We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of September 30, 2007March 31, 2008 and the related consolidated statements of income, and comprehensive income and cash flows for each of the three-month and nine-month periods ended September 30, 2007March 31, 2008 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006.2007. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006,2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, preferred stock, and of cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement benefit plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 9, Note 3, Note 2(K)2(G) and Note 12 to the consolidated financial statements) dated February 27, 2007, except as to Note 2(H) and Note 16, which are as of September 14, 2007,28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006,2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
Financial Matters
FIRSTENERGY CORP. | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In millions except, | |
| | per share amounts) | |
REVENUES: | | | | | | |
Electric utilities | | $ | 2,913 | | | $ | 2,659 | |
Unregulated businesses | | | 364 | | | | 314 | |
Total revenues* | | | 3,277 | | | | 2,973 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Fuel and purchased power | | | 1,328 | | | | 1,121 | |
Other operating expenses | | | 800 | | | | 749 | |
Provision for depreciation | | | 164 | | | | 156 | |
Amortization of regulatory assets | | | 258 | | | | 251 | |
Deferral of new regulatory assets | | | (105 | ) | | | (144 | ) |
General taxes | | | 215 | | | | 203 | |
Total expenses | | | 2,660 | | | | 2,336 | |
| | | | | | | | |
OPERATING INCOME | | | 617 | | | | 637 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Investment income | | | 17 | | | | 33 | |
Interest expense | | | (179 | ) | | | (185 | ) |
Capitalized interest | | | 8 | | | | 5 | |
Total other expense | | | (154 | ) | | | (147 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 463 | | | | 490 | |
| | | | | | | | |
INCOME TAXES | | | 187 | | | | 200 | |
| | | | | | | | |
NET INCOME | | $ | 276 | | | $ | 290 | |
| | | | | | | | |
| | | | | | | | |
BASIC EARNINGS PER SHARE OF COMMON STOCK | | $ | 0.91 | | | $ | 0.92 | |
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | | 304 | | | | 314 | |
| | | | | | | | |
DILUTED EARNINGS PER SHARE OF COMMON STOCK | | $ | 0.90 | | | $ | 0.92 | |
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | | 307 | | | | 316 | |
| | | | | | | | |
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | $ | 0.55 | | | $ | 0.50 | |
| | | | | | | | |
| | | | | | | | |
* Includes $114 million and $108 million of excise tax collections in the first quarter of 2008 and 2007, respectively. | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral | |
part of these statements. | | | | | | | | |
On July 13, 2007, FGCO completed a $1.3 billion sale and leaseback transaction for its 779 MW interest in Unit 1 of the Bruce Mansfield Plant. The terms of the agreement provide for an approximate 33-year lease of the unit. FirstEnergy used the net, after-tax proceeds of approximately $1.2 billion to repay short-term debt that was used to fund its recent $900 million share repurchase program and $300 million pension contribution. FES’ registration obligations under the registration rights agreement applicable to the transaction were satisfied in September 2007, at which time the transaction was classified as an operating lease under GAAP for FES and FirstEnergy. The $1.1 billion book gain from the transaction was deferred and will be amortized ratably over the lease term. FGCO continues to operate the plant under the terms of the agreement.FIRSTENERGY CORP. | |
| | | | | | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | | | | | |
| | (In millions) | |
| | | | | | |
NET INCOME | | $ | 276 | | | $ | 290 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (20 | ) | | | (11 | ) |
Unrealized gain (loss) on derivative hedges | | | (13 | ) | | | 21 | |
Change in unrealized gain on available-for-sale securities | | | (58 | ) | | | 17 | |
Other comprehensive income (loss) | | | (91 | ) | | | 27 | |
Income tax expense (benefit) related to other comprehensive income | | | (33 | ) | | | 9 | |
Other comprehensive income (loss), net of tax | | | (58 | ) | | | 18 | |
| | | | | | | | |
COMPREHENSIVE INCOME | | $ | 218 | | | $ | 308 | |
| | | | | | | | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral | |
part of these statements. | | | | | | | | |
On August 30, 2007, Penelec issued $300 million of 6.05% unsecured senior notes due 2017. A portion of the net proceeds from the issuance and sale of the senior notes was used to fund the repurchase of $200 million of Penelec’s common stock from FirstEnergy. The remainder was used to repay short-term borrowings and for general corporate purposes.35
FIRSTENERGY CORP. | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In millions) | |
ASSETS | | | | | | |
| | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 70 | | | $ | 129 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $34 million and | | | | | | | | |
$36 million, respectively, for uncollectible accounts) | | | 1,264 | | | | 1,256 | |
Other (less accumulated provisions of $24 million and | | | | | | | | |
$22 million, respectively, for uncollectible accounts) | | | 159 | | | | 165 | |
Materials and supplies, at average cost | | | 570 | | | | 521 | |
Prepayments and other | | | 307 | | | | 159 | |
| | | 2,370 | | | | 2,230 | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
In service | | | 24,894 | | | | 24,619 | |
Less - Accumulated provision for depreciation | | | 10,454 | | | | 10,348 | |
| | | 14,440 | | | | 14,271 | |
Construction work in progress | | | 1,465 | | | | 1,112 | |
| | | 15,905 | | | | 15,383 | |
INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 2,025 | | | | 2,127 | |
Investments in lease obligation bonds | | | 679 | | | | 717 | |
Other | | | 714 | | | | 754 | |
| | | 3,418 | | | | 3,598 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 5,606 | | | | 5,607 | |
Regulatory assets | | | 3,797 | | | | 3,945 | |
Pension assets | | | 723 | | | | 700 | |
Other | | | 596 | | | | 605 | |
| | | 10,722 | | | | 10,857 | |
| | $ | 32,415 | | | $ | 32,068 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 2,183 | | | $ | 2,014 | |
Short-term borrowings | | | 1,649 | | | | 903 | |
Accounts payable | | | 754 | | | | 777 | |
Accrued taxes | | | 416 | | | | 408 | |
Other | | | 1,167 | | | | 1,046 | |
| | | 6,169 | | | | 5,148 | |
CAPITALIZATION: | | | | | | | | |
Common stockholders’ equity- | | | | | | | | |
Common stock, $.10 par value, authorized 375,000,000 shares- | | | | | | | | |
304,835,407 shares outstanding. | | | 31 | | | | 31 | |
Other paid-in capital | | | 5,472 | | | | 5,509 | |
Accumulated other comprehensive loss | | | (108 | ) | | | (50 | ) |
Retained earnings | | | 3,596 | | | | 3,487 | |
Total common stockholders' equity | | | 8,991 | | | | 8,977 | |
Long-term debt and other long-term obligations | | | 8,332 | | | | 8,869 | |
| | | 17,323 | | | | 17,846 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 2,717 | | | | 2,671 | |
Asset retirement obligations | | | 1,287 | | | | 1,267 | |
Deferred gain on sale and leaseback transaction | | | 1,052 | | | | 1,060 | |
Power purchase contract loss liability | | | 682 | | | | 750 | |
Retirement benefits | | | 911 | | | | 894 | |
Lease market valuation liability | | | 643 | | | | 663 | |
Other | | | 1,631 | | | | 1,769 | |
| | | 8,923 | | | | 9,074 | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 32,415 | | | $ | 32,068 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these | |
balance sheets. | | | | | | | | |
FIRSTENERGY CORP. | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In millions) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 276 | | | $ | 290 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 164 | | | | 156 | |
Amortization of regulatory assets | | | 258 | | | | 251 | |
Deferral of new regulatory assets | | | (105 | ) | | | (144 | ) |
Nuclear fuel and lease amortization | | | 26 | | | | 26 | |
Deferred purchased power and other costs | | | (59 | ) | | | (116 | ) |
Deferred income taxes and investment tax credits, net | | | 89 | | | | 53 | |
Investment impairment | | | 16 | | | | 5 | |
Deferred rents and lease market valuation liability | | | 4 | | | | (25 | ) |
Accrued compensation and retirement benefits | | | (142 | ) | | | (65 | ) |
Commodity derivative transactions, net | | | 8 | | | | 1 | |
Gain on asset sales | | | (37 | ) | | | - | |
Cash collateral received | | | 8 | | | | 6 | |
Pension trust contribution | | | - | | | | (300 | ) |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (6 | ) | | | (155 | ) |
Materials and supplies | | | (17 | ) | | | 15 | |
Prepayments and other current assets | | | (115 | ) | | | (74 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (23 | ) | | | (108 | ) |
Accrued taxes | | | (5 | ) | | | 73 | |
Accrued interest | | | 91 | | | | 86 | |
Electric service prepayment programs | | | (19 | ) | | | (17 | ) |
Other | | | (56 | ) | | | (15 | ) |
Net cash provided from (used for) operating activities | | | 356 | | | | (57 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | - | | | | 250 | |
Short-term borrowings, net | | | 746 | | | | 1,139 | |
Redemptions and Repayments- | | | | | | | | |
Common stock | | | - | | | | (891 | ) |
Long-term debt | | | (368 | ) | | | (13 | ) |
Net controlled disbursement activity | | | 6 | | | | 12 | |
Stock-based compensation tax benefit | | | 11 | | | | 8 | |
Common stock dividend payments | | | (168 | ) | | | (159 | ) |
Net cash provided from financing activities | | | 227 | | | | 346 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (711 | ) | | | (296 | ) |
Proceeds from asset sales | | | 50 | | | | - | |
Sales of investment securities held in trusts | | | 361 | | | | 273 | |
Purchases of investment securities held in trusts | | | (384 | ) | | | (294 | ) |
Cash investments | | | 58 | | | | 25 | |
Other | | | (16 | ) | | | 2 | |
Net cash used for investing activities | | | (642 | ) | | | (290 | ) |
| | | | | | | | |
Net decrease in cash and cash equivalents | | | (59 | ) | | | (1 | ) |
Cash and cash equivalents at beginning of period | | | 129 | | | | 90 | |
Cash and cash equivalents at end of period | | $ | 70 | | | $ | 89 | |
| | | | | | | | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. | |
On October 4, 2007, FGCO and NGC closed on the issuance of $427 million of pollution control revenue bonds (PCRBs). Proceeds from the issuance will be used to redeem, during the fourth quarter of 2007, an equal amount of outstanding PCRBs originally issued on behalf of the Ohio Companies. This transaction brings the total amount of PCRBs transferred from the Ohio Companies and Penn to FGCO and NGC to approximately $1.9 billion, with approximately $265 million remaining to be transferred. The transfer of these PCRBs supports the intra-system generation asset transfer that was completed in 2005.
FIRSTENERGY’S BUSINESS
FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through three core business segments (see Results of Operations).FIRSTENERGY SOLUTIONS CORP.
Energy Delivery Services transmits and distributes electricity through FirstEnergy's eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to non-shopping retail customers under the PLR obligations in its Pennsylvania and New Jersey franchise areas. Its net income reflects the commodity costs of securing electricity from the competitive energy services segment under partial requirements purchased power agreements with FES and non-affiliated power suppliers, including associated transmission costs. ANALYSIS OF RESULTS OF OPERATIONS |
· | Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the PLR requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates FirstEnergy's generating facilities and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.
|
FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through its subsidiaries, FGCO and NGC, owns or leases and operates FirstEnergy’s fossil and hydroelectric generation facilities and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
· | Ohio Transitional Generation Services supplies the electric power needs of non-shopping customers under the PLR requirements of FirstEnergy's Ohio Companies. The segment's net income is primarily derived from electric generation sales revenues less the cost of power purchased from the competitive energy services segmentFES’ revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through a full-requirements PSA arrangement with FES, including net transmission and ancillary costs charged by MISO to deliver energy to retail customers.
|
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 14 to the consolidated financial statements. Net income by major business segment was as follows:
| | Three Months Ended September 30, | | Nine Months Ended September 30, | |
| | | | Increase | | | | Increase | |
| | 2007 | | 2006 | | (Decrease) | | 2007 | | 2006 | | (Decrease) | |
| | (In millions, except per share amounts) | |
Net Income (Loss) | | | | | | | | | | | | | |
By Business Segment: | | | | | | | | | | | | | |
Energy delivery services | | $ | 269 | | $ | 280 | | $ | (11 | ) | $ | 695 | | $ | 702 | | $ | (7 | ) |
Competitive energy services | | | 148 | | | 169 | | | (21 | ) | | 388 | | | 302 | | | 86 | |
Ohio transitional generation services | | | 16 | | | 27 | | | (11 | ) | | 69 | | | 88 | | | (19 | ) |
Other and reconciling adjustments* | | | (20 | ) | | (22 | ) | | 2 | | | (111 | ) | | (113 | ) | | 2 | |
Total | | $ | 413 | | $ | 454 | | $ | (41 | ) | $ | 1,041 | | $ | 979 | | $ | 62 | |
| | | | | | | | | | | | | | | | | | | |
Basic Earnings Per Share: | | | | | | | | | | | | | | | | | | | |
Income from continuing operations | | $ | 1.36 | | $ | 1.40 | | $ | (0.04 | ) | $ | 3.39 | | $ | 3.00 | | $ | 0.39 | |
Discontinued operations | | | - | | | 0.01 | | | (0.01 | ) | | - | | | (0.01 | ) | | 0.01 | |
Net earnings per basic share | | $ | 1.36 | | $ | 1.41 | | $ | (0.05 | ) | $ | 3.39 | | $ | 2.99 | | $ | 0.40 | |
| | | | | | | | | | | | | | | | | | | |
Diluted Earnings Per Share: | | | | | | | | | | | | | | | | | | | |
Income from continuing operations | | $ | 1.34 | | $ | 1.39 | | $ | (0.05 | ) | $ | 3.35 | | $ | 2.98 | | $ | 0.37 | |
Discontinued operations | | | - | | | 0.01 | | | (0.01 | ) | | - | | | (0.01 | ) | | 0.01 | |
Net earnings per diluted share | | $ | 1.34 | | $ | 1.40 | | $ | (0.06 | ) | $ | 3.35 | | $ | 2.97 | | $ | 0.38 | |
| | | | | | | | | | | | | | | | | | | |
* Represents other operating segments and reconciling adjustments including interest expense on holding company debt and corporate support services revenues and expenses.
Summary of Results of Operations – Third Quarter of 2007 Compared with the Third Quarter of 2006
Financial results for FirstEnergy's major business segments in the third quarter of 2007 and 2006 were as follows:
| | | | | | | | Ohio | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | Other and | | | | |
| | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | |
Third Quarter 2007 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | (In millions) | | | | | | | | | | | | | |
Revenues: | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | |
Electric | | $ | 2,340 | | | $ | 338 | | | $ | 716 | | | $ | - | | | $ | 3,394 | |
Other | | | 180 | | | | 32 | | | | 7 | | | | 28 | | | | 247 | |
Internal | | | - | | | | 806 | | | | - | | | | (806 | ) | | | - | |
Total Revenues | | | 2,520 | | | | 1,176 | | | | 723 | | | | (778 | ) | | | 3,641 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 1,116 | | | | 554 | | | | 631 | | | | (806 | ) | | | 1,495 | |
Other operating expenses | | | 436 | | | | 264 | | | | 80 | | | | (24 | ) | | | 756 | |
Provision for depreciation | | | 102 | | | | 51 | | | | - | | | | 9 | | | | 162 | |
Amortization of regulatory assets | | | 279 | | | | - | | | | 9 | | | | - | | | | 288 | |
Deferral of new regulatory assets | | | (82 | ) | | | - | | | | (25 | ) | | | - | | | | (107 | ) |
General taxes | | | 166 | | | | 26 | | | | 1 | | | | 4 | | | | 197 | |
Total Expenses | | | 2,017 | | | | 895 | | | | 696 | | | | (817 | ) | | | 2,791 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 503 | | | | 281 | | | | 27 | | | | 39 | | | | 850 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | 58 | | | | 5 | | | | - | | | | (33 | ) | | | 30 | |
Interest expense | | | (120 | ) | | | (44 | ) | | | - | | | | (39 | ) | | | (203 | ) |
Capitalized interest | | | 3 | | | | 5 | | | | - | | | | 1 | | | | 9 | |
Total Other Expense | | | (59 | ) | | | (34 | ) | | | - | | | | (71 | ) | | | (164 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations | | | | | | | | | | | | | | | | | |
Before Income Taxes | | | 444 | | | | 247 | | | | 27 | | | | (32 | ) | | | 686 | |
Income taxes | | | 175 | | | | 99 | | | | 11 | | | | (12 | ) | | | 273 | |
Net Income | | $ | 269 | | | $ | 148 | | | $ | 16 | | | $ | (20 | ) | | $ | 413 | |
| | | | | | | | Ohio | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | Other and | | | | |
| | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | |
Third Quarter 2006 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | (In millions) | |
Revenues: | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | |
Electric | | $ | 2,120 | | | $ | 313 | | | $ | 682 | | | $ | - | | | $ | 3,115 | |
Other | | | 186 | | | | 40 | | | | 8 | | | | 15 | | | | 249 | |
Internal | | | - | | | | 762 | | | | - | | | | (762 | ) | | | - | |
Total Revenues | | | 2,306 | | | | 1,115 | | | | 690 | | | | (747 | ) | | | 3,364 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 960 | | | | 515 | | | | 604 | | | | (762 | ) | | | 1,317 | |
Other operating expenses | | | 468 | | | | 218 | | | | 76 | | | | (4 | ) | | | 758 | |
Provision for depreciation | | | 97 | | | | 49 | | | | - | | | | 7 | | | | 153 | |
Amortization of regulatory assets | | | 237 | | | | - | | | | 6 | | | | - | | | | 243 | |
Deferral of new regulatory assets | | | (107 | ) | | | - | | | | (46 | ) | | | - | | | | (153 | ) |
General taxes | | | 157 | | | | 21 | | | | 5 | | | | 4 | | | | 187 | |
Total Expenses | | | 1,812 | | | | 803 | | | | 645 | | | | (755 | ) | | | 2,505 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 494 | | | | 312 | | | | 45 | | | | 8 | | | | 859 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | 80 | | | | 18 | | | | - | | | | (52 | ) | | | 46 | |
Interest expense | | | (109 | ) | | | (52 | ) | | | - | | | | (24 | ) | | | (185 | ) |
Capitalized interest | | | 4 | | | | 3 | | | | - | | | | - | | | | 7 | |
Subsidiaries' preferred stock dividends | | | (2 | ) | | | - | | | | - | | | | - | | | | (2 | ) |
Total Other Expense | | | (27 | ) | | | (31 | ) | | | - | | | | (76 | ) | | | (134 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations | | | | | | | | | | | | | | | | | | | | |
Before Income Taxes | | | 467 | | | | 281 | | | | 45 | | | | (68 | ) | | | 725 | |
Income taxes | | | 187 | | | | 112 | | | | 18 | | | | (44 | ) | | | 273 | |
Income from continuing operations | | | 280 | | | | 169 | | | | 27 | | | | (24 | ) | | | 452 | |
Discontinued operations | | | - | | | | - | | | | - | | | | 2 | | | | 2 | |
Net Income | | $ | 280 | | | $ | 169 | | | $ | 27 | | | $ | (22 | ) | | $ | 454 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Changes Between Third Quarter 2007 and | | | | | | | | | | | | | | | | | |
Third Quarter 2006 Financial Results | | | | | | | | | | | | | | | | | | | | |
Increase (Decrease) | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Revenues: | | | | | | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | | | | | | |
Electric | | $ | 220 | | | $ | 25 | | | $ | 34 | | | $ | - | | | $ | 279 | |
Other | | | (6 | ) | | | (8 | ) | | | (1 | ) | | | 13 | | | | (2 | ) |
Internal | | | - | | | | 44 | | | | - | | | | (44 | ) | | | - | |
Total Revenues | | | 214 | | | | 61 | | | | 33 | | | | (31 | ) | | | 277 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 156 | | | | 39 | | | | 27 | | | | (44 | ) | | | 178 | |
Other operating expenses | | | (32 | ) | | | 46 | | | | 4 | | | | (20 | ) | | | (2 | ) |
Provision for depreciation | | | 5 | | | | 2 | | | | - | | | | 2 | | | | 9 | |
Amortization of regulatory assets | | | 42 | | | | - | | | | 3 | | | | - | | | | 45 | |
Deferral of new regulatory assets | | | 25 | | | | - | | | | 21 | | | | - | | | | 46 | |
General taxes | | | 9 | | | | 5 | | | | (4 | ) | | | - | | | | 10 | |
Total Expenses | | | 205 | | | | 92 | | | | 51 | | | | (62 | ) | | | 286 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 9 | | | | (31 | ) | | | (18 | ) | | | 31 | | | | (9 | ) |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | (22 | ) | | | (13 | ) | | | - | | | | 19 | | | | (16 | ) |
Interest expense | | | (11 | ) | | | 8 | | | | - | | | | (15 | ) | | | (18 | ) |
Capitalized interest | | | (1 | ) | | | 2 | | | | - | | | | 1 | | | | 2 | |
Subsidiaries' preferred stock dividends | | | 2 | | | | - | | | | - | | | | - | | | | 2 | |
Total Other Expense | | | (32 | ) | | | (3 | ) | | | - | | | | 5 | | | | (30 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations | | | | | | | | | | | | | | | | | | | | |
Before Income Taxes | | | (23 | ) | | | (34 | ) | | | (18 | ) | | | 36 | | | | (39 | ) |
Income taxes | | | (12 | ) | | | (13 | ) | | | (7 | ) | | | 32 | | | | - | |
Income from continuing operations | | | (11 | ) | | | (21 | ) | | | (11 | ) | | | 4 | | | | (39 | ) |
Discontinued operations | | | - | | | | - | | | | - | | | | (2 | ) | | | (2 | ) |
Net Income | | $ | (11 | ) | | $ | (21 | ) | | $ | (11 | ) | | $ | 2 | | | $ | (41 | ) |
Energy Delivery Services – Third Quarter 2007 Compared to Third Quarter 2006
Net income decreased $11 million (or 4%) to $269 million in the third quarter of 2007 compared to $280 million in the third quarter of 2006, primarily due to increased purchased power costsarrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and higher amortizationTE to supply each of regulatory assets, partially offset by higher revenues and reduced other operating expenses.
Revenues –
The increase in total revenues resulted from the following sources:
| | Three Months Ended | | | |
| | September 30, | | | |
Revenues by Type of Service | | 2007 | | 2006 | | Increase (Decrease) | |
| | (In millions) | |
| | | | | | | | | | ) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
The change in distribution KWH deliveries by customer class are summarized in the following table:
Electric Distribution KWH Deliveries
| | |
| | | |
| | | |
| | | |
Total Distribution KWH Deliveries
| | | |
The reduction in distribution services revenues was primarily due to distribution rate decreases fortheir PLR obligations through 2008, at prices that take into consideration their respective PUCO-authorized billing rates. FES also has a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective PLR obligations at fixed prices through 2010. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement. FES also supplies the majority of the PLR requirements of Penn at market-based rates as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).competitive solicitation conducted by Penn. FES’ existing contractual obligations to Penn expire on May 31, 2008, but could continue if FES successfully bids in future competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.
The following table summarizes the price and volume factors contributing to the $201 million increase in generation revenues in the third quarterResults of 2007 compared to 2006:
Sources of Change in Generation Revenues | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 5.9% decrease in sales volumes | | $ | (50 | ) |
Change in prices | | | | |
| | | | |
Wholesale: | | | | |
Effect of 95% increase in sales volumes | | | 86 | |
Change in prices | | | | |
| | | | |
Net Increase in Generation Sales | | $ | 201 | |
The increase in retail generation prices during the third quarter of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.
Transmission revenues increased $42 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect to current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).
Operations
Expenses –
TheIn the first three months of 2008, net increases in revenues discussed above were offset by a $205income decreased to $90 million increase in expenses due to the following:
| · | Purchased power costs were $157 million higher in the third quarter of 2007 due to higher unit costs, increased volumes purchased and a decrease in purchased power cost deferrals. The increased unit costs reflected the effect of higher JCP&L purchased power unit prices resulting from the BGS auction. The increased KWH purchases in 2007 primarily resulted from more sales to the PJM wholesale market by Met-Ed and Penelec. Deferred purchased power costs were lower due to higher generation charges to JCP&L customers. The following table summarizes the sources of changes in purchased power costs:
|
Sources of Change in Purchased Power | | | |
| | (In millions) | |
| | | | |
Purchased Power: | | | | |
Change due to increased unit costs | | $ | 97 | |
Change due to increased volume | | | 42 | |
Decrease in NUG costs deferred | | | 18 | |
Net Increase in Purchased Power Costs | | $ | 157 | |
| · | Amortization of regulatory assets increased $42 million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC revenues for JCP&L as discussed above.
|
| · | The deferral of new regulatory assets during the third quarter of 2007 was $25 million lower than in 2006 due in part to $40 million in reduced deferrals of transmission related PJM costs. The reduced deferral in the third quarter of 2007 was attributable to greater recovery of PJM costs in the 2007 period under the transmission service charge rider (see Outlook – State Regulatory Matters - Pennsylvania). The reduction in deferred PJM costs was partially offset by higher distribution deferrals under the RCP. |
· Other operating expenses decreased $32 million, partially offsetting the above increases, due to the net effects of:
- | A decrease of $21 million in transmission expenses caused by the expiration of transmission hedging instruments and reduced financial transmission rights revenue. |
-A decrease in operation and maintenance expenses of $19 million primarily due to lower employee labor and benefit costs ($10 million) lower uncollectible
expenses related to customer receivables ($4 million) and lower leased equipment costs ($3 million).
- An increase in miscellaneous operating expenses ($9 million) resulting from increased corporate support billings from FESC.
Other Expense –
Other expense increased $32 million in 2007 compared to the third quarter of 2006 primarily due to lower investment income of $22 million resulting from the repayment of notes receivable from affiliates since the third quarter of 2006, and increased interest expense of $11 million related in part to new debt issuances by CEI, JCP&L and Penelec.
Competitive Energy Services – Third Quarter 2007 Compared to Third Quarter 2006
Net income for this segment was $148 million in the third quarter of 2007 compared to $169$103 million in the same period last year. Increasedin 2007. The decrease in net income was primarily due to higher fuel and purchased power costs and other operating expenses, partially offset by lower purchased power costs and higher revenues, led to the $21 million decrease.revenues.
Revenues
Revenues –
Total revenues increased $61by $81 million in the third quarterfirst three months of 20072008 compared to the same period in 2006. This increase primarily resulted2007 due to increases in revenues from increasednon-affiliated and affiliated wholesale sales, to the Ohio Companies, Met-Ed and Penelec as well as higher unit prices from the Ohio Companies. These increases were partially offset by lower retail generation sales. Retail generation sales to Pennrevenues decreased as a result of decreased sales in the implementation of its competitive solicitation processPJM market partially offset by increased sales in 2007. Higher retail revenues resulted from increased KWHthe MISO market. Lower sales in the PJM market were primarily due to lower contract renewals for commercial and industrial customers. Greater sales in the MISO market were primarily due to FES’ capturing more shopping customers in Penn’s service territory, partially offset by reduced volume in the PJM market.
Increased non-affiliatedlower customer usage. Non-affiliated wholesale revenues primarily reflected capacity revenues earned in PJM’s new capacity market. The capacity market was initiated in June 2007 to encourage the developmentincreased as a result of capacity resources in PJM. Lowermore generation available for wholesale sales to non-affiliates partially offset these increases due to decreased generation available for the non-affiliated wholesale market.
The increase in reported segment revenues resulted from the following sources:
| | Three Months Ended | | | |
| | September 30, | | Increase | |
Revenues By Type of Service | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
Non-Affiliated Generation Sales: | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Total Non-Affiliated Generation Sales | | | | | | | | | | |
Affiliated Generation Sales | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
| | Increase | |
Source of Change in Non-Affiliated Generation Sales | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 0.2% increase in sales volumes | | $ | 1 | |
Change in prices | | | | |
| | | | |
Wholesale: | | | | |
Effect of 11% decrease in sales volumes | | | (15 | ) |
Change in prices | | | | |
| | | | |
Net Increase in Non-Affiliated Generation Sales | | | | |
| | | |
| | | |
Source of Change in Affiliated Generation Sales | | | |
| | (In millions) | |
Ohio Companies: | | | | |
Effect of 2% increase in sales volumes | | $ | 12 | |
Change in prices | | | | |
| | | | |
Pennsylvania Companies: | | | | |
Effect of 8% increase in sales volumes | | | 13 | |
Change in prices | | | | |
| | | | |
Net Increase in Affiliated Generation Sales | | | | |
Expenses -
Total expenses were $92 million higher in the third quarter of 2007 due to the net effect of the following factors:
| · | Purchased power costs increased $55 million due primarily to higher volumes for replacement power related to a forced outage at Perry in the third quarter of 2007 and higher market prices. The sources of change in purchased power costs are summarized in the following table: |
Source of Change in Purchased Power | | Increase | |
| | (In millions) | |
| | | | |
Change due to increased unit costs | | $ | 14 | |
Change due to 18% increase in volume | | | 31 | |
Change due to new PJM capacity market | | | 10 | |
Total Increase in Purchased Power Costs | | $ | 55 | |
| · | Fuel costs were $16 million lower primarily due to lower coal prices ($8 million), reduced emission allowance costs ($5 million) and a decrease in natural gas consumed resulting from reduced combustion turbine generation ($2 million). |
| · | Fossil operating costs were $32 million higher in 2007 primarily due to the absence of gains on the sales of emissions allowances recognized in 2006. |
| · | Miscellaneous operating expenses were $13 million higher primarily due to increased contractor expenses related to the Beaver Valley Unit 1 outage and corporate support billings from FESC. |
| · | Higher general taxes of $5 million resulted from increased gross receipts taxes and property taxes. |
Ohio Transitional Generation Services – Third Quarter 2007 Compared to Third Quarter 2006
Net income decreased $11 million to $16 million in the third quarter of 2007 compared to $27 million in the same period last year. Higher purchased power costs were partially offset by higher generation revenues.
Revenues –non-affiliates.
The increase in reported segment revenues resulted from the following sources:
| | Three Months Ended | | | |
| | September 30, | | | |
Revenues by Type of Service | | 2007 | | 2006 | | Increase | |
| | (In millions) | |
| | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The following table summarizes the price and volume factors contributing to the increase in generationaffiliated company wholesale sales revenues from retail customers:
Source of Change in Generation Sales | | | |
| | (In millions) | |
Effect of 2% increase in sales volumes | | $ | 10 | |
Change in prices | | | | |
Total Increase in Retail Generation Sales | | | | |
| | | | |
The increase in generation sales was primarily due to higher weather-related usage in the third quarter of 2007 resulting from slightly higher than normal cooling degree days during the period. Average prices increased slightly due to customer usage patterns and higher composite unit prices for returning customers.
Expenses -
Purchased power costs were $27 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costs are summarized in the following table:
Source of Change in Purchased Power | | Increase | |
| | (In millions) | |
Purchases from non-affiliates: | | | | |
Change due to increased unit costs | | $ | - | |
Change due to volume | | | 1 | |
| | | 1 | |
Purchases from FES: | | | | |
Change due to increased unit costs | | | 14 | |
Change due to volume | | | 12 | |
| | | 26 | |
Total Increase in Purchased Power Costs | | $ | 27 | |
The increase in volumes purchased was due to the higher retail generation sales requirements. The higher unit costs resulted from the provision of the full-requirements PSA with FES under which purchased power unit costs reflected the increases in the Ohio Companies’ retail generation sales unit prices.
The deferral of new regulatory assets decreased by $21 million in the third quarter of 2007 compared to 2006 due to reduced cost deferrals under the Ohio Companies’ RCP.
Other – Third Quarter 2007 Compared to Third Quarter 2006
FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $2 million increase in FirstEnergy’s net income in the third quarter of 2007 compared to the same quarter of 2006. The increase was primarily due to the sale of First Communications ($13 million, net of taxes) offset by higher financing costs of $14 million.
Summary of Results of Operations – First Nine Months of 2007 Compared with the First Nine Months of 2006
Financial results for FirstEnergy's major business segments in the first nine months of 2007 and 2006 were as follows:
| | | | | | | | Ohio | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | Other and | | | | |
| | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | |
First Nine Months 2007 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | (In millions) | |
Revenues: | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | |
Electric | | $ | 6,148 | | | $ | 973 | | | $ | 1,942 | | | $ | - | | | $ | 9,063 | |
Other | | | 507 | | | | 116 | | | | 26 | | | | 11 | | | | 660 | |
Internal | | | - | | | | 2,210 | | | | - | | | | (2,210 | ) | | | - | |
Total Revenues | | | 6,655 | | | | 3,299 | | | | 1,968 | | | | (2,199 | ) | | | 9,723 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 2,838 | | | | 1,461 | | | | 1,712 | | | | (2,210 | ) | | | 3,801 | |
Other operating expenses | | | 1,255 | | | | 839 | | | | 218 | | | | (57 | ) | | | 2,255 | |
Provision for depreciation | | | 301 | | | | 153 | | | | - | | | | 23 | | | | 477 | |
Amortization of regulatory assets | | | 765 | | | | - | | | | 20 | | | | - | | | | 785 | |
Deferral of new regulatory assets | | | (299 | ) | | | - | | | | (100 | ) | | | - | | | | (399 | ) |
General taxes | | | 486 | | | | 81 | | | | 3 | | | | 19 | | | | 589 | |
Total Expenses | | | 5,346 | | | | 2,534 | | | | 1,853 | | | | (2,225 | ) | | | 7,508 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 1,309 | | | | 765 | | | | 115 | | | | 26 | | | | 2,215 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | 190 | | | | 13 | | | | 1 | | | | (111 | ) | | | 93 | |
Interest expense | | | (347 | ) | | | (144 | ) | | | (1 | ) | | | (101 | ) | | | (593 | ) |
Capitalized interest | | | 7 | | | | 13 | | | | - | | | | 1 | | | | 21 | |
Total Other Expense | | | (150 | ) | | | (118 | ) | | | - | | | | (211 | ) | | | (479 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations | | | | | | | | | | | | | | | | | | | | |
Before Income Taxes | | | 1,159 | | | | 647 | | | | 115 | | | | (185 | ) | | | 1,736 | |
Income taxes | | | 464 | | | | 259 | | | | 46 | | | | (74 | ) | | | 695 | |
Net Income | | $ | 695 | | | $ | 388 | | | $ | 69 | | | $ | (111 | ) | | $ | 1,041 | |
| | | | | | | | Ohio | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | Other and | | | | |
| | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | |
First Nine Months 2006 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | (In millions) | |
Revenues: | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | |
Electric | | $ | 5,434 | | | $ | 955 | | | $ | 1,790 | | | $ | - | | | $ | 8,179 | |
Other | | | 442 | | | | 122 | | | | 18 | | | | 60 | | | | 642 | |
Internal | | | 14 | | | | 1,997 | | | | - | | | | (2,011 | ) | | | - | |
Total Revenues | | | 5,890 | | | | 3,074 | | | | 1,808 | | | | (1,951 | ) | | | 8,821 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 2,343 | | | | 1,416 | | | | 1,558 | | | | (2,011 | ) | | | 3,306 | |
Other operating expenses | | | 1,197 | | | | 838 | | | | 185 | | | | 10 | | | | 2,230 | |
Provision for depreciation | | | 282 | | | | 143 | | | | - | | | | 20 | | | | 445 | |
Amortization of regulatory assets | | | 650 | | | | - | | | | 15 | | | | - | | | | 665 | |
Deferral of new regulatory assets | | | (275 | ) | | | - | | | | (104 | ) | | | - | | | | (379 | ) |
General taxes | | | 459 | | | | 70 | | | | 7 | | | | 17 | | | | 553 | |
Total Expenses | | | 4,656 | | | | 2,467 | | | | 1,661 | | | | (1,964 | ) | | | 6,820 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 1,234 | | | | 607 | | | | 147 | | | | 13 | | | | 2,001 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | 244 | | | | 35 | | | | - | | | | (159 | ) | | | 120 | |
Interest expense | | | (310 | ) | | | (148 | ) | | | (1 | ) | | | (69 | ) | | | (528 | ) |
Capitalized interest | | | 11 | | | | 9 | | | | - | | | | 1 | | | | 21 | |
Subsidiaries' preferred stock dividends | | | (9 | ) | | | - | | | | - | | | | 3 | | | | (6 | ) |
Total Other Expense | | | (64 | ) | | | (104 | ) | | | (1 | ) | | | (224 | ) | | | (393 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations | | | | | | | | | | | | | | | | | | | | |
Before Income Taxes | | | 1,170 | | | | 503 | | | | 146 | | | | (211 | ) | | | 1,608 | |
Income taxes | | | 468 | | | | 201 | | | | 58 | | | | (102 | ) | | | 625 | |
Income from continuing operations | | | 702 | | | | 302 | | | | 88 | | | | (109 | ) | | | 983 | |
Discontinued operations | | | - | | | | - | | | | - | | | | (4 | ) | | | (4 | ) |
Net Income | | $ | 702 | | | $ | 302 | | | $ | 88 | | | $ | (113 | ) | | $ | 979 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Changes Between First Nine Months 2007 | | | | | | | | | | | | | | | | | |
and First Nine Months 2006 | | | | | | | | | | | | | | | | | | | | |
Financial Results Increase (Decrease) | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Revenues: | | | | | | | | | | | | | | | | | | | | |
External | | | | | | | | | | | | | | | | | | | | |
Electric | | $ | 714 | | | $ | 18 | | | $ | 152 | | | $ | - | | | $ | 884 | |
Other | | | 65 | | | | (6 | ) | | | 8 | | | | (49 | ) | | | 18 | |
Internal | | | (14 | ) | | | 213 | | | | - | | | | (199 | ) | | | - | |
Total Revenues | | | 765 | | | | 225 | | | | 160 | | | | (248 | ) | | | 902 | |
| | | | | | | | | | | | | | | | | | | | |
Expenses: | | | | | | | | | | | | | | | | | | | | |
Fuel and purchased power | | | 495 | | | | 45 | | | | 154 | | | | (199 | ) | | | 495 | |
Other operating expenses | | | 58 | | | | 1 | | | | 33 | | | | (67 | ) | | | 25 | |
Provision for depreciation | | | 19 | | | | 10 | | | | - | | | | 3 | | | | 32 | |
Amortization of regulatory assets | | | 115 | | | | - | | | | 5 | | | | - | | | | 120 | |
Deferral of new regulatory assets | | | (24 | ) | | | - | | | | 4 | | | | - | | | | (20 | ) |
General taxes | | | 27 | | | | 11 | | | | (4 | ) | | | 2 | | | | 36 | |
Total Expenses | | | 690 | | | | 67 | | | | 192 | | | | (261 | ) | | | 688 | |
| | | | | | | | | | | | | | | | | | | | |
Operating Income | | | 75 | | | | 158 | | | | (32 | ) | | | 13 | | | | 214 | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
Investment income | | | (54 | ) | | | (22 | ) | | | 1 | | | | 48 | | | | (27 | ) |
Interest expense | | | (37 | ) | | | 4 | | | | - | | | | (32 | ) | | | (65 | ) |
Capitalized interest | | | (4 | ) | | | 4 | | | | - | | | | - | | | | - | |
Subsidiaries' preferred stock dividends | | | 9 | | | | - | | | | - | | | | (3 | ) | | | 6 | |
Total Other Expense | | | (86 | ) | | | (14 | ) | | | 1 | | | | 13 | | | | (86 | ) |
| | | | | | | | | | | | | | | | | | | | |
Income From Continuing Operations | | | | | | | | | | | | | | | | | | | | |
Before Income Taxes | | | (11 | ) | | | 144 | | | | (31 | ) | | | 26 | | | | 128 | |
Income taxes | | | (4 | ) | | | 58 | | | | (12 | ) | | | 28 | | | | 70 | |
Income from continuing operations | | | (7 | ) | | | 86 | | | | (19 | ) | | | (2 | ) | | | 58 | |
Discontinued operations | | | - | | | | - | | | | - | | | | 4 | | | | 4 | |
Net Income | | $ | (7 | ) | | $ | 86 | | | $ | (19 | ) | | $ | 2 | | | $ | 62 | |
Energy Delivery Services – First Nine Months of 2007 Compared to First Nine Months of 2006
Net income decreased $7 million (or 1%) to $695 million in the first nine months of 2007 compared to $702 million in the first nine months of 2006, primarily due to increased revenues partially offset by higher operating expenses and other expenses.
Revenues –
The increase in total revenues resulted from the following sources:
| | Nine Months Ended | | | |
| | September 30, | | | |
Revenues by Type of Service | | 2007 | | 2006 | | Increase | |
| | (In millions) | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
The change in distribution deliveries by customer class is summarized in the following table:
Electric Distribution KWH Deliveries
| | | |
| | | | |
| | | | |
| | | | |
Total Distribution KWH Deliveries
| | | | |
The increase in electric distribution deliveries to customers was primarily due to higher weather-related usage during the first nine months of 2007 compared to the same period of 2006 (heating degree days increased by 13.7% and cooling degree days increased by 9.5%). The higher revenues from increased distribution deliveries were partially offset by distribution rate decreases for Met-Ed and Penelec as a result of a January 11, 2007 PPUC rate decision (see Outlook – State Regulatory Matters – Pennsylvania).
The following table summarizes the price and volume factors contributing to the $572 million increase in non-affiliated generation sales revenues in 2007 compared to 2006:
Sources of Change in Generation Sales | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 2% decrease in sales volumes | | $ | (38 | ) |
Change in prices | | | | |
| | | | |
Wholesale: | | | | |
Effect of 118% increase in sales volumes | | | 232 | |
Change in prices | | | | |
| | | | |
Net Increase in Generation Sales | | $ | 572 | |
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in Penn’s service territory in the first nine months of 2007. The increase in retail generation prices during the first nine months of 2007 compared to 2006 was primarily due to increased generation rates for JCP&L resulting from the New Jersey BGS auction process and an increase in NUGC rates authorized by the NJBPU. Wholesale generation sales increased principally as a result of Met-Ed and Penelec selling additional available power into the PJM market beginning in January 2007.
Transmission revenues increased $169 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the January 2007 PPUC authorization of transmission cost recovery. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, with no material effect on current period earnings (see Outlook – State Regulatory Matters – Pennsylvania).
Expenses –
The increases in revenues discussed above were partially offset by a $690 million increase in expenses due to the following:
| · | Purchased power costs were $495 million higher in the first nine months of 2007 due to higher unit costs and volumes purchased. The increased unit costs reflected the effect of higher JCP&L costs resulting from the BGS auction process. The increased purchases in 2007 were due primarily to higher sales to the wholesale market. The following table summarizes the sources of changes in purchased power costs:
|
Sources of Change in Purchased Power | | | |
| | (In millions) | |
| | | | |
Purchased Power: | | | | |
Change due to increased unit costs | | $ | 261 | |
Change due to increased volume | | | 174 | |
Decrease in NUG costs deferred | | | 60 | |
Net Increase in Purchased Power Costs | | $ | 495 | |
| · | Other operating expenses increased $58 million due to the net effects of:
|
- | An increase of $80 million in MISO and PJM transmission expenses, resulting primarily from higher congestion costs.
|
- | A decrease in miscellaneous operating expenses of $10 million primarily due to changes in the assessment of regulatory fees and employee benefits
from FESC.
|
- | A decrease in operation and maintenance expenses of $9 million primarily due to increased labor activities devoted to construction projects in 2007.
|
| · | Amortization of regulatory assets increased $115 million compared to 2006 due primarily to recovery of deferred BGS costs through higher NUGC rates for JCP&L as discussed above.
|
| · | The deferral of new regulatory assets during the first nine months of 2007 was $24 million higher in 2007 primarily due to the deferral of previously expensed decommissioning costs of $27 million related to the Saxton nuclear research facility (see Outlook – State Regulatory Matters - Pennsylvania), increased RCP distribution deferrals of $23 million, offset by a reduction in deferred PJM transmission costs of $30 million.
|
· | Depreciation expense increased $19 million and property taxes increased $27 million due primarily to property additions since the third quarter of 2006. |
Other Expense –
Other expense increased $86 million in 2007 compared to the first nine months of 2006 primarily due to lower investment income of $54 million resulting from the repayment of notes receivable from affiliates since the third quarter of 2006 and increased interest expense of $37 million related to new debt issuances by CEI, JCP&L and Penelec.
Competitive Energy Services – First Nine Months of 2007 Compared to First Nine Months of 2006
Net income for this segment was $388 million in the first nine months of 2007 compared to $302 million in the same period last year. This increase reflects an improvement in gross generation margin and lower nuclear production costs, which were partially offset by increased depreciation and general taxes and reduced investment income.
Revenues –
Total revenues increased $225 million in the first nine months of 2007 compared to the same period in 2006. This increase primarily resulted from higher unit prices under affiliated generationgreater sales to the Ohio and Pennsylvania Companies and increased retail sales, which were partially offset by lower non-affiliated wholesale sales.
The higher retail revenues resulted from increased sales in both the MISO and PJM markets. The increase in MISO retail sales primarily reflect FES’ increased sales to shopping customers in Penn’s service territory. Lower non-affiliated wholesale revenues reflected the effect of decreased generation available for the non-affiliated wholesale market due to increased affiliated company power sales under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.
The increased affiliated company generation revenues were due to higher unit prices and increased sales volumes. The increase in PSA sales to the Ohio Companies was due tomeet their higher retail generation sales requirements. The higherHigher unit prices resulted from the provision of the full-requirements PSA under which PSA rates reflect the increasesincrease in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn due to a 45% increase in customer shopping in the implementationfirst quarter of its competitive solicitation process in2008 compared to the first quarter of 2007.
The increase in reported segment revenues resulted from the following sources:
| | Nine Months Ended | | | |
| | September 30, | | Increase | |
Revenues by Type of Service | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
Non-Affiliated Generation Sales: | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
Total Non-Affiliated Generation Sales | | | | | | | | | | |
Affiliated Generation Sales | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Transmission revenues decreased $25revenue increased $10 million due to reducedincreased retail load in the MISO market lowerand higher transmission rates andprices ($12 million), partially offset by reduced financial transmission rightsFTR auction revenue.revenues ($2 million).
Changes in revenues in the first three months of 2008 from the same period of 2007 are summarized below:
| | Three Months Ended | | | |
| | March 31, | | Increase | |
Revenues by Type of Service | | 2008 | | 2007 | | (Decrease) | |
| | (In millions) | |
Non-Affiliated Generation Sales: | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
Total Non-Affiliated Generation Sales | | | | | | | | | | |
Affiliated Generation Sales | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales:sales in the first three months of 2008 compared to the same period last year:
| | Increase | |
Source of Change in Non-Affiliated Generation Sales | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 12% increase in sales volumes | | $ | 52 | |
Change in prices | | | | |
| | | | |
Wholesale: | | | | |
Effect of 26% decrease in sales volumes | | | (131 | ) |
Change in prices | | | | |
| | | | ) |
Net Increase in Non-Affiliated Generation Sales | | | | |
| | | |
Source of Change in Affiliated Generation Sales | | | |
| | (In millions) | |
Ohio Companies: | | | | |
Effect of 4% increase in sales volumes | | $ | 56 | |
Change in prices | | | | |
| | | | |
Pennsylvania Companies: | | | | |
Effect of 12% increase in sales volumes | | | 54 | |
Change in prices | | | | |
| | | | |
Net Increase in Affiliated Generation Sales | | | | |
| | Increase | |
Source of Change in Non-Affiliated Generation Revenues | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 9.0% decrease in sales volumes | | $ | (16 | ) |
Change in prices | | | | |
| | | | ) |
Wholesale: | | | | |
Effect of 3.5% increase in sales volumes | | | 4 | |
Change in prices | | | | |
| | | | |
Net Increase in Non-Affiliated Generation Revenues | | | | |
| | Increase | |
Source of Change in Affiliated Generation Revenues | | | |
| | (In millions) | |
Ohio Companies: | | | | |
Effect of 1.2% increase in sales volumes | | $ | 6 | |
Change in prices | | | | |
| | | | |
Pennsylvania Companies: | | | | |
Effect of 9.0% increase in sales volumes | | | 16 | |
Change in prices | | | | ) |
| | | | |
Net Increase in Affiliated Generation Revenues | | | | |
Expenses -
Total expenses increased $67by $94 million in the first ninethree months of 2007 due to the following factors:
| · | Purchased power costs increased $86 million due principally to higher volumes for replacement power related to the forced outages at Bruce Mansfield and Perry. |
| · | Higher fossil operating costs of $43 million due to the absence of gains from the sale of emissions allowances recognized in 2006 ($24 million) and increased scheduled maintenance outages ($13 million). |
| · | Higher depreciation expenses of $10 million were due to property additions. |
| · | Higher general taxes of $11 million resulted from increased gross receipts taxes and property taxes. |
Partially offsetting the higher costs were:
| · | Fuel costs were $41 million lower primarily due to reduced coal costs and emission allowance costs offset by increases in nuclear fuel and natural gas costs. Coal costs were reduced due to a $14 million inventory adjustment and $23 million of reduced coal consumption reflecting lower generation. Reduced emission allowance costs ($18 million) were partially offset by increased natural gas costs ($4 million) due to increased consumption and nuclear fuel costs ($8 million) due to increased consumption and higher prices. |
·Nuclear operating costs were $54 million lower due to fewer outages in 20072008 compared to 2006 and reduced employee benefit costs.
Other Expense –
Total other expense in the first nine months of 2007 was $14 million higher than the 2006 period primarily due to decreased earnings on nuclear decommissioning trust investments (including a $16 million impairment in 2007).
Ohio Transitional Generation Services – First Nine Months of 2007 Compared to First Nine Months of 2006
Net income for this segment decreased to $69 million in the first nine months of 2007 from $88 million inwith the same period last year. Higher operating expenses, primarily for purchased power, were partially offset by higher generation revenues.
Revenues –
The increase in reported segment revenues resulted from the following sources:
| | Nine Months Ended | | | |
| | September 30, | | Increase | |
Revenues by Type of Service | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
| | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
of 2007. The following table summarizes the price and volume factors contributing to the increasechanges in sales revenuesfuel and purchased power costs in the first three months of 2008 from retail customers:the same period last year:
Source of Change in Generation Sales | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 4% increase in sales volumes | | $ | 66 | |
Change in prices | | | | |
Total Increase in Retail Generation Sales | | | | |
Source of Change in Fuel and Purchased Power | | | |
| | (In millions) | |
Nuclear Fuel: | | | | |
Change due to increased unit costs | | $ | 1 | |
Change due to volume consumed | | | (3 | ) |
| | | (2 | ) |
Fossil Fuel: | | | | |
Change due to increased unit costs | | | 19 | |
Change due to volume consumed | | | 71 | |
| | | 90 | |
Non-affiliated Purchased Power: | | | | |
Change due to increased unit costs | | | 55 | |
Change due to volume purchased | | | (34 | ) |
| | | 21 | |
Affiliated Purchased Power: | | | | |
Change due to decreased unit costs | | | (16 | ) |
Change due to volume purchased | | | (35 | ) |
| | | (51 | ) |
Net Increase in Fuel and Purchased Power Costs | | | | |
Fossil fuel costs increased $90 million in the first three months of 2008 primarily as a result of increased coal consumption reflecting higher generation as a result of fewer outages in 2008 compared to 2007. Higher unit prices were due to increased coal transportation and emission allowance costs in the first quarter of 2008. The higher fossil fuel costs were partially offset by lower nuclear fuel costs of $2 million. Lower nuclear fuel costs reflect decreased nuclear generation primarily as a result of the refueling outage at Davis-Besse in the first quarter of 2008.
The increasePurchased power costs decreased as a result of lower purchases from affiliates, partially offset by increased non-affiliated purchased power costs. Purchases from affiliated companies decreased as a result of the assignment of CEI’s and TE’s leasehold interests in generation sales wasthe Mansfield Plant to FGCO in October 2007. Purchased power costs from non-affiliates increased primarily as a result of higher market rates partially offset by reduced volume requirements due to increased available fossil generation.
Other operating expenses increased by $33 million in the first three months of 2008 from the same period of 2007 primarily due to higher weather-related usagelease expenses relating to the assignment of CEI’s and TE’s leasehold interests in the Mansfield Plant to FGCO and the sale and leaseback of Mansfield Unit 1 that were completed subsequent to the first quarter in 2007. Higher nuclear operating costs were due to the refueling outage at Davis-Besse and preparatory work associated with the Beaver Valley Unit 2 refueling outage that is scheduled for the second quarter of 2008.
Depreciation expense increased by $2 million in the first ninethree months of 20072008 primarily due to fossil and nuclear property additions since the first quarter of 2007.
General taxes increased by $1 million in the first three months of 2008 compared to the same period of 2007 as a result of higher gross receipts taxes and property taxes.
Other Expense
Other expense increased by $4 million in the first three months of 2008 from the same period of 2007 primarily as a result of an increase in trust securities impairments and reduced loans to the unregulated money pool, partially offset by lower interest expense. Lower interest expense reflected the repayment of notes issued to associated companies in connection with the transfers of generation assets in 2005, partially offset by the issuance of lower-cost pollution control debt subsequent to March 31, 2007.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to FES.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to FES.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of FirstEnergy Solutions Corp.:
We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed above,in Note 8, Note 4, Note 2(G) and reduced customer shopping. Average pricesNote 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
|
PricewaterhouseCoopers LLP Cleveland, Ohio May 7, 2008 |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales to affiliates | | $ | 776,307 | | | $ | 713,674 | |
Electric sales to non-affiliates | | | 301,266 | | | | 287,629 | |
Other | | | 21,543 | | | | 16,990 | |
Total revenues | | | 1,099,116 | | | | 1,018,293 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Fuel | | | 321,689 | | | | 233,535 | |
Purchased power from non-affiliates | | | 206,724 | | | | 186,203 | |
Purchased power from affiliates | | | 25,485 | | | | 76,483 | |
Other operating expenses | | | 296,546 | | | | 263,596 | |
Provision for depreciation | | | 49,742 | | | | 48,010 | |
General taxes | | | 23,197 | | | | 21,718 | |
Total expenses | | | 923,383 | | | | 829,545 | |
| | | | | | | | |
OPERATING INCOME | | | 175,733 | | | | 188,748 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Miscellaneous income (expense) | | | (2,904 | ) | | | 19,732 | |
Interest expense to affiliates | | | (7,210 | ) | | | (29,446 | ) |
Interest expense - other | | | (24,535 | ) | | | (17,358 | ) |
Capitalized interest | | | 6,663 | | | | 3,209 | |
Total other expense | | | (27,986 | ) | | | (23,863 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 147,747 | | | | 164,885 | |
| | | | | | | | |
INCOME TAXES | | | 57,763 | | | | 62,381 | |
| | | | | | | | |
NET INCOME | | | 89,984 | | | | 102,504 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (1,820 | ) | | | (1,360 | ) |
Unrealized gain on derivative hedges | | | 5,718 | | | | 17,758 | |
Change in unrealized gain on available-for-sale securities | | | (51,852 | ) | | | 17,450 | |
Other comprehensive income (loss) | | | (47,954 | ) | | | 33,848 | |
Income tax expense (benefit) related to other comprehensive income | | | (17,403 | ) | | | 12,333 | |
Other comprehensive income (loss), net of tax | | | (30,551 | ) | | | 21,515 | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 59,433 | | | $ | 124,019 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an | |
integral part of these statements. | | | | | | | | |
| | | | | | | | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 2 | | | $ | 2 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $6,988,000 and | | | | | | | | |
$8,072,000, respectively, for uncollectible accounts) | | | 125,116 | | | | 133,846 | |
Associated companies | | | 317,740 | | | | 376,499 | |
Other (less accumulated provisions of $2,500,000 and $9,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 2,224 | | | | 3,823 | |
Notes receivable from associated companies | | | 737,387 | | | | 92,784 | |
Materials and supplies, at average cost | | | 474,625 | | | | 427,015 | |
Prepayments and other | | | 135,734 | | | | 92,340 | |
| | | 1,792,828 | | | | 1,126,309 | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
In service | | | 8,703,760 | | | | 8,294,768 | |
Less - Accumulated provision for depreciation | | | 4,032,545 | | | | 3,892,013 | |
| | | 4,671,215 | | | | 4,402,755 | |
Construction work in progress | | | 1,058,080 | | | | 761,701 | |
| | | 5,729,295 | | | | 5,164,456 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 1,263,338 | | | | 1,332,913 | |
Long-term notes receivable from associated companies | | | 62,900 | | | | 62,900 | |
Other | | | 24,388 | | | | 40,004 | |
| | | 1,350,626 | | | | 1,435,817 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Accumulated deferred income tax benefits | | | 256,983 | | | | 276,923 | |
Lease assignment receivable from associated companies | | | 67,256 | | | | 215,258 | |
Goodwill | | | 24,248 | | | | 24,248 | |
Property taxes | | | 47,774 | | | | 47,774 | |
Pension assets | | | 16,070 | | | | 16,723 | |
Unamortized sale and leaseback costs | | | 85,695 | | | | 70,803 | |
Other | | | 34,819 | | | | 43,953 | |
| | | 532,845 | | | | 695,682 | |
| | $ | 9,405,594 | | | $ | 8,422,264 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 1,608,456 | | | $ | 1,441,196 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 1,145,959 | | | | 264,064 | |
Other | | | 700,000 | | | | 300,000 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 405,668 | | | | 445,264 | |
Other | | | 185,704 | | | | 177,121 | |
Accrued taxes | | | 142,834 | | | | 171,451 | |
Other | | | 248,106 | | | | 237,806 | |
| | | 4,436,727 | | | | 3,036,902 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity - | | | | | | | | |
Common stock, without par value, authorized 750 shares- | | | | | | | | |
7 shares outstanding | | | 1,161,473 | | | | 1,164,922 | |
Accumulated other comprehensive income | | | 110,103 | | | | 140,654 | |
Retained earnings | | | 1,188,639 | | | | 1,108,655 | |
Total common stockholder's equity | | | 2,460,215 | | | | 2,414,231 | |
Long-term debt and other long-term obligations | | | 77,956 | | | | 533,712 | |
| | | 2,538,171 | | | �� | 2,947,943 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Deferred gain on sale and leaseback transaction | | | 1,051,871 | | | | 1,060,119 | |
Accumulated deferred investment tax credits | | | 59,969 | | | | 61,116 | |
Asset retirement obligations | | | 823,686 | | | | 810,114 | |
Retirement benefits | | | 65,348 | | | | 63,136 | |
Property taxes | | | 48,095 | | | | 48,095 | |
Lease market valuation liability | | | 341,881 | | | | 353,210 | |
Other | | | 39,846 | | | | 41,629 | |
| | | 2,430,696 | | | | 2,437,419 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 9,405,594 | | | $ | 8,422,264 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an | |
integral part of these balance sheets. | | | | | | | | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 89,984 | | | $ | 102,504 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 49,742 | | | | 48,010 | |
Nuclear fuel and lease amortization | | | 25,426 | | | | 26,437 | |
Deferred rents and lease market valuation liability | | | (34,887 | ) | | | - | |
Deferred income taxes and investment tax credits, net | | | 30,781 | | | | 21,210 | |
Investment impairment | | | 14,943 | | | | 4,169 | |
Accrued compensation and retirement benefits | | | (11,042 | ) | | | (8,297 | ) |
Commodity derivative transactions, net | | | 8,086 | | | | 537 | |
Gain on asset sales | | | (4,964 | ) | | | - | |
Cash collateral, net | | | 1,601 | | | | 1,384 | |
Pension trust contribution | | | - | | | | (64,020 | ) |
Decrease (increase) in operating assets: | | | | | | | | |
Receivables | | | 69,533 | | | | (62,940 | ) |
Materials and supplies | | | (12,948 | ) | | | 10,580 | |
Prepayments and other current assets | | | (12,260 | ) | | | (1,440 | ) |
Increase (decrease) in operating liabilities: | | | | | | | | |
Accounts payable | | | (17,149 | ) | | | 213,484 | |
Accrued taxes | | | (28,652 | ) | | | (2,913 | ) |
Accrued interest | | | (728 | ) | | | 2,930 | |
Other | | | (7,514 | ) | | | 6,694 | |
Net cash provided from operating activities | | | 159,952 | | | | 298,329 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Equity contribution from parent | | | - | | | | 700,000 | |
Short-term borrowings, net | | | 1,281,896 | | | | 197,731 | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (288,603 | ) | | | (745,444 | ) |
Common stock dividend payments | | | (10,000 | ) | | | - | |
Net cash provided from financing activities | | | 983,293 | | | | 152,287 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (476,529 | ) | | | (117,506 | ) |
Proceeds from asset sales | | | 5,088 | | | | - | |
Sales of investment securities held in trusts | | | 173,123 | | | | 178,632 | |
Purchases of investment securities held in trusts | | | (181,079 | ) | | | (188,076 | ) |
Loans to associated companies, net | | | (644,604 | ) | | | (319,898 | ) |
Other | | | (19,244 | ) | | | (3,768 | ) |
Net cash used for investing activities | | | (1,143,245 | ) | | | (450,616 | ) |
| | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | - | |
Cash and cash equivalents at beginning of period | | | 2 | | | | 2 | |
Cash and cash equivalents at end of period | | $ | 2 | | | $ | 2 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of | |
these statements. | | | | | | | | |
OHIO EDISON COMPANY
ANALYSIS OF RESULTS OF OPERATIONS |
OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those customers electing to retain OE and Penn as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company. Penn purchases power from FES and third-party suppliers through a competitive RFP process.
Results of Operations
In the first three months of 2008, net income decreased to $44 million from $54 million in the same period of 2007. The decrease primarily resulted from higher operating costs, a decrease in the deferral of new regulatory assets and lower investment income, partially offset by higher electric sales revenues.
Revenues
Revenues increased by $27 million, or 4.3%, in the first three months of 2008 compared with the same period in 2007, primarily due to increases in retail generation revenues ($17 million) and distribution throughput revenues ($12 million).
Retail generation revenues increased primarily due to higher composite unitaverage prices for returningacross all customer classes, partially offset by decreased KWH sales to commercial and industrial customers. The percentagehigher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see “Regulatory Matters – Ohio” within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries). Weather conditions in the first three months of 2008 compared to the same period in 2007 contributed to the higher KWH sales to residential customers (heating degree days increased 2.8% and 0.7% in OE’s and Penn’s service territories, respectively). Commercial and industrial retail generation services provided by alternative suppliersKWH sales were lower due to totalincreased customer shopping in Penn’s service territory in the first quarter of 2008 compared to the same period last year.
Changes in retail generation sales delivered byand revenues in the Ohio Companies in their service areas decreased by 6.4 percentage pointsfirst three months of 2008 from the same period last year.
Expenses -
Purchased power costs were $153 million higher due primarily to higher unit costs for power purchased from FES. The factors contributing to the higher costsin 2007 are summarized in the following table:tables:
Retail Generation KWH Sales | | Increase (Decrease) | |
| | | | |
Residential | | | 1.0 | % |
Commercial | | | (2.5 | )% |
Industrial | | | (4.1 | )% |
Net Decrease in Generation Sales | | | (1.5 | )% |
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 11 | |
Commercial | | | 1 | |
Industrial | | | 5 | |
Increase in Generation Revenues | | $ | 17 | |
Revenues from distribution throughput increased by $12 million in the first three months of 2008 compared to the same period in 2007 due to higher average unit prices for all customer classes and higher KWH deliveries to residential and commercial customers. The higher average prices resulted from a transmission rider increase effective July 1, 2007. The higher KWH deliveries to residential and commercial customers reflected the favorable weather conditions described above.
Changes in distribution KWH deliveries and revenues in the first three months of 2008 from the same period in 2007 are summarized in the following tables.
Distribution KWH Deliveries | | | Increase (Decrease) | |
| | | | |
Residential | | | 1.7 | % |
Commercial | | | 1.2 | % |
Industrial | | | (0.8 | )% |
Net Increase in Distribution Deliveries | | | 0.7 | % |
Distribution Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 6 | |
Commercial | | | 4 | |
Industrial | | | 2 | |
Increase in Distribution Revenues | | $ | 12 | |
Expenses
Source of Change in Purchased Power | | Increase | |
| | (In millions) | |
Purchases from non-affiliates: | | | | |
Change due to increased unit costs | | $ | 6 | |
Change due to volume purchased | | | 2 | |
| | | 8 | |
Purchases from FES: | | | | |
Change due to increased unit costs | | | 89 | |
Change due to volume purchased | | | 56 | |
| | | 145 | |
Total Increase in Purchased Power Costs | | $ | 153 | |
Total expenses increased by $15 million in the first three months of 2008 from the same period of 2007. The following table presents changes from the prior year by expense category.
Expenses – Changes | | Increase (Decrease) | |
| | | (In millions) | |
Purchased power costs | | $ | (10 | ) |
Nuclear operating costs | | | 1 | |
Other operating costs | | | 6 | |
Provision for depreciation | | | 3 | |
Amortization of regulatory assets | | | 3 | |
Deferral of new regulatory assets | | | 11 | |
General taxes | | | 1 | |
Net Increase in Expenses | | $ | 15 | |
Lower purchased power costs in the first three months of 2008 primarily reflected the lower retail generation KWH sales in Penn’s service territory described above, partially offset by higher unit prices as provided for under OE’s PSA with FES. The increase in other operating costs for the first three months of 2008 was primarily due to higher transmission expenses related to MISO operations. Higher depreciation expense in the first three months of 2008 reflected capital additions subsequent to the first quarter of 2007. Higher amortization of regulatory assets in the first three months of 2008 was primarily due to increased amortization of MISO transmission deferrals. The decrease in the deferral of new regulatory assets for the first three months of 2008 was primarily due to lower MISO costs deferred in excess of transmission revenues and lower RCP fuel and distribution cost deferrals.
Other Income
Other income decreased $12 million in the first three months of 2008 as compared with the same period of 2007 primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies since the first quarter of 2007.
Income Taxes
In the first quarter of 2007, OE’s income taxes included an immaterial adjustment applicable to prior periods of $7.2 million related to an inter-company federal tax allocation arrangement between FirstEnergy and its subsidiaries.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to OE.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to OE.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Ohio Edison Company:
We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
|
PricewaterhouseCoopers LLP Cleveland, Ohio May 7, 2008 |
OHIO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 622,271 | | | $ | 594,344 | |
Excise tax collections | | | 30,378 | | | | 31,254 | |
Total revenues | | | 652,649 | | | | 625,598 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Fuel | | | 3,170 | | | | 3,015 | |
Purchased power | | | 340,186 | | | | 349,852 | |
Nuclear operating costs | | | 43,021 | | | | 41,514 | |
Other operating costs | | | 94,135 | | | | 88,486 | |
Provision for depreciation | | | 21,493 | | | | 18,848 | |
Amortization of regulatory assets | | | 48,538 | | | | 45,417 | |
Deferral of new regulatory assets | | | (25,411 | ) | | | (36,649 | ) |
General taxes | | | 50,453 | | | | 49,745 | |
Total expenses | | | 575,585 | | | | 560,228 | |
| | | | | | | | |
OPERATING INCOME | | | 77,064 | | | | 65,370 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Investment income | | | 15,055 | | | | 26,630 | |
Miscellaneous income (expense) | | | (3,806 | ) | | | 373 | |
Interest expense | | | (17,641 | ) | | | (21,022 | ) |
Capitalized interest | | | 110 | | | | 110 | |
Total other income (expense) | | | (6,282 | ) | | | 6,091 | |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 70,782 | | | | 71,461 | |
| | | | | | | | |
INCOME TAXES | | | 26,873 | | | | 17,426 | |
| | | | | | | | |
NET INCOME | | | 43,909 | | | | 54,035 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (3,994 | ) | | | (3,423 | ) |
Change in unrealized gain on available-for-sale securities | | | (7,571 | ) | | | (126 | ) |
Other comprehensive loss | | | (11,565 | ) | | | (3,549 | ) |
Income tax benefit related to other comprehensive loss | | | (4,262 | ) | | | (1,503 | ) |
Other comprehensive loss, net of tax | | | (7,303 | ) | | | (2,046 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 36,606 | | | $ | 51,989 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part | |
of these statements. | | | | | | | | |
OHIO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 732 | | | $ | 732 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $7,870,000 and $8,032,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 266,360 | | | | 248,990 | |
Associated companies | | | 179,875 | | | | 185,437 | |
Other (less accumulated provisions of $5,638,000 and $5,639,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 16,474 | | | | 12,395 | |
Notes receivable from associated companies | | | 589,790 | | | | 595,859 | |
Prepayments and other | | | 17,785 | | | | 10,341 | |
| | | 1,071,016 | | | | 1,053,754 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,804,505 | | | | 2,769,880 | |
Less - Accumulated provision for depreciation | | | 1,106,174 | | | | 1,090,862 | |
| | | 1,698,331 | | | | 1,679,018 | |
Construction work in progress | | | 60,617 | | | | 50,061 | |
| | | 1,758,948 | | | | 1,729,079 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Long-term notes receivable from associated companies | | | 258,405 | | | | 258,870 | |
Investment in lease obligation bonds | | | 253,747 | | | | 253,894 | |
Nuclear plant decommissioning trusts | | | 119,948 | | | | 127,252 | |
Other | | | 33,014 | | | | 36,037 | |
| | | 665,114 | | | | 676,053 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Regulatory assets | | | 709,969 | | | | 737,326 | |
Pension assets | | | 235,933 | | | | 228,518 | |
Property taxes | | | 65,520 | | | | 65,520 | |
Unamortized sale and leaseback costs | | | 43,882 | | | | 45,133 | |
Other | | | 44,640 | | | | 48,075 | |
| | | 1,099,944 | | | | 1,124,572 | |
| | $ | 4,595,022 | | | $ | 4,583,458 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 334,656 | | | $ | 333,224 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 50,692 | | | | 50,692 | |
Other | | | 2,609 | | | | 2,609 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 155,654 | | | | 174,088 | |
Other | | | 19,376 | | | | 19,881 | |
Accrued taxes | | | 93,390 | | | | 89,571 | |
Accrued interest | | | 16,459 | | | | 22,378 | |
Other | | | 99,532 | | | | 65,163 | |
| | | 772,368 | | | | 757,606 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 175,000,000 shares - | | | | | | | | |
60 shares outstanding | | | 1,220,368 | | | | 1,220,512 | |
Accumulated other comprehensive income | | | 41,083 | | | | 48,386 | |
Retained earnings | | | 351,186 | | | | 307,277 | |
Total common stockholder's equity | | | 1,612,637 | | | | 1,576,175 | |
Long-term debt and other long-term obligations | | | 839,107 | | | | 840,591 | |
| | | 2,451,744 | | | | 2,416,766 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 783,777 | | | | 781,012 | |
Accumulated deferred investment tax credits | | | 15,990 | | | | 16,964 | |
Asset retirement obligations | | | 95,009 | | | | 93,571 | |
Retirement benefits | | | 176,597 | | | | 178,343 | |
Deferred revenues - electric service programs | | | 36,821 | | | | 46,849 | |
Other | | | 262,716 | | | | 292,347 | |
| | | 1,370,910 | | | | 1,409,086 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 4,595,022 | | | $ | 4,583,458 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part | |
of these balance sheets. | | | | | | | | |
OHIO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 43,909 | | | $ | 54,035 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 21,493 | | | | 18,848 | |
Amortization of regulatory assets | | | 48,538 | | | | 45,417 | |
Deferral of new regulatory assets | | | (25,411 | ) | | | (36,649 | ) |
Amortization of lease costs | | | 32,934 | | | | 32,934 | |
Deferred income taxes and investment tax credits, net | | | 6,866 | | | | (3,992 | ) |
Accrued compensation and retirement benefits | | | (19,482 | ) | | | (16,794 | ) |
Pension trust contribution | | | - | | | | (20,261 | ) |
Increase in operating assets- | | | | | | | | |
Receivables | | | (27,496 | ) | | | (102,469 | ) |
Prepayments and other current assets | | | (7,451 | ) | | | (6,339 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (18,939 | ) | | | 42,095 | |
Accrued taxes | | | 2,991 | | | | (46,791 | ) |
Accrued interest | | | (5,919 | ) | | | (6,812 | ) |
Electric service prepayment programs | | | (10,028 | ) | | | (9,053 | ) |
Other | | | (2,066 | ) | | | (3,283 | ) |
Net cash provided from (used for) operating activities | | | 39,939 | | | | (59,114 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | - | | | | 77,473 | |
Redemptions and Repayments- | | | | | | | | |
Common stock | | | - | | | | (500,000 | ) |
Long-term debt | | | (80 | ) | | | (72 | ) |
Net cash used for financing activities | | | (80 | ) | | | (422,599 | ) |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (49,011 | ) | | | (29,888 | ) |
Sales of investment securities held in trusts | | | 62,344 | | | | 12,951 | |
Purchases of investment securities held in trusts | | | (63,797 | ) | | | (13,805 | ) |
Loan repayments from associated companies, net | | | 6,534 | | | | 511,082 | |
Cash investments | | | 147 | | | | 168 | |
Other | | | 3,924 | | | | 1,187 | |
Net cash provided from (used for) investing activities | | | (39,859 | ) | | | 481,695 | |
| | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | (18 | ) |
Cash and cash equivalents at beginning of period | | | 732 | | | | 712 | |
Cash and cash equivalents at end of period | | $ | 732 | | | $ | 694 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part | |
of these statements. | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
ANALYSIS OF RESULTS OF OPERATIONS |
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI’s power supply requirements are primarily provided by FES – an affiliated company.
Results of Operations
Net income in the first three months of 2008 decreased to $58 million from $64 million in the same period of 2007. The decrease resulted primarily from higher purchased power costs, increased amortization of regulatory assets and lower investment income, partially offset by the elimination of fuel costs (due to assigning leasehold interests in generating assets to FGCO) and decreases in other operating expenses.
Revenues
Revenues decreased by $4 million, or 1%, in the first three months of 2008 compared to the same period of 2007 primarily due to a decrease in wholesale generation revenues ($32 million), partially offset by an increase in retail generation revenues ($18 million) and distribution revenues ($10 million).
Wholesale generation revenues decreased due to the assignment of CEI’s leasehold interests in the Bruce Mansfield Plant to FGCO on October 16, 2007. Prior to the assignment, CEI sold power from its interests in the plant to FGCO.
Retail generation revenues increased in the first three months of 2008 due to higher average unit prices across all customer classes and increased sales volume to residential and commercial customers compared to the same period of 2007. The higher average unit prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see “Regulatory Matters – Ohio” within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries). More weather-related usage in the first three months of 2008 compared to the same period of 2007 primarily contributed to the increased sales volume in the residential and commercial sectors (heating degree days increased 1.7% from the same period in 2007).
Increases in retail generation sales and revenues in the first three months of 2008 compared to the same period in 2007 are summarized in the following tables:
Retail Generation KWH Sales | | Increase | |
| | | | |
Residential | | | 3.0 | % |
Commercial | | | 1.8 | % |
Industrial | | | 1.0 | % |
Increase in Retail Generation Sales | | | 1.8 | % |
Retail Generation Revenues | | Increase | |
| | (in millions) | |
Residential | | $ | 7 | |
Commercial | | | 4 | |
Industrial | | | 7 | |
Increase in Generation Revenues | | $ | 18 | |
Revenues from distribution throughput increased by $10 million in the first three months of 2008 compared to the same period of 2007 primarily due higher average unit prices for all customer classes and higher KWH deliveries to residential and commercial customers. The higher average unit prices resulted from a transmission rider increase effective July 1, 2007. The higher KWH deliveries to residential and commercial customers in the first three months of 2008 reflected the weather impacts described above.
Changes in distribution KWH deliveries and revenues in the first three months of 2008 compared to the corresponding period of 2007 are summarized in the following tables.
Distribution KWH Deliveries | | Increase | |
| | | | |
Residential | | | 3.0 | % |
Commercial | | | 1.3 | % |
Industrial | | | 1.0 | % |
Increase in Distribution Deliveries | | | 1.7 | % |
Distribution Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 4 | |
Commercial | | | 3 | |
Industrial | | | 3 | |
Net Increase in Distribution Revenues | | $ | 10 | |
Expenses
Total expenses increased by $1 million in the first three months of 2008 compared to the same period of 2007. The following table presents the change from the prior year by expense category:
Expenses - Changes | | Increase (Decrease) | |
| | (in millions) | |
Fuel costs | | $ | (13 | ) |
Purchased power costs | | | 13 | |
Other operating costs | | | (10 | ) |
Amortization of regulatory assets | | | 5 | |
Deferral of new regulatory assets | | | 5 | |
General taxes | | | 1 | |
Net Increase in Expenses | | $ | 1 | |
The increaseabsence of fuel costs in purchasesthe first three months of 2008 was due to the higher retail generation sales requirements. Theassignment of CEI’s leasehold interests in the Mansfield Plant to FGCO on October 16, 2007. Prior to the assignment, CEI incurred fuel expenses related to its leasehold interest in the plant. Higher purchased power costs primarily reflected higher unit costs reflect the increases in the Ohio Companies’ retail generation rates,prices, as provided for under the PSA with FES.
Other operating expenses increased $33 millioncosts were lower primarily due to MISO transmission-related expenses. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.
Other – First Nine Monthsthe assignment of 2007 Compared to First Nine Months of 2006
FirstEnergy’s financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $2 million increase in FirstEnergy’s net incomeCEI’s leasehold interests in the first nine monthsMansfield plant. Higher amortization of 2007.regulatory assets were primarily due to increased transition cost amortization due to the higher KWH sales discussed above and increases related to the effective interest methodology. The increasechange in deferrals of new regulatory assets was primarily due to the salelower deferred MISO expenses (more expenses currently recovered through increased transmission tariffs) and RCP fuel costs (implementation of First Communications ($13 million, net of taxes), the absence of subsidiaries’ preferred stock dividendsfuel cost recovery rider). The change in 2007 ($6 million)general taxes is primarily due to higher real and the absence of a $4 million loss included in 2006 results from discontinued operations (see Note 4).personal property taxes.
Other Expense
CAPITAL RESOURCES AND LIQUIDITYOther expense increased by $5 million in the first three months of 2008 compared to the same period of 2007 primarily due to lower investment income, partially offset by a reduction in interest expense. Lower investment income is primarily the result of principal repayments since the first quarter of 2007 on notes receivable from associated companies. The lower interest expense is due to long-term debt redemptions ($489 million) since the first quarter of 2007, partially offset by a debt issuance in the first quarter of 2007 ($250 million).
FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2007 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.Legal Proceedings
Changes in Cash PositionSee the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to CEI.
FirstEnergy's primary sourceNew Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of cash requiredRegistrant Subsidiaries for continuing operations as a holding company is cash fromdiscussion of new accounting standards and interpretations applicable to CEI.
.
Report of Independent Registered Public Accounting Firm
To the operationsStockholder and Board of its subsidiaries. FirstEnergy and certainDirectors of its subsidiaries also
The Cleveland Electric Illuminating Company:
We have access to $2.75 billionreviewed the accompanying consolidated balance sheet of short-term financing under a revolving credit facility which expires in 2011. Under the terms of the facility, FirstEnergy is permitted to have up to $1.5 billion in outstanding borrowings at any time, subject to the facility cap of $2.75 billion of aggregate outstanding borrowings by itThe Cleveland Electric Illuminating Company and its subsidiaries thatas of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are also parties to such facility. In the first nine monthsresponsibility of 2007, FirstEnergy received $1.8 billionthe Company’s management.
We conducted our review in accordance with the standards of cash dividendsthe Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and returnmaking inquiries of capital from its subsidiariespersons responsible for financial and paid $464 millionaccounting matters. It is substantially less in cash dividends to common shareholders. Withscope than an audit conducted in accordance with the exceptionstandards of Met-Ed,the Public Company Accounting Oversight Board (United States), the objective of which is currentlythe expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an accumulated deficit position, there are nounqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material restrictions onrespects in relation to the payment of cash dividends by the subsidiaries of FirstEnergy.consolidated balance sheet from which it has been derived.
|
PricewaterhouseCoopers LLP Cleveland, Ohio May 7, 2008 |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 418,708 | | | $ | 422,805 | |
Excise tax collections | | | 18,600 | | | | 18,027 | |
Total revenues | | | 437,308 | | | | 440,832 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Fuel | | | - | | | | 13,191 | |
Purchased power | | | 193,244 | | | | 180,657 | |
Other operating costs | | | 65,118 | | | | 74,951 | |
Provision for depreciation | | | 19,076 | | | | 18,468 | |
Amortization of regulatory assets | | | 38,256 | | | | 33,129 | |
Deferral of new regulatory assets | | | (29,248 | ) | | | (33,957 | ) |
General taxes | | | 40,083 | | | | 38,894 | |
Total expenses | | | 326,529 | | | | 325,333 | |
| | | | | | | | |
OPERATING INCOME | | | 110,779 | | | | 115,499 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Investment income | | | 9,188 | | | | 17,687 | |
Miscellaneous income | | | 534 | | | | 731 | |
Interest expense | | | (32,520 | ) | | | (35,740 | ) |
Capitalized interest | | | 196 | | | | 205 | |
Total other expense | | | (22,602 | ) | | | (17,117 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 88,177 | | | | 98,382 | |
| | | | | | | | |
INCOME TAXES | | | 30,326 | | | | 34,833 | |
| | | | | | | | |
NET INCOME | | | 57,851 | | | | 63,549 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (213 | ) | | | 1,202 | |
Income tax expense related to other comprehensive income | | | 281 | | | | 355 | |
Other comprehensive income (loss), net of tax | | | (494 | ) | | | 847 | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 57,357 | | | $ | 64,396 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating | |
Company are an integral part of these statements. | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 241 | | | $ | 232 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $7,224,000 and $7,540,000, | | | 266,701 | | | | 251,000 | |
respectively, for uncollectible accounts) | | | | | | | | |
Associated companies | | | 70,727 | | | | 166,587 | |
Other | | | 3,643 | | | | 12,184 | |
Notes receivable from associated companies | | | 54,679 | | | | 52,306 | |
Prepayments and other | | | 1,728 | | | | 2,327 | |
| | | 397,719 | | | | 484,636 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,142,458 | | | | 2,256,956 | |
Less - Accumulated provision for depreciation | | | 827,160 | | | | 872,801 | |
| | | 1,315,298 | | | | 1,384,155 | |
Construction work in progress | | | 40,834 | | | | 41,163 | |
| | | 1,356,132 | | | | 1,425,318 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Investment in lessor notes | | | 425,722 | | | | 463,431 | |
Other | | | 10,275 | | | | 10,285 | |
| | | 435,997 | | | | 473,716 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 1,688,521 | | | | 1,688,521 | |
Regulatory assets | | | 853,716 | | | | 870,695 | |
Pension assets | | | 64,497 | | | | 62,471 | |
Property taxes | | | 76,000 | | | | 76,000 | |
Other | | | 32,735 | | | | 32,987 | |
| | | 2,715,469 | | | | 2,730,674 | |
| | $ | 4,905,317 | | | $ | 5,114,344 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 207,281 | | | $ | 207,266 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 365,816 | | | | 531,943 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 139,423 | | | | 169,187 | |
Other | | | 6,169 | | | | 5,295 | |
Accrued taxes | | | 118,102 | | | | 94,991 | |
Accrued interest | | | 37,726 | | | | 13,895 | |
Other | | | 35,044 | | | | 34,350 | |
| | | 909,561 | | | | 1,056,927 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity | | | | | | | | |
Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | |
67,930,743 shares outstanding | | | 873,353 | | | | 873,536 | |
Accumulated other comprehensive loss | | | (69,623 | ) | | | (69,129 | ) |
Retained earnings | | | 743,278 | | | | 685,428 | |
Total common stockholder's equity | | | 1,547,008 | | | | 1,489,835 | |
Long-term debt and other long-term obligations | | | 1,447,980 | | | | 1,459,939 | |
| | | 2,994,988 | | | | 2,949,774 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 719,938 | | | | 725,523 | |
Accumulated deferred investment tax credits | | | 18,102 | | | | 18,567 | |
Retirement benefits | | | 94,322 | | | | 93,456 | |
Deferred revenues - electric service programs | | | 21,297 | | | | 27,145 | |
Lease assignment payable to associated companies | | | 38,420 | | | | 131,773 | |
Other | | | 108,689 | | | | 111,179 | |
| | | 1,000,768 | | | | 1,107,643 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 4,905,317 | | | $ | 5,114,344 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating | |
Company are an integral part of these balance sheets. | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 57,851 | | | $ | 63,549 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 19,076 | | | | 18,468 | |
Amortization of regulatory assets | | | 38,256 | | | | 33,129 | |
Deferral of new regulatory assets | | | (29,248 | ) | | | (33,957 | ) |
Deferred rents and lease market valuation liability | | | - | | | | (46,528 | ) |
Deferred income taxes and investment tax credits, net | | | (4,965 | ) | | | (5,453 | ) |
Accrued compensation and retirement benefits | | | (3,507 | ) | | | (890 | ) |
Pension trust contribution | | | - | | | | (24,800 | ) |
Decrease in operating assets- | | | | | | | | |
Receivables | | | 90,280 | | | | 224,011 | |
Prepayments and other current assets | | | 604 | | | | 592 | |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (28,889 | ) | | | (256,808 | ) |
Accrued taxes | | | 23,196 | | | | 13,959 | |
Accrued interest | | | 23,831 | | | | 18,122 | |
Electric service prepayment programs | | | (5,847 | ) | | | (5,313 | ) |
Other | | | (63 | ) | | | (167 | ) |
Net cash provided from (used for) operating activities | | | 180,575 | | | | (2,086 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | - | | | | 247,715 | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (165 | ) | | | (150 | ) |
Short-term borrowings, net | | | (177,960 | ) | | | (130,585 | ) |
Dividend Payments- | | | | | | | | |
Common stock | | | - | | | | (24,000 | ) |
Net cash provided from (used for) financing activities | | | (178,125 | ) | | | 92,980 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (37,203 | ) | | | (36,682 | ) |
Loans to associated companies, net | | | (2,373 | ) | | | (231,907 | ) |
Collection of principal on long-term notes receivable | | | - | | | | 133,341 | |
Redemptions of lessor notes | | | 37,709 | | | | 35,614 | |
Other | | | (574 | ) | | | 9,294 | |
Net cash used for investing activities | | | (2,441 | ) | | | (90,340 | ) |
| | | | | | | | |
Net increase in cash and cash equivalents | | | 9 | | | | 554 | |
Cash and cash equivalents at beginning of period | | | 232 | | | | 221 | |
Cash and cash equivalents at end of period | | $ | 241 | | | $ | 775 | |
| | | | | | | | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating | |
Company are an integral part of these statements. | | | | | | | | |
On MarchTHE TOLEDO EDISON COMPANY
ANALYSIS OF RESULTS OF OPERATIONS |
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE’s power supply requirements are provided by FES – an affiliated company.
Results of Operations
Net income in the first three months of 2008 decreased to $17 million from $26 million in the same period of 2007. The decrease resulted primarily from lower electric sales revenues, higher purchased power costs and a decrease in the deferral of new regulatory assets, partially offset by lower fuel, nuclear and other operating costs.
Revenues
Revenues decreased $29 million, or 12%, in the first three months of 2008 compared to the same period of 2007 primarily due to lower wholesale generation revenues ($45 million), partially offset by increased retail generation revenues ($11 million) and distribution revenues ($4 million).
The decrease in wholesale revenues resulted primarily from the termination of TE’s Beaver Valley Unit 2 sale agreement with CEI at the end of 2007 FirstEnergy repurchased approximately 14.4 million shares, or approximately 4.5%,($26 million) and lower PSA sales to FES in the first three months of its outstanding common stock at an initial price2008 ($20 million) due to the assignment of approximately $900 million pursuant to an accelerated share repurchase program. FirstEnergy acquired these shares under its previously announced authorization to repurchase up to 16 million shares of its common stock. The share repurchase was funded with short-term borrowings, which have since been repaid with the proceeds fromTE’s leasehold interests in the Bruce Mansfield Plant to FGCO effective October 16, 2007. In 2008, TE is selling the 158 MW entitlement from its 18.26% leasehold interest in Beaver Valley Unit 1 sale and leaseback transaction.2 to NGC.
On July 13, 2007, FGCO completedRetail generation revenues increased in the first three months of 2008 due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers compared to the same period of 2007. Industrial KWH sales decreased due in part to a salemaintenance outage for a large industrial customer during the first quarter of 2008. The higher average prices included the 2008 fuel cost recovery rider that became effective January 16, 2008 (see “Regulatory Matters – Ohio” within the Combined Management’s Discussion and leaseback transaction for its 93.825% undivided interestAnalysis of Registrant Subsidiaries). The increase in Bruce Mansfield Unit 1, representing 779 MWsales volume reflects increased weather-related usage in the first three months of net demonstrated capacity. The purchase price of approximately $1.329 billion (net after-tax proceeds of approximately $1.2 billion) for the undivided interest was funded through a combination of equity investments by affiliates of AIG Financial Products Corp. and Union Bank of California, N.A. in six lessor trusts and proceeds2008 (heating degree days increased 3.3% from the salesame period of $1.135 billion aggregate principal amount of 6.85% pass through certificates due 2034. A like principal amount of secured notes maturing June 1, 2034 were issued by the lessor trusts to the pass through trust that issued and sold the certificates. The lessor trusts leased the undivided interest back to FGCO for a term of approximately 33 years under substantially identical leases. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The notes and certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements. FES’ registration obligations under the registration rights agreement applicable to the $1.135 billion principal amount of pass through certificates issued in connection with the transaction were satisfied in September 2007, at which time the transaction was classified as an operating lease under GAAP for FES and FirstEnergy. This transaction generated tax capital gains of approximately $752 million. Accordingly, FirstEnergy reduced its tax loss carryforward valuation allowances in the third quarter of 2007, with a corresponding reduction to goodwill (see Note 3)2007).
As of September 30, 2007, FirstEnergy had $30 million of cashChanges in retail electric generation KWH sales and cash equivalents compared with $90 million as of December 31, 2006. The major sources of changes in these balances are summarized below.
Cash Flows From Operating Activities
FirstEnergy's consolidated net cash from operating activities is provided primarily by its energy delivery services and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $1.2 billionrevenues in the first ninethree months of 2008 from the same period of 2007 and 2006are summarized as follows:in the following tables.
| | Nine Months Ended | |
| | September 30, | |
| | 2007 | | 2006 | |
| | (In millions) | |
Net income | | $ | 1,041 | | $ | 979 | |
Non-cash charges | | | 358 | | | 497 | |
Pension trust contribution | | | (300 | ) | | - | |
Working capital and other | | | 52 | | | (233 | ) |
| | $ | 1,151 | | $ | 1,243 | |
| | Increase | |
Retail Generation KWH Sales | | (Decrease) | |
| | | | |
Residential | | | 4.4 | % |
Commercial | | | 5.6 | % |
Industrial | | | (4.3 | )% |
Net Decrease in Retail Generation Sales | | | (0.1 | )% |
Net cash providedRetail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 4 | |
Commercial | | | 3 | |
Industrial | | | 4 | |
Increase in Retail Generation Revenues | | $ | 11 | |
Revenues from operating activities decreaseddistribution throughput increased by $92$4 million in the first ninethree months of 20072008 compared to the first nine months of 2006 primarilysame period in 2007 due to a $300 million pension trust contribution in 2007higher average unit prices for all customer classes and a $139 million change in non-cash charges, partially offset by a $285 million change in working capitalhigher KWH deliveries to residential and other and a $62 million increase in net income (see Results of Operations above).commercial customers. The decrease in non-cash charges and increase from working capital primarily reflects changes to deferred income taxes and accrued taxes related to the Bruce Mansfield Unit 1 sale and leaseback transaction discussed above. Excluding the tax effects of the sale and leaseback transaction, the changes in working capital and other primarilyhigher average prices resulted from a $322 milliontransmission rider increase in receivables dueeffective July 1, 2007. The higher KWH deliveries to higher sales, partially offset by $92 million from reduced materialsresidential and supplies inventories due primarily to lower coal inventory levels and $78 million of decreased payments for accounts payable, reflecting a changecommercial customers in the timing of payments from the first ninethree months of 2006.2008 reflected the weather impacts described above.
Changes in distribution KWH deliveries and revenues in the first three months of 2008 from the same period of 2007 are summarized in the following tables.
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | |
Residential | | | 3.6 | % |
Commercial | | | 2.3 | % |
Industrial | | | (4.0 | )% |
Net Decrease in Distribution Deliveries | | | (0.4 | )% |
Distribution Revenues | | Increase (Decrease) | |
| | (In millions) | |
Residential | | $ | 3 | |
Commercial | | | 2 | |
Industrial | | | (1 | ) |
Net Increase in Distribution Revenues | | $ | 4 | |
Cash Flows From Financing ActivitiesExpenses
In the first nine months of 2007, cash used for financing activities was $1.4 billion compared to $444Total expenses decreased $15 million in the first ninethree months of 2006.2008 from the same period of 2007. The following table presents changes from the prior year by expense category.
Expenses – Changes | | Increase (Decrease) | |
| | (In millions) | |
| | $ | | |
Purchased power costs | | | | |
| | | | ) |
| | | | |
Amortization of regulatory assets | | | | |
Deferral of new regulatory assets | | | | |
| | | | |
| | | | ) |
Lower fuel costs in the first three months of 2008 compared to the same period of 2007 were due to the assignment of TE’s leasehold interests in the Mansfield Plant to FGCO in October 2007. Higher purchased power costs reflected higher unit prices as provided for under the PSA with FES and a 1.8% increase in KWH purchases. Nuclear operating expenses decreased primarily due to the reversal ($8 million) of the above-market lease liability associated with TE’s leasehold interest in Beaver Valley Unit 2 related to the termination of the CEI sale agreement discussed above. Other operating costs were lower primarily due to the assignment of TE’s leasehold interests in the Mansfield Plant ($9 million). The change in the deferral of new regulatory assets was primarily due to more common shares repurchasedlower deferred RCP distribution costs ($3 million) and fuel costs ($1 million).
Other Expense
Other expense decreased $2 million in the first three months of 2008 compared to the same period of 2007 than in 2006 andprimarily due to lower interest expense, partially offset by lower investment income. The lower interest expense resulted from the repaymentredemption of short-term borrowings inlong-term debt ($85 million principal amount) since the first quarter of 2007. The following table summarizes security issuances and redemptions.decrease in investment income resulted primarily from the principal repayments since the first quarter of 2007 on notes receivable from associated companies.
| | Nine Months Ended | |
| | September 30, | |
Securities Issued or Redeemed | | 2007 | | 2006 | |
| | (In millions) | |
New issues | | | | | |
Pollution control notes | | $ | - | | $ | 253 | |
Secured notes | | | - | | | 382 | |
Unsecured notes | | | 1,100 | | | 600 | |
| | $ | 1,100 | | $ | 1,235 | |
Redemptions | | | | | | | |
First mortgage bonds | | $ | 287 | | $ | 1 | |
Pollution control notes | | | 4 | | | 311 | |
Senior secured notes | | | 203 | | | 181 | |
Unsecured notes | | | 153 | | | 500 | |
Common stock | | | 918 | | | 600 | |
Preferred stock | | | - | | | 107 | |
| | $ | 1,565 | | $ | 1,700 | |
| | | | | | | |
Short-term borrowings, net | | $ | (535 | ) | $ | 482 | |
Legal Proceedings
FirstEnergy had approximately $573 millionSee the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of short-term indebtedness asRegistrant Subsidiaries for discussion of September 30, 2007 comparedlegal proceedings applicable to approximately $1.1 billion as of December 31, 2006. Available bank borrowing capability as of September 30, 2007 included the following:TE.
Borrowing Capability (In millions) | | | |
Short-term credit facilities(1) | | $ | 2,870 | |
Accounts receivable financing facilities | | | 550 | |
Utilized | | | (570 | ) |
LOCs | | | (337 | ) |
Net available capability | | $ | 2,513 | |
| | | | |
(1) Includes the $2.75 billion revolving credit facility described below, a $100 million revolving credit facility that expires in December 2009 and a $20 million uncommitted line of credit.
|
New Accounting Standards and Interpretations
AsSee the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of September 30, 2007, the Ohio CompaniesRegistrant Subsidiaries for discussion of new accounting standards and Penn had the aggregate capabilityinterpretations applicable to issue approximately $3.1 billion of additional FMB on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMB by OE, CEI and TE is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMB) (i) supporting pollution control notes or similar obligations, or (ii) as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $543 million, $459 million and $112 million, respectively, as of September 30, 2007. JCP&L satisfied the provision of its senior note indenture for the release of all FMBs held as collateral for senior notes in May 2007, subsequently repaid its other remaining FMBs and, effective September 14, 2007, discharged and released its mortgage indenture.TE.
.
The applicable earnings coverage tests in the respective charters of OE, TE, Penn and JCP&L are currently inoperative. In the event that any of them issues preferred stock in the future, the applicable earnings coverage test will govern the amount of preferred stock that may be issued. CEI, Met-Ed and Penelec do not have similar restrictions and could issue up to the number of preferred shares authorized under their respective charters.
Report of Independent Registered Public Accounting Firm
As
To the Stockholder and Board of September 30, 2007, approximately $1.0 billion
Directors of capacity remained unused under an existing FirstEnergy shelf registration statement filedThe Toledo Edison Company:
We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the SECstandards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in 2003 to support future securities issuances. The shelf registration provides the flexibility to issue and sell various types of securities, including common stock, debt securities, and share purchase contracts and related share purchase units. As of September 30, 2007, OE had approximately $400 million of capacity remaining unused under a shelf registration for unsecured debt securities filedscope than an audit conducted in accordance with the SEC in 2006.standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
FirstEnergy and certainBased on our review, we are not aware of its subsidiaries are partiesany material modifications that should be made to a $2.75 billion five-year revolving credit facility (includedthe accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the borrowing capability table above). FirstEnergy may requestUnited States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007 and defined benefit pension and other postretirement plans as of December 31, 2006, as discussed in Note 8 and Note 4 to the consolidated financial statements) dated February 28, 2008, we expressed an increaseunqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the total commitments available under this facility upaccompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to a maximum of $3.25 billion. Commitments under the facility are available until August 24, 2011, unless the lenders agree, at the request of the Borrowers, to two additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each Borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.
The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations:
| | Revolving | | Regulatory and | |
| | Credit Facility | | Other Short-Term | |
| | | | | |
| | (In millions) | |
FirstEnergy | | $ | 2,750 | | $ | - | (2) |
OE | | | 500 | | | 500 | |
Penn | | | 50 | | | 41 | |
CEI | | | 250 | (3) | | 500 | |
TE | | | 250 | (3) | | 500 | |
JCP&L | | | 425 | | | 423 | |
Met-Ed | | | 250 | | | 250 | (4) |
Penelec | | | 250 | | | 250 | (4) |
FES | | | 250 | | | - | (2) |
ATSI | | | - | (5) | | 50 | |
consolidated balance sheet from which it has been derived.
| (1)
| As of September 30, 2007. |
| (2)
| No regulatory approvals, statutory or charter limitations applicable. |
| (3)
| Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s. |
| (4)
| Excluding amounts which may be borrowed under the regulated money pool. |
| (5)
| The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) such borrower has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed the obligations of such borrower under the facility. |
The revolving credit facility, combined with an aggregate $550 million ($255 million unused as of September 30, 2007) of accounts receivable financing facilities for OE, CEI, TE, Met-Ed, Penelec and Penn, are intended to provide liquidity to meet working capital requirements and for other general corporate purposes for FirstEnergy and its subsidiaries.
Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of September 30, 2007, FirstEnergy and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
Borrower
| | |
FirstEnergyPricewaterhouseCoopers LLP
| | 57 | % |
OECleveland, Ohio
| | 47 | % |
PennMay 7, 2008
| | 21 | % |
CEI
| | 60 | % |
TE
| | 55 | % |
JCP&L
| | 31 | % |
Met-Ed
| | 46 | % |
Penelec
| | 50 | % |
FES
| | 48 | % |
THE TOLEDO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 203,669 | | | $ | 233,056 | |
Excise tax collections | | | 8,025 | | | | 7,400 | |
Total revenues | | | 211,694 | | | | 240,456 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Fuel | | | 1,482 | | | | 10,147 | |
Purchased power | | | 101,298 | | | | 96,169 | |
Nuclear operating costs | | | 10,457 | | | | 17,721 | |
Other operating costs | | | 33,390 | | | | 42,921 | |
Provision for depreciation | | | 9,025 | | | | 9,117 | |
Amortization of regulatory assets | | | 25,025 | | | | 23,876 | |
Deferral of new regulatory assets | | | (9,494 | ) | | | (13,481 | ) |
General taxes | | | 14,377 | | | | 13,734 | |
Total expenses | | | 185,560 | | | | 200,204 | |
| | | | | | | | |
OPERATING INCOME | | | 26,134 | | | | 40,252 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Investment income | | | 6,481 | | | | 7,225 | |
Miscellaneous expense | | | (1,514 | ) | | | (3,100 | ) |
Interest expense | | | (6,035 | ) | | | (7,503 | ) |
Capitalized interest | | | 37 | | | | 83 | |
Total other expense | | | (1,031 | ) | | | (3,295 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 25,103 | | | | 36,957 | |
| | | | | | | | |
INCOME TAXES | | | 8,088 | | | | 11,097 | |
| | | | | | | | |
NET INCOME | | | 17,015 | | | | 25,860 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (63 | ) | | | 573 | |
Change in unrealized gain on available-for-sale securities | | | 1,961 | | | | 379 | |
Other comprehensive income | | | 1,898 | | | | 952 | |
Income tax expense related to other comprehensive income | | | 728 | | | | 334 | |
Other comprehensive income, net of tax | | | 1,170 | | | | 618 | |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 18,185 | | | $ | 26,478 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company | |
are an integral part of these statements. | | | | | | | | |
THE TOLEDO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 213 | | | $ | 22 | |
Receivables- | | | | | | | | |
Customers | | | 966 | | | | 449 | |
Associated companies | | | 42,232 | | | | 88,796 | |
Other (less accumulated provisions of $471,000 and $615,000, | | | | | |
respectively, for uncollectible accounts) | | | 4,241 | | | | 3,116 | |
Notes receivable from associated companies | | | 107,664 | | | | 154,380 | |
Prepayments and other | | | 684 | | | | 865 | |
| | | 156,000 | | | | 247,628 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 854,457 | | | | 931,263 | |
Less - Accumulated provision for depreciation | | | 397,670 | | | | 420,445 | |
| | | 456,787 | | | | 510,818 | |
Construction work in progress | | | 28,735 | | | | 19,740 | |
| | | 485,522 | | | | 530,558 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Investment in lessor notes | | | 142,657 | | | | 154,646 | |
Long-term notes receivable from associated companies | | | 37,457 | | | | 37,530 | |
Nuclear plant decommissioning trusts | | | 69,491 | | | | 66,759 | |
Other | | | 1,734 | | | | 1,756 | |
| | | 251,339 | | | | 260,691 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 500,576 | | | | 500,576 | |
Regulatory assets | | | 187,579 | | | | 203,719 | |
Pension assets | | | 29,420 | | | | 28,601 | |
Property taxes | | | 21,010 | | | | 21,010 | |
Other | | | 28,959 | | | | 20,496 | |
| | | 767,544 | | | | 774,402 | |
| | $ | 1,660,405 | | | $ | 1,813,279 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 34 | | | $ | 34 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 56,448 | | | | 245,215 | |
Other | | | 3,973 | | | | 4,449 | |
Notes payable to associated companies | | | 66,217 | | | | 13,396 | |
Accrued taxes | | | 37,085 | | | | 30,245 | |
Lease market valuation liability | | | 36,900 | | | | 36,900 | |
Other | | | 51,563 | | | | 22,747 | |
| | | 252,220 | | | | 352,986 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $5 par value, authorized 60,000,000 shares - | | | | | |
29,402,054 shares outstanding | | | 147,010 | | | | 147,010 | |
Other paid-in capital | | | 173,141 | | | | 173,169 | |
Accumulated other comprehensive loss | | | (9,436 | ) | | | (10,606 | ) |
Retained earnings | | | 192,633 | | | | 175,618 | |
Total common stockholder's equity | | | 503,348 | | | | 485,191 | |
Long-term debt and other long-term obligations | | | 303,392 | | | | 303,397 | |
| | | 806,740 | | | | 788,588 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 99,732 | | | | 103,463 | |
Accumulated deferred investment tax credits | | | 9,967 | | | | 10,180 | |
Lease market valuation liability | | | 300,775 | | | | 310,000 | |
Retirement benefits | | | 64,422 | | | | 63,215 | |
Asset retirement obligations | | | 28,744 | | | | 28,366 | |
Deferred revenues - electric service programs | | | 9,969 | | | | 12,639 | |
Lease assignment payable to associated companies | | | 28,835 | | | | 83,485 | |
Other | | | 59,001 | | | | 60,357 | |
| | | 601,445 | | | | 671,705 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 1,660,405 | | | $ | 1,813,279 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company | |
are an integral part of these balance sheets. | | | | | | | | |
THE TOLEDO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 17,015 | | | $ | 25,860 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 9,025 | | | | 9,117 | |
Amortization of regulatory assets | | | 25,025 | | | | 23,876 | |
Deferral of new regulatory assets | | | (9,494 | ) | | | (13,481 | ) |
Deferred rents and lease market valuation liability | | | 6,099 | | | | (10,891 | ) |
Deferred income taxes and investment tax credits, net | | | (3,404 | ) | | | (3,639 | ) |
Accrued compensation and retirement benefits | | | (1,813 | ) | | | (756 | ) |
Pension trust contribution | | | - | | | | (7,659 | ) |
Decrease in operating assets- | | | | | | | | |
Receivables | | | 45,738 | | | | 158 | |
Prepayments and other current assets | | | 181 | | | | 312 | |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (189,243 | ) | | | (17,533 | ) |
Accrued taxes | | | 6,840 | | | | 9,379 | |
Accrued interest | | | 4,663 | | | | 3,951 | |
Electric service prepayment programs | | | (2,670 | ) | | | (2,616 | ) |
Other | | | 991 | | | | (541 | ) |
Net cash provided from (used for) operating activities | | | (91,047 | ) | | | 15,537 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | 52,821 | | | | - | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (9 | ) | | | - | |
Short-term borrowings, net | | | - | | | | (46,518 | ) |
Net cash provided from (used for) financing activities | | | 52,812 | | | | (46,518 | ) |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (19,435 | ) | | | (6,064 | ) |
Loans repayments from (loans to) associated companies, net | | | 46,789 | | | | (8,583 | ) |
Collection of principal on long-term notes receivable | | | - | | | | 32,202 | |
Redemption of lessor notes | | | 11,989 | | | | 14,804 | |
Sales of investment securities held in trusts | | | 3,908 | | | | 16,863 | |
Purchases of investment securities held in trusts | | | (4,715 | ) | | | (17,642 | ) |
Other | | | (110 | ) | | | (420 | ) |
Net cash provided from investing activities | | | 38,426 | | | | 31,160 | |
| | | | | | | | |
Net increase in cash and cash equivalents | | | 191 | | | | 179 | |
Cash and cash equivalents at beginning of period | | | 22 | | | | 22 | |
Cash and cash equivalents at end of period | | $ | 213 | | | $ | 201 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an | |
integral part of these statements. | | | | | | | | |
The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.JERSEY CENTRAL POWER & LIGHT COMPANY
FirstEnergy'sMANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated companieselectric transmission and distribution services. JCP&L also haveprovides generation services to those customers electing to retain JCP&L as their power supplier.
Results of Operations
Net income for the abilityfirst three months of 2008 decreased to borrow$34 million from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is$38 million in the same for each company receiving a loan from their respective poolperiod in 2007. The decrease was primarily due to higher other operating costs, partially offset by higher non-generation revenues.
Revenues
In the first three months of 2008, revenues increased $111 million, or 16.5%, as compared with the same period of 2007. Retail and is based on the average cost of funds available through the pool. The average interest rate for borrowingswholesale generation revenues increased by $73 million and $38 million, respectively, in the first ninethree months of 2007 was 5.66% for the regulated companies’ money pool and 5.65% for the unregulated companies’ money pool.2008.
FirstEnergy’s accessRetail generation revenues from all customer classes increased in the first three months of 2008 compared to capital marketsthe same period of 2007 due to higher unit prices resulting from the BGS auction effective June 1, 2007, partially offset by a slight decrease in retail generation KWH sales. Sales volume decreased primarily due to milder weather in the first three months of 2008 (heating degree days were 6.7% lower than the first three months of 2007) and costsan increase in customer shopping in the commercial and industrial customer sectors by 3.6 percentage points and 3.0 percentage points, respectively.
Wholesale generation revenues increased $38 million in the first three months of financing2008 due to higher market prices, partially offset by a slight decrease in sales volumes as compared to the first three months of 2007.
Changes in retail generation KWH sales and revenues by customer class in the first three months of 2008 compared to the same period of 2007 are influenced bysummarized in the ratings of its securities. The following table displays FirstEnergy’s, FES’ and the Companies’ securities ratings as of October 18, 2007. The ratings outlook from Moody’s is stable for FES and positive for all other companies. The ratings outlook from S&P on all securities is negative.tables:
Retail Generation KWH Sales | | Increase Securities (Decrease) | |
| | | | |
Residential | | | 0.1 | % |
Commercial | | | (3.4 | )% |
Industrial | | | (12.4 | )% |
Net Decrease in Generation Sales | | | (1.9 | )% |
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 43 | |
Commercial | | | 28 | |
Industrial | | | 2 | |
Increase in Generation Revenues | | $ | 73 | |
Distribution revenues increased in the first three months of 2008 as compared to the same period of 2007 due to slight increases in composite unit prices and KWH deliveries.
Changes in distribution KWH deliveries in the first three months of 2008 compared to the same period in 2007 are summarized in the following table:
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | | |
Residential | | | | 0.1 | % |
Commercial | | | | 1.2 | % |
Industrial | | | | (1.3 | )% |
Net Increase in Distribution Deliveries | | | | 0.4 | % |
Expenses
Total expenses increased by $113 million in the first three months of 2008 as compared to the same period of 2007. The following table presents changes from the prior year period by expense category:
Expenses - Changes | | | Increase (Decrease) | |
| | | (In millions) | |
Purchased power costs | | | $ | 110 | |
Other operating costs | | | | 4 | |
Provision for depreciation | | | | 3 | |
Amortization of regulatory assets | | | | (4 | ) |
Net increase in expenses | | | $ | 113 | |
Purchased power costs increased in the first three months of 2008 primarily due to higher unit prices resulting from the BGS auction effective June 1, 2007, partially offset by a decrease in purchases due to the lower KWH sales discussed above. Other operating costs increased in the first three months of 2008 primarily due to higher expenses related to JCP&L’s customer assistance programs. Depreciation expense increased primarily due to an increase in depreciable property since the first quarter of 2007. Amortization of regulatory assets decreased in the first three months of 2008 primarily due to the completion in December 2007 of certain regulatory asset amortizations associated with TMI-2.
Other Expenses
Other expenses increased by $6 million in the first three months of 2008 as compared to the same period in 2007 primarily due to interest expense associated with JCP&L’s $550 million issuance of senior notes in May 2007 ($3 million) and reduced income on life insurance investments ($2 million).
Sale of Investment
On April 17, 2008, JCP&L closed on the sale of its 86-MW Forked River Power Plant to Maxim Power Corp. for $20 million. In conjunction with this sale, FES entered into a 10-year tolling agreement with Maxim for the entire capacity of the plant. The sale is subject to regulatory accounting and will not have a material impact on the JCP&L’s earnings in the second quarter of 2008. The New Jersey Rate Counsel has appealed the NJBPU’s approval of the sale to the Appellate Division of the Superior Court of New Jersey, where it is currently pending.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to JCP&L.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to JCP&L.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Jersey Central Power & Light Company:
We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007 and defined benefit pension and other postretirement plans as of December 31, 2006, as discussed in Note 8 and Note 4 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
|
FirstEnergyPricewaterhouseCoopers LLP Cleveland, Ohio May 7, 2008 |
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 781,433 | | | $ | 670,907 | |
Excise tax collections | | | 12,795 | | | | 12,836 | |
Total revenues | | | 794,228 | | | | 683,743 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Purchased power | | | 496,681 | | | | 386,497 | |
Other operating costs | | | 78,784 | | | | 74,651 | |
Provision for depreciation | | | 23,282 | | | | 20,516 | |
Amortization of regulatory assets | | | 91,519 | | | | 95,228 | |
General taxes | | | 17,028 | | | | 16,999 | |
Total expenses | | | 707,294 | | | | 593,891 | |
| | | | | | | | |
OPERATING INCOME | | | 86,934 | | | | 89,852 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Miscellaneous income (expense) | | | (389 | ) | | | 3,061 | |
Interest expense | | | (24,464 | ) | | | (22,416 | ) |
Capitalized interest | | | 276 | | | | 513 | |
Total other expense | | | (24,577 | ) | | | (18,842 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 62,357 | | | | 71,010 | |
| | | | | | | | |
INCOME TAXES | | | 28,403 | | | | 32,664 | |
| | | | | | | | |
NET INCOME | | | 33,954 | | | | 38,346 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (3,449 | ) | | | (2,115 | ) |
Unrealized gain on derivative hedges | | | 69 | | | | 97 | |
Other comprehensive loss | | | (3,380 | ) | | | (2,018 | ) |
Income tax benefit related to other comprehensive loss | | | (1,470 | ) | | | (984 | ) |
Other comprehensive loss, net of tax | | | (1,910 | ) | | | (1,034 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 32,044 | | | $ | 37,312 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company | |
are an integral part of these statements. | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 40 | | | $ | 94 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $3,400,000 and $3,691,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 299,104 | | | | 321,026 | |
Associated companies | | | 1,757 | | | | 21,297 | |
Other | | | 53,553 | | | | 59,244 | |
Notes receivable - associated companies | | | 18,410 | | | | 18,428 | |
Prepaid taxes | | | 1,302 | | | | 1,012 | |
Other | | | 20,609 | | | | 17,603 | |
| | | 394,775 | | | | 438,704 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 4,208,016 | | | | 4,175,125 | |
Less - Accumulated provision for depreciation | | | 1,524,495 | | | | 1,516,997 | |
| | | 2,683,521 | | | | 2,658,128 | |
Construction work in progress | | | 98,143 | | | | 90,508 | |
| | | 2,781,664 | | | | 2,748,636 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear fuel disposal trust | | | 176,107 | | | | 176,512 | |
Nuclear plant decommissioning trusts | | | 168,056 | | | | 175,869 | |
Other | | | 2,054 | | | | 2,083 | |
| | | 346,217 | | | | 354,464 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Regulatory assets | | | 1,475,802 | | | | 1,595,662 | |
Goodwill | | | 1,825,716 | | | | 1,826,190 | |
Pension assets | | | 106,211 | | | | 100,615 | |
Other | | | 15,107 | | | | 16,307 | |
| | | 3,422,836 | | | | 3,538,774 | |
| | $ | 6,945,492 | | | $ | 7,080,578 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 27,735 | | | $ | 27,206 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 82,380 | | | | 130,381 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 18,699 | | | | 7,541 | |
Other | | | 168,178 | | | | 193,848 | |
Accrued taxes | | | 32,968 | | | | 3,124 | |
Accrued interest | | | 26,656 | | | | 9,318 | |
Other | | | 107,879 | | | | 103,286 | |
| | | 464,495 | | | | 474,704 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $10 par value, authorized 16,000,000 shares- | | | | | | | | |
14,421,637 shares outstanding | | | 144,216 | | | | 144,216 | |
Other paid-in capital | | | 2,655,248 | | | | 2,655,941 | |
Accumulated other comprehensive loss | | | (21,791 | ) | | | (19,881 | ) |
Retained earnings | | | 201,542 | | | | 237,588 | |
Total common stockholder's equity | | | 2,979,215 | | | | 3,017,864 | |
Long-term debt and other long-term obligations | | | 1,554,064 | | | | 1,560,310 | |
| | | 4,533,279 | | | | 4,578,174 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Power purchase contract loss liability | | | 682,481 | | | | 749,671 | |
Accumulated deferred income taxes | | | 798,967 | | | | 800,214 | |
Nuclear fuel disposal costs | | | 194,034 | | | | 192,402 | |
Asset retirement obligations | | | 91,025 | | | | 89,669 | |
Other | | | 181,211 | | | | 195,744 | |
| | | 1,947,718 | | | | 2,027,700 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 6,945,492 | | | $ | 7,080,578 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company | |
are an integral part of these balance sheets. | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 33,954 | | | $ | 38,346 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 23,282 | | | | 20,516 | |
Amortization of regulatory assets | | | 91,519 | | | | 95,228 | |
Deferred purchased power and other costs | | | (40,293 | ) | | | (78,303 | ) |
Deferred income taxes and investment tax credits, net | | | 723 | | | | 8,076 | |
Accrued compensation and retirement benefits | | | (15,113 | ) | | | (8,374 | ) |
Cash collateral from (returned to) suppliers | | | (502 | ) | | | 1 | |
Pension trust contribution | | | - | | | | (17,800 | ) |
Decrease (increase) in operating assets: | | | | | | | | |
Receivables | | | 48,733 | | | | (23,381 | ) |
Materials and supplies | | | 255 | | | | (1 | ) |
Prepaid taxes | | | (290 | ) | | | 11,946 | |
Other current assets | | | (1,305 | ) | | | 454 | |
Increase (decrease) in operating liabilities: | | | | | | | | |
Accounts payable | | | (14,511 | ) | | | (62,038 | ) |
Accrued taxes | | | 29,844 | | | | 31,599 | |
Accrued interest | | | 17,338 | | | | 9,794 | |
Other | | | 13,302 | | | | (555 | ) |
Net cash provided from operating activities | | | 186,936 | | | | 25,508 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | - | | | | 37,071 | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (5,872 | ) | | | (9,569 | ) |
Short-term borrowings, net | | | (48,069 | ) | | | - | |
Dividend Payments- | | | | | | | | |
Common stock | | | (70,000 | ) | | | (15,000 | ) |
Net cash provided from (used for) financing activities | | | (123,941 | ) | | | 12,502 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (56,047 | ) | | | (40,015 | ) |
Loan repayments from associated companies, net | | | 18 | | | | 532 | |
Sales of investment securities held in trusts | | | 56,506 | | | | 26,436 | |
Purchases of investment securities held in trusts | | | (61,290 | ) | | | (30,437 | ) |
Other | | | (2,236 | ) | | | 5,479 | |
Net cash used for investing activities | | | (63,049 | ) | | | (38,005 | ) |
| | | | | | | | |
Net change in cash and cash equivalents | | | (54 | ) | | | 5 | |
Cash and cash equivalents at beginning of period | | | 94 | | | | 41 | |
Cash and cash equivalents at end of period | | $ | 40 | | | $ | 46 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company | |
are an integral part of these statements. | | | | | | | | |
METROPOLITAN EDISON COMPANY
ANALYSIS OF RESULTS OF OPERATIONS |
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier.
Results of Operations
Net income decreased to $22 million in the first quarter of 2008, compared to $32 million in the same period of 2007. The decrease was primarily due to higher purchased power costs, increased other operating costs and a decrease in the deferral of new regulatory assets, partially offset by higher revenues.
Revenues
Revenues increased by $30 million, or 8.1%, in the first quarter of 2008, compared to the same period of 2007, primarily due to higher retail and wholesale generation revenues combined with higher distribution throughput revenues, partially offset by a decrease in PJM transmission revenues.
In the first quarter of 2008, retail generation revenues increased $6 million primarily due to higher KWH sales to the residential and commercial customer classes and higher composite unit prices in all customer classes, partially offset by lower KWH sales to the industrial customer class.
Changes in retail generation sales and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:
| | Senior unsecuredIncrease | |
Retail Generation KWH Sales | | BBB-(Decrease) | | Baa3 |
| | | | |
Residential | | | 4.6 | % |
Commercial | | | 4.1 | % |
Industrial | | | (1.8 | )% |
Net Increase in Retail Generation Sales | | | 2.7 | % |
| | Increase | |
OERetail Generation Revenues | | Senior unsecured(Decrease) | |
| | BBB-(In millions) | |
Residential | | Baa2 $ | 4 | |
Commercial | | | 3 | |
Industrial | | | (1 | ) |
Net Increase in Retail Generation Revenues | | $ | 6 | |
Wholesale revenues increased by $27 million in the first quarter of 2008, compared to the same period of 2007, primarily reflecting higher spot market prices for PJM market participants.
Revenues from distribution throughput increased $4 million in the first quarter of 2008, compared to the same period in 2007, due to higher KWH deliveries in the residential and commercial customer classes, partially offset by decreased KWH deliveries to industrial customers.
Changes in distribution KWH deliveries and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | |
Residential | | | 4.6 | % |
CEICommercial | | Senior secured | 4.1 | % |
Industrial | | BBB+ | (1.8 | )% |
Net Increase in Distribution Deliveries | | Baa2 | 2.7 | % |
Distribution Revenues | | Increase | |
| | Senior unsecured(In millions) | |
Residential | | BBB- $ | 1 | |
Commercial | | Baa3 | 3 | |
Industrial | | | - | |
Increase in Distribution Revenues | | $ | 4 | |
PJM transmission revenues decreased by $7 million in the first quarter of 2008 compared to the same period of 2007, primarily due to decreased PJM FTR revenue. Met-Ed defers the difference between revenue from its transmission rider and transmission costs incurred, resulting in no material effect to current period earnings.
Operating Expenses
Total operating expenses increased by $42 million in the first quarter of 2008 compared to the same period of 2007. The following table presents changes from the prior year by expense category:
Expenses – Changes | | Increase | |
| | (In millions) | |
Purchased power costs | | $ | 25 | |
Other operating costs | | | 9 | |
Provision for depreciation | | | 1 | |
Amortization of regulatory assets | | | 1 | |
Deferral of new regulatory assets | | | 5 | |
General taxes | | | 1 | |
Increase in expenses | | $ | 42 | |
Purchased power costs increased by $25 million in the first quarter of 2008, primarily due to higher composite unit prices combined with increased KWH purchased to source increased generation sales. Other operating costs increased by $9 million in the first quarter of 2008 primarily due to higher transmission expenses associated with increased transmission volumes and increased labor and contractor service expenses for storm restoration work performed during the first quarter of 2008.
The deferral of new regulatory assets decreased in the first quarter of 2008 primarily due to the absence of the 2007 deferral of decommissioning costs ($15 million) associated with the Saxton nuclear research facility (see Note 11(C)), partially offset by increased transmission cost deferrals.
Other Expense
Other expense increased in the first quarter of 2008 primarily due to a decrease in interest earned on regulatory assets, reflecting a lower regulatory asset base, combined with an increase in other expenses, primarily due to reduced income from life insurance investments.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to Met-Ed.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Met-Ed.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Metropolitan Edison Company:
We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
|
PricewaterhouseCoopers LLP Cleveland, Ohio May 7, 2008 |
METROPOLITAN EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 379,608 | | | $ | 352,136 | |
Gross receipts tax collections | | | 20,718 | | | | 18,120 | |
Total revenues | | | 400,326 | | | | 370,256 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Purchased power | | | 216,982 | | | | 191,589 | |
Other operating costs | | | 107,017 | | | | 98,018 | |
Provision for depreciation | | | 11,112 | | | | 10,284 | |
Amortization of regulatory assets | | | 35,575 | | | | 34,140 | |
Deferral of new regulatory assets | | | (37,772 | ) | | | (42,726 | ) |
General taxes | | | 21,781 | | | | 21,052 | |
Total expenses | | | 354,695 | | | | 312,357 | |
| | | | | | | | |
OPERATING INCOME | | | 45,631 | | | | 57,899 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Interest income | | | 5,479 | | | | 7,726 | |
Miscellaneous income (expense) | | | (309 | ) | | | 1,109 | |
Interest expense | | | (11,672 | ) | | | (11,756 | ) |
Capitalized interest | | | (219 | ) | | | 260 | |
Total other expense | | | (6,721 | ) | | | (2,661 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 38,910 | | | | 55,238 | |
| | | | | | | | |
INCOME TAXES | | | 16,675 | | | | 23,599 | |
| | | | | | | | |
NET INCOME | | | 22,235 | | | | 31,639 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (2,233 | ) | | | (1,452 | ) |
Unrealized gain on derivative hedges | | | 84 | | | | 84 | |
Other comprehensive loss | | | (2,149 | ) | | | (1,368 | ) |
Income tax benefit related to other comprehensive loss | | | (970 | ) | | | (692 | ) |
Other comprehensive loss, net of tax | | | (1,179 | ) | | | (676 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 21,056 | | | $ | 30,963 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company | |
are an integral part of these statements. | | | | | | | | |
METROPOLITAN EDISON COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 132 | | | $ | 135 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $4,483,000 and $4,327,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 144,865 | | | | 142,872 | |
Associated companies | | | 55,776 | | | | 27,693 | |
Other | | | 20,673 | | | | 18,909 | |
Notes receivable from associated companies | | | 12,828 | | | | 12,574 | |
Prepaid taxes | | | 56,202 | | | | 14,615 | |
Other | | | 850 | | | | 1,348 | |
| | | 291,326 | | | | 218,146 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 1,997,131 | | | | 1,972,388 | |
Less - Accumulated provision for depreciation | | | 758,228 | | | | 751,795 | |
| | | 1,238,903 | | | | 1,220,593 | |
Construction work in progress | | | 32,946 | | | | 30,594 | |
| | | 1,271,849 | | | | 1,251,187 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 271,771 | | | | 286,831 | |
Other | | | 1,377 | | | | 1,360 | |
| | | 273,148 | | | | 288,191 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 424,070 | | | | 424,313 | |
Regulatory assets | | | 530,006 | | | | 494,947 | |
Pension assets | | | 54,198 | | | | 51,427 | |
Other | | | 31,097 | | | | 36,411 | |
| | | 1,039,371 | | | | 1,007,098 | |
| | $ | 2,875,694 | | | $ | 2,764,622 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Short-term borrowings- | | | | | | | | |
Associated companies | | $ | 167,070 | | | $ | 185,327 | |
Other | | | 250,000 | | | | 100,000 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 25,556 | | | | 29,855 | |
Other | | | 56,797 | | | | 66,694 | |
Accrued taxes | | | 1,501 | | | | 16,020 | |
Accrued interest | | | 7,059 | | | | 6,778 | |
Other | | | 25,191 | | | | 27,393 | |
| | | 533,174 | | | | 432,067 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 900,000 shares- | | | | | | | | |
859,000 shares outstanding | | | 1,202,833 | | | | 1,203,186 | |
Accumulated other comprehensive loss | | | (16,576 | ) | | | (15,397 | ) |
Accumulated deficit | | | (116,922 | ) | | | (139,157 | ) |
Total common stockholder's equity | | | 1,069,335 | | | | 1,048,632 | |
Long-term debt and other long-term obligations | | | 513,661 | | | | 542,130 | |
| | | 1,582,996 | | | | 1,590,762 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 456,126 | | | | 438,890 | |
Accumulated deferred investment tax credits | | | 8,234 | | | | 8,390 | |
Nuclear fuel disposal costs | | | 43,831 | | | | 43,462 | |
Asset retirement obligations | | | 163,239 | | | | 160,726 | |
Retirement benefits | | | 7,621 | | | | 8,681 | |
Other | | | 80,473 | | | | 81,644 | |
| | | 759,524 | | | | 741,793 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 2,875,694 | | | $ | 2,764,622 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral | |
part of these balance sheets. | | | | | | | | |
METROPOLITAN EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 22,235 | | | $ | 31,639 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 11,112 | | | | 10,284 | |
Amortization of regulatory assets | | | 35,575 | | | | 34,140 | |
Deferred costs recoverable as regulatory assets | | | (10,628 | ) | | | (19,160 | ) |
Deferral of new regulatory assets | | | (37,772 | ) | | | (42,726 | ) |
Deferred income taxes and investment tax credits, net | | | 17,307 | | | | 16,178 | |
Accrued compensation and retirement benefits | | | (9,655 | ) | | | (7,683 | ) |
Cash collateral | | | - | | | | 3,050 | |
Pension trust contribution | | | - | | | | (11,012 | ) |
Increase in operating assets- | | | | | | | | |
Receivables | | | (30,863 | ) | | | (49,818 | ) |
Prepayments and other current assets | | | (41,088 | ) | | | (27,131 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (14,196 | ) | | | (58,986 | ) |
Accrued taxes | | | (14,519 | ) | | | (9,835 | ) |
Accrued interest | | | 281 | | | | 1,243 | |
Other | | | 3,892 | | | | 3,939 | |
Net cash used for operating activities | | | (68,319 | ) | | | (125,878 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | 131,743 | | | | 150,619 | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (28,515 | ) | | | - | |
Net cash provided from financing activities | | | 103,228 | | | | 150,619 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (31,296 | ) | | | (18,803 | ) |
Sales of investment securities held in trusts | | | 40,513 | | | | 25,323 | |
Purchases of investment securities held in trusts | | | (43,391 | ) | | | (28,519 | ) |
Loans to associated companies, net | | | (254 | ) | | | (2,822 | ) |
Other | | | (484 | ) | | | 79 | |
Net cash used for investing activities | | | (34,912 | ) | | | (24,742 | ) |
| | | | | | | | |
Net change in cash and cash equivalents | | | (3 | ) | | | (1 | ) |
Cash and cash equivalents at beginning of period | | | 135 | | | | 130 | |
Cash and cash equivalents at end of period | | $ | 132 | | | $ | 129 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are | |
an integral part of these statements. | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY
ANALYSIS OF RESULTS OF OPERATIONS |
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier.
Results of Operations
Net income decreased to $21 million in the first quarter of 2008, compared to $32 million in the same period of 2007. The decrease was primarily due to increased purchased power costs and other operating costs and a decrease in the deferral of new regulatory assets, partially offset by higher revenues.
Revenues
Revenues increased by $40 million, or 11.1%, in the first quarter of 2008 as compared to the same time period of 2007, primarily due to higher retail and wholesale generation revenues, distribution throughput revenues and PJM transmission revenues.
In the first quarter of 2008, retail generation revenues increased $5 million primarily due to higher KWH sales to the residential and commercial customer classes and higher composite unit prices in all customer classes, partially offset by lower KWH sales to the industrial customer class.
Changes in retail generation sales and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:
Retail Generation KWH Sales | | Increase (Decrease) | |
| | | |
Residential | | | 4.5 | % |
TECommercial | | Senior unsecured | 3.0 | % |
Industrial | | BBB- | (1.6 | )% |
Net Increase in Retail Generation Sales | | Baa3 | 2.2 | % |
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 3 | |
Commercial | | | 2 | |
Industrial | | | - | |
Increase in Retail Generation Revenues | | $ | 5 | |
Wholesale revenues increased $21 million in the first quarter of 2008, compared to the same period of 2007, primarily reflecting higher spot market prices for PJM market participants.
Revenues from distribution throughput increased $4 million in the first quarter of 2008 compared to the same period of 2007, due to increased usage in the residential and commercial customer classes, partially offset by decreased KWH deliveries to industrial customers.
Changes in distribution KWH deliveries and revenues in the first quarter of 2008 compared to the same period of 2007 are summarized in the following tables:
Distribution KWH Deliveries | | Increase (Decrease) | |
| | | | | | |
Penn | | Senior secured | | A- | | Baa1 |
Residential | | | 4.5 | % |
Commercial | | | 3.0 | % |
JCP&L | | Senior unsecured | | BBB | | Baa2 |
Industrial | | | (1.5 | )% |
Net Increase in Retail Generation Sales | | | |
Met-Ed2.1 | | Senior unsecured | | BBB | | Baa2 |
| | | | | | |
Penelec | | Senior unsecured | | BBB | | Baa2 |
| | | | | | |
FES | | Corporate Credit/Issuer Rating | | BBB | | Baa2% |
Distribution Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 2 | |
Commercial | | | 2 | |
Industrial | | | - | |
Increase in Retail Generation Revenues | | $ | 4 | |
On February 21, 2007, FirstEnergy made a $700PJM transmission revenues increased by $10 million equity investment in FES, allthe first quarter of which was subsequently contributed to FGCO and used to pay down generation asset transfer-related promissory notes owed2008 compared to the Ohio Companies and Penn. OE used its $500 million of proceeds to repurchase shares of its common stock from FirstEnergy.
On March 27, 2007, CEI issued $250 million of 5.70% unsecured senior notes due 2017. The proceeds of the offering were used to reduce CEI’s short-term borrowings and for general corporate purposes.
On May 21, 2007, JCP&L issued $550 million of senior unsecured debt securities, consisting of $250 million of 5.65% senior notes due 2017 and $300 million of 6.15% senior notes due 2037. A portion of the proceeds of the offering were used to redeem outstanding FMB of JCP&L comprised of $125 million principal amount of 7.50% series and $150 million principal amount of 6.75% series. On July 1, 2007, JCP&L also redeemed all $12.2 million outstanding principal amount of its remaining series of FMB. In addition, $125 million of proceeds were used to repurchase shares of its common stock from FirstEnergy. The remaining proceeds were used for general corporate purposes.
As described above, on July 13, 2007, FGCO completed the sale and leaseback of a 93.825% undivided interest in Unit 1 of the Bruce Mansfield Generating Plant. Net after-tax proceeds of approximately $1.2 billion from the transaction were used to repay short-term borrowings from, and to invest in, the FirstEnergy non-utility money pool. The repayments and investment allowed FES to reduce its investment in that money pool in order to repay approximately $250 million of external bank borrowings and fund a $600 million equity repurchase from FirstEnergy. FirstEnergy used these funds to reduce its external short term borrowings as discussed above.
On August 30, 2007, Penelec issued $300 million of 6.05% unsecured senior notes due 2017. A portion of the net proceeds from the issuance and sale of the senior notes were used to fund the repurchase of $200 million of Penelec’s common stock from FirstEnergy. The remaining net proceeds were used to repay short-term borrowings and for general corporate purposes.
On October 4, 2007, FGCO and NGC closed on the issuance of $427 million of pollution control revenue bonds (PCRBs). Proceeds from the issuance will be used to redeem, during the fourth quartersame period of 2007, an equal amount of outstanding PCRBs originally issued on behalf ofprimarily due to higher transmission volumes. Penelec defers the Ohio Companies. This transaction brings thedifference between revenue from its transmission rider and total amount of PCRBs transferred from the Ohio Companies and Penntransmission costs incurred, resulting in no material effect to FGCO and NGC to approximately $1.9 billion, with approximately $265 million remaining to be transferred. The transfer of these PCRBs supports the intra-system generation asset transfer that was completed in 2005.current period earnings.
Cash Flows From Investing ActivitiesOperating Expenses
Net cash flows provided from investing activities resulted principally fromTotal operating expenses increased by $49 million in the proceeds fromfirst quarter of 2008 as compared with the Bruce Mansfield Unit 1 sale and leaseback transaction, partially offset by property additions. Energy delivery services expenditures for property additions primarily include expenditures related to transmission and distribution facilities. Capital expenditures by the competitive energy services segment are principally generation-related.same period of 2007. The following table summarizes investing activities forpresents changes from the nine months ended September 30, 2007 and 2006prior year by segment:expense category:
Summary of Cash Flows | | Property | | | | | | | |
Provided from (Used for) Investing Activities | | Additions | | Investments | | Other | | Total | |
Sources (Uses) | | (In millions) | |
Nine Months Ended September 30, 2007 | | | | | | | | | |
| | | | | | | | | | ) | | | |
Competitive energy services | | | | | | | | | | ) | | | |
| | | | | | | ) | | | | | | ) |
Inter-Segment reconciling items | | | | | | | ) | | | | | | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Nine Months Ended September 30, 2006 | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
Competitive energy services | | | | | | | | | | ) | | | |
| | | | | | | | | | | | | |
Inter-Segment reconciling items | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | |
Expenses - Changes | | Increase |
| | (In millions) |
Purchased power costs | | $ | 20 |
Other operating costs | | | 12 |
Provision for depreciation | | | 1 |
Amortization of regulatory assets | | | 1 |
Deferral of new regulatory assets | | | 13 |
General taxes | | | 2 |
Increase in expenses | | $ | 49 |
Purchased power costs increased by $20 million, or 10.2%, in the first quarter of 2008 compared to the same period of 2007, primarily due to increased composite unit prices combined with higher KWH purchases to source increased retail and wholesale generation sales. Other operating costs increased by $12 million in the first quarter of 2008 principally due to higher congestion costs and other transmission expenses associated with increased transmission volumes.
The deferral of new regulatory assets decreased in the first quarter of 2008 primarily due to the absence of the 2007 deferral of decommissioning costs ($12 million) associated with the Saxton nuclear research facility (see Note 11) and a decrease in transmission cost deferrals.
In the first nine monthsquarter of 2007, net cash provided from investing activities was $2312008, general taxes increased $2 million as compared to $822 million used for investing activities in the first nine months of 2006. The change was principally due to $1.3 billion in proceeds from the Bruce Mansfield Unit 1 sale and leaseback transaction described above. Partially offsetting the cash proceeds from the sale and leaseback transaction was a $137 million increase in property additions and a $61 million decrease in cash provided from cash investments, primarily from the use of restricted cash investments to repay debt during 2006.
During the remaining three months of 2007, capital requirements for property additions and capital leases are expected to be approximately $460 million. FirstEnergy and the Companies have additional requirements of approximately $10 million for maturing long-term debt during the remainder of 2007. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements, and funds raised in the capital markets.
FirstEnergy's capital spending for the period 2007-2011 is expected to be nearly $8.0 billion (excluding nuclear fuel), of which approximately $1.5 billion applies to 2007. Investments for additional nuclear fuel during the 2007-2011 period are estimated to be approximately $1.2 billion, of which about $95 million applies to 2007. During the same period FirstEnergy's nuclear fuel investments are expectedof 2007, primarily due to be reduced by approximately $810 million and $100 million, respectively, as the nuclear fuel is consumed.higher gross receipts taxes.
GUARANTEES AND OTHER ASSURANCESOther Expense
As partIn the first quarter of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries2008, other expense increased primarily due to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds,higher interest expense associated with Penelec’s $300 million senior note issuance in August 2007 and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy’s credit ratings.reduced income from life insurance investments.
AsLegal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of September 30, 2007, FirstEnergy’s maximum exposureRegistrant Subsidiaries for discussion of legal proceedings applicable to potential future payments under outstanding guaranteesPenelec.
New Accounting Standards and other assurances approximated $4.7 billion, as summarized below:Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Penelec.
| | Maximum | |
Guarantees and Other Assurances | | | |
| | (In millions) | |
FirstEnergy Guarantees of Subsidiaries | | | |
Energy and Energy-Related Contracts (1) | | $ | 647 | |
LOC (long-term debt) – interest coverage (2) | | | 9 | |
Other (3) | | | 575 | |
| | | 1,231 | |
| | | | |
Subsidiaries’ Guarantees | | | | |
Energy and Energy-Related Contracts | | | 37 | |
LOC (long-term debt) – interest coverage (2) | | | 3 | |
Other (4) | | | 2,686 | |
| | | 2,726 | |
| | | | |
Surety Bonds | | | 75 | |
LOC (long-term debt) – interest coverage (2) | | | 5 | |
LOC (non-debt) (5)(6) | | | 690 | |
| | | | |
Total Guarantees and Other Assurances | | $ | 4,727 | |
Report of Independent Registered Public Accounting Firm
| (1)
| Issued for open-ended terms, with a 10-day termination right by FirstEnergy. |
To the Stockholder and Board of
Directors of Pennsylvania Electric Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of March 31, 2008 and the related consolidated statements of income, comprehensive income and cash flows for each of the three-month periods ended March 31, 2008 and 2007. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2007, and the related consolidated statements of income, capitalization, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for uncertain tax positions as of January 1, 2007, defined benefit pension and other postretirement plans as of December 31, 2006 and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 8, Note 4, Note 2(G) and Note 11 to the consolidated financial statements) dated February 28, 2008, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2007, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
| (2)
| Reflects the interest coverage portion of LOCs issued in support of floating-rate pollution control revenue bonds with various maturities. The principal amount of floating-rate pollution control revenue bonds of $1.6 billion is reflected in long-term debt on FirstEnergy’s consolidated balance sheets. |
| (3)
| Includes guarantees of $300 million for OVEC obligations and $80 million for nuclear decommissioning funding assurances. |
PricewaterhouseCoopers LLP | (4)
| Includes FES’ guarantee of FGCO’s obligations under the sale and leaseback of Bruce Mansfield Unit 1. |
Cleveland, OhioMay 7, 2008 | (5)
| Includes $71 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility. |
| (6)
| Includes approximately $194 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by CEI and TE, $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE. |
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of subsidiary financing principally for the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of its subsidiaries directly involved in these energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty's legal claim to be satisfied by FirstEnergy’s other assets. The likelihood that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related contracts is remote.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of September 30, 2007, FirstEnergy’s maximum exposure under these collateral provisions was $442 million.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
FirstEnergy has guaranteed the obligations of the operators of the TEBSA project up to a maximum of $6 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($27 million as of September 30, 2007), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA. The LOC was reduced to $19 million on October 15, 2007.
As described above, on July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in the Bruce Mansfield Plant Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.
OFF-BALANCE SHEET ARRANGEMENTS
FES and the Ohio Companies have obligations that are not included on FirstEnergy’s Consolidated Balance Sheets related to sale and leaseback arrangements involving Perry Unit 1, Beaver Valley Unit 2 and the Bruce Mansfield Plant, which are satisfied through operating lease payments. As of September 30, 2007, the present value of these sale and leaseback operating lease commitments, net of trust investments, total $2.0 billion.
FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under Guarantees and Other Assurances above.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Derivatives that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs. The change in the fair value of commodity derivative contracts related to energy production during the three months and nine months ended September 30, 2007 is summarized in the following table:
| Three Months Ended | | Nine Months Ended | |
Increase (Decrease) in the Fair Value | September 30, 2007 | | September 30, 2007 | |
of Commodity Derivative Contracts | Non-Hedge | | Hedge | | Total | | Non-Hedge | | Hedge | | Total | |
| (In millions) | |
Change in the Fair Value of | | | | | | | | | | | | |
Commodity Derivative Contracts: | | | | | | | | | | | | |
Outstanding net liability at beginning of period | $ | (845 | ) | $ | (12 | ) | $ | (857 | ) | $ | (1,140 | ) | $ | (17 | ) | $ | (1,157 | ) |
Additions/change in value of existing contracts | | (38 | ) | | - | | | (38 | ) | | 69 | | | (6 | ) | | 63 | |
Settled contracts | | 47 | | | 5 | | | 52 | | | 235 | | | 16 | | | 251 | |
Outstanding net liability at end of period (1) | | (836 | ) | | (7 | ) | | (843 | ) | | (836 | ) | | (7 | ) | | (843 | ) |
| | | | | | | | | | | | | | | | | | |
Non-commodity Net Liabilities at End of Period: | | | | | | | | | | | | | | | | | | |
Interest rate swaps (2) | | - | | | (8 | ) | | (8 | ) | | - | | | (8 | ) | | (8 | ) |
Net Liabilities - Derivative Contracts at End of Period | $ | (836 | ) | $ | (15 | ) | $ | (851 | ) | $ | (836 | ) | $ | (15 | ) | $ | (851 | ) |
| | | | | | | | | | | | | | | | | | |
Impact of Changes in Commodity Derivative Contracts(3) | | | | | | | | | | | | | | | | | | |
Income Statement effects (pre-tax) | $ | 4 | | $ | - | | $ | 4 | | $ | 4 | | $ | - | | $ | 4 | |
Balance Sheet effects: | | | | | | | | | | | | | | | | | | |
Other comprehensive income (pre-tax) | $ | - | | $ | 5 | | $ | 5 | | $ | - | | $ | 10 | | $ | 10 | |
Regulatory assets (net) | $ | (5 | ) | $ | - | | $ | (5 | ) | $ | (300 | ) | $ | - | | $ | (300 | ) |
(1)
| Includes $836 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset. |
(2)
| Interest rate swaps are treated as cash flow or fair value hedges (see Interest Rate Swap Agreements below). |
(3)
| Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions. |
Derivatives are included on the Consolidated Balance Sheet as of September 30, 2007 as follows:
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | |
| | (In millions) | |
| | | | | | | |
| | | | | | | | | | |
| | | | | | | ) | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Other non-current liabilities | | | | ) | | | | | | |
| | | | | | | | | | |
| | | | ) | | | | | | ) |
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of September 30, 2007 are summarized by year in the following table:
Source of Information | | | | | | | | | | | | | | | |
- Fair Value by Contract Year | | | | | | | | | | | | | | | |
| | (In millions) | |
Prices actively quoted(2) | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
Other external sources(3) | | | (60 | ) | | (239 | ) | | (173 | ) | | (150 | ) | | - | | | - | | | (622 | ) |
Prices based on models | | | | | | | | | | | | | | | | ) | | | ) | | | ) |
Total(4) | | | | ) | | | ) | | | ) | | | ) | | | ) | | | ) | | | ) |
(1) For the last quarter of 2007.
(2) Exchange traded.
(3) Broker quote sheets.
(4)Includes $836 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset.
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of September 30, 2007. Based on derivative contracts held as of September 30, 2007, an adverse 10% change in commodity prices would decrease net income by approximately $6 million during the next 12 months.
Interest Rate Swap Agreements- Fair Value Hedges
FirstEnergy utilizes fixed-for-floating interest rate swap agreements as part of its ongoing effort to manage the interest rate risk associated with its debt portfolio. These derivatives are treated as fair value hedges of fixed-rate, long-term debt issues – protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. During the first nine months of 2007, FirstEnergy paid $8 million to terminate swaps with a notional amount $150 million as its subsidiary redeemed the associated hedged debt. The loss was recognized as interest expense during the nine-month period. As of September 30, 2007, the debt underlying the $600 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.11%, which the swaps have converted to a current weighted average variable rate of 5.72%.
| | September 30, 2007 | | December 31, 2006 | |
| | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | |
| | Amount | | Date | | Value | | Amount | | Date | | Value | |
| | (In millions) | |
Fair value hedges | | $ | | | | | | $ | | | $ | | | | | | $ | | ) |
| | | | | | | | | | | | | | | | | | | ) |
| | | | | | | | | | ) | | | | | | | | | ) |
| | | | | | | | | | | | | | | | | | | ) |
| | | | | | | | | | | | | | | | | | | ) |
| | | | | | | | | | | | | | | | | | | ) |
| | | | | | | | | | | | | | | | | | | ) |
Forward Starting Swap Agreements - Cash Flow Hedges
PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | |
| Three Months Ended | |
| March 31, | |
| | | | | | |
| | 2008 | | | 2007 | |
| | | | | | |
| (In thousands) | |
| | | | | | |
REVENUES: | | | | | | |
Electric sales | | $ | 376,028 | | | $ | 339,226 | |
Gross receipts tax collections | | | 19,464 | | | | 16,680 | |
Total revenues | | | 395,492 | | | | 355,906 | |
| | | | | | | | |
EXPENSES: | | | | | | | | |
Purchased power | | | 221,234 | | | | 200,842 | |
Other operating costs | | | 71,077 | | | | 59,461 | |
Provision for depreciation | | | 12,516 | | | | 11,777 | |
Amortization of regulatory assets | | | 16,346 | | | | 15,394 | |
Deferral of new regulatory assets | | | (3,526 | ) | | | (17,088 | ) |
General taxes | | | 21,855 | | | | 19,851 | |
Total expenses | | | 339,502 | | | | 290,237 | |
| | | | | | | | |
OPERATING INCOME | | | 55,990 | | | | 65,669 | |
| | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
Miscellaneous income (expense) | | | (191 | ) | | | 1,417 | |
Interest expense | | | (15,322 | ) | | | (11,337 | ) |
Capitalized interest | | | (806 | ) | | | 258 | |
Total other expense | | | (16,319 | ) | | | (9,662 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 39,671 | | | | 56,007 | |
| | | | | | | | |
INCOME TAXES | | | 18,279 | | | | 24,263 | |
| | | | | | | | |
NET INCOME | | | 21,392 | | | | 31,744 | |
| | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
Pension and other postretirement benefits | | | (3,473 | ) | | | (2,825 | ) |
Unrealized gain on derivative hedges | | | 16 | | | | 16 | |
Change in unrealized gain on available-for-sale securities | | | 11 | | | | (3 | ) |
Other comprehensive loss | | | (3,446 | ) | | | (2,812 | ) |
Income tax benefit related to other comprehensive loss | | | (1,506 | ) | | | (1,298 | ) |
Other comprehensive loss, net of tax | | | (1,940 | ) | | | (1,514 | ) |
| | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 19,452 | | | $ | 30,230 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company | |
are an integral part of these statements. | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | March 31, | | | December 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 43 | | | $ | 46 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $4,201,000 and $3,905,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 141,316 | | | | 137,455 | |
Associated companies | | | 23,396 | | | | 22,014 | |
Other | | | 28,833 | | | | 19,529 | |
Notes receivable from associated companies | | | 16,923 | | | | 16,313 | |
Prepaid gross receipts taxes | | | 41,242 | | | | - | |
Other | | | 2,426 | | | | 3,077 | |
| | | 254,179 | | | | 198,434 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,230,667 | | | | 2,219,002 | |
Less - Accumulated provision for depreciation | | | 843,500 | | | | 838,621 | |
| | | 1,387,167 | | | | 1,380,381 | |
Construction work in progress | | | 33,727 | | | | 24,251 | |
| | | 1,420,894 | | | | 1,404,632 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 132,152 | | | | 137,859 | |
Non-utility generation trusts | | | 113,958 | | | | 112,670 | |
Other | | | 536 | | | | 531 | |
| | | 246,646 | | | | 251,060 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 777,616 | | | | 777,904 | |
Pension assets | | | 69,405 | | | | 66,111 | |
Other | | | 29,770 | | | | 33,893 | |
| | | 876,791 | | | | 877,908 | |
| | $ | 2,798,510 | | | $ | 2,732,034 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Short-term borrowings- | | | | | | | | |
Associated companies | | $ | 183,102 | | | $ | 214,893 | |
Other | | | 150,000 | | | | - | |
Accounts payable- | | | | | | | | |
Associated companies | | | 61,476 | | | | 83,359 | |
Other | | | 50,516 | | | | 51,777 | |
Accrued taxes | | | 9,302 | | | | 15,111 | |
Accrued interest | | | 13,677 | | | | 13,167 | |
Other | | | 23,330 | | | | 25,311 | |
| | | 491,403 | | | | 403,618 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $20 par value, authorized 5,400,000 shares- | | | | | | | | |
4,427,577 shares outstanding | | | 88,552 | | | | 88,552 | |
Other paid-in capital | | | 920,265 | | | | 920,616 | |
Accumulated other comprehensive income | | | 3,006 | | | | 4,946 | |
Retained earnings | | | 79,336 | | | | 57,943 | |
Total common stockholder's equity | | | 1,091,159 | | | | 1,072,057 | |
Long-term debt and other long-term obligations | | | 732,465 | | | | 777,243 | |
| | | 1,823,624 | | | | 1,849,300 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Regulatory liabilities | | | 67,347 | | | | 73,559 | |
Accumulated deferred income taxes | | | 220,500 | | | | 210,776 | |
Retirement benefits | | | 41,644 | | | | 41,298 | |
Asset retirement obligations | | | 83,129 | | | | 81,849 | |
Other | | | 70,863 | | | | 71,634 | |
| | | 483,483 | | | | 479,116 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 2,798,510 | | | $ | 2,732,034 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an | |
integral part of these balance sheets. | | | | | | | | |
FirstEnergy utilizes forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries in 2007 and 2008. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first nine months of 2007, FirstEnergy terminated forward swaps with an aggregate notional value of $1.6 billion. FirstEnergy paid $20 million in cash related to the terminations, which will be recognized over the terms of the associated future debt. There was no ineffective portion associated with the loss. As of September 30, 2007, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $400 million and an aggregate fair value of $5 million.79
| | September 30, 2007 | | December 31, 2006 | |
| | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | |
| | Amount | | Date | | Value | | Amount | | Date | | Value | |
| | (In millions) | |
Cash flow hedges | | $ | | | | | | $ | | | $ | | | | | | $ | | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | ) | | | | | | | | | ) |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | | 2007 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 21,392 | | | $ | 31,744 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 12,516 | | | | 11,777 | |
Amortization of regulatory assets | | | 16,346 | | | | 15,394 | |
Deferral of new regulatory assets | | | (3,526 | ) | | | (17,088 | ) |
Deferred costs recoverable as regulatory assets | | | (8,403 | ) | | | (18,433 | ) |
Deferred income taxes and investment tax credits, net | | | 10,541 | | | | 13,366 | |
Accrued compensation and retirement benefits | | | (10,488 | ) | | | (8,786 | ) |
Cash collateral | | | 301 | | | | 1,450 | |
Pension trust contribution | | | - | | | | (13,436 | ) |
Increase in operating assets- | | | | | | | | |
Receivables | | | (13,701 | ) | | | (30,050 | ) |
Prepayments and other current assets | | | (40,591 | ) | | | (36,225 | ) |
Increase (Decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (23,144 | ) | | | (46,168 | ) |
Accrued taxes | | | (5,809 | ) | | | (9,152 | ) |
Accrued interest | | | 510 | | | | 5,518 | |
Other | | | 4,991 | | | | 3,920 | |
Net cash used for operating activities | | | (39,065 | ) | | | (96,169 | ) |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | 118,209 | | | | 119,361 | |
Redemptions and Repayments | | | | | | | | |
Long-term debt | | | (45,112 | ) | | | - | |
Net cash provided from financing activities | | | 73,097 | | | | 119,361 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (28,902 | ) | | | (20,404 | ) |
Sales of investment securities held in trusts | | | 24,407 | | | | 12,758 | |
Purchases of investment securities held in trusts | | | (29,083 | ) | | | (15,509 | ) |
Loan repayments from (loans to) associated companies, net | | | (610 | ) | | | 708 | |
Other | | | 153 | | | | (747 | ) |
Net cash used for investing activities | | | (34,035 | ) | | | (23,194 | ) |
| | | | | | | | |
Net change in cash and cash equivalents | | | (3 | ) | | | (2 | ) |
Cash and cash equivalents at beginning of period | | | 46 | | | | 44 | |
Cash and cash equivalents at end of period | | $ | 43 | | | $ | 42 | |
| | | | | | | | |
The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are | |
an integral part of these statements. | | | | | | | | |
COMBINED MANAGEMENT’S DISCUSSION
AND ANALYSIS OF REGISTRANT SUBSIDIARIES
The following is a combined presentation of certain disclosures referenced in Management’s Narrative Analysis of Results of Operations of FES and the Companies. This information should be read in conjunction with (i) FES’ and the Companies’ respective Consolidated Financial Statements and Management’s Narrative Analysis of Results of Operations; (ii) the Combined Notes to Consolidated Financial Statements as they relate to FES and the Companies; and (iii) FES’ and the Companies’ respective 2007 Annual Reports on Form 10-K.
Included in nuclear decommissioning trusts are marketable equity securities carried at their market valueRegulatory Matters (Applicable to each of approximately $1.4 billion as of September 30, 2007 and December 31, 2006. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $139 million reduction in fair value as of September 30, 2007.
CREDIT RISK
Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.
FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB+ (S&P). As of September 30, 2007, the largest credit concentration with one party (currently rated investment grade) represented 10.9% of FirstEnergy‘s total credit risk. Within FirstEnergy’s unregulated energy subsidiaries, 99% of credit exposures, net of collateral and reserves, were with investment-grade counterparties as of September 30, 2007.
Outlook
State Regulatory MattersCompanies)
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:
· | restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies; |
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· | establishing or defining the PLR obligations to customers in the Companies' service areas; |
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· | providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; |
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· | itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges; |
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· | continuing regulation of the Companies' transmission and distribution systems; and |
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· | requiring corporate separation of regulated and unregulated business activities. |
The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $227$137 million as of September 30, 2007March 31, 2008 (JCP&L - $93$78 million and Met-Ed - $43 million and Penelec - $91$59 million). Regulatory assets not earning a current return willare expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec.Met-Ed. The following table discloses regulatory assets by company:
| | September 30, | | December 31, | | Increase | | | March 31, | | December 31, | | Increase | |
Regulatory Assets* | | 2007 | | 2006 | | (Decrease) | | | 2008 | | 2007 | | (Decrease) | |
| | (In millions) | | | (In millions) | |
OE | | $ | 717 | | $ | 741 | | $ | (24 | ) | | $ | 710 | | $ | 737 | | $ | (27 | ) |
CEI | | | 856 | | | 855 | | | 1 | | | | 854 | | | 871 | | | (17 | ) |
TE | | | 215 | | | 248 | | | (33 | ) | | | 188 | | | 204 | | | (16 | ) |
JCP&L | | | 1,758 | | | 2,152 | | | (394 | ) | | | 1,476 | | | 1,596 | | | (120 | ) |
Met-Ed | | | 459 | | | 409 | | | 50 | | | | 530 | | | 495 | | | 35 | |
ATSI | | | | | | | | | | | | | | | | | | | | ) |
Total | | | | | | | | | | ) | | | | | | | | | | ) |
The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005.RCP. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 20072008 through 2010:
On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing retail generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hourKWH would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. A slice-of-system approach would require the successful bidder to be responsible for supplying a fixed percentage of the utility’s total load notwithstanding the customer’s classification. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Comments by intervenors in the case were filed on September 5, 2007. The PUCO Staff filed comments on September 21, 2007. Parties filedInitial and reply comments on the proposal were filed by various parties in September and October 12, 2007.2007, respectively. The Ohio Companies requested thatproposal is currently pending before the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.PUCO.
A utility could also simultaneously file an MRO in which it would have to demonstrate the following objective market criteria: The utility or its transmission service affiliate belongs to a FERC-approved RTO having a market-monitor function and the ability to mitigate market power, and a published source exists that identifies information for traded electricity and energy plan was officially introducedproducts that are contracted for delivery two years into the Ohio Senate.future. The PUCO would test the ESP and its pricing and all other terms and conditions against the MRO and may only approve the ESP if it is found to be more favorable to customers. As part of an ESP with a plan period longer than three years, the PUCO shall prospectively determine every fourth year of the plan whether it is substantially likely the plan will provide the electric distribution utility a return on common equity significantly in excess of the return likely to be earned by publicly traded companies, including utilities, that face comparable business and financial risk (comparable companies). If so, the PUCO may terminate the ESP. Annually under an ESP, the PUCO shall determine whether an electric distribution utility's earned return on common equity is significantly in excess of returns earned on common equity during the same period by comparable companies, and if so, shall require the utility to return such excess to customers by prospective adjustments. Amended Substitute SB221 also includes provisions dealing with advanced and renewable energy standards that contemplate 25% of electrical usage from these sources by 2025. Energy efficiency measures in the bill proposesrequire energy savings in excess of 22% by 2025. Requirements are in place to revise statemeet annual benchmarks for renewable energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standardsresources and energy efficiency, standards,subject to review by the PUCO. FirstEnergy is currently evaluating this legislation and create GHG emissions reporting and carbon control planning requirements. The bill also proposesexpects to move to a “hybrid” system for determining rates for PLR servicefile an ESP in which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate the existencesecond or third quarter of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee has been conducting hearings on the bill and receiving testimony from interested parties, including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. Several proposed amendments to the bill have been submitted, including those from Ohio’s investor-owned electric utilities. A substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of the Ohio Companies.2008.
Pennsylvania(Applicable to FES, Met-Ed, Penelec, OE and Penn)
Met-Ed and Penelec have been purchasingpurchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec.agreement. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy requirements during the term of these agreements with FES.
On September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that were substantially higher than the fixed price in the partial requirements agreements.
Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The parties also have separately terminated the supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.
If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for itstheir fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.
Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.
The PPUC entered its Opinionopinion and Orderorder in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, when new transmission rates were effective, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes into NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission expenses and the transmission deferral.costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.
On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. OnFrom June 19,through October 2007, initial responsive and reply briefs were filed and responsive briefs were filed through September 21, 2007. Reply briefs were filed on October 5, 2007.by various parties. Oral arguments are expectedscheduled to take place in late 2007 or earlySeptember 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.
As of September 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $496 million and $58 million, respectively. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiringApril 14, 2008, Met-Ed and Penelec filed annual updates to reflect the deferred NUG cost balances as ifTSC rider for the stranded cost accounting methodology modification had not been implemented. Asperiod June 1, 2008, through May 31, 2009. The proposed TSCs include a resultcomponent for under-recovery of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3actual transmission costs incurred during the prior period (Met-Ed - $144 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded- $4 million) and future transmission cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its orderprojections for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.
On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed has proposed a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for fixed-price, tranche-based, pay as bid PLR supply torecovery through future TSCs by December 31, 2010.
On March 13, 2008, the PPUC approved the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. On September 28, 2007, Penn filed aprocurement process in Penn’s Joint Petition for Settlement resolving all but one issueSettlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the case. Briefstwo RFPs for small commercial load were alsoapproved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed on September 28, 2007compliance tariffs with the new default service generation rates based on the unresolved issueapproved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of incremental uncollectible accounts expense.tranches for both 12 and 24-month supply. The settlementPPUC approved the bids on April 16, 2008. The second RFP is either supported, or not opposed, by all parties. Thescheduled to be held on May 14, 2008, after which time the PPUC is expected to act onapprove the settlement and the unresolved issue in late November or early December 2007 for the initial RFPnew rates to take place in Januarygo into effect June 1, 2008.
On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet demandenergy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and an optionala three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of anythis pending legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy isMet-Ed, Penelec, OE and Penn are unable to predict what impact, if any, such legislation may have on itstheir operations.
New Jersey(Applicable to JCP&L)
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2007,March 31, 2008, the accumulated deferred cost balance totaled approximately $330$264 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, theThe NJBPU Staff circulated a revised draftdrafts of the proposal to interested stakeholders. Another revised draft was circulated bystakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU Staffaccepted proposed rules for publication in the New Jersey Register on February 8, 2007.March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 with comments from interested parties due on May 16, 2008.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated withthrough the issuancecreation of a proposed set of objectives which, as to electricity, included the following:
· Reduce the total projected electricity demand by 20% by 2020;
· | Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date; |
· Reduce air pollution related to energy use;
· Encourage and maintain economic growth and development;
· | Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020; |
· | Maintain unit prices for electricity to no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and |
· Eliminate transmission congestion by 2020.
Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. PublicIn addition, public stakeholder meetings were held in the fall of 2006 and in early 2007, and further2007.
On April 17, 2008, a draft EMP was released for public meetings are expected later in 2007. A finalcomment. The draft EMP establishes four major goals:
· | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
· | reduce peak demand for electricity by 5,700 MW by 2020 (amounting to about a 22% reduction in projected demand); |
· | meet 22.5% of the state’s electricity needs with renewable energy by 2020; and |
· | develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity. |
Following the EMPpublic comment period which is expected to extend into July 2008, a final EMP will be presentedissued to the Governor in late 2007.be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergyJCP&L cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.operations.
On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments whichthat were due onsubmitted in September 26,and October 2007. At this time, FirstEnergy cannot predictFinal regulations (effective upon publication) were published in the outcomeNew Jersey Register March 17, 2008. Upon preliminary review of this process nor determine the impact, if any, suchnew regulations, may haveJCP&L does not expect a material impact on its operations or those of JCP&L.operations.
FERC Matters(Applicable to FES and each of the Companies)
Transmission Service between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the RTORthrough and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate so-called “pancaking” of transmission charges between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a SECArate mechanism to recover lost RTORtransmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period from load serving entities.period. The FERC issued orders in 2005 setting the SECA for hearing. ATSI, JCP&L, Met-Ed, Penelec, and FES participated in the FERC hearings held in May 2006 concerning the calculation and imposition of the SECA charges. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the fourthsecond quarter of 2007.2008.
PJM Transmission Rate Design
On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, BG&E and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. Hearings were held and numerous parties appeared and litigated various issues; includingissues concerning PJM rate design; notably AEP, which filed in opposition proposingproposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM. AtPJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the conclusioneffect of shifting recovery of the hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the costcosts of all PJMhigh voltage transmission facilities should be recovered through a postage stamp rate.The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties,lines to other transmission zones, including FirstEnergy, submitted briefs opposing the ALJ’s decisionthose where JCP&L, Met-Ed, and recommendations.Penelec serve load. On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC foundfinding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be socializedcollected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. Nevertheless, theThe FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 Order. Subsequently, FirstEnergy and other parties filed pleadings opposingorder. On January 31, 2008, the requests for rehearing.rehearing were denied. The FERC’s Ordersorders on PJM rate design if sustained on rehearing and appeal, will prevent the allocation of a portion of the costrevenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission costs shifting torevenue recovery from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues will proceed to hearing in May 2008. On February 13, 2008, AEP appealed the FERC’s orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.
New FERC TransmissionPost Transition Period Rate Design Filings
The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within the MISO, and between MISO and PJM. On August 1, 2007, a number of filings were made withby MISO, PJM, and the FERC by transmission owning utilities in the MISO and PJM footprint that could affect the transmission rates paid by FirstEnergy’s operating companies and FES.
FirstEnergy joined in a filing made by the MISOvast majority of transmission owners, that would maintainincluding FirstEnergy affiliates, which proposed to retain the existing “license plate” rates for transmission service within MISO provided over existing transmission facilities. FirstEnergy also joined in a filing made by both the MISO and PJM transmission owners proposing to continue the elimination of transmission rates associated with service over existing transmission facilities between MISO and PJM. If adoptedrate design. These filings were approved by the FERC these filings would not affecton January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving FirstEnergy affiliates for transmission service over existing transmission facilities.facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint be maintained (known as the RECB Process). Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.
The Midwest Stand-Alone Transmission Companies made a filing under Section 205 of the Federal Power Act requesting that 100% of the cost of new qualifying 345 kV and higher transmission facilitiesmethodology) be spread throughout the entire MISO footprint. Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process. If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilities to the FirstEnergy footprint in MISO, and increase the transmission rates paid by load-serving FirstEnergy affiliates in MISO.retained.
On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “SuperRegion”“Super Region” that regionalizesrecovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above.above from all transmission customers. Lower voltage facilities would continue to be recovered in the hostlocal utility transmission rate zone through a license plate rate. AEP requestsrequested a refund effective October 1, 2007, or alternatively, February 1, 2008. The effectOn January 31, 2008, the FERC issued an order denying the complaint. A rehearing request by AEP is pending before the FERC.
Distribution of this proposal, if adopted by FERC, would be to shift significant costs toMISO Network Service Revenues
Effective February 1, 2008, the FirstEnergy zonesMISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and PJM. FirstEnergy believes that mosta majority of these costs would ultimately be recoverable in retail rates. On October 12, 2007, BG&E filed a motion to dismiss AEP’s complaint. On October 16, 2007, the Organization of MISO States filed comments urging the FERC to dismiss AEP’s complaint. Interventions and protests to AEP’s complaint and answers to BG&E’s motion to dismiss were due October 29, 2007. FirstEnergy and other transmission owners filed protestson December 3, 2007 to AEP’s complaintchange the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and support for BG&E’s motion to dismiss. AEP has asked for consolidation of its complaintretained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the cases above,FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and FirstEnergy expects itthat transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.
Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be resolvedcharged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.
On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same timeline as those cases.day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.
Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC. All or some of these proceedings may be consolidated by the FERC and set for hearing. The outcome of these cases cannot be predicted. Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates. FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates. Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.
MISO Ancillary Services Market and Balancing Area Consolidation Filing
MISO made a filing on September 14, 2007 to establish Ancillary Services marketsan ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. An effective date of June 1, 2008 was requestedThis filing would permit load serving entities to purchase their operating reserve requirements in the filing.
MISO’s previous filing to establish an Ancillary Services market was rejected without prejudice by FERC on June 22, 2007, subject to MISO making certain modifications in its filing. FirstEnergy believes that MISO’s September 14 filing generally addresses the FERC’s directives. FirstEnergy supportsa competitive market. FES, CEI, OE, Penn and TE support the proposal to establish markets for Ancillary Services and consolidate existing balancing areas,areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. MISO has since notified the FERC that the start of its ASM is delayed until September of 2008.
Duquesne’s Request to Withdraw from PJM
On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join the MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but filed objections on specificcovering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.
On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FES and the Companies and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed the MISO proposal. Interventionsto submit detailed plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and protestsPJM to MISO’s filing were madework together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 9, 2008.
On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators can contract with FERCPJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfies the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on October 15, 2007.April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.
MISO Resource Adequacy Proposal
Order No. 890MISO made a filing on Open Access Transmission TariffsDecember 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy generally supports the proposal as it promotes a mechanism that will result in long-term commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC approved MISO’s Resource Adequacy proposal on March 26, 2008. Rehearing requests are pending on the FERC’s March 26 Order. A compliance filing establishing the enforcement mechanism for the reserve margin requirement is due on or before June 25, 2008.
Organized Wholesale Power Markets
On February 16, 2007,21, 2008, the FERC issued a finalNOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule (Order No. 890)addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FES and the Companies do not believe that revises its decade-old open access transmissionthe proposed rule will have a significant impact on their operations. Comments on the NOPR were filed on April 18, 2008.
Environmental Matters
Various federal, state and local authorities regulate FES and the Companies with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Companies with regard to environmental matters could have a material adverse effect on their earnings and competitive position to the extent that they compete with companies that are not subject to such regulations and, policies. The FERC explained thattherefore, do not bear the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffsrisk of costs associated with compliance, or failure to comply, with such regulations. FES and the FERC’s order. MISO, PJM and ATSI submitted tariff filings toCompanies estimate capital expenditures for environmental compliance of approximately $1.4 billion for the FERC on October 11, 2007. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.period 2008-2012.
Environmental Matters
FirstEnergy accruesFES and the Companies accrue environmental liabilities only when it concludesthey conclude that it is probable that it hasthey have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’sFES’ and the Companies’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance(Applicable to FES)
FirstEnergyFES is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergyFES believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the Clean Air Act. FirstEnergyCAA. FES has disputed those alleged violations based on its Clean Air ActCAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergyFES complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FirstEnergy'sFES' facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergyFES believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act,CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 16,18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.
On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the Court. Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the sale of the Portland Station in 1999, Met-Ed is currently studying PennFuture’s complaint.indemnified by Sithe Energy against any other liability arising under the CAA whether it arises out of pre-1999 or post-1999 events.
National Ambient Air Quality Standards(Applicable to FES)
In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR allowed each affected state until 2006 to develop implementing regulations to achieve additionalrequires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2). FirstEnergy'sFES' Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO2 and NOX emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NOX emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOX emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOX cap of 1.3 million tons annually. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. The future cost of compliance with these regulations may be substantial and willmay depend on the outcome of this litigation and how they areCAIR is ultimately implemented by the states in which FirstEnergy operates affected facilities.implemented.
Mercury Emissions(Applicable to FES)
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially,phases; initially, capping national mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at and 15 tons per year by 2018. However, the final rules giveSeveral states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and environmental groups appealed the CAMR have been challenged into the United States Court of Appeals for the District of Columbia. FirstEnergy'sOn February 8, 2008, the court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap and trade program. The EPA must now seek further judicial review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with thesemercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented by the states in which FirstEnergy operates affected facilities.implemented.
The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FirstEnergy would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FirstEnergy will be disadvantaged if these model rules were implemented as proposed because FirstEnergy’s substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’sFES’ only Pennsylvania coal-fired Pennsylvania power plant, until 2015, if at all.
W. H. Sammis Plant(Applicable to FES, OE and Penn)
In 1999 and 2000, the EPA issued an NOV or compliance orders to nine utilities alleging violations ofand the Clean Air ActDOJ filed a civil complaint against OE and Penn based on operation and maintenance of 44 power plants, including the W. H.W.H. Sammis Plant which was owned at that time by OE(Sammis NSR Litigation) and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civilsimilar complaints against various investor-owned utilities, including a complaint against OE and Penn in theinvolving 44 other U.S. District Court for the Southern District of Ohio. Thesepower plants. This case, along with seven other similar cases, are referred to as the New Source Review, or NSR cases.
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergyFGCO, OE and Penn could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreementconsent decree are currently estimated to be $1.7$1.3 billion for 2007 through 2011FGCO for 2008-2012 ($400650 million of which is expected to be spent during 2007,2008, with the largest portion of the remaining $1.3 billion$650 million expected to be spent in 2008 and 2009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.
On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 millionEPA has not yet issued a final regulation. FGCO’s future cost of which is satisfied by entering into 93 MW (or 23 MW if federal tax creditscompliance with those regulations may be substantial and will depend on how they are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.ultimately implemented.
Climate Change(Applicable to FES)
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. AtAlso, in an April 16, 2008 speech, President Bush set a policy goal of stopping the international level, efforts have begun to develop climate change agreements for post-2012growth of GHG reductions. Theemissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States.States, and the Senate Environmental and Public Works Committees have passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the Clean Air Act.CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the Clean Air ActCAA to regulate “air pollutants” from those and other facilities. Also on April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.
FirstEnergyFES cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FirstEnergyFES is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act(Applicable to FES)
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy'sFES’ plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy'sFES' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality when(when aquatic organisms are pinned against screens or other parts of a cooling water intake system,system) and entrainment which(which occurs when aquatic life is drawn into a facility's cooling water system.system). On January 26, 2007, the federalUnited States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. On April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review certain aspects of the Second Circuit’s decision. FirstEnergy is evaluatingstudying various control options and their costs and effectiveness. Depending on the outcomeresults of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future costcosts of compliance with these standards may require material capital expenditures.
Regulation of Hazardous Waste(Applicable to FES and each of the Companies)
As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardousnon-hazardous waste.
Under NRC regulations, FirstEnergyFES and the Companies must ensure that adequate funds will be available to decommission its nuclear facilities. As of September 30, 2007, FirstEnergyMarch 31, 2008, FES and the Companies had approximately $1.5$2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and Perry.TMI-2. As part of the application to the NRC to transfer the ownership of these nuclear facilitiesDavis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plansand FES (and Exelon for TMI-1 as it relates to seekthe timing of the decommissioning of TMI-2) seeks for these facilities.
The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site aremay be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2007,March 31, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition,Total liabilities of approximately $92 million (JCP&L - $65 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2008. Included in the total for JCP&L hasare accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey; those costswhich are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $89 million have been accrued through September 30, 2007.
Other Legal Proceedings
Other Legal Proceedings
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other material items not otherwise discussed above are described below.
Power Outages and Related Litigation(Applicable to JCP&L)
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court. FirstEnergyCourt and a case management conference with the presiding Judge is scheduled for June 13, 2008. JCP&L is defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of September 30, 2007.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. – Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.March 31, 2008.
FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Two other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. The four cases remaining were consolidated for hearing by the PUCO in an order dated March 7, 2006. In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on January 8, 2008.
FirstEnergy is defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
Nuclear Plant Matters(Applicable to FES)
On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for InformationDFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information, about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for InformationDFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. The NRC heldFENOC submitted a public meeting on June 27, 2007 with FENOC to discuss FENOC’ssupplemental response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarifyclarifying certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplementalDFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to future NRC review.
Other Legal Matters(Applicable to OE, JCP&L and FES)
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint which OE has opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. The arbitration panel provided additional rulings regarding damages during a September 2007 hearing and it is anticipated that he will issue aA final order in lateidentifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L intendsfiled its answer and counterclaim to re-file an appeal againvacate the award on December 31, 2007. The court held a scheduling conference in federal district court once the damages associatedApril 2008 where it set a briefing schedule with this case are identified at an individual employee level.all briefs to be concluded by July 2008. JCP&L recognized a liability for the potential $16 million award in 2005.
The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready in the event of a strike.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
SFAS 157 – “Fair Value Measurements”
In September 2006, the FASB issued SFAS 157 that establishes how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement, as well as the inclusion of an adjustment for risk, restrictions and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.
| SFAS 159 – “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115”
|
In February 2007, the FASB issued SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value. This Statement requires companies to provide additional information that will help investors and other users of financial statements to more easily understand the effect of the company’s choice to use fair value on its earnings. The Standard also requires companies to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157and SFAS 107. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FirstEnergy is currently evaluating the impact of this Statement on its financial statements.
EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”
In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to APIC. This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years beginning after December 15, 2007. EITF 06-11 is not expected to have a material effect on FirstEnergy’s financial statements.
FSP FIN 39-1 – “Amendment of FASB Interpretation No. 39”
In April 2007, the FASB issued Staff Position (FSP) FIN 39-1, which permits an entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments that have been offset under the same master netting arrangement as the derivative instruments. This FSP is effective for fiscal years beginning after November 15, 2007, with early application permitted. The effects of applying the guidance in this FSP should be recognized as a retrospective change in accounting principle for all financial statements presented. FirstEnergy is currently evaluating the impact of this FSP on its financial statements but it is not expected to have a material impact.
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended | |
| | September 30, | | | September 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales to affiliates | | $ | 805,372 | | | $ | 762,106 | | | $ | 2,209,743 | | | $ | 1,997,096 | |
Other | | | 365,536 | | | | 347,474 | | | | 1,048,189 | | | | 1,063,026 | |
Total revenues | | | 1,170,908 | | | | 1,109,580 | | | | 3,257,932 | | | | 3,060,122 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Fuel | | | 301,786 | | | | 315,521 | | | | 804,201 | | | | 844,913 | |
Purchased power from non-affiliates | | | 228,755 | | | | 173,620 | | | | 577,831 | | | | 477,249 | |
Purchased power from affiliates | | | 62,508 | | | | 55,647 | | | | 209,576 | | | | 188,698 | |
Other operating expenses | | | 235,033 | | | | 198,716 | | | | 731,774 | | | | 774,767 | |
Provision for depreciation | | | 48,500 | | | | 46,894 | | | | 145,030 | | | | 135,414 | |
General taxes | | | 22,242 | | | | 17,609 | | | | 64,870 | | | | 55,550 | |
Total expenses | | | 898,824 | | | | 808,007 | | | | 2,533,282 | | | | 2,476,591 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 272,084 | | | | 301,573 | | | | 724,650 | | | | 583,531 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Miscellaneous income | | | 12,655 | | | | 27,662 | | | | 47,756 | | | | 44,843 | |
Interest expense to affiliates | | | (9,641 | ) | | | (41,416 | ) | | | (61,904 | ) | | | (122,664 | ) |
Interest expense - other | | | (31,794 | ) | | | (7,914 | ) | | | (70,845 | ) | | | (17,880 | ) |
Capitalized interest | | | 5,131 | | | | 2,389 | | | | 12,763 | | | | 8,698 | |
Total other expense | | | (23,649 | ) | | | (19,279 | ) | | | (72,230 | ) | | | (87,003 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 248,435 | | | | 282,294 | | | | 652,420 | | | | 496,528 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 93,671 | | | | 106,175 | | | | 243,736 | | | | 184,572 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 154,764 | | | | 176,119 | | | | 408,684 | | | | 311,956 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | (1,360 | ) | | | - | | | | (4,080 | ) | | | - | |
Unrealized gain (loss) on derivative hedges | | | 4,863 | | | | (6,257 | ) | | | 9,451 | | | | (6,376 | ) |
Change in unrealized gain on available for sale securities | | | 21,263 | | | | 20,945 | | | | 80,053 | | | | 29,266 | |
Other comprehensive income | | | 24,766 | | | | 14,688 | | | | 85,424 | | | | 22,890 | |
Income tax expense related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | 8,915 | | | | 5,453 | | | | 30,474 | | | | 8,548 | |
Other comprehensive income, net of tax | | | 15,851 | | | | 9,235 | | | | 54,950 | | | | 14,342 | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 170,615 | | | $ | 185,354 | | | $ | 463,634 | | | $ | 326,298 | |
| | | | | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of | |
these statements. | | | | | | | | | | | | | | | | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | September 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 2 | | | $ | 2 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $8,007,000 and $7,938,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 144,443 | | | | 129,843 | |
Associated companies | | | 285,462 | | | | 235,532 | |
Other (less accumulated provisions of $9,000 and $5,593,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 5,416 | | | | 4,085 | |
Notes receivable from associated companies | | | 242,612 | | | | 752,919 | |
Materials and supplies, at average cost | | | 441,066 | | | | 460,239 | |
Prepayments and other | | | 83,825 | | | | 57,546 | |
| | | 1,202,826 | | | | 1,640,166 | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
In service | | | 8,183,578 | | | | 8,355,344 | |
Less - Accumulated provision for depreciation | | | 3,852,896 | | | | 3,818,268 | |
| | | 4,330,682 | | | | 4,537,076 | |
Construction work in progress | | | 596,879 | | | | 339,886 | |
| | | 4,927,561 | | | | 4,876,962 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 1,342,083 | | | | 1,238,272 | |
Long-term notes receivable from associated companies | | | 62,900 | | | | 62,900 | |
Other | | | 39,964 | | | | 72,509 | |
| | | 1,444,947 | | | | 1,373,681 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Accumulated deferred income taxes | | | 240,182 | | | | - | |
Goodwill | | | 24,248 | | | | 24,248 | |
Property taxes | | | 44,111 | | | | 44,111 | |
Pension assets | | | 9,449 | | | | - | |
Other | | | 70,638 | | | | 39,839 | |
| | | 388,628 | | | | 108,198 | |
| | $ | 7,963,962 | | | $ | 7,999,007 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 1,469,721 | | | $ | 1,469,660 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 237,070 | | | | 1,022,197 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 432,695 | | | | 556,049 | |
Other | | | 177,820 | | | | 136,631 | |
Accrued taxes | | | 537,060 | | | | 113,231 | |
Other | | | 163,239 | | | | 100,941 | |
| | | 3,017,605 | | | | 3,398,709 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 750 shares- | | | | | | | | |
7 and 8 shares outstanding, respectively | | | 1,163,934 | | | | 1,050,302 | |
Accumulated other comprehensive income | | | 166,673 | | | | 111,723 | |
Retained earnings | | | 1,038,412 | | | | 697,338 | |
Total common stockholder's equity | | | 2,369,019 | | | | 1,859,363 | |
Long-term debt | | | 505,196 | | | | 1,614,222 | |
| | | 2,874,215 | | | | 3,473,585 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Deferred gain on sale and leaseback transaction | | | 1,068,769 | | | | - | |
Accumulated deferred income taxes | | | - | | | | 121,449 | |
Accumulated deferred investment tax credits | | | 62,275 | | | | 65,751 | |
Asset retirement obligation | | | 797,357 | | | | 760,228 | |
Retirement benefits | | | 53,505 | | | | 103,027 | |
Property taxes | | | 44,433 | | | | 44,433 | |
Other | | | 45,803 | | | | 31,825 | |
| | | 2,072,142 | | | | 1,126,713 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 7,963,962 | | | $ | 7,999,007 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of these |
balance sheets. | | | | | | | | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Nine Months Ended | |
| | September 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 408,684 | | | $ | 311,956 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 145,030 | | | | 135,414 | |
Nuclear fuel and lease amortization | | | 75,102 | | | | 66,360 | |
Deferred income taxes and investment tax credits, net | | | (381,042 | ) | | | 47,188 | |
Investment impairment | | | 14,296 | | | | - | |
Accrued compensation and retirement benefits | | | 3,414 | | | | 13,704 | |
Commodity derivative transactions, net | | | 4,913 | | | | 46,500 | |
Gain on asset sales | | | (12,105 | ) | | | (35,973 | ) |
Cash collateral, net | | | (19,798 | ) | | | 20,643 | |
Pension trust contribution | | | (64,020 | ) | | | - | |
Decrease (increase) in operating assets: | | | | | | | | |
Receivables | | | (30,172 | ) | | | (46,063 | ) |
Materials and supplies | | | 48,123 | | | | (1,683 | ) |
Prepayments and other current assets | | | (5,118 | ) | | | 211 | |
Increase (decrease) in operating liabilities: | | | | | | | | |
Accounts payable | | | (108,949 | ) | | | (162,502 | ) |
Accrued taxes | | | 424,100 | | | | 77,524 | |
Accrued interest | | | 14,355 | | | | 2,431 | |
Other | | | (36,498 | ) | | | (17,605 | ) |
Net cash provided from operating activities | | | 480,315 | | | | 458,105 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | - | | | | 251,945 | |
Equity contributions from parent | | | 710,468 | | | | - | |
Short-term borrowings, net | | | - | | | | 66,817 | |
Redemptions and Repayments- | | | | | | | | |
Common stock | | | (600,000 | ) | | | - | |
Long-term debt | | | (1,110,174 | ) | | | (253,240 | ) |
Short-term borrowings, net | | | (785,127 | ) | | | - | |
Common stock dividend payments | | | (67,000 | ) | | | - | |
Net cash provided from (used for) financing activities | | | (1,851,833 | ) | | | 65,522 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (482,907 | ) | | | (427,298 | ) |
Proceeds from asset sales | | | 12,990 | | | | 20,437 | |
Proceeds from sale and leaseback transaction | | | 1,328,919 | | | | - | |
Sales of investment securities held in trusts | | | 521,535 | | | | 886,863 | |
Purchases of investment securities held in trusts | | | (521,535 | ) | | | (886,863 | ) |
Loan repayments from (loans to) associated companies, net | | | 510,307 | | | | (88,292 | ) |
Other | | | 2,209 | | | | (28,474 | ) |
Net cash provided from (used for) investing activities | | | 1,371,518 | | | | (523,627 | ) |
| | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | - | |
Cash and cash equivalents at beginning of period | | | 2 | | | | 2 | |
Cash and cash equivalents at end of period | | $ | 2 | | | $ | 2 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an |
integral part of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of FirstEnergy Solutions Corp.:
We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 as discussed in Note 3 to those consolidated financial statements) dated April 11, 2007,except as to Note 12, which is as of August 6, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007
FIRSTENERGY SOLUTIONS CORP.
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through its subsidiaries, FGCO and NGC, owns or leases and operates FirstEnergy’s fossil and hydroelectric generation facilities and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
FES’ revenues are primarily from the sale of electricity (provided from FES’ generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR requirements. These affiliated power sales include a full-requirements PSA with OE, CEI and TE to supply each of their PLR obligations through 2008, at prices that take into consideration their respective PUCO authorized billing rates. FES also has a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective PLR obligations at fixed prices through 2010. The fixed prices under the partial requirements agreement are expected to remain below wholesale market prices during the term of the agreement. FES also supplies the majority of the PLR requirements of Penn at market-based rates as a result of a competitive solicitation conducted by Penn. FES’ existing contractual obligations to Penn expire on May 31, 2008, but could continue if FES successfully bids in future competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, Maryland and Michigan.
Results of Operations
In the first nine months of 2007, net income increased to $409 million from $312 million in the first nine months of 2006. The increase in net income was primarily due to higher revenues and lower fuel and other operating expenses, partially offset by higher purchased power costs.
Revenues
Revenues increased by $198 million in the first nine months of 2007 compared to the same period in 2006 due to increases in revenues from non-affiliated retail generation sales and affiliated wholesale sales, partially offset by lower non-affiliated wholesale sales. Retail generation sales revenues increased as a result of higher unit prices and increased KWH sales. Higher unit prices primarily reflected higher generation rates in the MISO and PJM markets where FES is an alternative supplier. Increased KWH sales to FES’ commercial and industrial customers during the first nine months of 2007 were partially offset by a decrease in sales to residential customers returning to FES’ Ohio utility affiliates for their generation requirements. Affiliated wholesale revenues were higher as a result of increased sales and higher unit prices for sales to the Ohio Companies.
Non-affiliated wholesale revenues decreased as a result of lower generation available for the non-affiliated market due to increased affiliated company power sales requirements under the Ohio Companies’ full-requirements PSA and the partial-requirements power sales agreement with Met-Ed and Penelec.
The increase in sales to the Ohio Companies was due to their higher retail generation sales requirements. Higher unit prices resulted from the provision of the full-requirements PSA under which PSA rates reflect the increase in the Ohio Companies’ retail generation rates. The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements. These increases were partially offset by lower sales to Penn as a result of the implementation of its competitive solicitation process in 2007.
Transmission revenue decreased $25 million due to reduced retail load in the MISO market, lower transmission rates and reduced financial transmission rights auction revenue.
Changes in revenues in the first nine months of 2007 from the same period of 2006 are summarized below:
| | Nine Months Ended | | | |
| | Sept 30, | | Increase | |
Revenues by Type of Service | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
Non-Affiliated Generation Sales: | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
Total Non-Affiliated Generation Sales | | | | | | | | | | |
Affiliated Generation Sales | | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | ) |
| | | | | | | | | | |
The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated sales in the first nine months of 2007 compared to the same period last year:
| | Increase | |
Source of Change in Non-Affiliated Generation Revenues | | | |
| | (In millions) | |
Retail: | | | | |
Effect of 12% increase in sales volumes | | $ | 52 | |
Change in prices | | | | |
| | | | |
Wholesale: | | | | |
Effect of 26% decrease in sales volumes | | | (131 | ) |
Change in prices | | | | |
| | | | ) |
Net Increase in Non-Affiliated Generation Revenues | | | | |
Source of Change in Affiliated Generation Revenues | | | |
| | (In millions) | |
Ohio Companies: | | | | |
Effect of 4% increase in sales volumes | | $ | 56 | |
Change in prices | | | | |
| | | | |
Pennsylvania Companies: | | | | |
Effect of 12% increase in sales volumes | | | 54 | |
Change in prices | | | | |
| | | | |
Net Increase in Affiliated Generation Revenues | | | | |
Expenses
Total expenses increased by $57 million in the first nine months of 2007 compared with the same period of 2006. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2007 from the same period last year:
Source of Change in Fuel and Purchased Power | | | |
| | (In millions) | |
Nuclear Fuel: | | | | |
Change due to increased unit costs | | $ | 3 | |
Change due to volume consumed | | | 5 | |
| | | 8 | |
Fossil Fuel: | | | | |
Change due to decreased unit costs | | | (4 | ) |
Change due to volume consumed | | | (45 | ) |
| | | (49 | ) |
Purchased Power: | | | | |
Change due to increased unit costs | | | 51 | |
Change due to volume purchased | | | 71 | |
| | | 122 | |
Net Increase in Fuel and Purchased Power Costs | | | | |
Fossil fuel costs decreased $49 million in the first nine months of 2007 primarily as a result of reduced coal and emission allowance costs. Coal costs were lower due to a $14 million inventory adjustment as a result of an interim physical inventory and $23 million from reduced coal consumption reflecting lower generation as a result of planned maintenance outages at Sammis Units 6 and 7 and Eastlake Unit 5 and forced outage at Mansfield Unit 1.
The lower fossil fuel costs were partially offset by higher nuclear fuel costs of $8 million. Higher nuclear fuel costs were due to higher unit costs and increased nuclear generation in the first nine months of 2007 as compared to the same period of 2006.
Purchased power costs increased as a result of increased volumes purchased and higher unit prices. Volumes purchased in the first nine months of 2007 increased by 10.6% due to the outages at the Sammis, Eastlake, Mansfield and Perry plants. Other operating expenses decreased by $43 million in the first nine months of 2007 from the same period of 2006 primarily due to lower nuclear operating costs as a result of fewer outages in 2007 compared to 2006 and reduced employee benefit costs.
Depreciation expense increased by $10 million in the first nine months of 2007 primarily due to fossil and nuclear property additions subsequent to the third quarter of 2006.
General taxes increased by $9 million in the first nine months of 2007 compared to the same period of 2006 as a result of higher property taxes and gross receipts taxes.
Other Expense
Other expense decreased by $15 million in the first nine months of 2007 from the same periods of 2006 primarily as a result of lower interest expense. Lower interest expense reflected the repayment of GAT-related notes to associated companies, partially offset by the issuance of lower-cost pollution control debt subsequent to October 1, 2006.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to FES.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to FES.
OHIO EDISON COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended | |
| | September 30, | | | September 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | |
STATEMENTS OF INCOME | | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 638,336 | | | $ | 642,294 | | | $ | 1,802,110 | | | $ | 1,745,699 | |
Excise tax collections | | | 30,472 | | | | 31,379 | | | | 89,077 | | | | 87,269 | |
Total revenues | | | 668,808 | | | | 673,673 | | | | 1,891,187 | | | | 1,832,968 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Fuel | | | 2,821 | | | | 2,954 | | | | 8,148 | | | | 8,726 | |
Purchased power | | | 364,709 | | | | 395,560 | | | | 1,037,200 | | | | 971,613 | |
Nuclear operating costs | | | 41,783 | | | | 44,995 | | | | 130,951 | | | | 129,585 | |
Other operating costs | | | 100,265 | | | | 108,362 | | | | 285,871 | | | | 290,776 | |
Provision for depreciation | | | 19,482 | | | | 18,399 | | | | 57,440 | | | | 53,962 | |
Amortization of regulatory assets | | | 53,026 | | | | 49,717 | | | | 144,569 | | | | 147,022 | |
Deferral of new regulatory assets | | | (41,417 | ) | | | (44,962 | ) | | | (132,410 | ) | | | (123,285 | ) |
General taxes | | | 46,158 | | | | 47,826 | | | | 141,296 | | | | 137,652 | |
Total expenses | | | 586,827 | | | | 622,851 | | | | 1,673,065 | | | | 1,616,051 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 81,981 | | | | 50,822 | | | | 218,122 | | | | 216,917 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Investment income | | | 19,827 | | | | 32,993 | | | | 67,803 | | | | 98,853 | |
Miscellaneous income | | | 670 | | | | 1,639 | | | | 3,362 | | | | 835 | |
Interest expense | | | (20,311 | ) | | | (24,597 | ) | | | (62,749 | ) | | | (60,195 | ) |
Capitalized interest | | | 136 | | | | 698 | | | | 398 | | | | 1,832 | |
Subsidiary's preferred stock dividend requirements | | | - | | | | (156 | ) | | | - | | | | (467 | ) |
Total other income | | | 322 | | | | 10,577 | | | | 8,814 | | | | 40,858 | |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 82,303 | | | | 61,399 | | | | 226,936 | | | | 257,775 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 34,089 | | | | 17,902 | | | | 79,074 | | | | 91,239 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 48,214 | | | | 43,497 | | | | 147,862 | | | | 166,536 | |
| | | | | | | | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS AND | | | | | | | | | | | | | | | | |
REDEMPTION PREMIUM | | | - | | | | 51 | | | | - | | | | 4,297 | |
| | | | | | | | | | | | | | | | |
EARNINGS ON COMMON STOCK | | $ | 48,214 | | | $ | 43,446 | | | $ | 147,862 | | | $ | 162,239 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 48,214 | | | $ | 43,497 | | | $ | 147,862 | | | $ | 166,536 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirment benefits | | | (3,423 | ) | | | - | | | | (10,270 | ) | | | - | |
Change in unrealized gain on available for sale securities | | | 2,442 | | | | 3,795 | | | | 7,415 | | | | 5,467 | |
Other comprehensive income (loss) | | | (981 | ) | | | 3,795 | | | | (2,855 | ) | | | 5,467 | |
Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | (573 | ) | | | 1,369 | | | | (1,688 | ) | | | 1,972 | |
Other comprehensive income (loss), net of tax | | | (408 | ) | | | 2,426 | | | | (1,167 | ) | | | 3,495 | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 47,806 | | | $ | 45,923 | | | $ | 146,695 | | | $ | 170,031 | |
| | | | | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of these | |
statements. | | | | | | | | | | | | | | | | |
OHIO EDISON COMPANY | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | September 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 727 | | | $ | 712 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $8,518,000 and $15,033,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 271,680 | | | | 234,781 | |
Associated companies | | | 167,686 | | | | 141,084 | |
Other (less accumulated provisions of $5,548,000 and $1,985,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 20,093 | | | | 13,496 | |
Notes receivable from associated companies | | | 626,841 | | | | 458,647 | |
Prepayments and other | | | 17,148 | | | | 13,606 | |
| | | 1,104,175 | | | | 862,326 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,722,468 | | | | 2,632,207 | |
Less - Accumulated provision for depreciation | | | 1,053,942 | | | | 1,021,918 | |
| | | 1,668,526 | | | | 1,610,289 | |
Construction work in progress | | | 42,494 | | | | 42,016 | |
| | | 1,711,020 | | | | 1,652,305 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Long-term notes receivable from associated companies | | | 365,767 | | | | 1,219,325 | |
Investment in lease obligation bonds | | | 274,077 | | | | 291,393 | |
Nuclear plant decommissioning trusts | | | 128,168 | | | | 118,209 | |
Other | | | 36,756 | | | | 38,160 | |
| | | 804,768 | | | | 1,667,087 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Regulatory assets | | | 717,311 | | | | 741,564 | |
Pension assets | | | 106,682 | | | | 68,420 | |
Property taxes | | | 60,080 | | | | 60,080 | |
Unamortized sale and leaseback costs | | | 46,384 | | | | 50,136 | |
Other | | | 44,457 | | | | 18,696 | |
| | | 974,914 | | | | 938,896 | |
| | $ | 4,594,877 | | | $ | 5,120,614 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 442,264 | | | $ | 159,852 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | - | | | | 113,987 | |
Other | | | 52,609 | | | | 3,097 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 200,104 | | | | 115,252 | |
Other | | | 17,766 | | | | 13,068 | |
Accrued taxes | | | 141,516 | | | | 187,306 | |
Accrued interest | | | 17,435 | | | | 24,712 | |
Other | | | 101,543 | | | | 64,519 | |
| | | 973,237 | | | | 681,793 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 175,000,000 shares - | | | | | | | | |
60 and 80 shares outstanding, respectively | | | 1,220,173 | | | | 1,708,441 | |
Accumulated other comprehensive income | | | 2,041 | | | | 3,208 | |
Retained earnings | | | 257,870 | | | | 260,736 | |
Total common stockholder's equity | | | 1,480,084 | | | | 1,972,385 | |
Long-term debt and other long-term obligations | | | 836,430 | | | | 1,118,576 | |
| | | 2,316,514 | | | | 3,090,961 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 676,784 | | | | 674,288 | |
Accumulated deferred investment tax credits | | | 17,856 | | | | 20,532 | |
Asset retirement obligations | | | 92,157 | | | | 88,223 | |
Retirement benefits | | | 159,096 | | | | 167,379 | |
Deferred revenues - electric service programs | | | 59,255 | | | | 86,710 | |
Other | | | 299,978 | | | | 310,728 | |
| | | 1,305,126 | | | | 1,347,860 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 4,594,877 | | | $ | 5,120,614 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of | | | | | |
these balance sheets. | | | | | | | | |
OHIO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Nine Months Ended | |
| | September 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 147,862 | | | $ | 166,536 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 57,440 | | | | 53,962 | |
Amortization of regulatory assets | | | 144,569 | | | | 147,022 | |
Deferral of new regulatory assets | | | (132,410 | ) | | | (123,285 | ) |
Amortization of lease costs | | | 28,567 | | | | 28,600 | |
Deferred income taxes and investment tax credits, net | | | (29,155 | ) | | | (27,850 | ) |
Accrued compensation and retirement benefits | | | (34,572 | ) | | | 2,985 | |
Pension trust contribution | | | (20,261 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (70,098 | ) | | | 26,198 | |
Prepayments and other current assets | | | (3,542 | ) | | | (4,172 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | 89,550 | | | | (24,937 | ) |
Accrued taxes | | | (37,355 | ) | | | (27,826 | ) |
Accrued interest | | | (7,277 | ) | | | 12,839 | |
Electric service prepayment programs | | | (27,455 | ) | | | (24,975 | ) |
Other | | | 7,260 | | | | 2,570 | |
Net cash provided from operating activities | | | 113,123 | | | | 207,667 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | - | | | | 592,763 | |
Equity contributions from parent | | | 11,621 | | | | - | |
Redemptions and Repayments- | | | | | | | | |
Common stock | | | (500,000 | ) | | | (500,000 | ) |
Preferred stock | | | - | | | | (63,893 | ) |
Long-term debt | | | (1,190 | ) | | | (138,085 | ) |
Short-term borrowings, net | | | (64,475 | ) | | | (177,595 | ) |
Dividend Payments- | | | | | | | | |
Common stock | | | (150,000 | ) | | | (73,000 | ) |
Preferred stock | | | - | | | | (1,369 | ) |
Net cash used for financing activities | | | (704,044 | ) | | | (361,179 | ) |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (109,461 | ) | | | (94,278 | ) |
Sales of investment securities held in trusts | | | 31,624 | | | | 32,826 | |
Purchases of investment securities held in trusts | | | (33,586 | ) | | | (34,209 | ) |
Loan repayments from associated companies, net | | | 685,364 | | | | 148,199 | |
Cash investments | | | 17,316 | | | | 93,900 | |
Other | | | (321 | ) | | | 6,848 | |
Net cash provided from investing activities | | | 590,936 | | | | 153,286 | |
| | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 15 | | | | (226 | ) |
Cash and cash equivalents at beginning of period | | | 712 | | | | 929 | |
Cash and cash equivalents at end of period | | $ | 727 | | | $ | 703 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral | |
part of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Ohio Edison Company:
We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005 as discussed in Note 3, Note 2(G) and Note 11 to the consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007
OHIO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. OE also provides generation services to those customers electing to retain OE as their power supplier. OE’s power supply requirements are provided by FES – an affiliated company.
Results of Operations
In the first nine months of 2007, earnings on common stock decreased to $148 million from $162 million in the same period of 2006. The decrease in earnings primarily resulted from higher purchased power costs and lower other income, partially offset by higher electric sales revenues.
Revenues
Revenues increased by $58 million or 3.2% in the first nine months of 2007 compared with the same period in 2006, primarily due to a $65 million increase in retail generation revenues, partially offset by decreases in revenues from distribution throughput of $16 million.
Higher retail generation revenues from residential customers reflected increased sales volume and the impact of higher average unit prices. Weather conditions in the first nine months of 2007 compared to the same period in 2006 contributed to the higher KWH sales to residential customers (heating degree days increased 11.5% and 8.4% and cooling degree days increased by 26.9% and 25.2% in OE’s and Penn’s service territories, respectively). Commercial retail generation revenues increased primarily due to higher average unit prices, partially offset by reduced KWH sales. Average prices increased due to the higher generation prices that were effective in January 2007 under Penn’s competitive RFP process. Retail generation revenues from the industrial sector decreased primarily due to an increase in customer shopping in Penn’s service territory in the first nine months of 2007 as compared to the same period in 2006. The percentage of shopping customers increased to 27.7 percent in the first nine months of 2007 from 15.8 percent in the first nine months of 2006.
Changes in retail generation sales and revenues in the first nine months of 2007 from the corresponding period of 2006 are summarized in the following tables:
Retail Generation KWH Sales
| | Increase (Decrease)
| |
| | | | |
Residential | | | 7.4 | % |
Commercial | | | (1.4 | )% |
Industrial | | | (16.0 | )% |
Net Decrease in Generation Sales
| | | (3.7
| )%
|
Retail Generation Revenues | | Increase (Decrease) | |
| | (In millions) | |
Residential | | $ | 80 | |
Commercial | | | 23 | |
Industrial | | | (38 | ) |
Net Increase in Generation Revenues | | $ | 65 | |
A small increase in distribution revenues from residential customers was more than offset by decreases in distribution revenues from commercial and industrial customers. The increase from residential customers reflected higher deliveries due to the favorable weather conditions described above in the first nine months of 2007 as compared to the same period in 2006, partially offset by lower composite unit prices. Reduced distribution revenues from commercial customers in the first nine months of 2007 resulted from lower unit prices, partially offset by increased KWH deliveries. Distribution revenues from industrial customers decreased in the first nine months of 2007 as a result of lower unit prices and reduced KWH deliveries.
Changes in distribution KWH deliveries and revenues in the first nine months of 2007 from the corresponding period of 2006 are summarized in the following tables.
Distribution KWH Deliveries
| | Increase (Decrease)
| |
| | | | |
Residential | | | 5.8 | % |
Commercial | | | 3.3 | % |
Industrial | | | (2.2 | )% |
Net Increase in Distribution Deliveries
| | | 2.2
| %
|
Distribution Revenues | | Increase (Decrease) | |
| | (In millions) | |
Residential | | $ | 2 | |
Commercial | | | (5 | ) |
Industrial | | | (13 | ) |
Net Decrease in Distribution Revenues | | $ | (16 | ) |
Expenses
Total expenses increased by $57 million in the first nine months of 2007 from the same period of 2006. The following table presents changes from the prior year by expense category.
Expenses – Changes | | Increase (Decrease) | |
| | | (In millions) | |
Purchased power costs | | $ | 65 | |
Nuclear operating costs | | | 1 | |
Other operating costs | | | (5 | ) |
Provision for depreciation | | | 3 | |
Amortization of regulatory assets | | | (2 | ) |
Deferral of new regulatory assets | | | (9 | ) |
General taxes | | | 4 | |
Net Increase in Expenses | | $ | 57 | |
Higher purchased power costs in the first nine months of 2007 primarily reflected higher unit prices under Penn’s competitive RFP process and OE’s PSA with FES. The decrease in other operating costs for the first nine months of 2007 was primarily due to lower employee benefit expenses, partially offset by higher transmission expenses related to MISO operations. Higher depreciation expense in the first nine months of 2007 reflected capital additions subsequent to the third quarter of 2006. The increase in the deferral of new regulatory assets for the first nine months of 2007��was primarily due to increases in MISO cost deferrals and RCP distribution cost deferrals, partially offset by lower RCP fuel cost deferrals. General taxes were higher in the first nine months of 2007 as compared to the same period last year as a result of higher real and personal property taxes and KWH excise taxes.
Other Income
Other income decreased $32 million in the first nine months of 2007 as compared with the same period of 2006 primarily due to reductions in interest income on notes receivable resulting from principal payments from associated companies since the third quarter of 2006. Higher interest expense also contributed to the decrease in other income in the first nine months of 2007, with interest expense associated with OE’s issuance of $600 million of long-term debt in June 2006 being partially offset by debt redemptions since the third quarter of 2006.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to OE.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to OE.
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended | |
| | September 30, | | | September 30, | |
| | | | | | | | | | | | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 510,577 | | | $ | 497,336 | | | $ | 1,366,396 | | | $ | 1,304,525 | |
Excise tax collections | | | 18,514 | | | | 18,587 | | | | 53,009 | | | | 51,579 | |
Total revenues | | | 529,091 | | | | 515,923 | | | | 1,419,405 | | | | 1,356,104 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Fuel | | | 12,160 | | | | 12,748 | | | | 39,683 | | | | 39,724 | |
Purchased power | | | 216,194 | | | | 229,779 | | | | 575,520 | | | | 531,490 | |
Other operating costs | | | 85,114 | | | | 81,510 | | | | 243,140 | | | | 222,841 | |
Provision for depreciation | | | 18,913 | | | | 17,524 | | | | 56,094 | | | | 45,775 | |
Amortization of regulatory assets | | | 42,077 | | | | 38,826 | | | | 110,253 | | | | 99,832 | |
Deferral of new regulatory assets | | | (37,692 | ) | | | (39,060 | ) | | | (114,708 | ) | | | (101,283 | ) |
General taxes | | | 37,930 | | | | 34,228 | | | | 110,922 | | | | 100,808 | |
Total expenses | | | 374,696 | | | | 375,555 | | | | 1,020,904 | | | | 939,187 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 154,395 | | | | 140,368 | | | | 398,501 | | | | 416,917 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Investment income | | | 13,805 | | | | 24,715 | | | | 47,816 | | | | 76,325 | |
Miscellaneous income (expense) | | | (760 | ) | | | 813 | | | | 3,197 | | | | 6,209 | |
Interest expense | | | (34,423 | ) | | | (34,774 | ) | | | (107,430 | ) | | | (104,140 | ) |
Capitalized interest | | | 309 | | | | 836 | | | | 655 | | | | 2,346 | |
Total other expense | | | (21,069 | ) | | | (8,410 | ) | | | (55,762 | ) | | | (19,260 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 133,326 | | | | 131,958 | | | | 342,739 | | | | 397,657 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 54,610 | | | | 48,496 | | | | 131,525 | | | | 150,730 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 78,716 | | | | 83,462 | | | | 211,214 | | | | 246,927 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | 1,202 | | | | - | | | | 3,607 | | | | - | |
Income tax expense related to other comprehensive income | | | 356 | | | | - | | | | 1,068 | | | | - | |
Other comprehensive income, net of tax | | | 846 | | | | - | | | | 2,539 | | | | - | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 79,562 | | | $ | 83,462 | | | $ | 213,753 | | | $ | 246,927 | |
| | | | | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an integral | |
part of these statements. | | | | | | | | | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | September 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 234 | | | $ | 221 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $8,057,000 and $6,783,000 | | | | | |
respectively, for uncollectible accounts) | | | 304,608 | | | | 245,193 | |
Associated companies | | | 53,564 | | | | 249,735 | |
Other | | | 21,331 | | | | 14,240 | |
Notes receivable from associated companies | | | 41,054 | | | | 27,191 | |
Prepayments and other | | | 1,510 | | | | 2,314 | |
| | | 422,301 | | | | 538,894 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,199,913 | | | | 2,136,766 | |
Less - Accumulated provision for depreciation | | | 844,600 | | | | 819,633 | |
| | | 1,355,313 | | | | 1,317,133 | |
Construction work in progress | | | 55,382 | | | | 46,385 | |
| | | 1,410,695 | | | | 1,363,518 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Long-term notes receivable from associated companies | | | 265,660 | | | | 486,634 | |
Investment in lessor notes | | | 463,433 | | | | 519,611 | |
Other | | | 10,302 | | | | 13,426 | |
| | | 739,395 | | | | 1,019,671 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 1,688,521 | | | | 1,688,521 | |
Regulatory assets | | | 855,618 | | | | 854,588 | |
Pension assets | | | 16,791 | | | | - | |
Property taxes | | | 65,000 | | | | 65,000 | |
Other | | | 42,993 | | | | 33,306 | |
| | | 2,668,923 | | | | 2,641,415 | |
| | $ | 5,241,314 | | | $ | 5,563,498 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 266,271 | | | $ | 120,569 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 73,459 | | | | 218,134 | |
Other | | | 100,000 | | | | - | |
Accounts payable- | | | | | | | | |
Associated companies | | | 237,072 | | | | 365,678 | |
Other | | | 6,194 | | | | 7,194 | |
Accrued taxes | | | 132,941 | | | | 128,829 | |
Accrued interest | | | 41,393 | | | | 19,033 | |
Lease market valuation liability | | | 58,750 | | | | 60,200 | |
Other | | | 44,931 | | | | 52,101 | |
| | | 961,011 | | | | 971,738 | |
| | | | | | | | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | |
67,930,743 shares outstanding | | | 873,037 | | | | 860,133 | |
Accumulated other comprehensive loss | | | (101,892 | ) | | | (104,431 | ) |
Retained earnings | | | 620,155 | | | | 713,201 | |
Total common stockholder's equity | | | 1,391,300 | | | | 1,468,903 | |
Long-term debt and other long-term obligations | | | 1,670,898 | | | | 1,805,871 | |
| | | 3,062,198 | | | | 3,274,774 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 461,410 | | | | 470,707 | |
Accumulated deferred investment tax credits | | | 18,994 | | | | 20,277 | |
Lease market valuation liability | | | 491,085 | | | | 547,800 | |
Retirement benefits | | | 110,620 | | | | 122,862 | |
Deferred revenues - electric service programs | | | 34,768 | | | | 51,588 | |
Other | | | 101,228 | | | | 103,752 | |
| | | 1,218,105 | | | | 1,316,986 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 5,241,314 | | | $ | 5,563,498 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company |
are an integral part of these balance sheets. | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Nine Months Ended | |
| | September 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 211,214 | | | $ | 246,927 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 56,094 | | | | 45,775 | |
Amortization of regulatory assets | | | 110,253 | | | | 99,832 | |
Deferral of new regulatory assets | | | (114,708 | ) | | | (101,283 | ) |
Deferred rents and lease market valuation liability | | | (46,327 | ) | | | (55,166 | ) |
Deferred income taxes and investment tax credits, net | | | (40,964 | ) | | | (9,513 | ) |
Accrued compensation and retirement benefits | | | 2,575 | | | | 2,681 | |
Pension trust contribution | | | (24,800 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | 140,359 | | | | 189 | |
Prepayments and other current assets | | | 661 | | | | (387 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (143,210 | ) | | | 29,681 | |
Accrued taxes | | | 4,545 | | | | (14,588 | ) |
Accrued interest | | | 22,360 | | | | 12,427 | |
Electric service prepayment programs | | | (16,819 | ) | | | (13,623 | ) |
Other | | | 2,996 | | | | (5,270 | ) |
Net cash provided from operating activities | | | 164,229 | | | | 237,682 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | 247,424 | | | | - | |
Equity contributions from parent | | | 12,756 | | | | - | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (223,555 | ) | | | (118,295 | ) |
Short-term borrowings, net | | | (59,328 | ) | | | (58,819 | ) |
Dividend Payments- | | | | | | | | |
Common stock | | | (304,000 | ) | | | (118,000 | ) |
Net cash used for financing activities | | | (326,703 | ) | | | (295,114 | ) |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (100,583 | ) | | | (89,771 | ) |
Loan repayments from (loans to) associated companies, net | | | (13,863 | ) | | | 108,034 | |
Collection of principal on long-term notes receivable | | | 220,974 | | | | - | |
Redemption of lessor notes | | | 56,177 | | | | 44,553 | |
Other | | | (218 | ) | | | (5,368 | ) |
Net cash provided from investing activities | | | 162,487 | | | | 57,448 | |
| | | | | | | | |
Net increase in cash and cash equivalents | | | 13 | | | | 16 | |
Cash and cash equivalents at beginning of period | | | 221 | | | | 207 | |
Cash and cash equivalents at end of period | | $ | 234 | | | $ | 223 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company |
are an integral part of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of The Cleveland Electric Illuminating Company:
We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 11 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. CEI’s power supply requirements are primarily provided by FES – an affiliated company.
Results of Operations
Net income in the first nine months of 2007 decreased to $211 million from $247 million in the same period of 2006. The decrease resulted primarily from higher purchased power costs and other operating costs, partially offset by higher revenues.
Revenues
Revenues increased by $63 million or 5% in the first nine months of 2007 compared to the same period of 2006 primarily due to higher retail generation and wholesale revenues. Retail generation revenues increased by $38 million due to increased KWH sales and higher composite unit prices for all customer classes. More weather-related usage in the first nine months of 2007 compared to the same period of 2006 primarily contributed to the increased KWH sales in the residential and commercial sectors (cooling degree days increased 19% and heating degree days increased 15% from the same period in 2006). Increased KWH sales in the industrial sector reflected a slight decrease in customer shopping.
Wholesale generation revenues increased by $17 million in the first nine months of 2007 compared to the corresponding period of 2006. The increase was primarily due to higher unit prices for PSA sales. CEI sells power from its leasehold interests in the Bruce Mansfield plant to FGCO.
Increases in retail generation sales and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables:
Retail Generation KWH Sales
| | Increase
| |
| | | | |
Residential | | | 4.3 | % |
Commercial | | | 6.0 | % |
Industrial | | | 1.2 | % |
Increase in Retail Generation Sales
| | | 3.2
| %
|
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 9 | |
Commercial | | | 15 | |
Industrial | | | 14 | |
Increase in Generation Revenues | | $ | 38 | |
Revenues from distribution throughput increased by $5 million in the first nine months of 2007 compared to the same period of 2006 primarily due to increased KWH deliveries to all customer classes, partially offset by lower composite unit prices for the industrial sector. Increased KWH deliveries were primarily a result of the weather in 2007 as described above.
Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables.
Distribution KWH Deliveries
| | Increase
| |
| | | | |
Residential | | | 4.5 | % |
Commercial | | | 3.7 | % |
Industrial | | | 0.7 | % |
Increase in Distribution Deliveries
| | | 2.5
| %
|
Distribution Revenues | | Increase (Decrease) | |
| | (In millions) | |
Residential | | $ | 6 | |
Commercial | | | 6 | |
Industrial | | | (7 | ) |
Net Increase in Distribution Revenues | | $ | 5 | |
Expenses
Total expenses increased by $82 million in the first nine months of 2007 compared to the same period of 2006. The following table presents the change from the prior year by expense category:
Expenses - Changes | | Increase (Decrease) | |
| | (in millions) | |
Purchased power costs | | $ | 44 | |
Other operating costs | | | 20 | |
Provision for depreciation | | | 10 | |
Amortization of regulatory assets | | | 11 | |
Deferral of new regulatory assets | | | (13 | ) |
General taxes | | | 10 | |
Net Increase in Expenses | | $ | 82 | |
Higher purchased power costs in the first nine months of 2007 compared to the corresponding period of 2006 primarily reflect higher unit prices associated with the PSA with FES and an increase in purchased power to meet CEI’s higher retail generation sales requirements. Higher other operating costs in the first nine months of 2007 compared to the same period of 2006 reflect increases in MISO transmission related expenses due to increased transmission volumes. The increased depreciation in the first nine months of 2007 is primarily due to property additions since the third quarter of 2006 and the absence of a credit adjustment in the second quarter of 2006 that related to prior periods ($6.5 million pre-tax, $4 million net of tax).
The increased amortization of regulatory assets in the first nine months of 2007 compared to the corresponding period of 2006 was due to increased transition cost amortization reflecting the higher KWH sales discussed above. The increase in the deferral of new regulatory assets in the first nine months of 2007 reflect a higher level of MISO costs that were deferred in excess of transmission revenues recognized and increased distribution cost deferrals under CEI’s RCP. General taxes were higher in the first nine months of 2007 compared to the same period of 2006 primarily as a result of higher real and personal property taxes.
Other Expense
Other expense increased by $37 million in the first nine months of 2007 compared to the corresponding period of 2006 primarily due to lower investment income on associated company notes receivable in 2007. CEI received principal repayments from FGCO and NGC subsequent to the third quarter of 2006 on notes receivable related to the generation asset transfers.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to CEI.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to CEI.
THE TOLEDO EDISON COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended | |
| | September 30, | | | September 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
STATEMENTS OF INCOME | | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 261,736 | | | $ | 254,979 | | | $ | 728,429 | | | $ | 684,992 | |
Excise tax collections | | | 7,926 | | | | 7,858 | | | | 22,026 | | | | 21,420 | |
Total revenues | | | 269,662 | | | | 262,837 | | | | 750,455 | | | | 706,412 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Fuel | | | 8,784 | | | | 9,399 | | | | 29,392 | | | | 28,799 | |
Purchased power | | | 112,502 | | | | 112,389 | | | | 304,947 | | | | 268,468 | |
Nuclear operating costs | | | 17,705 | | | | 19,252 | | | | 53,272 | | | | 54,450 | |
Other operating costs | | | 47,212 | | | | 44,253 | | | | 136,297 | | | | 124,396 | |
Provision for depreciation | | | 9,231 | | | | 8,386 | | | | 27,475 | | | | 24,723 | |
Amortization of regulatory assets | | | 30,460 | | | | 27,336 | | | | 79,284 | | | | 73,909 | |
Deferral of new regulatory assets | | | (15,645 | ) | | | (15,340 | ) | | | (47,373 | ) | | | (43,186 | ) |
General taxes | | | 11,912 | | | | 13,406 | | | | 38,646 | | | | 38,590 | |
Total expenses | | | 222,161 | | | | 219,081 | | | | 621,940 | | | | 570,149 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 47,501 | | | | 43,756 | | | | 128,515 | | | | 136,263 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Investment income | | | 6,721 | | | | 9,724 | | | | 21,255 | | | | 28,449 | |
Miscellaneous expense | | | (2,153 | ) | | | (1,933 | ) | | | (7,309 | ) | | | (6,543 | ) |
Interest expense | | | (8,786 | ) | | | (4,940 | ) | | | (25,205 | ) | | | (13,614 | ) |
Capitalized interest | | | 220 | | | | 277 | | | | 467 | | | | 835 | |
Total other income (expense) | | | (3,998 | ) | | | 3,128 | | | | (10,792 | ) | | | 9,127 | |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 43,503 | | | | 46,884 | | | | 117,723 | | | | 145,390 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 18,435 | | | | 17,706 | | | | 44,924 | | | | 54,834 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 25,068 | | | | 29,178 | | | | 72,799 | | | | 90,556 | |
| | | | | | | | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS | | | - | | | | 1,161 | | | | - | | | | 3,597 | |
| | | | | | | | | | | | | | | | |
EARNINGS ON COMMON STOCK | | $ | 25,068 | | | $ | 28,017 | | | $ | 72,799 | | | $ | 86,959 | |
| | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 25,068 | | | $ | 29,178 | | | $ | 72,799 | | | $ | 90,556 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | 574 | | | | - | | | | 1,720 | | | | - | |
Change in unrealized gain on available for sale securities | | | 1,946 | | | | 1,379 | | | | 1,656 | | | | 432 | |
Other comprehensive income | | | 2,520 | | | | 1,379 | | | | 3,376 | | | | 432 | |
Income tax expense related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | 902 | | | | 498 | | | | 1,193 | | | | 156 | |
Other comprehensive income, net of tax | | | 1,618 | | | | 881 | | | | 2,183 | | | | 276 | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 26,686 | | | $ | 30,059 | | | $ | 74,982 | | | $ | 90,832 | |
| | | | | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of | |
these statements. | | | | | | | | | | | | | | | | |
THE TOLEDO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | September 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 20 | | | $ | 22 | |
Receivables- | | | | | | | | |
Customers | | | 335 | | | | 772 | |
Associated companies | | | 31,180 | | | | 13,940 | |
Other (less accumulated provisions of $518,000 and $430,000, | | | | | |
respectively, for uncollectible accounts) | | | 3,600 | | | | 3,831 | |
Notes receivable from associated companies | | | 79,188 | | | | 100,545 | |
Prepayments and other | | | 627 | | | | 851 | |
| | | 114,950 | | | | 119,961 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 913,191 | | | | 894,888 | |
Less - Accumulated provision for depreciation | | | 406,949 | | | | 394,225 | |
| | | 506,242 | | | | 500,663 | |
Construction work in progress | | | 26,665 | | | | 16,479 | |
| | | 532,907 | | | | 517,142 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Investment in lessor notes | | | 154,674 | | | | 169,493 | |
Long-term notes receivable from associated companies | | | 92,700 | | | | 128,858 | |
Nuclear plant decommissioning trusts | | | 64,598 | | | | 61,094 | |
Other | | | 1,778 | | | | 1,871 | |
| | | 313,750 | | | | 361,316 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 500,576 | | | | 500,576 | |
Regulatory assets | | | 214,896 | | | | 247,595 | |
Pension assets | | | 5,962 | | | | - | |
Property taxes | | | 22,010 | | | | 22,010 | |
Other | | | 29,427 | | | | 30,042 | |
| | | 772,871 | | | | 800,223 | |
| | $ | 1,734,478 | | | $ | 1,798,642 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 55,134 | | | $ | 30,000 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 103,250 | | | | 84,884 | |
Other | | | 4,043 | | | | 4,021 | |
Notes payable to associated companies | | | 190,758 | | | | 153,567 | |
Accrued taxes | | | 52,865 | | | | 47,318 | |
Lease market valuation liability | | | 23,655 | | | | 24,600 | |
Other | | | 32,906 | | | | 37,551 | |
| | | 462,611 | | | | 381,941 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $5 par value, authorized 60,000,000 shares - | | | | | |
29,402,054 shares outstanding | | | 147,010 | | | | 147,010 | |
Other paid-in capital | | | 172,949 | | | | 166,786 | |
Accumulated other comprehensive loss | | | (34,621 | ) | | | (36,804 | ) |
Retained earnings | | | 157,139 | | | | 204,423 | |
Total common stockholder's equity | | | 442,477 | | | | 481,415 | |
Long-term debt | | | 303,220 | | | | 358,281 | |
| | | 745,697 | | | | 839,696 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 141,813 | | | | 161,024 | |
Accumulated deferred investment tax credits | | | 10,389 | | | | 11,014 | |
Lease market valuation liability | | | 192,774 | | | | 218,800 | |
Retirement benefits | | | 77,275 | | | | 77,843 | |
Asset retirement obligations | | | 27,899 | | | | 26,543 | |
Deferred revenues - electric service programs | | | 15,896 | | | | 23,546 | |
Other | | | 60,124 | | | | 58,235 | |
| | | 526,170 | | | | 577,005 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 1,734,478 | | | $ | 1,798,642 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are | |
an integral part of these balance sheets. | | | | | | | | |
THE TOLEDO EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Nine Months Ended | |
| | September 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 72,799 | | | $ | 90,556 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 27,475 | | | | 24,723 | |
Amortization of regulatory assets | | | 79,284 | | | | 73,909 | |
Deferral of new regulatory assets | | | (47,373 | ) | | | (43,186 | ) |
Deferred rents and lease market valuation liability | | | (23,551 | ) | | | (27,114 | ) |
Deferred income taxes and investment tax credits, net | | | (32,530 | ) | | | (28,603 | ) |
Accrued compensation and retirement benefits | | | 3,493 | | | | 2,766 | |
Pension trust contribution | | | (7,659 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (13,368 | ) | | | (25,069 | ) |
Prepayments and other current assets | | | 224 | | | | (75 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | 9,515 | | | | 1,102 | |
Accrued taxes | | | 7,463 | | | | 3,458 | |
Accrued interest | | | 3,444 | | | | (709 | ) |
Electric service prepayment programs | | | (7,650 | ) | | | (6,744 | ) |
Other | | | 1,953 | | | | 1,716 | |
Net cash provided from operating activities | | | 73,519 | | | | 66,730 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | 37,191 | | | | 113,886 | |
Equity contribution from parent | | | 6,125 | | | | - | |
Redemptions and Repayments- | | | | | | | | |
Preferred stock | | | - | | | | (30,000 | ) |
Long-term debt | | | (30,014 | ) | | | (53,650 | ) |
Dividend Payments- | | | | | | | | |
Common stock | | | (120,000 | ) | | | (50,000 | ) |
Preferred stock | | | - | | | | (3,597 | ) |
Net cash used for financing activities | | | (106,698 | ) | | | (23,361 | ) |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (41,573 | ) | | | (45,661 | ) |
Loan repayments from (loans to) associated companies, net | | | 21,438 | | | | (61,549 | ) |
Collection of principal on long-term notes receivable | | | 36,077 | | | | 53,766 | |
Redemption of lessor notes | | | 14,819 | | | | 9,275 | |
Sales of investment securities held in trusts | | | 39,260 | | | | 50,255 | |
Purchases of investment securities held in trusts | | | (39,557 | ) | | | (50,433 | ) |
Other | | | 2,713 | | | | 983 | |
Net cash provided from (used for) investing activities | | | 33,177 | | | | (43,364 | ) |
| | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | (2 | ) | | | 5 | |
Cash and cash equivalents at beginning of period | | | 22 | | | | 15 | |
Cash and cash equivalents at end of period | | $ | 20 | | | $ | 20 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an | |
integral part of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of The Toledo Edison Company:
We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006 as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007
THE TOLEDO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. TE’s power supply requirements are provided by FES – an affiliated company.
Results of Operations
Earnings on common stock in the first nine months of 2007 decreased to $73 million from $87 million in the same period of 2006. The decrease resulted primarily from higher purchased power and other operating costs and increased interest expense, partially offset by higher electric sales revenues.
Revenues
Revenues increased $44 million or 6.2% in the first nine months of 2007 compared to the same period of 2006 primarily due to increases in retail generation revenues ($24 million), wholesale generation revenues ($11 million) and distribution revenues ($6 million). Retail generation revenues increased in the first nine months of 2007 due to higher average prices and increased sales volume across all customer classes compared to the same period of 2006. Average prices increased primarily due to higher composite unit prices for retail generation shopping customers returning to TE. The increase in sales volume also reflects increased weather-related usage in the first nine months of 2007 (heating and cooling degree days increased 15.2% and 7.2%, respectively, from the same period of 2006).
The increase in wholesale revenues resulted primarily from increased KWH sales to associated companies and higher unit prices. TE sells KWH from its leasehold interests in Beaver Valley Unit 2 and the Bruce Mansfield Plant to CEI and FGCO, respectively.
Increases in retail electric generation KWH sales and revenues in the first nine months of 2007 from the same period of 2006 are summarized in the following tables.
Retail Generation KWH Sales
| | Increase
| |
| | | | |
Residential | | | 8.0 | % |
Commercial | | | 3.1 | % |
Industrial | | | 1.0 | % |
Increase in Retail Generation Sales
| | | 3.1
| %
|
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 8 | |
Commercial | | | 4 | |
Industrial | | | 12 | |
Increase in Retail Generation Revenues | | $ | 24 | |
Revenues from distribution throughput increased by $6 million in the first nine months of 2007 compared to the same period in 2006 due to higher KWH deliveries to all customer sectors, partially offset by lower average unit prices for industrial customers. The higher KWH deliveries to residential and commercial customers in the first nine months of 2007 reflected the weather impacts described above.
Changes in distribution KWH deliveries and revenues in the first nine months of 2007 from the same period of 2006 are summarized in the following tables.
Distribution KWH Deliveries
| | Increase
| |
| | | | |
Residential | | | 5.5 | % |
Commercial | | | 2.6 | % |
Industrial | | | 1.1 | % |
Increase in Distribution Deliveries
| | | 2.5
| %
|
Distribution Revenues | | Increase (Decrease) | |
| | (In millions) | |
Residential | | $ | 7 | |
Commercial | | | 3 | |
Industrial | | | (4 | ) |
Net Increase in Distribution Revenues | | $ | 6 | |
Expenses
Total expenses increased $52 million in the first nine months of 2007 from the same period of 2006. The following table presents changes from the prior year by expense category:
Expenses – Changes | | Increase (Decrease) | |
| | (In millions) | |
| | $ | | |
| | | | ) |
| | | | |
Provision for depreciation | | | | |
Amortization of regulatory assets | | | | |
Deferral of new regulatory assets | | | | |
| | | | |
Higher purchased power costs in the first nine months of 2007 compared to the same period of 2006 reflected higher unit prices associated with the PSA with FES and an increase in KWH purchases to meet the higher retail generation sales requirements. Other operating costs were higher due to an $11 million increase in MISO network transmission expenses in the first nine months of 2007. Depreciation expense was higher due to an increase in depreciable property, reflecting plant additions since the third quarter of 2006. Higher amortization of regulatory assets was due to increased amortization of transition cost deferrals ($3 million) and MISO transmission deferrals ($2 million). The change in the deferral of new regulatory assets was primarily due to increased deferrals for MISO transmission expenses ($7 million) and RCP distribution costs ($4 million), partially offset by lower RCP fuel cost deferrals ($5 million).
Other Expense
Other expense increased $20 million in the first nine months of 2007 compared to the same period of 2006 primarily due to lower investment income and higher interest expense. The decrease in investment income resulted primarily from the principal repayments since the third quarter of 2006 on notes receivable from associated companies. The higher interest expense is principally associated with new long-term debt issued in November 2006.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to TE.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to TE.
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended | |
| | September 30, | | | September 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
STATEMENTS OF INCOME | | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 1,018,049 | | | $ | 895,389 | | | $ | 2,457,146 | | | $ | 2,059,499 | |
Excise tax collections | | | 15,168 | | | | 15,679 | | | | 39,849 | | | | 38,845 | |
Total revenues | | | 1,033,217 | | | | 911,068 | | | | 2,496,995 | | | | 2,098,344 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Purchased power | | | 654,418 | | | | 546,125 | | | | 1,505,420 | | | | 1,204,880 | |
Other operating costs | | | 87,010 | | | | 90,578 | | | | 236,225 | | | | 245,711 | |
Provision for depreciation | | | 22,032 | | | | 21,099 | | | | 63,867 | | | | 62,553 | |
Amortization of regulatory assets | | | 107,837 | | | | 78,052 | | | | 296,955 | | | | 210,323 | |
General taxes | | | 18,631 | | | | 19,187 | | | | 51,183 | | | | 49,691 | |
Total expenses | | | 889,928 | | | | 755,041 | | | | 2,153,650 | | | | 1,773,158 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 143,289 | | | | 156,027 | | | | 343,345 | | | | 325,186 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Miscellaneous income | | | 2,967 | | | | 2,091 | | | | 9,266 | | | | 8,162 | |
Interest expense | | | (24,666 | ) | | | (21,437 | ) | | | (71,576 | ) | | | (62,420 | ) |
Capitalized interest | | | 483 | | | | 1,004 | | | | 1,559 | | | | 2,933 | |
Total other expense | | | (21,216 | ) | | | (18,342 | ) | | | (60,751 | ) | | | (51,325 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 122,073 | | | | 137,685 | | | | 282,594 | | | | 273,861 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 46,275 | | | | 58,316 | | | | 118,637 | | | | 120,506 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 75,798 | | | | 79,369 | | | | 163,957 | | | | 153,355 | |
| | | | | | | | | | | | | | | | |
PREFERRED STOCK DIVIDEND REQUIREMENTS | | | - | | | | 917 | | | | - | | | | 1,167 | |
| | | | | | | | | | | | | | | | |
EARNINGS ON COMMON STOCK | | $ | 75,798 | | | $ | 78,452 | | | $ | 163,957 | | | $ | 152,188 | |
| | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 75,798 | | | $ | 79,369 | | | $ | 163,957 | | | $ | 153,355 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | (2,114 | ) | | | - | | | | (6,344 | ) | | | - | |
Unrealized gain on derivative hedges | | | 69 | | | | 100 | | | | 235 | | | | 207 | |
Other comprehensive income (loss) | | | (2,045 | ) | | | 100 | | | | (6,109 | ) | | | 207 | |
Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | (994 | ) | | | 41 | | | | (2,973 | ) | | | 84 | |
Other comprehensive income (loss), net of tax | | | (1,051 | ) | | | 59 | | | | (3,136 | ) | | | 123 | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 74,747 | | | $ | 79,428 | | | $ | 160,821 | | | $ | 153,478 | |
| | | | | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral | |
part of these statements. | | | | | | | | | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | September 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 77 | | | $ | 41 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $4,821,000 and $3,524,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 396,700 | | | | 254,046 | |
Associated companies | | | 369 | | | | 11,574 | |
Other (less accumulated provisions of $718,000 and $204,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 62,235 | | | | 40,023 | |
Notes receivable - associated companies | | | 22,734 | | | | 24,456 | |
Materials and supplies, at average cost | | | 1,915 | | | | 2,043 | |
Prepaid taxes | | | 41,670 | | | | 13,333 | |
Other | | | 14,080 | | | | 18,076 | |
| | | 539,780 | | | | 363,592 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 4,122,325 | | | | 4,029,070 | |
Less - Accumulated provision for depreciation | | | 1,490,846 | | | | 1,473,159 | |
| | | 2,631,479 | | | | 2,555,911 | |
Construction work in progress | | | 84,199 | | | | 78,728 | |
| | | 2,715,678 | | | | 2,634,639 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear fuel disposal trust | | | 172,278 | | | | 171,045 | |
Nuclear plant decommissioning trusts | | | 177,217 | | | | 164,108 | |
Other | | | 2,075 | | | | 2,047 | |
| | | 351,570 | | | | 337,200 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Regulatory assets | | | 1,757,516 | | | | 2,152,332 | |
Goodwill | | | 1,826,190 | | | | 1,962,361 | |
Pension assets | | | 43,183 | | | | 14,660 | |
Other | | | 15,124 | | | | 17,781 | |
| | | 3,642,013 | | | | 4,147,134 | |
| | $ | 7,249,041 | | | $ | 7,482,565 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | 26,680 | | | $ | 32,683 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 155,395 | | | | 186,540 | |
Accounts payable- | | | | | | | | |
Associated companies | | | 22,399 | | | | 80,426 | |
Other | | | 211,788 | | | | 160,359 | |
Accrued taxes | | | 25,793 | | | | 1,451 | |
Accrued interest | | | 27,520 | | | | 14,458 | |
Cash collateral from suppliers | | | 68 | | | | 32,311 | |
Other | | | 85,746 | | | | 96,139 | |
| | | 555,389 | | | | 604,367 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $10 par value, authorized 16,000,000 shares- | | | | | | | | |
14,421,637 and 15,009,335 shares outstanding, respectively | | | 144,216 | | | | 150,093 | |
Other paid-in capital | | | 2,657,775 | | | | 2,908,279 | |
Accumulated other comprehensive loss | | | (47,390 | ) | | | (44,254 | ) |
Retained earnings | | | 266,342 | | | | 145,480 | |
Total common stockholder's equity | | | 3,020,943 | | | | 3,159,598 | |
Long-term debt and other long-term obligations | | | 1,568,296 | | | | 1,320,341 | |
| | | 4,589,239 | | | | 4,479,939 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Power purchase contract loss liability | | | 872,305 | | | | 1,182,108 | |
Accumulated deferred income taxes | | | 762,782 | | | | 803,944 | |
Nuclear fuel disposal costs | | | 190,524 | | | | 183,533 | |
Asset retirement obligations | | | 88,334 | | | | 84,446 | |
Other | | | 190,468 | | | | 144,228 | |
| | | 2,104,413 | | | | 2,398,259 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 7,249,041 | | | $ | 7,482,565 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an | | | | | |
integral part of these balance sheets. | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Nine Months Ended | |
| | September 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 163,957 | | | $ | 153,355 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
Provision for depreciation | | | 63,867 | | | | 62,553 | |
Amortization of regulatory assets | | | 296,955 | | | | 210,323 | |
Deferred purchased power and other costs | | | (157,201 | ) | | | (213,621 | ) |
Deferred income taxes and investment tax credits, net | | | (23,786 | ) | | | 25,217 | |
Accrued compensation and retirement benefits | | | (17,543 | ) | | | (4,196 | ) |
Cash collateral returned to suppliers | | | (32,243 | ) | | | (108,926 | ) |
Pension trust contribution | | | (17,800 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (153,660 | ) | | | (50,337 | ) |
Materials and supplies | | | 127 | | | | 86 | |
Prepaid taxes | | | (28,337 | ) | | | (29,923 | ) |
Other current assets | | | 2,079 | | | | (2,118 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (6,598 | ) | | | (8,131 | ) |
Accrued taxes | | | 29,318 | | | | (16,992 | ) |
Accrued interest | | | 13,062 | | | | 16,296 | |
Tax collections payable | | | (12,478 | ) | | | (10,316 | ) |
Other | | | (7,440 | ) | | | (4,814 | ) |
Net cash provided from operating activities | | | 112,279 | | | | 18,456 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Long-term debt | | | 549,999 | | | | 382,400 | |
Equity contribution from parent | | | 4,636 | | | | - | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (324,256 | ) | | | (162,157 | ) |
Short-term borrowings, net | | | (31,145 | ) | | | (44,162 | ) |
Common stock | | | (125,000 | ) | | | - | |
Preferred stock | | | - | | | | (13,461 | ) |
Dividend Payments- | | | | | | | | |
Common stock | | | (43,000 | ) | | | (45,000 | ) |
Preferred stock | | | - | | | | (354 | ) |
Net cash provided from financing activities | | | 31,234 | | | | 117,266 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (144,668 | ) | | | (123,540 | ) |
Loan repayments from (loans to) associated companies, net | | | 1,722 | | | | (8,638 | ) |
Sales of investment securities held in trusts | | | 169,649 | | | | 169,676 | |
Purchases of investment securities held in trusts | | | (171,820 | ) | | | (171,847 | ) |
Other | | | 1,640 | | | | (1,417 | ) |
Net cash used for investing activities | | | (143,477 | ) | | | (135,766 | ) |
| | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | 36 | | | | (44 | ) |
Cash and cash equivalents at beginning of period | | | 41 | | | | 102 | |
Cash and cash equivalents at end of period | | $ | 77 | | | $ | 58 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company | |
are an integral part of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Jersey Central Power & Light Company:
We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, as discussed in Note 3 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also provides generation services to those customers electing to retain JCP&L as their power supplier.
Results of Operations
Earnings on common stock increased to $164 million in the first nine months of 2007 compared to $152 million for the same period in 2006. The increase was primarily due to higher revenues and lower other operating costs, partially offset by higher purchased power costs and increased amortization of regulatory assets.
Revenues
Revenues increased $399 million or 19% in the first nine months of 2007 compared with the same period of 2006. Retail and wholesale generation revenues increased by $250 million and $49 million, respectively, in the first nine months of 2007.
Retail generation revenues from all customer classes increased in the first nine months of 2007 compared to 2006 due to higher unit prices resulting from the BGS auctions effective June 1, 2006 and June 1, 2007 and higher retail generation KWH sales. Sales volume increased as a result of weather conditions in the first nine months of 2007 (heating degree days were 15.8% higher than the first nine months of 2006 and cooling degree days decreased slightly). Industrial generation KWH sales declined in the first nine months of 2007 from the same period in 2006 due to an increase in customer shopping.
Wholesale generation revenues increased $49 million in the first nine months of 2007 due to higher market prices, partially offset by a 3.0% decrease in sales volume compared with the first nine months of 2006.
Changes in retail generation KWH sales and revenues by customer class in the first nine months of 2007 compared to the same period of 2006 are summarized in the following table:
Retail Generation KWH Sales
| | Increase
(Decrease)
| |
| | | | |
Residential | | | 2.3 | % |
Commercial | | | 1.6 | % |
Industrial | | | (7.0 | )% |
Net Increase in Generation Sales
| | | 1.6
| %
|
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 145 | |
Commercial | | | 100 | |
Industrial | | | 5 | |
Increase in Generation Revenues | | $ | 250 | |
Distribution revenues increased in the first nine months of 2007 compared to the same period of 2006 due to higher composite unit prices and increased KWH deliveries, reflecting the weather impacts described above. The higher unit prices resulted from an NUGC rate increase effective in December 2006.
Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables.
Distribution KWH Deliveries
| | Increase
| |
| | | | | |
Residential | | | | 2.3 | % |
Commercial | | | | 3.3 | % |
Industrial | | | | 1.1 | % |
Increase in Distribution Deliveries
| | | | 2.6
| %
|
Distribution Revenues | | | Increase | |
| | | (In millions) |
Residential | | | $ | 35 | |
Commercial | | | | 38 | |
Industrial | | | | 6 | |
Increase in Distribution Revenues | | | $ | 79 | |
The higher revenues for the first nine months of 2007 also included $20 million of increased revenues resulting from the August 2006 securitization of deferred costs associated with JCP&L’s BGS supply.
Expenses
Total expenses increased by $380 million in the first nine months of 2007 as compared to the same period of 2006. The following table presents changes from the prior year by expense category:
Expenses - Changes | | | Increase (Decrease) | |
| | | (In millions) |
Purchased power costs | | | $ | 300 | |
Other operating costs | | | | (9 | ) |
Provision for depreciation | | | | 1 | |
Amortization of regulatory assets | | | | 87 | |
General Taxes | | | | 1 | |
Net increase in expenses | | | $ | 380 | |
The increase in purchased power costs primarily reflected higher unit prices resulting from the June 2006 and June 2007 BGS auctions. Other operating costs decreased $9 million in the first nine months of 2007 primarily due to lower employee benefit costs. Amortization of regulatory assets increased $87 million in the first nine months of 2007 due to higher cost recovery associated with the December 2006 NUGC rate increase.
Other Expenses
Other expenses increased $9 million in the first nine months of 2007 from the same period in 2006 primarily due to interest expense associated with JCP&L’s $550 million issuance of Senior Notes in May 2007.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to JCP&L.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to JCP&L.
METROPOLITAN EDISON COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended | |
| | September 30, | | | September 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 391,083 | | | $ | 337,750 | | | $ | 1,087,460 | | | $ | 898,320 | |
Gross receipts tax collections | | | 19,524 | | | | 18,431 | | | | 55,146 | | | | 51,293 | |
Total revenues | | | 410,607 | | | | 356,181 | | | | 1,142,606 | | | | 949,613 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Purchased power | | | 209,842 | | | | 184,508 | | | | 584,249 | | | | 487,465 | |
Other operating costs | | | 106,104 | | | | 108,740 | | | | 315,227 | | | | 229,394 | |
Provision for depreciation | | | 11,154 | | | | 10,197 | | | | 31,969 | | | | 31,390 | |
Amortization of regulatory assets | | | 36,853 | | | | 33,560 | | | | 101,965 | | | | 89,277 | |
Deferral of new regulatory assets | | | (19,151 | ) | | | (44,213 | ) | | | (93,772 | ) | | | (89,794 | ) |
General taxes | | | 21,986 | | | | 21,362 | | | | 63,208 | | | | 60,578 | |
Total expenses | | | 366,788 | | | | 314,154 | | | | 1,002,846 | | | | 808,310 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 43,819 | | | | 42,027 | | | | 139,760 | | | | 141,303 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Interest income | | | 7,239 | | | | 8,053 | | | | 22,740 | | | | 25,767 | |
Miscellaneous income | | | 1,366 | | | | 1,477 | | | | 3,973 | | | | 5,881 | |
Interest expense | | | (13,291 | ) | | | (12,291 | ) | | | (38,471 | ) | | | (35,546 | ) |
Capitalized interest | | | 292 | | | | 355 | | | | 940 | | | | 966 | |
Total other expense | | | (4,394 | ) | | | (2,406 | ) | | | (10,818 | ) | | | (2,932 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 39,425 | | | | 39,621 | | | | 128,942 | | | | 138,371 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 14,737 | | | | 14,631 | | | | 53,145 | | | | 55,390 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 24,688 | | | | 24,990 | | | | 75,797 | | | | 82,981 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | (1,452 | ) | | | - | | | | (4,357 | ) | | | - | |
Unrealized gain on derivative hedges | | | 83 | | | | 83 | | | | 251 | | | | 251 | |
Other comprehensive income (loss) | | | (1,369 | ) | | | 83 | | | | (4,106 | ) | | | 251 | |
Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | (693 | ) | | | 34 | | | | (2,078 | ) | | | 104 | |
Other comprehensive income (loss), net of tax | | | (676 | ) | | | 49 | | | | (2,028 | ) | | | 147 | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 24,012 | | | $ | 25,039 | | | $ | 73,769 | | | $ | 83,128 | |
| | | | | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part of | |
these statements. | | | | | | | | | | | | | | | | |
METROPOLITAN EDISON COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | September 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 126 | | | $ | 130 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $4,740,000 and $4,153,000, | | | | | | | | |
respectively, for uncollectible accounts) | | | 154,622 | | | | 127,084 | |
Associated companies | | | 23,728 | | | | 3,604 | |
Other | | | 18,043 | | | | 8,107 | |
Notes receivable from associated companies | | | 34,620 | | | | 31,109 | |
Prepaid taxes | | | 5,755 | | | | 13,533 | |
Other | | | 1,976 | | | | 1,424 | |
| | | 238,870 | | | | 184,991 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 1,976,453 | | | | 1,920,563 | |
Less - Accumulated provision for depreciation | | | 755,018 | | | | 739,719 | |
| | | 1,221,435 | | | | 1,180,844 | |
Construction work in progress | | | 21,124 | | | | 18,466 | |
| | | 1,242,559 | | | | 1,199,310 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 290,349 | | | | 269,777 | |
Other | | | 1,360 | | | | 1,362 | |
| | | 291,709 | | | | 271,139 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 426,368 | | | | 496,129 | |
Regulatory assets | | | 458,566 | | | | 409,095 | |
Pension assets | | | 26,239 | | | | 7,261 | |
Other | | | 38,653 | | | | 46,354 | |
| | | 949,826 | | | | 958,839 | |
| | $ | 2,722,964 | | | $ | 2,614,279 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Currently payable long-term debt | | $ | - | | | $ | 50,000 | |
Short-term borrowings- | | | | | | | | |
Associated companies | | | 254,826 | | | | 141,501 | |
Other | | | 80,000 | | | | - | |
Accounts payable- | | | | | | | | |
Associated companies | | | 24,807 | | | | 100,232 | |
Other | | | 55,186 | | | | 59,077 | |
Accrued taxes | | | 9,033 | | | | 11,300 | |
Accrued interest | | | 7,343 | | | | 7,496 | |
Other | | | 26,960 | | | | 22,825 | |
| | | 458,155 | | | | 392,431 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, without par value, authorized 900,000 shares- | | | | | | | | |
859,500 shares outstanding | | | 1,207,634 | | | | 1,276,075 | |
Accumulated other comprehensive loss | | | (28,544 | ) | | | (26,516 | ) |
Accumulated deficit | | | (158,873 | ) | | | (234,620 | ) |
Total common stockholder's equity | | | 1,020,217 | | | | 1,014,939 | |
Long-term debt and other long-term obligations | | | 542,100 | | | | 542,009 | |
| | | 1,562,317 | | | | 1,556,948 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Accumulated deferred income taxes | | | 393,169 | | | | 387,456 | |
Accumulated deferred investment tax credits | | | 8,623 | | | | 9,244 | |
Nuclear fuel disposal costs | | | 43,038 | | | | 41,459 | |
Asset retirement obligations | | | 158,302 | | | | 151,107 | |
Retirement benefits | | | 15,830 | | | | 19,522 | |
Other | | | 83,530 | | | | 56,112 | |
| | | 702,492 | | | | 664,900 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 2,722,964 | | | $ | 2,614,279 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral part | |
of these balance sheets. | | | | | | | | |
METROPOLITAN EDISON COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Nine Months Ended | |
| | September 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 75,797 | | | $ | 82,981 | |
Adjustments to reconcile net income to net cash from operating activities- | | | | | |
Provision for depreciation | | | 31,969 | | | | 31,390 | |
Amortization of regulatory assets | | | 101,965 | | | | 89,277 | |
Deferred costs recoverable as regulatory assets | | | (53,276 | ) | | | (53,406 | ) |
Deferral of new regulatory assets | | | (93,772 | ) | | | (89,794 | ) |
Deferred income taxes and investment tax credits, net | | | 20,514 | | | | 27,895 | |
Accrued compensation and retirement benefits | | | (14,404 | ) | | | (6,007 | ) |
Cash collateral | | | 1,650 | | | | (21,500 | ) |
Pension trust contribution | | | (11,012 | ) | | | - | |
Decrease (increase) in operating assets- | | | | | | | | |
Receivables | | | (57,599 | ) | | | 27,680 | |
Prepayments and other current assets | | | 7,227 | | | | (8,247 | ) |
Increase (decrease) in operating liabilities- | | | | | | | | |
Accounts payable | | | (79,316 | ) | | | (1,553 | ) |
Accrued taxes | | | 1,787 | | | | (10,451 | ) |
Accrued interest | | | (153 | ) | | | (308 | ) |
Other | | | 5,436 | | | | (1,777 | ) |
Net cash provided from (used for) operating activities | | | (63,187 | ) | | | 66,180 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing- | | | | | | | | |
Short-term borrowings, net | | | 193,324 | | | | 116,624 | |
Equity contribution from parent | | | 1,237 | | | | - | |
Redemptions and Repayments- | | | | | | | | |
Long-term debt | | | (50,000 | ) | | | (100,000 | ) |
Dividend Payments- | | | | | | | | |
Common Stock | | | - | | | | (5,000 | ) |
Net cash provided from financing activities | | | 144,561 | | | | 11,624 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (74,812 | ) | | | (65,332 | ) |
Sales of investment securities held in trusts | | | 153,943 | | | | 146,841 | |
Purchases of investment securities held in trusts | | | (156,623 | ) | | | (153,953 | ) |
Loans to associated companies, net | | | (3,511 | ) | | | (4,853 | ) |
Other | | | (375 | ) | | | (494 | ) |
Net cash used for investing activities | | | (81,378 | ) | | | (77,791 | ) |
| | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | (4 | ) | | | 13 | |
Cash and cash equivalents at beginning of period | | | 130 | | | | 120 | |
Cash and cash equivalents at end of period | | $ | 126 | | | $ | 133 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral | |
part of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Metropolitan Edison Company:
We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007
METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned, electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier.
Results of Operations
Net income for the first nine months of 2007 decreased to $76 million from $83 million in the first nine months of 2006. The decrease was primarily due to higher purchased power costs and other operating costs, partially offset by higher revenues.
Revenues
Revenues increased by $193 million, or 20.3%, in the first nine months of 2007 compared with the first nine months of 2006. This increase was primarily due to higher distribution revenues and wholesale generation revenues.
In the first nine months of 2007, retail generation revenues increased by $19 million primarily due to higher KWH sales in all customer sectors. The increase in retail generation revenues in the residential and commercial sectors primarily resulted from higher weather-related usage in the first nine months of 2007 as compared to the same period of 2006 (heating degree days increased by 17.1% and cooling degree days increased by 7.1%).
Increases in retail generation sales and revenues in the first nine months of 2007 compared to the same period of 2006 are summarized in the following tables:
Retail Generation KWH Sales
| | Increase
| |
| | | | |
Residential | | | 5.6 | % |
Commercial | | | 4.0 | % |
Industrial | | | 0.6 | % |
Increase in Retail Generation Sales
| | | 3.6
| %
|
Retail Generation Revenues
| | Increase
| |
| | (In millions)
| |
Residential | | $ | 11 | |
Commercial | | | 8 | |
Industrial | | | - | |
Increase in Retail Generation Revenues
| | $
| 19
| |
Wholesale revenues increased by $107 million in the first nine months of 2007 compared with the same period of 2006 due to Met-Ed selling additional available power into the PJM market beginning in January 2007.
Revenues from distribution throughput increased by $55 million in the first nine months of 2007 compared to the same period in 2006. The increase was due to higher KWH deliveries, reflecting the effect of the weather discussed above, and an increase in composite unit prices resulting from the January 2007 PPUC authorization to increase transmission rates, partially offset by a decrease in distribution rates.
Increases in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the same period of 2006 are summarized in the following tables:
Distribution KWH Deliveries
| | Increase
| |
| | | | |
Residential | | | 5.6 | % |
Commercial | | | 4.0 | % |
Industrial | | | 0.2 | % |
Increase in Distribution Deliveries
| | | 3.5
| %
|
| | | |
Distribution Revenues
| | Increase
| |
| | (In millions)
| |
Residential | | $ | 38 | |
Commercial | | | 5 | |
Industrial | | | 12 | |
Increase in Distribution Revenues
| | $
| 55
| |
PJM transmission revenues increased by $18 million in the first nine months of 2007 as a result of higher transmission volumes and additional PJM auction revenue rights, compared to the prior year period. Met-Ed defers the difference between revenue from its transmission rider and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total expenses increased by $195 million in the first nine months of 2007 compared to the same period of 2006. The following table presents changes from the prior year by expense category:
Expenses – Changes | | Increase (Decrease) | |
| | (In millions) | |
Purchased power costs | | $ | 97 | |
Other operating costs | | | 86 | |
Amortization of regulatory assets | | | 13 | |
Deferral of new regulatory assets | | | (4 | ) |
General taxes | | | 3 | |
Net increase in expenses | | $ | 195 | |
Purchased power costs increased in the first nine months of 2007 by $97 million due to higher volumes purchased to source higher generation sales, combined with higher composite unit costs. Other operating costs increased in the first nine months of 2007 primarily due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above ($83 million) and increased expenses ($3 million) related to Met-Ed’s customer assistance programs.
Amortization of regulatory assets increased in the first nine months of 2007 primarily due to the recovery (through Met-Ed’s transmission rider discussed above) of certain transmission costs deferred in 2006 and the amortization of the Saxton nuclear research facility’s decommissioning costs as authorized by the PPUC in January 2007. The deferral of new regulatory assets increased in the first nine months of 2007 primarily due to the deferral of previously expensed Saxton decommissioning costs of $15 million (see Legal Proceedings), partially offset by lower PJM transmission deferrals.
In the first nine months of 2007, general taxes increased primarily due to higher gross receipts taxes.
On October 1, 2007, Met-Ed sold 100% of its interest in York Haven Power Company for $5 million. The sale is subject to regulatory accounting and will not have a material impact on Met-Ed’s earnings in the fourth quarter of 2007.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to Met-Ed.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Met-Ed.
PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | | | | | | | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended | |
| | September 30, | | | September 30, | |
| | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | (In thousands) | |
REVENUES: | | | | | | | | | | | | |
Electric sales | | $ | 336,798 | | | $ | 287,633 | | | $ | 991,769 | | | $ | 813,860 | |
Gross receipts tax collections | | | 16,637 | | | | 15,787 | | | | 48,989 | | | | 46,311 | |
Total revenues | | | 353,435 | | | | 303,420 | | | | 1,040,758 | | | | 860,171 | |
| | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
Purchased power | | | 203,247 | | | | 165,921 | | | | 588,583 | | | | 474,437 | |
Other operating costs | | | 51,571 | | | | 65,165 | | | | 169,299 | | | | 151,640 | |
Provision for depreciation | | | 12,566 | | | | 11,828 | | | | 36,678 | | | | 36,269 | |
Amortization of regulatory assets, net | | | 20,861 | | | | 3,825 | | | | 32,648 | | | | 19,804 | |
General taxes | | | 19,433 | | | | 18,593 | | | | 57,634 | | | | 55,440 | |
Total expenses | | | 307,678 | | | | 265,332 | | | | 884,842 | | | | 737,590 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 45,757 | | | | 38,088 | | | | 155,916 | | | | 122,581 | |
| | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
Miscellaneous income | | | 1,483 | | | | 2,182 | | | | 5,035 | | | | 6,179 | |
Interest expense | | | (14,017 | ) | | | (11,840 | ) | | | (38,426 | ) | | | (33,975 | ) |
Capitalized interest | | | 194 | | | | 363 | | | | 737 | | | | 1,132 | |
Total other expense | | | (12,340 | ) | | | (9,295 | ) | | | (32,654 | ) | | | (26,664 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 33,417 | | | | 28,793 | | | | 123,262 | | | | 95,917 | |
| | | | | | | | | | | | | | | | |
INCOME TAXES | | | 10,387 | | | | 10,733 | | | | 49,025 | | | | 39,251 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 23,030 | | | | 18,060 | | | | 74,237 | | | | 56,666 | |
| | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | | | (2,825 | ) | | | - | | | | (8,475 | ) | | | - | |
Unrealized gain on derivative hedges | | | 16 | | | | 17 | | | | 49 | | | | 49 | |
Change in unrealized gain on available for sale securities | | | 10 | | | | 14 | | | | (6 | ) | | | (4 | ) |
Other comprehensive income (loss) | | | (2,799 | ) | | | 31 | | | | (8,432 | ) | | | 45 | |
Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | |
comprehensive income | | | (1,294 | ) | | | 13 | | | | (3,894 | ) | | | 20 | |
Other comprehensive income (loss), net of tax | | | (1,505 | ) | | | 18 | | | | (4,538 | ) | | | 25 | |
| | | | | | | | | | | | | | | | |
TOTAL COMPREHENSIVE INCOME | | $ | 21,525 | | | $ | 18,078 | | | $ | 69,699 | | | $ | 56,691 | |
| | | | | | | | | | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral | | | | | |
part of these statements. | | | | | | | | | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | |
CONSOLIDATED BALANCE SHEETS | |
(Unaudited) | |
| | September 30, | | | December 31, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
ASSETS | | | | | | |
CURRENT ASSETS: | | | | | | |
Cash and cash equivalents | | $ | 38 | | | $ | 44 | |
Receivables- | | | | | | | | |
Customers (less accumulated provisions of $4,094,000 and $3,814,000 | | | | | | | | |
respectively, for uncollectible accounts) | | | 138,007 | | | | 126,639 | |
Associated companies | | | 21,872 | | | | 49,728 | |
Other | | | 19,047 | | | | 16,367 | |
Notes receivable from associated companies | | | 17,170 | | | | 19,548 | |
Prepaid taxes | | | 7,268 | | | | 3,016 | |
Other | | | 1,724 | | | | 1,220 | |
| | | 205,126 | | | | 216,562 | |
UTILITY PLANT: | | | | | | | | |
In service | | | 2,188,553 | | | | 2,141,324 | |
Less - Accumulated provision for depreciation | | | 824,141 | | | | 809,028 | |
| | | 1,364,412 | | | | 1,332,296 | |
Construction work in progress | | | 26,835 | | | | 22,124 | |
| | | 1,391,247 | | | | 1,354,420 | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
Nuclear plant decommissioning trusts | | | 137,896 | | | | 125,216 | |
Non-utility generation trusts | | | 147,745 | | | | 99,814 | |
Other | | | 531 | | | | 531 | |
| | | 286,172 | | | | 225,561 | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
Goodwill | | | 777,904 | | | | 860,716 | |
Pension assets | | | 34,484 | | | | 11,474 | |
Other | | | 34,371 | | | | 36,059 | |
| | | 846,759 | | | | 908,249 | |
| | $ | 2,729,304 | | | $ | 2,704,792 | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Short-term borrowings- | | | | | | | | |
Associated companies | | $ | 187,313 | | | $ | 199,231 | |
Other | | | 65,000 | | | | - | |
Accounts payable- | | | | | | | | |
Associated companies | | | 107,666 | | | | 92,020 | |
Other | | | 46,283 | | | | 47,629 | |
Accrued taxes | | | 3,091 | | | | 11,670 | |
Accrued interest | | | 13,832 | | | | 7,224 | |
Other | | | 24,481 | | | | 21,178 | |
| | | 447,666 | | | | 378,952 | |
CAPITALIZATION: | | | | | | | | |
Common stockholder's equity- | | | | | | | | |
Common stock, $20 par value, authorized 5,400,000 shares- | | | | | | | | |
4,427,577 and 5,290,596 shares outstanding, respectively | | | 88,552 | | | | 105,812 | |
Other paid-in capital | | | 925,229 | | | | 1,189,434 | |
Accumulated other comprehensive loss | | | (11,731 | ) | | | (7,193 | ) |
Retained earnings | | | 39,195 | | | | 90,005 | |
Total common stockholder's equity | | | 1,041,245 | | | | 1,378,058 | |
Long-term debt and other long-term obligations | | | 777,020 | | | | 477,304 | |
| | | 1,818,265 | | | | 1,855,362 | |
NONCURRENT LIABILITIES: | | | | | | | | |
Regulatory liabilities | | | 77,441 | | | | 96,151 | |
Asset retirement obligations | | | 80,589 | | | | 76,924 | |
Accumulated deferred income taxes | | | 183,598 | | | | 193,662 | |
Retirement benefits | | | 51,289 | | | | 50,328 | |
Other | | | 70,456 | | | | 53,413 | |
| | | 463,373 | | | | 470,478 | |
COMMITMENTS AND CONTINGENCIES (Note 10) | | | | | | | | |
| | $ | 2,729,304 | | | $ | 2,704,792 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an | |
integral part of these balance sheets. | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | |
CONSOLIDATED STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | |
| | Nine Months Ended | |
| | September 30, | |
| | 2007 | | | 2006 | |
| | (In thousands) | |
| | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
Net income | | $ | 74,237 | | | $ | 56,666 | |
Adjustments to reconcile net income to net cash from operating activities | | | | | | | | |
Provision for depreciation | | | 36,678 | | | | 36,269 | |
Amortization of regulatory assets | | | 43,601 | | | | 40,854 | |
Deferral of new regulatory assets | | | (10,953 | ) | | | (21,050 | ) |
Deferred costs recoverable as regulatory assets | | | (54,228 | ) | | | (56,272 | ) |
Deferred income taxes and investment tax credits, net | | | 8,065 | | | | 14,518 | |
Accrued compensation and retirement benefits | | | (16,032 | ) | | | 2,807 | |
Cash collateral | | | 50 | | | | - | |
Pension trust contribution | | | (13,436 | ) | | | - | |
Decrease (increase) in operating assets | | | | | | | | |
Receivables | | | 13,809 | | | | 22,719 | |
Prepayments and other current assets | | | (4,757 | ) | | | (2,977 | ) |
Increase (decrease) in operating liabilities | | | | | | | | |
Accounts payable | | | 14,299 | | | | (15,555 | ) |
Accrued taxes | | | (6,191 | ) | | | (9,841 | ) |
Accrued interest | | | 6,608 | | | | 5,468 | |
Other | | | 2,653 | | | | (2,188 | ) |
Net cash provided from operating activities | | | 94,403 | | | | 71,418 | |
| | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
New Financing | | | | | | | | |
Long-Term Debt | | | 297,149 | | | | - | |
Short-term borrowings, net | | | 53,082 | | | | 21,278 | |
Equity contribution from parent | | | 1,261 | | | | - | |
Redemptions and Repayments | | | | | | | | |
Common Stock | | | (200,000 | ) | | | - | |
Dividend Payments | | | | | | | | |
Common Stock | | | (125,000 | ) | | | (5,000 | ) |
Net cash provided from financing activities | | | 26,492 | | | | 16,278 | |
| | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
Property additions | | | (70,076 | ) | | | (81,228 | ) |
Loan repayments from (loans to) associated companies, net | | | 2,378 | | | | (2,976 | ) |
Sales of investment securities held in trust | | | 94,292 | | | | 83,601 | |
Purchases of investment securities held in trust | | | (144,167 | ) | | | (83,601 | ) |
Other, net | | | (3,328 | ) | | | (3,480 | ) |
Net cash used for investing activities | | | (120,901 | ) | | | (87,684 | ) |
| | | | | | | | |
Net increase (decrease) in cash and cash equivalents | | | (6 | ) | | | 12 | |
Cash and cash equivalents at beginning of period | | | 44 | | | | 35 | |
Cash and cash equivalents at end of period | | $ | 38 | | | $ | 47 | |
| | | | | | | | |
The preceding Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an | |
integral part of these statements. | | | | | | | | |
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Pennsylvania Electric Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of September 30, 2007 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2007 and 2006 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2007 and 2006. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2006, and the related consolidated statements of income, capitalization, common stockholder’s equity, preferred stock, cash flows and taxes for the year then ended (not presented herein), and in our report (which contained references to the Company’s change in its method of accounting for defined benefit pension and other postretirement benefit plans as of December 31, 2006, and conditional asset retirement obligations as of December 31, 2005, as discussed in Note 3, Note 2(G) and Note 9 to those consolidated financial statements) dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2006, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.
PricewaterhouseCoopers LLP
Cleveland, Ohio
October 31, 2007
PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier.
Results of Operations
In the first nine months of 2007, net income increased to $74 million, compared to $57 million in the first nine months of 2006. The increase in net income was primarily due to higher revenues, partially offset by increased purchased power costs and other operating costs.
Revenues
Revenues increased by $181 million, or 21.0%, in the first nine months of 2007 compared to the same period last year. The increase was primarily due to higher distribution revenues and wholesale generation revenues.
Retail generation revenues increased $15 million for the first nine months of 2007 primarily due to higher KWH sales to all customer classes. The increase in retail generation revenues in the residential and commercial sectors was primarily impacted by weather in the first nine months of 2007 (heating degree days increased 11.0% and cooling degree days increased 14.1% as compared to the same time period of 2006).
Increases in retail generation sales and revenues in first nine months of 2007 compared to the corresponding period of 2006 are summarized in the following tables:
Retail Generation KWH Sales
| | Increase
| |
| | | |
Residential | | | 3.6 | % |
Commercial | | | 3.6 | % |
Industrial | | | 0.1 | % |
Increase in Retail Generation Sales
| | | 2.5
| %
|
| | | |
Retail Generation Revenues | | Increase | |
| | (In millions) | |
Residential | | $ | 6 | |
Commercial | | | 8 | |
Industrial | | | 1 | |
Increase in Retail Generation Revenues | | $ | 15 | |
Wholesale revenues increased $123 million in the first nine months of 2007, compared with the same period of 2006 due to Penelec selling additional available power into the PJM market beginning in January 2007.
Revenues from distribution throughput increased $37 million in the first nine months of 2007 due to higher KWH deliveries to residential and commercial customers reflecting the effect of the weather discussed above and an increase in composite unit prices for residential and industrial customers resulting from a January 2007 PPUC authorization to increase transmission rates, partially offset by a decrease in distribution rates.
Changes in distribution KWH deliveries and revenues in the first nine months of 2007 compared to the same period in 2006 are summarized in the following tables:
| | Increase
| |
Distribution KWH Deliveries
| | (Decrease)
| |
| | | |
Residential | | | 3.6 | % |
Commercial | | | 3.6 | % |
Industrial | | | (1.3 | )% |
Net Increase in Distribution Deliveries
| | | 1.9
| %
|
| | Increase | |
Distribution Revenues | | (Decrease) | |
| | (In millions) | |
Residential | | $ | 37 | |
Commercial | | | (4 | ) |
Industrial | | | 4 | |
Net Increase in Distribution Revenues | | $ | 37 | |
PJM transmission revenues increased by $6 million in the first nine months of 2007 compared to the same period in 2006 due to higher transmission volumes and additional PJM auction revenue rights in 2007. Penelec defers the difference between revenue from its transmission rider and transmission costs incurred, with no material effect to current period earnings.
Expenses
Total expenses increased by $147 million in the first nine months of 2007 compared with the same period in 2006. The following table presents changes from the prior year by expense category:
| | |
Expenses - Changes | | Increase |
| | (In millions) |
Purchased power costs | | $ | 114 |
Other operating costs | | | 18 |
Amortization of regulatory assets, net | | | 13 |
General taxes | | | 2 |
Increase in Expenses | | $ | 147 |
Purchased power costs increased by $114 million, or 24.1% in the first nine months of 2007, compared to the same period of 2006. The increase was due primarily to higher volumes purchased to source higher retail and wholesale generation sales combined with higher composite unit costs. Other operating costs increased by $18 million in the first nine months of 2007 principally due to higher congestion costs and other transmission expenses associated with the increased transmission volumes discussed above.
Net amortization of regulatory assets increased in the first nine months of 2007 primarily due to the recovery (through Penelec’s transmission rider discussed above) of certain transmission costs deferred in 2006 and lower transmission cost deferrals in 2007, partially offset by the deferral of new regulatory assets for previously expensed decommissioning costs of $12 million associated with the Saxton nuclear research facility as authorized by the PPUC in January 2007 (see Legal Proceedings).
General taxes increased $2 million in the first nine months of 2007 as compared to 2006, primarily due to higher gross receipts taxes.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to Penelec.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Penelec.
COMBINED MANAGEMENT’S DISCUSSION
AND ANALYSIS OF REGISTRANT SUBSIDIARIES
The following is a combined presentation of certain disclosures referenced in Management’s Narrative Analysis of Results of Operations of FES and the Companies. This information should be read in conjunction with (i) FES’ and the Companies’ respective Consolidated Financial Statements and Management’s Narrative Analysis of Results of Operations; (ii) the Notes to Consolidated Financial Statements as they relate to FES and the Companies; and (iii) the Companies’ respective 2006 Annual Reports on Form 10-K.
Regulatory Matters(Applicable to each of the Companies)
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Companies' respective state regulatory plans. These provisions include:
· | restructuring the electric generation business and allowing the Companies' customers to select a competitive electric generation supplier other than the Companies; |
| |
· | establishing or defining the PLR obligations to customers in the Companies' service areas; |
| |
· | providing the Companies with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; |
| |
· | itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges; |
| |
· | continuing regulation of the Companies' transmission and distribution systems; and |
| |
· | requiring corporate separation of regulated and unregulated business activities. |
The Companies and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $227 million as of September 30, 2007 (JCP&L - $93 million, Met-Ed - $43 million and Penelec - $91 million). Regulatory assets not earning a current return will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. The following table discloses regulatory assets by company:
| | September 30, | | December 31, | | Increase | |
Regulatory Assets* | | 2007 | | 2006 | | (Decrease) | |
| | (In millions) | |
OE | | $ | 717 | | $ | 741 | | $ | (24 | ) |
CEI | | | 856 | | | 855 | | | 1 | |
TE | | | 215 | | | 248 | | | (33 | ) |
JCP&L | | | 1,758 | | | 2,152 | | | (394 | ) |
Met-Ed | | | 459 | | | 409 | | | 50 | |
ATSI | | | | | | | | | | |
Total | | | | | | | | | | ) |
* | Penelec had net regulatory liabilities of approximately $77 million
and $96 million as of September 30, 2007 and December 31,
2006, respectively. These net regulatory liabilities are included in
Other Non-current Liabilities on the Consolidated Balance Sheets.
|
Ohio (Applicable to OE, CEI and TE)
The Ohio Companies filed an application and stipulation with the PUCO on September 9, 2005 seeking approval of the RCP, a supplement to the RSP. On November 4, 2005, the Ohio Companies filed a supplemental stipulation with the PUCO, which constituted an additional component of the RCP filed on September 9, 2005. On January 4, 2006, the PUCO approved, with modifications, the Ohio Companies’ RCP to supplement the RSP to provide customers with more certain rate levels than otherwise available under the RSP during the plan period. The following table provides the estimated net amortization of regulatory transition costs and deferred shopping incentives (including associated carrying charges) under the RCP for the period 2007 through 2010:
Amortization | | | | | | | | | Total | |
| | | | | | | | Ohio | |
| | (In millions) | |
2007 | | $ | 176 | | $ | 108 | | $ | 92 | | $ | 376 | |
2008 | | | 209 | | | 126 | | | 113 | | | 448 | |
2009 | | | - | | | 217 | | | - | | | 217 | |
2010 | | | | | | | | | | | | | |
Total Amortization | | | | | | | | | | | | | |
Several parties subsequently filed appeals to the Supreme Court of Ohio in connection with certain portions of the RCP approved by the PUCO. In its order, the PUCO authorized the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs, all such costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a 25-year period through distribution rates, which was expected to begin on January 1, 2009 for OE and TE, and approximately May 2009 for CEI. Through September 30, 2007, the deferred fuel costs, including interest, were $89 million, $61 million and $26 million for OE, CEI and TE, respectively.
On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated certain provisions of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” because fuel costs are a component of generation service, not distribution service, and because the Court concluded the PUCO did not address whether the deferral of fuel costs was anticompetitive. The Court remanded the matter to the PUCO for further consideration consistent with the Court’s Opinion on this issue and affirmed the PUCO’s Order in all other respects. On September 7, 2007, the Ohio Companies filed a Motion for Reconsideration with the Court. On September 10, 2007 the Ohio Companies filed an Application with the PUCO that requests the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. The Ohio Companies requested the riders become effective in October 2007 and end in December 2008, subject to reconciliation which is expected to continue through the first quarter of 2009. This matter is currently pending before the PUCO. Although unable to predict the ultimate outcome of this matter, the Ohio Companies intend to continue deferring the fuel costs pursuant to the RCP, pending the Court’s disposition of the Motion for Reconsideration and the PUCO’s action with respect to the Ohio Companies’ Application.
On August 31, 2005, the PUCO approved a rider recovery mechanism through which the Ohio Companies may recover all MISO transmission and ancillary service related costs incurred during each year ending June 30. Pursuant to the PUCO’s order, the Ohio Companies, on May 1, 2007, filed revised riders, which became effective on July 1, 2007. The revised riders represent an increase over the amounts collected through the 2006 riders of approximately $64 million annually. If it is subsequently determined by the PUCO that adjustments to the rider as filed are necessary, such adjustments, with carrying costs, will be incorporated into the 2008 transmission rider filing.
On May 8, 2007, the Ohio Companies filed with the PUCO a notice of intent to file for an increase in electric distribution rates. The Ohio Companies filed the application and rate request with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operating and maintenance expenses and recovery of regulatory assets created by deferrals that were approved in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million to the PUCO to establish the test period data that will be used as the basis for setting rates in that proceeding. The PUCO Staff is expected to issue its report in the case in the fourth quarter of 2007 with evidentiary hearings to follow in early 2008. The PUCO order is expected to be issued in the second quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.
On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per kilowatt-hour would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Comments by intervenors in the case were filed on September 5, 2007. The PUCO Staff filed comments on September 21, 2007. Parties filed reply comments on October 12, 2007. The Ohio Companies requested that the PUCO issue an order by November 1, 2007, to provide sufficient time to conduct the bidding process.
On September 25, 2007, the Ohio Governor’s proposed energy plan was officially introduced into the Ohio Senate. The bill proposes to revise state energy policy to address electric generation pricing after 2008, establish advanced energy portfolio standards and energy efficiency standards, and create GHG emissions reporting and carbon control planning requirements. The bill also proposes to move to a “hybrid” system for determining rates for PLR service in which electric utilities would provide regulated generation service unless they satisfy a statutory burden to demonstrate the existence of a competitive market for retail electricity. The Senate Energy & Public Utilities Committee has been conducting hearings on the bill and receiving testimony from interested parties, including the Governor’s Energy Advisor, the Chairman of the PUCO, consumer groups, utility executives and others. Several proposed amendments to the bill have been submitted, including those from Ohio’s investor-owned electric utilities. A substitute version of the bill, which incorporated certain of the proposed amendments, was introduced into the Senate Energy & Public Utilities Committee on October 25, 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of the Ohio Companies.
Pennsylvania (Applicable to FES, Met-Ed, Penelec and Penn)
Met-Ed and Penelec have been purchasing a portion of their PLR requirements from FES through a partial requirements wholesale power sales agreement and various amendments. Under these agreements, FES retained the supply obligation and the supply profit and loss risk for the portion of power supply requirements not self-supplied by Met-Ed and Penelec. The FES agreements have reduced Met-Ed's and Penelec's exposure to high wholesale power prices by providing power at a fixed price for their uncommitted PLR capacity and energy requirements during the term of these agreements with FES.
On September 26, 2006, Met-Ed and Penelec successfully conducted a competitive RFP for a portion of their PLR obligation for the period December 1, 2006 through December 31, 2008. FES was one of the successful bidders in that RFP process and on September 26, 2006 entered into a supplier master agreement to supply a certain portion of Met-Ed’s and Penelec’s PLR requirements at market prices that were substantially higher than the fixed price in the partial requirements agreements.
Based on the outcome of the 2006 comprehensive transition rate filing, as described below, Met-Ed, Penelec and FES agreed to restate the partial requirements power sales agreement effective January 1, 2007. The restated agreement incorporates the same fixed price for residual capacity and energy supplied by FES as in the prior arrangements between the parties, and automatically extends for successive one year terms unless any party gives 60 days’ notice prior to the end of the year. The restated agreement also allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy thus sold to the extent needed for Met-Ed and Penelec to satisfy their PLR obligations. The parties also have separately terminated the supplier master agreements in connection with the restatement of the partial requirements agreement. Accordingly, the energy that would have been supplied under the supplier master agreement will now be provided under the restated partial requirements agreement. The fixed price under the restated agreement is expected to remain below wholesale market prices during the term of the agreement.
If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for its fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.
Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec also requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.
The PPUC entered its Opinion and Order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, when new transmission rates were effective, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes in NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission expenses and the transmission deferral. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million). Met-Ed and Penelec filed a Petition for Reconsideration on January 26, 2007 on the issues of consolidated tax savings and rate of return on equity. Other parties filed Petitions for Reconsideration on transmission (including congestion), transmission deferrals and rate design issues. On February 8, 2007, the PPUC entered an order granting Met-Ed’s, Penelec’s and the other parties’ petitions for procedural purposes. Due to that ruling, the period for appeals to the Commonwealth Court of Pennsylvania was tolled until 30 days after the PPUC entered a subsequent order ruling on the substantive issues raised in the petitions. On March 1, 2007, the PPUC issued three orders: (1) a tentative order regarding the reconsideration by the PPUC of its own order; (2) an order denying the Petitions for Reconsideration of Met-Ed, Penelec and the OCA and denying in part and accepting in part the MEIUG’s and PICA’s Petition for Reconsideration; and (3) an order approving the compliance filing. Comments to the PPUC for reconsideration of its order were filed on March 8, 2007, and the PPUC ruled on the reconsideration on April 13, 2007, making minor changes to rate design as agreed upon by Met-Ed, Penelec and certain other parties.
On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. On June 19, 2007, initial briefs were filed and responsive briefs were filed through September 21, 2007. Reply briefs were filed on October 5, 2007. Oral arguments are expected to take place in late 2007 or early 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the financial condition and results of operations of Met-Ed, Penelec and FirstEnergy.
As of September 30, 2007, Met-Ed's and Penelec's unrecovered regulatory deferrals pursuant to the 2006 comprehensive transition rate case, the 1998 Restructuring Settlement (including the Phase 2 Proceedings) and the FirstEnergy/GPU Merger Settlement Stipulation were $496 million and $58 million, respectively. During the PPUC’s annual audit of Met-Ed’s and Penelec’s NUG stranded cost balances in 2006, it noted a modification to the NUG purchased power stranded cost accounting methodology made by Met-Ed and Penelec. On August 18, 2006, a PPUC Order was entered requiring Met-Ed and Penelec to reflect the deferred NUG cost balances as if the stranded cost accounting methodology modification had not been implemented. As a result of this PPUC order, Met-Ed recognized a pre-tax charge of approximately $10.3 million in the third quarter of 2006, representing incremental costs deferred under the revised methodology in 2005. Met-Ed and Penelec continue to believe that the stranded cost accounting methodology modification is appropriate and on August 24, 2006 filed a petition with the PPUC pursuant to its order for authorization to reflect the stranded cost accounting methodology modification effective January 1, 1999. Hearings on this petition were held in February 2007 and briefing was completed on March 28, 2007. The ALJ’s initial decision was issued on May 3, 2007 and denied Met-Ed's and Penelec’s request to modify their NUG stranded cost accounting methodology. The companies filed exceptions to the initial decision on May 23, 2007 and replies to those exceptions were filed on June 4, 2007. It is not known when the PPUC may issue a final decision in this matter.
On May 2, 2007, Penn filed a plan with the PPUC for the procurement of PLR supply from June 2008 through May 2011. The filing proposes multiple, competitive RFPs with staggered delivery periods for fixed-price, tranche-based, pay as bid PLR supply to the residential and commercial classes. The proposal phases out existing promotional rates and eliminates the declining block and the demand components on generation rates for residential and commercial customers. The industrial class PLR service will be provided through an hourly-priced service provided by Penn. Quarterly reconciliation of the differences between the costs of supply and revenues from customers is also proposed. On September 28, 2007, Penn filed a Joint Petition for Settlement resolving all but one issue in the case. Briefs were also filed on September 28, 2007, on the unresolved issue of incremental uncollectible accounts expense. The settlement is either supported, or not opposed, by all parties. The PPUC is expected to act on the settlement and the unresolved issue in late November or early December 2007 for the initial RFP to take place in January 2008.
On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation programs to meet demand growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and an optional three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The final form of any legislation arising from the special legislative session is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.
New Jersey (Applicable to JCP&L)
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2007, the accumulated deferred cost balance totaled approximately $330 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting a continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. A schedule for further NJBPU proceedings has not yet been set.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that would prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. Comments on the alternative proposal were submitted on June 15, 2006. On November 3, 2006, the Staff circulated a revised draft proposal to interested stakeholders. Another revised draft was circulated by the NJBPU Staff on February 8, 2007.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated with the issuance of a proposed set of objectives which, as to electricity, included the following:
· Reduce the total projected electricity demand by 20% by 2020;
· | Meet 22.5% of New Jersey’s electricity needs with renewable energy resources by that date; |
· Reduce air pollution related to energy use;
· Encourage and maintain economic growth and development;
· | Achieve a 20% reduction in both Customer Average Interruption Duration Index and System Average Interruption Frequency Index by 2020; |
· | Maintain unit prices for electricity to no more than +5% of the regional average price (region includes New York, New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia); and |
· Eliminate transmission congestion by 2020.
Comments on the objectives and participation in the development of the EMP have been solicited and a number of working groups have been formed to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. EMP working groups addressing (1) energy efficiency and demand response, (2) renewables, (3) reliability, and (4) pricing issues have completed their assigned tasks of data gathering and analysis and have provided reports to the EMP Committee. Public stakeholder meetings were held in the fall of 2006 and in early 2007, and further public meetings are expected later in 2007. A final draft of the EMP is expected to be presented to the Governor in late 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation may have on its operations or those of JCP&L.
On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments which were due on September 26, 2007. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such regulations may have on its operations or those of JCP&L.
FERC Matters (Applicable(Applicable to FES and each of the Companies)
On November 18, 2004,SFAS 141(R) – “Business Combinations”
In December 2007, the FERCFASB issued an orderSFAS 141(R), which requires the acquiring entity in a business combination to recognize all the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141(R) attempts to reduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the RTORneed for transmission service betweennumerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FES or any of the MISO and PJM regions. The FERCCompanies that close after January 1, 2009. In addition, the Standard also orderedaffects the MISO, PJMaccounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FES and the transmission ownersCompanies are currently evaluating the impact of adopting this Standard on their financial statements.
SFAS 160 - “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”
In December 2007, the FASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. This Statement is effective for fiscal years, and interim periods within MISOthose fiscal years, beginning on or after December 15, 2008. Early adoption is prohibited. The Statement is not expected to have a material impact on FES’ or the Companies’ financial statements.
| SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” |
In March 2008, the FASB issued SFAS 161, which enhances the current disclosure framework for derivative instruments and PJMhedging activities. The Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure better conveys the purpose of derivative use in terms of the risks that the entity is intending to submit compliance filings containingmanage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a SECA mechanismtabular format is designed to recover lost RTOR revenuesprovide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is designed to provide information on the potential effect on an entity’s liquidity from using derivatives. Finally, this Statement requires cross-referencing within the footnotes, which is intended to help users of financial statements locate important information about derivative instruments. FES and the Companies are currently evaluating the impact of adopting this Standard on their financial statements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy is a 16-month transition period from load serving entities. The FERC issued orders in 2005 settingdiversified energy company that holds, directly or indirectly, all of the SECA for hearing.outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and FES participatedits subsidiaries FGCO and NGC, and FESC.
FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.
These statements should be read in conjunction with the financial statements and notes included in the FERC hearings held in May 2006 concerningcombined Annual Report on Form 10-K for the calculationyear ended December 31, 2007 for FirstEnergy, FES and impositionthe Companies. The consolidated unaudited financial statements of FirstEnergy, FES and each of the SECA charges. Companies reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 8) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.
The presiding judge issuedconsolidated financial statements as of March 31, 2008 and for the three-month periods ended March 31, 2008 and 2007 have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated May 7, 2008) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.
2. EARNINGS PER SHARE
Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The pool of stock-based compensation tax benefits is calculated in accordance with SFAS 123(R). On March 2, 2007, FirstEnergy repurchased approximately 14.4 million shares, or 4.5%, of its outstanding common stock through an accelerated share repurchase program at an initial decision on August 10, 2006, rejecting the compliance filings made by the RTOs and transmission owners, ruling on various issues and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006.price of approximately $900 million. A final order could be issued by the FERCpurchase price adjustment of $51 million was settled in the fourth quartercash on December 13, 2007. The following table reconciles basic and diluted earnings per share of 2007.common stock:
On January 31, 2005, certain PJM transmission owners made three filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. In the second filing, the settling transmission owners proposed a revised Schedule 12 to the PJM tariff designed to harmonize the rate treatment of new and existing transmission facilities. Interventions and protests were filed on February 22, 2005. In the third filing, BG&E and Pepco Holdings, Inc. requested a formula rate for transmission service provided within their respective zones. Hearings were held and numerous parties appeared and litigated various issues; including AEP, which filed in opposition proposing to create a "postage stamp" rate for high voltage transmission facilities across PJM. At the conclusion of the hearings, the ALJ issued an initial decision adopting the FERC Trial Staff’s position that the cost of all PJM transmission facilities should be recovered through a postage stamp rate.The ALJ recommended an April 1, 2006 effective date for this change in rate design. Numerous parties, including FirstEnergy, submitted briefs opposing the ALJ’s decision and recommendations. On April 19, 2007, the FERC issued an order rejecting the ALJ’s findings and recommendations in nearly every respect. The FERC found that the PJM transmission owners’ existing “license plate” rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be socialized throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. Nevertheless, the FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.Reconciliation of Basic and Diluted | | Three Months Ended March 31, | |
Earnings per Share of Common Stock | | 2008 | | 2007 | |
| (In millions, except per share amounts) |
Net income | | $ | 276 | | $ | 290 | |
| | | | | | | |
Average shares of common stock outstanding – Basic | | | 304 | | | 314 | |
Assumed exercise of dilutive stock options and awards | | | 3 | | | 2 | |
Average shares of common stock outstanding – Dilutive | | | 307 | | | 316 | |
| | | | | | | |
Basic earnings per share of common stock | | $ | 0.91 | | $ | 0.92 | |
Diluted earnings per share of common stock | | $ | 0.90 | | $ | 0.92 | |
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 Order. Subsequently, FirstEnergy and other parties filed pleadings opposing the requests for rehearing. The FERC’s Orders on PJM rate design, if sustained on rehearing and appeal, will prevent the allocation of the cost of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission costs shifting to the JCP&L, Met-Ed and Penelec zones.
New FERC Transmission Rate Design Filings3. DIVESTITURES AND DISCONTINUED OPERATIONS
On AugustMarch 7, 2008, FirstEnergy sold certain telecommunication assets, resulting in a net after-tax gain of $19.3 million. As a result of the sale, FirstEnergy adjusted goodwill by $1 million for the former GPU companies due to the realization of tax benefits that had been reserved in purchase accounting. The sale of assets did not meet the criteria for classification as discontinued operations as of March 31, 2008.
4. FAIR VALUE MEASURES
Effective January 1, 2007,2008, FirstEnergy adopted SFAS 157, which provides a numberframework for measuring fair value under GAAP and, among other things, requires enhanced disclosures about assets and liabilities recognized at fair value. FirstEnergy also adopted SFAS 159 on January 1, 2008, which provides the option to measure certain financial assets and financial liabilities at fair value. FirstEnergy has analyzed its financial assets and financial liabilities within the scope of filings were made withSFAS 159 and, as of March 31, 2008, has elected not to record eligible assets and liabilities at fair value.
As defined in SFAS 157, fair value is the FERC by transmission owning utilitiesprice that would be received for an asset or paid to transfer a liability (exit price) in the MISOprincipal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and PJM footprintthe lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that could affectare held in various trusts.
Level 2 – Pricing inputs are either directly or indirectly observable in the transmission rates paidmarket as of the reporting date, other than quoted prices in active markets included in Level 1. FirstEnergy’s Level 2 consists primarily of investments in debt securities held in various trusts and commodity forwards. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category include non-exchange-traded derivatives such as forwards and certain interest rate swaps.
Level 3 – Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the longer term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s operating companies and FES.Level 3 instruments consist of NUG contracts.
FirstEnergy joinedutilizes market data and assumptions that market participants would use in a filing made bypricing the MISO transmission owners that would maintainasset or liability, including assumptions about risk and the existing “license plate” ratesrisks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the market approach for transmission service within MISO provided over existing transmission facilities.recurring fair value measurements using the best information available. Accordingly, FirstEnergy also joined in a filing made by bothmaximizes the MISOuse of observable inputs and PJM transmission owners proposing to continueminimizes the eliminationuse of transmission rates associated with service over existing transmission facilities between MISO and PJM. If adopted by the FERC, these filings would not affect the rates charged to load-serving FirstEnergy affiliates for transmission service over existing transmission facilities. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint be maintained (known as the RECB Process). Each of these filings was supported by the majority of transmission owners in either MISO or PJM, as applicable.unobservable inputs.
The Midwest Stand-Alone Transmission Companies made a filing under Section 205following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of March 31, 2008. As required by SFAS 157, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the Federal Power Act requesting that 100%significance of the cost of new qualifying 345 kV and higher transmission facilities be spread throughout the entire MISO footprint. Further, Indianapolis Power and Light Company separately moved the FERC to reopen the record to address the cost allocation for the RECB Process. If either proposal is adopted by the FERC, it could shift a greater portion of the cost of new 345 kV and higher transmission facilitiesparticular input to the FirstEnergy footprint in MISO,fair value measurement requires judgment and increasemay affect the transmission rates paid by load-serving FirstEnergy affiliates in MISO.valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “SuperRegion” that regionalizes the cost of new and existing transmission facilities operated at voltages of 345 kV and above. Lower voltage facilities would continue to be recovered in the host utility transmission rate zone through a license plate rate. AEP requests a refund effective October 1, 2007, or alternatively, February 1, 2008. The effect of this proposal, if adopted by FERC, would be to shift significant costs to the FirstEnergy zones in MISO and PJM. FirstEnergy believes that most of these costs would ultimately be recoverable in retail rates. On October 12, 2007, BG&E filed a motion to dismiss AEP’s complaint. On October 16, 2007, the Organization of MISO States filed comments urging the FERC to dismiss AEP’s complaint. Interventions and protests to AEP’s complaint and answers to BG&E’s motion to dismiss were due October 29, 2007. FirstEnergy and other transmission owners filed protests to AEP’s complaint and support for BG&E’s motion to dismiss. AEP has asked for consolidation of its complaint with the cases above, and FirstEnergy expects it to be resolved on the same timeline as those cases.
Any increase in rates charged for transmission service to FirstEnergy affiliates is dependent upon the outcome of these proceedings at FERC. All or some of these proceedings may be consolidated by the FERC and set for hearing. The outcome of these cases cannot be predicted. Any material adverse impact on FirstEnergy would depend upon the ability of the load-serving FirstEnergy affiliates to recover increased transmission costs in their retail rates. FirstEnergy believes that current retail rate mechanisms in place for PLR service for the Ohio Companies and for Met-Ed and Penelec would permit them to pass through increased transmission charges in their retail rates. Increased transmission charges in the JCP&L and Penn transmission zones would be the responsibility of competitive electric retail suppliers, including FES.
MISO Ancillary Services Market and Balancing Area Consolidation Filing
MISO made a filing on September 14, 2007 to establish Ancillary Services markets for regulation, spinning and supplemental reserves to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. An effective date of June 1, 2008 was requested in the filing.
MISO’s previous filing | | March 31, 2008 | |
Recurring Fair Value Measures | | Level 1 | | Level 2 | | Level 3 | | Total | |
| | (In millions) | |
Assets: | | | | | | | | | | | | | |
Derivatives | | $ | 4 | | $ | 98 | | $ | - | | $ | 102 | |
Nuclear decommissioning trusts(1) | | | 1,070 | | | 953 | | | - | | | 2,023 | |
Other investments(2) | | | 21 | | | 303 | | | - | | | 324 | |
Total | | $ | 1,095 | | $ | 1,354 | | $ | - | | $ | 2,449 | |
| | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | |
Derivatives | | $ | - | | $ | 98 | | $ | - | | $ | 98 | |
NUG contracts(3) | | | - | | | - | | | 682 | | | 682 | |
Total | | $ | - | | $ | 98 | | $ | 682 | | $ | 780 | |
| (1) | Balance excludes $2 million of receivables, payables and accrued income. |
| (2) | Excludes $318 million of the cash surrender value of life insurance contracts. |
| (3) | NUG contracts are completely offset by regulatory assets. |
The determination of the above fair value measures takes into consideration various factors required under SFAS 157. These factors include the credit standing of the counterparties involved, the impact of credit enhancements (such as cash deposits, LOCs and priority interests) and the impact of nonperformance risk.
Exchange-traded derivative contracts, which include some futures and options, are generally based on unadjusted quoted market prices in active markets and are classified within Level 1. Forwards, options and swap contracts that are not exchange-traded are classified as Level 2 as the fair values of these items are based on ICE quotes or market transactions in the OTC markets. In addition, complex or longer term structured transactions can introduce the need for internally-developed model inputs that may not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is classified as Level 3.
Nuclear decommissioning trusts consist of equity securities listed on active exchanges classified as Level 1 and various debt securities and collective trusts classified as Level 2. Other investments represent the NUG trusts, spent nuclear fuel trusts and rabbi trust investments, which primarily consist of various debt securities and collective trusts classified as Level 2.
The following table sets forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2008 (in millions):
Balance as of January 1, 2008 | | $ | 750 | |
Realized and unrealized gains (losses)(1) | | | (58 | ) |
Purchases, sales, issuances and settlements, net(1) | | | (10 | ) |
Net transfers to (from) Level 3 | | | - | |
Balance as of March 31, 2008 | | $ | 682 | |
| | | | |
Change in unrealized gains (losses) relating to | | | | |
instruments held as of March 31, 2008 | | $ | (58 | ) |
| | | | |
(1) Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings. | |
Under FSP FAS 157-2, FirstEnergy has elected to establishdefer, for one year, the election of SFAS 157 for financial assets and financial liabilities measured at fair value on a non-recurring basis. FirstEnergy is currently evaluating the impact of FAS 157 on those financial assets and financial liabilities measured at fair value on a non-recurring basis.
5. DERIVATIVE INSTRUMENTS
FirstEnergy is exposed to financial risks resulting from the fluctuation of interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchases and normal sales criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item, depending on whether or not it is designated as part of a hedge transaction, the nature of the hedge transaction and hedge effectiveness. FirstEnergy does not offset fair value for the right to reclaim collateral or the obligation to return collateral.
FirstEnergy hedges anticipated transactions using cash flow hedges. Such transactions include hedges of anticipated electricity and natural gas purchases and anticipated interest payments associated with future debt issues. The effective portion of such hedges are initially recorded in equity as other comprehensive income or loss and are subsequently included in net income as the underlying hedged commodities are delivered or interest payments are made. Gains and losses from any ineffective portion of cash flow hedges are included directly in earnings.
The net deferred losses of $84 million included in AOCL as of March 31, 2008, for derivative hedging activity, as compared to $75 million as of December 31, 2007, resulted from a net $21 million increase related to current hedging activity and a $12 million decrease due to net hedge losses reclassified to earnings during the three months ended March 31, 2008. Based on current estimates, approximately $19 million (after tax) of the net deferred losses on derivative instruments in AOCL as of March 31, 2008 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.
FirstEnergy has entered into swaps that have been designated as fair value hedges of fixed-rate, long-term debt issues to protect against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. Swap maturities, call options, fixed interest rates received, and interest payment dates match those of the underlying debt obligations. As of March 31, 2008, FirstEnergy had interest rate swaps with an Ancillary Servicesaggregate notional value of $250 million and a fair value of $5 million.
During 2007 and the first three months of 2008, FirstEnergy entered into several forward starting swap agreements (forward swaps) in order to hedge a portion of the consolidated interest rate risk associated with the anticipated issuance of variable-rate, short-term debt and fixed-rate, long-term debt securities by one or more of its subsidiaries as outstanding debt matures during 2008 and 2009. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first three months of 2008, FirstEnergy terminated swaps with a notional value of $300 million and entered into swaps with a notional value of $500 million. FirstEnergy paid $18 million related to the terminations, $1 million of which was deemed ineffective and recognized in current period earnings. FirstEnergy will recognize the remaining $17 million loss over the life of the associated future debt. As of March 31, 2008, FirstEnergy had forward swaps with an aggregate notional amount of $600 million and a fair value of $(8) million.
6. ASSET RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations under SFAS 143 for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditional retirement obligations (primarily for asbestos remediation) in accordance with FIN 47.
The ARO liability of $1.3 billion as of March 31, 2008 is primarily related to the future nuclear decommissioning of the Beaver Valley, Davis-Besse, Perry and TMI-2 nuclear generating facilities. FirstEnergy utilized an expected cash flow approach to measure the fair value of the nuclear decommissioning ARO.
FirstEnergy maintains nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. As of March 31, 2008, the fair value of the decommissioning trust assets was approximately $2.0 billion.
The following tables analyze changes to the ARO balance during the first quarters of 2008 and 2007, respectively.
ARO Reconciliation | | FirstEnergy | | FES | | OE | | CEI | | TE | | JCP&L | | Met-Ed | | Penelec | |
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Revisions in estimated cash flows | | | - | | | | | | | | | | | | | | | | | | | | | | |
| | $ | 1,287 | | | | | | | | | | | | | | | | | | | | | | |
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7. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory defined benefit pension plans that cover substantially all of its employees and those of its subsidiaries. The trusteed plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market was rejected without prejudicevalue as of December 31, 2007. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
The components of FirstEnergy's net periodic pension cost and other postretirement benefit cost (including amounts capitalized) for the three months ended March 31, 2008 and 2007, consisted of the following:
| | Pension Benefits | | Other Postretirement Benefits | |
| | 2008 | | 2007 | | 2008 | | 2007 | |
| | (In millions) | |
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Expected return on plan assets | | | | | | | | | | | | | |
Amortization of prior service cost | | | | | | | | | | | | | |
Recognized net actuarial loss | | | | | | | | | | | | | |
Net periodic cost (credit) | | | | ) | | | | | | ) | | | ) |
Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net periodic pension costs and net periodic postretirement benefit costs (including amounts capitalized) recognized by FERC on June 22,each of the Companies for the three months ended March 31, 2008 and 2007 subject to MISO making certain modifications in its filing. FirstEnergy believes that MISO’s September 14 filing generallywere as follows:
| | Pension Benefit Cost (Credit) | | Other Postretirement Benefit Cost (Credit) | |
| | 2008 | | 2007 | | 2008 | | 2007 | |
| | (In millions) | |
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8. VARIABLE INTEREST ENTITIES
FIN 46R addresses the FERC’s directives.consolidation of VIEs, including special-purpose entities, that are not controlled through voting interests or in which the equity investors do not bear the entity's residual economic risks and rewards. FirstEnergy supportsand its subsidiaries consolidate VIEs when they are determined to be the proposalVIE's primary beneficiary as defined by FIN 46R.
Trusts
FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to establish markets for Ancillary Servicesrefinance debt originally issued in connection with sale and consolidate existing balancing areas, but filed objections on specific aspectsleaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.
PNBV was established to purchase a portion of the MISO proposal. Interventionslease obligation bonds issued in connection with OE’s 1987 sale and protestsleaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to MISO’s filing were madepurchase the notes issued by PNBV. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with FERC on October 15, 2007.CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.
Order No. 890 on Open Access Transmission Tariffs
On February 16, 2007, the FERC issued a final rule (Order No. 890) that revises its decade-old open access transmission regulations and policies. The FERC explained that the final rule is intended to strengthen non-discriminatory access to the transmission grid, facilitate FERC enforcement, and provide for a more open and coordinated transmission planning process. The final rule became effective on May 14, 2007. MISO, PJM and ATSI will be filing revised tariffs to comply with the FERC’s order. MISO, PJM and ATSI submitted tariff filings to the FERC on October 11, 2007. As a market participant in both MISO and PJM, FirstEnergy will conform its business practices to each respective revised tariff.
Environmental MattersLoss Contingencies
FES and the Ohio Companies accrueare exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments are made. The following table shows each company’s net exposure to loss based upon the casualty value provisions mentioned above as of March 31, 2008:
| | Maximum Exposure | | Discounted Lease Payments, net | | Net Exposure |
| | (in millions) |
FES | | $ | 1,364 | | $ | 1,216 | | $ | 148 |
OE | | 819 | | 628 | | 191 |
CEI | | 782 | | 77 | | 705 |
TE | | 782 | | 457 | | 325 |
In October 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly formed wholly-owned subsidiary in December 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE will remain primarily liable on the 1987 leases and related agreements as to the lessors and other parties to the agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.
On March 3, 2008, notice was given to the nine owner trusts that are lessors under sale and leaseback transactions, originally entered into by TE in 1987, that NGC would acquire the related 18.26% undivided interest in Beaver Valley Unit 2 through the exercise of the periodic purchase option provided for in the applicable facility leases. The purchase price to be paid by NGC for the undivided interest will be equal to the higher of a specified casualty value under the applicable facility leases (approximately $239 million in the aggregate for the equity portion of all nine facility leases) and the fair market sales value of such undivided interests. Determination of the fair market sales value may become subject to an appraisal procedure provided for in the lease documentation. An additional payment of approximately $236 million would be required to prepay in full the outstanding principal of, and accrued but unpaid interest on, the lessor notes of the nine owner trusts. Alternatively, this amount would not be paid as part of the aggregate purchase price if the lessor notes are instead assumed at the time of the exercise of the option. If NGC determines to prepay the notes, it is possible that the proceeds from such prepayment may not be sufficient to pay the principal of, and interest on, the bonds as they become due. If that is the case, NGC would provide a mechanism to address any such potential shortfall in a timely manner.
Power Purchase Agreements
In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains approximately 30 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.
FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R.
Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months ended March 31, 2008 and 2007 are shown in the following table:
| | Three Months Ended | |
| | March 31, | |
| | 2008 | | 2007 | |
| | (In millions) | |
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Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold $182 million of transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.
JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of March 31, 2008, $391 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.
Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of $157,000 payable from TBC collections.
9. INCOME TAXES
On January 1, 2007, FirstEnergy adopted FIN 48, which provides guidance for accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS 109. This interpretation prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. FIN 48 also provides guidance on derecognition, classification, interest, penalties, accounting in interim periods, disclosure and transition. The evaluation of a tax position in accordance with this interpretation is a two-step process. The first step is to determine if it is more likely than not that a tax position will be sustained upon examination, based on the merits of the position, and should therefore be recognized. The second step is to measure a tax position that meets the more likely than not recognition threshold to determine the amount of income tax benefit to recognize in the financial statements.
As of January 1, 2007, the total amount of FirstEnergy’s unrecognized tax benefits was $268 million. FirstEnergy recorded a $2.7 million cumulative effect adjustment to the January 1, 2007 balance of retained earnings to increase reserves for uncertain tax positions. Of the total amount of unrecognized income tax benefits, $92 million would favorably affect FirstEnergy’s effective tax rate upon recognition. The majority of items that would not have affected the effective tax rate would be purchase accounting adjustments to goodwill upon recognition. During the first three months of 2008 and 2007, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of March 31, 2008, FirstEnergy expects that it is reasonably possible that $8 million of the unrecognized benefits will be resolved within the next twelve months and is included in the caption “accrued taxes,” with the remaining $263 million included in the caption “other non-current liabilities” on the Consolidated Balance Sheets.
FIN 48 also requires companies to recognize interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized in accordance with FIN 48 and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes, consistent with its policy prior to implementing FIN 48. The net amount of interest accrued as of March 31, 2008 was $57 million, as compared to $53 million as of December 31, 2007. During the first three months of 2008 and 2007, there were no material changes to the amount of interest accrued.
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2007. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audits for the years 2004-2006 are expected to close before December 2008, but management anticipates certain items to be under appeal. The IRS began auditing the year 2007 in February 2007 and year 2008 in February 2008 under its Compliance Assurance Process experimental program. Neither audit is expected to close before December 2008. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.
10. COMMITMENTS, GUARANTEES AND CONTINGENCIES
(A) GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of March 31, 2008, outstanding guarantees and other assurances aggregated approximately $4.4 billion, consisting of parental guarantees - $0.9 billion, subsidiaries’ guarantees - $2.7 billion, surety bonds - $0.1 billion and LOCs - $0.7 billion.
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $0.9 billion discussed above) as of March 31, 2008 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral or provision of an LOC may be required of the subsidiary. As of March 31, 2008, FirstEnergy's maximum exposure under these collateral provisions was $440 million.
Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $66 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
FirstEnergy has also guaranteed the obligations of the operators of the TEBSA project, up to a maximum of $2 million (subject to escalation) under the project's operations and maintenance agreement. In connection with the sale of TEBSA in January 2004, the purchaser indemnified FirstEnergy against any loss under this guarantee. FirstEnergy has also provided an LOC ($19 million as of March 31, 2008), which is renewable and declines yearly based upon the senior outstanding debt of TEBSA.
In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.
(B) | ENVIRONMENTAL MATTERS |
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of approximately $1.4 billion for the period 2008-2012.
FirstEnergy accrues environmental liabilities only when they concludeit concludes that it is probable that they haveit has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FES’ and the Companies’FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance(Applicable to FES)
FESFirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $32,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FESFirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the Clean Air Act. FESCAA. FirstEnergy has disputed those alleged violations based on its Clean Air ActCAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding the opacity limit applicable to the common stack for Bay Shore Units 2, 3 and 4.
FESFirstEnergy complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls and the generation of more electricity at lower-emitting plants. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FES'FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FESFirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal Clean Air Act,CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Mansfield Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 16,18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim.
On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 1995 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the Court. Although it remains liable for civil or criminal penalties and fines that may be assessed relating to events prior to the sale of the Portland Station in 1999, Met-Ed is currently studying PennFuture’s complaint.indemnified by Sithe Energy against any other liability arising under the CAA whether it arises out of pre-1999 or post-1999 events.
National Ambient Air Quality Standards(Applicable to FES)
In July 1997, the EPA promulgated changes in the NAAQS for ozone and fine particulate matter. In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR allowed each affected state until 2006 to develop implementing regulations to achieve additionalrequires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2). FES’FirstEnergy's Michigan, Ohio and Pennsylvania fossil generation facilities will be subject to caps on SO2 and NOX emissions, whereas its New Jersey fossil generation facility will be subject to only a cap on NOX emissions. According to the EPA, SO2 emissions will be reduced by 45% (from 2003 levels) by 2010 across the states covered by the rule, with reductions reaching 73% (from 2003 levels) by 2015, capping SO2 emissions in affected states to just 2.5 million tons annually. NOX emissions will be reduced by 53% (from 2003 levels) by 2009 across the states covered by the rule, with reductions reaching 61% (from 2003 levels) by 2015, achieving a regional NOX cap of 1.3 million tons annually. CAIR has been challenged in the United States Court of Appeals for the District of Columbia. The future cost of compliance with these regulations may be substantial and willmay depend on the outcome of this litigation and how they areCAIR is ultimately implemented by the states in which FES operates affected facilities.implemented.
Mercury Emissions(Applicable to FES)
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases. Initially,phases; initially, capping national mercury emissions will be capped nationally at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program). Phase II of the mercury cap-and-trade program will cap nationwide mercury emissions from coal-fired power plants at and 15 tons per year by 2018. However, the final rules giveSeveral states substantial discretion in developing rules to implement these programs. In addition, both the CAIR and environmental groups appealed the CAMR have been challenged into the United States Court of Appeals for the District of Columbia. FES'On February 8, 2008, the court vacated the CAMR ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA must now seek further judicial review of that ruling or take regulatory action to promulgate new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with thesemercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented by the states in which FES operates affected facilities.implemented.
The model rules for both CAIR and CAMR contemplate an input-based methodology to allocate allowances to affected facilities. Under this approach, allowances would be allocated based on the amount of fuel consumed by the affected sources. FES would prefer an output-based generation-neutral methodology in which allowances are allocated based on megawatts of power produced, allowing new and non-emitting generating facilities (including renewables and nuclear) to be entitled to their proportionate share of the allowances. Consequently, FES will be disadvantaged if these model rules were implemented as proposed because FES’ substantial reliance on non-emitting (largely nuclear) generation is not recognized under the input-based allocation.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. Pennsylvania’s mercury regulation would deprive FES of mercury emission allowances that were to be allocated to the Mansfield Plant under the CAMR and that would otherwise be available for achieving FirstEnergy system-wide compliance. It is anticipated that compliance with these regulations, if approved by the EPA and implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FES’FirstEnergy’s only Pennsylvania coal-fired Pennsylvania power plant, until 2015, if at all.
W. H. Sammis Plant(Applicable to FES, OE and Penn)
In 1999 and 2000, the EPA issued an NOV or compliance orders to nine utilities alleging violations ofand the Clean Air ActDOJ filed a civil complaint against OE and Penn based on operation and maintenance of 44 power plants, including the W. H.W.H. Sammis Plant which was owned at that time by OE(Sammis NSR Litigation) and Penn, and is now owned by FGCO. In addition, the DOJ filed eight civilsimilar complaints against various investor-owned utilities, including a complaint against OE and Penn in theinvolving 44 other U.S. District Court for the Southern District of Ohio. Thesepower plants. This case, along with seven other similar cases, are referred to as the New Source Review, or NSR cases.
On March 18, 2005, OE and Penn announced that they had reached a settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation. This settlement agreement, which is in the form of a consent decree, was approved by the court on July 11, 2005, and requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices and provides for stipulated penalties for failure to install and operate such pollution controls in accordance with that agreement. Consequently, if FirstEnergy fails to install such pollution control devices, for any reason, including, but not limited to, the failure of any third-party contractor to timely meet its delivery obligations for such devices, FirstEnergy could be exposed to penalties under the Sammis NSR Litigation consent decree. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation settlement agreementconsent decree are currently estimated to be $1.7$1.3 billion for 2007 through 20112008-2012 ($400650 million of which is expected to be spent during 2007,2008, with the largest portion of the remaining $1.3 billion$650 million expected to be spent in 20082009). This amount is included in the estimated capital expenditures for environmental compliance referenced above.
On April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, on May 8, 2007, the EPA proposed to revise the NSR regulations to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR. The EPA has not yet issued a final regulation. FGCO’s future cost of compliance with those regulations may be substantial and 2009).will depend on how they are ultimately implemented.
The Sammis NSR Litigation consent decree also requires FirstEnergy to spend up to $25 million toward environmentally beneficial projects, $14 million of which is satisfied by entering into 93 MW (or 23 MW if federal tax credits are not applicable) of wind energy purchased power agreements with a 20-year term. An initial 16 MW of the 93 MW consent decree obligation was satisfied during 2006.
Climate Change(Applicable to FES)
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG emitted by developed countries by 5.2% from 1990 levels between 2008 and 2012. The United States signed the Kyoto Protocol in 1998 but it failed to receive the two-thirds vote required for ratification by the United States Senate. However, the Bush administration has committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. AtAlso, in an April 16, 2008 speech, President Bush set a policy goal of stopping the international level, efforts have begun to develop climate change agreements for post-2012growth of GHG reductions. Theemissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States.States, and the Senate Environmental and Public Works Committees have passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the Clean Air Act.CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the Clean Air ActCAA to regulate “air pollutants” from those and other facilities. Also on April 2, 2007, the United States Supreme Court ruled that changes in annual emissions (in tons/year) rather than changes in hourly emissions rate (in kilograms/hour) must be used to determine whether an emissions increase triggers NSR. Subsequently, the EPA proposed to change the NSR regulations, on May 8, 2007, to utilize changes in the hourly emission rate (in kilograms/hour) to determine whether an emissions increase triggers NSR.
FESFirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FESFirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act(Applicable to FES)
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FES'FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FES'FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality when(when aquatic organisms are pinned against screens or other parts of a cooling water intake system,system) and entrainment which(which occurs when aquatic life is drawn into a facility's cooling water system.system). On January 26, 2007, the federalUnited States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment (BPJ) to minimize impacts on fish and shellfish from cooling water intake structures. FESOn April 14, 2008, the Supreme Court of the United States granted a petition for a writ of certiorari to review certain aspects of the Second Circuit’s decision. FirstEnergy is evaluatingstudying various control options and their costs and effectiveness. Depending on the outcomeresults of such studies, the outcome of the Supreme Court’s review of the Second Circuit’s decision, the EPA’s further rulemaking and any action taken by the states exercising BPJ, the future costcosts of compliance with these standards may require material capital expenditures.
Regulation of Hazardous Waste(Applicable to FES and each of the Companies)
As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate nonhazardousnon-hazardous waste.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of September 30, 2007,March 31, 2008, FirstEnergy had approximately $1.5$2.0 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and Perry.TMI-2. As part of the application to the NRC to transfer the ownership of these nuclear facilitiesDavis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any rate of return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy plans(and Exelon for TMI-1 as it relates to seekthe timing of the decommissioning of TMI-2) seeks for these facilities.
The Companies have been named as PRPs at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all PRPs for a particular site aremay be liable on a joint and several basis. Therefore, environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of September 30, 2007,March 31, 2008, based on estimates of the total costs of cleanup, the Companies' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. In addition, JCP&L has accrued liabilities for environmental remediation of former manufactured gas plants in New Jersey; those costs are being recovered by JCP&L through a non-bypassable SBC. Total liabilities of approximately $89$92 million (JCP&L - $60$65 million, TE - $3$1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through September 30, 2007.March 31, 2008. Included in the total for JCP&L are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants in New Jersey; which are being recovered by JCP&L through a non-bypassable SBC.
Other Legal Proceedings(C) OTHER LEGAL PROCEEDINGS
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other material items not otherwise discussed above are described below.
Power Outages and Related Litigation(Applicable to FES and each of the Companies)
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
In August 2002, the trial court granted partial summary judgment to JCP&L and dismissed the plaintiffs' claims for consumer fraud, common law fraud, negligent misrepresentation, and strict product liability. In November 2003, the trial court granted JCP&L's motion to decertify the class and denied plaintiffs' motion to permit into evidence their class-wide damage model indicating damages in excess of $50 million. These class decertification and damage rulings were appealed to the Appellate Division. The Appellate Division issued a decision in July 2004, affirming the decertification of the originally certified class, but remanding for certification of a class limited to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation resulting in planned and unplanned outages in the area during a 2-3 day period. In 2005, JCP&L renewed its motion to decertify the class based on a very limited number of class members who incurred damages and also filed a motion for summary judgment on the remaining plaintiffs’ claims for negligence, breach of contract and punitive damages. In July 2006, the New Jersey Superior Court dismissed the punitive damage claim and again decertified the class based on the fact that a vast majority of the class members did not suffer damages and those that did would be more appropriately addressed in individual actions. Plaintiffs appealed this ruling to the New Jersey Appellate Division which, in March 2007, reversed the decertification of the Red Bank class and remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. JCP&L filed a petition for allowance of an appeal of the Appellate Division ruling to the New Jersey Supreme Court which was denied in May 2007. Proceedings are continuing in the Superior Court.Court and a case management conference with the presiding Judge is scheduled for June 13, 2008. FirstEnergy is defending this class action but is unable to predict the outcome of this matter. No liability has been accrued as of September 30, 2007.March 31, 2008.
On August 14, 2003, various states and parts of southern Canada experienced widespread power outages. The outages affected approximately 1.4 million customers in FirstEnergy's service area. The U.S. – Canada Power System Outage Task Force’s final report in April 2004 on the outages concluded, among other things, that the problems leading to the outages began in FirstEnergy’s Ohio service area. Specifically, the final report concluded, among other things, that the initiation of the August 14, 2003 power outages resulted from an alleged failure of both FirstEnergy and ECAR to assess and understand perceived inadequacies within the FirstEnergy system; inadequate situational awareness of the developing conditions; and a perceived failure to adequately manage tree growth in certain transmission rights of way. The Task Force also concluded that there was a failure of the interconnected grid's reliability organizations (MISO and PJM) to provide effective real-time diagnostic support. The final report is publicly available through the Department of Energy’s Web site (www.doe.gov). FirstEnergy believes that the final report does not provide a complete and comprehensive picture of the conditions that contributed to the August 14, 2003 power outages and that it does not adequately address the underlying causes of the outages. FirstEnergy remains convinced that the outages cannot be explained by events on any one utility's system. The final report contained 46 “recommendations to prevent or minimize the scope of future blackouts.” Forty-five of those recommendations related to broad industry or policy matters while one, including subparts, related to activities the Task Force recommended be undertaken by FirstEnergy, MISO, PJM, ECAR, and other parties to correct the causes of the August 14, 2003 power outages. FirstEnergy implemented several initiatives, both prior to and since the August 14, 2003 power outages, which were independently verified by NERC as complete in 2004 and were consistent with these and other recommendations and collectively enhance the reliability of its electric system. FirstEnergy’s implementation of these recommendations in 2004 included completion of the Task Force recommendations that were directed toward FirstEnergy. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.
FirstEnergy companies also are defending four separate complaint cases before the PUCO relating to the August 14, 2003 power outages. Two of those cases were originally filed in Ohio State courts but were subsequently dismissed for lack of subject matter jurisdiction and further appeals were unsuccessful. In these cases the individual complainants—three in one case and four in the other—sought to represent others as part of a class action. The PUCO dismissed the class allegations, stating that its rules of practice do not provide for class action complaints. Two other pending PUCO complaint cases were filed by various insurance carriers either in their own name as subrogees or in the name of their insured. In each of these cases, the carrier seeks reimbursement from various FirstEnergy companies (and, in one case, from PJM, MISO and AEP, as well) for claims paid to insureds for damages allegedly arising as a result of the loss of power on August 14, 2003. A fifth case in which a carrier sought reimbursement for claims paid to insureds was voluntarily dismissed by the claimant in April 2007. A sixth case involving the claim of a non-customer seeking reimbursement for losses incurred when its store was burglarized on August 14, 2003 was dismissed. The four cases remaining were consolidated for hearing by the PUCO in an order dated March 7, 2006. In that order the PUCO also limited the litigation to service-related claims by customers of the Ohio operating companies; dismissed FirstEnergy as a defendant; and ruled that the U.S.-Canada Power System Outage Task Force Report was not admissible into evidence. In response to a motion for rehearing filed by one of the claimants, the PUCO ruled on April 26, 2006 that the insurance company claimants, as insurers, may prosecute their claims in their name so long as they also identify the underlying insured entities and the Ohio utilities that provide their service. The PUCO denied all other motions for rehearing. The plaintiffs in each case have since filed amended complaints and the named FirstEnergy companies have answered and also have filed a motion to dismiss each action. On September 27, 2006, the PUCO dismissed certain parties and claims and otherwise ordered the complaints to go forward to hearing. The cases have been set for hearing on January 8, 2008.
FirstEnergy is defending these actions, but cannot predict the outcome of any of these proceedings or whether any further regulatory proceedings or legal actions may be initiated against the Companies. Although FirstEnergy is unable to predict the impact of these proceedings, if FirstEnergy or its subsidiaries were ultimately determined to have legal liability in connection with these proceedings, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
Nuclear Plant Matters(Applicable to FES)
On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for InformationDFI to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information, about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for InformationDFI reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. The NRC heldFENOC submitted a public meeting on June 27, 2007 with FENOC to discuss FENOC’ssupplemental response to the Demand for Information. In follow-up discussions, FENOC was requested to provide supplemental information to clarifyclarifying certain aspects of the Demand for Information response and provide additional details regarding plans to implement the commitments made therein. FENOC submitted this supplementalDFI response to the NRC on July 16, 2007. On August 15, 2007, the NRC issued a confirmatory order imposing these commitments. FENOC must inform the NRC’s Office of Enforcement after it completes the key commitments embodied in the NRC’s order. FENOC’s compliance with these commitments is subject to future NRC review.
Other Legal Matters(Applicable
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to OEFirstEnergy's normal business operations pending against FirstEnergy and JCP&L)its subsidiaries. The other potentially material items not otherwise discussed above are described below.
On August 22, 2005, a class action complaint was filed against OE in Jefferson County, Ohio Common Pleas Court, seeking compensatory and punitive damages to be determined at trial based on claims of negligence and eight other tort counts alleging damages from W.H. Sammis Plant air emissions. The two named plaintiffs are also seeking injunctive relief to eliminate harmful emissions and repair property damage and the institution of a medical monitoring program for class members. On April 5, 2007, the Court rejected the plaintiffs’ request to certify this case as a class action and, accordingly, did not appoint the plaintiffs as class representatives or their counsel as class counsel. On July 30, 2007, plaintiffs’ counsel voluntarily withdrew their request for reconsideration of the April 5, 2007 Court order denying class certification and the Court heard oral argument on the plaintiffs’ motion to amend their complaint which OE has opposed. On August 2, 2007, the Court denied the plaintiffs’ motion to amend their complaint. The plaintiffs have appealed the Court’s denial of the motion for certification as a class action and motion to amend their complaint.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. At the conclusion of the June 1, 2005 hearing, the arbitration panel decided not to hear testimony on damages and closed the proceedings. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. On February 6, 2006, a federal district court granted a union motion to dismiss, as premature, a JCP&L appeal of the award filed on October 18, 2005. The arbitration panel provided additional rulings regarding damages during a September 2007 hearing and it is anticipated that he will issue aA final order in lateidentifying the individual damage amounts was issued on October 31, 2007. The award appeal process was initiated. The union filed a motion with the federal court to confirm the award and JCP&L intendsfiled its answer and counterclaim to re-file an appeal againvacate the award on December 31, 2007. The court held a scheduling conference in federal district court once the damages associatedApril 2008 where it set a briefing schedule with this case are identified at an individual employee level.all briefs to be concluded by July 2008. JCP&L recognized a liability for the potential $16 million award in 2005.
The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan ready in the event of a strike.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows.
New Accounting Standards and Interpretations(Applicable to FES and each of the Companies)
11. REGULATORY MATTERS
SFAS 157 – “Fair Value Measurements”(A) RELIABILITY INITIATIVES
In Septemberlate 2003 and early 2004, a series of letters, reports and recommendations were issued from various entities, including governmental, industry and ad hoc reliability entities (PUCO, FERC, NERC and the U.S. – Canada Power System Outage Task Force) regarding enhancements to regional reliability. The proposed enhancements were divided into two groups: enhancements that were to be completed in 2004; and enhancements that were to be completed after 2004. In 2004, FirstEnergy completed all of the enhancements that were recommended for completion in 2004. FirstEnergy is also proceeding with the implementation of the recommendations that were to be completed subsequent to 2004 and will continue to periodically assess the FERC-ordered Reliability Study recommendations for forecasted 2009 system conditions, recognizing revised load forecasts and other changing system conditions which may impact the recommendations. Thus far, implementation of the recommendations has not required, nor is expected to require, substantial investment in new or material upgrades to existing equipment. The FERC or other applicable government agencies and reliability coordinators may, however, take a different view as to recommended enhancements or may recommend additional enhancements in the future that could require additional material expenditures.
As a result of outages experienced in JCP&L’s service area in 2002 and 2003, the NJBPU performed a review of JCP&L’s service reliability. On June 9, 2004, the NJBPU approved a stipulation that addresses a third-party consultant’s recommendations on appropriate courses of action necessary to ensure system-wide reliability. The stipulation incorporates the consultant’s focused audit of, and recommendations regarding, JCP&L’s Planning and Operations and Maintenance programs and practices. On June 1, 2005, the consultant completed his work and issued his final report to the NJBPU. On July 14, 2006, JCP&L filed a comprehensive response to the FASB issued SFAS 157consultant’s report with the NJBPU. JCP&L will complete the remaining substantive work described in the stipulation in 2008. JCP&L continues to file compliance reports with the NJBPU reflecting JCP&L’s activities associated with implementing the stipulation.
In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Companies and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including the ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.
FirstEnergy believes that establishes how companies should measure fair value when they are requiredit is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that NERC, ReliabilityFirst and the FERC will continue to use a fair value measure for recognition or disclosure purposes under GAAP. This Statement addresses the need for increased consistency and comparability in fair value measurements and for expanded disclosures about fair value measurements. The key changes to current practice are: (1) the definition of fair value which focuses on an exit price rather than entry price; (2) the methods used to measure fair value such as emphasis that fair value is a market-based measurement, not an entity-specific measurement,refine existing reliability standards as well as the inclusion of an adjustment for risk, restrictionsto develop and credit standing; and (3) the expanded disclosures about fair value measurements. This Statement is effective foradopt new reliability standards. The financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. FES and the Companies are currently evaluating the impact of complying with new or amended standards cannot be determined at this Statementtime. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on theirFirstEnergy’s part to comply with the reliability standards for its bulk power system could have a material adverse effect on its financial statements.condition, results of operations and cash flows.
In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, ReliabilityFirst has scheduled a compliance audit of FirstEnergy’s bulk-power system within the PJM region in 2008. FirstEnergy currently does not expect any material adverse financial impact as a result of these audits.
(B) OHIO
On January 4, 2006, the PUCO issued an order authorizing the Ohio Companies to recover certain increased fuel costs through a fuel rider and to defer certain other increased fuel costs to be incurred from January 1, 2006 through December 31, 2008, including interest on the deferred balances. The order also provided for recovery of the deferred costs over a twenty-five-year period through distribution rates. On August 29, 2007, the Supreme Court of Ohio concluded that the PUCO violated a provision of the Ohio Revised Code by permitting the Ohio Companies “to collect deferred increased fuel costs through future distribution rate cases, or to alternatively use excess fuel-cost recovery to reduce deferred distribution-related expenses” and remanded the matter to the PUCO for further consideration. On September 10, 2007 the Ohio Companies filed an application with the PUCO that requested the implementation of two generation-related fuel cost riders to collect the increased fuel costs that were previously authorized to be deferred. On January 9, 2008 the PUCO approved the Ohio Companies’ proposed fuel cost rider to recover increased fuel costs to be incurred in 2008 commencing January 1, 2008 through December 31, 2008, which is expected to be approximately $189 million. In addition, the PUCO ordered the Ohio Companies to file a separate application for an alternate recovery mechanism to collect the 2006 and 2007 deferred fuel costs. On February 8, 2008, the Ohio Companies filed an application proposing to recover $226 million of deferred fuel costs and carrying charges for 2006 and 2007 pursuant to a separate fuel rider, with alternative options for the recovery period ranging from five to twenty-five years. This second application is currently pending before the PUCO and a hearing has been set for July 15, 2008.
The Ohio Companies filed an application and rate request for an increase in electric distribution rates with the PUCO on June 7, 2007. The requested increase is expected to be more than offset by the elimination or reduction of transition charges at the time the rates go into effect and would result in lowering the overall non-generation portion of the average electric bill for most Ohio customers. The distribution rate increases reflect capital expenditures since the Ohio Companies’ last distribution rate proceedings, increases in operation and maintenance expenses and recovery of regulatory assets that were authorized in prior cases. On August 6, 2007, the Ohio Companies updated their filing supporting a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of their investigation into the distribution rate request. In its reports, the PUCO Staff recommended a distribution rate increase in the range of $161 million to $180 million, with $108 million to $127 million for distribution revenue increases and $53 million for recovery of costs deferred under prior cases. This amount excludes the recovery of deferred fuel costs, whose recovery is now being sought in a separate proceeding before the PUCO, discussed above. On January 3, 2008, the Ohio Companies and intervening parties filed objections to the Staff Reports and on January 10, 2008, the Ohio Companies filed supplemental testimony. Evidentiary hearings began on January 29, 2008 and continued through February 25, 2008. During the evidentiary hearings, the PUCO Staff submitted testimony decreasing their recommended revenue increase to a range of $114 million to $132 million. Additionally, in testimony submitted on February 11, 2008, the PUCO Staff adopted a position regarding interest deferred for RCP-related deferrals, line extension deferrals and transition tax deferrals that, if upheld by the PUCO, would result in the write-off of approximately $45 million of interest costs deferred through March 31, 2008 ($0.09 per share of common stock). The PUCO is expected to render its decision during the second or third quarter of 2008. The new rates would become effective January 1, 2009 for OE and TE, and approximately May 2009 for CEI.
On July 10, 2007, the Ohio Companies filed an application with the PUCO requesting approval of a comprehensive supply plan for providing retail generation service to customers who do not purchase electricity from an alternative supplier, beginning January 1, 2009. The proposed competitive bidding process would average the results of multiple bidding sessions conducted at different times during the year. The final price per KWH would reflect an average of the prices resulting from all bids. In their filing, the Ohio Companies offered two alternatives for structuring the bids, either by customer class or a “slice-of-system” approach. A slice-of-system approach would require the successful bidder to be responsible for supplying a fixed percentage of the utility’s total load notwithstanding the customer’s classification. The proposal provides the PUCO with an option to phase in generation price increases for residential tariff groups who would experience a change in their average total price of 15 percent or more. The PUCO held a technical conference on August 16, 2007 regarding the filing. Initial and reply comments on the proposal were filed by various parties in September and October 2007, respectively. The proposal is currently pending before the PUCO.
On April 22, 2008, an amended version of Substitute SB221 was passed by the Ohio House of Representatives and sent back to the Ohio Senate for concurrence. On April 23, 2008, the Ohio Senate approved the House's amendments to Substitute SB221 and forwarded the bill to the Governor for signature, which he signed on May 1, 2008. Amended Substitute SB221 requires all electric distribution utilities to file an RSP, now called an ESP, with the PUCO. An ESP is required to contain a proposal for the supply and pricing of retail generation and may include proposals, without limitation, related to one or more of the following:
· | automatic recovery of prudently incurred fuel, purchased power, emission allowance costs and federally mandated energy taxes; |
SFAS 159 – “The Fair Value Option· | construction work in progress for Financial Assetscosts of constructing an electric generating facility or environmental expenditure for any electric generating facility; |
· | costs of an electric generating facility; |
· | terms related to customer shopping, bypassability, standby, back-up and Financial Liabilities – Including an amendmentdefault service; |
· | accounting for deferrals related to stabilizing retail electric service; |
· | automatic increases or decreases in standard service offer price; |
· | phase-in and securitization; |
· | transmission service and related costs; |
· | distribution service and related costs; and |
· | economic development and energy efficiency. |
A utility could also simultaneously file an MRO in which it would have to demonstrate the following objective market criteria: The utility or its transmission service affiliate belongs to a FERC-approved RTO having a market-monitor function and the ability to mitigate market power, and a published source exists that identifies information for traded electricity and energy products that are contracted for delivery two years into the future. The PUCO would test the ESP and its pricing and all other terms and conditions against the MRO and may only approve the ESP if it is found to be more favorable to customers. As part of an ESP with a plan period longer than three years, the PUCO shall prospectively determine every fourth year of the plan whether it is substantially likely the plan will provide the electric distribution utility a return on common equity significantly in excess of the return likely to be earned by publicly traded companies, including utilities, that face comparable business and financial risk (comparable companies). If so, the PUCO may terminate the ESP. Annually under an ESP, the PUCO shall determine whether an electric distribution utility's earned return on common equity is significantly in excess of returns earned on common equity during the same period by comparable companies, and if so, shall require the utility to return such excess to customers by prospective adjustments. Amended Substitute SB221 also includes provisions dealing with advanced and renewable energy standards that contemplate 25% of electrical usage from these sources by 2025. Energy efficiency measures in the bill require energy savings in excess of 22% by 2025. Requirements are in place to meet annual benchmarks for renewable energy resources and energy efficiency, subject to review by the PUCO. FirstEnergy is currently evaluating this legislation and expects to file an ESP in the second or third quarter of 2008.
(C) PENNSYLVANIA
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. The fixed price under the agreement is expected to remain below wholesale market prices during the term of the agreement. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. Based on the PPUC’s January 11, 2007 order described below, if FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC.
Met-Ed and Penelec made a comprehensive transition rate filing with the PPUC on April 10, 2006 to address a number of transmission, distribution and supply issues. If Met-Ed's and Penelec's preferred approach involving accounting deferrals had been approved, annual revenues would have increased by $216 million and $157 million, respectively. That filing included, among other things, a request to charge customers for an increasing amount of market-priced power procured through a CBP as the amount of supply provided under the then existing FES agreement was to be phased out. Met-Ed and Penelec also requested approval of a January 12, 2005 petition for the deferral of transmission-related costs incurred during 2006. In this rate filing, Met-Ed and Penelec requested recovery of annual transmission and related costs incurred on or after January 1, 2007, plus the amortized portion of 2006 costs over a ten-year period, along with applicable carrying charges, through an adjustable rider. Changes in the recovery of NUG expenses and the recovery of Met-Ed's non-NUG stranded costs were also included in the filing. On May 4, 2006, the PPUC consolidated the remand of the FirstEnergy and GPU merger proceeding, related to the quantification and allocation of merger savings, with the comprehensive transition rate filing case.
The PPUC entered its opinion and order in the comprehensive rate filing proceeding on January 11, 2007. The order approved the recovery of transmission costs, including the transmission-related deferral for January 1, 2006 through January 10, 2007, and determined that no merger savings from prior years should be considered in determining customers’ rates. The request for increases in generation supply rates was denied as were the requested changes to NUG expense recovery and Met-Ed’s non-NUG stranded costs. The order decreased Met-Ed’s and Penelec’s distribution rates by $80 million and $19 million, respectively. These decreases were offset by the increases allowed for the recovery of transmission costs. Met-Ed’s and Penelec’s request for recovery of Saxton decommissioning costs was granted and, in January 2007, Met-Ed and Penelec recognized income of $15 million and $12 million, respectively, to establish regulatory assets for those previously expensed decommissioning costs. Overall rates increased by 5.0% for Met-Ed ($59 million) and 4.5% for Penelec ($50 million).
On March 30, 2007, MEIUG and PICA filed a Petition for Review with the Commonwealth Court of Pennsylvania asking the court to review the PPUC’s determination on transmission (including congestion) and the transmission deferral. Met-Ed and Penelec filed a Petition for Review on April 13, 2007 on the issues of consolidated tax savings and the requested generation rate increase. The OCA filed its Petition for Review on April 13, 2007, on the issues of transmission (including congestion) and recovery of universal service costs from only the residential rate class. From June through October 2007, initial responsive and reply briefs were filed by various parties. Oral arguments are scheduled to take place in September 2008. If Met-Ed and Penelec do not prevail on the issue of congestion, it could have a material adverse effect on the results of operations of Met-Ed, Penelec and FirstEnergy.
On April 14, 2008, Met-Ed and Penelec filed annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The proposed TSCs include a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed has proposed a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.
On March 13, 2008, the PPUC approved the residential procurement process in Penn’s Joint Petition for Settlement. This RFP process calls for load-following, full-requirements contracts for default service procurement for residential customers for the period covering June 1, 2008 through May 31, 2011. The PPUC had previously approved the default service procurement processes for commercial and industrial customers. The default service procurement for small commercial customers was conducted through multiple RFPs, while the default service procurement for large commercial and industrial customers will utilize hourly pricing. Bids in the two RFPs for small commercial load were approved by the PPUC on February 22, 2008, and March 20, 2008. On March 28, 2008, Penn filed compliance tariffs with the new default service generation rates based on the approved RFP bids for small commercial customers which the PPUC then certified on April 4, 2008. On April 14, 2008, the first RFP for residential customers’ load was held consisting of tranches for both 12 and 24-month supply. The PPUC approved the bids on April 16, 2008. The second RFP is scheduled to be held on May 14, 2008, after which time the PPUC is expected to approve the new rates to go into effect June 1, 2008.
On February 1, 2007, the Governor of Pennsylvania proposed an EIS. The EIS includes four pieces of proposed legislation that, according to the Governor, is designed to reduce energy costs, promote energy independence and stimulate the economy. Elements of the EIS include the installation of smart meters, funding for solar panels on residences and small businesses, conservation and demand reduction programs to meet energy growth, a requirement that electric distribution companies acquire power that results in the “lowest reasonable rate on a long-term basis,” the utilization of micro-grids and a three year phase-in of rate increases. On July 17, 2007 the Governor signed into law two pieces of energy legislation. The first amended the Alternative Energy Portfolio Standards Act of 2004 to, among other things, increase the percentage of solar energy that must be supplied at the conclusion of an electric distribution company’s transition period. The second law allows electric distribution companies, at their sole discretion, to enter into long term contracts with large customers and to build or acquire interests in electric generation facilities specifically to supply long-term contracts with such customers. A special legislative session on energy was convened in mid-September 2007 to consider other aspects of the EIS. The Pennsylvania House and Senate on March 11, 2008 and December 12, 2007, respectively, passed different versions of bills to fund the Governor’s EIS proposal. Neither chamber has formally considered the other’s bill. On February 12, 2008, the Pennsylvania House passed House Bill 2200 which provides for energy efficiency and demand management programs and targets as well as the installation of smart meters within ten years. Other legislation has been introduced to address generation procurement, expiration of rate caps, conservation and renewable energy. The final form of this pending legislation is uncertain. Consequently, FirstEnergy is unable to predict what impact, if any, such legislation may have on its operations.
(D) NEW JERSEY
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2008, the accumulated deferred cost balance totaled approximately $264 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004 supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DRA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. With the approval of the NJBPU Staff, the affected utilities jointly submitted an alternative proposal on June 1, 2006. The NJBPU Staff circulated revised drafts of the proposal to interested stakeholders in November 2006 and again in February 2007. On February 1, 2008, the NJBPU accepted proposed rules for publication in the New Jersey Register on March 17, 2008. A public hearing on these proposed rules was held on April 23, 2008 with comments from interested parties due on May 16, 2008.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. In October 2006, the current EMP process was initiated through the creation of a number of working groups to obtain input from a broad range of interested stakeholders including utilities, environmental groups, customer groups, and major customers. In addition, public stakeholder meetings were held in the fall of 2006 and in early 2007.
On April 17, 2008, a draft EMP was released for public comment. The draft EMP establishes four major goals:
· | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
· | reduce peak demand for electricity by 5,700 MW by 2020 (amounting to about a 22% reduction in projected demand); |
· | meet 22.5% of FASB Statement No. 115”the state’s electricity needs with renewable energy by 2020; and |
· | develop low carbon emitting, efficient power plants and close the gap between the supply and demand for electricity. |
Following the public comment period which is expected to extend into July 2008, a final EMP will be issued to be followed by appropriate legislation and regulation as necessary. At this time, FirstEnergy cannot predict the outcome of this process nor determine the impact, if any, such legislation or regulation may have on its operations or those of JCP&L.
On February 13, 2007, the NJBPU Staff informally issued a draft proposal relating to changes to the regulations addressing electric distribution service reliability and quality standards. Meetings between the NJBPU Staff and interested stakeholders to discuss the proposal were held and additional, revised informal proposals were subsequently circulated by the Staff. On September 4, 2007, proposed regulations were published in the New Jersey Register, which proposal will be subsequently considered by the NJBPU following comments that were submitted in September and October 2007. Final regulations (effective upon publication) were published in the New Jersey Register March 17, 2008. Upon preliminary review of the new regulations, FirstEnergy does not expect a material impact on its operations or those of JCP&L.
(E) FERC MATTERS
Transmission Service between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate so-called “pancaking” of transmission charges between the MISO and PJM regions. The FERC also ordered the MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or “SECA”) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order could be issued by the FERC in the second quarter of 2008.
PJM Transmission Rate Design
On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce future transmission revenue recovery from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge. The FERC’s action on the settlement agreement is pending. The remaining merchant transmission cost allocation issues will proceed to hearing in May 2008. On February 13, 2008, AEP appealed the FERC’s orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit.
Post Transition Period Rate Design
The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.
On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. A rehearing request by AEP is pending before the FERC.
Distribution of MISO Network Service Revenues
Effective February 1, 2008, the MISO Transmission Owners Agreement provides for a change in the method of distributing transmission revenues among the transmission owners. MISO and a majority of the MISO transmission owners filed on December 3, 2007 to change the MISO tariff to clarify, for purposes of distributing network transmission revenue to the transmission owners, that all network transmission service revenues, whether collected by MISO or directly by the transmission owner, are included in the revenue distribution calculation. This clarification was necessary because some network transmission service revenues are collected and retained by transmission owners in states where retail choice does not exist, and their “unbundled” retail load is currently exempt from MISO network service charges. The tariff changes filed with the FERC ensure that revenues collected by transmission owners from bundled load are taken into account in the revenue distribution calculation, and that transmission owners with bundled load do not collect more than their revenue requirements. Absent the changes, transmission owners, and ultimately their customers, with unbundled load or in retail choice states, such as ATSI, would subsidize transmission owners with bundled load, who would collect their revenue requirement from bundled load, plus share in revenues collected by MISO from unbundled customers. This would result in a large revenue shortfall for ATSI, which would eventually be passed on to customers in the form of higher transmission rates as calculated pursuant to ATSI’s Attachment O formula under the MISO tariff.
Numerous parties filed in support of the tariff changes, including the public service commissions of Michigan, Ohio and Wisconsin. Ameren filed a protest on December 26, 2007, arguing that the December 3, 2007 filing violates the MISO Transmission Owners’ Agreement as well as an agreement among Ameren (Union Electric), MISO, and the Missouri Public Service Commission, which provides that Union Electric’s bundled load cannot be charged by MISO for network service. On February 2, 2008, the FERC issued an order conditionally accepting the tariff amendment subject to a minor compliance filing, which was made on March 3, 2008. This order ensures that ATSI will continue to receive transmission revenues from MISO equivalent to its transmission revenue requirement. A rehearing request by Ameren is pending before the FERC.
On February 1, 2008, MISO filed a request to continue using the existing revenue distribution methodology on an interim basis pending amendment of the MISO Transmission Owners’ Agreement. This request was accepted by the FERC on March 13, 2008. On that same day, MISO and the MISO transmission owners made a filing to amend the Transmission Owners’ Agreement to effectively continue the distribution of transmission revenues that was in effect prior to February 1, 2008. This matter is currently pending before the FERC.
MISO Ancillary Services Market and Balancing Area Consolidation
MISO made a filing on September 14, 2007 to establish an ASM for regulation, spinning and supplemental reserves, to consolidate the existing 24 balancing areas within the MISO footprint, and to establish MISO as the NERC registered balancing authority for the region. This filing would permit load serving entities to purchase their operating reserve requirements in a competitive market. FirstEnergy supports the proposal to establish markets for Ancillary Services and consolidate existing balancing areas. On February 25, 2008, the FERC issued an order approving the ASM subject to certain compliance filings. MISO has since notified the FERC that the start of its ASM is delayed until September of 2008.
Duquesne’s Request to Withdraw from PJM
On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join the MISO. In its filing, Duquesne asked the FERC to be relieved of certain capacity payment obligations to PJM for capacity auctions conducted prior to its departure from PJM, but covering service for planning periods through May 31, 2011. Duquesne asserted that its primary reason for exiting PJM is to avoid paying future obligations created by PJM’s forward capacity market. FirstEnergy believes that Duquesne’s filing did not identify or address numerous legal, financial or operational issues that are implicated or affected directly by Duquesne’s proposal. Consequently, FirstEnergy submitted responsive filings that, while conceding Duquesne’s rights to exit PJM, contested various aspects of Duquesne’s proposal. FirstEnergy particularly focused on Duquesne’s proposal that it be allowed to exit PJM without payment of its share of existing capacity market commitments. FirstEnergy also objected to Duquesne’s failure to address the firm transmission service requirements that would be necessary for FirstEnergy to continue to use the Beaver Valley Plant to meet existing commitments in the PJM capacity markets and to serve native load. Other market participants also submitted filings contesting Duquesne’s plans.
On January 17, 2008, the FERC conditionally approved Duquesne’s request to exit PJM. Among other conditions, the FERC obligated Duquesne to pay the PJM capacity obligations through May 31, 2011. The FERC’s order took notice of the numerous transmission and other issues raised by FirstEnergy and other parties to the proceeding, but did not provide any responsive rulings or other guidance. Rather, the FERC ordered Duquesne to make a compliance filing in forty-five days detailing how Duquesne will satisfy its obligations under the PJM Transmission Owners’ Agreement. The FERC likewise directed the MISO to submit detailed plans to integrate Duquesne into the MISO. Finally, the FERC directed MISO and PJM to work together to resolve the substantive and procedural issues implicated by Duquesne’s transition into the MISO. These issues remain unresolved. If Duquesne satisfies all of the obligations set by the FERC, its planned transition date is October 9, 2008.
On March 18, 2008, the PJM Power Providers Group filed a request for emergency clarification regarding whether Duquesne-zone generators (including the Beaver Valley Plant) could participate in PJM’s May 2008 auction for the 2011-2012 RPM delivery year. FirstEnergy and the other Duquesne-zone generators filed responsive pleadings. On April 18, 2008, the FERC issued its Order on Motion for Emergency Clarification, wherein the FERC ruled that although the status of the Duquesne-zone generators will change to “External Resource” upon Duquesne’s exit from PJM, these generators can contract with PJM for the transmission reservations necessary to participate in the May 2008 auction. FirstEnergy has complied with FERC’s order by obtaining executed transmission service agreements for firm point-to-point transmission service for the 2011-2012 delivery year and, as such, FirstEnergy satisfies the criteria to bid the Beaver Valley Plant into the May 2008 RPM auction. Notwithstanding these events, on April 30, 2008 and May 1, 2008, certain members of the PJM Power Providers Group filed further pleadings on these issues. On May 2, 2008, FirstEnergy filed a responsive pleading. FirstEnergy is participating in the May 2008 RPM auction for the 2011-2012 RPM delivery year.
MISO Resource Adequacy Proposal
MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load serving entities in its state. FirstEnergy generally supports the proposal as it promotes a mechanism that will result in long-term commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were filed on January 28, 2008. The FERC approved MISO’s Resource Adequacy proposal on March 26, 2008. Rehearing requests are pending on the FERC’s March 26 Order. A compliance filing establishing the enforcement mechanism for the reserve margin requirement is due on or before June 25, 2008.
Organized Wholesale Power Markets
On February 21, 2008, the FERC issued a NOPR through which it proposes to adopt new rules that it states will “improve operations in organized electric markets, boost competition and bring additional benefits to consumers.” The proposed rule addresses demand response and market pricing during reserve shortages, long-term power contracting, market-monitoring policies, and responsiveness of RTOs and ISOs to stakeholders and customers. FirstEnergy does not believe that the proposed rule will have a significant impact on its operations. Comments on the NOPR were filed on April 18, 2008.
12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS |
SFAS 141(R) – “Business Combinations”
In FebruaryDecember 2007, the FASB issued SFAS 159,141(R), which provides companies with an optionrequires the acquiring entity in a business combination to report selected financialrecognize all the assets acquired and liabilities atassumed in the transaction; establishes the acquisition-date fair value. This Statementvalue as the measurement objective for all assets acquired and liabilities assumed; and requires companiesthe acquirer to provide additional information that will helpdisclose to investors and other users all of financial statementsthe information they need to more easilyevaluate and understand the nature and financial effect of the company’s choicebusiness combination. SFAS 141(R) attempts to use fair valuereduce the complexity of existing GAAP related to business combinations. The Standard includes both core principles and pertinent application guidance, eliminating the need for numerous EITF issues and other interpretative guidance. SFAS 141(R) will affect business combinations entered into by FirstEnergy that close after January 1, 2009. In addition, the Standard also affects the accounting for changes in tax valuation allowances made after January 1, 2009, that were established as part of a business combination prior to the implementation of this Standard. FirstEnergy is currently evaluating the impact of adopting this Standard on its earnings. The Standard also requires companies to displayfinancial statements.
SFAS 160 - “Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51”
In December 2007, the fair valueFASB issued SFAS 160 that establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of those assets and liabilities for whicha subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the company has chosen to use fair value onconsolidated entity that should be reported as equity in the face of the balance sheet. This guidance does not eliminate disclosure requirements included in other accounting standards, including requirements for disclosures about fair value measurements included in SFAS 157and SFAS 107. consolidated financial statements. This Statement is effective for financial statements issued for fiscal years, beginning after November 15, 2007, and interim periods within those years. FES and the Companies are currently evaluating the impact of this Statement on their financial statements.
EITF 06-11 – “Accounting for Income Tax Benefits of Dividends or Share-based Payment Awards”
In June 2007, the FASB released EITF 06-11, which provides guidance on the appropriate accounting for income tax benefits related to dividends earned on nonvested share units that are charged to retained earnings under SFAS 123(R). The consensus requires that an entity recognize the realized tax benefit associated with the dividends on nonvested shares as an increase to additional paid-in capital (APIC). This amount should be included in the APIC pool, which is to be used when an entity’s estimate of forfeitures increases or actual forfeitures exceed its estimates, at which time the tax benefits in the APIC pool would be reclassified to the income statement. The consensus is effective for income tax benefits of dividends declared during fiscal years, beginning on or after December 15, 2007. EITF 06-112008. Early adoption is prohibited. The Statement is not expected to have a material impact on FES’ or the Companies’FirstEnergy’s financial statements.
FSP FIN 39-1 – “Amendment of FASB Interpretation No. 39” | SFAS 161 - “Disclosures about Derivative Instruments and Hedging Activities – an Amendment of FASB Statement No. 133” |
In April 2007,March 2008, the FASB issued Staff Position (FSP) FIN 39-1,SFAS 161, which permits an entityrequires enhancements to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognizedcurrent disclosure framework for derivative instruments and hedging activities. The Statement requires that have been offset underobjectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure is intended to better convey the same master netting arrangement aspurpose of derivatives use in terms of the risks that the entity is intending to manage. The FASB believes disclosing the fair values of derivative instruments and their gains and losses in a tabular format is designed to provide a more complete picture of the location in an entity’s financial statements of both the derivative instruments. This FSPpositions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features is effective for fiscal years beginning after November 15, 2007, with early application permitted. The effectsdesigned to provide financial statement users information on the potential effect on an entity’s liquidity from using derivatives. Finally, this Statement requires cross-referencing within the footnotes, which is intended to help users of applying the guidance in this FSP should be recognized as a retrospective change in accounting principle for all financial statements presented. FES and the Companies arelocate important information about derivative instruments. FirstEnergy is currently evaluating the impact of adopting this FSPStandard on theirits financial statements but it is not expected to have a material impact.statements.
13. SEGMENT INFORMATION
FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The “Other” segment primarily consists of telecommunications services. The assets and revenues for the other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.”
The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets and default service electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.
The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electric sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from the affiliated company PSA sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment’s customers. The segment’s internal revenues represent the affiliated company PSA sales.
The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from the competitive energy services segment through full-requirements PSA arrangements, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of generation load. This segment’s total assets consist of accounts receivable for generation revenues from retail customers.
Segment Financial Information | | | | | | | | | | | | | | | | |
| | | | | | | | Ohio | | | | | | | | | | |
| | Energy | | | Competitive | | | Transitional | | | | | | | | | | |
| | Delivery | | | Energy | | | Generation | | | | | | Reconciling | | | | |
Three Months Ended | | Services | | | Services | | | Services | | | Other | | | Adjustments | | | Consolidated | |
| | (In millions) | |
March 31, 2008 | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 2,212 | | | $ | 329 | | | $ | 707 | | | $ | 40 | | | $ | (11 | ) | | $ | 3,277 | |
Internal revenues | | | - | | | | 776 | | | | - | | | | - | | | | (776 | ) | | | - | |
Total revenues | | | 2,212 | | | | 1,105 | | | | 707 | | | | 40 | | | | (787 | ) | | | 3,277 | |
Depreciation and amortization | | | 255 | | | | 53 | | | | 4 | | | | - | | | | 5 | | | | 317 | |
Investment income | | | 45 | | | | (6 | ) | | | 1 | | | | - | | | | (23 | ) | | | 17 | |
Net interest charges | | | 103 | | | | 27 | | | | - | | | | - | | | | 41 | | | | 171 | |
Income taxes | | | 119 | | | | 58 | | | | 15 | | | | 14 | | | | (19 | ) | | | 187 | |
Net income | | | 179 | | | | 87 | | | | 23 | | | | 22 | | | | (35 | ) | | | 276 | |
Total assets | | | 23,211 | | | | 8,108 | | | | 257 | | | | 281 | | | | 558 | | | | 32,415 | |
Total goodwill | | | 5,582 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,606 | |
Property additions | | | 255 | | | | 462 | | | | - | | | | 12 | | | | (18 | ) | | | 711 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
March 31, 2007 | | | | | | | | | | | | | | | | | | | | | | | | |
External revenues | | $ | 2,040 | | | $ | 321 | | | $ | 619 | | | $ | 12 | | | $ | (19 | ) | | $ | 2,973 | |
Internal revenues | | | - | | | | 714 | | | | - | | | | - | | | | (714 | ) | | | - | |
Total revenues | | | 2,040 | | | | 1,035 | | | | 619 | | | | 12 | | | | (733 | ) | | | 2,973 | |
Depreciation and amortization | | | 220 | | | | 51 | | | | (15 | ) | | | 1 | | | | 6 | | | | 263 | |
Investment income | | | 70 | | | | 3 | | | | 1 | | | | - | | | | (41 | ) | | | 33 | |
Net interest charges | | | 107 | | | | 49 | | | | 1 | | | | 2 | | | | 21 | | | | 180 | |
Income taxes | | | 148 | | | | 65 | | | | 15 | | | | 5 | | | | (33 | ) | | | 200 | |
Net income | | | 218 | | | | 98 | | | | 24 | | | | 1 | | | | (51 | ) | | | 290 | |
Total assets | | | 23,526 | | | | 7,089 | | | | 246 | | | | 254 | | | | 675 | | | | 31,790 | |
Total goodwill | | | 5,874 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,898 | |
Property additions | | | 155 | | | | 124 | | | | - | | | | 1 | | | | 16 | | | | 296 | |
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.
14. SUPPLEMENTAL GUARANTOR INFORMATION |
On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES’ lease guaranty.
The consolidating statements of income for the three months ended March 31, 2008 and 2007, consolidating balance sheets as of March 31, 2008 and December 31, 2007 and condensed consolidating statements of cash flows for the three months ended March 31, 2008 and 2007 for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING STATEMENTS OF INCOME | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
REVENUES | | $ | 1,099,848 | | | $ | 567,701 | | | $ | 325,684 | | | $ | (894,117 | ) | | $ | 1,099,116 | |
| | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
Fuel | | | 2,138 | | | | 291,239 | | | | 28,312 | | | | - | | | | 321,689 | |
Purchased power from non-affiliates | | | 206,724 | | | | - | | | | - | | | | - | | | | 206,724 | |
Purchased power from affiliates | | | 891,979 | | | | 2,138 | | | | 25,485 | | | | (894,117 | ) | | | 25,485 | |
Other operating expenses | | | 37,596 | | | | 107,167 | | | | 139,595 | | | | 12,188 | | | | 296,546 | |
Provision for depreciation | | | 307 | | | | 26,599 | | | | 24,194 | | | | (1,358 | ) | | | 49,742 | |
General taxes | | | 5,415 | | | | 11,570 | | | | 6,212 | | | | - | | | | 23,197 | |
Total expenses | | | 1,144,159 | | | | 438,713 | | | | 223,798 | | | | (883,287 | ) | | | 923,383 | |
| | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (44,311 | ) | | | 128,988 | | | | 101,886 | | | | (10,830 | ) | | | 175,733 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | |
net income from equity investees | | | 121,725 | | | | (1,208 | ) | | | (6,537 | ) | | | (116,884 | ) | | | (2,904 | ) |
Interest expense to affiliates | | | (82 | ) | | | (5,289 | ) | | | (1,839 | ) | | | - | | | | (7,210 | ) |
Interest expense - other | | | (3,978 | ) | | | (25,968 | ) | | | (11,018 | ) | | | 16,429 | | | | (24,535 | ) |
Capitalized interest | | | 21 | | | | 6,228 | | | | 414 | | | | - | | | | 6,663 | |
Total other income (expense) | | | 117,686 | | | | (26,237 | ) | | | (18,980 | ) | | | (100,455 | ) | | | (27,986 | ) |
| | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 73,375 | | | | 102,751 | | | | 82,906 | | | | (111,285 | ) | | | 147,747 | |
| | | | | | | | | | | | | | | | | | | | |
INCOME TAXES (BENEFIT) | | | (16,609 | ) | | | 39,285 | | | | 32,764 | | | | 2,323 | | | | 57,763 | |
| | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 89,984 | | | $ | 63,466 | | | $ | 50,142 | | | $ | (113,608 | ) | | $ | 89,984 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING STATEMENTS OF INCOME | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
REVENUES | | $ | 1,019,387 | | | $ | 551,355 | | | $ | 234,091 | | | $ | (786,540 | ) | | $ | 1,018,293 | |
| | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
Fuel | | | 2,367 | | | | 201,231 | | | | 29,937 | | | | - | | | | 233,535 | |
Purchased power from non-affiliates | | | 186,203 | | | | 2,367 | | | | - | | | | (2,367 | ) | | | 186,203 | |
Purchased power from affiliates | | | 784,172 | | | | 59,069 | | | | 17,415 | | | | (784,173 | ) | | | 76,483 | |
Other operating expenses | | | 51,249 | | | | 99,095 | | | | 113,252 | | | | - | | | | 263,596 | |
Provision for depreciation | | | 453 | | | | 24,936 | | | | 22,621 | | | | - | | | | 48,010 | |
General taxes | | | 4,934 | | | | 10,568 | | | | 6,216 | | | | - | | | | 21,718 | |
Total expenses | | | 1,029,378 | | | | 397,266 | | | | 189,441 | | | | (786,540 | ) | | | 829,545 | |
| | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (9,991 | ) | | | 154,089 | | | | 44,650 | | | | - | | | | 188,748 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | |
net income from equity investees | | | 113,948 | | | | 916 | | | | 5,200 | | | | (100,332 | ) | | | 19,732 | |
Interest expense to affiliates | | | - | | | | (24,331 | ) | | | (5,115 | ) | | | - | | | | (29,446 | ) |
Interest expense - other | | | (1,385 | ) | | | (6,760 | ) | | | (9,213 | ) | | | - | | | | (17,358 | ) |
Capitalized interest | | | 5 | | | | 2,099 | | | | 1,105 | | | | - | | | | 3,209 | |
Total other income (expense) | | | 112,568 | | | | (28,076 | ) | | | (8,023 | ) | | | (100,332 | ) | | | (23,863 | ) |
| | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 102,577 | | | | 126,013 | | | | 36,627 | | | | (100,332 | ) | | | 164,885 | |
| | | | | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 73 | | | | 49,289 | | | | 13,019 | | | | - | | | | 62,381 | |
| | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 102,504 | | | $ | 76,724 | | | $ | 23,608 | | | $ | (100,332 | ) | | $ | 102,504 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING BALANCE SHEETS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
As of March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
ASSETS | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
CURRENT ASSETS: | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
Receivables- | | | | | | | | | | | | | | | | | | | | |
Customers | | | 125,116 | | | | - | | | | - | | | | - | | | | 125,116 | |
Associated companies | | | 285,350 | | | | 231,049 | | | | 96,852 | | | | (295,511 | ) | | | 317,740 | |
Other | | | 1,174 | | | | 1,050 | | | | - | | | | | | | | 2,224 | |
Notes receivable from associated companies | | | 668,376 | | | | - | | | | 69,011 | | | | - | | | | 737,387 | |
Materials and supplies, at average cost | | | 2,849 | | | | 264,501 | | | | 207,275 | | | | - | | | | 474,625 | |
Prepayments and other | | | 107,798 | | | | 26,208 | | | | 1,728 | | | | - | | | | 135,734 | |
| | | 1,190,665 | | | | 522,808 | | | | 374,866 | | | | (295,511 | ) | | | 1,792,828 | |
| | | | | | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
In service | | | 35,302 | | | | 5,359,381 | | | | 3,700,973 | | | | (391,896 | ) | | | 8,703,760 | |
Less - Accumulated provision for depreciation | | | 7,810 | | | | 2,655,103 | | | | 1,537,747 | | | | (168,115 | ) | | | 4,032,545 | |
| | | 27,492 | | | | 2,704,278 | | | | 2,163,226 | | | | (223,781 | ) | | | 4,671,215 | |
Construction work in progress | | | 10,792 | | | | 881,899 | | | | 165,389 | | | | - | | | | 1,058,080 | |
| | | 38,284 | | | | 3,586,177 | | | | 2,328,615 | | | | (223,781 | ) | | | 5,729,295 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,263,338 | | | | - | | | | 1,263,338 | |
Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | |
Investment in associated companies | | | 2,598,022 | | | | - | | | | - | | | | (2,598,022 | ) | | | - | |
Other | | | 2,529 | | | | 21,657 | | | | 202 | | | | - | | | | 24,388 | |
| | | 2,600,551 | | | | 21,657 | | | | 1,326,440 | | | | (2,598,022 | ) | | | 1,350,626 | |
| | | | | | | | | | | | | | | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
Accumulated deferred income taxes | | | 10,518 | | | | 495,131 | | | | - | | | | (248,666 | ) | | | 256,983 | |
Lease assignment receivable from associated companies | | | - | | | | 67,256 | | | | - | | | | - | | | | 67,256 | |
Goodwill | | | 24,248 | | | | | | | | - | | | | - | | | | 24,248 | |
Property taxes | | | - | | | | 25,007 | | | | 22,767 | | | | - | | | | 47,774 | |
Pension assets | | | 3,214 | | | | 12,856 | | | | - | | | | - | | | | 16,070 | |
Unamortized sale and leaseback costs | | | - | | | | 38,120 | | | | - | | | | 47,575 | | | | 85,695 | |
Other | | | 18,177 | | | | 49,393 | | | | 5,188 | | | | (37,939 | ) | | | 34,819 | |
| | | 56,157 | | | | 687,763 | | | | 27,955 | | | | (239,030 | ) | | | 532,845 | |
| | $ | 3,885,657 | | | $ | 4,818,405 | | | $ | 4,057,876 | | | $ | (3,356,344 | ) | | $ | 9,405,594 | |
| | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Currently payable long-term debt | | $ | - | | | $ | 738,087 | | | $ | 887,265 | | | $ | (16,896 | ) | | $ | 1,608,456 | |
Notes payable- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | - | | | | 885,760 | | | | 260,199 | | | | - | | | | 1,145,959 | |
Other | | | 700,000 | | | | - | | | | - | | | | - | | | | 700,000 | |
Accounts payable- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | 554,844 | | | | 1,419 | | | | 119,773 | | | | (270,368 | ) | | | 405,668 | |
Other | | | 55,614 | | | | 130,090 | | | | - | | | | - | | | | 185,704 | |
Accrued taxes | | | 3,378 | | | | 116,383 | | | | 47,292 | | | | (24,219 | ) | | | 142,834 | |
Other | | | 85,100 | | | | 107,791 | | | | 9,731 | | | | 45,484 | | | | 248,106 | |
| | | 1,398,936 | | | | 1,979,530 | | | | 1,324,260 | | | | (265,999 | ) | | | 4,436,727 | |
| | | | | | | | | | | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
Common stockholder's equity | | | 2,460,215 | | | | 1,011,907 | | | | 1,579,614 | | | | (2,591,521 | ) | | | 2,460,215 | |
Long-term debt and other long-term obligations | | | - | | | | 1,320,773 | | | | 62,900 | | | | (1,305,717 | ) | | | 77,956 | |
| | | 2,460,215 | | | | 2,332,680 | | | | 1,642,514 | | | | (3,897,238 | ) | | | 2,538,171 | |
| | | | | | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,051,871 | | | | 1,051,871 | |
Accumulated deferred income taxes | | | - | | | | - | | | | 244,978 | | | | (244,978 | ) | | | - | |
Accumulated deferred investment tax credits | | | - | | | | 35,350 | | | | 24,619 | | | | - | | | | 59,969 | |
Asset retirement obligations | | | - | | | | 24,947 | | | | 798,739 | | | | - | | | | 823,686 | |
Retirement benefits | | | 9,332 | | | | 56,016 | | | | - | | | | - | | | | 65,348 | |
Property taxes | | | - | | | | 25,329 | | | | 22,766 | | | | - | | | | 48,095 | |
Lease market valuation liability | | | - | | | | 341,881 | | | | - | | | | - | | | | 341,881 | |
Other | | | 17,174 | | | | 22,672 | | | | - | | | | - | | | | 39,846 | |
| | | 26,506 | | | | 506,195 | | | | 1,091,102 | | | | 806,893 | | | | 2,430,696 | |
| | $ | 3,885,657 | | | $ | 4,818,405 | | | $ | 4,057,876 | | | $ | (3,356,344 | ) | | $ | 9,405,594 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONSOLIDATING BALANCE SHEETS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
As of December 31, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
ASSETS | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
CURRENT ASSETS: | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
Receivables- | | | | | | | | | | | | | | | | | | | | |
Customers | | | 133,846 | | | | - | | | | - | | | | - | | | | 133,846 | |
Associated companies | | | 327,715 | | | | 237,202 | | | | 98,238 | | | | (286,656 | ) | | | 376,499 | |
Other | | | 2,845 | | | | 978 | | | | - | | | | - | | | | 3,823 | |
Notes receivable from associated companies | | | 23,772 | | | | - | | | | 69,012 | | | | - | | | | 92,784 | |
Materials and supplies, at average cost | | | 195 | | | | 215,986 | | | | 210,834 | | | | - | | | | 427,015 | |
Prepayments and other | | | 67,981 | | | | 21,605 | | | | 2,754 | | | | - | | | | 92,340 | |
| | | 556,356 | | | | 475,771 | | | | 380,838 | | | | (286,656 | ) | | | 1,126,309 | |
| | | | | | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
In service | | | 25,513 | | | | 5,065,373 | | | | 3,595,964 | | | | (392,082 | ) | | | 8,294,768 | |
Less - Accumulated provision for depreciation | | | 7,503 | | | | 2,553,554 | | | | 1,497,712 | | | | (166,756 | ) | | | 3,892,013 | |
| | | 18,010 | | | | 2,511,819 | | | | 2,098,252 | | | | (225,326 | ) | | | 4,402,755 | |
Construction work in progress | | | 1,176 | | | | 571,672 | | | | 188,853 | | | | - | | | | 761,701 | |
| | | 19,186 | | | | 3,083,491 | | | | 2,287,105 | | | | (225,326 | ) | | | 5,164,456 | |
| | | | | | | | | | | | | | | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,332,913 | | | | - | | | | 1,332,913 | |
Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | |
Investment in associated companies | | | 2,516,838 | | | | - | | | | - | | | | (2,516,838 | ) | | | - | |
Other | | | 2,732 | | | | 37,071 | | | | 201 | | | | - | | | | 40,004 | |
| | | 2,519,570 | | | | 37,071 | | | | 1,396,014 | | | | (2,516,838 | ) | | | 1,435,817 | |
| | | | | | | | | | | | | | | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
Accumulated deferred income taxes | | | 16,978 | | | | 522,216 | | | | - | | | | (262,271 | ) | | | 276,923 | |
Lease assignment receivable from associated companies | | | - | | | | 215,258 | | | | - | | | | - | | | | 215,258 | |
Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
Property taxes | | | - | | | | 25,007 | | | | 22,767 | | | | - | | | | 47,774 | |
Pension asset | | | 3,217 | | | | 13,506 | | | | - | | | | - | | | | 16,723 | |
Unamortized sale and leaseback costs | | | - | | | | 27,597 | | | | - | | | | 43,206 | | | | 70,803 | |
Other | | | 22,956 | | | | 52,971 | | | | 6,159 | | | | (38,133 | ) | | | 43,953 | |
| | | 67,399 | | | | 856,555 | | | | 28,926 | | | | (257,198 | ) | | | 695,682 | |
TOTAL ASSETS | | $ | 3,162,511 | | | $ | 4,452,888 | | | $ | 4,092,883 | | | $ | (3,286,018 | ) | | $ | 8,422,264 | |
| | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Currently payable long-term debt | | $ | - | | | $ | 596,827 | | | $ | 861,265 | | | $ | (16,896 | ) | | $ | 1,441,196 | |
Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | - | | | | 238,786 | | | | 25,278 | | | | - | | | | 264,064 | |
Other | | | 300,000 | | | | - | | | | - | | | | - | | | | 300,000 | |
Accounts payable- | | | | | | | | | | | | | | | | | | | | |
Associated companies | | | 287,029 | | | | 175,965 | | | | 268,926 | | | | (286,656 | ) | | | 445,264 | |
Other | | | 56,194 | | | | 120,927 | | | | - | | | | - | | | | 177,121 | |
Accrued taxes | | | 18,831 | | | | 125,227 | | | | 28,229 | | | | (836 | ) | | | 171,451 | |
Other | | | 57,705 | | | | 131,404 | | | | 11,972 | | | | 36,725 | | | | 237,806 | |
| | | 719,759 | | | | 1,389,136 | | | | 1,195,670 | | | | (267,663 | ) | | | 3,036,902 | |
| | | | | | | | | | | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
Common stockholder's equity | | | 2,414,231 | | | | 951,542 | | | | 1,562,069 | | | | (2,513,611 | ) | | | 2,414,231 | |
Long-term debt and other long-term obligations | | | - | | | | 1,597,028 | | | | 242,400 | | | | (1,305,716 | ) | | | 533,712 | |
| | | 2,414,231 | | | | 2,548,570 | | | | 1,804,469 | | | | (3,819,327 | ) | | | 2,947,943 | |
| | | | | | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,060,119 | | | | 1,060,119 | |
Accumulated deferred income taxes | | | - | | | | - | | | | 259,147 | | | | (259,147 | ) | | | - | |
Accumulated deferred investment tax credits | | | - | | | | 36,054 | | | | 25,062 | | | | - | | | | 61,116 | |
Asset retirement obligations | | | - | | | | 24,346 | | | | 785,768 | | | | - | | | | 810,114 | |
Retirement benefits | | | 8,721 | | | | 54,415 | | | | - | | | | - | | | | 63,136 | |
Property taxes | | | - | | | | 25,328 | | | | 22,767 | | | | - | | | | 48,095 | |
Lease market valuation liability | | | - | | | | 353,210 | | | | - | | | | - | | | | 353,210 | |
Other | | | 19,800 | | | | 21,829 | | | | - | | | | - | | | | 41,629 | |
| | | 28,521 | | | | 515,182 | | | | 1,092,744 | | | | 800,972 | | | | 2,437,419 | |
TOTAL LIABILITIES AND CAPITALIZATION | | $ | 3,162,511 | | | $ | 4,452,888 | | | $ | 4,092,883 | | | $ | (3,286,018 | ) | | $ | 8,422,264 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
NET CASH PROVIDED FROM (USED FOR) | | | | | | | | | | | | | | | |
OPERATING ACTIVITIES | | $ | 273,827 | | | $ | (122,171 | ) | | $ | 8,108 | | | $ | 188 | | | $ | 159,952 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
New Financing- | | | | | | | | | | | | | | | | | | | | |
Short-term borrowings, net | | | 400,000 | | | | 646,975 | | | | 234,921 | | | | - | | | | 1,281,896 | |
Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
Long-term debt | | | - | | | | (135,063 | ) | | | (153,540 | ) | | | - | | | | (288,603 | ) |
Common stock dividend payments | | | (10,000 | ) | | | - | | | | - | | | | - | | | | (10,000 | ) |
Net cash provided from financing activities | | | 390,000 | | | | 511,912 | | | | 81,381 | | | | - | | | | 983,293 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
Property additions | | | (19,406 | ) | | | (375,391 | ) | | | (81,545 | ) | | | (187 | ) | | | (476,529 | ) |
Proceeds from asset sales | | | - | | | | 5,088 | | | | - | | | | - | | | | 5,088 | |
Sales of investment securities held in trusts | | | - | | | | - | | | | 173,123 | | | | - | | | | 173,123 | |
Purchases of investment securities held in trusts | | | - | | | | - | | | | (181,079 | ) | | | - | | | | (181,079 | ) |
Loans to associated companies, net | | | (644,604 | ) | | | - | | | | - | | | | - | | | | (644,604 | ) |
Other | | | 183 | | | | (19,438 | ) | | | 12 | | | | (1 | ) | | | (19,244 | ) |
Net cash used for investing activities | | | (663,827 | ) | | | (389,741 | ) | | | (89,489 | ) | | | (188 | ) | | | (1,143,245 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | - | | | | - | | | | - | | | | - | |
Cash and cash equivalents at beginning of period | | | 2 | | | | - | | | | - | | | | - | | | | 2 | |
Cash and cash equivalents at end of period | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | |
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
(Unaudited) | |
| | | | | | | | | | | | | | | |
For the Three Months Ended March 31, 2007 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | (In thousands) | |
| | | | | | | | | | | | | | | |
NET CASH PROVIDED FROM | | | | | | | | | | | | | | | |
OPERATING ACTIVITIES | | $ | 65,870 | | | $ | 55,003 | | | $ | 177,456 | | | $ | - | | | $ | 298,329 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
New Financing- | | | | | | | | | | | | | | | | | | | | |
Equity contribution from parent | | | 700,000 | | | | 700,000 | | | | - | | | | (700,000 | ) | | | 700,000 | |
Short-term borrowings, net | | | 250,000 | | | | - | | | | - | | | | (52,269 | ) | | | 197,731 | |
Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
Long-term debt | | | - | | | | (616,728 | ) | | | (128,716 | ) | | | - | | | | (745,444 | ) |
Short-term borrowings, net | | | - | | | | (52,269 | ) | | | - | | | | 52,269 | | | | - | |
Net cash provided from (used for) financing activities | | | 950,000 | | | | 31,003 | | | | (128,716 | ) | | | (700,000 | ) | | | 152,287 | |
| | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
Property additions | | | (214 | ) | | | (81,400 | ) | | | (35,892 | ) | | | - | | | | (117,506 | ) |
Sales of investment securities held in trusts | | | - | | | | - | | | | 178,632 | | | | - | | | | 178,632 | |
Purchases of investment securities held in trusts | | | - | | | | - | | | | (188,076 | ) | | | - | | | | (188,076 | ) |
Loans to associated companies, net | | | (316,003 | ) | | | - | | | | (3,895 | ) | | | - | | | | (319,898 | ) |
Investment in subsidiary | | | (700,000 | ) | | | - | | | | - | | | | 700,000 | | | | - | |
Other | | | 347 | | | | (4,606 | ) | | | 491 | | | | - | | | | (3,768 | ) |
Net cash used for investing activities | | | (1,015,870 | ) | | | (86,006 | ) | | | (48,740 | ) | | | 700,000 | | | | (450,616 | ) |
| | | | | | | | | | | | | | | | | | | | |
Net change in cash and cash equivalents | | | - | | | | - | | | | - | | | | - | | | | - | |
Cash and cash equivalents at beginning of period | | | 2 | | | | - | | | | - | | | | - | | | | 2 | |
Cash and cash equivalents at end of period | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information” in Item 2 above.
ITEM 4. CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY
The applicable registrant'sFirstEnergy’s chief executive officer and chief financial officer have reviewed and evaluated the registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the applicable registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to the registrant and its consolidated subsidiaries by others within those entities.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended September 30, 2007,March 31, 2008, there were no changes in FirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’s internal control over financial reporting.
ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Each registrant's chief executive officer and chief financial officer have reviewed and evaluated such registrant's disclosure controls and procedures. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that such registrant's disclosure controls and procedures are effective and were designed to bring to their attention material information relating to such registrant and its consolidated subsidiaries by others within those entities.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended March 31, 2008, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 10 and 11 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
ITEM 1A. RISK FACTORS
See Item 1A RISK FACTORS in Part I of the Form 10-K for the year ended December 31, 20062007 for a discussion of the risk factors of FirstEnergy and the subsidiary registrants. For the quarter ended September 30, 2007,March 31, 2008, there have been no material changes to these risk factors.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
(c) FirstEnergy
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock.
| | | | | Period | |
| | July 1-31, | | August 1-31, | | September 1-30, | | Third | | | January 1-31, | | February 1-29, | | March 1-31, | | First | |
| | | | | | | | | | | | | | | | | | |
Total Number of Shares Purchased (a) | | 29,656 | | 83,448 | | 253,701 | | 366,805 | | | 329,106 | | 16,853 | | 988,386 | | 1,334,345 | |
Average Price Paid per Share | | $66.00 | | $62.95 | | $61.85 | | $62.44 | | | $76.56 | | $71.68 | | $68.55 | | $70.57 | |
Total Number of Shares Purchased | | | | | | | | | | | | | | | | | | |
As Part of Publicly Announced Plans | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Maximum Number (or Approximate Dollar | | | | | | | | | | | | | | | | | | | | |
Value) of Shares that May Yet Be | | | | | | | | | | | | | | | | | | | | | | |
Purchased Under the Plans or Programs | | | 1,629,890 | | 1,629,890 | | 1,629,890 | | | 1,629,890 | | | - | | - | | - | | - | |
| | | | | | | | | | | | | | |
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.