UNITED STATES
SECURITIES AND EXCHANGE
COMMISSION
Washington, D.C. 20549
For the quarterly period ended September 30, 2004
OR
For the transition period from _________ to __________.
| Commission File Number |
Exact name of registrants as specified in their charters, state of incorporation, address of principal executive offices, and telephone number |
I.R.S. Employer Identification Number |
| 1-15929 | Progress Energy, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina |
56-2155481 |
| 1-3382 | Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. 410 South Wilmington Street Raleigh, North Carolina 27601-1748 Telephone: (919) 546-6111 State of Incorporation: North Carolina |
56-0165465 |
NONE
Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No
Indicate by check mark whether Progress Energy, Inc. (Progress Energy) is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes X No __
Indicate by check mark whether Carolina Power & Light Company is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes __ No X
This combined Form 10-Q is filed separately by two registrants: Progress Energy and Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC). Information contained herein relating to either individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrant.
Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date. As of November 3, 2004, each registrant had the following shares of common stock outstanding:
| Registrant | Description | Shares |
|---|---|---|
| Progress Energy | Common Stock (Without Par Value) | 247,047,599 |
| PEC | Common Stock (Without Par Value) | 159,608,055 (all of which were held by Progress Energy, Inc.) |
Glossary of Terms
Safe Harbor For Forward-Looking Statements
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
| Consolidated Interim Financial Statements: |
| Progress
Energy, Inc. ________________________________________ |
| Unaudited
Consolidated Statements of Income Unaudited Consolidated Balance Sheets Unaudited Consolidated Statements of Cash Flows Notes to Consolidated Interim Financial Statements |
| Carolina
Power & Light Company d/b/a Progress Energy Carolinas, Inc. ________________________________________ |
| Unaudited
Consolidated Statements of Income Unaudited Consolidated Balance Sheets Unaudited Consolidated Statements of Cash Flows Notes to Consolidated Interim Financial Statements |
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 6. Exhibits
Signatures
The following abbreviations or acronyms used in the text of this combined Form 10-Q are defined below:
| TERM | DEFINITION |
|---|---|
| AFUDC the Agreement Bcf Btu CAIR CCO Colona the Company or Progress Energy CR3 CVO DIG DMT DOE DWM EIA EITF ENCNG EPA FASB Staff Position 106-2 FDEP Federal Circuit FERC FIN No. 46R Florida Progress or FPC FPSC Fuels Genco Jackson MACT Medicare Act Mesa MGP Moody's MW NCNG NCUC Norfolk Southern NOx NOx SIP Call NRC NSP OCI O&M OPEB PCH PEC PEF PFA the Plan PLRs Progress Rail PRP PTC PT LLC Progress Ventures PUHCA PVI PWR Rail Services or Rail RTO SCPSC Section 29 Service Company SFAS No. 71 SFAS No. 131 SFAS No. 133 SFAS No. 142 SFAS No. 143 SFAS No. 148 SFAS No. 149 SMD NOPR SO2 S&P SRS STB Tax Agreement the Trust Westchester |
Allowance for funds used during construction Stipulation and Settlement Agreement Billion cubic feet British thermal units Clean Air Interstate Rule Competitive Commercial Operations business segment Colona Synfuel Limited Partnership, LLLP Progress Energy, Inc. and subsidiaries Progress Energy Florida Inc.'s nuclear generating plant, Crystal River Unit No. 3 Contingent value obligation Derivatives Implementation Group Dynegy Marketing and Trading United States Department of Energy North Carolina Department of Environment and Natural Resources, Division of Waste Management Energy Information Agency Emerging Issues Task Force Eastern North Carolina Natural Gas Company, formerly referred to as Eastern NC United States Environmental Protection Agency Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003 Florida Department of Environment and Protection United States Circuit Court of Appeals Federal Energy Regulatory Commission FASB Interpretation No. 46, "Consolidation of Variable Interest Entities - An Interpretation of ARB No. 51," revised December 2003 Florida Progress Corporation Florida Public Service Commission Fuels business segment Progress Genco Ventures, LLC Jackson County EMC Maximum Available Control Technology Medicare Prescription Drug, Improvement and Modernization Act of 2003 Mesa Hydrocarbons, LLC Manufactured gas plant Moody's Investors Service Megawatts North Carolina Natural Gas Corporation North Carolina Utilities Commission Norfolk Southern Railway Company Nitrogen oxide EPA rule which requires 23 jurisdictions including North and South Carolina and Georgia to further reduce nitrogen oxide emissions United States Nuclear Regulatory Commission Northern States Power Accumulated other comprehensive income Operating and maintenance Other post-employment benefits Progress Capital Holdings, Inc. Progress Energy Carolinas, Inc., formerly referred to as Carolina Power & Light Company Progress Energy Florida, Inc., formerly referred to as Florida Power Corporation IRS Pre-filing Agreement Revenue Sharing Incentive Plan Private Letter Rulings Progress Rail Services Corporation Potentially responsible parties Progress Telecommunications Corporation Progress Telecom LLC Business unit of Progress Energy primarily made up of nonregulated energy generation, gas, coal and synthetic fuel operations and energy marketing Public Utility Holding Company Act of 1935, as amended Legal entity of Progress Ventures, Inc. Pressurized water reactor Rail Services business segment Regional Transmission Organization Public Service Commission of South Carolina Section 29 of the Internal Revenue Code Progress Energy Service Company, LLC Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information" Statement of Financial Accounting Standards No. 133, "Accounting for Derivative and Hedging Activities" Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - An Amendment of FASB Statement No. 123" Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission and Standard Market Design Sulfur dioxide Standard & Poor's Rating Agency Strategic Resource Solutions Corp. Surface Transportation Board Inter-company Income Tax Allocation Agreement FPC Capital I trust Westchester Gas Company |
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
This combined report contains forward-looking statements within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The matters discussed throughout this combined Form 10-Q that are not historical facts are forward-looking and, accordingly, involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.
In addition, forward-looking statements are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” including, but not limited to, statements under the sub-headings “Liquidity and Capital Resources”and “Other Matters” about the effects of new environmental regulations, nuclear decommissioning costs and the effect of electric utility industry restructuring.
Any forward-looking statement speaks only as of the date on which such statement is made, and neither Progress Energy, Inc. (Progress Energy or the Company) nor Progress Energy Carolinas, Inc. (PEC) undertakes any obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made.
Examples of factors that you should consider with respect to any forward-looking statements made throughout this document include, but are not limited to, the following: the impact of fluid and complex government laws and regulations, including those relating to the environment; deregulation or restructuring in the electric industry that may result in increased competition and unrecovered (stranded) costs; the uncertainty regarding the timing, creation and structure of regional transmission organizations; weather conditions that directly influence the demand for electricity; our ability to recover through the regulatory process, and the timing of, the costs associated with the four hurricanes that impacted our service territory in 2004 or other significant weather events; recurring seasonal fluctuations in demand for electricity; fluctuations in the price of energy commodities and purchased power; economic fluctuations and the corresponding impact on Progress Energy, Inc. and its subsidiaries’ commercial and industrial customers; the ability of the Company’s subsidiaries to pay upstream dividends or distributions to it; the impact on the facilities and the businesses of the Company from a terrorist attack; the inherent risks associated with the operation of nuclear facilities, including environmental, health, regulatory and financial risks; the ability to successfully access capital markets on favorable terms; the impact that increases in leverage may have on the Company; the ability of the Company to maintain its current credit ratings; the impact of derivative contracts used in the normal course of business by the Company; investment performance of pension and benefit plans; the Company's ability to control costs, including pension and benefit expense, and achieve its cost management targets for 2007; the availability and use of Internal Revenue Code Section 29 (Section 29) tax credits by synthetic fuel producers and the Company’s continued ability to use Section 29 tax credits related to its coal and synthetic fuel businesses; the impact to our financial condition and performance in the event it is determined the Company is not entitled to previously taken Section 29 tax credits; the Company’s ability to manage the risks involved with the operation of its nonregulated plants, including dependence on third parties and related counter-party risks, and a lack of operating history; the Company’s ability to manage the risks associated with its energy marketing operations; the outcome of any ongoing or future litigation or similar disputes and the impact of any such outcome or related settlements; and unanticipated changes in operating expenses and capital expenditures. Many of these risks similarly impact the Company’s subsidiaries.
These and other risk factors are detailed from time to time in the Progress Energy and PEC United States Securities and Exchange Commission (SEC) reports. Many, but not all of the factors that may impact actual results are discussed in the Risk Factors sections of Progress Energy’s and PEC’s annual report on Form 10-K for the year ended December 31, 2003, which were filed with the SEC on March 12, 2004. These reports should be read carefully. All such factors are difficult to predict, contain uncertainties that may materially affect actual results and may be beyond the control of Progress Energy and PEC. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor can it assess the effect of each such factor on Progress Energy and PEC.
Item 1. Financial Statements
UNAUDITED CONSOLIDATED STATEMENTS of INCOME
| Three Months Ended September 30 |
Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions except per share data) | 2004 | 2003 | 2004 | 2003 | |||||
| Operating Revenues | |||||||||
| Utility | $ 2,043 | $ 1,914 | $ 5,449 | $ 5,151 | |||||
| Diversified business | 732 | 543 | 2,002 | 1,543 | |||||
| Total Operating Revenues | 2,775 | 2,457 | 7,451 | 6,694 | |||||
| Operating Expenses | |||||||||
| Utility | |||||||||
| Fuel used in electric generation | 556 | 489 | 1,517 | 1,294 | |||||
| Purchased power | 269 | 254 | 671 | 667 | |||||
| Operation and maintenance | 324 | 369 | 1,059 | 1,068 | |||||
| Depreciation and amortization | 213 | 220 | 622 | 664 | |||||
| Taxes other than on income | 114 | 107 | 328 | 304 | |||||
| Diversified business | |||||||||
| Cost of sales | 620 | 455 | 1,797 | 1,346 | |||||
| Depreciation and amortization | 52 | 45 | 143 | 114 | |||||
| Other | 43 | 42 | 131 | 130 | |||||
| Total Operating Expenses | 2,191 | 1,981 | 6,268 | 5,587 | |||||
| Operating Income | 584 | 476 | 1,183 | 1,107 | |||||
| Other Income (Expense) | |||||||||
| Interest income | 2 | 2 | 9 | 8 | |||||
| Other, net | 36 | (2 | ) | 11 | (17 | ) | |||
| Total Other Income (Expense) | 38 | — | 20 | (9 | ) | ||||
| Interest Charges | |||||||||
| Net interest charges | 160 | 147 | 486 | 462 | |||||
| Allowance for borrowed funds used during construction | (2 | ) | (2 | ) | (5 | ) | (7 | ) | |
| Total Interest Charges, Net | 158 | 145 | 481 | 455 | |||||
| Income from Continuing Operations before Income Tax and | 464 | 331 | 722 | 643 | |||||
| Cumulative Effect of Change in Accounting Principle | |||||||||
| Income Tax Expense (Benefit) | 161 | (6 | ) | 158 | (55 | ) | |||
| Income from Continuing Operations before Cumulative Effect of | 303 | 337 | 564 | 698 | |||||
| Change in Accounting Principle | |||||||||
| Discontinued Operations, Net of Tax | — | (19 | ) | 1 | (5 | ) | |||
| Income before Cumulative Effect of Change in Accounting Principle | 303 | 318 | 565 | 693 | |||||
| Cumulative Effect of Change in Accounting Principle, Net of Tax | — | — | — | 1 | |||||
| Net Income | $ 303 | $ 318 | $ 565 | $ 694 | |||||
| Average Common Shares Outstanding | 243 | 239 | 242 | 236 | |||||
| Basic Earnings per Common Share | |||||||||
| Income from Continuing Operations before Cumulative | |||||||||
| Effect of Change in Accounting Principle | $ 1.25 | $ 1.41 | $ 2.33 | $ 2.96 | |||||
| Discontinued Operations, Net of Tax | — | (0.08 | ) | — | (0.02 | ) | |||
| Net Income | $ 1.25 | $ 1.33 | $ 2.33 | $ 2.94 | |||||
| Diluted Earnings per Common Share | |||||||||
| Income from Continuing Operations before Cumulative | |||||||||
| Effect of Change in Accounting Principle | $ 1.24 | $ 1.40 | $ 2.32 | $ 2.95 | |||||
| Discontinued Operations, Net of Tax | — | (0.08 | ) | — | (0.02 | ) | |||
| Net Income | $ 1.24 | $ 1.32 | $ 2.32 | $ 2.93 | |||||
| Dividends Declared per Common Share | $ 0.575 | $ 0.560 | $ 1.725 | $ 1.680 | |||||
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
PROGRESS
ENERGY, INC.
UNAUDITED
CONSOLIDATED BALANCE SHEETS
| (in millions) | September 30 | December 31 | |||
|---|---|---|---|---|---|
| ASSETS | 2004 | 2003 | |||
| Utility Plant | |||||
| Utility plant in service | $ 22,068 | $ 21,675 | |||
| Accumulated depreciation | (8,417 | ) | (8,169 | ) | |
| Utility plant in service, net | 13,651 | 13,506 | |||
| Held for future use | 13 | 13 | |||
| Construction work in progress | 680 | 634 | |||
| Nuclear fuel, net of amortization | 220 | 228 | |||
| Total Utility Plant, Net | 14,564 | 14,381 | |||
| Current Assets | |||||
| Cash and cash equivalents | 57 | 273 | |||
| Accounts receivable | 794 | 798 | |||
| Unbilled accounts receivable | 231 | 217 | |||
| Inventory | 935 | 795 | |||
| Deferred fuel cost | 382 | 317 | |||
| Prepayments and other current assets | 397 | 375 | |||
| Total Current Assets | 2,796 | 2,775 | |||
| Deferred Debits and Other Assets | |||||
| Regulatory assets | 894 | 612 | |||
| Nuclear decommissioning trust funds | 993 | 938 | |||
| Diversified business property, net | 2,186 | 2,158 | |||
| Miscellaneous other property and investments | 454 | 464 | |||
| Goodwill | 3,719 | 3,726 | |||
| Prepaid pension costs | 474 | 462 | |||
| Intangibles, net | 295 | 327 | |||
| Other assets | 245 | 253 | |||
| Total Deferred Debits and Other Assets | 9,260 | 8,940 | |||
| Total Assets | $ 26,620 | $ 26,096 | |||
| CAPITALIZATION AND LIABILITIES | |||||
| Common Stock Equity | |||||
| Common stock without par value, 500 million shares authorized, | |||||
| 247 and 246 million shares issued and outstanding, respectively | $ 5,339 | $ 5,270 | |||
| Unearned restricted shares | (15 | ) | (17 | ) | |
| Unearned ESOP shares | (76 | ) | (89 | ) | |
| Accumulated other comprehensive loss | (62 | ) | (50 | ) | |
| Retained earnings | 2,475 | 2,330 | |||
| Total Common Stock Equity | 7,661 | 7,444 | |||
| Preferred Stock of Subsidiaries-Not Subject to Mandatory Redemption | 93 | 93 | |||
| Long-Term Debt, Affiliate | 309 | 309 | |||
| Long-Term Debt, Net | 9,245 | 9,625 | |||
| Total Capitalization | 17,308 | 17,471 | |||
| Current Liabilities | |||||
| Current portion of long-term debt | 348 | 868 | |||
| Accounts payable and accrued liabilities | 940 | 643 | |||
| Interest accrued | 154 | 209 | |||
| Dividends declared | 141 | 140 | |||
| Short-term obligations | 668 | 4 | |||
| Customer deposits | 174 | 167 | |||
| Other current liabilities | 652 | 580 | |||
| Total Current Liabilities | 3,077 | 2,611 | |||
| Deferred Credits and Other Liabilities | |||||
| Accumulated deferred income taxes | 807 | 737 | |||
| Accumulated deferred investment tax credits | 179 | 190 | |||
| Regulatory liabilities | 2,977 | 2,885 | |||
| Asset retirement obligations | 1,323 | 1,271 | |||
| Other liabilities | 949 | 931 | |||
| Total Deferred Credits and Other Liabilities | 6,235 | 6,014 | |||
| Commitments and Contingencies (Note 15) | |||||
| Total Capitalization and Liabilities | $ 26,620 | $ 26,096 | |||
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
PROGRESS
ENERGY, INC.
UNAUDITED
CONSOLIDATED STATEMENTS of CASH FLOWS
| Nine Months Ended September 30 | |||||
|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | |||
| Operating Activities | |||||
| Net income | $ 565 | $ 694 | |||
| Adjustments to reconcile net income to net cash provided by operating | |||||
| activities: | |||||
| (Income) loss from discontinued operations | (1 | ) | 5 | ||
| Cumulative effect of change in accounting principle | — | (1 | ) | ||
| Depreciation and amortization | 857 | 853 | |||
| Deferred income taxes | 124 | (208 | ) | ||
| Investment tax credit | (11 | ) | (12 | ) | |
| Deferred fuel credit | (65 | ) | (144 | ) | |
| Cash provided (used) by changes in operating assets and liabilities | |||||
| Accounts receivable | (32 | ) | (77 | ) | |
| Inventories | (32 | ) | 63 | ||
| Prepayments and other current assets | (54 | ) | 30 | ||
| Accounts payable | 53 | (22 | ) | ||
| Income taxes, net | (25 | ) | 140 | ||
| Other current liabilities | (3 | ) | (13 | ) | |
| Other | (59 | ) | 123 | ||
| Net Cash Provided by Operating Activities | 1,317 | 1,431 | |||
| Investing Activities | |||||
| Gross utility property additions | (704 | ) | (759 | ) | |
| Diversified business property additions | (181 | ) | (476 | ) | |
| Nuclear fuel additions | (63 | ) | (96 | ) | |
| Contributions to nuclear decommissioning trust | (26 | ) | (26 | ) | |
| Investments in non-utility activities | (12 | ) | (11 | ) | |
| Acquisition of intangibles | (1 | ) | (198 | ) | |
| Proceeds from sales of investments and assets | 101 | 478 | |||
| Net decrease in restricted cash | 5 | 22 | |||
| Other | (8 | ) | (4 | ) | |
| Net Cash Used in Investing Activities | (889 | ) | (1,070 | ) | |
| Financing Activities | |||||
| Issuance of common stock | 58 | 284 | |||
| Purchase of common stock | (7 | ) | (7 | ) | |
| Issuance of long-term debt | 1 | 1,243 | |||
| Net increase (decrease) in short-term indebtedness | 664 | (696 | ) | ||
| Net decrease in cash provided by checks drawn in excess of bank balances | (52 | ) | (53 | ) | |
| Retirement of long-term debt | (905 | ) | (699 | ) | |
| Dividends paid on common stock | (423 | ) | (403 | ) | |
| Other | 20 | 9 | |||
| Net Cash Used in Financing Activities | (644 | ) | (322 | ) | |
| Net (Decrease) Increase in Cash and Cash Equivalents | (216 | ) | 39 | ||
| Cash and Cash Equivalents at Beginning of Period | 273 | 61 | |||
| Cash and Cash Equivalents at End of Period | $ 57 | $ 100 | |||
| Supplemental Disclosures of Cash Flow Information | |||||
| Cash paid during the year - interest (net of amount capitalized) | $ 530 | $ 516 | |||
| income taxes (net of refunds) | $ 112 | $ 97 | |||
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
1. ORGANIZATION AND BASIS OF PRESENTATION
| A. | Organization |
| Progress Energy, Inc. is a holding company headquartered in Raleigh, North Carolina and registered under the Public Utility Holding Company Act of 1935 (PUHCA), as amended. As such, Progress Energy, Inc. and its subsidiaries (Progress Energy or the Company) are subject to the regulatory provisions of PUHCA. |
| Through its wholly-owned subsidiaries, Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a Progress Energy Florida, Inc. (PEF), the Company's PEC Electric and PEF segments are primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina, South Carolina and Florida. The Progress Ventures business unit consists of the Fuels (Fuels) and the Competitive Commercial Operations (CCO) business segments. The Fuels segment is involved in natural gas drilling and production, coal terminal services, coal mining, synthetic fuel production, fuel transportation and delivery. The CCO segment includes nonregulated electric generation and energy marketing activities. Through the Rail Services (Rail) segment, the Company is involved in nonregulated railcar repair, rail parts reconditioning and sales, and scrap metal recycling. Through its other business units, the Company engages in other nonregulated business areas, including telecommunications and energy management and related services. Progress Energy's legal structure is not currently aligned with the functional management and financial reporting of the Progress Ventures business unit. Whether, and when, the legal and functional structures will converge depends upon regulatory action, which cannot currently be anticipated. |
| B. | Basis of Presentation |
| These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual statements. Because the accompanying consolidated interim financial statements do not include all of the information and footnotes required by GAAP, they should be read in conjunction with the audited financial statements for the period ended December 31, 2003, and notes thereto included in Progress Energy's Form 10-K for the year ended December 31, 2003. |
| PEC and PEF collect from customers certain excise taxes, which include gross receipts tax, franchise taxes, and other excise taxes, levied by the state or local government upon the customers. PEC and PEF account for excise taxes on a gross basis. For the three month periods ended September 30, 2004 and 2003, excise taxes of approximately $70 million and $65 million, respectively, are included in taxes other than on income in the accompanying Consolidated Statements of Income. For the nine month periods ended September 30, 2004 and 2003, excise taxes of approximately $184 million and $169 million, respectively, are included in taxes other than on income in the accompanying Consolidated Statements of Income. These approximate amounts are also included in utility revenues. |
| The amounts included in the consolidated interim financial statements are unaudited but, in the opinion of management, reflect all normal recurring adjustments necessary to fairly present the Company's financial position and results of operations for the interim periods. Due to seasonal weather variations and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or future periods. |
| In preparing financial statements that conform with GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates. Certain amounts for 2003 have been reclassified to conform to the 2004 presentation. The results of operations of the Rail Services segment are reported one month in arrears. |
| C. | Subsidiary Reporting Period Change |
| In the fourth quarter of 2003, the Company ceased recording portions of Fuels' segment operations, primarily synthetic fuel operations, one month in arrears. As a result, earnings for the year ended December 31, 2003 as reported in the Company's Form 10-K, included 13 months of results for these operations. The 2003 quarterly results for periods ended March 31, June 30 and September 30 have been restated for the above-mentioned reporting period change. This resulted in ten months of earnings in the nine months ended September 30, 2003. The impact of the reclassification of earnings between quarters is outlined in the table below: |
| Three Months Ended September 30, 2003 | As Previously | Quarter | As | ||||
|---|---|---|---|---|---|---|---|
| (in millions, except per share data) | Reported | Reclassification | Restated | ||||
| Income from Continuing Operations before Cumulative Effect | |||||||
| of Change in Accounting Principle | $338 | $ (1 | ) | $337 | |||
| Net Income | $319 | $ (1 | ) | $318 | |||
Basic earnings per common share | |||||||
| Income from Continuing Operations before Cumulative | |||||||
| Effect of Change in Accounting Principle | $1.42 | $(0.01 | ) | $1.41 | |||
| Net Income | $1.34 | $(0.01 | ) | $1.33 | |||
Diluted earnings per common share | |||||||
| Income from Continuing Operations before Cumulative | |||||||
| Effect of Change in Accounting Principle | $1.42 | $(0.02 | ) | $1.40 | |||
| Net Income | $1.34 | $(0.02 | ) | $1.32 | |||
| Nine Months Ended September 30, 2003 | As Previously | Quarter | As | ||||
|---|---|---|---|---|---|---|---|
| (in millions, except per share data) | Reported | Reclassification | Restated | ||||
| Income from Continuing Operations before Cumulative Effect | |||||||
| of Change in Accounting Principle | $684 | $ 14 | $698 | ||||
| Net Income | $680 | $ 14 | $694 | ||||
Basic earnings per common share | |||||||
| Income from Continuing Operations before Cumulative | |||||||
| Effect of Change in Accounting Principle | $2.90 | $0.06 | $2.96 | ||||
| Net Income | $2.88 | $0.06 | $2.94 | ||||
Diluted earnings per common share | |||||||
| Income from Continuing Operations before Cumulative | |||||||
| Effect of Change in Accounting Principle | $2.89 | $0.06 | $2.95 | ||||
| Net Income | $2.87 | $0.06 | $2.93 | ||||
| D. | Stock-Based Compensation |
| The Company measures compensation expense for stock options as the difference between the market price of its common stock and the exercise price of the option at the grant date. The exercise price at which options are granted by the Company equals the market price at the grant date, and accordingly, no compensation expense has been recognized for stock option grants. For purposes of the pro forma disclosures required by Statement of Financial Accounting Standards (SFAS) No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure – an Amendment of FASB Statement No. 123,” the estimated fair value of the Company’s stock options is amortized to expense over the options’ vesting period. The following table illustrates the effect on net income and earnings per share if the fair value method had been applied to all outstanding and unvested awards in each period: |
| Three Months Ended September 30 |
Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions except per share data) | 2004 | 2003 | 2004 | 2003 | |||||
| Net Income, as reported | $303 | $318 | $565 | $694 | |||||
| Deduct: Total stock option expense determined under | |||||||||
| fair value method for all awards, net of related tax | |||||||||
| effects | 3 | 3 | 9 | 7 | |||||
| Pro forma net income | $300 | $315 | $556 | $687 | |||||
| Basic earnings per share | |||||||||
| As reported | $1.25 | $1.33 | $2.33 | $2.94 | |||||
| Pro forma | $1.23 | $1.32 | $2.29 | $2.91 | |||||
Fully diluted earnings per share | |||||||||
| As reported | $1.24 | $1.32 | $2.32 | $2.93 | |||||
| Pro forma | $1.23 | $1.31 | $2.29 | $2.90 | |||||
| The Company expects to begin expensing stock options in 2005, either by adopting SFAS No. 123, as amended by SFAS No. 148, or by adopting new FASB guidance on accounting for stock-based compensation that is expected to be issued in late 2004 and become effective July 1, 2005. In 2004, however, the Company made the decision to cease granting stock options and intends to replace that compensation program with other programs. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued. If stock option expense is recorded for the full year 2005, approximately $7 million of pre-tax expense would be recorded. |
| E. | Consolidation of Variable Interest Entities |
| The Company consolidates all voting interest entities in which it owns a majority voting interest and all variable interest entities for which it is the primary beneficiary in accordance with FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51” (FIN No. 46R). The Company is the primary beneficiary of and consolidates two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Internal Revenue Code. As of September 30, 2004, the total assets of the two entities were $39 million, the majority of which are collateral for the entities’ obligations and are included in other current assets and miscellaneous other property and investments in the Consolidated Balance Sheets. |
| The Company is the primary beneficiary of a limited partnership which invests in 17 low-income housing partnerships that qualify for federal and state tax credits. The Company has requested but has not received all the necessary information to determine the primary beneficiary of the limited partnership’s underlying 17 partnership investments, and has applied the information scope exception in FIN No. 46R, paragraph 4(g) to the 17 partnerships. The Company has no direct exposure to loss from the 17 partnerships; the Company’s only exposure to loss is from its investment of less than $1 million in the consolidated limited partnership. The Company will continue its efforts to obtain the necessary information to fully apply FIN No. 46R to the 17 partnerships. The Company believes that if the limited partnership is determined to be the primary beneficiary of the 17 partnerships, the effect of consolidating the 17 partnerships would not be significant to the Company’s Consolidated Balance Sheets. |
| The Company has variable interests in two power plants resulting from long-term power purchase contracts. The Company has requested the necessary information to determine if the counterparties are variable interest entities or to identify the primary beneficiaries. Both entities declined to provide the Company with the necessary financial information, and the Company has applied the information scope exception in FIN No. 46R, paragraph 4(g). The Company’s only significant exposure to variability from these contracts results from fluctuations in the market price of fuel used by the two entities’plants to produce the power purchased by the Company. The Company is able to recover these fuel costs under PEC’s fuel clause. Total purchases from these counterparties were approximately $46 million and $43 million in the first nine months of 2004 and 2003, respectively. The Company will continue its efforts to obtain the necessary information to fully apply FIN No. 46R to these contracts. The combined generation capacity of the two entities’ power plants is approximately 880 MW. The Company believes that if it is determined to be the primary beneficiary of these two entities, the effect of consolidating the entities would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on the Company’s common stock equity, net earnings, or cash flows. However, because the Company has not received any financial information from these two counterparties, the impact cannot be determined at this time. |
| The Company also has interests in several other variable interest entities for which the Company is not the primary beneficiary. These arrangements include investments in approximately 27 limited partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities. The aggregate maximum loss exposure at September 30, 2004, that the Company could be required to record in its income statement as a result of these arrangements totals approximately $37 million. The creditors of these variable interest entities do not have recourse to the general credit of the Company in excess of the aggregate maximum loss exposure. |
2. NEW ACCOUNTING STANDARDS
| In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law. In accordance with guidance issued by the FASB in FASB Staff Position 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003” (FASB Staff Position 106-2), the Company elected to defer accounting for the effects of the Medicare Act due to uncertainties regarding the effects of the implementation of the Medicare Act and the accounting for certain provisions of the Medicare Act. In May 2004, the FASB issued definitive accounting guidance for the Medicare Act in FASB Staff Position 106-2, which was effective for the Company in the third quarter of 2004. FASB Staff Position 106-2 results in the recognition of lower other postretirement employment benefit (OPEB) costs to reflect prescription drug-related federal subsidies to be received under the Medicare Act. As a result of the Medicare Act, the Company’s accumulated postretirement benefit obligation as of January 1, 2004 was reduced by approximately $83 million, and the Company’s 2004 net periodic cost will be reduced by approximately $13 million due to the Medicare Act. The Company recorded $10 million of the net periodic cost reduction in the quarter ended September 30, 2004. Prior quarters were not restated due to the immateriality of the adjustments. |
3. HURRICANE-RELATED COSTS
| Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of the Company’s service territories during the third quarter of 2004, most significantly impacting PEF’s territory. Restoration of the Company’s systems from hurricane-related damage is estimated at $379 million. PEC has estimated restoration costs of $13 million, of which $12 million was charged to operation and maintenance expense and $1 million was charged to capital expenditures. PEF has estimated total costs of $366 million, of which $55 million was charged to capital expenditures, and $311 million was charged to the storm damage reserve pursuant to a regulatory order. |
| In accordance with a regulatory order, PEF accrues $6 million annually to a storm damage reserve and is allowed to defer losses in excess of the accumulated reserve. Under the order, the storm reserve is charged with operation and maintenance expenses related to storm restoration and with capital expenditures related to storm restoration that are in excess of expenditures assuming normal operating conditions. As of September 30, 2004, $266 million of hurricane restoration costs in excess of the previously recorded storm reserve have been classified as a regulatory asset in order to recognize the probable recoverability of these costs. On November 2, 2004, PEF filed a petition with the Florida Public Service Commission (FPSC) to recover $252 million of storm costs plust interest from retail ratepayers over a two-year period. The remaining storm reserve costs of $14 million are attributable to wholesale customers. The Company believes such costs are recoverable. |
| PEC does not have an on-going regulatory mechanism to recover storm costs and; therefore, hurricane restoration costs recorded in the third quarter of 2004 were charged to operations and maintenance expenses or capital expenditures based on the nature of the work performed. In connection with other storms, PEC has previously sought and received permission from the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC) to defer storm expenses and amortize them over a five-year period. PEC is planning to seek deferral of 2004 storm costs from the NCUC in the fourth quarter of 2004. |
| Total capital expenditures of approximately $56 million have been included in construction work in progress as reported on the Consolidated Balance Sheets for Progress Energy at September 30, 2004. Due to the frequency and timing of these storms, the replaced equipment has not been fully identified or quantified at this time. As such, current expenditures are recorded as construction work in progress and replaced equipment is still presented gross in the utility plant in service and accumulated depreciation balances reported on the Consolidated Balance Sheets of Progress Energy as of September 30, 2004 instead of being retired. Due to the accounting treatment for regulated utility assets and related depreciation, these retirements, when recorded, will reduce utility plant in service and accumulated depreciation by offsetting amounts, therefore having no impact on total utility plant, net or the Consolidated Statements of Income. |
| As a result of the substantial hurricane restoration costs, the Company’s regular federal income tax liability has been significantly reduced, resulting in a charge of $79 million related to Section 29 tax credits. See Note 14 and 15 for additional discussion. |
4. DIVESTITURES
| A. | Divestiture of Synthetic Fuel Partnership Interests |
| In June 2004, the Company through its subsidiary Progress Fuels sold, in two transactions, a combined 49.8% partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gain from the sales will be recognized on a cost recovery basis. The Company’s book value of the interests sold totaled approximately $5 million. Based on projected production and tax credit levels, the Company anticipates receiving total gross proceeds of $10 million in 2004, approximately $30 million per year from 2005 through 2007 and approximately $9 million through the second quarter of 2008. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil which could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized could be significantly impacted. See Note 15 for additional discussion regarding the impact of oil prices on Section 29 tax credits. Under the agreements, the buyers had a right to unwind the transactions if an IRS reconfirmation private letter ruling (PLR) was not received by October 15, 2004. The reconfirmation PLR was received in September 2004. An immaterial gain was recorded for the three months ended September 30, 2004. |
| B. | Railcar Ltd. Divestiture |
| In December 2002, the Progress Energy Board of Directors adopted a resolution approving the sale of Railcar Ltd., a subsidiary included in the Rail Services segment. In March 2003, the Company signed a letter of intent to sell the majority of Railcar Ltd. assets to The Andersons, Inc., and the transaction closed in February 2004. Proceeds from the sale were approximately $82 million before transaction costs and taxes of approximately $13 million. In July 2004, the Company sold the remaining assets classified as held for sale to a third-party for net proceeds of $6 million. The assets of Railcar Ltd. were grouped as assets held for sale and were included in other current assets on the Consolidated Balance Sheets at December 31, 2003 at approximately $75 million, which reflected the Company’s estimates of the fair value expected to be realized from the sale of these assets less costs to sell. |
| C. | NCNG Divestiture |
| In October 2002, the Company announced the Board of Directors’ approval to sell North Carolina Natural Gas Corporation (NCNG) and the Company’s equity investment in Eastern North Carolina Natural Gas Company (ENCNG) to Piedmont Natural Gas Company, Inc. On September 30, 2003, the Company completed the sale. The 2003 net income of these operations is reported as discontinued operations in the Consolidated Statements of Income. Interest expense of $3 million and $10 million for the three and nine months ended September 30, 2003, respectively, has been allocated to discontinued operations based on the net assets of NCNG, assuming a uniform debt-to-equity ratio across the Company’s operations. Results of discontinued operations were as follows: |
| (in millions) | Three Months Ended September 30, 2003 |
Nine Months Ended September 30, 2003 | |||
|---|---|---|---|---|---|
| Revenues | $ 59 | $ 284 | |||
| (Loss) earnings before income taxes | $(16 | ) | $ 6 | ||
| Income tax (benefit) expense | (6 | ) | 2 | ||
| Net (loss) earnings from discontinued | |||||
| Operations | $(10 | ) | $ 4 | ||
| Estimated loss on disposal of discontinued | |||||
| operations, including applicable income | (9 | ) | (9 | ) | |
| tax expense of $4 | |||||
| Net loss from discontinued operations | $(19 | ) | $ (5 | ) | |
| During the nine months ended September 30, 2004, the Company recorded a reduction to the loss on the sale of NCNG of approximately $1 million after-tax related to an adjustment of deferred taxes. |
5. ACQUISITIONS AND BUSINESS COMBINATIONS
| Progress Telecommunications Corporation |
| In December 2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc. (Caronet), both wholly-owned subsidiaries of Progress Energy, and EPIK Communications, Inc. (EPIK), a wholly-owned subsidiary of Odyssey Telecorp, Inc. (Odyssey), contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC (PT LLC), a subsidiary of PTC. Subsequently, in December 2003 the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash and Caronet became a wholly-owned subsidiary of Odyssey. Following consummation of all the transactions described above, PTC holds a 55% ownership interest in, and is the parent of, PT LLC. Odyssey holds a combined 45% ownership interest in PT LLC through EPIK and Caronet. The accounts of PT LLC are included in the Company’s Consolidated Financial Statements since the transaction date. The minority interest is included in other liabilities and deferred credits in the Consolidated Balance Sheets. |
| The transaction was accounted for as a partial acquisition of EPIK through the issuance of the stock of a consolidated subsidiary. The contributions of PTC’s and Caronet’s net assets were recorded at their carrying values of approximately $31 million. EPIK’s contribution was recorded at its estimated fair value of $22 million using the purchase method. No gain or loss was recognized on the transaction. The EPIK purchase price was initially allocated as follows: property and equipment — $27 million; other current assets — $9 million; current liabilities — $21 million, and goodwill — $7 million. During 2004, PT LLC obtained certain external appraisals of acquired assets and developed a restructuring plan to exit certain leasing arrangements of EPIK. Based on the results of these activities, the preliminary purchase price allocation for EPIK was revised as follows at September 30, 2004: property and equipment — $39 million; other current assets — $7 million; intangible assets — $1 million; current liabilities — $19 million and exit costs — $6 million. The exit costs consist primarily of lease termination penalties and noncancellable lease payments made after certain leased properties are vacated. The purchase price allocation is subject to adjustment in the fourth quarter of 2004 pending the completion of certain external appraisals and the finalization of the restructuring plan, which is expected to be substantially completed by December 31, 2004. |
6. REGULATORY MATTERS
| A. | Retail Rate Matters |
| PEC has exclusively utilized external funding for its decommissioning liability since 1994. Prior to 1994, PEC retained funds internally to meet its decommissioning liability. A NCUC order issued in February 2004 found that by January 1, 2008, PEC must begin transitioning these amounts to external funds. The transition of $131 million must be completed by December 31, 2017, and at least 10% must be transitioned each year. |
| PEC filed with the SCPSC seeking permission to defer expenses incurred from the first quarter 2004 winter storm. The SCPSC approved PEC’s request to defer the costs and amortize them ratably over five years beginning in January 2005. Approximately $10 million related to storm costs incurred during the first quarter of 2004 was deferred in that quarter. |
| During the first quarter of 2004, PEC met the requirements of both the NCUC and the SCPSC for the implementation of a depreciation study which allowed the utility to reduce the rates used to calculate depreciation expense. As a result, depreciation expense decreased $7 million for the three months ended September 30, 2004 compared to the prior year quarter and decreased $17 million for the nine months ended September 30, 2004 compared to the prior year nine month period. |
| In October 2004, PEC filed a revised depreciation study with the NCUC and SCPSC supporting a reduction in annual depreciation expense of approximately $47 million. The reduction is due solely to extended lives at each of PEC’s nuclear units. The new depreciation rates are proposed to be effective January 1, 2004. |
| PEC obtained SCPSC and NCUC approval of fuel factors in annual fuel-adjustment proceedings. The SCPSC approved PEC’s petition to leave billing rates unchanged from the prior year by order issued in March 2004. The NCUC approved an annual increase of $62 million by order issued in September 2004. |
| In a filing dated September 9, 2004, as amended in November 2004, PEF is requesting the FPSC to approve recovery through PEF’s pass-through clauses in 2005 an increase of $278 million. This includes recovery for various pass-through items, primarily projected fuel cost increases in 2005 and $77 million related to under-recovered fuel costs in 2004 along with projected environmental costs. PEF expects a total of $156 million of under-recovered fuel costs for 2004 as of year end, of which PEF has requested deferral of $79 million until 2006 to mitigate the impact on customers resulting from the need to also recover hurricane-related costs. A decision on PEF’s request is expected from the FPSC at the conclusion of its annual fuel hearing, which began on November 8, 2004. |
| On June 29, 2004, the FPSC approved a Stipulation and Settlement Agreement, executed on April 29, 2004, by PEF, the Office of Public Counsel and the Florida Industrial Power Users Group. The stipulation and settlement resolved the issue pending before the FPSC regarding the costs PEF will be allowed to recover through its Fuel and Purchased Power Cost Recovery clause in 2004 and beyond for waterborne coal deliveries by the Company’s affiliated coal supplier, Progress Fuels Corporation. The settlement sets fixed per ton prices based on point of origin for all waterborne coal deliveries in 2004, and establishes a market-based pricing methodology for determining recoverable waterborne coal transportation costs through a competitive solicitation process or market price proxies in 2005 and thereafter. The settlement reduces the amount that PEF will charge to the Fuel and Purchased Power Cost Recovery clause for waterborne transportation by approximately $13 million beginning in 2004. |
| In March 2002, the parties in PEF’s rate case entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters. The Agreement was approved by the FPSC and is generally effective May 1, 2002 through December 31, 2005; provided, however, that if PEF’s base rate earnings fall below a 10% return on equity, PEF may petition the FPSC to amend its base rates. |
| PEF has determined that additional generating capacity will be required in late 2007 and has requested approval by the FPSC to build an additional unit at PEF’s Hines Complex. On October 28, 2004, the Prehearing Order in the Hines 4 Determination of Need proceeding was issued. The order reflects a stipulation between the FPSC Staff and the Company resolving all issues and agreement that the FPSC should grant an affirmative Determination of Need for the construction of a Hines Unit 4. The stipulation finds that Hines Unit 4 is needed to maintain electric system reliability and integrity and to continue to provide adequate electricity to its ratepayers at a reasonable cost. Hines Unit 4 will be a combined cycle unit with a generating capacity of 461 megawatts (summer rating). The estimated total in-service cost of Hines Unit 4 is $286 million, and the unit is planned for commercial operation in December 2007. If the actual cost is less than the estimate, customers will receive the benefit of such cost under runs. Any costs that exceed this estimate will be not recoverable absent extraordinary circumstances as found by the FPSC in subsequent proceedings. The FPSC approved the final order on November 3, 2004. |
| B. | Regional Transmission Organizations |
| In 2000, the Federal Energy Regulatory Commission (FERC) issued Order 2000 regarding regional transmission organizations (RTOs). This Order set minimum characteristics and functions that RTOs must meet, including independent transmission service. In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. In April 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provides an overview of what the FERC currently intends to include in a final rule in the SMD NOPR docket. The White Paper retains the fundamental and most protested aspects of SMD NOPR, including mandatory RTOs and the FERC’s assertion of jurisdiction over certain aspects of retail service. The FERC has not yet issued a final rule on SMD NOPR. The Company cannot predict the outcome of these matters or the effect that they may have on the GridSouth and GridFlorida proceedings currently ongoing before the FERC. It is unknown what impact the future proceedings will have on the Company’s earnings, revenues or prices. |
| The FPSC ruled in December 2001 that the formation of GridFlorida by the three major investor-owned utilities in Florida, including PEF, was prudent but ordered changes in the structure and market design of the proposed organization. In September 2002, the FPSC set a hearing for market design issues; this order was appealed to the Florida Supreme Court by the consumer advocate of the state of Florida. In June 2003, the Florida Supreme Court dismissed the appeal without prejudice. In September 2003, the FERC held a Joint Technical Conference with the FPSC to consider issues related to formation of an RTO for peninsular Florida. In December 2003, the FPSC ordered further state proceedings and established a collaborative workshop process to be conducted during 2004. In June 2004, the workshop process was abated pending completion of a cost-benefit study currently anticipated to be completed in December 2004 with subsequent action by the FPSC to be determined at that time. |
| The Company has $33 million and $4 million invested in GridSouth and GridFlorida, respectively, related to startup costs at September 30, 2004. The Company expects to recover these startup costs in conjunction with the GridSouth and GridFlorida original structures or in conjunction with any alternate combined transmission structures that emerge. |
| C. | Implementation of SFAS No. 143 |
| In connection with the implementation of SFAS No. 143, “Accounting for Asset Retirement Obligations,” in 2003, PEC filed a request with the NCUC requesting deferral of the difference between expense pursuant to SFAS No. 143 and expense as previously determined by the NCUC. The NCUC granted the deferral of the January 1, 2003 cumulative adjustment. Because the clean air legislation discussed in Note 15 under “Air Quality”contained a prohibition against cost deferrals unless certain criteria are met, the NCUC denied the deferral of the ongoing effects. Therefore, PEC ceased deferral of the ongoing effects during the second quarter for the six months ended June 30, 2003 related to its North Carolina retail jurisdiction. Pre-tax income for the three and six months ended June 30, 2003 increased by approximately $14 million, which represents a decrease in non-ARO cost of removal expense, partially offset by an increase in decommissioning expense. The Company provided additional information to the NCUC that demonstrated that deferral of the ongoing effects should also be allowed. In August 2003, the NCUC revised its decision and approved the deferral of the ongoing effects of SFAS No. 143 at which time the $14 million impact was reversed. |
| D. | FERC Market Power Mitigation |
| A FERC order issued in November 2001 on certain unaffiliated utilities’ triennial market based wholesale power rate authorization updates required certain mitigation actions that those utilities would need to take for sales/purchases within their control areas and required those utilities to post information on their websites regarding their power systems’ status. As a result of a request for rehearing filed by certain market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004, the FERC issued two orders concerning utilities’ ability to sell wholesale electricity at market based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC’s current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. Management is unable to predict the outcome of these actions by the FERC or their effect on future results of operations and cash flows. However, the Company does not anticipate that the current operations of PEC or PEF would be impacted materially if they were unable to sell power at market-based rates in their respective control areas. Due to PEC’s failure of one of the two interim market power screens, on August 12, 2004, PEC notified the FERC that it would revise its Market Based Rate tariff to restrict it to sales outside PEC’s control area and file a new cost based tariff for sales within PEC’s control area that incorporates the FERC’s default cost based rate methodologies for sales of one year or less. PEC anticipates making this filing by year-end. |
7. GOODWILL AND OTHER INTANGIBLE ASSETS
| The Company performed the annual goodwill impairment test in accordance with FASB Statement No. 142, Goodwill and Other Intangible Assets, for the CCO segment in the first quarter of 2004, and the annual goodwill impairment test for the PEC Electric and PEF segments in the second quarter of 2004, each of which indicated no impairment. |
| The changes in the carrying amount of goodwill for the periods ended September 30, 2004 and December 31, 2003, by reportable segment, are as follows: |
| (in millions) | PEC Electric | PEF | CCO | Other | Total | ||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Balance as of January 1, 2003 | $1,922 | $1,733 | $64 | $ — | $ 3,719 | ||||||
| Acquisitions | — | — | — | 7 | 7 | ||||||
| Balance as of December 31, 2003 | $1,922 | $1,733 | $64 | $ 7 | $ 3,726 | ||||||
| Purchase accounting adjustment | — | — | — | (7 | ) | (7 | ) | ||||
| Balance as of September 30, 2004 | $1,922 | $1,733 | $64 | $ — | $ 3,719 | ||||||
| In December 2003, $7 million in goodwill was acquired as part of Progress Telecommunications Corporation’s partial acquisition of EPIK and was reported in the Other segment. As discussed in Note 5, the Company revised the preliminary EPIK purchase price allocation as of September 2004, and the $7 million of goodwill was reallocated to certain tangible assets acquired based on the preliminary results of external appraisals. |
| The gross carrying amount and accumulated amortization of the Company’s intangible assets at September 30, 2004 and December 31, 2003, are as follows: |
| September 30, 2004 | December 31, 2003 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | Gross Carrying Amount |
Accumulated Amortization |
Gross Carrying Amount |
Accumulated Amortization | |||||
| Synthetic fuel intangibles | $134 | $(75 | ) | $140 | $(64 | ) | |||
| Power agreements acquired | 221 | (34 | ) | 221 | (20 | ) | |||
| Other | 63 | (14 | ) | 62 | (12 | ) | |||
| Total | $410 | $(123 | ) | $423 | $(96 | ) | |||
| In June 2004, the Company sold, in two transactions, a combined 49.8 percent partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel operations. Approximately $6 million in synthetic fuel intangibles and $4 million in related accumulated amortization were included in the sale of the partnership interest. |
| All of the Company’s intangibles are subject to amortization. Synthetic fuel intangibles represent intangibles for synthetic fuel technology. These intangibles are being amortized on a straight-line basis until the expiration of tax credits under Section 29 of the Internal Revenue Code (Section 29) in December 2007. The intangibles related to power agreements acquired are being amortized based on the economic benefits of the contracts. Other intangibles are primarily acquired customer contracts and permits that are amortized over their respective lives. |
| Amortization expense recorded on intangible assets for the three months ended September 30, 2004 and 2003 was $10 million and $11 million, respectively. Amortization expense recorded on intangible assets for the nine months ended September 30, 2004 and 2003 was $31 million and $26 million, respectively. The estimated annual amortization expense for intangible assets for 2004 through 2008, in millions, is approximately $41, $34, $35, $35 and $17, respectively. |
8. EQUITY
| A. | Earnings Per Common Share |
| A reconciliation of the weighted-average number of common shares outstanding for basic and dilutive earnings per share purposes is as follows: |
| (in millions) | Three Months Ended September 30 |
Nine Months Ended September 30 | |||||||
|---|---|---|---|---|---|---|---|---|---|
| 2004 | 2003 | 2004 | 2003 | ||||||
| Weighted-average common shares - basic | 243 | 239 | 242 | 236 | |||||
| Restricted stock awards | — | 1 | 1 | 1 | |||||
| Weighted-average shares - fully dilutive | 243 | 240 | 243 | 237 | |||||
| B. | Comprehensive Income |
| Comprehensive income for the three months ended September 30, 2004 and 2003 was $297 million and $338 million, respectively. Comprehensive income for the nine months ended September 30, 2004 and 2003 was $553 million and $696 million, respectively. Changes in other comprehensive income for the periods consisted primarily of changes in the fair value of derivatives used to hedge cash flows related to interest on long-term debt and gas sales. |
9. FINANCING ACTIVITIES
| Between October 19, 2004 and November 1, 2004, Progress Energy and its subsidiaries PEC and PEF borrowed a net total of $535 million ($365 million by Progress Energy; $115 million by PEC; and $55 million by PEF) under certain long-term revolving credit facilities. In addition, PEF and PEC borrowed $170 million and $90 million, respectively, under their short-term credit facilities. Each of these credit facilities contains various cross default and other acceleration provisions. The borrowed funds will be used to pay off maturing commercial paper and for other cash needs. This action was taken due to the uncertain impact on Progress Energy’s, PEC’s, and PEF’s ability to access the commercial paper markets resulting from recent ratings actions taken by Standard and Poor’s (“S&P”) credit rating agency and Moody’s Investor Services (“Moody’s”). |
| On October 19, 2004, S&P changed Progress Energy’s outlook from stable to negative. S&P cited the uncertainties regarding the timing of the recovery of hurricane costs, the Company’s debt reduction plans, and the IRS audit of the Company’s Earthco synthetic fuels facilities as the reasons for the change in outlook. On October 25, 2004, S&P reduced the short-term debt rating of Progress Energy, PEC and PEF to A-3 from A-2, as a result of their change in outlook discussed above. |
| On October 20, 2004, Moody’s changed its outlook for Progress Energy from stable to negative and placed the ratings of PEF under review for possible downgrade. PEC’s ratings were affirmed by Moody’s. |
| Moody’s cited the following reasons for its change in the outlook for Progress Energy: financial ratios that are weak for its current rating category; rising O&M, pension, benefit, and insurance costs; and delays in executing its deleveraging plan. With respect to PEF, Moody’s cited declining cash flow coverages and rising leverage over the last several years; expected funding needs for a large capital expenditure program; risks with regard to its upcoming 2005 rate case and the timing of hurricane cost recovery as reasons for putting its ratings under review. |
| The changes by S&P and Moody’s do not trigger any debt or guarantee collateral requirements, nor do they have any material impact on the overall liquidity of Progress Energy or any of its affiliates. To date, Progress Energy’s, PEC’s, and PEF’s access to the commercial paper markets has not been materially impacted by the rating agencies’ actions. However, the changes are expected to increase the interest rate incurred on its short-term borrowings by 0.25% to 0.875%. |
| Progress Energy’s, PEC’s, and PEF’s long-term credit facilities were arranged through a syndication of financial institutions and support their commercial paper programs. Progress Energy took advantage of favorable market conditions and entered into a new $1.1 billion five year line of credit, effective August 5, 2004, and expiring August 5, 2009. This facility replaced Progress Energy’s $250 million 364 day line of credit and its three year $450 million line of credit, which were both scheduled to expire in November 2004. |
| On July 28, 2004, PEC extended its $165 million 364-day line of credit, which was scheduled to expire on July 29, 2004. The line of credit will expire on July 27, 2005. |
| On July 1, 2004, PEF paid at maturity $40 million 6.69% Medium-Term Notes Series B with commercial paper proceeds and cash from operations. |
| On April 30, 2004, PEC redeemed $35 million of Darlington County 6.6% Series Pollution Control Bonds at 102.5% of par, $2 million of New Hanover County 6.3% Series Pollution Control Bonds at 101.5% of par, and $2 million of Chatham County 6.3% Series Pollution Control Bonds at 101.5% of par with cash from operations. |
| On March 30, 2004, PEF extended its $200 million 364-day line of credit. The line of credit will expire on March 29, 2005. |
| On March 1, 2004, Progress Energy used available cash and proceeds from the issuance of commercial paper to pay at maturity $500 million 6.55% senior unsecured notes. Cash and commercial paper capacity for this retirement was created primarily from proceeds of the sale of assets and long-term debt financings in 2003. |
| On February 9, 2004, Progress Capital Holdings, Inc. paid at maturity $25 million 6.48% medium term notes with available cash from operations. |
| On January 15, 2004, PEC paid at maturity $150 million 5.875% First Mortgage Bonds with commercial paper proceeds. On April 15, 2004, PEC also paid at maturity $150 million 7.875% First Mortgage Bonds with commercial paper proceeds and cash from operations. |
| For the nine months ended September 30, 2004, the Company issued approximately 1.3 million shares of its common stock for approximately $58 million in proceeds from its Investor Plus Stock Purchase Plan and its employee benefit plans. For the quarter ended September 30, 2004, there were no material stock issuances. For the nine months ended September 30, 2004 and 2003, the dividends paid on common stock were approximately $423 million and $403 million, respectively. |
10. BENEFIT PLANS
| The Company and some of its subsidiaries have a non-contributory defined benefit retirement (pension) plan for substantially all full-time employees. The Company also has supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, the Company and some of its subsidiaries provide contributory other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria. The components of the net periodic benefit cost for the three and nine months ended September 30 are: |
| Three Months Ended September 30 | Pension Benefits | Other Postretirement Benefits | |||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Service cost | $ 14 | $ 13 | $ 1 | $ 4 | |||||
| Interest cost | 27 | 27 | 6 | 10 | |||||
| Expected return on plan assets | (41 | ) | (36 | ) | (2 | ) | (1 | ) | |
| Amortization of actuarial (gain) loss | 4 | 10 | 1 | 1 | |||||
| Other amortization, net | — | — | — | 1 | |||||
| Net periodic cost | $ 4 | $ 14 | $ 6 | $ 15 | |||||
| Additional cost / (benefit) recognition (a) | (4 | ) | (6 | ) | 1 | 1 | |||
| Net periodic cost recognized | $ — | $ 8 | $ 7 | $ 16 | |||||
| Nine Months Ended September 30 | Pension Benefits | Other Postretirement Benefits | |||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Service cost | $ 40 | $ 39 | $ 9 | $ 11 | |||||
| Interest cost | 82 | 81 | 23 | 25 | |||||
| Expected return on plan assets | (116 | ) | (108 | ) | (4 | ) | (3 | ) | |
| Amortization of actuarial (gain) loss | 16 | 19 | 3 | 4 | |||||
| Other amortization, net | — | — | 1 | 3 | |||||
| Net periodic cost | $ 22 | $ 31 | $ 32 | $ 40 | |||||
| Additional cost / (benefit) recognition (a) | (12 | ) | (14 | ) | 2 | 1 | |||
| Net periodic cost recognized | $ 10 | $ 17 | $ 34 | $ 41 | |||||
| (a) Due to the acquisition of FPC. See Note 16B of Progress Energy’s Form 10-K for year ended December 31, 2003. |
| The net periodic costs for other postretirement benefits decreased during the three and nine months ended September 30, 2004 due to the implementation of FASB Staff Position 106-2. See discussion in Note 2 to the Progress Energy Consolidated Interim Financial Statements. |
11. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS
| Progress Energy and its subsidiaries are exposed to various risks related to changes in market conditions. The Company has a risk management committee that includes senior executives from various business groups. The risk management committee is responsible for administering risk management policies and monitoring compliance with those policies by all subsidiaries. The Company may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 17 to the financial statements in Item 8 of the Form 10-K for the year ended December 31, 2003. |
| A. | Commodity Derivatives |
| Nonhedging Derivatives |
| Nonhedging derivatives, primarily electricity and natural gas contracts, are entered into for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. |
| Since December 31, 2003, PEF has entered into derivative instruments related to its exposure to price fluctuations on fuel oil purchases. At September 30, 2004, the fair value of these instruments was an $11 million asset position. These instruments receive regulatory accounting treatment. Gains are recorded in regulatory liabilities and losses are recorded in regulatory assets. |
| Cash Flow Hedges |
| Progress Energy’s subsidiaries designate a portion of commodity derivative instruments as cash flow hedges under SFAS No. 133. |
| Progress Fuels periodically enters into derivative instruments to hedge its exposure to price fluctuations on natural gas sales. As of September 30, 2004, Progress Fuels was hedging exposures to the price variability of portions of its natural gas production through December 2005. |
| The fair values of cash flow hedges at September 30, 2004 and December 31, 2003 were as follows: |
| Progress Fuels | |||||
|---|---|---|---|---|---|
| (millions of dollars) | 2004 | 2003 | |||
| Fair value of assets | $ — | $ — | |||
| Fair value of liabilities | (40 | ) | (12 | ) | |
| Fair value, net | $(40 | ) | $(12 | ) | |
| The ineffective portion of commodity cash flow hedges for the three and nine month periods ending September 30, 2004 was not material to the Company’s results of operations. At September 30, 2004, there were $25 million of after-tax deferred losses in accumulated other comprehensive income OCI, of which $21 million are expected to be reclassified to earnings during the next 12 months as the hedged transactions occur. Due to the volatility of the commodities markets, the value in OCI is subject to change prior to its reclassification into earnings. |
| B. | Interest Rate Derivatives – Fair Value or Cash Flow Hedges |
| The Company uses cash flow hedging strategies to hedge variable interest rates on long-term and short-term debt and to hedge interest rates with regard to future fixed-rate debt issuances. The Company uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. |
| The fair values of interest rate hedges at September 30, 2004 and December 31, 2003 were as follows: |
| September 30 | December 31 | ||||
|---|---|---|---|---|---|
| (in millions ) | 2004 | 2003 | |||
| Interest rate cash flow hedges | $(9 | ) | $(6 | ) | |
| Interest rate fair value hedges | $ 8 | $(4 | ) | ||
| Cash Flow Hedges |
| The following table presents selected information related to the Company’s interest rate cash flow hedges included in accumulated OCI at September 30, 2004: |
| Accumulated Other Comprehensive Income/(Loss), net of tax(a) (millions of dollars) |
Portion Expected to be Reclassified to Earnings during the Next 12 Months(b) | ||
|---|---|---|---|
| $(24 | ) | $(6) | |
| (a) includes amounts related to terminated hedges |
| (b) actual amounts that will be reclassified to earnings may vary from the expected amounts presented above as a result of changes in interest rates |
| As of September 30, 2004, PEC had $110 million notional amount of pay-fixed forward swaps to hedge its exposure to interest rates with regard to future issuances of debt and $26 million notional amount of pay-fixed forward starting swaps to hedge its exposure to interest rates with regard to an upcoming railcar lease. All the swaps have a computational period of ten years. The ineffective portion of interest rate cash flow hedges for the three and nine month periods ending September 30, 2004 was not material to the Company’s results of operations. |
| As of September 30, 2004 Progress Ventures, Inc. (PVI) a wholly-owned subsidiary of Progress Energy, had $195 million maximum notional amount of interest rate collars in place to hedge floating interest rate exposure associated with variable-rate long-term debt. PVI is required to hedge 50% of the amount outstanding under its bank facility through March 2007. |
| In May 2004, Progress Energy, Inc. terminated interest rate cash flow hedges, with a total notional amount of $400 million, related to projected outstanding balances of commercial paper. The fair value of the hedges at December 31, 2003 was $5 million. Amounts in accumulated other comprehensive income related to these terminated hedges will be reclassified to earnings as the hedged interest payments occur. |
| Fair Value Hedges |
| As of September 30, 2004, Progress Energy had $500 million notional amount of fixed rate debt swapped to floating rate debt by executing interest rate derivative agreements. These agreements expire on various dates through March 2011. During the nine months ended September 30, 2004 interest rate swap agreements totaling $700 million notional amount were terminated. In November 2004, Progress Energy terminated $350 million notional amount of swaps. The gain or loss on the agreements was deferred and is being amortized over the life of the bonds as these agreements had been designated as fair value hedges for accounting purposes. |
12. FINANCIAL INFORMATION BY BUSINESS SEGMENT
| The Company currently provides services through the following business segments: PEC Electric, PEF, Fuels, CCO, Rail Services and Other. |
| PEC Electric and PEF are primarily engaged in the generation, transmission, distribution and sale of electric energy in portions of North Carolina, South Carolina and Florida. These electric operations are subject to the rules and regulations of the FERC, the NCUC, the SCPSC, the FPSC and the United States Nuclear Regulatory Commission (NRC). These electric operations also distribute and sell electricity to other utilities, primarily on the east coast of the United States. |
| Fuels’operations, which are located throughout the United States, are involved in natural gas drilling and production, coal terminal services, coal mining, synthetic fuel production, fuel transportation and delivery. |
| CCO’s operations, which are located in the southeastern United States, include nonregulated electric generation operations and marketing activities. |
| Rail Services’ operations include railcar repair, rail parts reconditioning and sales, and scrap metal recycling. These activities include maintenance and reconditioning of salvageable scrap components of railcars, locomotive repair and right-of-way maintenance. Rail Services’ operations are located in the United States, Canada and Mexico. |
| The Other segment, whose operations are in the United States, is composed of other nonregulated business areas including telecommunications and energy service operations and other nonregulated subsidiaries that do not separately meet the disclosure requirements of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” |
| In addition to these reportable operating segments, the Company has other corporate activities that include holding company operations, service company operations and eliminations. The profit or loss of the identified segments plus the loss of Corporate represents the Company’s total income from continuing operations before cumulative effect of change in accounting principle. |
| Revenues | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| (in millions) | Unaffiliated | Intersegment | Total | Income from Continuing Operations |
Assets | ||||||
| FOR THE THREE MONTHS | |||||||||||
| ENDED SEPTEMBER 30, 2004 | |||||||||||
| PEC Electric | $1,014 | $ — | $ 1,014 | $ 175 | $10,819 | ||||||
| PEF | 1,029 | — | 1,029 | 140 | 8,005 | ||||||
| Fuels | 332 | 75 | 407 | (36 | ) | 1,112 | |||||
| CCO | 90 | — | 90 | 15 | 1,821 | ||||||
| Rail Services | 291 | — | 291 | 8 | 572 | ||||||
| Other | 19 | — | 19 | — | 300 | ||||||
| Corporate | — | (75 | ) | (75 | ) | 1 | 3,991 | ||||
| Consolidated totals | $2,775 | $ — | $ 2,775 | $ 303 | $26,620 | ||||||
| FOR THE THREE MONTHS | |||||||||
| ENDED SEPTEMBER 30, 2003 | |||||||||
| PEC Electric | $1,010 | $ — | $ 1,010 | $ 160 | |||||
| PEF | 904 | — | 904 | 115 | |||||
| Fuels | 252 | 88 | 340 | 79 | |||||
| CCO | 67 | — | 67 | 13 | |||||
| Rail Services | 210 | — | 210 | 1 | |||||
| Other | 14 | 4 | 18 | (4 | ) | ||||
| Corporate | — | (92 | ) | (92 | ) | (27 | ) | ||
| Consolidated totals | $2,457 | $ — | $ 2,457 | $ 337 | |||||
| Revenues | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | Unaffiliated | Intersegment | Total | Income from Continuing Operations | |||||
| FOR THE NINE MONTHS | |||||||||
| ENDED SEPTEMBER 30, 2004 | |||||||||
| PEC Electric | $2,776 | $ -- | $ 2,776 | $ 388 | |||||
| PEF | 2,673 | -- | 2,673 | 273 | |||||
| Fuels | 928 | 226 | 1,154 | 69 | |||||
| CCO | 196 | -- | 196 | 11 | |||||
| Rail Services | 816 | -- | 816 | 17 | |||||
| Other | 62 | 2 | 64 | (32 | ) | ||||
| Corporate | -- | (228 | ) | (228 | ) | (162 | ) | ||
| Consolidated totals | $7,451 | $ -- | $ 7,451 | $ 564 | |||||
| FOR THE NINE MONTHS | |||||||||
| ENDED SEPTEMBER 30, 2003 | |||||||||
| PEC Electric | $2,752 | $ -- | $ 2,752 | $ 383 | |||||
| PEF | 2,399 | -- | 2,399 | 247 | |||||
| Fuels | 763 | 257 | 1,020 | 175 | |||||
| CCO | 137 | -- | 137 | 23 | |||||
| Rail Services | 601 | -- | 601 | -- | |||||
| Other | 42 | 11 | 53 | (2 | ) | ||||
| Corporate | -- | (268 | ) | (268 | ) | (128 | ) | ||
| Consolidated totals | $6,694 | $ -- | $ 6,694 | $ 698 | |||||
| No single customer accounted for 10% or more of unaffiliated revenues. |
13. OTHER INCOME AND OTHER EXPENSE
| Other income and expense includes interest income and other income and expense items as discussed below. The components of other, net as shown on the accompanying Consolidated Statements of Income are as follows: |
| Three Months Ended September 30 |
Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Other income | |||||||||
| Net financial trading gain | $ 3 | $ — | $ 7 | $ — | |||||
| Nonregulated energy and delivery services income | 6 | 6 | 21 | 19 | |||||
| Contingent value obligations unrealized gain | 20 | — | 7 | — | |||||
| Investment gains | 2 | 1 | 3 | 2 | |||||
| Income from equity investments | 6 | — | 3 | — | |||||
| AFUDC equity | 3 | 2 | 7 | 8 | |||||
| Gain on sale of property | 2 | 1 | 3 | 2 | |||||
| Other | 8 | 12 | 14 | 19 | |||||
| Total other income | $50 | $ 22 | $65 | $ 50 | |||||
| Other expense | |||||||||
| Nonregulated energy and delivery services expenses | $ 5 | $ 5 | $14 | $ 14 | |||||
| Donations | 2 | 3 | 12 | 11 | |||||
| Investment losses | — | 2 | 2 | 12 | |||||
| Contingent value obligations unrealized loss | — | 4 | — | 4 | |||||
| Loss from equity investments | — | 1 | — | 3 | |||||
| Write-off of non-trade receivable | — | — | 7 | — | |||||
| Loss on sale of property | — | 2 | — | 2 | |||||
| Other | 7 | 7 | 19 | 21 | |||||
| Total other expense | $14 | $ 24 | $54 | $ 67 | |||||
| Other, net | $36 | $(2 | ) | $11 | $(17 | ) | |||
| Net financial trading gains and losses represent non-asset-backed trades of electricity and gas. Nonregulated energy and delivery services include power protection services and mass-market programs such as surge protection, appliance services and area light sales, and delivery, transmission and substation work for other utilities. |
14. INCOME TAXES
| In accordance with the provisions of Accounting Principles Board Opinion (APB) No. 28, “Interim Financial Reporting,” GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was decreased by $38 million and $35 million for the three months ended September 30, 2004 and 2003, respectively, in order to maintain an effective tax rate consistent with the estimated annual rate. Income tax expense was increased by $6 million and decreased by $41 million for the nine months ended September 30, 2004 and 2003, respectively. The income tax provisions for the Company differ from amounts computed by applying the Federal statutory tax rate to income before income taxes, primarily due to the recognition of synthetic fuel tax credits. |
| Progress Energy, through its subsidiaries, produces a coal-based solid synthetic fuel. The production and sale of the synthetic fuel from these facilities qualifies for tax credits under Section 29 of the Code (Section 29) if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel and that the fuel was produced from a facility that was placed in service before July 1, 1998. Synthetic fuel tax credit amounts not utilized are carried forward indefinitely as deferred alternative minimum tax credits. The amount of Section 29 credits that the Company is allowed to claim in any calendar year is limited by the amount of the Company’s regular federal income tax liability. Because of the substantial costs the Company incurred from damage attributable to hurricanes in August through September 2004, the Company’s regular federal income tax liability for 2004 will be significantly reduced. Based on the revised projections of 2004 taxable income, the Company has generated more Section 29 credits through September 30, 2004 than it currently estimates are allowable for calendar year 2004. As a result, the Company recorded a charge of $79 million in September 2004 related to previously recognized Section 29 credits that it anticipates cannot be used. |
15. COMMITMENTS AND CONTINGENCIES
| Contingencies and significant changes to the commitments discussed in Note 21 of the Company’s 2003 Annual Report on Form 10-K are described below. |
| A. | Guarantees |
| As a part of normal business, Progress Energy and certain wholly-owned subsidiaries enter into various agreements providing future financial or performance assurances to third parties, which are outside the scope of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). Such agreements include guarantees, standby letters of credit and surety bonds. At September 30, 2004, management does not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Consolidated Balance Sheets. |
| At September 30, 2004, the Company had issued guarantees on behalf of third parties with a maximum exposure of approximately $10 million. These guarantees support synthetic fuel operations. |
| In connection with the sale of partnership interests in Colona (see Note 4A), Progress Fuels indemnified the buyers against any claims related to Colona resulting from violations of any environmental laws. Although the terms of the agreement provide for no limitation to the maximum potential future payments under the indemnification, the Company has estimated that the maximum total of such payments would not be material. |
| B. | Insurance |
| Both PEC and PEF are insured against public liability for a nuclear incident up to $10.8 billion per occurrence. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear power plants, each company, as an owner of nuclear units, can be assessed a portion of any third-party liability claims arising from an accident at any commercial nuclear power plant in the United States. In the event that public liability claims from an insured nuclear incident exceed $300 million (currently available through commercial insurers), each company would be subject to assessments of up to $101 million for each reactor owned per occurrence. Payment of such assessments would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Congress is considering revisions to the Price Anderson Act that could include increased limits and assessments per reactor owned. The final outcome of this matter cannot be predicted at this time. |
| PEC and PEF self-insure their transmission and distribution lines against loss due to storm damage and other natural disasters. PEF accrues $6 million annually to a storm damage reserve pursuant to a regulatory order and may defer losses in excess of the reserve. See Note 3 to the Progress Energy Consolidated Financial Statements for discussion of major storms and related impact. |
| C. | Claims and Uncertainties |
| The Company is subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters. Reference is made to Note 21E to the financial statements in Item 8 of the Form 10-K for the year ended December 31, 2003. |
| Hazardous and Solid Waste Management |
| Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. PEC and PEF are potentially responsible parties (PRPs) at several manufactured gas plant (MGP) sites. In addition, the Company and its subsidiaries are periodically notified by regulators including the EPA and various state agencies of their involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. A discussion of these sites by legal entity follows. |
| PEC, PEF and Progress Fuels Corporation have filed claims with the Company’s general liability insurance carriers to recover costs arising from actual or potential environmental liabilities. Some claims have been settled and others are still pending. While the Company cannot predict the outcome of these matters, the outcome is not expected to have a material effect on the consolidated financial position or results of operations. |
| The Company is also currently in the process of assessing potential costs and exposures at other sites. As the assessments are developed and analyzed, the Company will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated. |
| PEC. There are nine former MGP sites and other sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. PEC received insurance proceeds to address costs associated with environmental liabilities related to its involvement with some sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. At December 31, 2003, the balance in the fund was $9 million. During the nine months ended September 30, 2004, PEC spent approximately $2 million related to environmental remediation. The remaining balance in the fund at September 30, 2004 was $7 million. At September 30, 2004, PEC had an accrual of $9 million recorded for environmental liabilities, which includes $2 million transferred from NCNG at the time of the sale of NCNG. PEC is unable to provide an estimate of the reasonably possible total remediation costs beyond what is currently accrued due to the fact that investigations have not been completed at all sites. This accrual has been recorded on an undiscounted basis. PEC measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. PEC will accrue costs for the sites to the extent its liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached to the stage where a reasonable estimate of the remediation costs can be made, PEC cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is anticipated that sufficient information will become available for several sites during 2005 to allow a reasonable estimate of PEC’s obligation for those sites to be made. |
| PEF. At September 30, 2004, PEF has accrued $27 million for probable and estimable costs related to various environmental sites. Of this accrual, $17 million is for costs associated with the remediation of distribution and substation transformers for which PEF has received approval from the FPSC for recovery through the Environmental Cost Recovery Clause (ECRC). The remaining $10 million is related to two former MGP sites and other sites associated with PEF that have required or are anticipated to require investigation and/or remediation costs. At December 31, 2003, the accrual balance for costs associated with the remediation of distribution transformers was $12 million. For the nine months ended September 30, 2004, PEF accrued an additional $8 million and spent approximately $3 million related to the remediation of transformers and recorded a regulatory asset for the probable recovery through the ECRC. |
| These accruals have been recorded on an undiscounted basis. PEF measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. This process often includes assessing and developing cost-sharing arrangements with other PRPs. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet advanced to the stage where a reasonable estimate of the remediation costs can be made, at this time PEF is unable to provide an estimate of its obligation to remediate these sites beyond what is currently accrued. As more activity occurs at these sites, PEF will assess the need to adjust the accruals. It is anticipated that sufficient information will be become available in 2005 to make a reasonable estimate of PEF’s obligation for one of these MGP sites. |
| The Florida Legislature passed the risk-based corrective action (RBCA, known as Global RBCA) legislation in the 2003 regular session. Risk-based corrective action generally means that the corrective action prescribed for contaminated sites can correlate to the level of human health risk imposed by the contamination at the property. The Global RBCA law expands the use of the risk-based corrective action to all contaminated sites in the state that are not currently in one of the state’s waste cleanup programs. Over the past 18 months, the Florida Department of Environmental Protection (FDEP) has been in the process of developing the rules required by the RBCA statute, holding meetings with interested stakeholders and hosting public workshops. The rules have the potential for making future clean-ups in Florida more costly to complete. The FDEP has not yet announced its schedule to submit its rule for adoption. The Company cannot predict the outcome of this matter. |
| Florida Progress Corporation (FPC). In 2001, FPC sold its Inland Marine Transportation business operated by MEMCO Barge Line, Inc. to AEP Resources, Inc. FPC established an accrual to address indemnities and retained an environmental liability associated with the transaction. FPC estimates that its contractual liability to AEP Resources, Inc., associated with Inland Marine Transportation, is $4 million at September 30, 2004 and has accrued such amount. The previous accrual of $10 million was reduced in 2003 based on a change in estimate. This accrual has been determined on an undiscounted basis. FPC measures its liability for this site based on estimable and probable remediation scenarios. |
| Certain historical sites exist that are being addressed voluntarily by FPC. An immaterial accrual has been established to address investigation expenses related to these sites. The Company cannot determine the total costs that may be incurred in connection with these sites. |
| Rail. Rail Services is voluntarily addressing certain historical waste sites. The Company cannot determine the total costs that may be incurred in connection with these sites. |
| Air Quality |
| There has been and may be further proposed legislation requiring reductions in air emissions for NOx, SO2, carbon dioxide and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs which could be material to the Company’s consolidated financial position or results of operations. Control equipment that will be installed on North Carolina fossil generating facilities as part of the North Carolina legislation discussed below may address some of the issues outlined above. However, the Company cannot predict the outcome of this matter. |
| The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The Company was asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. The EPA initiated civil enforcement actions against other unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements calling for expenditures by these unaffiliated utilities, ranging from $1.0 billion to $1.4 billion. A utility that was not subject to a civil enforcement action settled its New Source Review issues with the EPA for $300 million. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related cost through rate adjustments or similar mechanisms. The Company cannot predict the outcome of this matter. |
| In 2003, the EPA published a final rule addressing routine equipment replacement under the New Source Review program. The rule defines routine equipment replacement and the types of activities that are not subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The rule was challenged in the Federal Appeals Court and its implementation stayed. In July 2004, the EPA announced it will reconsider certain issues arising from the final routine equipment replacement rule. Reconsideration does not impact the court-approved stay. The agency had indicated its plans to issue a final decision on these reconsidered issues by year-end. The Company cannot predict the outcome of this matter. |
| In 1998, the EPA published a final rule under Section 110 of the Clean Air Act addressing the regional transport of ozone (NOx SIP Call). Total capital expenditures to meet the requirements of the NOx SIP Call Rule in North and South Carolina could reach approximately $370 million, which has not been adjusted for inflation. The Company has spent approximately $284 million to date related to these projected amounts. Increased operation and maintenance costs relating to the NOx SIP Call are not expected to be material to the Company’s results of operations. Further controls are anticipated as electricity demand increases. |
| In 1997, the EPA issued final regulations establishing a new 8-hour ozone standard. In April 2004, the EPA identified areas that do not meet the standard. The states with identified areas, including North and South Carolina, are proceeding with the implementation of the federal 8-hour ozone standard. Both states promulgated final regulations, which will require PEC to install NOx controls under the states’ programs to comply with the 8-hour standard. The costs of those controls are included in the $370 million cost estimate above. However, further technical analysis and rulemaking may result in a requirement for additional controls at some units. The Company cannot predict the outcome of this matter. |
| In June 2002, legislation was enacted in North Carolina requiring the state’s electric utilities to reduce the emissions of NOx and SO2 from coal-fired power plants. Progress Energy projects that its capital costs to meet these emission targets will total over $800 million by the end of 2013. PEC has expended approximately $69 million of these capital costs through September 30, 2004. PEC currently has approximately 5,100 MW of coal-fired generation capacity in North Carolina that is affected by this legislation. The law requires the emissions reductions to be completed in phases by 2013, and applies to each utility’s total system rather than setting requirements for individual power plants. The law also freezes the utilities’ base rates for five years unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return established and found reasonable by the NCUC in the utilities’ last general rate case. Further, the law allows the utilities to recover from their retail customers the projected capital costs during the first seven years of the ten-year compliance period beginning on January 1, 2003. The utilities must recover at least 70% of their projected capital costs during the five-year rate freeze period. PEC recognized amortization of $20 million for the quarter ended September 30, 2004. No amortization was recognized in the quarter ended September 30, 2003. PEC recognized amortization of $50 million and $54 million in the nine months ended September 30, 2004 and 2003, respectively, and has recognized $124 million in cumulative amortization through September 30, 2004. Pursuant to the law, PEC entered into an agreement with the State of North Carolina to transfer to the State certain NOx and SO2 emissions allowances that result from compliance with the collective NOx and SO2 emissions limitations set out in the law. The law also requires the State to undertake a study of mercury and carbon dioxide emissions in North Carolina. Operation and maintenance costs will increase due to the additional personnel, materials and general maintenance associated with the equipment. Operation and maintenance expenses are recoverable through base rates, rather than as part of this program. Progress Energy cannot predict the future regulatory interpretation, implementation or impact of this law. |
| In 1997, the EPA’s Mercury Study Report and Utility Report to Congress concluded that mercury is not a risk to the average person in America and expressed uncertainty about whether reductions in mercury emissions from coal-fired power plants would reduce human exposure. Nevertheless, the EPA determined in 2000 that regulation of mercury emissions from coal-fired power plants was appropriate. In 2003, the EPA proposed alternative control plans that would limit mercury emissions from coal-fired power plants. The first, a Maximum Achievable Control Technology (MACT) standard applicable to every coal-fired plant, would require compliance in 2008. The second, which the EPA has stated it prefers, is a mercury cap and trade program that would require limits to be met in two phases, in 2010 and 2018. The EPA expects to finalize the mercury rule in March 2005. Achieving compliance with the proposal could involve significant capital costs that could be material and adverse to the Company’s consolidated financial position or results of operations. The Company cannot predict the outcome of this matter. |
| In conjunction with the proposed mercury rule, the EPA proposed a MACT standard to regulate nickel emissions from residual oil-fired units. The agency estimates the proposal will reduce national nickel emissions to approximately 103 tons. As proposed, the rule may require the company to install additional pollution controls on its residual oil-fired units, resulting in significant capital expenditures. PEC’s oil-fired units have pollution controls in place, which would meet the proposed requirements of the nickel rule. The EPA expects to finalize the nickel rule in March 2005. Compliance costs will be determined once the rule is finalized. |
| In December 2003, the EPA released its proposed Interstate Air Quality Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The EPA’s proposal requires 28 jurisdictions, including North Carolina, South Carolina, Georgia and Florida, to further reduce NOx and SO2 emissions in order to attain preset state NOx and SO2 emissions levels. The rule is expected to become final by the end of 2004. The air quality controls already installed for compliance with the NOx SIP Call and currently planned by the Company to comply with the North Carolina Clean Smokestacks Act will reduce the costs required to meet the CAIR requirements for the Company’s North Carolina units. Additional compliance costs will be determined once the rule is finalized. |
| In March 2004, the North Carolina Attorney General filed a petition with the EPA under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in thirteen other states, including South Carolina to reduce their NOx and SO2 emissions. The state of North Carolina contends these out-of-state polluters are interfering with North Carolina’s ability to meet national air quality standards for ozone and particulate matter. The EPA has not made a determination on the Section 126 petition, and the Company cannot predict the outcome of this matter. |
| Water Quality |
| As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams may be generated at the affected facilities. Integration of these new wastewater streams into the existing wastewater treatment processes may result in permitting, construction and treatment requirements imposed on PEC and PEF in the immediate and extended future. |
| After many years of litigation and settlement negotiations the EPA adopted regulations in February 2004 to implement Section 316(b) of the Clean Water Act. These regulations became effective September 7, 2004. The purpose of these regulations is to minimize adverse environmental impacts caused by cooling water intake structures and intake systems. Over the next several years these regulations will impact the larger base load generation facilities and may require the facilities to mitigate the effects to aquatic organisms by constructing intake modifications or undertaking other restorative activities. The Company currently estimates that from 2005 through 2009 the range of its expenditures to meet the Section 316(b) requirements of the Clean Water Act will be $85 million to $115 million. The range includes $20 million to $30 million at PEC and $65 million to $85 million at PEF. |
| Other Environmental Matters |
| The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. Russia recently announced its intent to ratify the Protocol, which would allow the treaty to enter into force. The United States has not adopted the Kyoto Protocol, and the Bush administration has stated it favors voluntary programs. A number of carbon dioxide emissions control proposals have been advanced in Congress and by the Bush administration. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to the Company’s consolidated financial position or results of operations if associated costs of control or limitation cannot be recovered from customers. The Company favors the voluntary program approach recommended by the administration and is evaluating options for the reduction, avoidance and sequestration of greenhouse gases. However, the Company cannot predict the outcome of this matter. |
| Other Contingencies |
| 1. As required under the Nuclear Waste Policy Act of 1982, PEC and PEF each entered into a contract with the United States Department of Energy (DOE) under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract. |
| In 1995, the DOE issued a final interpretation that it did not have an unconditional obligation to take spent nuclear fuel by January 31, 1998. In Indiana Michigan Power v. DOE, the Court of Appeals vacated the DOE’s final interpretation and ruled that the DOE had an unconditional obligation to begin taking spent nuclear fuel. The Court did not specify a remedy because the DOE was not yet in default. |
| After the DOE failed to comply with the decision in Indiana Michigan Power v. DOE, a group of utilities petitioned the Court of Appeals in Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to begin taking spent nuclear fuel by January 31, 1998. The DOE took the position that their delay was unavoidable, and the DOE was excused from performance under the terms and conditions of the contract. The Court of Appeals found that the delay was not unavoidable, but did not order the DOE to begin taking spent nuclear fuel, stating that the utilities had a potentially adequate remedy by filing a claim for damages under the contract. |
| After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a group of utilities filed a motion with the Court of Appeals to enforce the mandate in NSP v. DOE. Specifically, this group of utilities asked the Court to permit the utilities to escrow their waste fee payments, to order the DOE not to use the waste fund to pay damages to the utilities, and to order the DOE to establish a schedule for disposal of spent nuclear fuel. The Court denied this motion based primarily on the grounds that a review of the matter was premature, and that some of the requested remedies fell outside of the mandate in NSP v. DOE. |
| Subsequently, a number of utilities each filed an action for damages in the Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal Circuit) ruled that utilities may sue the DOE for damages in the Federal Court of Claims instead of having to file an administrative claim with the DOE. |
| In January 2004, PEC and PEF filed a complaint with the DOE claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from various Progress Energy facilities on or before January 31, 1998. Damages due to DOE’s breach will likely exceed $100 million. Similar suits have been initiated by over two dozen other utilities. |
| In July 2002, Congress passed an override resolution to Nevada’s veto of DOE’s proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nevada. DOE plans to submit a license application for the Yucca Mountain facility by the end of 2004. In November 2003, Congressional negotiators approved $580 million for fiscal year 2004 for the Yucca Mountain project, $123 million more than the previous year. In January 2003, the State of Nevada, Clark County, Nevada, and the City of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the Congressional override resolution. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period. The DOE continues to state it plans to begin operation of the repository at Yucca Mountain in 2010. PEC and PEF cannot predict the outcome of this matter. |
| With certain modifications and additional approval by the NRC including the installation of onsite dry storage facilities at Robinson (2005) and Brunswick (2010), PEC’s spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on PEC’s system through the expiration of the operating licenses for all of PEC’s nuclear generating units. |
| PEF is currently storing spent nuclear fuel onsite in spent fuel pools. PEF’s nuclear unit, Crystal River Unit No. 3 (CR3), has sufficient storage capacity in place for fuel consumed through the end of the expiration of the current license in 2016. PEF will seek renewal of the CR3 operating license and if approved, additional dry storage will be necessary in 2014. |
| 2. In November 2001, Strategic Resource Solutions Corp. (SRS) filed a claim against the San Francisco Unified School District (the District) and other defendants claiming that SRS is entitled to approximately $10 million in unpaid contract payments and delay and impact damages related to the District’s $30 million contract with SRS. In March 2002, the District filed a counterclaim, seeking compensatory damages and liquidated damages in excess of $120 million, for various claims, including breach of contract and demand on a performance bond. SRS asserted defenses to the District’s claims. SRS amended its claims and asserted new claims against the District and other parties, including a former SRS employee and a former District employee. |
| In March 2003, the City Attorney and the District filed new claims in the form of a cross-complaint against SRS, Progress Energy, Inc., Progress Energy Solutions, Inc., and certain individuals, alleging fraud, false claims, violations of California statutes, and seeking compensatory damages, punitive damages, liquidated damages, treble damages, penalties, attorneys’ fees and injunctive relief. The filing stated that the City and the District seek “more than $300 million in damages and penalties.” PEC was later added as a cross-defendant. |
| In June 2004, the Company reached a settlement agreement with the District in this matter. The settlement totaled $43 million and is included in diversified business cost of sales in the accompanying Consolidated Statement of Income for the nine months ended September 30, 2004. The accrual of the settlement was recorded on an undiscounted basis. The terms of the settlement require SRS to pay the District $10 million upon approval in September 2004, and an additional $16 million in 2005 and $17 million in 2006. In addition, during a transition period ending September 10, 2004, SRS provided maintenance and training on the equipment and software it installed and maintained for the District. The agreement settles all claims and cross-claims related to SRS, Progress Energy, Progress Energy Solutions and PEC. |
| 3. In 2001, PEC entered into a contract to purchase coal from Dynegy Marketing and Trade (DMT). After DMT experienced financial difficulties, including credit ratings downgrades by certain credit reporting agencies, PEC requested credit enhancements in accordance with the terms of the coal purchase agreement in July 2002. When DMT did not offer credit enhancements, as required by a provision in the contract, PEC terminated the contract in July 2002. |
| PEC initiated a lawsuit seeking a declaratory judgment that the termination was lawful. DMT counterclaimed, stating the termination was a breach of contract and an unfair and deceptive trade practice. On March 23, 2004, the United States District Court for the Eastern District of North Carolina ruled that PEC was liable for breach of contract, but ruled against DMT on its unfair and deceptive trade practices claim. On April 6, 2004, the Court entered a judgment against PEC in the amount of approximately $10 million. The Court did not rule on DMT’s request under the contract for pending legal costs. |
| On May 4, 2004, PEC authorized its outside counsel to file a notice of appeal of the April 6, 2004, judgment and on May 7, 2004, the notice of appeal was filed with the United States Court of Appeals for the Fourth Circuit. On June 8, 2004, DMT filed a motion to dismiss the appeal on the ground that PEC’s notice of appeal should have been filed on or before May 6, 2004. On June 16, 2004, PEC filed a motion with the trial court requesting an extension of the deadline for the filing of the notice of appeal. By order dated September 10, 2004, the trial court denied the extension request. On September 15, 2004, PEC filed a notice of appeal of the September 10, 2004 order and by order dated September 29, 2004, the appellate court consolidated the first and second appeals. DMT’s motion to dismiss the first appeal remains pending. |
| PEC recorded a liability for the judgment of approximately $10 million and a regulatory asset for the probable recovery through its fuel adjustment clause in the first quarter of 2004. The Company cannot predict the outcome of this matter. |
| 4. On February 1, 2002, the Company filed a complaint with the Surface Transportation Board (STB) challenging the rates charged by Norfolk Southern Railway Company (Norfolk Southern) for coal transportation to certain generating plants. In a decision dated December 2003, the STB found that the rates were unreasonable and awarded reparations of $23 million and prescribed a methodology to determine maximum rates. Both parties petitioned for reconsideration of the December 2003 decision. On October 20, 2004, the STB reversed its December 2003 decision and concluded that the rates charged by Norfolk Southern were not unreasonable. The Company is in the process of evaluating future actions, which may include an application to the STB to phase in the new rates, or a judicial appeal. As of September 30, 2004, the Company has accrued a liability of $39 million, to return the reparations of $23 million, which was originally recorded as a regulatory liability, and accrue additional 2004 expenses of $16 million, of which $14 million, has been allocated to retail customers and recorded as deferred fuel cost while the remaining $2 million attributable to wholesale customers has been charged to fuel used in electric generation. |
| 5. The Company, through its subsidiaries, is a majority owner in five entities and a minority owner in one entity that owns facilities that produce synthetic fuel as defined under the Internal Revenue Code (Code). The production and sale of the synthetic fuel from these facilities qualifies for tax credits under Section 29 if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel and that the fuel was produced from a facility that was placed in service before July 1, 1998. The amount of Section 29 credits that the Company is allowed to claim in any calendar year is limited by the amount of the Company's regular federal income tax liability. Synthetic fuel tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits. All entities have received private letter rulings (PLRs) from the Internal Revenue Service (IRS) with respect to their synthetic fuel operations. The PLRs do not limit the production on which synthetic fuel credits may be claimed. Total Section 29 credits generated to date (including those generated by FPC prior to its acquisition by the Company) are approximately $1.4 billion, of which $669 million has been used and $700 million are being carried forward as deferred alternative minimum tax credits. Also $79 million has not been recognized due to the decrease in tax liability from the 2004 hurricane damage. The current Section 29 tax credit program expires at the end of 2007. |
| Impact of Hurricanes |
| For the nine-month period ended September 30, 2004, the Company’s synthetic fuel facilities have sold 7.7 million tons of synthetic fuel which generated an estimated $204 million of Section 29 tax credits. Due to the anticipated decrease in the Company’s tax liability as a result of the 2004 hurricanes, the Company estimates that it will be able to use in 2004 or carry forward to future years only $125 million of these Section 29 tax credits. As a result, the Company has recorded a charge of $79 million related to Section 29 tax credits. The Company is currently evaluating its options for mitigating some or all of this loss of tax credits. |
| Pre-Filing Agreement Program |
| In September 2002, all of Progress Energy’s majority-owned synthetic fuel entities were accepted into the IRS’s Pre-Filing Agreement (PFA) program. The PFA program allows taxpayers to voluntarily accelerate the IRS exam process in order to seek resolution of specific issues. Either the Company or the IRS can withdraw from the program at any time, and issues not resolved through the program may proceed to the next level of the IRS exam process. |
| In February 2004, subsidiaries of the Company finalized execution of the Colona Closing Agreement with the IRS concerning their Colona synthetic fuel facilities. The Colona Closing Agreement provided that the Colona facilities were placed in service before July 1, 1998, which is one of the qualification requirements for tax credits under Section 29. The Colona Closing Agreement further provides that the fuel produced by the Colona facilities in 2001 is a “qualified fuel” for purposes of the Section 29 tax credits. This action concluded the IRS PFA program with respect to Colona. |
| In July 2004, Progress Energy was notified that the Internal Revenue Service (IRS) field auditors anticipate taking an adverse position regarding the placed-in-service date of the Company’s four Earthco synthetic fuel facilities. Due to the auditors’ position, the IRS has decided to exercise its right to withdraw from the Pre-Filing Agreement (PFA) program with Progress Energy. With the IRS’s withdrawal from the PFA program, the review of Progress Energy’s Earthco facilities is back on the normal procedural audit path of the Company’s tax returns. Through September 30, 2004, the Company, on a consolidated basis, has used or carried forward $1 billion of tax credits generated by Earthco facilities. If these credits were disallowed, the Company’s one time exposure for cash tax payments would be $286 million (excluding interest), and earnings and equity would be reduced by $1 billion, excluding interest. Progress Energy’s $1.13 billion credit facility includes a covenant which limits the maximum debt-to-total capital ratio to 65%. This ratio includes other forms of indebtedness such as guarantees issued by PGN, letters of credit and capital leases. As of September 30, 2004, the Company’s debt-to-total impact was 60.6% based on the credit agreement definition for this ratio. The impact on this ratio of reversing $1 billion of tax credits and paying $286 million for taxes would be to increase the ratio to 64.4%. |
| On October 29, 2004, Progress Energy received the IRS field auditors’ report concluding that the Earthco facilities had not been placed in service before July 1, 1998, and that the tax credits generated by those facilities should be disallowed. The Company disagrees with the field audit team’s factual findings and believes that the Earthco facilities were placed in service before July 1, 1998. The Company also believes that the report applies an inappropriate legal standard concerning what constitutes “placed in service”. The Company intends to contest the field auditors’ findings and their proposed disallowance of the tax credits. |
| Because of the stark disagreement between the Company and the field auditors as to the proper legal standard to apply, the Company believes that it is appropriate to have this issue reviewed by the National Office of the IRS, just as the National Office reviewed the issues involving chemical change. The Company could go directly to the Appeals section of the IRS, but it believes that clarification on the critical legal disagreements would help to resolve this matter. At this point, however, the Company does not know if the field auditors will agree to present this matter to the National Office. The Company believes that the appeals process, including proceedings before the National Office, could take up to two years to complete, however, it cannot control the actual timing of resolution and cannot predict the outcome of this matter. |
| In management’s opinion, the Company is complying with all the necessary requirements to be allowed such credits under Section 29, and, although it cannot provide certainty, it believes that it will prevail in these matters. Accordingly, while the Company has adjusted its synthetic fuel production for 2004 in response to the effects of the hurricane damage on its 2004 tax liability, it has no current plans to alter its synthetic fuel production schedule for future years as a result of the IRS field auditors’report. However, should the Company fail to prevail in these matters, there could be material liability for previously taken Section 29 tax credits, with a material adverse impact on earnings and cash flows. |
| In July 2004, the FASB stated that it plans to issue an exposure draft of a proposed interpretation of SFAS No. 109, “Accounting for Income Taxes”, that would address the accounting for uncertain tax positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the financial statements. The exposure draft is expected to be issued in the fourth quarter of 2004. The Company cannot predict what actions the FASB will take or how any such actions might ultimately affect the Company’s financial position or results of operations, but such changes could have a material impact on the Company’s evaluation and recognition of Section 29 tax credits. |
| Permanent Subcommittee |
| In October 2003, the United States Senate Permanent Subcommittee on Investigations began a general investigation concerning synthetic fuel tax credits claimed under Section 29. The investigation is examining the utilization of the credits, the nature of the technologies and fuels created, the use of the synthetic fuel and other aspects of Section 29 and is not specific to the Company’s synthetic fuel operations. Progress Energy is providing information in connection with this investigation. The Company cannot predict the outcome of this matter. |
| Sale of Partnership Interest |
| In June 2004, the Company through its subsidiary, Progress Fuels sold, in two transactions, a combined 49.8 percent partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gain from the sales will be recognized on a cost recovery basis. The Company’s book value of the interests sold totaled approximately $5 million. Based on projected production and tax credit levels, the Company anticipates receiving total gross proceeds of $10 million in 2004, approximately $30 million per year from 2005 through 2007 and approximately $9 million through the second quarter of 2008. In the event that the synthetic fuel tax credits from the Colona facility are reduced, including an increase in the price of oil which could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted. |
| Under the agreements, the buyers had a right to unwind the transactions if an IRS reconfirmation private letter ruling (PLR) was not received by October 15, 2004. The reconfirmation PLR was received in September 2004. An immaterial gain was recorded for the three months ended September 30, 2004. |
| Impact of Crude Oil Prices |
| Although the Internal Revenue Code Section 29 tax credit program is expected to continue through 2007, recent unprecedented and unanticipated increases in the price of oil could limit the amount of those credits or eliminate them altogether for one or more of the years following 2004. This possibility is due to a provision of Section 29 that provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the “Annual Average Price”) exceeds a certain threshold value (the “Threshold Price”), the amount of Section 29 tax credits are reduced for that year. Also, if the Annual Average Price increases high enough (the “Phase Out Price”), the Section 29 tax credits are eliminated for that year. For 2003, the Threshold Price was $50.14 per barrel and the Phase Out Price was $62.94 per barrel. The Threshold Price and the Phase Out Price are adjusted annually for inflation. |
| If the Annual Average Price falls between the Threshold Price and the Phase Out Price for a year, the amount by which Section 29 tax credits are reduced will depend on where the Average Annual Price falls in that continuum. For example, for 2003, if the Annual Average Price had been $56.54 per barrel, there would have been a 50% reduction in the amount of Section 29 tax credits for that year. |
| The Secretary of the Treasury calculates the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the Energy Information Agency (EIA). Because the EIA publishes its information on a three month lag, the Secretary of the Treasury finalizes its calculations three months after the year in question ends. Thus, the Annual Average Price for calendar year 2003 was published in April 2004. |
| Although the official notice for 2004 is not expected to be published until April of 2005, the Company does not believe that the Annual Average Price for 2004 will reach the Threshold Price for 2004. Even with oil prices at historic highs, oil prices would have to experience a significant and sustained increase for the remainder of the year for the Annual Average Price to approach the anticipated Threshold Price. Consequently, the Company does not expect the amount of its 2004 Section 29 tax credits to be adversely affected by oil prices. |
| The Company cannot predict with any certainty the Annual Average Price for 2005 or beyond. Therefore, it cannot predict whether the price of oil will have a material effect on its synthetic fuel business after 2004. However, if during 2005 through 2007, oil prices remain at historically high levels or increase, the Company’s synthetic fuel business may be adversely affected for those years and, depending on the magnitude of such increases in oil prices, the adverse affect for those years could be material and could have an impact on the Company’s synthetic fuel production plans. |
| 6. The Company and its subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, accruals and disclosures have been made in accordance with SFAS No. 5, “Accounting for Contingencies,” to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on the Company’s consolidated results of operations or financial position. |
UNAUDITED CONSOLIDATED STATEMENTS of INCOME
| Three Months Ended September 30 |
Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Operating Revenues | |||||||||
| Electric | $ 1,014 | $ 1,010 | $ 2,776 | $ 2,752 | |||||
| Diversified business | — | 2 | 1 | 8 | |||||
| Total Operating Revenues | 1,014 | 1,012 | 2,777 | 2,760 | |||||
| Operating Expenses | |||||||||
| Fuel used in electric generation | 220 | 234 | 637 | 637 | |||||
| Purchased power | 96 | 98 | 238 | 240 | |||||
| Operation and maintenance | 197 | 205 | 632 | 605 | |||||
| Depreciation and amortization | 139 | 135 | 393 | 416 | |||||
| Taxes other than on income | 44 | 45 | 132 | 124 | |||||
| Diversified business | — | — | — | 3 | |||||
| Total Operating Expenses | 696 | 717 | 2,032 | 2,025 | |||||
| Operating Income | 318 | 295 | 745 | 735 | |||||
| Other Income (Expense) | |||||||||
| Interest income | — | 1 | 2 | 4 | |||||
| Other, net | 7 | (4 | ) | (1 | ) | (14 | ) | ||
| Total Other Income (Expense) | 7 | (3 | ) | 1 | (10 | ) | |||
| Interest Charges | |||||||||
| Interest charges | 50 | 47 | 146 | 145 | |||||
| Allowance for borrowed funds used during construction | (1 | ) | 1 | (2 | ) | (1 | ) | ||
| Total Interest Charges, Net | 49 | 48 | 144 | 144 | |||||
| Income before Income Tax | 276 | 244 | 602 | 581 | |||||
| Income Tax Expense | 101 | 87 | 216 | 200 | |||||
| Net Income | $ 175 | $ 157 | $ 386 | $ 381 | |||||
| Preferred Stock Dividend Requirement | 1 | 1 | 2 | 2 | |||||
| Earnings for Common Stock | $ 174 | $ 156 | $ 384 | $ 379 | |||||
See Notes to Consolidated Interim Financial Statements.
CAROLINA
POWER & LIGHT COMPANY
d/b/a
PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED
CONSOLIDATED BALANCE SHEETS
| (in millions) | September 30 | December 31 | |||
|---|---|---|---|---|---|
| ASSETS | 2004 | 2003 | |||
| Utility Plant | |||||
| Utility plant in service | $ 13,563 | $ 13,331 | |||
| Accumulated depreciation | (5,499 | ) | (5,306 | ) | |
| Utility plant in service, net | 8,064 | 8,025 | |||
| Held for future use | 5 | 5 | |||
| Construction work in progress | 297 | 306 | |||
| Nuclear fuel, net of amortization | 169 | 159 | |||
| Total Utility Plant, Net | 8,535 | 8,495 | |||
| Current Assets | |||||
| Cash and cash equivalents | 18 | 238 | |||
| Accounts receivable | 266 | 265 | |||
| Unbilled accounts receivable | 135 | 145 | |||
| Receivables from affiliated companies | 39 | 27 | |||
| Inventory | 381 | 348 | |||
| Deferred fuel cost | 170 | 113 | |||
| Prepayments and other current assets | 69 | 82 | |||
| Total Current Assets | 1,078 | 1,218 | |||
| Deferred Debits and Other Assets | |||||
| Regulatory assets | 498 | 477 | |||
| Nuclear decommissioning trust funds | 554 | 505 | |||
| Miscellaneous other property and investments | 166 | 169 | |||
| Other assets | 135 | 118 | |||
| Total Deferred Debits and Other Assets | 1,353 | 1,269 | |||
| Total Assets | $ 10,966 | $ 10,982 | |||
| CAPITALIZATION AND LIABILITIES | |||||
| Common Stock Equity | |||||
| Common stock without par value, authorized 200 million shares, | |||||
| 160 million shares issued and outstanding | $ 1,973 | $ 1,953 | |||
| Unearned ESOP common stock | (76 | ) | (89 | ) | |
| Accumulated other comprehensive loss | (9 | ) | (7 | ) | |
| Retained earnings | 1,338 | 1,380 | |||
| Total Common Stock Equity | 3,226 | 3,237 | |||
| Preferred Stock - Not Subject to Mandatory Redemption | 59 | 59 | |||
| Long-Term Debt, Net | 2,749 | 3,086 | |||
| Total Capitalization | 6,034 | 6,382 | |||
| Current Liabilities | |||||
| Current portion of long-term debt | 300 | 300 | |||
| Accounts payable and accrued liabilities | 248 | 188 | |||
| Payables to affiliated companies | 89 | 136 | |||
| Notes payable to affiliated companies | — | 25 | |||
| Interest accrued | 58 | 64 | |||
| Short-term obligations | 146 | 4 | |||
| Other current liabilities | 251 | 166 | |||
| Total Current Liabilities | 1,092 | 883 | |||
| Deferred Credits and Other Liabilities | |||||
| Accumulated deferred income taxes | 1,103 | 1,125 | |||
| Accumulated deferred investment tax credits | 142 | 148 | |||
| Regulatory liabilities | 1,240 | 1,149 | |||
| Asset retirement obligations | 973 | 932 | |||
| Other liabilities | 382 | 363 | |||
| Total Deferred Credits and Other Liabilities | 3,840 | 3,717 | |||
| Commitments and Contingencies (Note 11) | |||||
| Total Capitalization and Liabilities | $ 10,966 | $ 10,982 | |||
See Notes to Consolidated Interim Financial Statements.
CAROLINA
POWER & LIGHT COMPANY
d/b/a
PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED
CONSOLIDATED STATEMENTS of CASH FLOWS
| Nine Months Ended September 30 | |||||
|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | |||
| Operating Activities | |||||
| Net income | $ 386 | $ 381 | |||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||
| Depreciation and amortization | 460 | 486 | |||
| Deferred income taxes | (20 | ) | (46 | ) | |
| Investment tax credit | (6 | ) | (8 | ) | |
| Deferred fuel (credit) cost | (57 | ) | 11 | ||
| Cash provided (used) by changes in operating assets and liabilities: | |||||
| Accounts receivable | 7 | 38 | |||
| Inventories | 9 | 17 | |||
| Prepayments and other current assets | 5 | 11 | |||
| Accounts payable | (35 | ) | (85 | ) | |
| Other current liabilities | 78 | 97 | |||
| Other | 62 | 59 | |||
| Net Cash Provided by Operating Activities | 889 | 961 | |||
| Investing Activities | |||||
| Gross property additions | (363 | ) | (347 | ) | |
| Proceeds from sale of assets and investments | 5 | 26 | |||
| Nuclear fuel additions | (63 | ) | (46 | ) | |
| Contributions to nuclear decommissioning trust | (26 | ) | (26 | ) | |
| Other investing activities | 5 | (1 | ) | ||
| Net Cash Used in Investing Activities | (442 | ) | (394 | ) | |
| Financing Activities | |||||
| Issuance of long-term debt, net | — | 588 | |||
| Net increase (decrease) in short-term obligations | 142 | (438 | ) | ||
| Net change in intercompany notes | (42 | ) | (73 | ) | |
| Retirement of long-term debt | (339 | ) | (269 | ) | |
| Dividends paid to parent | (426 | ) | (328 | ) | |
| Dividends paid on preferred stock | (2 | ) | (2 | ) | |
| Net Cash Used in Financing Activities | (667 | ) | (522 | ) | |
| Net (Decrease) Increase in Cash and Cash Equivalents | (220 | ) | 45 | ||
| Cash and Cash Equivalents at Beginning of Period | 238 | 18 | |||
| Cash and Cash Equivalents at End of Period | $ 18 | $ 63 | |||
| Supplemental Disclosures of Cash Flow Information | |||||
| Cash paid during the year - interest (net of amount capitalized) | $ 146 | $ 151 | |||
| income taxes (net of refunds) | $ 200 | $ 210 | |||
See Notes to Consolidated Interim Financial Statements.
CAROLINA
POWER & LIGHT COMPANY
d/b/a
PROGRESS ENERGY CAROLINAS, INC.
NOTES TO
CONSOLIDATED INTERIM FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
| A. | Organization |
| Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC) is a public service corporation primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina. Through its wholly-owned subsidiaries, PEC is also involved in nonregulated business activities. PEC is a wholly-owned subsidiary of Progress Energy, Inc. (the Company or Progress Energy). The Company is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). Both the Company and its subsidiaries are subject to the regulatory provisions of PUHCA. PEC is regulated by the North Carolina Utilities Commission (NCUC), the Public Service Commission of South Carolina (SCPSC), the Federal Energy Regulatory Commission (FERC) and the United States Nuclear Regulatory Commission (NRC). |
| B. | Basis of Presentation |
| These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for annual statements. Because the accompanying consolidated interim financial statements do not include all of the information and footnotes required by GAAP, they should be read in conjunction with the audited financial statements for the period ended December 31, 2003 and notes thereto included in PEC’s Form 10-K for the year ended December 31, 2003. |
| PEC collects from customers certain excise taxes, which include gross receipts tax, franchise taxes, and other excise taxes, levied by the state or local government upon the customers. PEC accounts for excise taxes on a gross basis. For the three month periods ended September 30, 2004 and 2003, excise taxes of approximately $25 million are included in taxes other than on income in the accompanying Consolidated Statements of Income. For the nine month periods ended September 30, 2004 and 2003, excise taxes of approximately $70 million and $65 million, respectively, are included in taxes other than on income in the accompanying Consolidated Statements of Income. These approximate amounts are also included in utility revenues. |
| The amounts included in the consolidated interim financial statements are unaudited but, in the opinion of management, reflect all normal recurring adjustments necessary to fairly present PEC’s financial position and results of operations for the interim periods. Due to seasonal weather variations and the timing of outages of electric generating units, especially nuclear-fueled units, the results of operations for interim periods are not necessarily indicative of amounts expected for the entire year or future periods. |
| In preparing financial statements that conform with GAAP, management must make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and amounts of revenues and expenses reflected during the reporting period. Actual results could differ from those estimates. Certain amounts for 2003 have been reclassified to conform to the 2004 presentation. |
| C. | Stock-Based Compensation |
| PEC measures compensation expense for stock options as the difference between the market price of its common stock and the exercise price of the option at the grant date. The exercise price at which options are granted by the Company equals the market price at the grant date, and accordingly, no compensation expense has been recognized for stock option grants. For purposes of the pro forma disclosures required by Statement of Financial Account Standards (SFAS) No. 148, “Accounting for Stock-Based Compensation –Transition and Disclosure – an Amendment of FASB Statement No. 123” (SFAS No. 148), the estimated fair value of the Company’s stock options is amortized to expense over the options’ vesting period. The following table illustrates the effect on net income and earnings per share if the fair value method had been applied to all outstanding and unvested awards in each period: |
| Three Months Ended September 30 |
Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Earnings for Common Stock, as reported | $174 | $156 | $384 | $379 | |||||
| Deduct: Total stock option expense determined underfair value method for all awards, net of related tax effects |
2 | 2 | 5 | 4 | |||||
| Pro forma net income | $172 | $154 | $379 | $375 | |||||
| PEC expects to begin expensing stock options in 2005, either by adopting SFAS No. 123, as amended by SFAS No. 148, or by adopting new FASB guidance on accounting for stock-based compensation that is expected to be issued in late 2004 and become effective July 1, 2005. In 2004, however, the Company made the decision to cease granting stock options and intends to replace that compensation program with other programs. Therefore, the amount of stock option expense expected to be recorded in 2005 is below the amount that would have been recorded if the stock option program had continued. If stock option expense is recorded for the full year 2005, approximately $3 million of pre-tax expense would be recorded. |
| D. | Consolidation of Variable Interest Entities |
| PEC consolidates all voting interest entities in which it owns a majority voting interest and all variable interest entities for which it is the primary beneficiary in accordance with FASB Interpretation No. 46R, “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51” (FIN No. 46R). PEC is the primary beneficiary of and consolidates two limited partnerships that qualify for federal affordable housing and historic tax credits under Section 42 of the Internal Revenue Code. As of September 30, 2004, the total assets of the two entities were $39 million, the majority of which are collateral for the entities’ obligations and are included in other current assets and miscellaneous other property in the Consolidated Balance Sheet. |
| PEC is the primary beneficiary of a limited partnership which invests in 17 low-income housing partnerships that qualify for federal and state tax credits. PEC has requested but has not received all the necessary information to determine the primary beneficiary of the limited partnership’s underlying 17 partnership investments, and has applied the information scope exception in FIN No. 46R, paragraph 4(g) to the 17 partnerships. PEC has no direct exposure to loss from the 17 partnerships; PEC’s only exposure to loss is from its investment of less than $1 million in the consolidated limited partnership. PEC will continue its efforts to obtain the necessary information to fully apply FIN No. 46R to the 17 partnerships. PEC believes that if the limited partnership is determined to be the primary beneficiary of the 17 partnerships, the effect of consolidating the 17 partnerships would not be significant to PEC’s Consolidated Balance Sheets. |
| PEC has variable interests in two power plants resulting from long-term power purchase contracts. PEC has requested the necessary information to determine if the counterparties are variable interest entities or to identify the primary beneficiaries. Both entities declined to provide PEC with the necessary financial information, and PEC has applied the information scope exception in FIN No. 46R, paragraph 4(g). PEC’s only significant exposure to variability from these contracts results from fluctuations in the market price of fuel used by the two entities’ plants to produce the power purchased by PEC. PEC is able to recover these fuel costs under its fuel clause. Total purchases from these counterparties were approximately $46 million and $43 million in the first nine months of 2004 and 2003, respectively. PEC will continue its efforts to obtain the necessary information to fully apply FIN No. 46R to these contracts. The combined generation capacity of the two entities’ power plants is approximately 880 MW. PEC believes that if it is determined to be the primary beneficiary of these two entities, the effect of consolidating the entities would result in increases to total assets, long-term debt and other liabilities, but would have an insignificant or no impact on PEC’s common stock equity, net earnings, or cash flows. However, because PEC has not received any financial information from these two counterparties, the impact cannot be determined at this time. |
| PEC also has interests in several other variable interest entities for which PEC is not the primary beneficiary. These arrangements include investments in approximately 22 limited partnerships, limited liability corporations and venture capital funds and two building leases with special-purpose entities. The aggregate maximum loss exposure at September 30, 2004, that PEC could be required to record in its income statement as a result of these arrangements totals approximately $24 million. The creditors of these variable interest entities do not have recourse to the general credit of PEC in excess of the aggregate maximum loss exposure. |
2. NEW ACCOUNTING STANDARDS
| In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law. In accordance with guidance issued by the FASB in FASB Staff Position 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003” (FASB Staff Position 106-2), PEC elected to defer accounting for the effects of the Medicare Act due to uncertainties regarding the effects of the implementation of the Medicare Act and the accounting for certain provisions of the Medicare Act. In May 2004, the FASB issued definitive accounting guidance for the Medicare Act in FASB Staff Position 106-2, which was effective for PEC in the third quarter of 2004. FASB Staff Position 106-2 results in the recognition of lower other post retirement employee benefit (OPEB) costs to reflect prescription drug-related federal subsidies to be received under the Medicare Act. As a result of the Medicare Act, PEC’s accumulated postretirement benefit obligation as of January 1, 2004 was reduced by approximately $42 million and PEC’s 2004 net periodic cost will be reduced by approximately $7 million. PEC recorded $5 million of the net periodic cost reduction in the quarter ended September 30, 2004. Prior quarters were not restated due to the immateriality of the adjustments. |
3. HURRICANE-RELATED COSTS
| Hurricanes Charley and Ivan struck portions of PEC’s service territory during the third quarter of 2004. PEC has estimated restoration costs of $13 million, of which $12 million was charged to operation and maintenance expense and $1 million was charged to capital expenditures. |
| PEC does not have an on-going regulatory mechanism to recover storm costs and, therefore, hurricane restoration costs recorded in the third quarter of 2004 were charged to operations and maintenance expenses or capital expenditures based on the nature of the work performed. In connection with other storms, PEC has previously sought and received permission from the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC) to defer storm expenses and amortize them over a five-year period. PEC is planning to seek deferral of 2004 storm costs from the NCUC in the fourth quarter of 2004. |
4. REGULATORY MATTERS
| A. | Retail Rate Matters |
| PEC has exclusively utilized external funding for its decommissioning liability since 1994. Prior to 1994, PEC retained funds internally to meet its decommissioning liability. An NCUC order issued in February 2004 found that by January 1, 2008 PEC must begin transitioning these amounts to external funds. The transition of $131 million must be completed by December 31, 2017, and at least 10% must be transitioned each year. |
| PEC filed with the SCPSC seeking permission to defer expenses incurred from the first quarter 2004 winter storm. The SCPSC approved PEC’s request to defer the costs and amortize them ratably over five years beginning in January 2005. Approximately $10 million related to storm costs incurred during the first quarter of 2004 was deferred in that quarter. |
| During the first quarter of 2004, PEC met the requirements of both the NCUC and the SCPSC for the implementation of a depreciation study which allowed the utility to reduce the rates used to calculate depreciation expense. As a result, depreciation expense decreased $7 million for the three months ended September 30, 2004 compared to the prior year quarter and decreased $17 million for the nine months ended September 30, 2004 compared to the prior year nine month period. |
| In October 2004, PEC filed a revised depreciation study with the NCUC and SCPSC supporting a reduction in annual depreciation expense of approximately $47 million. The reduction is due solely to extended lives at each of PEC’s nuclear units. The new depreciation rates are proposed to be effective January 1, 2004. |
| PEC obtained SCPSC and NCUC approval of fuel factors in annual fuel-adjustment proceedings. The SCPSC approved PEC’s petition to leave billing rates unchanged from the prior year by order issued in March 2004. The NCUC approved an annual increase of $62 million by order issued in September 2004. |
| B. | Regional Transmission Organizations |
| In 2000, the FERC issued Order No. 2000 on RTOs, which set minimum characteristics and functions that RTOs must meet, including independent transmission service. In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would materially alter the manner in which transmission and generation services are provided and paid for. In April 2003, the FERC released a White Paper on the Wholesale Market Platform. The White Paper provides an overview of what the FERC currently intends to include in a final rule in the SMD NOPR docket. The White Paper retains the fundamental and most protested aspects of SMD NOPR, including mandatory RTOs and the FERC’s assertion of jurisdiction over certain aspects of retail service. The FERC has not yet issued a final rule on SMD NOPR. PEC cannot predict the outcome of these matters or the effect that they may have on the GridSouth proceedings currently ongoing before the FERC. It is unknown what impact the future proceedings will have on PEC’s earnings, revenues or prices. |
| PEC has $33 million invested in GridSouth related to startup costs at September 30, 2004. PEC expects to recover these startup costs in conjunction with the GridSouth original structure or in conjunction with any alternate combined transmission structures that emerge. |
| C. | Implementation of SFAS No. 143 |
| In connection with the implementation of SFAS No. 143, “Accounting for Asset Retirement Obligations,” in 2003, PEC filed a request with the NCUC requesting deferral of the difference between expense pursuant to SFAS No. 143 and expense as previously determined by the NCUC. The NCUC granted the deferral of the January 1, 2003 cumulative adjustment. Because the clean air legislation discussed in Note 11 under “Air Quality”contained a prohibition against cost deferrals unless certain criteria are met, the NCUC denied the deferral of the ongoing effects. Therefore, PEC ceased deferral of the ongoing effects during the second quarter for the six months ended June 30, 2003 related to its North Carolina retail jurisdiction. Pre-tax income for the three and six months ended June 30, 2003 increased by approximately $14 million, which represents a decrease in non-ARO cost of removal expense, partially offset by an increase in decommissioning expense. The Company provided additional information to the NCUC that demonstrated that deferral of the ongoing effects should also be allowed. In August 2003, the NCUC revised its decision and approved the deferral of the ongoing effects of SFAS No. 143 at which time the $14 million impact was reversed. |
| D. | FERC Market Power Mitigation |
| A FERC order issued in November 2001 on certain unaffiliated utilities’ triennial market based wholesale power rate authorization updates required certain mitigation actions that those utilities would need to take for sales/purchases within their control areas and required those utilities to post information on their websites regarding their power systems’ status. As a result of a request for rehearing filed by certain market participants, FERC issued an order delaying the effective date of the mitigation plan until after a planned technical conference on market power determination. In December 2003, the FERC issued a staff paper discussing alternatives and held a technical conference in January 2004. In April 2004, the FERC issued two orders concerning utilities’ ability to sell wholesale electricity at market based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a rulemaking to consider whether the FERC’s current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way. Management is unable to predict the outcome of these actions by the FERC or their effect on future results of operations and cash flows. However, PEC does not anticipate that its current operations would be impacted materially if they were unable to sell power at market-based rates in their respective control areas. Due to PEC’s failure of one of the two interim market power screens, on August 12, 2004, PEC notified the FERC that it would revise its Market Based Rate tariff to restrict it to sales outside PEC’s control area and file a new cost based tariff for sales within PEC’s control area that incorporates the FERC’s default cost based rate methodologies for sales of one year or less. PEC anticipates making this filing by year-end. |
5. COMPREHENSIVE INCOME
| Comprehensive income for the three months ended September 30, 2004 and 2003 was $170 million and $162 million, respectively. Comprehensive income for the nine months ended September 30, 2004 and 2003 was $384 million and $385 million, respectively. Changes in other comprehensive income for the periods consisted primarily of changes in fair value of derivatives used to hedge cash flows related to interest on long-term debt. |
6. FINANCING ACTIVITIES
| Between October 19, 2004 and November 1, 2004, PEC borrowed a net total of $115 million under certain long-term revolving credit facilities. In addition, PEC borrowed $90 million under its short-term credit facility. The credit facilities contain various cross default and other acceleration provisions. PEC’s long-term credit facilities were arranged through a syndication of financial institutions and support its commercial paper programs. The borrowed funds will be used to pay off maturing commercial paper and for other cash needs. This action was taken due to the uncertain impact on PEC’s ability to access the commercial paper markets resulting from recent ratings actions taken by Standard and Poor’s (“S&P”) credit rating agency and Moody’s Investor Services (“Moody’s”). |
| On October 19, 2004, S&P changed Progress Energy’s outlook from stable to negative. S&P cited the uncertainties regarding the timing of the recovery of hurricane costs, the Company’s debt reduction plans, and the IRS audit of the Company’s Earthco synthetic fuels facilities as the reasons for the change in outlook. On October 25, 2004, S&P reduced the short-term debt rating of PEC to A-3 from A-2, as a result of their change in outlook discussed above. |
| On October 20, 2004, Moody’s changed its outlook for Progress Energy from stable to negative. PEC’s ratings were affirmed by Moody’s. |
| The changes by S&P do not trigger any debt or guarantee collateral requirements, nor do they have any material impact on the overall liquidity of PEC. To date, PEC’s access to the commercial paper markets has not been materially impacted by the rating agencies’ actions. However, the changes are expected to increase the interest rate incurred on its short-term borrowings by 0.25% to 0.875%. |
| On July 28, 2004, PEC extended its $165 million 364-day line of credit, which was scheduled to expire on July 29, 2004. The line of credit will expire on July 27, 2005. |
| On April 30, 2004, PEC redeemed $35 million of Darlington County 6.6% Series Pollution Control Bonds at 102.5% of par, $2 million of New Hanover County 6.3% Series Pollution Control Bonds at 101.5% of par, and $2 million of Chatham County 6.3% Series Pollution Control Bonds at 101.5% of par with cash from operations. |
| On January 15, 2004, PEC paid at maturity $150 million 5.875% First Mortgage Bonds with commercial paper proceeds. On April 15, 2004, PEC also paid at maturity $150 million 7.875% First Mortgage Bonds with commercial paper proceeds and cash from operations. |
7. BENEFIT PLANS
| PEC has a non-contributory defined benefit retirement (pension) plan for substantially all full-time employees. PEC also has supplementary defined benefit pension plans that provide benefits to higher-level employees. In addition to pension benefits, PEC provides contributory other postretirement benefits (OPEB), including certain health care and life insurance benefits, for retired employees who meet specified criteria. The components of the net periodic benefit cost for the three and nine months ended September 30 are: |
| Three Months Ended September 30 | Pension Benefits | Other Postretirement Benefits | |||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Service cost | $ 6 | $ 6 | $ 1 | $ 2 | |||||
| Interest cost | 13 | 14 | 3 | 5 | |||||
| Expected return on plan assets | (18 | ) | (19 | ) | (1 | ) | (1 | ) | |
| Amortization, net | — | 1 | — | 1 | |||||
| Net periodic cost | $ 1 | $ 2 | $ 3 | $ 7 | |||||
| Nine Months Ended September 30 | Pension Benefits | Other Postretirement Benefits | |||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Service cost | $ 18 | $ 17 | $ 5 | $ 5 | |||||
| Interest cost | 39 | 38 | 11 | 11 | |||||
| Expected return on plan assets | (52 | ) | (52 | ) | (3 | ) | (2 | ) | |
| Amortization, net | 1 | 1 | 2 | 4 | |||||
| Net periodic cost | $ 6 | $ 4 | $ 15 | $ 18 | |||||
| Net periodic costs for other postretirement benefits decreased during the three and nine months ended September 30, 2004 due to the implementation of FASB Staff Position 106-2. See discussion in Note 2 to the Consolidated Interim Financial Statements. |
8. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS
| Under its risk management policy, PEC may use a variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in commodity prices and interest rates. See Note 12 to the financial statements in Item 8 of the Annual Report on Form 10-K for the year ended December 31, 2003. |
| Nonhedging Derivatives |
| Nonhedging derivatives, primarily electricity and natural gas contracts, are entered into for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions. Gains and losses from such contracts were not material during the nine months ending September 30, 2004, and PEC did not have material outstanding positions in such contracts at September 30, 2004. |
| Cash Flow Hedges |
| PEC uses cash flow hedging strategies to hedge variable interest rates on long-term and short-term debt and to hedge interest rates with regard to future fixed-rate debt issuances. As of September 30, 2004, PEC had $110 million notional amount of pay-fixed forward swaps to hedge its exposure to interest rates with regard to future issuances of debt and $26 million notional amount of pay-fixed forward starting swaps to hedge its exposure to interest rates with regard to an upcoming railcar lease. All the swaps have a computational period of ten years. These hedges had a fair value liability position of $2 million at September 30, 2004. PEC had no open cash flow hedges at December 31, 2003. The ineffective portion of interest rate cash flow hedges for the three and nine-month periods ending September 30, 2004 was not material to PEC’s results of operations. As of September 30, 2004, PEC had $7 million of after-tax deferred losses in accumulated other comprehensive income (OCI), including amounts related to terminated hedges, of which $1 million are expected to be reclassified to earnings within the next 12 months. Due to the volatility of interest rates, the value in OCI is subject to change prior to its reclassification into earnings. |
| Fair Value Hedges |
| PEC uses fair value hedging strategies to manage its exposure to fixed interest rates on long-term debt. At September 30, 2004 and December 31, 2003, PEC had no open interest rate fair value hedges. |
9. FINANCIAL INFORMATION BY BUSINESS SEGMENT
| PEC’s operations consist primarily of the PEC Electric segment which is engaged in the generation, transmission, distribution and sale of electric energy primarily in portions of North Carolina and South Carolina. These electric operations are subject to the rules and regulations of the FERC, the NCUC, the SCPSC and the NRC. PEC Electric also distributes and sells electricity to other utilities, primarily on the east coast of the United States. |
| The Other segment, whose operations are primarily in the United States, is made up of other nonregulated business areas and eliminations that do not separately meet the disclosure requirements of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” |
| The financial information for PEC segments for the three and nine months ended September 30, 2004 and 2003 is as follows: |
| Three Months Ended September 30 | 2004 | 2003 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in millions) | PEC Electric |
Other | Total | PEC Electric |
Other | Total | |||||||
| Total revenues | $1,014 | $ — | $1,014 | $1,010 | $ 2 | $1,012 | |||||||
| Earnings available | 175 | (1 | ) | 174 | 160 | (4 | ) | 156 | |||||
| for common | |||||||||||||
| Nine Months Ended September 30 | 2004 | 2003 | |||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| (in millions) | PEC Electric |
Other | Total | PEC Electric |
Other | Total | |||||||
| Total revenues | $2,776 | $ 1 | $ 2777 | $2,752 | $ 8 | $2,760 | |||||||
| Earnings available | 388 | (4 | ) | 384 | 383 | (4 | ) | 379 | |||||
| for common | |||||||||||||
| No single customer accounted for 10% or more of unaffiliated revenues. |
10. OTHER INCOME AND OTHER EXPENSE
| Other income and expense includes interest income and other income and expense items as discussed below. The components of other, net as shown on the accompanying Consolidated Statements of Income are as follows: |
| Three Months Ended September 30 |
Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Other income | |||||||||
| Net financial trading gain | $ 3 | $ — | $ 7 | $ — | |||||
| Nonregulated energy and delivery services income | 2 | 3 | 9 | 9 | |||||
| Investment gains | 2 | 1 | 3 | 2 | |||||
| AFUDC equity | 1 | (1 | ) | 3 | 1 | ||||
| Gain on sale of property | 2 | 1 | 3 | 2 | |||||
| Other | 2 | 2 | 3 | 5 | |||||
| Total other income | $12 | $ 6 | $ 28 | $ 19 | |||||
| Other expense | |||||||||
| Nonregulated energy and delivery services expenses | $ 2 | $ 2 | $ 6 | $ 6 | |||||
| Donations | 1 | 1 | 5 | 4 | |||||
| Investment losses | — | 2 | 2 | 12 | |||||
| Write-off of non-trade receivable | — | — | 7 | — | |||||
| Loss on sale of property | — | 2 | — | 2 | |||||
| Other | 2 | 3 | 9 | 9 | |||||
| Total other expense | $ 5 | $ 10 | $ 29 | $ 33 | |||||
| Other, net | $ 7 | $(4 | ) | $(1 | ) | $(14 | ) | ||
| Net financial trading gains and losses represent non-asset-backed trades of electricity and gas. Nonregulated energy and delivery services include power protection services and mass market programs such as surge protection, appliance services and area light sales, and delivery, transmission and substation work for other utilities. |
11. COMMITMENTS AND CONTINGENCIES
| Contingencies and significant changes to the commitments discussed in Note 16 of the Company’s 2003 Annual Report on Form 10-K are described below. |
| A. | Guarantees |
| As a part of normal business, PEC enters into various agreements providing future financial or performance assurances to third parties, which are outside the scope of Financial Accounting Standards Board (FASB) Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). Such agreements include guarantees, standby letters of credit and surety bonds. At September 30, 2004, management does not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Consolidated Balance Sheets. At September 30, 2004, PEC had no guarantees issued on behalf of unconsolidated subsidiaries or other third parties. |
| B. | Insurance |
| PEC is insured against public liability for a nuclear incident up to $10.8 billion per occurrence. Under the current provisions of the Price Anderson Act, which limits liability for accidents at nuclear plants, PEC, as an owner of nuclear units, can be assessed a portion of any third-party liability claims arising from an accident at any commercial nuclear power plant in the United States. In the event that public liability claims from an insured nuclear incident exceed $300 million (currently available through commercial insurers), PEC would be subject to assessments of up to $101 million for each reactor owned per occurrence. Payment of such assessments would be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. Congress is considering revisions to the Price Anderson Act that could include increased limits and assessments per reactor owned. The final outcome of this matter cannot be predicted at this time. |
| PEC self-insures its transmission and distribution lines against loss due to storm damage and other natural disasters. |
| C. | Claims and Uncertainties |
| PEC is subject to federal, state and local regulations addressing hazardous and solid waste management, air and water quality and other environmental matters. See Note 16D to the financial statements in Item 8 of the Form 10-K for the year ended December 31, 2003. |
| Hazardous and Solid Waste Management |
| Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, are regulated under federal and state laws. The principal regulatory agency that is responsible for a specific former manufactured gas plant (MGP) site depends largely upon the state in which the site is located. There are several MGP sites to which PEC has some connection. In this regard, PEC and other potentially responsible parties (PRPs) are participating in, investigating and, if necessary, remediating former MGP sites with several regulatory agencies, including, but not limited to, the U.S. Environmental Protection Agency (EPA) and the North Carolina Department of Environment and Natural Resources, Division of Waste Management (DWM). In addition, PEC is periodically notified by regulators such as the EPA and various state agencies of its involvement or potential involvement in sites, other than MGP sites, that may require investigation and/or remediation. |
| PEC has filed claims with its general liability insurance carriers to recover costs arising from actual or potential environmental liabilities. All claims have been settled other than with insolvent carriers. These settlements have not had a material effect on the consolidated financial position or results of operations. |
| PEC is also currently in the process of assessing potential costs and exposures at other environmentally impaired sites. As the assessments are developed and analyzed, PEC will accrue costs for the sites to the extent the costs are probable and can be reasonably estimated. |
| There are nine former MGP sites and other sites associated with PEC that have required or are anticipated to require investigation and/or remediation costs. PEC received insurance proceeds to address costs associated with environmental liabilities related to its involvement with some sites. All eligible expenses related to these are charged against a specific fund containing these proceeds. At December 31, 2003, the balance in the fund was $9 million. During the nine months ended September 30, 2004, PEC spent approximately $2 million related to environmental remediation. The remaining balance in the fund at September 30, 2004 was $7 million. At September 30, 2004, PEC had an accrual of $9 million recorded for environmental liabilities, which includes $2 million transferred from NCNG at the time of the sale of NCNG. PEC is unable to provide an estimate of the reasonably possible total remediation costs beyond what is currently accrued due to the fact that investigations have not been completed at all sites. This accrual has been recorded on an undiscounted basis. PEC measures its liability for these sites based on available evidence including its experience in investigating and remediating environmentally impaired sites. The process often involves assessing and developing cost-sharing arrangements with other PRPs. PEC will accrue costs for the sites to the extent its liability is probable and the costs can be reasonably estimated. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet reached to the stage where a reasonable estimate of the remediation costs can be made, PEC cannot determine the total costs that may be incurred in connection with the remediation of all sites at this time. It is anticipated that sufficient information will become available for several sites during 2005 to allow a reasonable estimate of PEC’s obligation for those sites to be made. |
| Air Quality |
| There has been and may be further proposed legislation requiring reductions in air emissions for NOx, SO2, carbon dioxide and mercury. Some of these proposals establish nationwide caps and emission rates over an extended period of time. This national multi-pollutant approach to air pollution control could involve significant capital costs which could be material to PEC’s consolidated financial position or results of operations. Control equipment that will be installed on North Carolina fossil generating facilities as part of the North Carolina legislation discussed below may address some of the issues outlined above. However, PEC cannot predict the outcome of this matter. |
| The EPA is conducting an enforcement initiative related to a number of coal-fired utility power plants in an effort to determine whether modifications at those facilities were subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. PEC was asked to provide information to the EPA as part of this initiative and cooperated in providing the requested information. The EPA initiated civil enforcement actions against other unaffiliated utilities as part of this initiative. Some of these actions resulted in settlement agreements calling for expenditures by these unaffiliated utilities, ranging from $1.0 billion to $1.4 billion. A utility that was not subject to a civil enforcement action settled its New Source Review issues with the EPA for $300 million. These settlement agreements have generally called for expenditures to be made over extended time periods, and some of the companies may seek recovery of the related cost through rate adjustments or similar mechanisms. PEC cannot predict the outcome of this matter. |
| In 2003, the EPA published a final rule addressing routine equipment replacement under the New Source Review program. The rule defines routine equipment replacement and the types of activities that are not subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The rule was challenged in the Federal Appeals Court and its implementation stayed. In July 2004, the EPA announced it will reconsider certain issues arising from the final routine equipment replacement rule. Reconsideration does not impact the court-approved stay. The agency plans to issue a final decision on these reconsidered issues by year end. PEC cannot predict the outcome of this matter. |
| In 1998, the EPA published a final rule at Section 110 of the Clean Air Act addressing the regional transport of ozone (NOx SIP Call). Total capital expenditures to meet these measures in North and South Carolina could reach approximately $370 million, which has not been adjusted for inflation. PEC has spent approximately $284 million to date related to these expenditures. Increased operation and maintenance costs relating to the NOx SIP Call are not expected to be material to PEC’s results of operations. Further controls are anticipated as electricity demand increases. |
| In 1997, the EPA issued final regulations establishing a new 8-hour ozone standard. In 1999, the District of Columbia Circuit Court of Appeals ruled against the EPA with regard to the federal 8-hour ozone standard. The U.S. Supreme Court has upheld, in part, the District of Columbia Circuit Court of Appeals decision. In April 2004, the EPA identified areas that do not meet the standard. The states with identified areas, including North and South Carolina are proceeding with the implementation of the federal 8-hour ozone standard. Both states promulgated final regulations, which will require PEC to install NOx controls under the states’ 8-hour standard. The costs of those controls are included in the $370 million cost estimate above. However, further technical analysis and rulemaking may result in a requirement for additional controls at some units. PEC cannot predict the outcome of this matter. |
| In June 2002, legislation was enacted in North Carolina requiring the state’s electric utilities to reduce the emissions of NOx and SO2 from coal-fired power plants. PEC expects its capital costs to meet these emission targets will be over $800 million by 2013. PEC has expended approximately $69 million of these capital costs through September 30, 2004. PEC currently has approximately 5,100 MW of coal-fired generation capacity in North Carolina that is affected by this legislation. The law requires the emissions reductions to be completed in phases by 2013, and applies to each utility’s total system rather than setting requirements for individual power plants. The law also freezes the utilities’ base rates for five years unless there are extraordinary events beyond the control of the utilities or unless the utilities persistently earn a return substantially in excess of the rate of return established and found reasonable by the NCUC in the utilities’ last general rate case. Further, the law allows the utilities to recover from their retail customers the projected capital costs during the first seven years of the ten-year compliance period beginning on January 1, 2003. The utilities must recover at least 70% of their projected capital costs during the five-year rate freeze period. PEC recognized amortization of $20 million in the quarter ended September 30, 2004. No amortization was recognized in the quarter ended September 30, 2003. PEC recognized amortization of $50 million and $54 million in the nine months ended September 30, 2004 and 2003, respectively, and has recognized $124 million in cumulative amortization through September 30, 2004. Pursuant to the law, PEC entered into an agreement with the state of North Carolina to transfer to the state certain NOx and SO2 emissions allowances that result from compliance with the collective NOx and SO2 emissions limitations set out in the law. The law also requires the state to undertake a study of mercury and carbon dioxide emissions in North Carolina. Operation and maintenance costs will increase due to the additional personnel, materials and general maintenance associated with the equipment. Operation and maintenance expenses are recoverable through base rates, rather than as part of this program. PEC cannot predict the future regulatory interpretation, implementation or impact of this law. |
| In 1997, the EPA’s Mercury Study Report and Utility Report to Congress conveyed that mercury is not a risk to the average American and expressed uncertainty about whether reductions in mercury emissions from coal-fired power plants would reduce human exposure. Nevertheless, the EPA determined in 2000 that regulation of mercury emissions from coal-fired power plants was appropriate. In 2003, the EPA proposed alternative control plans that would limit mercury emissions from coal-fired power plants. The first, a Maximum Achievable Control Technology (MACT) standard applicable to every coal-fired plant, would require compliance in 2008. The second, which the EPA has stated it prefers, is a mercury cap and trade program that would require limits to be met in two phases, 2010 and 2018. The EPA expects to finalize the mercury rule in March 2005. Achieving compliance with the proposal could involve significant capital costs which could be material to PEC’s consolidated financial position or results of operations. PEC cannot predict the outcome of this matter. |
| In conjunction with the proposed mercury rule, the EPA proposed a MACT standard to regulate nickel emissions from residual oil-fired units. The agency estimates the proposal will reduce national nickel emissions to approximately 103 tons. The EPA expects to finalize the nickel rule in March 2005. PEC’s oil-fired units have pollution controls in place, which would meet the proposed requirements of the nickel rule. |
| In December 2003, the EPA released its proposed Interstate Air Quality Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The EPA’s proposal requires 28 jurisdictions, including North Carolina, South Carolina, Georgia and Florida, to further reduce NOx and SO2 emissions in order to attain preset state NOx and SO2 emissions levels. The rule is expected to become final by the end of 2004. The air quality controls already installed for compliance with the NOx SIP Call and currently planned by PEC for compliance with the North Carolina law will reduce the costs required to meet the CAIR requirements for PEC’s North Carolina units. Additional compliance costs will be determined once the rule is finalized. |
| In March 2004, the North Carolina Attorney General filed a petition with the EPA under Section 126 of the Clean Air Act, asking the federal government to force coal-fired power plants in thirteen other states, including South Carolina, to reduce their NOx and SO2 emissions. The state of North Carolina contends these out-of-state polluters are interfering with North Carolina’s ability to meet national air quality standards for ozone and particulate matter. The EPA has not made a determination on the Section 126 petition, and PEC cannot predict the outcome of this matter. |
| Water Quality |
| As a result of the operation of certain control equipment needed to address the air quality issues outlined above, new wastewater streams may be generated at the applicable facilities. Integration of these new wastewater streams into the existing wastewater treatment processes may result in permitting, construction and requirements imposed on PEC in the immediate and extended future. |
| After many years of litigation and settlement negotiations the EPA adopted regulations in February 2004 for the implementation of Section 316(b) of the Clean Water Act. These regulations became effective September 7, 2004. The purpose of these regulations is to minimize adverse environmental impacts caused by cooling water intake structures and intake systems. Over the next several years these regulations will impact the larger base load generation facilities and may require the facilities to mitigate the effects to aquatic organisms by constructing intake modifications or undertaking other restorative activities. Substantial costs could be incurred by the facilities in order to comply with the new regulation. PEC currently estimates that from 2005 through 2009 the range of its expenditures to meet the Section 316(b) requirements of the Clean Water Act will be $20 million to $30 million. |
| Other Environmental Matters |
| The Kyoto Protocol was adopted in 1997 by the United Nations to address global climate change by reducing emissions of carbon dioxide and other greenhouse gases. Russia recently announced its intent to ratify the Protocol, which would allow the treaty to enter into force. The United States has not adopted the Kyoto Protocol, and the Bush administration has stated it favors voluntary programs. A number of carbon dioxide emissions control proposals have been advanced in Congress and by the Bush administration. Reductions in carbon dioxide emissions to the levels specified by the Kyoto Protocol and some legislative proposals could be materially adverse to PEC’s consolidated financial position or results of operations if associated costs cannot be recovered from customers. PEC favors the voluntary program approach recommended by the administration and is evaluating options for the reduction, avoidance, and sequestration of greenhouse gases. However, PEC cannot predict the outcome of this matter. |
| Other Contingencies |
| 1. As required under the Nuclear Waste Policy Act of 1982, PEC entered into a contract with the DOE under which the DOE agreed to begin taking spent nuclear fuel by no later than January 31, 1998. All similarly situated utilities were required to sign the same standard contract. |
| In 1995, the DOE issued a final interpretation that it did not have an unconditional obligation to take spent nuclear fuel by January 31, 1998. In Indiana Michigan Power v. DOE, the Court of Appeals vacated the DOE’s final interpretation and ruled that the DOE had an unconditional obligation to begin taking spent nuclear fuel. The Court did not specify a remedy because the DOE was not yet in default. |
| After the DOE failed to comply with the decision in Indiana Michigan Power v. DOE, a group of utilities petitioned the Court of Appeals in Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to begin taking spent nuclear fuel by January 31, 1998. The DOE took the position that its delay was unavoidable, and the DOE was excused from performance under the terms and conditions of the contract. The Court of Appeals found that the delay was not unavoidable, but did not order the DOE to begin taking spent nuclear fuel, stating that the utilities had a potentially adequate remedy by filing a claim for damages under the contract. |
| After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a group of utilities filed a motion with the Court of Appeals to enforce the mandate in NSP v. DOE. Specifically, this group of utilities asked the Court to permit the utilities to escrow their waste fee payments, to order the DOE not to use the waste fund to pay damages to the utilities, and to order the DOE to establish a schedule for disposal of spent nuclear fuel. The Court denied this motion based primarily on the grounds that a review of the matter was premature, and that some of the requested remedies fell outside of the mandate in NSP v. DOE. |
| Subsequently, a number of utilities each filed an action for damages in the Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal Circuit) ruled that utilities may sue the DOE for damages in the Federal Court of Claims instead of having to file an administrative claim with DOE. |
| In January 2004, PEC filed a complaint with the DOE claiming that the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept spent nuclear fuel from various Progress Energy facilities on or before January 31, 1998. Damages due to DOE’s breach will likely exceed $100 million. Similar suits have been initiated by over two dozen other utilities. |
| In July 2002, Congress passed an override resolution to Nevada’s veto of DOE’s proposal to locate a permanent underground nuclear waste storage facility at Yucca Mountain, Nevada. DOE plans to submit a license application for the Yucca Mountain facility by the end of 2004. In November 2003, Congressional negotiators approved $580 million for fiscal year 2004 for the Yucca Mountain project, $123 million more than the previous year. In January 2003, the State of Nevada, Clark County, Nevada, and the City of Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the Congressional override resolution. On July 9, 2004, the Court rejected the challenge to the constitutionality of the resolution approving Yucca Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance period. The DOE continues to state it plans to begin operation of the repository at Yucca Mountain in 2010. PEC cannot predict the outcome of this matter. |
| With certain modifications and additional approval by the NRC including the installation of onsite dry storage facilities at Robinson (2005) and Brunswick (2010), PEC’s spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel generated on its system through the expiration of the operating licenses for all of its nuclear generating units. |
| 2. In 2001, PEC entered into a contract to purchase coal from Dynegy Marketing and Trade (DMT). After DMT experienced financial difficulties, including credit ratings downgrades by certain credit reporting agencies, PEC requested credit enhancements in accordance with the terms of the coal purchase agreement in July 2002. When DMT did not offer credit enhancements, as required by a provision in the contract, PEC terminated the contract in July 2002. |
| PEC initiated a lawsuit seeking a declaratory judgment that the termination was lawful. DMT counterclaimed, stating the termination was a breach of contract and an unfair and deceptive trade practice. On March 23, 2004, the United States District Court for the Eastern District of North Carolina ruled that PEC was liable for breach of contract, but ruled against DMT on its unfair and deceptive trade practices claim. On April 6, 2004, the Court entered a judgment against PEC in the amount of approximately $10 million. The Court did not rule on DMT’s request under the contract for pending legal costs. |
| On May 4, 2004, PEC authorized its outside counsel to file a notice of appeal of the April 6, 2004, judgment and on May 7, 2004, the notice of appeal was filed with the United States Court of Appeals for the Fourth Circuit. On June 8, 2004, DMT filed a motion to dismiss the appeal on the ground that PEC’s notice of appeal should have been filed on or before May 6, 2004. On June 16, 2004, PEC filed a motion with the trial court requesting an extension of the deadline for the filing of the notice of appeal. By order dated September 10, 2004, the trial court denied the extension request. On September 15, 2004, PEC filed a notice of appeal of the September 10, 2004 order and by order dated September 29, 2004, the appellate court consolidated the first and second appeals. DMT’s motion to dismiss the first appeal remains pending. |
| PEC recorded a liability for the judgment of approximately $10 million and a regulatory asset for the probable recovery through its fuel adjustment clause in the first quarter of 2004. The Company cannot predict the outcome of this matter. |
| 3. On February 1, 2002, filed a complaint with the Surface Transportation Board (STB) challenging the rates charged by Norfolk Southern Railway Company (Norfolk Southern) for coal transportation to certain generating plants. In a decision dated December 2003, the STB found that the rates were unreasonable and awarded reparations of $23 million and prescribed a methodology to determine maximum rates. Both parties petitioned for reconsideration of the December 2003 decision. On October 20, 2004, the STB reversed its December 2003 decision and concluded that the rates charged by Norfolk Southern were not unreasonable. The Company is in the process of evaluating future actions, which may include an application to the STB to phase in the new rates, or a judicial appeal. As of September 30, 2004, PEC has accrued a liability of $39 million, to return the reparations of $23 million, which was originally recorded as a regulatory liability, and accrue additional 2004 expenses of $16 million, of which $14 million, has been allocated to retail customers and recorded as deferred fuel cost while the remaining $2 million attributable to wholesale customers has been charged to fuel used in electric generation. |
| 4. PEC and its subsidiaries are involved in various litigation matters in the ordinary course of business, some of which involve substantial amounts. Where appropriate, accruals have been made in accordance with SFAS No. 5, “Accounting for Contingencies,” to provide for such matters. In the opinion of management, the final disposition of pending litigation would not have a material adverse effect on PEC’s consolidated results of operations or financial position. |
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following Management’s Discussion and Analysis contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Many, but not all of the factors that may impact actual results are discussed in the Risk Factors sections of Progress Energy’s and PEC’s annual report on Form 10-K for the year ended December 31, 2003, which were filed with the SEC on March 12, 2004. Please review “SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS” herein for a discussion of the factors that may impact any such forward-looking statements made herein.
Amounts reported in the interim Consolidated Statements of Income are not necessarily indicative of amounts expected for the respective annual or future periods due to the effects of seasonal temperature variations on energy consumption, significant weather events, timing of maintenance on electric generating units and timing of synthetic fuel production, among other factors.
This discussion should be read in conjunction with the accompanying financial statements found elsewhere in this report and in conjunction with the 2003 Form 10-K.
RESULTS OF OPERATIONS
Progress Energy is an integrated energy company, with its primary focus on the end-use and wholesale electricity markets. The Company’s reportable business segments and their primary operations include:
| o | Progress Energy Carolinas Electric (PEC Electric) – primarily engaged in the generation, transmission, distribution and sale of electricity in portions of North Carolina and South Carolina; |
| o | Progress Energy Florida (PEF) – primarily engaged in the generation, transmission, distribution and sale of electricity in portions of Florida; |
| o | Competitive Commercial Operations (CCO) – engaged in nonregulated electric generation operations and marketing activities primarily in the southeastern United States; |
| o | Fuels – primarily engaged in natural gas drilling and production in Texas and Louisiana, coal terminal services, coal mining, the production of synthetic fuels and related services, and fuel transportation and delivery, all of which are located in Kentucky, West Virginia, and Virginia; |
| o | Rail Services (Rail) – engaged in various rail and railcar related services in 23 states, Mexico and Canada; and o Other Businesses (Other) – engaged in other nonregulated business areas, including telecommunications primarily in the eastern United States and energy service operations, which do not meet the requirements for separate segment reporting disclosure. |
| o | Corporate activities that include holding company operations, service company operations and eliminations. |
In this section, earnings and the factors affecting earnings for the three and nine months ended September 30, 2004 as compared to the same periods in 2003 are discussed. The discussion begins with a summarized overview of the Company’s consolidated earnings, which is followed by a more detailed discussion and analysis by business segment.
OVERVIEW
For the quarter ended September 30, 2004, Progress Energy’s net income was $303 million or $1.25 per share compared to $318 million or $1.33 per share for the same period in 2003. The decrease in net income as compared to the prior quarter was attributable to:
| o | A reduction in synthetic fuel earnings due to lower synthetic fuel sales and the recording of a charge related to tax credits due to the impact of hurricanes during the quarter. |
| o | Increased interest charges as results in 2003 were favorably impacted by the reversal of interest expense for resolved tax matters. |
| o | Reduction in revenues due to customer outages in Florida associated with hurricanes. |
Partially offsetting these items were:
| o | Favorable customer growth in the Carolinas. |
| o | Increased margins as a result of the allowed return on the Hines 2 Plant in Florida. |
| o | Reduced operations and maintenance (O&M) costs at the utilities due primarily to reduction in salaries and benefits and timing of projects delayed due to storm restoration efforts. |
| o | Increased Rail earnings due to higher volumes and prices. |
| o | Unrealized gains recorded on contingent value obligations. |
| o | Reduction in losses recorded for discontinued operations. |
For the nine months ended September 30, 2004, Progress Energy’s net income was $565 million or $2.33 per share compared to $694 million or $2.94 per share for the same period in 2003. The decrease in net income as compared to prior year was due primarily to:
| o | A reduction in synthetic fuel earnings due to lower synthetic fuel sales and the recording of a charge related to tax credits due to the impact of hurricanes during the year. |
| o | Lower off-system wholesale sales, primarily at PEC Electric. |
| o | Recording of litigation settlement reached in the civil suit by SRS. |
| o | Decreased nonregulated generation earnings due to receipt of a contract termination payment on a tolling agreement in 2003 and higher fixed costs and interest charges in 2004. |
| o | Reduction in revenues due to customer outages in Florida associated with the hurricanes. |
| o | Increased interest charges as results in 2003 were favorably impacted by the reversal of interest expense for resolved tax matters. |
| o | The impact of tax levelization. |
Partially offsetting these items were:
| o | Favorable weather in the Carolinas. |
| o | Reduction in revenue sharing provisions in Florida |
| o | Favorable customer growth in both the Carolinas and Florida. |
| o | Increased margins as a result of the allowed return on the Hines 2 Plant in Florida. |
| o | Lower depreciation and amortization costs at the utilities. |
| o | Increased earnings for natural gas and Rail operations. |
| o | Unrealized gains recorded on contingent value obligations. |
| o | Reduction in losses recorded for discontinued operations. |
Basic earnings per share decreased in 2004 due in part to the factors outlined above. Dilution related to the issuances under the Company’s Investor Plus Stock Purchase Plan and employee benefit programs in 2003 and 2004 also reduced basic earnings per share by $0.02 for the third quarter of 2004 and $0.06 for the nine months ended September 30, 2004.
Beginning in the fourth quarter of 2003, the Company ceased recording portions of Fuels segment’s operations, primarily synthetic fuel facilities, one month in arrears. As a result, earnings for the year ended December 31, 2003 included 13 months of operations, resulting in a net income increase of $2 million for the year. The Company restated previously reported consolidated quarterly earnings to reflect the new reporting periods which resulted in four months earnings in the first quarter of 2003 and changed reported net income for subsequent quarters. Earnings decreased $1 million for the three months ended September 30, 2003 and increased $14 million for the nine months ended September 30, 2003 as compared to amounts originally reported.
The Company’s segments contributed the following profits or losses for the three and nine months ended September 30, 2004 and 2003:
| (in millions) | Three Months Ended September 30 |
Nine Months Ended September 30 | |||||||
|---|---|---|---|---|---|---|---|---|---|
| Business Segment | 2004 | 2003 | 2004 | 2003 | |||||
| PEC Electric | $ 175 | $ 160 | $ 388 | $ 383 | |||||
| PEF | 140 | 115 | 273 | 247 | |||||
| Fuels | (36 | ) | 79 | 69 | 175 | ||||
| CCO | 15 | 13 | 11 | 23 | |||||
| Rail | 8 | 1 | 17 | — | |||||
| Other | — | (4 | ) | (32 | ) | (2 | ) | ||
| Total Segment Profit | 302 | 364 | 726 | 826 | |||||
| Corporate | 1 | (27 | ) | (162 | ) | (128 | ) | ||
| Income from continuing operations | 303 | 337 | 564 | 698 | |||||
| NCNG discontinued operations | — | (19 | ) | 1 | (5 | ) | |||
| Cumulative effect of change in accounting | |||||||||
| principle, net of tax | — | — | — | 1 | |||||
| Net income | $ 303 | $ 318 | $ 565 | $ 694 | |||||
In March 2003, the SEC completed an audit of Progress Energy Service Company, LLC (Service Company) and recommended that the Company change its cost allocation methodology for allocating Service Company costs. As part of the audit process, the Company was required to change the cost allocation methodology for 2003 and record retroactive reallocations between its affiliates in the first quarter of 2003 for allocations originally made in 2001 and 2002. This change in allocation methodology and the related retroactive adjustments have no impact on consolidated expense or earnings. The new allocation methodology, as compared to the previous allocation methodology, generally decreases expenses in the regulated utilities and increases expenses in the nonregulated businesses. The regulated utilities’ reallocations are within operation and maintenance (O&M) expense, while the diversified businesses’ reallocations are generally within diversified business expenses. The impact on the individual lines of business is included in the following discussions.
Cost Management Initiative
On October 12, 2004, Progress Energy announced to its employees a cost-management initiative to analyze the size and structure of the entire organization and reduce projected operating expenses over the next three years. This initiative is focused on reducing the rate of cost increases throughout the Company. These cost initiatives will likely require some workforce reductions. Among the options being considered is a voluntary early-retirement program. By 2007, the Company is estimating total annual savings of at least $75 million from this cost management initiative.
PROGRESS ENERGY CAROLINAS ELECTRIC
PEC Electric contributed segment profits of $175 million and $160 million for the three months ended September 30, 2004 and 2003, respectively, and $388 million and $383 million for the nine months ended September 30, 2004 and 2003, respectively. The increase in profits for the three months ended September 30, 2004 as compared to the same period in 2003 is due primarily to increased revenue from customer growth, lower O&M charges and the impact of losses booked on investments in limited partnerships in 2003, partially offset by lower wholesale revenues. The increase in profits for the nine months ended September 30, 2004 as compared to the same period in 2003 is primarily due to the favorable impact of weather, increased revenues from customer growth and lower depreciation and amortization charges, partially offset by lower wholesale revenues and higher O&M charges.
PEC Electric’s revenues for the three and nine months ended September 30, 2004 and 2003, and the percentage change by customer class are as follows:
| (in millions of $) | Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Customer Class | 2004 | Change | % Change | 2003 | 2004 | Change | % Change | 2003 | |||||||||
| Residential | $ 387 | $ 2 | 0 | .5 | $ 385 | $ 1,041 | $ 51 | 5 | .2 | $ 990 | |||||||
| Commercial | 256 | 6 | 2 | .4 | 250 | 677 | 27 | 4 | .2 | 650 | |||||||
| Industrial | 188 | 9 | 5 | .0 | 179 | 496 | 14 | 2 | .9 | 482 | |||||||
| Governmental | 24 | — | — | 24 | 62 | 2 | 3 | .3 | 60 | ||||||||
| Total retail revenues | 855 | 17 | 2 | .0 | 838 | 2,276 | 94 | 4 | .3 | 2,182 | |||||||
| Wholesale | 146 | (28 | ) | (16 | .1) | 174 | 441 | (97 | ) | (18 | .0) | 538 | |||||
| Unbilled | (11 | ) | 13 | — | (24 | ) | (9 | ) | 23 | — | (32 | ) | |||||
| Miscellaneous | 24 | 2 | 9 | .1 | 22 | 68 | 4 | 6 | .3 | 64 | |||||||
| Total electric revenues | $ 1,014 | $ 4 | 0 | .4 | $ 1,010 | $ 2,776 | $ 24 | 0 | .9 | $ 2,752 | |||||||
PEC Electric’s energy sales for the three and nine months ended September 30, 2004 and 2003, and the amount and percentage change by customer class are as follows:
| (in thousands of mWh) | Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Customer Class | 2004 | Change | % Change | 2003 | 2004 | Change | % Change | 2003 | |||||||||
| Residential | 4,405 | (19 | ) | (0 | .4) | 4,424 | 12,671 | 608 | 5 | .0 | 12,063 | ||||||
| Commercial | 3,752 | 65 | 1 | .8 | 3,687 | 9,982 | 366 | 3 | .8 | 9,616 | |||||||
| Industrial | 3,550 | 137 | 4 | .0 | 3,413 | 9,823 | 207 | 2 | .2 | 9,616 | |||||||
| Governmental | 414 | (6 | ) | (1 | .4) | 420 | 1,096 | 15 | 1 | .4 | 1,081 | ||||||
| Total retail revenues | 12,121 | 177 | 1 | .5 | 11,944 | 33,572 | 1,196 | 3 | .7 | 32,376 | |||||||
| Wholesale | 3,244 | (706 | ) | (17 | .9) | 3,950 | 10,148 | (1,722 | ) | (14 | .5) | 11,870 | |||||
| Unbilled | (300 | ) | 164 | — | (464 | ) | (280 | ) | 269 | — | (549 | ) | |||||
| Total mWh sales | 15,065 | (365 | ) | (2 | .4) | 15,430 | 43,440 | (257 | ) | (0 | .6) | 43,697 | |||||
Three months ended September 30, 2004 compared to the three months ended September 30, 2003
PEC Electric’s revenues, excluding recoverable fuel revenues of $183 million and $180 million for the three months ended September 30, 2004 and 2003, respectively, increased $1 million. The increase in retail revenues was due primarily to favorable customer growth offset by unfavorable weather. PEC Electric has approximately 26,000 additional customers as of September 30, 2004 compared to September 30, 2003. Weather was unfavorable due primarily to a reduction in cooling and heating degree days of 3% and 56%, respectively, compared to prior quarter. The increase in retail revenues was offset partially by a reduction in wholesale revenues. The reduction in wholesale revenues is due primarily to weaker power market conditions, increased fuel prices and lower contracted capacity in the wholesale market. PEC monitors its wholesale contract portfolio on a regular basis. During 2003 and 2004, several contracts expired or were renegotiated with less favorable terms. Due to the slightly depressed wholesale market and increased competition, this trend could continue as contracts are renewed in the upcoming years.
Fuel and purchased power costs represent the costs of generation, which includes fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and purchased power expenses are recovered primarily through cost recovery clauses and, as such, changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that is subject to recovery is deferred for future collection or refund to customers.
Fuel and purchased power expenses decreased $16 million from $332 million for the three months ended September 30, 2003 to $316 million for the three months ended September 30, 2004. Fuel used in electric generation decreased $14 million to $220 compared to the same period in the prior year. This decrease is due to a reduction in deferred fuel expense of $30 million as a result of the underrecovery of current period fuel costs offset by an increase in fuel used in generation of $16 million due primarily to higher coal costs. Purchased power expenses decreased $2 million to $96 million compared to prior year.
O&M costs were $197 million for the three months ended September 30, 2004, which represents an $8 million decrease compared to the same period in 2003. O&M costs decreased $8 million due primarily to lower benefits expenses resulting from favorable adjustments to pension and OPEB obligations based on the latest actuarial valuations which reflected the implementation of FASB Staff Position 106-2 for OPEB obligations. See discussion in Note 2 to the Progress Energy Consolidated Interim Financial Statements.
Hurricanes Charley and Ivan struck portions of PEC’s service territory during the third quarter of 2004. Restoration of the PEC’s system from hurricane-related damage is estimated at $13 million, of which $12 million has been charged to O&M expenses and $1 million has been charged to capital expenditures. Storm costs for 2004 did not significantly reduce earnings when compared to the prior year quarter as results for the three months ended September 30, 2003 included restoration costs related to Hurricane Isabel.
PEC does not have an on-going regulatory mechanism to recover storm costs and; therefore, hurricane restoration costs recorded in the third quarter of 2004 have been charged to O&M expenses or capital expenditures based on the nature of the work performed. In connection with other storms, PEC has previously sought and received permission for the North Carolina Utilities Commission (NCUC) and the Public Service Commision of South Carolina (SCPSC) to defer storm expenses and amortize them over a five-year period. PEC is planning to seek deferral of 2004 storm costs in the fourth quarter of 2004.
Depreciation and amortization expense increased $4 million from $135 million for the quarter ended September 30, 2003 to $139 million for the quarter ended September 30, 2004. The increase compared to prior quarter is due to increased clean air amortization of $20 million compared to the prior year and higher depreciation expense due to assets placed in service of $3 million. In addition, a depreciation adjustment was made to increase depreciation expense by $7 million in the third quarter of 2004 for cost of removal. These items were partially offset by the impact of the depreciation study and the impact of an adjustment booked in 2003 related to the SFAS No. 143 implementation. During the first half of 2004, PEC Electric filed with the NCUC and obtained approval from the SCPSC for a depreciation study which allowed the utility to reduce the rates used to calculate depreciation expense. As a result, depreciation expense decreased $7 million compared to the prior year quarter. In October 2004, PEC filed a revised depreciation study with the NCUC and the SCPSC supporting a reduction in annual depreciation expense of approximately $47 million. The reduction is due solely to extended lives at each of PEC’s nuclear units. The new depreciation rates are proposed to be effective January 1, 2004. Depreciation expense also decreased $14 million from the impact of an adjustment booked in 2003 related to the implementation of SFAS No. 143. In the prior year, PEC filed a request with the NCUC requesting deferral of the difference between expense pursuant to SFAS No. 143 and expense as previously determined by the NCUC. The NCUC granted deferral of the cumulative adjustment but denied deferral of the ongoing effects. As a result, PEC ceased deferral of the ongoing effects during the second quarter of 2003 related to its North Carolina retail rate jurisdictions. This resulted in a reduction of depreciation and amortization expense for the quarter ended June 30, 2003 of $14 million which represented a decrease in non-ARO cost of removal expense partially offset by an increase in decommissioning expense. In August 2003, the NCUC revised its decision and approved deferral of the ongoing effects of SFAS No. 143 at which time the $14 million reduction was reversed which increased depreciation and amortization for the quarter ended September 30, 2003.
Other expenses have decreased $11 million for the three months ended September 30, 2004 as compared to the same period in the prior year. This decrease is primarily due to losses on limited partnership investments recorded in 2003.
Nine months ended September 30, 2004 compared to the nine months ended September 30, 2003
PEC Electric’s revenues, excluding recoverable fuel revenues of $505 million and $473 million for the nine months ended September 30, 2004 and 2003, respectively, decreased $8 million. The decrease in revenues was due primarily to lower wholesale sales. Wholesale revenues decreased $97 million from $538 million to $441 million. Revenues for the nine months ended September 30, 2003 included strong sales to the Northeastern United States as a result of favorable market conditions. The decline in wholesale revenues was partially offset by increased retail revenues of $38 million as a result of favorable weather, with cooling degree days and heating degree days 15% and 1%, respectively, above prior year. In addition, favorable customer growth increased revenue $42 million, partially offsetting the decrease in wholesale sales.
Fuel and purchased power costs represent the costs of generation, which includes fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and purchased power expenses are recovered primarily through cost recovery clauses and, as such, changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that is subject to recovery is deferred for future collection or refund to customers.
Fuel and purchased power expenses were $875 million for the nine months ended September 30, 2004, which represents a $2 million decrease compared to the same period in the prior year. This decrease is due to a reduction in deferred fuel expense as a result of the underrecovery of current period fuel costs offset by an increase in fuel used in generation due primarily to higher coal costs. Purchased power expenses decreased $2 million to $238 million compared to prior year.
O&M costs were $632 million for the nine months ended September 30, 2004, which represents a $27 million increase compared to the same period in 2003. O&M costs increased $21 million primarily due to an increase in outage scope and duration at the nuclear plants. In addition, O&M charges were favorably impacted by $16 million related to the retroactive reallocation of Service Company costs in the prior year. These increases were partially offset by a reduction in storm restoration costs of $7 million compared to the prior year. Storm costs for the nine months ended September 30, 2003 were $25 million and included costs associated with the major ice storms and Hurricane Isabel. Storm costs for the nine months ended September 30, 2004 were $18 million and included costs related to an ice storm and Hurricanes Charley and Ivan.
Depreciation and amortization expense decreased $23 million from $416 million for the nine months ended September 30, 2003 to $393 million for the nine months ended September 30, 2004. As previously discussed, PEC filed a depreciation study which allowed the utility to reduce the rates used to calculate depreciation expense. The impact of the study for the nine months ended September 30, 2004 was a reduction of depreciation of $17 million compared to the same prior year period. In addition, clean air amortization for the nine months ended September 30, 2004 decreased $3 million compared to the same prior year period. These decreases were partially offset by increases for assets placed in service.
Taxes other than on income increased $8 million from $124 million for the nine months ended September 30, 2003 to $132 million for the nine months ended September 30, 2004. This increase is due to an increase in gross receipts taxes of $5 million related to an increase in revenues and a 2004 adjustment related to the prior year. The remaining variance in other taxes is due to an increase in property taxes of $3 million.
PROGRESS ENERGY FLORIDA
PEF contributed segment profits of $140 million and $115 million for the three months ended September 30, 2004 and 2003, respectively, and $273 million and $247 million for the nine months ended September 30, 2004 and 2003, respectively. The increase in profits for the three months ended September 30, 2004 when compared to 2003 is primarily due to favorable weather and customer growth, increased wholesale sales, the additional return on investment for the Hines 2 plant and reduced O&M expenditures. These items were partially offset by the reduction in revenues related to major storms and increased interest expense. Profits for the nine months ended September 30, 2004 increased due to a reduction in the provision for revenue sharing, favorable customer growth, the additional return on investment on the Hines 2 plant and reduced O&M expenses. These items were partially offset by unfavorable weather, a reduction in revenues related to the hurricanes, increased interest expenses and increased depreciation expense from assets placed in service.
PEF’s electric revenues for the three and nine months ended September 30, 2004 and 2003, and the amount and percentage change by customer class are as follows:
| (in millions of $) | Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Customer Class | 2004 | Change | % Change | 2003 | 2004 | Change | % Change | 2003 | |||||||||
| Residential | $ 554 | $ 52 | 10 | .4 | $ 502 | $ 1,378 | $ 78 | 6 | .0 | $ 1,300 | |||||||
| Commercial | 242 | 28 | 13 | .1 | 214 | 637 | 80 | 14 | .4 | 557 | |||||||
| Industrial | 64 | 7 | 12 | .3 | 57 | 192 | 32 | 20 | .0 | 160 | |||||||
| Governmental | 56 | 7 | 14 | .3 | 49 | 155 | 22 | 16 | .5 | 133 | |||||||
| Retail revenue sharing | 5 | 1 | 25 | .0 | 4 | (2 | ) | 22 | 91 | .7 | (24 | ) | |||||
| Total retail revenues | 921 | 95 | 11 | .5 | 826 | 2,360 | 234 | 11 | .0 | 2,126 | |||||||
| Wholesale | 79 | 27 | 51 | .9 | 52 | 199 | 26 | 15 | .0 | 173 | |||||||
| Unbilled | (5 | ) | (1 | ) | — | (4 | ) | 13 | 10 | — | 3 | ||||||
| Miscellaneous | 34 | 4 | 13 | .3 | 30 | 101 | 4 | 4 | .1 | 97 | |||||||
| Total electric revenues | $ 1,029 | $ 125 | 13 | .8 | $ 904 | $ 2,673 | $274 | 11 | .4 | $ 2,399 | |||||||
PEF’s electric energy sales for the three and nine months ended September 30, 2004 and 2003, and the amount and percentage change by customer class are as follows:
| (in thousands of mWh) | Three Months Ended September 30 | Nine Months Ended September 30 | |||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| Customer Class | 2004 | Change | % Change | 2003 | 2004 | Change | % Change | 2003 | |||||||||
| Residential | 5,981 | 242 | 4 | .2 | 5,739 | 14,777 | (219 | ) | (1 | .5) | 14,996 | ||||||
| Commercial | 3,334 | — | — | 3,334 | 8,766 | 39 | 0 | .4 | 8,727 | ||||||||
| Industrial | 1,014 | (14 | ) | (1 | .4) | 1,028 | 3,088 | 137 | 4 | .6 | 2,951 | ||||||
| Governmental | 818 | 13 | 1 | .6 | 805 | 2,241 | 37 | 1 | .7 | 2,204 | |||||||
| Total retail energy sales | 11,147 | 241 | 2 | .2 | 10,906 | 28,872 | (6 | ) | — | 28,878 | |||||||
| Wholesale | 1,394 | 388 | 38 | .6 | 1,006 | 3,809 | 637 | 20 | .1 | 3,172 | |||||||
| Unbilled | (146 | ) | (34 | ) | — | (112 | ) | 509 | 68 | — | 441 | ||||||
| Total mWh sales | 12,395 | 595 | 5 | .0 | 11,800 | 33,190 | 699 | 2 | .2 | 32,491 | |||||||
Three months ended September 30, 2004 compared to the three months ended September 30, 2003
PEF’s revenues, excluding recoverable fuel and other pass-through revenues of $588 million and $485 million for the three months ended September 30, 2004 and 2003, respectively, increased $22 million. This increase was due to favorable customer growth and weather (excluding the hurricane impacts), and increased wholesale sales. Favorable customer growth contributed an additional $13 million compared to the prior quarter. PEF has approximately 31,000 additional customers as of September 30, 2004 compared to September 30, 2003. The impact of favorable weather resulted in an $8 million increase in revenues. Wholesale revenues are $7 million higher compared to prior quarter as a result of signing new contracts and extending pre-existing contracts. Included in fuel revenues is the return on Hines 2 which contributed $9 million in additional revenues. Based on the Stipulation and Settlement Agreement reached with the FPSC in April 2002, beginning with the in-service date of PEF’s Hines Unit 2 and continuing through December 2005, PEF will be allowed to recover through the fuel cost recovery clause a return on average investment and depreciation expense for Hines Unit 2, to the extent such costs do not exceed the Unit’s cumulative fuel cost savings over the recovery period. These increases were offset partially by the reduction in revenues of approximately $12 million related to customer outages caused by Hurricanes Charley, Frances and Jeanne.
Fuel and purchased power costs represent the costs of generation, which includes fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and purchased power expenses are recovered primarily through cost recovery clauses and, as such, changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that is subject to recovery is deferred for future collection or refund to customers.
Fuel and purchased power expenses increased $97 million from $411 million for the three months ended September 30, 2003 to $508 million for the three months ended September 30, 2004. This increase is attributable primarily to an increase in fuel used in electric generation which increased $80 million. Higher system requirements and increased fuel costs in the current year account for $66 million of the $80 million increase in fuel used in electric generation. The remaining increase is due to the recovery of fuel expenses that were deferred in the prior year. Purchased power expenses increased $17 million compared to the prior quarter due to higher system requirements and an increase in prices.
O&M costs decreased $25 million, when compared to the $163 million incurred during the three months ended September 30, 2003. This decrease is primarily related to lower business unit spending of $17 million due the timing of outages and maintenance activities at generation facilities (including the nuclear outage costs in the prior year) and the delay of several major projects due to storm restoration work (storm costs are recorded in the storm reserve). In addition, benefit-related costs decreased $11 million due primarily to pension and OPEB adjustments which were recorded during the current quarter based on the latest actuarial valuations which reflected the implementation of FASB Staff Position 106-2 for OPEB obligations. See discussion in Note 2 to the Consolidated Interim Financial Statements.
Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of PEF’s service territory during the third quarter of 2004. PEF incurred total costs of $366 million, of which $55 million has been charged to capital expenditures, and $311 million has been charged to the storm damage reserve.
In accordance with a regulatory order, PEF accrues $6 million annually to a storm damage reserve and is allowed to defer losses in excess of the accumulated reserve. Under the order, the storm reserve is charged with O&M expenses related to storm restoration and with capital expenditures related to storm restoration that are in excess of expenditures assuming normal operating conditions. As of September 30, 2004, $266 million of hurricane restoration costs in excess of the previously recorded storm reserve have been classified as a regulatory asset in order to recognize the probable recoverability of these costs. On November 2, 2004, PEF filed a petition with the Florida Public Service Commission (FPSC) to recover $252 million of storm costs plus interest from retail ratepayers over a two-year period. See discussion in Note 3 to the Consolidated Financial Statements.
Depreciation and amortization decreased $14 million when compared to the $82 million incurred during the three months ended September 30, 2003, primarily due to the amortization of the Tiger Bay regulatory asset in the prior year. The Tiger Bay regulatory asset, for contract termination costs, was recovered pursuant to an agreement between PEF and the FPSC which was approved in 1997. The amortization of the regulatory asset was calculated using revenues collected under the fuel adjustment clause; as such, fluctuations in this expense did not have an impact on earnings. During the third quarter of 2003, Tiger Bay amortization was $17 million. The Tiger Bay asset was fully amortized in September 2003. The decrease in Tiger Bay amortization was partially offset by additional depreciation for assets placed in service.
Interest charges increased $17 million from $10 million for the quarter ended September 30, 2003 to $27 million for the quarter ended September 30, 2004. Interest costs in 2003 were favorably impacted by the reversal of interest expense due to the resolution of certain tax matters.
Nine months ended September 30, 2004 compared to the nine months ended September 30, 2003
PEF’s revenues, excluding recoverable fuel and other pass-through revenues of $1,513 million and $1,279 million for the nine months ended September 30, 2004 and 2003, respectively, increased $40 million. This increase was due primarily to a reduction in the provision for revenue sharing of $22 million. Results for 2003 included the accrual of an additional $18 million related to the 2002 revenue sharing provision as ordered by the FPSC in June of 2003. In addition, favorable customer growth and increased wholesale sales increased revenues by $22 million and $9 million, respectively. Included in fuel revenues is the return on Hines Unit 2, which contributed $27 million in additional revenues in 2004. These increases were partially offset by the reduction in revenues related to customer outages for Hurricanes Charley, Frances and Jeanne of approximately $12 million and the impact of milder weather in the current year of approximately $9 million.
Fuel and purchased power costs represent the costs of generation, which includes fuel purchases for generation, as well as energy purchased in the market to meet customer load. Fuel and purchased power expenses are recovered primarily through cost recovery clauses and, as such, changes in these expenses do not have a material impact on earnings. The difference between fuel and purchased power costs incurred and associated fuel revenues that is subject to recovery is deferred for future collection or refund to customers.
Fuel and purchased power expenses were $1,313 million for the nine months ended September 30, 2004, which represents a $229 million increase compared to the same period in the prior year. This increase is due to increases in fuel used in electric generation and purchased power expenses of $223 million and $6 million, respectively. Higher system requirements and increased fuel costs in the current year account for $75 million of the increase in fuel used in electric generation. The remaining increase is due to the recovery of fuel expenses that were deferred in the prior year, partially offset by the deferral of current year underrecovered fuel expenses. In November 2003, the FPSC approved PEF’s request for a cost adjustment in its annual fuel filing due to the rising costs of fuel. The new rates became effective January 2004.
O&M costs decreased $8 million, when compared to the $458 million incurred during the nine months ended September 30, 2003. This decrease is primarily related to favorable benefit related costs of $9 million, primarily pension and OPEB adjustments which were recorded based on the latest actuarial valuations which reflected the implementation of FASB Staff Position 106-2 for OPEB obligations. See discussion in Note 2 to the Consolidated Interim Financial Statements.
Depreciation and amortization decreased $32 million when compared to the $241 million incurred during the nine months ended September 30, 2003, primarily due to the amortization of the Tiger Bay regulatory asset in the prior year. The Tiger Bay regulatory asset, for contract termination costs, was recovered pursuant to an agreement between PEF and the FPSC which was approved in 1997. The amortization of the regulatory asset was calculated using revenues collected under the fuel adjustment clause; as such, fluctuations in this expense did not have an impact on earnings. During the nine months ended September 30, 2003, Tiger Bay amortization was $47 million. The Tiger Bay asset was fully amortized in September 2003. The decrease in Tiger Bay amortization was partially offset by additional depreciation for assets placed in service, including expenses for Hines Unit 2 of approximately $7 million. This depreciation expense is being recovered through the fuel cost recovery clause as allowed by the FPSC. See discussion of the return in the revenues analysis above.
Taxes other than on income have increased $16 million from $180 million for the nine months ended September 30, 2003 to $196 million for the nine months ended September 30, 2004. This increase is due to increases in gross receipts and franchise taxes of $6 million and $5 million, respectively, related to an increase in revenues and an increase in property taxes of $7 million due to increases in property placed in service and tax rate increases.
Interest charges increased $19 million from $68 million for the nine months ended September 30, 2003 to $87 million for the nine months ended September 30, 2004. Interest costs in 2003 were favorably impacted by the reversal of interest expense due to the resolution of certain tax matters.
DIVERSIFIED BUSINESSES
The Company’s diversified businesses consist of the Fuels segment, the CCO segment, the Rail segment and the Other segment. These businesses are explained in more detail below.
FUELS
The Fuels’ segment operations include synthetic fuels production, natural gas production, coal extraction and terminal operations. Fuels’ results for the nine months ended September 30, 2003 were restated to reflect ten months of earnings for certain operations, primarily synthetic fuel facilities.
The following summarizes Fuels’ segment profits for the three and nine months ended September 30, 2004 and 2003:
| Three Months Ended September 30 |
Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Synthetic fuel operations | $(57 | ) | $60 | $15 | $143 | ||||
| Gas production | 15 | 10 | 40 | 26 | |||||
| Coal and other operations | 6 | 9 | 14 | 6 | |||||
| Segments Profits | $(36 | ) | $79 | $69 | $175 | ||||
Synthetic Fuel Operations
The synthetic fuel operations generated net losses of $57 million for the three months ended September 30, 2004 compared to net profits of $60 million for the three months ended September 30, 2003. Synthetic fuel operations generated segment profits of $15 million and $143 million for the nine months ended September 30, 2004 and 2003, respectively. The production and sale of synthetic fuel generate operating losses, but qualify for tax credits under Section 29 of the Code, which more than offset the effect of such losses. See Note 15 to the Progress Energy Notes to the Consolidated Interim Financial Statements for further discussion of synthetic fuel tax credit matters.
The operations resulted in the following for the three and nine months ended September 30, 2004 and 2003:
| Three Months Ended September 30 |
Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Tons sold | 2.1 | 3.0 | 7.7 | 8.5 | |||||
| Operating losses, excluding tax credits | $(33 | ) | $(31 | ) | $(110 | ) | $(97 | ) | |
| Tax credits generated | 55 | 91 | 204 | 240 | |||||
| Tax credits reversed | (79 | ) | — | (79 | ) | — | |||
| Net profits | $(57 | ) | $ 60 | $ 15 | $ 143 | ||||
Synthetic fuel operations net profits decreased in the three months ended September 30, 2004 as compared to the same period in 2003 due primarily to a decrease in synthetic fuel production and the recording of a charge related to tax credits as a result of hurricane costs (as described above) which reduced the Company’s projected 2004 regular tax liability. These factors also explain the decrease in synthetic fuels net profits for the nine months ended September 30, 2004. The Company’s anticipated 2004 tax liability is based on approximately five million tons. As such, the Company recorded a charge of $79 million for tax credits associated with approximately 2.7 million tons sold during the year which the Company anticipates cannot be used. The Company anticipates total synthetic fuel production of approximately eight million tons in 2004 which is down compared to 2003 production levels of approximately 12 million tons. The Company has ceased production at its Earthco facilities for the remainder of 2004 due to the decrease in tax appetite.
Natural Gas Operations
Natural gas operations generated profits of $15 million and $10 million for the three months ended September 30, 2004 and 2003, respectively, and $40 million and $26 million for the nine months ended September 30, 2004 and 2003, respectively. There is an increase in production resulting from the acquisition of North Texas Gas in late February 2003, along with increased drilling. The increase in production, coupled with higher gas prices in 2004, contributed to the increased earnings in 2004 as compared to 2003. Volume and prices have increased 17% and 22%, respectively, compared to the three months ended September 30, 2003. Volume and prices have increased 20% and 17%, respectively, for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003. In October 2003, the Company completed the sale of certain gas producing properties owned by Mesa Hydrocarbons, LLC. The following summarizes the gas production, revenues and gross margins for the three and nine months ended September 30, 2004 and 2003 by production facility:
| Three Months Ended September 30 | Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| 2004 | 2003 | 2004 | 2003 | ||||||
| Production in Bcf equivalent | |||||||||
| Mesa | — | 1.3 | — | 4.5 | |||||
| Westchester | 5.7 | 3.6 | 14.7 | 9.9 | |||||
| North Texas Gas | 2.9 | 2.4 | 8.2 | 4.8 | |||||
| Total Production | 8.6 | 7.3 | 22.9 | 19.2 | |||||
| Revenues in millions | |||||||||
| Mesa | $— | $ 4 | $ — | $12 | |||||
| Westchester | 32 | 18 | 80 | 49 | |||||
| North Texas Gas | 14 | 12 | 41 | 26 | |||||
| Total Revenues | $46 | $34 | $121 | $87 | |||||
| Gross Margin | |||||||||
| in millions of $ | $37 | $26 | $ 97 | $69 | |||||
| As a % of revenues | 80 | % | 76 | % | 80 | % | 79 | % | |
Coal and Other Operations
Coal and other operations generated segment profits of $6 million for the three months ended September 30, 2004 compared to $9 million segment profits for the comparable period in the prior year. The decrease in profits of $3 million is due primarily to reduced earnings from fuel transportation operations related to the waterborne transportation ruling by the FPSC. This ruling reduced the price charged to PEF for waterborne coal deliveries by the fuel transportation operations of the Fuels’ segment. See Note 6A of the Progress Energy Consolidated Interim Financial Statements. For the nine months ended September 30, 2004, coal fuel and other operations generated segment profits of $14 million compared to segment profits of $6 million for the comparable period in the prior year. This increase in profits for the year to date is due primarily to higher volumes and margins for coal fuel operations of $15 million after-tax offset by a reduction in profits of $7 million after-tax for fuel transportation operations related to the waterborne transportation ruling by the FPSC as discussed above. The increase in profits is also due to the impact of the retroactive Service Company allocation in the prior year. Results in the same period for the prior year were negatively impacted by the retroactive reallocation of Service Company costs of $4 million after-tax.
The Company has begun exploring strategic alternatives regarding the Fuels’ coal mining business. As of September 30, 2004 the carrying value of long-lived assets of the coal mining business were $61 million. As a result of this initiative, the Company may trigger an impairment review in the fourth quarter of 2004; however, the Company cannot currently predict the outcome of this matter.
COMPETITIVE COMMERCIAL OPERATIONS
CCO’s operations generated segment profits of $15 million for the three months ended September 30, 2004 compared to $13 million of segment profits for the comparable period in the prior year. Results for the three months ended September 30, 2004 were favorably impacted by an increase in margins from serving new and existing contracts and market sales of $8 million pre-tax partially offset by an increase in fixed costs. Fixed costs increased $2 million pre-tax from interest expense due primarily to interest no longer being capitalized due to the completion of construction in the prior year and from an increase in gas transportation expenses of $2 million pre-tax. Results for 2004 include a full quarter’s charge for gas transportation services while results for 2003 include only one month’s service charges.
CCO’s operations generated segment profits of $11 million for the nine months ended September 30, 2004 compared to $23 million of segment profits for the comparable period in the prior year. Results for the nine months ended September 30, 2004 were favorably impacted by increased gross margin which was more than offset by higher fixed costs. Revenues increased $58 million pre-tax in the nine months ended September 30, 2004 due to increased revenues from marketing and tolling contracts offset by a termination payment received on a marketing contract in 2003 and current period realized and unrealized losses of $11 million pre-tax on contracts subject to mark to market accounting. Expenses for the cost of fuel and purchased power to supply marketing contracts offset the increased revenues of $58 million netting to an increase in gross margin of $13 million pre-tax for the nine months ended September 30, 2004 as compared to the same prior year period. Fixed costs increased $15 million pre-tax from additional depreciation and amortization on plants placed into service in 2003 and from an increase in interest expense of $13 million pre-tax due primarily to interest no longer being capitalized due to the completion of construction in the prior year. In addition, plant operating expenses increased $9 million pre-tax primarily due to higher gas transportation service charges which increased over prior year due to full period of expenses being reflected in current year results. Expenses were favorably impacted by a reduction in Service Company allocations. Results for 2003 were negatively impacted by the retroactive reallocation of Service Company costs of $3 million ($2 million after-tax).
| Three Months Ended September 30 | Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Total revenues | $90 | $67 | $196 | $137 | |||||
| Gross margin | |||||||||
| In millions of $ | $63 | $54 | $128 | $115 | |||||
| As a % of revenues | 70 | % | 81 | % | 65 | % | 84 | % | |
| Segment profits (losses) | $15 | $13 | $ 11 | $ 23 | |||||
The Company has contracts for 93% of planned production capacity for 2004 and approximately 77% in both 2005 and 2006. The 2005 decline results from the expiration of three tolling contracts. The Company continues to pursue opportunities with both current and potential new customers.
RAIL
Rail’s operations include railcar and locomotive repair, trackwork, rail parts reconditioning and sales, scrap metal recycling and other rail related services. The Company sold the majority of the assets of Railcar Ltd., a leasing subsidiary, in 2004. See Note 4B of the Progress Energy Notes to the Consolidated Interim Financial Statements.
Rail contributed segment profits of $8 million and $1 million for the three months ended September 30, 2004 and 2003, respectively. Revenues have increased $81 million to $291 million for the three months ended September 30, 2004 compared to the same period in the prior year. This increase is due primarily to increased volumes and higher prices in recycling operations and in part to increased production and sales in locomotive and railcar services and engineering and track services. Cost of goods sold increased $71 million from $182 million in the prior year. The increase in costs of good sold is due to increased costs for inventory, labor and operations as a result of the increased volume in the recycling operations, locomotive and railcar services and engineering and track services.
Rail contributed segment profit of $17 million for the nine months ended September 30, 2004 compared with a segment loss of less than $1 million for the same period in the prior year. Revenues increased $215 million to $816 million for the nine months ended September 30, 2004 compared to the same period in the prior year. This increase is due primarily to increased volumes and higher prices in recycling operations and in part to increased production and sales in locomotive and railcar services and engineering and track services. Tonnage for recycling operations is up 10 to 15% on an annualized basis compared to 2003. The increase in tonnage coupled with an increase in the average index price of approximately 90% accounts for the significant increase in revenues year over year. The American Metal Market index price for #1 rail road heavy melt (which is used as the index for buying and selling of railcars) has increased to $198 as of September 30, 2004 from $104 as of September 30, 2003. Cost of goods sold increased $183 million from $525 million in the prior year. The increase in costs of good sold is due to increased costs for inventory, labor and operations as a result of the increased volume in the recycling operations, locomotive and railcar services and engineering and track services. Results in the prior year were negatively impacted by the retroactive reallocation of Service Company costs of $3 million after-tax. The favorability related to the reallocation was offset by an increase in general and administrative costs in the current year related primarily to higher professional fees.
OTHER BUSINESSES SEGMENT
Progress Energy’s Other segment primarily includes the operations of SRS and the telecommunications operations of PT LLC. SRS is engaged in providing energy services to industrial, commercial and institutional customers to help manage energy costs and currently focuses its activities in the southeastern United States. PT LLC operations provide broadband capacity services, dark fiber and wireless services in Florida and the eastern United States.
SRS recorded a segment profit of less than $1 million for the three months ended September 30, 2004 compared with net loss of $1 million for the same period in the prior year. SRS recorded a net loss of $29 million for the nine months ended September 30, 2004 compared to a net loss of $1 million for the nine months ended September 30, 2004. The increased nine-month segment loss compared to the prior year is due primarily to the recording of the litigation settlement reached with San Francisco United School District related to civil proceedings. In June 2004, SRS reached a settlement with the District which settled all outstanding claims for approximately $43 million pre-tax ($29 million after-tax). See additional discussion in Note 15 to the Progress Energy Consolidated Interim Financial Statements.
CORPORATE SERVICES
Corporate Services includes the operations of the Holding Company, the Service Company and consolidation entities, as summarized below:
| Three Months Ended September 30 | Nine Months Ended September 30 | ||||||||
|---|---|---|---|---|---|---|---|---|---|
| (in millions) | 2004 | 2003 | 2004 | 2003 | |||||
| Other interest expense | $(64 | ) | $(73 | ) | $(202 | ) | $(208 | ) | |
| Contingent value obligations | 20 | (4 | ) | 7 | (4 | ) | |||
| Tax levelization | 38 | 35 | (6 | ) | 41 | ||||
| Tax reallocation | (9 | ) | (9 | ) | (27 | ) | (27 | ) | |
| Other income taxes | 13 | 32 | 72 | 94 | |||||
| Other | 3 | (8 | ) | (6 | ) | (24 | ) | ||
| Segment profit (loss) | $ 1 | $(27 | ) | $(162 | ) | $(128 | ) | ||
Other interest expense decreased $9 million to $64 million compared to $73 million for the three months ended September 30, 2003 and decreased $6 million compared to $202 million for the nine months ended September 30, 2003. Interest expense decreased during the current periods due to the repayment of a $500 million unsecured note by the Holding Company on March 1, 2004 which reduced interest expense by $8 million pre-tax for the quarter and $19 million pre-tax for the year to date. For the year to date this reduction was offset by interest no longer being capitalized due to the completion of construction at the CCO segment in the prior year. Approximately $10 million ($6 million after-tax) was capitalized in the nine months ended September 30, 2003. No interest expense was capitalized for the quarter ended September 30, 2003.
Progress Energy issued 98.6 million contingent value obligations (CVOs) in connection with the acquisition of FPC in 2000. Each CVO represents the right to receive contingent payments based on the performance of four synthetic fuel facilities owned by Progress Energy. The payments, if any, are based on the net after-tax cash flows the facilities generate. At September 30, 2004 and 2003, the CVOs had fair market values of approximately $16 million and $18 million, respectively. Progress Energy recorded an unrealized gain of $20 million for the three months ended September 30, 2004 and an unrealized loss of $4 million for the three months ended September 30, 2003 to record the changes in fair value of the CVOs, which had average unit prices of $0.16 and $0.18 at September 30, 2004 and 2003, respectively. Progress Energy recorded an unrealized gain of $7 million and an unrealized loss of $4 million for nine months ended September 30, 2004 and 2003, respectively.
GAAP requires companies to apply a levelized effective tax rate to interim periods that is consistent with the estimated annual effective tax rate. Income tax expense was decreased by $38 million and $35 million for the three months ended September 30, 2004 and 2003, respectively, in order to maintain an effective tax rate consistent with the estimated annual rate. Income tax expense was increased by $6 million and decreased by $41 million for the nine months ended September 30, 2004 and 2003, respectively. The tax credits associated with the Company’s synthetic fuel operations primarily drive the required levelization amount. Fluctuations in estimated annual earnings and tax credits can also cause large swings in the effective tax rate for interim periods. Therefore, this adjustment will vary each quarter, but will have no effect on net income for the year.
Progress Energy and its affiliates file a consolidated federal income tax return. The consolidated income tax of Progress Energy is allocated to subsidiaries in accordance with the Inter-company Income Tax Allocation Agreement (Tax Agreement). The Tax Agreement provided an allocation that recognizes positive and negative corporate taxable income. The Tax Agreement provides for an equitable method of apportioning the carry over of uncompensated tax benefits. Progress Energy tax benefits not related to acquisition interest expense are allocated to profitable subsidiaries, beginning in 2002, in accordance with a PUHCA order.
Other income taxes benefit decreased $19 million when compared to $32 million for the quarter ended September 30, 2004. This decrease is due primarily to increased taxes booked at the Holding Company of $15 million. The tax increase at Holding Company is due to a reduction in Florida consolidated return tax benefit of approximately $8 million due to the impact of the hurricanes. Income taxes increased an additional $6 million at the Holding Company as a result of a reserve booked related to identified state tax deficiencies. Other income taxes benefit decreased $22 million for the nine months ended September 30, 2004 compared to $94 million for the nine months ended September 30, 2003. This decrease is due primarily to the factors discussed for the quarter to date above.
Other expenses decreased $11 million and $18 million for the three and nine months ended September 30, 2004 and 2003, respectively, as compared to the same prior year periods. The $18 million decrease compared to prior year is due to reductions at the Service Company and the Holding Company. Other expense decreased compared to the prior year due to a reduction in Service Company expenses of approximately $6 million driven by decreases in advertising expenses due a shift in timing of promotions compared to prior year, reduced supply expense due to completion of a major project in prior year. These favorable items were offset partially by increased salaries and benefits due primarily to merit increases and incentive payouts related to storm support. Other costs at the Holding Company decreased $11 million compared to prior year due primarily to the impact of the retroactive reallocation of Service Company costs in the prior year. Other expenses for the prior year included $5 million in expenses based on the reallocation. An additional $3 million of favorability at the Holding Company is a result of a reduction of other taxes of approximately $3 million related to a 2003 assessment received from the South Carolina Department of Revenue which reduced the South Carolina license fee. These favorable items were offset by an increase in depreciation at the Service Company due to assets being placed in service.
DISCONTINUED OPERATIONS
In 2002, the Company approved the sale of NCNG to Piedmont Natural Gas Company, Inc. The sale closed on September 30, 2003. Net proceeds of approximately $443 million from the sale of NCNG were used to reduce outstanding short-term debt. NCNG contributed $19 million of net loss for the three months ended September 30, 2003. NCNG contributed $1 million of net income for the nine months ended September 30, 2004 compared to $5 million net loss for the comparable prior year period. During the nine months ended September 30, 2004, the Company recorded a reduction to the loss on the sale of NCNG of approximately $1 million after-tax related to deferred taxes.
LIQUIDITY AND CAPITAL RESOURCES
Progress Energy, Inc.
Progress Energy is a registered holding company and, as such, has no operations of its own. As a holding company, Progress Energy’s primary cash needs are funding its common dividend and interest expense. The ability to meet its cash needs is primarily dependent on the earnings and cash flows of its two electric utilities and nonregulated subsidiaries, and the ability of those subsidiaries to pay dividends or repay funds to Progress Energy.
Net cash provided by operating activities of $1.3 billion decreased $114 million for the nine months ended September 30, 2004, when compared to the corresponding period in the prior year. The decrease in cash flow from operating activities for the 2004 period is primarily due to the impact of hurricane costs at PEF during the third quarter.
Net cash used in investing activities of $889 million decreased $181 million for the nine months ended September 30, 2004, when compared to $1.1 billion in the corresponding period in the prior year. The decrease is primarily due to reduced nonregulated capital expenditures, primarily the purchase of North Texas Gas assets and a long-term power supply contract during the first nine months of 2003.
Between October 19, 2004 and November 1, 2004, Progress Energy and its subsidiaries PEC and PEF borrowed a net total of $535 million ($365 million by Progress Energy; $115 million by PEC; and $55 million by PEF) under certain long-term revolving credit facilities. In addition, PEF and PEC borrowed $170 million and $90 million, respectively, under their short-term credit facilities. Each of these credit facilities contains various cross default and other acceleration provisions. The borrowed funds will be used to pay off maturing commercial paper and for other cash needs. This action was taken due to the uncertain impact on Progress Energy’s, PEC’s, and PEF’s ability to access the commercial paper markets resulting from recent ratings actions taken by Standard and Poor’s (“S&P”) credit rating agency and Moody’s Investor Services (“Moody’s”).
On October 19, 2004, S&P changed Progress Energy’s outlook from stable to negative. S&P cited the uncertainties regarding the timing of the recovery of hurricane costs, the Company’s debt reduction plans, and the IRS audit of the Company’s Earthco synthetic fuels facilities as the reasons for the change in outlook. On October 25, 2004, S&P reduced the short-term debt rating of Progress Energy, PEC and PEF to A-3 from A-2, as a result of their change in outlook discussed above.
On October 20, 2004, Moody’s changed its outlook for Progress Energy from stable to negative and placed the ratings of PEF under review for possible downgrade. PEC’s ratings were affirmed by Moody’s.
Moody’s cited the following reasons for its change in the outlook for Progress Energy: financial ratios that are weak for its current rating category; rising O&M, pension, benefit, and insurance costs; and delays in executing its deleveraging plan. With respect to PEF, Moody’s cited declining cash flow coverages and rising leverage over the last several years; expected funding needs for a large capital expenditure program; risks with regard to its upcoming 2005 rate case and the timing of hurricane cost recovery as reasons for putting its ratings under review.
The changes by S&P and Moody’s do not trigger any debt or guarantee collateral requirements, nor do they have any material impact on the overall liquidity of Progress Energy or any of its affiliates. To date, Progress Energy’s, PEC’s, and PEF’s access to the commercial paper markets has not been materially impacted by the rating agencies’ actions. However, the changes are expected to increase the interest rate incurred on its short-term borrowings by 0.25% to 0.875%.
Due to the lower short-term debt rating issued by S&P, Progress Energy, PEC and PEF may continue to borrow under their revolving credit facilities instead of issuing commercial paper due to the difference in investor demand for lower-rated commercial paper. While the cost of borrowing under its revolving credit facilities is higher than commercial paper, it provides the same amount of liquidity.
Progress Energy’s, PEC’s, and PEF’s long-term credit facilities were arranged through a syndication of financial institutions and support their commercial paper programs. Progress Energy took advantage of favorable market conditions and entered into a new $1.1 billion five year line of credit, effective August 5, 2004, and expiring August 5, 2009. This facility replaces Progress Energy’s $250 million 364 day line of credit and its three year $450 million line of credit, which were both scheduled to expire in November 2004.
On July 28, 2004, PEC extended its $165 million 364-day line of credit, which was scheduled to expire on July 29, 2004. The line of credit will expire on July 27, 2005.
On July 1, 2004, PEF paid at maturity $40 million 6.69% Medium-Term Notes Series B with commercial paper proceeds and cash from operations.
On April 30, 2004, PEC redeemed $35 million of Darlington County 6.6% Series Pollution Control Bonds at 102.5% of par, $2 million of New Hanover County 6.3% Series Pollution Control Bonds at 101.5% of par, and $2 million of Chatham County 6.3% Series Pollution Control Bonds at 101.5% of par with cash from operations.
On March 30, 2004, PEF extended its $200 million 364-day line of credit. The line of credit will expire on March 29, 2005.
On March 1, 2004, Progress Energy used available cash and proceeds from the issuance of commercial paper to pay at maturity $500 million 6.55% senior unsecured notes. Cash and commercial paper capacity for this retirement was created primarily from proceeds of the sale of assets and long-term debt financings in 2003.
On February 9, 2004, Progress Capital Holdings, Inc. paid at maturity $25 million 6.48% medium term notes with available cash from operations.
On January 15, 2004, PEC paid at maturity $150 million 5.875% First Mortgage Bonds with commercial paper proceeds. On April 15, 2004, PEC also paid at maturity $150 million 7.875% First Mortgage Bonds with commercial paper proceeds and cash from operations.
For the nine months ended September 30, 2004, the Company issued approximately 1.3 million shares of its common stock for approximately $58 million in proceeds from its Investor Plus Stock Purchase Plan and its employee benefit plans. For the quarter ended September 30, 2004, there were no material stock issuances. For the nine months ended September 30, 2004 and 2003, the dividends paid on common stock were approximately $423 million and $403 million, respectively.
The Company’s filings with the Securities and Exchange Commission provide additional discussion of the risks associated with a credit ratings downgrade. See the “Risk Factors” section the Company’s Form 10-K for the year ended December 31, 2003. Also, see the Form 8-K filed November 3, 2004 for a discussion of the Company’s borrowings under its revolving credit facilities.
The amount and timing of future sales of company securities will depend on market conditions, operating cash flow, asset sales and the specific needs of the Company. The Company may from time to time sell securities beyond the amount needed to meet capital requirements in order to allow for the early redemption of long-term debt, the redemption of preferred stock, the reduction of short-term debt or for other general corporate purposes.
CONTRACTUAL OBLIGATION AND OFF-BALANCE SHEET ARRANGEMENTS
As of September 30, 2004, Progress Energy’s contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2003 Annual Report on Form 10-K.
As of September 30, 2004, the current portion of long-term debt is $348 million. Progress Energy expects to have sufficient resources to meet its future obligations either through internally generated funds, its short-term borrowing facilities or through the issuance of long-term debt.
Guarantees
As a part of normal business, Progress Energy and certain wholly-owned subsidiaries enter into various agreements providing future financial or performance assurances to third parties which are outside the scope of Financial Accounting Standards Board (FASB) Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to Progress Energy and subsidiaries on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’intended commercial purposes. The Company’s guarantees include performance obligations under power supply agreements, tolling agreements, transmission agreements, gas agreements, fuel procurement agreements and trading operations. The Company’s guarantees also include standby letters of credit, surety bonds and guarantees in support of nuclear decommissioning. At September 30, 2004, the Company had issued $1.3 billion of guarantees for future financial or performance assurance. Management does not believe conditions are likely for significant performance under the guarantees of performance issued by or on behalf of affiliates.
The majority of contracts supported by the guarantees contain provisions that trigger guarantee obligations based on downgrade events to below investment grade (below BBB- or Baa3), ratings triggers, monthly netting of exposure and/or payments and offset provisions in the event of a default. The recent outlook changes from S&P and Moody’s do not trigger any guarantee obligations. As of September 30, 2004, if the guarantee obligations were triggered, the maximum amount of liquidity requirements to support ongoing operations within a 90-day period, associated with guarantees for the company’s nonregulated portfolio and power supply agreements were $457 million.
As of September 30, 2004, Progress Energy had guarantees issued on behalf of third parties of approximately $10 million. See Note 15A of the “Notes to Consolidated Interim Financial Statements” in “Item 1, Financial Statements,” for a discussion of guarantees in accordance with FIN 45.
OTHER MATTERS
PEF Regulatory Matters
Rate Case Settlement
In March 2002, the parties in PEF’s rate case entered into a Stipulation and Settlement Agreement (the Agreement) related to retail rate matters. The Agreement was approved by the FPSC and is generally effective from May 1, 2002 through December 31, 2005; provided, however, that if PEF’s base rate earnings fall below a 10% return on equity, PEF may petition the FPSC to amend its base rates.
Hines Unit 4 Determination
PEF has determined that additional generating capacity will be required in late 2007 and has requested approval by the FPSC to build an additional unit at PEF’s Hines Complex. On October 28, 2004, the Prehearing order in the Hines 4 Determination of Need proceeding was issued. The order reflects a stipulation between the FPSC Staff and the Company resolving all issues and agreement that the FPSC should grant an affirmative Determination of Need for the construction of a Hines Unit 4. The stipulation finds that Hines Unit 4 is needed to maintain electric system reliability and integrity and to continue to provide adequate electricity to its ratepayers at a reasonable cost. Hines Unit 4 will be a combined cycle unit with a generating capacity of 461 megawatts (summer rating). The estimated total in-service cost of Hines Unit 4 is $286 million and the unit is planned for commercial operation in December 2007. If the actual cost is less than the estimate, customers will receive the benefit of such cost under runs. Any costs that exceed this estimate will be not recoverable absent extraordinary circumstances as found by the FPSC in subsequent proceedings. The FPSC approved the final order on November 3, 2004.
Synthetic Fuels Tax Credits
Progress Energy’s synthetic fuel operations are subject to numerous risks that may impact the Company, its operations, and the value of its securities. Many of these risks are discussed in the Company’s 2003 10-K, particularly the Risk Factors section. You should carefully read about these risks.
Progress Energy, through its subsidiaries, produces a coal-based solid synthetic fuel. The production and sale of the synthetic fuel from these facilities qualifies for tax credits under Section 29 of the Code (Section 29) if certain requirements are satisfied, including a requirement that the synthetic fuel differs significantly in chemical composition from the coal used to produce such synthetic fuel and that the fuel was produced from a facility that was placed in service before July 1, 1998. The amount of Section 29 credits that the Company is allowed to claim in any calendar year is limited by the amount of the Company's regular federal income tax liabiilty. Synthetic fuel tax credit amounts allowed but not utilized are carried forward indefinitely as deferred alternative minimum tax credits. All of Progress Energy’s synthetic fuel facilities have received private letter rulings (PLRs) from the Internal Revenue Service (IRS) with respect to their synthetic fuel operations. These tax credits are subject to review by the IRS, and if Progress Energy fails to prevail through the administrative or legal process, there could be a significant tax liability owed for previously taken Section 29 credits, with a significant impact on earnings and cash flows. Additionally, the ability to use tax credits currently being carried forward could be denied. Total Section 29 credits generated to date (including those generated by FPC prior to its acquisition by the Company) are approximately $1.4 billion, of which $669 million has been used and $700 million are being carried forward as deferred alternative minimum tax credits. Also $79 million has not been recognized due to the decrease in tax liability from the 2004 hurricane damage. The current Section 29 tax credit program expires at the end of 2007.
Impact of Hurricanes
For the nine-month period ended September 30, 2004, the Company’s synthetic fuel facilities have sold 7.7 million tons of synthetic fuel which generated an estimated $204 million of Section 29 tax credits. Due to the anticipated decrease in the Company’s tax liability as a result of the 2004 hurricanes, the Company estimates that it will be able to use in 2004 or carry forward to future years only $125 million of these Section 29 tax credits. As a result, the Company has recorded a charge of $79 million due to Section 29 tax credits. The Company is currently evaluating its options for mitigating some or all of this loss of tax credits.
Pre-Filing Agreement Program
In September 2002, all of the Company’s majority-owned synthetic fuel entities were accepted into the IRS’s Pre-filing Agreement (PFA) program. The PFA program allows taxpayers to voluntarily accelerate the IRS exam process in order to seek resolution of specific issues. Either the Company or the IRS can withdraw from the program, and issues not resolved through the program may proceed to the next level of the IRS exam process.
In February 2004, subsidiaries of the Company finalized execution of the Colona Closing Agreement with the IRS concerning their Colona synthetic fuel facilities. The Colona Closing Agreement provided that the Colona facilities were placed in service before July 1, 1998, which is one of the qualification requirements for tax credits under Section 29. The Colona Closing Agreement further provides that the fuel produced by the Colona facilities in 2001 is a “qualified fuel” for purposes of the Section 29 tax credits. This action concluded the IRS PFA program with respect to Colona.
In July 2004, Progress Energy was notified that the Internal Revenue Service (IRS) field auditors anticipate taking an adverse position regarding the placed-in-service date of the Company’s four Earthco synthetic fuel facilities. Due to the auditors’ position, the IRS has decided to exercise its right to withdraw from the Pre-Filing Agreement (PFA) program with Progress Energy. With the IRS’s withdrawal from the PFA program, the review of Progress Energy’s Earthco facilities is back on the normal procedural audit path of the Company’s tax returns. Through September 30, 2004, the Company, on a consolidated basis, has used or carried forward $1 billion of tax credits generated by Earthco facilities. If these credits were disallowed, the Company’s one time exposure for cash tax payments would be $286 million (excluding interest), and earnings and equity would be reduced by $1 billion, excluding interest. Progress Energy’s $1.13 billion credit facility includes a covenant which limits the maximum debt-to-total capital ratio to 65%. This ratio includes other forms of indebtedness such as guarantees issued by PGN, letters of credit and capital leases. As of September 30, 2004, the Company’s debt-to-total impact was 60.6% based on the credit agreement definition for this ratio. The impact on this ratio of reversing $1 billion of tax credits and paying $286 million for taxes would be to increase the ratio to 64.4%.
On October 29, 2004, Progress Energy received the IRS field auditors’ report concluding that the Earthco facilities had not been placed in service before July 1, 1998, and that the tax credits generated by those facilities should be disallowed. The Company disagrees with the field audit team’s factual findings and believes that the Earthco facilities were placed in service before July 1, 1998. The Company also believes that the report applies an inappropriate legal standard concerning what constitutes “placed in service”. The Company intends to contest the field auditors’ findings and their proposed disallowance of the tax credits.
Because of the stark disagreement between the Company and the field auditors as to the proper legal standard to apply, the Company believes that it is appropriate to have this issue reviewed by the National Office of the IRS, just as the National Office reviewed the issues involving chemical change. The Company could go directly to the Appeals section of the IRS, but it believes that clarification on the critical legal disagreements would help to resolve this matter. At this point, however, the Company does not know if the field auditors will agree to present this matter to the National Office. The Company believes that the appeals process, including proceedings before the National Office, could take up to two years to complete, however, it cannot control the actual timing of resolution and cannot predict the outcome of this matter.
In management’s opinion, Progress Energy is complying with all the necessary requirements to be allowed such credits under Section 29, and, although it cannot provide certainty, it believes that it will prevail in these matters. Accordingly, while the Company has adjusted its synthetic fuel production for 2004 in response to the effects of the hurricane damage on its 2004 tax liability, it has no current plans to alter its synthetic fuel production schedule for future years as a result of the IRS field auditors’ report. However, should the Company fail to prevail in these matters, there could be material liability for previously taken Section 29 tax credits, with a material adverse impact on earnings and cash flows.
In July 2004, the FASB stated that it plans to issue an exposure draft of a proposed interpretation of SFAS No. 109, “Accounting for Income Taxes”, that would address the accounting for uncertain tax positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of being sustained in order to record such benefits in the financial statements. The exposure draft is expected to be issued in the fourth quarter of 2004. The Company cannot predict what actions the FASB will take or how any such actions might ultimately affect the Company’s financial position or results of operations, but such changes could have a material impact on the Company’s evaluation and recognition of Section 29 tax credits.
Permanent Subcommittee
In October 2003, the United States Senate Permanent Subcommittee on Investigations began a general investigation concerning synthetic fuel tax credits claimed under Section 29. The investigation is examining the utilization of the credits, the nature of the technologies and fuels created, the use of the synthetic fuel and other aspects of Section 29 and is not specific to the Company’s synthetic fuel operations. Progress Energy is providing information in connection with this investigation. The Company cannot predict the outcome of this matter.
Sale of Partnership Interest
In June 2004, the Company through its subsidiary, Progress Fuels sold, in two transactions, a combined 49.8 percent partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel facilities. Substantially all proceeds from the sales will be received over time, which is typical of such sales in the industry. Gain from the sales will be recognized on a cost recovery basis. The Company’s book value of the interests sold totaled approximately $5 million. Based on projected production and tax credit levels, the Company anticipates receiving total gross proceeds of $10 million in 2004, approximately $30 million per year from 2005 through 2007 and approximately $9 million through the second quarter of 2008. In the event that the synthetic fuel tax credits at the Colona facility are reduced, including an increase in the price of oil which could limit or eliminate synthetic fuel tax credits, the amount of proceeds realized from the sale could be significantly impacted. Under the agreements, the buyers had a right to unwind the transactions if an IRS reconfirmation private letter ruling (PLR) was not received by October 15, 2004. The reconfirmation PLR was received in September 2004. An immaterial gain was recorded for the three months ended September 30, 2004.
Impact of Crude Oil Prices
Although the Internal Revenue Code Section 29 tax credit program is expected to continue through 2007, recent unprecedented and unanticipated increases in the price of oil could limit the amount of those credits or eliminate them altogether for one or more of the years following 2004. This possibility is due to a provision of Section 29 that provides that if the average wellhead price per barrel for unregulated domestic crude oil for the year (the “Annual Average Price”) exceeds a certain threshold value (the “Threshold Price”), the amount of Section 29 tax credits are reduced for that year. Also, if the Annual Average Price increases high enough (the “Phase Out Price”), the Section 29 tax credits are eliminated for that year. For 2003, the Threshold Price was $50.14 per barrel and the Phase Out Price was $62.94 per barrel. The Threshold Price and the Phase Out Price are adjusted annually for inflation.
If the Annual Average Price falls between the Threshold Price and the Phase Out Price for a year, the amount by which Section 29 tax credits are reduced will depend on where the Average Annual Price falls in that continuum. For example, for 2003, if the Annual Average Price had been $56.54 per barrel, there would have been a 50% reduction in the amount of Section 29 tax credits for that year.
The Secretary of the Treasury calculates the Annual Average Price based on the Domestic Crude Oil First Purchases Prices published by the Energy Information Agency (EIA). Because the EIA publishes its information on a three month lag, the Secretary of the Treasury finalizes its calculations three months after the year in question ends. Thus, the Annual Average Price for calendar year 2003 was published in April 2004.
Although the official notice for 2004 is not expected to be published until April of 2005, the Company does not believe that the Annual Average Price for 2004 will reach the Threshold Price for 2004. Even with oil prices at historic highs, oil prices would have to experience a significant and sustained increase for the remainder of the year for the Annual Average Price to approach the anticipated Threshold Price. Consequently, the Company does not expect the amount of its 2004 Section 29 tax credits to be adversely affected by oil prices.
The Company cannot predict with any certainty the Annual Average Price for 2005 or beyond. Therefore, it cannot predict whether the price of oil will have a material effect on its synthetic fuel business after 2004. However, if during 2005 through 2007, oil prices remain at historically high levels or increase, the Company’s synthetic fuel business may be adversely affected for those years and, depending on the magnitude of such increases in oil prices, the adverse affect for those years could be material and could have an impact on the Company’s synthetic fuel production plans.
Nuclear Matters
The United States Nuclear Regulatory Commission (NRC) on April 19, 2004, announced that it has renewed the operating license for PEC’s Robinson Nuclear Plant (Robinson) for an additional 20 years through July 2030. The original operating license of 40 years was set to expire in 2010. NRC operating licenses held by PEC currently expire in December 2014 and September 2016 for Brunswick Units 2 and 1, respectively. An application to extend these licenses 20 years was submitted in October 2004. The NRC operating license held by PEC for the Shearon Harris Nuclear Plant (Harris Plant) currently expires in October 2026. An application to extend this license 20 years is expected to be submitted in the fourth quarter of 2006.
The NRC operating license held by PEF for Crystal River Unit No. 3 (CR3) currently expires in December 2016. An application to extend this license 20 years is expected to be submitted in the first quarter 2009.
On February 27, 2004, PEC requested to have its license for the Independent Spent Fuel Storage Installation at the Robinson Plant extended 20 years with an exemption request for an additional 20-year extension. Its current license is due to expire in August 2006. PEC expects to receive this extension.
During the first quarter of 2004, PEC met the requirements of both the NCUC and the SCPSC for the implementation of a depreciation study which allowed the utility to reduce the rates used to calculate depreciation expense. In October 2004, PEC filed a revised depreciation study with the NCUC and SCPSC supporting a reduction in annual depreciation expense of approximately $47 million. The reduction is due solely to extended lives at each of PEC’s nuclear units. The new depreciation rates are proposed to be effective January 1, 2004.
In February 2004, the NRC issued a revised Order for inspection requirements for reactor pressure vessel heads at PWRs. The Company has reviewed the required inspection frequencies and has incorporated them into long range plans. The Harris Plant will complete the required non-visual non-destructive examination (NDE) inspection prior to February 2008. Both CR3 and Robinson will be required to inspect their new heads within 7 years or four refueling outages after replacement. CR3 plans to inspect its new head prior to the end of 2009, and Robinson will need to inspect its new head prior to 2012.
The NRC has issued various orders since September 2001 with regard to security at nuclear plants. These orders include additional restrictions on access, increased security measures at nuclear facilities and closer coordination with the Company’s partners in intelligence, military, law enforcement and emergency response at the federal, state and local levels. The Company is completing the requirements as outlined in the orders by the committed dates. As the NRC, other governmental entities and the industry continue to consider security issues, it is possible that more extensive security plans could be required.
Franchise Litigation
Three cities, with a total of approximately 18,000 customers, have litigation pending against PEF in various circuit courts in Florida. As previously reported, three other cities, with a total of approximately 30,000 customers, have subsequently settled their lawsuits with PEF and signed new, 30-year franchise agreements. The lawsuits principally seek 1) a declaratory judgment that the cities have the right to purchase PEF’s electric distribution system located within the municipal boundaries of the cities, 2) a declaratory judgment that the value of the distribution system must be determined through arbitration, and 3) injunctive relief requiring PEF to continue to collect from PEF’s customers and remit to the cities, franchise fees during the pending litigation, and as long as PEF continues to occupy the cities’ rights-of-way to provide electric service, notwithstanding the expiration of the franchise ordinances under which PEF had agreed to collect such fees. The circuit courts in those cases have entered orders requiring arbitration to establish the purchase price of PEF’s electric distribution system within five cities. Two appellate courts have upheld these circuit court decisions and authorized the cities to determine the value of PEF’s electric distribution system within the cities through arbitration.
Arbitration in one of the cases (with the 13,000-customer City of Winter Park) was completed in February 2003. That arbitration panel issued an award in May 2003 setting the value of PEF’s distribution system within the City of Winter Park at approximately $32 million, not including separation and reintegration costs and construction work in progress, which could add several million dollars to the award. The panel also awarded PEF approximately $11 million in stranded costs, which according to the award decreases over time. In September 2003, Winter Park voters passed a referendum that would authorize the City to issue bonds of up to approximately $50 million to acquire PEF’s electric distribution system. While the City has not yet definitively decided whether it will acquire the system, on April 26, 2004, the City Commission voted to enter into a hedge agreement to lock into interest rates for the acquisition of the system and to proceed with the acquisition. The City sought and received wholesale power supply bids and on June 23, 2004 executed a wholesale power supply contract with PEF. On May 12, 2004, the City solicited bids to operate and maintain the distribution system. The City received bids on July 1, 2004, and expects to make its selection this year. The City has indicated that its goal is to begin electric operations in June 2005. At this time, whether and when there will be further proceedings regarding the City of Winter Park cannot be determined.
Arbitration with the 2,500-customer Town of Belleair was completed in June 2003. In September 2003, the arbitration panel issued an award in that case setting the value of the electric distribution system within the Town at approximately $6 million. The panel further required the Town to pay to PEF its requested $1 million in separation and reintegration costs and approximately $2 million in stranded costs. The Town has not yet decided whether it will attempt to acquire the system; however, it has indicated its intent to seek bids for wholesale power supply and to operate and maintain the distribution system. The Town has also indicated that it may place the issue of whether to municipalize on a referendum ballot in March 2005. At this time, whether and when there will be further proceedings regarding the Town of Belleair cannot be determined.
Arbitration in the remaining city’s litigation (the 1,500-customer City of Edgewood) has not yet been scheduled.
A fourth city (the 7,000-customer City of Maitland) is contemplating municipalization and has indicated its intent to proceed with arbitration to determine the value of PEF’s electric distribution system within the City. Maitland’s franchise expires in August 2005. At this time, whether and when there will be further proceedings regarding the City of Maitland cannot be determined.
As part of the above litigation, two appellate courts have also reached opposite conclusions regarding whether PEF must continue to collect from its customers and remit to the cities “franchise fees” under the expired franchise ordinances. PEF has filed an appeal with the Florida Supreme Court to resolve the conflict between the two appellate courts. The Florida Supreme Court held oral argument in one of the appeals in August 2003. Subsequently, the Court requested briefing from the parties in the other appeal, which was completed in November 2003. On October 28, 2004, the court issued a decision holding that PEF must collect from its customers and remit to the cities franchise fees during the interim period when the City exercises its purchase option or executes a new franchise. The Court’s decision should not have a material impact on the Company.
Progress Energy Carolinas, Inc.
The information required by this item is incorporated herein by reference to the following portions of Progress Energy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations, insofar as they relate solely to PEC: RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES and OTHER MATTERS.
RESULTS OF OPERATIONS
The results of operations for the PEC Electric segment are identical between PEC and Progress Energy. The results of operations for PEC’s non-utility subsidiaries for the three and nine months ended September 30, 2004 and 2003 are not material to PEC’s consolidated financial statements.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities decreased $72 million for the nine months ended September 30, 2004, when compared to the corresponding period in the prior year. The decrease was caused primarily by a $57 million underrecovery of fuel costs.
Net cash used in investing activities of $442 million increased $48 million for the nine months ended September 30, 2004, when compared to $394 million in the corresponding period in the prior year. The increase was due primarily to higher capital spending associated with clean air compliance projects and increased spending for nuclear fuel.
Between October 19, 2004 and November 1, 2004, PEC borrowed a net total of $115 million under certain long-term revolving credit facilities. In addition, PEC borrowed $90 million under its short-term credit facilities. The credit facilities contain various cross default and other acceleration provisions. PEC’s long-term credit facilities were arranged through a syndication of financial institutions and support its commercial paper programs.
The borrowed funds will be used to pay off maturing commercial paper and for other cash needs. This action was taken due to the uncertain impact on PEC’s ability to access the commercial paper markets resulting from recent ratings actions taken by Standard and Poor’s (“S&P”) credit rating agency and Moody’s Investor Services (“Moody’s”).
On October 19, 2004, S&P changed Progress Energy’s outlook from stable to negative. S&P cited the uncertainties regarding the timing of the recovery of hurricane costs, the Company’s debt reduction plans, and the IRS audit of the Company’s Earthco synthetic fuels facilities as the reasons for the change in outlook. On October 25, 2004, S&P reduced the short-term debt rating of PEC to A-3 from A-2, as a result of their change in outlook discussed above.
On October 20, 2004, Moody’s changed its outlook for Progress Energy from stable to negative. PEC’s ratings were affirmed by Moody’s.
The changes by S&P do not trigger any debt or guarantee collateral requirements, nor do they have any material impact on the overall liquidity of PEC. To date, PEC’s access to the commercial paper markets has not been materially impacted by the rating agencies’ actions. However, the changes are expected to increase the interest rate incurred on its short-term borrowings by 0.25% to 0.875%.
Due to the lower short-term debt rating issued by S&P, PEC may continue to borrow under its revolving credit facilities instead of issuing commercial paper due to the difference in investor demand for lower-rated commercial paper. While the cost of borrowing under its revolving credit facilities is higher than commercial paper, it provides the same amount of liquidity.
On July 28, 2004, PEC extended its $165 million 364-day line of credit, which was scheduled to expire on July 29, 2004. The line of credit will expire on July 27, 2005.
On April 30, 2004, PEC redeemed $35 million of Darlington County 6.6% Series Pollution Control Bonds at 102.5% of par, $2 million of New Hanover County 6.3% Series Pollution Control Bonds at 101.5% of par, and $2 million of Chatham County 6.3% Series Pollution Control Bonds at 101.5% of par with cash from operations.
On January 15, 2004, PEC paid at maturity $150 million 5.875% First Mortgage Bonds with commercial paper proceeds. On April 15, 2004, PEC also paid at maturity $150 million 7.875% First Mortgage Bonds with commercial paper proceeds and cash from operations.
PEC’s filings with the Securities and Exchange Commission provide additional discussion of the risks associated with a credit ratings downgrade. See the “Risk Factors” section the PEC’s Form 10-K for the year ended December 31, 2003. Also, see the Form 8-K filed November 3, 2004 for a discussion of PEC’s borrowings under its revolving credit facilities. PEC expects to have sufficient resources to meet its future obligations either through internally generated funds, its short term-term borrowing facilities or through the issuance of long-term debt.
Guarantees
As a part of normal business, PEC enters into various agreements providing future financial or performance assurances to third parties, which are outside the scope of Financial Accounting Standards Board (FASB) Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). Such agreements include guarantees, standby letters of credit and surety bonds. At September 30, 2004, management does not believe conditions are likely for significant performance under these guarantees. To the extent liabilities are incurred as a result of the activities covered by the guarantees, such liabilities are included in the accompanying Consolidated Balance Sheets. At September 30, 2004, PEC had no guarantees issued on behalf of unconsolidated subsidiaries or other third parties. See discussion in Note 11 to the Consolidated Interim Financial Statements.
Contractual Obligations and Off-Balance Sheet Arrangements
As of September 30, 2004, PEC’s contractual cash obligations and other commercial commitments have not changed materially from what was reported in the 2003 Annual Report on Form 10-K.
As of September 30, 2004, the current portion of long-term debt is $300 million. PEC expects to have sufficient resources to meet its future obligations either through internally generated funds, its short-term borrowing facilities or through the issuance of long-term debt.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Progress Energy, Inc.
Other than described below, the various risks that the Company is exposed to has not materially changed since December 31, 2003.
Market risk represents the potential loss arising from adverse changes in market rates and prices. Certain market risks are inherent in the Company’s financial instruments, which arise from transactions entered into in the normal course of business. The Company’s primary exposures are changes in interest rates with respect to its long-term debt and commercial paper, and fluctuations in the return on marketable securities with respect to its nuclear decommissioning trust funds. The Company manages its market risk in accordance with its established risk management policies, which may include entering into various derivative transactions.
Marketable Securities Price Risk
The Company’s exposure to return on marketable securities for the nuclear decommissioning trust funds has not changed materially since December 31, 2003.
CVO Market Value Risk
The Company’s exposure to market value risk with respect to the CVOs has not changed materially since December 31, 2003. The CVOs are recorded at fair value and unrealized gains and losses from changes in fair value are recognized in earnings. At September 30, 2004 and December 31, 2003, the fair value of these CVOs was $16 million and $23 million, respectively.
Interest Risk
Progress Energy uses a number of models and methods to determine interest rate risk exposure and fair value of derivative positions. For reporting purposes, fair values and exposures are determined as of the end of the reporting period using the Bloomberg Financial Markets system.
The exposure to changes in interest rates on the Company’s fixed rate and variable rate long-term debt at September 30, 2004 has changed from December 31, 2003. The total fixed rate long-term debt at September 30, 2004 was $8.8 billion, with an average interest rate of 6.56% and fair market value of $9.4 billion. The total variable rate long-term debt at September 30, 2004, was $1.1 billion, with an average interest rate of 1.8% and fair market value of $1.1 billion.
The Company maintains a portion of its outstanding debt with floating interest rates. As of September 30, 2004 approximately 20% of consolidated debt was in floating rate mode compared to 18% at December 31, 2003.
Progress Energy uses interest rate derivative instruments to adjust the fixed and variable rate debt components of its debt portfolio and to hedge interest rates with regard to future fixed rate debt issuances. In accordance with FAS 133 interest rate derivatives that qualify as hedges are broken into one of two categories, cash flow hedges or fair value hedges. Cash flow hedges are used to reduce exposure to changes in cash flow due to fluctuating interest rates. Fair value hedges are used to reduce exposure to changes in fair market value due to interest rate changes.
The notional amounts of interest rate derivatives are not exchanged and do not represent exposure to credit loss. In the event of default by a counter party, the risk in the transaction is the cost of replacing the agreements at current market rates. Progress Energy only enters into interest rate derivative agreements with banks with credit ratings of single A or better.
Fair Value Hedges:
As of September 30, 2004, Progress Energy had $500 million of fixed rate debt swapped to floating rate debt by executing receive fixed interest rate swap agreements. Under terms of these swap agreements, Progress Energy will receive a fixed rate and pay a floating rate based on 3-month LIBOR. In November 2004, Progress Energy terminated $350 million notional amount of swaps against the 6.05% notes due April 15, 2007.
| Fair Value Hedges (dollars in millions) Progress Energy, Inc. as of September 30, 2004 |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Risk hedged | Notional Amount |
Receive | Pay(b) | Value | Exposure(c) | ||||||
| 6.05% Notes due 4/15/2007 | $350 | 3 | .35% | 3-month LIBOR | $ 3 | $(2 | ) | ||||
| 5.85% Notes due 10/30/2008 | $100 | 4 | .10% | 3-month LIBOR | $ 3 | $(1 | ) | ||||
| 7.10% Notes due 3/1/2011 | $ 50 | 4 | .65% | 3-month LIBOR | $ 2 | $(1 | ) | ||||
| Total | $500 | 3 | .63%(a) | 3-month LIBOR | $ 8 | $(4 | ) | ||||
as of December 31, 2003 | |||||||||||
| Risk hedged | |||||||||||
| 6.75% Notes due 3/1/2006 | $300 | 2 | .75% | 3-month LIBOR | $ 2 | $(1 | ) | ||||
| 6.05% Notes due 4/15/2007 | $350 | 3 | .35% | 3-month LIBOR | $ 3 | $(3 | ) | ||||
| 5.85% Notes due 10/30/2008 | $200 | 2 | .93% | 3-month LIBOR | $(9 | ) | $(2 | ) | |||
| Total | $850 | 3 | .04%(a) | 3-month LIBOR | $(4 | ) | $(6 | ) | |||
(a)Weighted average rate
(b)3-month LIBOR rate was 2.02% at September 30, 2004 and 1.15% at December 31, 2003.
(c) Exposure indicates change in value due to 25 basis point unfavorable shift in interest rates.
Cash Flow Hedges:
As of September 30, 2004, Progress Energy Inc. did not have any outstanding cash flow hedges. As of December 31, 2003, Progress Energy had $400 million notional amount of payer swaptions where the Company has the right, but not the obligation, to enter a pay-fixed swap and receive 3-month LIBOR, to hedge LIBOR exposure on future commercial paper issues for the period from 2005 through 2008. These swaptions were terminated in the second quarter of 2004 resulting in an immaterial loss that will be amortized over the period from 2005 through 2008.
As of September 30, 2004, PEC had $136 million of pay-fixed forward starting swaps in place to hedge cash flow risk due to future financing transactions. Under terms of these swap agreements, Progress Energy will receive a fixed rate and pay a floating rate based on 3-month LIBOR.
As of September 30, 2004 Progress Ventures, Inc. (PVI) a wholly-owned subsidiary of Progress Energy, had $195 million notional amount of interest rate collars in place to hedge floating interest rate exposure associated with variable-rate long-term debt. PVI is required to hedge 50% of the amount outstanding under its bank facility through March 2007.
| Cash Flow Hedges (dollars in millions) Progress Energy, Inc. as of September 30, 2004 |
None | ||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
as of December 31, 2003 |
|||||||||||
| Risk hedged | Notional Amount | Pay | Receive(b) | Fair Value | Exposure(c) | ||||||
| Commercial Paper interest risk | $400 | 4 | .75% | 3-month LIBOR | $5 | $(2 | ) | ||||
| from 2005 through 2008 | |||||||||||
| Progress Energy Carolinas as of September 30, 2004 |
|||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|
| Risk hedged | Notional Amount | Receive | (b) | Pay | Fair | Exposure | (c) | ||||
| Anticipated 10-Year Debt Issue | $110 | 4 | .85% | 3-month LIBOR | $(1 | ) | $(2 | ) | |||
| Rail car lease payment | $ 26 | 5 | .17% | 3-month LIBOR | $(1 | ) | $(1 | ) | |||
| Total | $136 | 4 | .91%(a) | 3-month LIBOR | $(2 | ) | $(3 | ) | |||
as of December 31, 2003 | None | ||||||||||
Progress Energy Ventures | |||||||||||
| as of September 30, 2004 | |||||||||||
| Risk hedged | Notional Amount | Receive | (b) | Pay | Fair | Exposure | (c) | ||||
| Libor exposure 6/22/03 to 12/21/04 | $195 | 6 | .0% | 4.13 | $(1 | ) | $ — | ||||
| Libor exposure 12/22/04 to 3/16/07 | $130 | 6 | .5% | 5.13 | $(6 | ) | $(1 | ) | |||
| Total | N/A | (d) | $(7 | ) | $(1 | ) | |||||
as of December 31, 2003 | |||||||||||
| Risk hedged | |||||||||||
| Libor exposure 6/22/03 to 12/21/04 | $195 | 6 | .0% | 4.13 | $(5 | ) | $ — | ||||
| Libor exposure 12/22/04 to 3/16/07 | $130 | 6 | .5% | 5.13 | $(6 | ) | $(1 | ) | |||
| Total | N/A | (d) | $(11 | ) | $(1 | ) | |||||
(b)3-month LIBOR rate was 2.02% at September 30, 2004 and 1.15% at December 31, 2003.
(c)Exposure indicates change in value due to 25 basis point unfavorable shift in interest rates.
(d)Notional amounts are not additive because instruments do not cover the same time period.
Commodity Price Risk
Nonhedging Derivatives:
Nonhedging derivatives, primarily electricity and natural gas contracts, are entered into for economic hedging purposes. While management believes the economic hedges mitigate exposures to fluctuations in commodity prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent with trading positions.
Since December 31, 2003, PEF has entered into derivative instruments related to its exposure to price fluctuations on fuel oil purchases. At September 30, 2004, the fair value of these instruments was an $11 million asset position. These instruments receive regulatory accounting treatment. Gains are recorded in regulatory liabilities and losses are recorded in regulatory assets.
Cash Flow Hedges:
Progress Fuels Corporation periodically enters into derivative instruments to hedge its exposure to price fluctuations on natural gas sales. As of September 30, 2004, Progress Fuels Corporation is hedging exposures to the price variability of portions of its natural gas production through December 2005.
The fair values of cash flow hedges at September 30, 2004 and December 31, 2003 were as follows:
| Progress Fuels | |||||
|---|---|---|---|---|---|
| (millions of dollars) | 2004 | 2003 | |||
| Fair value of assets | $ — | $ — | |||
| Fair value of liabilities | (40 | ) | (12 | ) | |
| Fair value, net | $(40 | ) | $(12 | ) | |
The ineffective portion of commodity cash flow hedges for the three and nine month periods ending September 30, 2004 was not material to the Company's results of operations. At September 30, 2004, there were $25 million of after-tax deferred losses in accumulated other comprehensive income (OCI), of which $21 million are expected to be reclassified to earnings during the next 12 months as the hedged transactions occur. Due to the volatility of the commodities markets, the value in OCI is subject to change prior to its reclassification into earnings.
Progress Energy Carolinas, Inc.
PEC has certain market risks inherent in its financial instruments, which arise from transactions entered into in the normal course of business. PEC's primary exposures are changes in interest rates with respect to long-term debt and commercial paper, and fluctuations in the return on marketable securities with respect to its nuclear decommissioning trust funds. PEC's exposure to these risks has not materially changed since December 31, 2003.
Item 4: Controls and Procedures
Progress Energy, Inc.
Pursuant to the Securities Exchange Act of 1934, Progress Energy carried out an evaluation, with the participation of Progress Energy's management, including Progress Energy's President and Chief Executive Officer, and Chief Financial Officer, of the effectiveness of Progress Energy's disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, Progress Energy's President and Chief Executive Officer, and Chief Financial Officer concluded that Progress Energy's disclosure controls and procedures are effective in timely alerting them to material information relating to Progress Energy (including its consolidated subsidiaries) required to be included in Progress Energy's periodic SEC filings.
There has been no change identified in Progress Energy's internal control over financial reporting during the quarter ended September 30, 2004 that has materially affected, or is reasonably likely to materially affect, Progress Energy's internal control over financial reporting.
Progress Energy Carolinas, Inc.
Pursuant to the Securities Exchange Act of 1934, PEC carried out an evaluation, with the participation of PEC's management, including PEC's President and Chief Executive Officer, and Chief Financial Officer, of the effectiveness of PEC's disclosure controls and procedures (as defined under the Securities Exchange Act of 1934) as of the end of the period covered by this report. Based upon that evaluation, PEC's President and Chief Executive Officer, and Chief Financial Officer concluded that PEC's disclosure controls and procedures are effective in timely alerting them to material information relating to PEC (including its consolidated subsidiaries) required to be included in PEC's periodic SEC filings.
There has been no change identified in PEC's internal control over financial reporting during the quarter ended September 30, 2004 that has materially affected, or is reasonably likely to materially affect, PEC's internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Legal aspects of certain matters are set forth in Part I, Item 1. See Note 15 to the Progress Energy, Inc. Consolidated Interim Financial Statements and Note 11 to the PEC's Consolidated Interim Financial Statements.
| 1. | U.S. Global, LLC v. Progress Energy, Inc. et al, Case No. 03004028-03 and Progress Synfuel Holdings, Inc. et al, v. U.S. Global, LLC, Case No. 03004028-03 |
A number of Progress Energy, Inc. subsidiaries and affiliates are parties to two lawsuits arising out of an Asset Purchase Agreement dated as of October 19, 1999, by and among U.S. Global LLC (Global), Earthco, certain affiliates of Earthco (collectively the Earthco Sellers), EFC Synfuel LLC (which is owned indirectly be Progress Energy, Inc.) and certain of its affiliates, including Solid Energy LLC, Solid Fuel LLC, Ceredo Synfuel LLC, Gulf Coast Synfuel LLC (currently named Sandy River Synfuel LLC) (collectively the Progress Affiliates), as amended by an amendment to Purchase Agreement as of August 23, 2000 (the Asset Purchase Agreement). Global has asserted that pursuant to the Asset Purchase Agreement it is entitled to (1) an interest in two synthetic fuel facilities currently owned by the Progress Affiliates, and (2) an option to purchase additional interests in the two synthetic fuel facilities.
The first suit, U.S. Global, LLC v. Progress Energy, Inc. et al, was filed in the Circuit Court for Broward County, Florida in March 2003 (the Florida Global Case). The Florida Global Case asserts claims for breach of the Asset Purchase Agreement and other contract and tort claims related to the Progress Affiliates' alleged interference with Global's rights under the Asset Purchase Agreement. The Florida Global Case requests an unspecified amount of compensatory damages, as well as declaratory relief. Following briefing and argument on a number of dispositive motions on successive versions of Global's complaint, on August 16, 2004, the Progress Affiliates answered the Fourth Amended Complaint by generally denying all of Global's substantive allegations and asserting numerous affirmative defenses. The parties are currently engaged in discovery in the Florida Global Case.
The second suit, Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC, was filed by the Progress Affiliates in the Superior Court for Wake County, North Carolina seeking declaratory relief consistent with the Company's interpretation of the asset Purchase Agreement (the North Carolina Global Case). Global was served with the North Carolina Global Case on April 17, 2003.
On May 15, 2003, Global moved to dismiss the North Carolina Global Case for lack of personal jurisdiction over Global. In the alternative, Global requested that the court decline to exercise its discretion to hear the Progress Affiliates' declaratory judgment action. On August 7, 2003, the Wake County Superior court denied Global's motion to dismiss and entered an order staying the North Carolina Global Case, pending the outcome of the Florida Global Case. The Progress Affiliates appealed the Superior court's order staying the case. By order dated September 7, 2004, the North Carolina Court of Appeals dismissed the Progress Affiliates' appeal.
The Company cannot predict the outcome of these matters, but will vigorously defend against the allegations.
| 2. | In re Progress Energy, Inc. Securities Litigation, Master File No. 04-CV-636 (JES) |
On February 3, 2004, Progress Energy, Inc. was served with a class action complaint alleging violations of federal security laws in connection with the Company's issuance of Contingent Value Obligations (CVOs). The action was filed by Gerber Asset Management LLC in the United States District Court for the Southern District of New York and names Progress Energy, Inc.'s former Chairman William Cavanaugh III and Progress Energy, Inc. as defendants. The Complaint alleges that Progress Energy failed to timely disclose the impact of the Alternative Minimum Tax required under Sections 55-59 of the Internal Revenue Code (Code) on the value of certain CVOs issued in connection with the Florida Progress Corporation merger. The suit seeks unspecified compensatory damages, as well as attorneys' fees and litigation costs.
On March 31, 2004, a second class action complaint was filed by Stanley Fried, Raymond X. Talamantes and Jacquelin Talamantes against William Cavanaugh III and Progress Energy, Inc. in the United States District Court for the Southern District of New York alleging violations of federal securities laws arising out of the Company's issuance of CVOs nearly identical to those alleged in the February 3, 2004 Gerber Asset Management complaint. On April 29, 2004, the Honorable John E. Sprizzo ordered among other things that (1) the two class action cases be consolidated, (2) Peak6 Capital Management LLC shall serve as the lead plaintiff in the consolidated action, and (3) the lead plaintiff shall file a consolidated amended complaint on or before June 15, 2004.
The lead plaintiff filed a consolidated amended complaint on June 15, 2004. In addition to the allegations asserted in the Gerber Asset Management and Fried complaints, the consolidated amended complaint alleges that the Company failed to disclose that excess fuel credits could not be carried over from one tax year into later years. On July 30, 2004, the Company filed a motion to dismiss the complaint; plaintiff submitted its opposition brief on September 14, 2004. The Court will hear oral argument on the Company's motion to dismiss on November 15, 2004.
The Company cannot predict the outcome of this matter, but will vigorously defend against the allegations.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities for Third Quarter of 2004
| (a) | (b) | (c) | (d) | ||||||
|---|---|---|---|---|---|---|---|---|---|
| Period | Total Number of Shares (or Units) Purchased(1)(2) |
Average Price Paid Per Share (or Unit) |
Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs(1) |
Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs(1) | |||||
| July 1 - July 31 | 151,596 | $ 41 | .57 | N/A | N/A | ||||
| August 1 - August 31 | 0 | N/A | N/A | N/A | |||||
| September 1 - September 30 | 0 | N/A | N/A | N/A | |||||
| Total: | 151,596 | $ 41 | .57 | N/A | N/A | ||||
| (1) | As of September 30, 2004, Progress Energy does not have any publicly announced plans or programs to purchase shares of its common stock. |
| (2) | 151,596 shares of our common stock were purchased in open-market transactions by the plan administrator satisfy share delivery requirements under the Progress Energy 401(k) Savings and Stock Ownership Plan. |
Item 6. Exhibits
| Exhibit Number |
Description | Progress Energy, Inc. |
Progress Energy Carolinas, Inc. |
|---|---|---|---|
| 31(a) | Certifications pursuant to Section 302 of the Sarbanes-Oxley Action of 2002 - Chairman, President and Chief Executive Officer |
X | X |
| 31(b) | Certifications pursuant to Section 302 of the Sarbanes-Oxley Action of 2002 - Executive Vice President and Chief Financial Officer |
X | X |
| 32(a) | Certifications pursuant to Section 906 of the Sarbanes-Oxley Action of 2002 - Chairman, President and Chief Executive Officer |
X | X |
| 32(b) | Certifications pursuant to Section 906 of the Sarbanes-Oxley Action of 2002 - Executive Vice President and Chief Financial Officer |
X | X |
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| PROGRESS ENERGY, INC. CAROLINA POWER & LIGHT COMPANY (Registrants) | |
|---|---|
| Date: November 9, 2004 | By: /s/ Geoffrey S. Chatas ______________________________ Geoffrey Chatas Executive Vice President and Chief Financial Officer |
| By: /s/Robert H. Bazemore, Jr. _________________________________ Robert H. Bazemore, Jr. Vice President and Controller Chief Accounting Officer |