Taxes. The net effect of all Fresh Start adjustments resulted in a gain of $3.9 billion, which is reflected in NRG Energy’s Predecessor Company results for the period from January 1, 2003 to December 5, 2003. The application of the Fresh Start provisions of SOP 90-7 created a new reporting entity having no retained earnings or accumulated deficit.
As part of the bankruptcy process, NRG Energy engaged an independent financial advisor to assist in the determination of its reorganized enterprise value. The fair value calculation was based on management’s forecast of expected cash flows from its core assets. Management’s forecast incorporated forward commodity
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
market prices obtained from a third party consulting firm. A discounted cash flow calculation was used to develop the enterprise value of Reorganized NRG, determined in part by calculating the weighted average cost of capital of the Reorganized NRG. The Discounted Cash Flow, (“DCF,”) valuation methodology equates the value of an asset or business to the present value of expected future economic benefits to be generated by that asset or business. The DCF methodology is a “forward looking” approach that discounts expected future economic benefits by a theoretical or observed discount rate. The independent financial advisor prepared a 30-year cash flow forecast using a discount rate of approximately 11%. The resulting reorganization enterprise value as included in the Disclosure Statement ranged from $5.5 billion to $5.7 billion. The independent financial advisor then subtracted NRG Energy’s project level debt and made several other adjustments to reflect the values of assets held for sale, excess cash and collateral requirements to estimate a range of Reorganized NRG equity value of between $2.2 billion and $2.6 billion.
In constructing the Fresh Start balance sheet upon emergence from bankruptcy, NRG Energy used a reorganization equity value of approximately $2.4 billion, as NRG Energy believed this value to be the best indication of the value of the ownership distributed to the new equity owners. NRG Energy’s Plan of Reorganization provided for the issuance of 100,000,000 shares of NRG Energy common stock to the various creditors resulting in a calculated price per share of $24.04. The reorganization value of approximately $9.1 billion was determined by adding the reorganized equity value of $2.4 billion, $3.7 billion of interest bearing debt and other liabilities of $3.0 billion. The reorganization value represents the fair value of an entity before liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring. This value is consistent with the voting creditors and Court’s approval of NRG Energy’s Plan of Reorganization.
The application of SOP 90-7 and push down accounting resulted in the creation of a new reporting entity for the Company. Consequently, the consolidated financial statements of the Reorganized Company and the Predecessor Company are separated by a black line to distinguish that the assets, liabilities and equity as well as the results of operations are not comparable between periods. Under the requirements of push down accounting, the Company has adjusted its assets and liabilities to their estimated fair values as of December 5, 2003. The impact of push down accounting resulted in the reduction of members’ equity for the Company in the amount of $20.2 million.
Between May 14, 2003 and December 23, 2003, the Company operated as a debtor in possession under the supervision of the bankruptcy court. The consolidated financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of SOP 90-7.
For financial reporting purposes, close of business on December 5, 2003, represents the date of NRG Energy’s emergence from bankruptcy. As previously stated, the Company and its subsidiaries emerged from bankruptcy on December 23, 2003. The accompanying consolidated financial statements reflect the impact of NRG Energy’s emergence from bankruptcy effective December 5, 2003. As used herein, the following terms refer to the Company and its operations:
“Predecessor Company” | The Company, prior to push down accounting The Company’s operations, January 1, 2001 - December 31, 2001 The Company’s operations, January 1, 2002 - December 31, 2002 The Company’s operations, January 1, 2003 - December 5, 2003 |
“Reorganized Company” | The Company, post push down accounting The Company’s operations, December 6, 2003 - December 31, 2003 |
The bankruptcy court in its confirmation order approved NRG Energy’s Plan of Reorganization on November 24, 2003, and subsequently approved the Company’s Plan of Reorganization on November 25,
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
2003. Under the requirements of SOP 90-7, the Fresh Start date is determined to be the confirmation date unless significant uncertainties exist regarding the effectiveness of the bankruptcy order. NRG Energy’s Plan of Reorganization required completion of the Xcel Energy settlement agreement prior to emergence from bankruptcy. Management believes this settlement agreement was a significant contingency and thus delayed the Fresh Start date until the Xcel Energy settlement agreement was finalized on December 5, 2003.
Cash and Cash Equivalents |
Cash and cash equivalents include highly liquid investments (primarily commercial paper) with a maturity of three months or less at the time of purchase.
Restricted Cash |
Restricted cash consists primarily of funds held within the Company’s subsidiaries that are restricted in their use due to contractual arrangements.
Inventory |
Inventory is valued at the lower of weighted average cost or market and consists principally of fuel oil, spare parts, coal and kerosene.
Property, Plant and Equipment |
Property, plant and equipment are stated at cost; however, impairment adjustments are recorded whenever events or changes in circumstances indicate carrying values may not be recoverable. At December 5, 2003, the Company recorded adjustments to the property, plant and equipment to reflect such items at fair value in accordance with push down accounting. A new cost basis was established with these adjustments. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The assets and related accumulated depreciation amounts are adjusted for asset retirements and disposals with the resulting gain or loss included in 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 SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. 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. Fair values are determined by a variety of valuation methods, including appraisals, sales prices of similar assets and present value techniques.
Debt Issuance Costs |
Debt issuance costs consist of legal and other costs incurred by the Company to obtain long-term financing. These costs, which were written off as part of push down accounting (see Note 3), were capitalized and amortized as interest expense on a straight-line basis that approximates the effective interest method over the terms of the related debt.
11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Intangible Assets |
Intangible assets represent contractual rights held by the Company. Intangible assets are amortized over their economic useful life and reviewed for impairment on a periodic basis.
Intangible assets consist primarily of the fair value of power sales agreements and emission allowances. The amounts related to the power sales agreements will be amortized as a reduction to revenue over the terms and conditions of each contract. Emission allowance related amounts will be amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023.
Revenue Recognition |
Revenues from the sale of electricity are recorded based upon the output delivered and capacity provided at rates specified under contract terms or prevailing market rates. Revenues and related costs under cost reimbursable contract provisions are recorded as costs are incurred.
In certain markets, which are operated/controlled by an independent system operator and in which the Company has entered into a netting agreement with the Independent System Operator (“ISO”), which results in receiving a netted invoice, the Company has recorded purchased energy as an offset against revenues received upon the sale of such energy. Capacity and ancillary revenue is recognized when contractually earned. Disputed revenues are not recorded in the financial statements until disputes are resolved and collection is assured.
Power Marketing Activities |
The Company’s subsidiaries have entered into agency agreements with a marketing affiliate for the sale of energy, capacity and ancillary services produced by these subsidiaries, and for the procurement and management of fuel (coal, oil derivatives and natural gas) and emission credit allowances, which enables the affiliate to engage in forward sales and hedging transactions to manage the subsidiaries’ electricity and fuel price exposure. Net gains or losses on hedges by the marketing affiliate, which are physically settled, are recognized in the same manner as the hedged item. The Company receives the net transaction price on all contracts that are physically settled by its marketing affiliate.
Income Taxes |
The Company has been organized as a limited liability company. Therefore, federal and state income taxes are assessed at the member level. However, a provision for separate company federal and state income taxes has been reflected in the accompanying consolidated financial statements (see Note 16 — Income Taxes). As a result of the Company being included in the NRG Energy consolidated tax return and tax payments, federal and state taxes payable amounts resulting from the tax provision are reflected as a contribution by members in the consolidated statement of members’ equity and consolidated balance sheets.
Deferred income taxes are recognized for the tax consequences in future years of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts at each year end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable for the period and the change during the period in deferred tax assets and liabilities. A valuation allowance is recorded to reduce deferred tax assets to the amount more likely than not to be realized.
Concentrations of Credit Risk |
Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, accounts receivable and derivative instruments. Cash accounts are generally held in
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
federally insured banks. Accounts 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 are generally not collateralized; however, the Company believes the credit risk posed by industry concentration is mitigated by the diversification and credit worthiness of its customer base.
Fair Value of Financial Instruments |
The carrying amount of cash and cash equivalents, restricted cash, receivables, accounts payables, debt and accrued liabilities approximate fair value because of the short maturity of these instruments. The fair value of long-term debt is estimated based on quoted market prices and similar instruments with equivalent credit quality.
Use of Estimates in Financial Statements |
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates.
In recording transactions and balances resulting from business operations, the Company uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, uncollectible accounts, and the valuation of long-term energy commodities contracts, among others. In addition, estimates are used to test long-lived assets for impairment and to determine 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.
Reclassifications |
Certain prior year amounts have been reclassified for comparative purposes. These reclassifications had no effect on the Company’s net income or total members’ equity as previously reported.
3. | Emergence from Bankruptcy and Fresh Start Reporting |
In accordance with the requirement of push down accounting, the Company’s fair value of $650.7 million was allocated to the Company’s assets and liabilities based on their individual estimated fair values. A third party was used to complete an independent appraisal of the Company’s tangible assets, intangible assets and contracts.
The determination of the fair value of the Company’s assets and liabilities was based on a number of estimates and assumptions, which are inherently subject to significant uncertainties and contingencies.
Due to the adoption of push down accounting as of December 5, 2003, the Reorganized Company’s consolidated balance sheets, consolidated statements of operations and cash flows have not been prepared on a consistent basis with the Predecessor Company’s consolidated financial statements and are not comparable in certain respects to the consolidated financial statements prior to the application of push down accounting. A black line has been drawn on the accompanying consolidated financial statements to separate and distinguish
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
between the Reorganized Company and the Predecessor Company. The effects of the push down accounting adjustments on the Company’s consolidated balance sheet as of December 5, 2003, were as follows:
Predecessor | Reorganized | |||||||||||||
Company | Company | |||||||||||||
December 5, | Push Down | December 6, | ||||||||||||
2003 | Adjustments | 2003 | ||||||||||||
(In thousands of dollars) | ||||||||||||||
ASSETS | ||||||||||||||
Current assets | ||||||||||||||
Cash and cash equivalents | $ | 5,258 | $ | — | $ | 5,258 | ||||||||
Restricted cash | 3,608 | — | 3,608 | |||||||||||
Accounts receivable | 306 | — | 306 | |||||||||||
Accounts receivable — affiliates | 24,349 | — | 24,349 | |||||||||||
Inventory | 131,940 | (23,266 | )(A) | 108,674 | ||||||||||
Prepayments and other current assets | 29,426 | — | 29,426 | |||||||||||
Current deferred income tax | 38,157 | (38,157 | )(B) | — | ||||||||||
Total current assets | 233,044 | (61,423 | ) | 171,621 | ||||||||||
Property, plant and equipment, net | 1,057,063 | (211,191 | )(C) | 845,872 | ||||||||||
Intangible assets, net | 21,223 | 192,987 | (D) | 214,210 | ||||||||||
Deferred income tax | 29,215 | 62,659 | (B) | 91,874 | ||||||||||
Other assets | 7,355 | — | 7,355 | |||||||||||
Total assets | $ | 1,347,900 | $ | (16,968 | ) | $ | 1,330,932 | |||||||
LIABILITIES AND MEMBERS’ EQUITY | ||||||||||||||
Current liabilities | ||||||||||||||
Current portion of long-term debt | $ | 556,500 | $ | — | $ | 556,500 | ||||||||
Note payable — affiliate | 30,000 | — | 30,000 | |||||||||||
Accounts payable | 64 | — | 64 | |||||||||||
Accrued interest | 26,342 | — | 26,342 | |||||||||||
Other accrued liabilities | 59,344 | — | 59,344 | |||||||||||
Derivative instruments valuation | 95 | — | 95 | |||||||||||
Current deferred income tax | — | 442 | (B) | 442 | ||||||||||
Total current liabilities | 672,345 | 442 | 672,787 | |||||||||||
Other long-term obligations | 4,749 | 2,744 | (D) | 7,493 | ||||||||||
Total liabilities | 677,094 | 3,186 | 680,280 | |||||||||||
Members’ equity | ||||||||||||||
Members’ contributions | 748,991 | (98,339 | ) | 650,652 | ||||||||||
Accumulated net loss | (78,185 | ) | 78,185 | — | ||||||||||
Total members’ equity | 670,806 | (20,154 | )(E) | 650,652 | ||||||||||
Total liabilities and members’ equity | $ | 1,347,900 | $ | (16,968 | ) | $ | 1,330,932 | |||||||
(A) | Accounting policy change upon adoption of push down accounting. Consumables are no longer included as inventory and are expensed as incurred. In addition, capital spare parts of $5.6 million were reclassified from inventory to property, plant and equipment. | |
(B) | Reflects the adjustment to deferred income tax assets and liabilities due to push down accounting. |
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(C) | Result of allocating the equity value in conformity with the purchase method of accounting for business combinations. These allocations were based on valuations obtained from independent appraisers. | |
(D) | Reflects management’s estimate, with the assistance of independent appraisers, of the fair value of power purchase agreements and SO2 emission credits. In addition, the Asset Retirement Obligation (“ARO”) was revalued. | |
(E) | The change in members’ equity reflects the fair value adjustment resulting from NRG Energy’s Fresh Start accounting procedures. |
4. | Other Charges |
Restructuring and impairment charges and reorganization items included in operating costs and expenses in the consolidated statement of operations include the following:
Reorganized | ||||||||||||
Company | Predecessor Company | |||||||||||
For the | For the | |||||||||||
Period from | Period from | |||||||||||
December 6, | January 1, | For the | ||||||||||
2003 through | 2003 through | Year Ended | ||||||||||
December 31, | December 5, | December 31, | ||||||||||
2003 | 2003 | 2002 | ||||||||||
(In thousands of dollars) | ||||||||||||
Restructuring and impairment charges | $ | — | $ | 230,571 | $ | 50,524 | ||||||
Reorganization items | 241 | 5,148 | — | |||||||||
$ | 241 | $ | 235,719 | $ | 50,524 | |||||||
Restructuring and Impairment Charges |
The Company reviewed the recoverability of its long-lived assets in accordance with the guidelines of SFAS No. 144. As a result of this review, the Company recorded pre-tax impairment charges of $230.6 million for the period from January 1, 2003 through December 5, 2003, and $49.3 million for the year ended December 31, 2002, as shown in the table below.
To determine whether an asset was impaired, the Company compared asset carrying values to total future estimated undiscounted cash flows. Separate analyses were completed for assets or groups of assets at the lowest level for which identifiable cash flows were largely independent of the cash flows of other assets and liabilities. The estimates of future cash flows included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of the Company’s assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service were based on the asset’s existing service potential. The cash flow estimates may include probability weightings to consider possible alternative courses of action and outcomes, given the uncertainty of available information and prospective market conditions.
If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to write down the asset to its fair value. Estimates of fair value were based on prices for similar assets and present value techniques. Fair values determined by similar asset prices reflect the Company’s current estimate of recoverability from expected marketing of project assets. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated future project operating costs, and expected plant operation given assumed market conditions.
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Restructuring and impairment charges included the following asset impairments for the period from January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002:
Predecessor Company | ||||||||||||
For the | ||||||||||||
Period from | ||||||||||||
January 1, | For the | |||||||||||
2003 through | Year Ended | |||||||||||
December 5, | December 31, | |||||||||||
2003 | 2002 | Fair Value Basis | ||||||||||
(In thousands of dollars) | ||||||||||||
Devon Power LLC | $ | 64,198 | $ | — | Projected cash flows | |||||||
Middletown Power LLC | 157,323 | — | Projected cash flows | |||||||||
Arthur Kill Power LLC | 9,050 | — | Projected cash flows | |||||||||
Somerset Power LLC | — | 49,289 | Projected cash flows | |||||||||
Total impairment charges | 230,571 | 49,289 | ||||||||||
Consulting fees related to pending bankruptcy | — | 1,235 | ||||||||||
Total restructuring and impairment charges | $ | 230,571 | $ | 50,524 | ||||||||
Connecticut Facilities — As a result of regulatory developments and changing circumstances in the second quarter of 2003, the Company updated the facilities’ cash flow models to incorporate changes to reflect the impact of the April 25, 2003, Federal Energy Regulatory Commission (“FERC”). FERC’s orders on Peaking Units Safe Harbor (“PUSH”) pricing, the pending termination of the Reliability Must Run Agreements (“RMR”), and to update the estimated impact of future locational capacity or deliverability requirements. Based on these revised cash flow models, management determined that the new estimates of pricing and cost recovery levels were not projected to return sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown Power LLC. As a consequence, during the second quarter of 2003, the Company recorded a $64.2 million and $157.3 million impairment at Devon Power LLC and Middletown Power LLC, respectively.
Arthur Kill Power LLC — During the third quarter of 2003, the Company cancelled its plans to re-establish fuel oil capacity at its Arthur Kill plant. This resulted in a charge of approximately $9.1 million to write-off assets under construction.
Somerset Power LLC — The credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity experienced by NRG Northeast during the third quarter of 2002 were “triggering events” which, pursuant to SFAS No. 144, required the Company to review the recoverability of its long-lived assets. As a result, the Company determined that Somerset Power became impaired during the third quarter of 2002 and should be written down to fair market value. Accordingly, the Company recorded asset impairment charges of $49.3 million related to Somerset Power.
There were no impairment charges for the period from December 6, 2003 to December 31, 2003.
Reorganization Items |
In connection with the confirmation of the Northeast/South Central Plan of Reorganization, the debt held by the Company became an allowable claim. As a result, the Company incurred a charge of approximately $3.4 million to write-off related debt issuance costs as well as incurring a pre-payment charge of approximately $8.3 million for the refinancing transaction completed with the emergence from bankruptcy of the Company. The $8.3 million was expensed in November 2003, as it was determined to be an allowed claim at that time. The Company recorded a gain of $18.1 million related to the write-off of the remaining
16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
unrecognized gain on the interest rate lock entered into by the Company upon the issuance of the Company’s debt.
Reorganized | Predecessor | |||||||||
Company | Company | |||||||||
For the | For the | |||||||||
Period from | Period from | |||||||||
December 6, | January 1, | |||||||||
2003 to | 2003 to | |||||||||
December 31, | December 5, | |||||||||
2003 | 2003 | |||||||||
(In thousands of dollars) | ||||||||||
Reorganization items | ||||||||||
Consulting and legal fees | $ | 241 | $ | (1,271 | ) | |||||
Deferred financing costs | — | (3,350 | ) | |||||||
Pre-payment charge | — | (8,348 | ) | |||||||
Write-off of interest rate lock | — | 18,117 | ||||||||
Total reorganization items | $ | 241 | $ | 5,148 | ||||||
5. | Inventory |
Inventory, which is valued at the lower of weighted average cost or market, consists of:
Predecessor | |||||||||||||
Reorganized Company | Company | ||||||||||||
December 31, | December 6, | December 31, | |||||||||||
2003 | 2003 | 2002 | |||||||||||
(In thousands of dollars) | |||||||||||||
Fuel oil | $ | 66,915 | $ | 65,462 | $ | 47,052 | |||||||
Spare parts | 24,947 | 24,986 | 59,524 | ||||||||||
Coal | 12,163 | 14,815 | 14,378 | ||||||||||
Kerosene | 3,416 | 3,411 | 2,852 | ||||||||||
Other | — | — | 157 | ||||||||||
Total inventory | $ | 107,441 | $ | 108,674 | $ | 123,963 | |||||||
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
6. | Property, Plant and Equipment |
The major classes of property, plant and equipment were as follows:
Predecessor | |||||||||||||||||||||
Reorganized Company | Company | Average | |||||||||||||||||||
Remaining | |||||||||||||||||||||
Depreciable | December 31, | December 6, | December 31, | Useful | |||||||||||||||||
Lives | 2003 | 2003 | 2002 | Life | |||||||||||||||||
(In thousands of dollars) | |||||||||||||||||||||
Facilities, machinery and equipment | 25-30 years | $ | 802,173 | $ | 802,492 | $ | 1,415,726 | 18 years | |||||||||||||
Land and improvements | 34,266 | 34,266 | 46,925 | ||||||||||||||||||
Construction in progress | 9,689 | 8,499 | 27,615 | ||||||||||||||||||
Office furnishings and equipment | 3-10 years | 615 | 615 | 1,196 | 2 years | ||||||||||||||||
Total property, plant and equipment | 846,743 | 845,872 | 1,491,462 | ||||||||||||||||||
Accumulated depreciation | (2,911 | ) | — | (157,534 | ) | ||||||||||||||||
Property, plant and equipment, net | $ | 843,832 | $ | 845,872 | $ | 1,333,928 | |||||||||||||||
7. | Asset Retirement Obligation |
Effective January 1, 2003, the Company adopted SFAS No. 143,Accounting for Asset Retirement Obligations. SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 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.
The Company identified certain retirement obligations related to environmental obligations for ash disposal site closures. The Company also identified similar other asset retirement obligations that could not be calculated because the assets associated with the retirement obligations were determined to have an indeterminate life. The adoption of SFAS No. 143 resulted in recording a $0.2 million increase to property, plant and equipment and a $0.3 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was recorded as a $0.1 million increase to depreciation expense and a $0.1 million increase to operating costs in the period from January 1, 2003 to December 5, 2003, as the Company considered the cumulative effect to be immaterial.
The following represents the balances of the asset retirement obligation at January 1, 2003, and the additions and accretion of the asset retirement obligation for the period from January 1, 2003 to December 5, 2003 and the period from December 6, 2003 to December 31, 2003, which is included in other long-term obligations in the consolidated balance sheet. Prior to December 5, 2003, the Company completed its annual review of asset retirement obligations. As part of that review, the Company identified new obligations in the amount of $4.0 million. As a result of applying push down accounting, the Company revalued its asset retirement obligations on December 6, 2003. The Company recorded an increase to its retirement obligation of
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
$2.7 million in connection with push down accounting. This amount results from a change in the discount rate used between adoption and December 5, 2003, equal to 500 to 600 basis points.
Predecessor Company | ||||||||||||||||||||
Accretion | ||||||||||||||||||||
Beginning | for Period | Adjustment | Ending | |||||||||||||||||
Balance | Ended | for | Balance | |||||||||||||||||
January 1, | Revisions | December 5, | Fresh Start | December 5, | ||||||||||||||||
2003 | to Estimate | 2003 | Reporting | 2003 | ||||||||||||||||
(In thousands of dollars) | ||||||||||||||||||||
Dunkirk Power LLC | $ | — | $ | 1,609 | $ | 136 | $ | 920 | $ | 2,665 | ||||||||||
Huntley Power LLC | — | 2,426 | 225 | 1,675 | 4,326 | |||||||||||||||
Someset Power LLC | 313 | — | 40 | 149 | 502 | |||||||||||||||
$ | 313 | $ | 4,035 | $ | 401 | $ | 2,744 | $ | 7,493 | |||||||||||
Reorganized Company | ||||||||||||
Accretion for | ||||||||||||
Beginning | Period | Ending | ||||||||||
Balance | December 6 to | Balance | ||||||||||
December 6, | December 31, | December 31, | ||||||||||
2003 | 2003 | 2003 | ||||||||||
(In thousands of dollars) | ||||||||||||
Dunkirk Power LLC | $ | 2,665 | $ | 12 | $ | 2,677 | ||||||
Huntley Power LLC | 4,326 | 20 | 4,346 | |||||||||
Somerset Power LLC | 502 | 3 | 505 | |||||||||
$ | 7,493 | $ | 35 | $ | 7,528 | |||||||
The following represents the pro forma effect on the Company’s net income for the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, as if the Company had adopted SFAS No. 143 as of January 1, 2001:
Predecessor Company | ||||||||||||
For the | ||||||||||||
Period from | ||||||||||||
January 1, | For the Years Ended | |||||||||||
2003 to | December 31, | |||||||||||
December 5, | ||||||||||||
2003 | 2002 | 2001 | ||||||||||
(As Restated) | (As Restated) | |||||||||||
(In thousands of dollars) | ||||||||||||
Net (loss) income as reported | $ | (145,687 | ) | $ | 425 | $ | 119,804 | |||||
Pro forma adjustment to reflect retroactive adoption of SFAS No. 143 | 188 | (56 | ) | (132 | ) | |||||||
Pro forma net (loss) income | $ | (145,499 | ) | $ | 369 | $ | 119,672 | |||||
On a pro forma basis, an asset retirement obligation of $0.3 million and $0.3 million would have been recorded as an other long-term obligation at January 1, 2002 and December 31, 2002, respectively, based on similar assumptions used to determine the amounts on the Company’s consolidated balance sheets at December 6, 2003 and December 31, 2003.
8. | Intangible Assets |
During the first quarter of 2002, the Company adopted SFAS No. 142,Goodwill and Other Intangible Assets, which requires new accounting for intangible assets, including goodwill. Intangible assets with finite
19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
lives will be amortized over their economic useful lives and periodically reviewed for impairment. Goodwill will no longer be amortized, but will be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value. The Company did not recognize any asset impairments as a result of adopting SFAS No. 142.
Reorganized Company |
The Company had intangible assets with a net carrying value of $214.2 million and $213.7 million at December 6, 2003 and December 31, 2003, respectively. The power sales agreement amounts will be amortized as a reduction to revenue over the terms and conditions of each contract. The amortization period is six months for the power sales agreement. Emission allowances will be amortized as additional fuel expense based upon the actual level of emissions from the respective plant through 2023. No amortization was recorded during the period from December 6, 2003 to December 31, 2003, as this balance includes only emission allowances for 2004 and beyond. All emission allowances for 2003 were used prior to December 5, 2003. The amortization expense for the period from December 6, 2003 to December 31, 2003, was $0.5 million related to power sales agreements. The annual aggregate amortization expense for each of the five succeeding years is expected to approximate $15.1 million in year one and $13.2 million in years two through five for both the power sales agreements and emission allowances. Intangible assets consisted of the following:
Reorganized Company | Predecessor Company | ||||||||||||||||||||||||
December 31, 2003 | December 6, 2003 | December 31, 2002 | |||||||||||||||||||||||
Gross | Gross | Gross | |||||||||||||||||||||||
Carrying | Accumulated | Carrying | Accumulated | Carrying | Accumulated | ||||||||||||||||||||
Amount | Amortization | Amount | Amortization | Amount | Amortization | ||||||||||||||||||||
(In thousands of dollars) | |||||||||||||||||||||||||
Intangible assets | |||||||||||||||||||||||||
Future transmission service | $ | — | $ | — | $ | — | $ | — | $ | 26,000 | $ | 2,605 | |||||||||||||
Power sales agreements | 3,140 | 523 | 3,140 | — | — | — | |||||||||||||||||||
Emission allowances | 211,070 | — | 211,070 | — | — | — | |||||||||||||||||||
Total intangible assets | $ | 214,210 | $ | 523 | $ | 214,210 | $ | — | $ | 26,000 | $ | 2,605 | |||||||||||||
Predecessor Company |
The Company had intangible assets with a carrying amount of $23.4 million at December 31, 2002, comprised of future transmission service being provided under a long-term contract. Amortization expense recognized for the years ended December 31, 2002 and 2001, was approximately $0.9 million and $1.7 million respectively. The amortization expense for the period from January 1, 2003 to December 5, 2003, was $2.2 million. The net amount of the intangible assets was transferred to fixed assets as part of push down accounting.
9. | Long-Term Debt and Note Payable — Affiliate |
On February 22, 2000, the Company issued $750 million of project level senior secured bonds, to refinance short-term project borrowings and for certain other purposes. The bond offering included three tranches: $320 million with an interest rate of 8.065% due in 2004, $130 million with an interest rate of 8.842% due in 2015 and $300 million with an interest rate of 9.292% due in 2024. Interest and principal payments are due semi-annually. The bonds were jointly and severally guaranteed by each of the Company’s subsidiaries. The bonds were secured by a security interest in the Company’s membership or other ownership interests in the guarantors and its rights under all inter-company notes between the Company and the guarantors. In
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
December 2000, the Company exchanged all of its outstanding bonds for bonds registered under the Securities Act of 1933. As a result of the Company’s failure to make the December 15, 2002 principal payment and other default provisions, the entire $556.5 million owed on the secured bonds was classified as a current liability at December 6, 2003 and December 31, 2002. On December 23, 2003, NRG Energy issued $1.25 billion in Second Priority Notes, due and payable on December 15, 2013. On the same date, NRG Energy also entered into a new credit facility for up to $1.45 billion. In addition, on December 23, 2003, the Company used proceeds of $570.1 million from a capital contribution from NRG Energy to pay the outstanding balance of $556.6 million along with the $1.1 million in accrued interest and $8.3 million in a pre-payment charge.
On June 15, 2002, NRG Energy loaned the Company $30 million to fund capital expenditures. The debt bears interest at the three-month London Interbank Offered Rate plus 0.5%. The debt is subject to the terms and conditions of the senior secured bonds’ indenture. The debt was repaid in the first quarter of 2004. Accordingly, the Company has classified this loan as a short-term affiliated note payable.
10. | Derivative Instruments and Hedging Activity |
On January 1, 2001, the Company adopted SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137, SFAS No. 138 and SFAS No. 149. SFAS No. 133 requires the Company to record all derivatives on the consolidated balance sheet at fair value. Changes in the fair value of nonhedge derivatives will be immediately recognized in earnings. The criteria used to determine if hedge accounting treatment is appropriate are (a) the designation of the hedge to an underlying exposure, (b) whether or not the overall risk is being reduced and (c) if there is a high degree of correlation between the value of the derivative instrument and the underlying obligation. Formal documentation of the hedging relationship, the nature of the underlying risk, the risk management objective, and the means by which effectiveness will be assessed is created at the inception of the hedge. Changes in fair values of derivatives accounted for as hedges will either be recognized in earnings as offsets to the changes in fair value of related hedged assets, liabilities and firm commitments or, for forecasted transactions, deferred and recorded as a component of other accumulated comprehensive income, (“OCI,”) until the hedged transactions occur and are recognized in earnings. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings. The Company also formally assesses both at inception and at least quarterly thereafter, whether the derivatives that are used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.
SFAS No. 133 applies to the Company’s long-term power sales contracts, long-term gas purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel requirements at generation facilities and protect investments in fuel inventories. At December 31, 2003, the Company had various commodity contracts extending through April 2004.
21
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Accumulated Other Comprehensive Income |
The following table summarizes the effects of SFAS No. 133 on the Company’s accumulated other comprehensive income balance at December 31, 2003, December 6, 2003 and December 31, 2002:
Reorganized | ||||||||||||||
Company | Predecessor Company | |||||||||||||
For the | For the | |||||||||||||
Period from | Period from | |||||||||||||
December 6, | January 1, | For the Year | ||||||||||||
2003 to | 2003 to | Ended | ||||||||||||
December 31, | December 5, | December 31, | ||||||||||||
2003 | 2003 | 2002 | ||||||||||||
(In thousands of dollars) | ||||||||||||||
Energy Commodities Gains (Losses) | ||||||||||||||
Beginning balance | $ | — | $ | 28,835 | $ | 107,741 | ||||||||
Unwound from OCI during period | ||||||||||||||
Due to unwinding of previously deferred amounts | — | (28,835 | ) | (48,086 | ) | |||||||||
Mark to market of hedge contracts | — | — | (30,820 | ) | ||||||||||
Ending balance | $ | — | $ | — | $ | 28,835 | ||||||||
Gains expected to unwind from OCI during next 12 months | $ | — | $ | — | $ | 28,835 | ||||||||
During the period from January 1, 2003 to December 5, 2003 and for the year ended December 31, 2002, the Company reclassified gains of $28.8 million and $48.1 million, respectively, from OCI to current-period earnings. This amount is recorded on the same line in the statement of operations in which the hedged item is recorded. Also during the year ended December 31, 2002, the Company recorded losses in OCI of approximately $30.8 million related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 at December 31, 2002, was a gain of approximately $28.8 million.
Statement of Operations |
The following tables summarize the effects of SFAS No. 133 on the Company’s statement of operations for the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and for the years ended December 31, 2002 and 2001, respectively:
Reorganized | |||||||||||||||||
Company | Predecessor Company | ||||||||||||||||
For the | For the | ||||||||||||||||
Period from | Period from | ||||||||||||||||
December 6, | January 1, | For the Years Ended | |||||||||||||||
2003 to | 2003 to | December 31, | |||||||||||||||
December 31, | December 5, | ||||||||||||||||
2003 | 2003 | 2002 | 2001 | ||||||||||||||
(In thousands of dollars) | |||||||||||||||||
Energy Commodities Gains (Losses) | |||||||||||||||||
Revenues | $ | 3 | $ | 18,241 | $ | (10,706 | ) | $ | (7,630 | ) | |||||||
Operating costs | 513 | (1,565 | ) | 25,163 | (23,597 | ) | |||||||||||
Total statement of operations impact before tax | $ | 516 | $ | 16,676 | $ | 14,457 | $ | (31,227 | ) | ||||||||
22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Reorganized | ||||||||||||||||||
Company | Predecessor Company | |||||||||||||||||
For the | For the | |||||||||||||||||
Period from | Period from | |||||||||||||||||
December 6, | January 1, | For the Years Ended | ||||||||||||||||
2003 to | 2003 to | December 31, | ||||||||||||||||
December 31, | December 5, | |||||||||||||||||
2003 | 2003 | 2002 | 2001 | |||||||||||||||
(In thousands of dollars) | ||||||||||||||||||
Energy Commodities Gains (Losses) | ||||||||||||||||||
Net gain (loss) recognized in earnings due to | ||||||||||||||||||
Instruments not accounted for as hedges | $ | 516 | $ | 16,676 | $ | 14,457 | $ | (31,227 | ) | |||||||||
Total statement of operations impact before tax | $ | 516 | $ | 16,676 | $ | 14,457 | $ | (31,227 | ) | |||||||||
Energy and Energy Related Commodities |
The Company is exposed to commodity price variability in electricity, emission allowances, natural gas, oil derivatives and coal used to meet fuel requirements. In order to manage these commodity price risks, the Company may enter into transactions for physical delivery of particular commodities for a specific period. Financial instruments are used to hedge physical deliveries, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps.
During the period from December 6, 2003 to December 31, 2003, the period from January 1, 2003 to December 5, 2003, and the years ended December 31, 2002 and 2001, respectively, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges.
The Company’s earnings for the period from December 6, 2003 to December 31, 2003 and the period from January 1, 2003 to December 5, 2003, were increased by unrealized gains of $0.5 million and $16.7 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133. The Company’s earnings for the years ended December 31, 2002 and 2001, were increased by an unrealized gain of $14.5 million and decreased by an unrealized loss of $31.2 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.
11. | Financial Instruments |
The estimated fair values of the Company’s recorded financial instruments are as follows:
Reorganized Company | Predecessor Company | |||||||||||||||||||||||
December 31, 2003 | December 6, 2003 | December 31, 2002 | ||||||||||||||||||||||
Carrying | Fair | Carrying | Fair | Carrying | Fair | |||||||||||||||||||
Amount | Value | Amount | Value | Amount | Value | |||||||||||||||||||
(In thousands of dollars) | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 6,250 | $ | 6,250 | $ | 5,258 | $ | 5,258 | $ | 14,354 | $ | 14,354 | ||||||||||||
Restricted cash | 4,198 | 4,198 | 3,608 | 3,608 | — | — | ||||||||||||||||||
Long-term debt, including current portion | — | — | 556,500 | 556,500 | 556,500 | 486,250 | ||||||||||||||||||
Note payable — affiliate | 30,000 | 30,000 | 30,000 | 30,000 | 30,000 | 30,000 |
For cash and cash equivalents and restricted cash, the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of long-term debt is estimated based on the quoted market prices for similar issues. The fair value of notes payable — affiliates approximates carrying value as the underlying instruments bear a variable market interest rate.
23
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
12. | Related Party Transactions |
The Company’s subsidiaries have entered into agency agreements with NRG Power Marketing Inc. (“NRG Power Marketing”), a wholly owned subsidiary of NRG Energy. The agreements are effective until December 31, 2030. Under the agreements, NRG Power Marketing will (i) have the exclusive right to manage, market, hedge and sell all power not otherwise sold or committed to by such subsidiaries, (ii) procure, provide and hedge for such subsidiaries all fuel required to operate their respective facilities and (iii) market, sell and purchase all emission credits owned, earned or acquired by such subsidiaries. In addition, NRG Power Marketing will have the exclusive right and obligation to effect the dispatch of the power output from the facilities.
Under the agreements, NRG Power Marketing pays to the subsidiaries gross receipts generated through sales, less costs incurred by NRG Power Marketing relative to its providing services (e.g. transmission and delivery costs, fuel cost, taxes, labor, contract services, etc.). The Company incurs no fees related to these power sales and agency agreements with NRG Power Marketing.
The Company has no employees and has entered into operation and maintenance agreements with subsidiaries of NRG Operating Services, Inc., (“NRG Operating Services”) a wholly owned subsidiary of NRG Energy. The agreements are effective for five years, with options to extend beyond five years. Under the agreements, the NRG Operating Services company operator operates and maintains its respective facility, including (i) coordinating fuel delivery, unloading and inventory, (ii) managing facility spare parts, (iii) meeting external performance standards for transmission of electricity, (iv) providing operating and maintenance consulting and (v) cooperating with and assisting the Company in performing the Company’s obligations under agreements related to its facilities.
Under the agreements, the operator charges an annual fee, and in addition, will be reimbursed for usual and customary costs related to providing the services including plant labor and other operating costs. A demobilization payment will be made if the subsidiary elects not to renew the agreement. There are also incentive fees and penalties based on performance under the approved operating budget, the heat rate and safety.
During the period from December 6, 2003 to December 31, 2003, and the period from January 1, 2003 to December 5, 2003, the Company incurred operating costs billed from NRG Operating Services totaling $13.1 million and $169.7 million, respectively. For the years ended December 31, 2002 and 2001, the Company incurred operating costs billed from NRG Operating Services totaling $147.5 million and $162.1 million, respectively.
The Company’s subsidiaries have entered into agreements with NRG Energy for corporate support and services. The agreements are perpetual in term, unless terminated in writing by a subsidiary. Under the agreements, NRG Energy will provide services, as requested, in areas such as human resources, accounting, finance, treasury, tax, office administration, information technology, engineering, construction management, environmental, legal and safety. Under the agreements, NRG Energy is paid for personnel time as well as out-of-pocket costs. These costs are reflected in general and administrative expenses in the consolidated statements of operations.
For the period from January 1, 2003 to December 5, 2003, and for the period from December 6, 2003 to December 31, 2003, the Company incurred charges from NRG Energy of $9.7 million and $2.5 million, respectively. For the years ended December 31, 2002 and 2001, the Company paid NRG Energy approximately $4.2 million and $5.1 million, respectively, for corporate support and services.
24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
13. | Sales to Significant Customers |
For the period from December 6, 2003 to December 31, 2003, two customers accounted for 60.7% (NYISO) and 28.7% (ISO New England) of total revenues. During the period from January 1, 2003 to December 5, 2003, two customers accounted for 80% (NYISO) and 19.3% (Connecticut Light and Power) of total revenues. During 2002, one customer, NYISO, accounted for 72.5% of NRG Northeast’s gross revenues. During 2001, two customers accounted for 72.5% of NRG Northeast’s total revenues, NYISO (58.4%) and Niagara Mohawk Power Corporation (14.1%). Such amounts include revenues from customers under contract with NRG Power Marketing.
14. | Commitments and Contingencies |
Operating Lease Commitments |
The Company leases certain of its storage space and equipment under operating leases expiring on various dates through 2006. Rental expense under these operating leases was approximately $0, $0.9 million, $0.8 million and $0.9 million for the period from December 6, 2003 to December 31, 2003, for the period from January 1, 2003 to December 5, 2003, and for the years ending December 31, 2002 and 2001, respectively. Future minimum lease commitments under these leases for the years ending after December 31, 2003, are as follows:
(In thousands | ||||
of dollars) | ||||
2004 | $ | 237 | ||
2005 | 222 | |||
2006 | 176 |
Environmental Matters |
The construction and operation of power projects are subject to stringent environmental and safety protection and land use laws and regulations in the United States. These laws and regulations generally require lengthy and complex processes to obtain licenses, permits and approvals from federal, state and local agencies. If such laws and regulations become more stringent and NRG Northeast’s facilities are not exempted from coverage, NRG Northeast could be required to make extensive modifications to further reduce potential environmental impacts. Also, NRG Northeast could be held responsible under environmental and safety laws for the cleanup of pollutant releases at its facilities or at off-site locations where it has sent wastes.
NRG Northeast and its subsidiaries strive to exceed the standards of compliance with applicable environmental and safety regulations. Nonetheless, NRG Northeast expects that future liability under or compliance with environmental and safety requirements could have a material effect on its operations or competitive position. It is not possible at this time to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of possible changes to environmental and safety regulations, regulatory interpretations or enforcement policies. In general, the effect of future laws or regulations is expected to require the addition of pollution control equipment or the imposition of restrictions on NRG Northeast’s operations.
As part of acquiring existing generating assets, NRG Northeast has inherited certain environmental liabilities associated with regulatory compliance and site contamination. Often potential compliance implementation plans are changed, delayed or abandoned due to one or more of the following conditions: (a) extended negotiations with regulatory agencies, (b) a delay in promulgating rules critical to dictating the design of expensive control systems, (c) changes in governmental/regulatory personnel, (d) changes in governmental priorities or (e) selection of a less expensive compliance option than originally envisioned.
25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In response to liabilities associated with these activities, NRG Northeast has established accruals where reasonable estimates of probable liabilities are possible. At December 31, 2003, December 6, 2003 and December 31, 2002, NRG Northeast has established such accruals in the amount of approximately $3.8 million, primarily related to its Arthur Kill and Astoria projects. NRG Northeast adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates are adjusted to reflect new information.
Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at the facility, and may be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by the party in connection with any releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under such laws to be strict (without fault) and joint and several. The cost of investigation, remediation or removal of any hazardous or toxic substances or petroleum products could be substantial. Although NRG Northeast has been involved in on-site contamination matters, to date, NRG Northeast has not been named as a potentially responsible party with respect to any off-site waste disposal matter.
Coal ash is produced as a by-product of coal combustion at the Dunkirk, Huntley, and Somerset Generating Stations. NRG Northeast attempts to direct its coal ash to beneficial uses. Even so, significant amounts of ash are landfilled at on-site and off-site locations. At Dunkirk and Huntley, ash is disposed at landfills owned and operated by NRG Northeast. No material liabilities outside the costs associated with closure, post-closure care and monitoring are expected at these facilities. NRG Northeast maintains financial assurance to cover costs associated with closure, post-closure care and monitoring activities. In the past, NRG Northeast has provided financial assurance via financial test and corporate guarantee. As a result of NRG Energy’s debt restructuring, NRG Northeast was required to re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, such costs currently estimated at approximately $5.8 million. NRG Northeast provided such financial assurance via a trust fund established in this amount on April 30, 2003.
NRG Northeast must also maintain financial assurance for closing interim status Resource Conservation and Recovery Act facilities at the Devon, Middletown, Montville and Norwalk Generating Stations. Previously, NRG Northeast has provided financial assurance via financial test. As a result of NRG Energy’s debt restructuring, NRG Northeast was required to re-establish financial assurance via an instrument requiring complete collateralization of closure and post-closure-related costs, such costs currently estimated at approximately $1.5 million. NRG Northeast provided such financial assurance via a trust fund established in this amount on April 30, 2003.
Historical clean-up liabilities were inherited as a part of acquiring the Somerset, Devon, Middletown, Montville, Norwalk, Arthur Kill and Astoria Generating Stations. NRG Northeast has recently satisfied clean-up obligations associated with the Ledge Road property (inherited as part of the Somerset acquisition). Site contamination liabilities arising under the Connecticut Transfer Act at the Devon, Middletown, Montville and Norwalk Stations have been identified and are currently being refined as part of on-going site investigations. NRG Northeast does not expect to incur material costs associated with completing the investigations at these stations or future work to cover and monitor landfill areas pursuant to the Connecticut requirements. Remedial obligations at the Arthur Kill Generating Station have been established in discussions between NRG Northeast and the New York State DEC and are estimated at $1.0 million. Remedial
26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
investigations are on going at the Astoria Generating Station. At this time, NRG Northeast’s long-term cleanup liability at this site is estimated at $1.5 million.
At December 31, 2003, December 6, 2003 and December 31, 2002, the Company had recorded an accrual in the amount of $2.1 million to cover penalties associated with historical opacity exceedances.
Contractual Commitments |
In connection with the acquisition of certain generating facilities NRG Northeast entered into various long-term transition agreements and standard offer agreements that obligated NRG Northeast to provide its customers, primarily the previous owners of the acquired facilities, with a certain portion of the energy and capacity output of the acquired facilities.
During 1999, NRG Northeast acquired the Huntley and Dunkirk generating facilities from Niagara Mohawk Power Corporation (“NiMo”). In connection with this acquisition, NRG Northeast entered into a four-year agreement with NiMo that requires NRG Northeast to provide to NiMo pursuant to a predetermined schedule fixed quantities of energy and capacity at a fixed price. The contract expired in June 2003 and was recorded as a cash flow hedge for financial reporting purposes (Note 10).
During 1999, the Company acquired certain generating facilities from Connecticut Light and Power Company (“CL&P”). NRG Power Marketing also entered into a four-year standard offer agreement that required NRG Power Marketing to provide to CL&P a portion of its load requirements through the year 2003 at a fixed rate of $43.83 per MWh. Through its agency agreement with the Company, NRG Power Marketing utilizes the capacity available in the Connecticut facilities in order to serve the contract. This agreement ended in December 2003.
During 1999, the Company acquired the Oswego generating facilities from NiMo and entered into a four-year transition power sales contract with NiMo in order to hedge NiMo’s transition to market rates. Under the agreement, NiMo will pay to Oswego Power a fixed monthly price plus start up fees for the right to claim, at a specified delivery point(s), the installed capacity of unit 5 and for the right to exercise an option for an additional 350 MW of installed capacity. This agreement expired in October 2003.
NRG Power Marketing has entered into a wholesale standard offer service agreement with Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation (collectively the “EUA Companies”). Under the agreement, NRG Power Marketing is obligated to provide each of the EUA Companies with firm all-requirements electric service, including capacity, energy, reserves, line losses and related services necessary to serve the aggregate load attributable to retail customers taking standard offer service. The price the EUA Companies pay to NRG Power Marketing for each unit of electricity is a fixed price plus a fuel adjustment factor.
In July 2002, NRG Power Marketing reached a tentative agreement with CL&P that would result in increased compensation to NRG Power Marketing, a supplier of CL&P’s wholesale supply agreement. CL&P filed an emergency petition with the Connecticut Department of Public Utility Control (“DPUC”) asking for approval of a shift of wholesale supply agreement revenues, effective August 1, 2002 through December 31, 2003, that would reallocate 0.7 cents per kilowatt-hour in the wholesale price paid to existing suppliers. On July 26, 2002, the DPUC denied the request of CL&P for an emergency letter ruling (see Note 15 — Regulatory Issues).
NYISO Claims |
In November 2002, the NYISO notified the Company of claims related to New York City mitigation adjustments, general NYISO billing adjustments and other miscellaneous charges related to sales between November 2000 and October 2002. The New York City mitigation adjustments totaled $11.5 million. NRG
27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Northeast did not contest that claim and it has been fully reserved. The general NYISO billing adjustment issue totaled $10.2 million and related to NYISO’s concern that the Company would not have sufficient revenue to cover subsequent revisions to its energy market settlements. At December 31, 2003, the NYISO held $4.5 million in escrow for such future settlement revision.
Guarantees |
In November 2002, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 45,Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor’s fiscal year end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.
In connection with push down accounting, all outstanding guarantees were considered new; accordingly, the Company applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception.
The Company is directly liable for the obligations of certain of its affiliates pursuant to guarantees relating to certain of their performance obligations. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of the Company’s generation facilities, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. The Company also provides performance guarantees to third parties on behalf of NRG Power Marketing in relation to certain of its sales and supply agreements.
At December 31, 2003, the Company’s obligations pursuant to its guarantees of the performance obligations of its affiliates and subsidiaries totaled approximately $7.3 million. No amount has been recorded as a liability as of December 31, 2003.
The nature and details of the Company’s guarantees were as follows:
Guarantee/ | Guarantee/ | |||||||||
Maximum | Maximum | |||||||||
Exposure — | Exposure — | |||||||||
December 6, | December 31, | Nature of | ||||||||
Name | 2003 | 2003 | Guarantee | Expiration Date | Triggering Event | |||||
(In thousands of dollars) | ||||||||||
Astoria/ Arthur Kill | Indeterminate | Indeterminate | Performance | None stated | Nonperformance | |||||
Devon/ Middletown/ Montville/ Norwalk | $2,339 | $2,339 | Performance | None stated | Nonperformance | |||||
NRG Power Marketing, as agent for NRG Northeast | $5,000 | $5,000 | Performance | March 31, 2004 | Nonperformance |
In addition to these guarantees, the Company is a guarantor under the debt issued by the Company’s ultimate parent, NRG Energy. NRG Energy issued $1.25 billion of 8% Second Priority Notes on December 23, 2003, due and payable on December 15, 2013. On January 28, 2004, NRG Energy also issued $475.0 million of Second Priority Notes, under the same terms and indenture as its December 23, 2003 offering.
28
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NRG Energy’s payment obligations under the notes and all related Parity Lien Obligations are guaranteed on an unconditional basis by each of NRG Energy’s current and future restricted subsidiaries, of which the Company is one. The notes are jointly and severally guaranteed by each of the guarantors. The subsidiary guarantees of the notes are secured, on a second priority basis, equally and ratably with any future Parity Lien Debt, by security interests in all of the assets of the guarantors, except certain excluded assets, subject to liens securing parity lien debt and other permitted prior liens.
The Company’s obligations pursuant to its guarantees of the performance, equity and indebtedness obligations were as follows:
Guarantee/ Maximum | Expiration | |||||||||||
Exposure | Nature of Guarantee | Date | Triggering Event | |||||||||
(In thousands of dollars) | ||||||||||||
Project/Subsidiary | ||||||||||||
NRG Energy Second Priority Notes due 2013 | $ | 1,753,000 | Obligations under credit agreement | 2013 | Nonperformance |
Legal Issues |
Consolidated Edison Co. of New York v. Federal Energy Regulatory Commission, Docket No. 01-1503 |
Consolidated Edison and others petitioned the United States Court of Appeals for the District of Columbia Circuit for review of certain FERC orders in which FERC refused to order a redetermination of prices in the NYISO operating reserves markets for the period from January 29, 2000 to March 27, 2000. Petitioners alleged that the prices in the operating reserves markets were unduly elevated by approximately $65 million as a result of market power abuse and operating flaws. On November 7, 2003, the Court issued a decision which found that the NYISO’s method of pricing spinning reserves violated the NYISO tariff. The Court also required FERC to determine whether the exclusion of a generating facility known as Blenheim-Gilboa and resources located in western New York from the non-spinning market also constituted a tariff violation and/ or whether these exclusions enabled NYISO to use its Temporary Extraordinary Procedure authority to require refunds. It is unclear at this time whether FERC will require refunds, much less the amount of any such refunds. If refunds are required, NRG entities which may be affected include NRG Power Marketing, Inc., Astoria Gas Turbine Power LLC and Arthur Kill Power LLC. Although non-NRG-related entities will share responsibility for payment of such refunds, under the petitioners’ theory the cumulative exposure to our above-listed entities could, according to the NYISO, exceed $23 million.
Electricity Consumers Resource Council v. Federal Energy Regulatory Commission, Docket No. 03-1449 |
On December 19, 2003 the Electricity Consumers Resource Council (“ECRC”) appealed to the United States Court of Appeals for the District of Columbia Circuit a recent decision by FERC approving the implementation of a demand curve for the New York installed capacity (“ICAP”) market. ECRC claims that the implementation of the ICAP demand curve violates section 205 of the Federal Power Act because it constitutes unreasonable ratemaking. The Company is a party to this appeal and will contest ECRC’s assertions, but at this time cannot assess what the eventual outcome will be.
Connecticut Light & Power Company v. NRG Power Marketing Inc., Docket No. 3:01-CV-2373 (A WT), pending in the United States District Court, District of Connecticut |
This matter involves a claim by Connecticut Light & Power Company for recovery of amounts allegedly owed for congestion charges under the terms of a Standard Offer Services contract between the parties, dated October 29, 1999. CL&P has served and filed its motion for summary judgment to which NRG Power
29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Marketing, Inc. (“NRG Power Marketing”) filed a response on March 21, 2003. CL&P has withheld approximately $30 million from amounts owed to NRG Power Marketing, claiming that it has the right to offset those amounts under the contract. NRG Power Marketing has counterclaimed seeking to recover those amounts, arguing among other things that CL&P has no rights under the contract to offset them. By reason of the previous bankruptcy stay, the court has not ruled on the pending motion. On November 6, 2003, the parties filed a join stipulation for relief from the automatic stay in order to allow the proceeding to go forward, and NRG Power Marketing is about to supplement the record on the pending summary judgment motion. NRG Power Marketing cannot estimate at this time the likelihood of an unfavorable outcome in this matter.
The State of New York and Erin M. Crotty, as Commissioner of the New York State Department of Environmental Conservation v. Niagara Mohawk Power Corporation, NRG Energy, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power, LLC, NRG Huntley Operations, Inc., Huntley Power, LLC, NRG Northeast Generating, LLC, Northeast Generation Holding, LLC, NRG Eastern, LLC and NRG Operating Services, Inc., United States District Court for the Western District of New York, Civil Action No. 02-CV-0024S |
In January 2002, the New York Department of Environmental Conservation (“DEC”) sued Niagara Mohawk Power Corporation (“NiMo”), NRG Energy and certain of NRG Energy’s affiliates in federal court in New York. The complaint asserted that projects undertaken at NRG Energy’s Huntley and Dunkirk plants by NiMo, the former owner of the facilities, required preconstruction permits pursuant to the Clean Air Act and that the failure to obtain these permits violated federal and state laws. In July, 2002, the NRG entities filed a motion to dismiss. On March 27, 2003 the court dismissed the complaint against the NRG entities with prejudice as to the federal claims and without prejudice as to the state claims. On December 31, 2003, the trial court granted the state’s motion to amend the complaint to again sue NRG Energy and various affiliates in this same action in the federal court in New York, asserting against them violations of operating permits and deficient operating permits at the Huntley and Dunkirk plants. The parties have commenced written discovery, and the court has scheduled the trial on liability issues for March, 2006. For several months, the parties have been engaged in discussions respecting possible settlement of this matter. If the case ultimately is litigated to an unfavorable outcome that could not be addressed otherwise, NRG Energy has estimated that the total investment that would be required to install pollution control devices could be as high as $300 million over a ten to twelve-year period. The NRG entities also could be found responsible for payment of certain penalties and fines.
Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power, LLC, and Dunkirk Power, LLC, Supreme Court, State of New York, County of Onondaga, Case No. 2001-4372 |
NRG Energy has asserted that NiMo is obligated to indemnify it for any related compliance costs associated with resolution of the above enforcement action. NiMo has filed suit in state court in New York seeking a declaratory judgment with respect to its obligations to indemnify NRG Energy under the asset sales agreement. NRG Energy has pending a summary judgment motion on its entitlement to be reimbursed by NIMO for attorneys’ fees incurred in the enforcement action.
Huntley Power LLC |
On April 30, 2003, the Huntley Station submitted a self-disclosure letter to the DEC reporting violations of applicable sulfur in fuel limits, which had occurred during 6 days in March 2003 at the chimneystack serving Huntley Units 63-66. The Huntley Station self-disclosed that the average sulfur emissions rates for those days had been 1.8 lbs/mm BTU, rather that the maximum allowance of 1.7 lbs/mm BTU. NRG Huntley Operations discontinued use of Unit 65 (the only unit utilizing the subject stack at the time) and has kept the remaining three units off line until adherence with the applicable standard is assured. On May 19, 2003, the DEC issued Huntley Power LLC a Notice of Violation. Huntley Power LLC has met with the DEC
30
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
to discuss the circumstances surrounding the event and the appropriate means of resolving the matter. Huntley Power LLC does not know what relief the DEC will seek through an enforcement action. Under applicable provisions of the Environmental Conservation Law, the DEC asserts that it may impose a civil penalty up to $10,000 plus an additional penalty not to exceed $10,000 for each day that a violation continues and may enjoin continuing violations.
Niagara Mohawk Power Corporation v. Dunkirk Power LLC, NRG Dunkirk Operations, Inc. Huntley Power LLC, Huntley Power Operations, Inc., Oswego Power LLC and Oswego Operations Inc., Supreme Court, Erie County, Index No. 1-2000-8681- Station Service Dispute |
On October 2, 2000, plaintiff Niagara Mohawk Power Corporation commenced this action against NRG Energy to recover damages, plus late fees, less payments received, through the date of judgment, as well as any additional amounts due and owing for electric service provided to the Dunkirk Plant after September 18, 2000. Niagara Mohawk claims that NRG Energy has failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999. Plaintiff has alleged breach of contract, suit on account, violation of statutory duty, and unjust enrichment claims. On or about October 23, 2000, NRG Energy served an answer denying liability and asserting affirmative defenses.
After proceeding through discovery, and prior to trial, the parties and the court entered into a Stipulation and Order filed August 9, 2002, consolidating this action with two other actions against the Company’s Huntley and Oswego subsidiaries, both of which cases assert the same claims and legal theories for failure to pay retail tariffs for utility services at those plants.
On October 8, 2002, a Stipulation and Order was filed in the Erie County Clerk’s Office staying this action, pending submission to FERC of some or all of these disputes. NRG Energy cannot make an evaluation of the likelihood of an unfavorable outcome. The cumulative potential loss could amount to some $40 million.
Niagara Mohawk Power Corporation V. Huntley Power LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC, and Oswego Operations, Inc., Case File November 26, 2002 in Federal Energy Regulatory Commission Docket No. EL 03-27-000 |
This is the companion action filed by NiMo at FERC, similarly asserting that NiMo is entitled to receive retail tariff amounts for electric service provided to the Huntley, Dunkirk and Oswego plants. On October 31, 2003, the FERC Trial Staff, a party to the proceedings, filed a reply brief in which it supported and agreed with each position taken by the Company’s facilities. In short, the staff argued that the Company’s facilities: (1) self-supply station power under the NYISO tariff (which took effect on April 1, 2003) in any month during which they produce more energy than they consume and, as such, should not be assessed a retail rate; (2) are connected only to transmission facilities and, as such, at most should only pay NiMo a FERC-approved transmission rate; and (3) should be allowed to net consumption and output even if power is injected into the grid at a different point from which it is drawn off. The Company is presently awaiting a ruling by FERC. At this stage of the proceeding, NRG Energy cannot estimate the likelihood of success on this action. As noted above, the cumulative potential loss could amount to some $40 million.
15. | Regulatory Issues |
New England |
Effective March 1, 2003, ISO-NE implemented its version of standard market design (“SMD”). This change dramatically modifies the New England market structure by incorporating locational marginal pricing (“LMP” — pricing by location rather than on a New England wide basis). Even though NRG Northeast views this change as a significant improvement to the existing market design, NRG Northeast still views the market in New England as incapable of allowing NRG Northeast to recover its costs and provide a reasonable
31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
return on investment. Consequently, on February 26, 2003, Devon Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC and NRG Power Marketing (collectively, the “NRG Filers”) filed and requested a cost of service rate with the Federal Energy Regulatory Commission (“FERC”) for most of its Connecticut fleet, requesting a February 27th effective date. The NRG Filers remain committed to working with ISO-NE, FERC and other stakeholders to continue to improve the New England market that will hopefully make further reliance on a cost of service rate unnecessary. While the NRG Filers have the right to file for such rate treatment, there are no assurances that FERC will grant such rates in the form or amount that the NRG Filers petitioned for in their filing. On March 25, 2003, the FERC issued an order (the “Order”) in response to the NRG Filers’ Joint Motion for Emergency Expedited Issuance of Order by March 17, 2003, in Docket No. ER03-563-000 (the “Emergency Motion”). In the Emergency Motion, the NRG Filers requested that FERC accept the NRG Filers’ reliability must-run agreements and assure the NRG Filers’ recovery of deferred maintenance costs for their New England generating facilities prior to the peak summer season. FERC accepted the NRG Filers’ filing as to the recovery of spring 2003 maintenance costs, subject to refund. FERC’s Order authorizes the ISO New England Inc. to begin collecting these maintenance costs in escrow for the benefit of the NRG Filers as of February 27, 2003. Several intervenors protested the Emergency Motion. FERC did not rule on the remainder of the issues to allow further time to consider protests it received related to the filing.
On April 25, 2003, FERC issued an order rejecting the remaining part of the proposed cost of service agreements including the monthly cost-based payment, citing certain policy determinations regarding cost of service agreements. Rather, FERC instructed ISO-NE to establish temporary bidding rules that would permit selected units (units with capacity factors of 10% or less during 2002), operating within designated congestion areas, such as Connecticut, to raise their bids to allow them the opportunity to recover their fixed and variable costs through the market. In May and June 2003, the ISO-NE revised its market rules to facilitate “peaking unit safe harbor,” or “PUSH,” bidding. On July 24, 2003, FERC clarified that the capacity factor of 10% or less applies to units rather than stations. Therefore, on a unit basis, all of the Company’s facilities qualify to bid under the temporary rules, except Middletown units 2 and 3. The PUSH bidding rule will remain in place until ISO-NE implements locational installed capacity payments, which FERC mandated ISO-NE implement no later than June 1, 2004. On March 1, 2004, ISO-NE filed a locational capacity proposal with FERC. Under the proposal, generators that are needed for reliability and have a capacity factor of 15% or less in 2003 are eligible for a monthly capacity payment of $5.38 per KW-month. Most of the Company’s generators located in Connecticut satisfy this requirement.
Consistent with the Company’s expectations, PUSH bidding has not yielded sufficient revenues to cover all costs for most of the Company’s affected facilities. On January 16, 2004, the Company filed proposed reliability-must-run agreements, or “RMR agreements,” with FERC for the following facilities: Devon station units 11-14, Middletown station and Montville station. The RMR agreement filings requested FERC to establish cost of service rates. On March 18, 2004 FERC granted us a one date suspension of the rates, subject to refund, set the case for hearing and consolidated the case with other similar NRG Energy cases before a settlement judge. In the March 18, 2004 order the FERC ruled that the RMR agreements would expire with the implementation of a locational installed capacity (“LICAP”) market, which is expected to begin on June 1, 2004. On April 14, 2004 we filed a motion for rehearing with FERC requesting the FERC revise the termination date ruling. As of this date, FERC has not responded to the rehearing request.
On February 6, 2004, we filed updated maintenance schedules for the tracking mechanism that provides for the payment by certain NEPOOL participants of third party maintenance expense incurred by NRG Energy. On April 1, 2004 FERC accepted the revised schedules, subject to refund, set the case for hearing and consolidated the case with other similar NRG Energy cases before a settlement judge. In the April 1, 2004 order the FERC ruled that the tracking mechanism would expire with the implementation of a locational installed capacity (“LICAP”) market, which is expected to begin on June 1, 2004. On April 14, 2004 we filed
32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
a motion for rehearing with FERC requesting the FERC revise the termination date ruling. As of this date, FERC has not responded to the rehearing request.
In addition to the facilities noted above, the following of the Company’s quick-start facilities in Connecticut have submitted PUSH bids that have been approved by FERC: Cos Cob, Franklin Drive, Branford, and Torrington. The existing RMR agreement between ISO-NE and the Company covering Devon station units 7 and 8 terminated on September 30, 2003. On October 2, 2003, the Company filed with FERC to extend the existing RMR agreement for the two Devon units. On December 1, 2003, FERC granted a one day suspension of the rates, subject to refund, set the case for hearing and appointed a settlement judge. On February 25, 2004, a FERC sponsored technical conference occurred to review the costs associated with the two Devon units. In the technical conference, the costs relevant to the RMR agreements were discussed. ISO NE has indicated in a letter dated February 27, 2004, that one of the Devon units will no longer be needed for reliability services. Therefore, on May 28, 2004, Devon 8 was retired. On May 28, 2004, a revised RMR Agreement was filed with FERC for Devon 7 facility to account for the cost remaining after the retirement of Devon 8. FERC has not yet acted on this revised RMR filing.
On June 2, 2004, FERC rejected ISO-NE’s LICAP proposal. The FERC ruled that LICAP would not go into effect until January 1, 2006. Until the implementation of LICAP, the existing PUSH bidding rules and existing RMR Agreements would continue. New RMR Agreements must also end when the LICAP market is implemented. Under this ruling the RMR agreements noted above would not terminate on June 1, 2004 but both would terminate when LICAP is implemented on January 1, 2006 or until the facilities are no longer needed for reliability. In the order, FERC also requested ISO-NE to address the question of whether southwest Connecticut should be a separate zone for capacity and energy. Also, in the order, FERC requested an administrative law judge to hold an evidentiary hearing to determine specific components of the LICAP proposal.
In response, ISO-NE, on July 7, 2004 filed a report with FERC requesting that a separate energy and capacity zone for southwest Connecticut be created effective as of January 1, 2006. Presently, there is only one energy and capacity zone for the entire state of Connecticut.
New York |
In April 2003, the NYISO implemented a demand curve in its capacity market and scarcity pricing improvements in its energy market. The New York demand curve eliminated the previous market structure’s tendency to price capacity at either its cap (deficiency rate) or near zero. In a complaint filed with FERC on December 15, 2003, Consolidated Edison Company of New York, Inc. and other load-serving entities alleged that NYISO had used the wrong rate setting methodology to establish prices and rebates in the New York City markets for a portion of the summer capacity auction in 2003, and that this action resulted in overcharges to customers and overpayments to suppliers, including the Company, totaling approximately $21 million, with the Company’s share being approximately $5 million. If the complaint were granted, the Company may be required to refund payments. On December 19, 2003, the Electricity Consumers Resource Council appealed the FERC decision approving the demand curve in the United States Court of Appeals for the District of Columbia Circuit. If the appeal is granted, it could require the elimination of the demand curve for the capacity market. On February 11, 2004, a FERC sponsored settlement conference took place without successful resolution of the issue. The NYISO scarcity pricing improvements have re-introduced some volatility in the New York energy markets when supplies are short.
The NYISO intends to introduce additional changes to its energy market in early 2004, with the implementation of Standard Market Design 2. Although the exact nature of these changes is not known at this time, the Company anticipates the changes to be small, targeted improvements to the NYISO’s present market.
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
16. | Income Taxes (Restatement) |
The Company is included in the consolidated tax return filings as a wholly owned indirect subsidiary of NRG Energy. Reflected in the financial statements and notes below are separate company federal and state tax provisions as if the Company had prepared separate filings. An income tax provision has been established on the accompanying consolidated financial statements as of the earliest period presented in order to reflect income taxes as if the Company filed its own tax return. The Company’s ultimate parent, NRG Energy, does not have a tax allocation agreement with its subsidiaries and prior to January 1, 2003, incomes taxes were not recorded or allocated to non tax paying entities or entities such as the Company which are treated as disregarded entities for tax purposes. Accordingly, the previously issued consolidated financial statements for the years ended December 31, 2002 and 2001, have been restated to include the effects of recording an income tax provision. Because the Company is not a party to a tax sharing agreement, current tax expense (benefit) is recorded as a capital contribution from (distribution to) the Company’s parent. The cumulative effect of recording an income tax provision (benefit) and deferred taxes resulted in recording as of December 31, 2000, a net deferred tax liability of $64.3 million and a reduction to members’ equity of $64.3 million.
The provision (benefit) for income taxes consists of the following:
Reorganized | |||||||||||||||||
Company | Predecessor Company | ||||||||||||||||
For the | For the | ||||||||||||||||
Period from | Period from | ||||||||||||||||
December 6, | January 1, | For the Years Ended | |||||||||||||||
2003 to | 2003 to | December 31, | |||||||||||||||
December 31, | December 5, | ||||||||||||||||
2003 | 2003 | 2002 | 2001 | ||||||||||||||
(In thousands of dollars) | |||||||||||||||||
Current | |||||||||||||||||
Federal | $ | 2,957 | $ | 11,390 | $ | 12,094 | $ | 59,902 | |||||||||
State | 1,183 | 4,555 | 4,837 | 23,959 | |||||||||||||
4,140 | 15,945 | 16,931 | 83,861 | ||||||||||||||
Deferred | |||||||||||||||||
Federal | 229 | (89,837 | ) | (9,622 | ) | 5,422 | |||||||||||
State | 91 | (35,932 | ) | (3,849 | ) | 2,168 | |||||||||||
320 | (125,769 | ) | (13,471 | ) | 7,590 | ||||||||||||
Total income tax expense (benefit) | $ | 4,460 | $ | (109,824 | ) | $ | 3,460 | $ | 91,451 | ||||||||
Effective tax rate | 43.2 | % | 43.0 | % | 89.1 | % | 43.3 | % |
The pre-tax income (loss) was as follows:
Reorganized | ||||||||||||||||
Company | Predecessor Company | |||||||||||||||
For the | For the | |||||||||||||||
Period from | Period from | |||||||||||||||
December 6, | January 1, | For the Years Ended | ||||||||||||||
2003 to | 2003 to | December 31, | ||||||||||||||
December 31, | December 5, | |||||||||||||||
2003 | 2003 | 2002 | 2001 | |||||||||||||
(In thousands of dollars) | ||||||||||||||||
U.S. | $ | 10,306 | $ | (255,511 | ) | $ | 3,885 | $ | 211,255 |
34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The components of the net deferred income tax (assets) liabilities were:
Predecessor | ||||||||||||||
Reorganized Company | Company | |||||||||||||
December 31, | December 6, | December 31, | ||||||||||||
2003 | 2003 | 2002 | ||||||||||||
(In thousands of dollars) | ||||||||||||||
Deferred tax liabilities | ||||||||||||||
Property | $ | — | $ | — | $ | 77,192 | ||||||||
Investments in projects | 3 | 3 | 1 | |||||||||||
Development costs | — | — | 2,555 | |||||||||||
Emissions credits | 90,722 | 90,722 | — | |||||||||||
Other | 1,982 | 1,691 | 7,030 | |||||||||||
Total deferred tax liabilities | 92,707 | 92,416 | 86,778 | |||||||||||
Deferred tax assets | ||||||||||||||
Deferred compensation, accrued vacation and other reserves | 3,236 | 3,261 | 10,268 | |||||||||||
Development costs | 116 | 120 | — | |||||||||||
Intangibles amortization (other than goodwill) | 8,163 | 8,225 | — | |||||||||||
Property | 121,863 | 123,587 | — | |||||||||||
Congestion accrual | 48,035 | 47,811 | — | |||||||||||
Other | 2,406 | 844 | 18,113 | |||||||||||
Total deferred tax assets (before valuation allowance) | 183,819 | 183,848 | 28,381 | |||||||||||
Valuation allowance | — | — | — | |||||||||||
Net deferred tax assets | 183,819 | 183,848 | 28,381 | |||||||||||
Net deferred tax (assets) liabilities | $ | (91,112 | ) | $ | (91,432 | ) | $ | 58,397 | ||||||
The net deferred tax (assets) liabilities consists of:
Predecessor | ||||||||||||
Reorganized Company | Company | |||||||||||
December 31, | December 6, | December 31, | ||||||||||
2003 | 2003 | 2002 | ||||||||||
(In thousands of dollars) | ||||||||||||
Current deferred tax liabilities (assets) | $ | 453 | $ | 442 | $ | (9,709 | ) | |||||
Noncurrent deferred tax (assets) liabilities | (91,565 | ) | (91,874 | ) | 68,106 | |||||||
Net deferred tax (assets) liabilities | $ | (91,112 | ) | $ | (91,432 | ) | $ | 58,397 | ||||
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The effective income tax rates of continuing operations differ from the statutory federal income tax rate of 35% as follows:
Reorganized | ||||||||||||||||||||||||||||||||
Company | Predecessor Company | |||||||||||||||||||||||||||||||
For the | For the | |||||||||||||||||||||||||||||||
Period from | Period from | |||||||||||||||||||||||||||||||
December 6, | January 1, | For the Years Ended | ||||||||||||||||||||||||||||||
2003 to | 2003 to | December 31, | ||||||||||||||||||||||||||||||
December 31, | December 5, | |||||||||||||||||||||||||||||||
2003 | 2003 | 2002 | 2001 | |||||||||||||||||||||||||||||
(In thousands of dollars) | ||||||||||||||||||||||||||||||||
Income (loss) before taxes | $ | 10,306 | $ | (255,511 | ) | $ | 3,885 | $ | 211,255 | |||||||||||||||||||||||
Tax at 35% | 3,607 | 35.0% | (89,429 | ) | 35.0% | 1,360 | 35.0% | 73,939 | 35.0% | |||||||||||||||||||||||
State taxes (net of federal benefit) | 828 | 8.0% | (20,395 | ) | 8.0% | 643 | 16.6% | 16,983 | 8.0% | |||||||||||||||||||||||
Other | 25 | 0.2% | — | 0.0% | 1,457 | 37.5% | 529 | 0.3% | ||||||||||||||||||||||||
Income tax expense (benefit) | $ | 4,460 | 43.2% | $ | (109,824 | ) | 43.0% | $ | 3,460 | 89.1% | $ | 91,451 | 43.3% | |||||||||||||||||||
17. | Reorganization Cash Payments and Receipts |
Cash Payments |
Professional Fees |
During the period from May 14, 2003 to December 5, 2003 and the period from December 6, 2003 to December 31, 2003, the Company made cash payments for professional fees to financial and legal advisors of $1.3 million and $0.2 million, respectively.
Refinancing Activities |
The Company made cash payments of $556.6 million related to the repayment of debt, including accrued interest of $1.1 million upon the emergence from bankruptcy on December 23, 2003, with proceeds from NRG Energy’s recently completed corporate level refinancing. The Company also made cash payments of $8.3 million for a pre-payment settlement upon the early payment of the debt.
Creditor Payments |
Upon the Company’s emergence from bankruptcy, no cash payments were made to creditors during the period from December 6, 2003 to December 31, 2003.
36
REPORT OF INDEPENDENT AUDITORS ON
To the Members of
Our audits of the consolidated financial statements referred to in our report dated March 10, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the period from January 1, 2003 to December 5, 2003 and for the two years ended December 31, 2002, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
/s/ PRICEWATERHOUSECOOPERS LLP | |
PricewaterhouseCoopers LLP |
Minneapolis, Minnesota
37
REPORT OF INDEPENDENT AUDITORS ON
To the Members of
Our audits of the consolidated financial statements referred to in our report dated March 10, 2004, also included an audit of the financial statement schedule listed herein. In our opinion, this financial statement schedule for the period from December 6, 2003 to December 31, 2003 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
/s/ PRICEWATERHOUSECOOPERS LLP | |
PricewaterhouseCoopers LLP |
Minneapolis, Minnesota
38
NRG NORTHEAST GENERATING LLC
SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
Column A | Column B | Column C | Column D | Column E | ||||||||||||||||
Additions | ||||||||||||||||||||
Balance at | Charged to | Charged to | Balance at | |||||||||||||||||
Beginning | Costs and | Other | End of | |||||||||||||||||
Description | of Period | Expenses | Accounts | Deductions | Period | |||||||||||||||
(In thousands) | ||||||||||||||||||||
Allowance for doubtful accounts, deducted from accounts receivable in the balance sheet: | ||||||||||||||||||||
Predecessor Company | ||||||||||||||||||||
Year ended December 31, 2001 | $ | 8,165 | $ | (8,165 | ) | $ | — | $ | — | $ | — | |||||||||
Year ended December 31, 2002 | — | 50,712 | — | — | 50,712 | |||||||||||||||
January 1 - December 5, 2003 | 50,712 | — | — | (50,712 | ) | — |
Reorganized Company | ||||||||||||||||||||
December 6 - December 31, 2003 | — | — | — | — | — |
39