UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
------ -------
Commission Exact name of registrants as specified in their charters, state of I.R.S. Employer
File Number incorporation, address of principal executive offices, and telephone number Identification Number
1-15929 Progress Energy, Inc. 56-2155481
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone: (919) 546-6111
State of Incorporation: North Carolina
1-3382 Carolina Power & Light Company 56-0165465
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
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 October 31, 2003, each
registrant had the following shares of common stock outstanding:
Registrant Description Shares
Progress Energy Common Stock (Without Par Value) 245,065,096
PEC Common Stock (Without Par Value) 159,608,055 (all of which
were held by Progress Energy, Inc.)
1
PROGRESS ENERGY, INC. AND PROGRESS ENERGY CAROLINAS, INC.
FORM 10-Q - For the Quarter Ended September 30, 2003
Glossary of Terms
Safe Harbor For Forward-Looking Statements
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Interim Financial Statements:
Progress Energy, Inc.
--------------------------------------------------------------
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Notes to Consolidated Interim Financial Statements
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
---------------------------------------------------------------
Consolidated Statements of Income
Consolidated Balance Sheets
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. Changes in Securities and Use of Proceeds
Item 6. Exhibits and Reports on Form 8-K
Signatures
2
GLOSSARY OF TERMS
The following abbreviations or acronyms used in the text of this combined Form
10-Q are defined below:
TERM DEFINITION
AFUDC Allowance for funds used during construction
the Agreement Stipulation and Settlement Agreement
APB No. 28 Accounting Principles Board Opinion No. 28, "Interim Financial Reporting"
ARO Asset retirement obligation
Bcf Billion cubic feet
CCO Competitive Commercial Operations
the Code Internal Revenue Code
Colona Colona Synfuel Limited Partnership, L.L.L.P.
the Company Progress Energy, Inc. and subsidiaries
CPI Consumer Price Index
CR3 Progress Energy Florida Inc.'s nuclear generating plant, Crystal River Unit No. 3
CVO Contingent value obligation
DIG Derivatives Implementation Group
DOE United States Department of Energy
Dt Dekatherm
DWM North Carolina Department of Environment and Natural Resources, Division of Waste
Management
EITF Emerging Issues Task Force
ENCNG Eastern North Carolina Natural Gas Company, formerly referred to as Eastern NC
EPA United States Environmental Protection Agency
FASB Financial Accounting Standards Board
FDEP Florida Department of Environment and Protection
Federal Circuit United States Circuit Court of Appeals
FERC Federal Energy Regulatory Commission
FIN No. 46 FASB Interpretation No. 46, "Consolidation of Variable Interest Entities - An
Interpretation of ARB No. 51"
Florida Progress or FPC Florida Progress Corporation
FPSC Florida Public Service Commission
Funding Corp. Florida Progress Funding Corporation
GAAP Accounting principles generally accepted in the United States of America
Genco Progress Genco Ventures, LLC
IRS Internal Revenue Service
Jackson Jackson Electric Membership Corp.
MACT Maximum Available Control Technology
Mesa Mesa Hydrocarbons, LLC
MGP Manufactured gas plant
MW Megawatt
NCNG North Carolina Natural Gas Corporation
NCUC North Carolina Utilities Commission
NOx SIP Call EPA rule which requires 23 jurisdictions including North and South
Carolina and Georgia to further reduce nitrogen oxide emissions
NRC United States Nuclear Regulatory Commission
NSP Northern States Power
PCH Progress Capital Holdings, Inc.
PEC Progress Energy Carolinas, Inc., formerly referred to as Carolina Power & Light Company
PEF Progress Energy Florida, Inc., formerly referred to as Florida Power Corporation
PFA IRS Prefiling Agreement
the Plan Revenue Sharing Incentive Plan
PLRs Private Letter Rulings
Preferred Securities FPC-obligated mandatorily redeemable preferred securities of FPC Capital I
Progress Energy Progress Energy, Inc.
Progress Rail Progress Rail Services Corporation
Progress Telecom Progress Telecommunications Corporation
3
Progress Ventures Business unit of Progress Energy primarily made up of nonregulated energy generation,
gas, coal and synthetic fuel operations and energy marketing
PUHCA Public Utility Holding Company Act of 1935, as amended
PVI Legal entity of Progress Ventures, Inc., formerly referred to as CPL Energy Ventures, Inc.
PWR Pressurized water reactor
RAFT Railcar Asset Financing Trust
Rail Rail Services
RTO Regional Transmission Organization
SCPSC Public Service Commission of South Carolina
SEC United States Securities and Exchange Commission
Section 29 Section 29 of the Internal Revenue Code
Section 42 Section 42 of the Internal Revenue Code
Service Company Progress Energy Service Company, LLC
SFAS No. 5 Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies"
SFAS No. 71 Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation"
SFAS No. 131 Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an
Enterprise and Related Information"
SFAS No. 133 Statement of Financial Accounting Standards No. 133, "Accounting for Derivative and
Hedging Activities"
SFAS No. 142 Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible
Assets"
SFAS No. 143 Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations"
SFAS No. 148 Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - An Amendment of FASB Statement No. 123"
SFAS No. 149 Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities"
SFAS No. 150 Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity"
SMD NOPR Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination
through Open Access Transmission and Standard Market Design
SRS Strategic Resource Solutions Corporation
the Trust FPC Capital I Trust
Westchester Westchester Gas Company
4
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-heading "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) 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; the impact of recent events in the
energy markets that have increased the level of public and regulatory scrutiny
in the energy industry and in the capital markets; 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; recurring seasonal fluctuations
in demand for electricity; fluctuations in the price of energy commodities and
purchased power; economic fluctuations and the corresponding impact on the
Company's 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 and PEC; the ability of the
Company and PEC to maintain their current credit ratings; the impact of
derivative contracts used in the normal course of business; the outcome of the
IRS's audit and inquiry into the availability and use of 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 fuels businesses; the continued
depressed state of the telecommunications industry and the Company's ability to
realize future returns from Progress Telecommunications Corporation and Caronet,
Inc.; the Company's ability to successfully integrate newly acquired assets,
properties or businesses into its operations as quickly or as profitably as
expected; 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; and
unanticipated changes in operating expenses and capital expenditures. Most of
these risks similarly impact the Company's subsidiaries including PEC.
These and other risk factors are detailed from time to time in the Progress
Energy and PEC 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, 2002, which
were filed with the SEC on March 21, 2003, and PEC's Form 8-K filed on September
8, 2003. 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.
5
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Progress Energy, Inc.
CONSOLIDATED INTERIM FINANCIAL STATEMENTS
September 30, 2003
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Nine Months Ended
(Unaudited) September 30, September 30,
- ----------------------------------------------------------------------------------------------------------------------
(In thousands except per share data) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------------
Operating Revenues
Utility $ 1,914,004 $ 1,908,817 $ 5,150,678 $ 5,007,321
Diversified business 526,762 403,562 1,418,800 1,103,707
- ----------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,440,766 2,312,379 6,569,478 6,111,028
- ----------------------------------------------------------------------------------------------------------------------
Operating Expenses
Utility
Fuel used in electric generation 488,607 448,960 1,293,561 1,185,769
Purchased power 254,627 269,108 667,194 675,066
Operation and maintenance 368,769 325,495 1,067,848 1,000,827
Depreciation and amortization 220,136 205,922 663,819 628,295
Taxes other than on income 107,222 104,989 304,499 294,217
Diversified business
Cost of sales 433,817 365,481 1,219,934 1,072,818
Depreciation and amortization 45,333 28,563 111,751 86,625
Impairment of long-lived assets - 304,986 - 304,986
Other 42,739 58,655 128,082 114,937
- ----------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,961,250 2,112,159 5,456,688 5,363,540
- ----------------------------------------------------------------------------------------------------------------------
Operating Income 479,516 200,220 1,112,790 747,488
- ----------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 2,166 3,293 8,464 11,673
Impairment of investments - (25,011) - (25,011)
Other, net (3,067) 10,806 (14,950) 14,249
- ----------------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) (901) (10,912) (6,486) 911
- ----------------------------------------------------------------------------------------------------------------------
Interest Charges
Net interest charges 146,006 142,242 461,774 482,571
Allowance for borrowed funds used during construction (1,932) (624) (7,041) (7,530)
- ----------------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 144,074 141,618 454,733 475,041
- ----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax 334,541 47,690 651,571 273,358
Income Tax Benefit (3,112) (109,383) (33,258) (129,710)
- ----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations 337,653 157,073 684,829 403,068
Discontinued Operations, Net of Tax (18,691) (5,139) (4,888) 2,013
- ----------------------------------------------------------------------------------------------------------------------
Net Income $ 318,962 $ 151,934 $ 679,941 $ 405,081
- ----------------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 239,025 216,079 236,183 214,700
- ----------------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
Income from Continuing Operations $ 1.42 $ 0.72 $ 2.90 $ 1.88
Discontinued Operations, Net of Tax ($ 0.08) ($ 0.01) ($ 0.02) $ 0.01
Net Income $ 1.34 $ 0.71 $ 2.88 $ 1.89
- ----------------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share
Income from Continuing Operations $ 1.42 $ 0.71 $ 2.89 $ 1.87
Discontinued Operations, Net of Tax ($ 0.08) ($ 0.01) ($ 0.02) $ 0.01
Net Income $ 1.34 $ 0.70 $ 2.87 $ 1.88
- ----------------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------------
Dividends Declared per Common Share $0.560 $0.545 $1.680 $1.635
- ----------------------------------------------------------------------------------------------------------------------
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
6
Progress Energy, Inc.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands except share data) September 30, December 31,
Assets 2003 2002
- ---------------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 21,198,711 $ 20,152,787
Accumulated depreciation (10,162,434) (10,480,880)
- ---------------------------------------------------------------------------------------------------------------
Utility plant in service, net 11,036,277 9,671,907
Held for future use 13,177 15,109
Construction work in progress 862,125 752,336
Nuclear fuel, net of amortization 219,574 216,882
- ---------------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 12,131,153 10,656,234
- ---------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 100,146 61,358
Accounts receivable 813,110 737,369
Unbilled accounts receivable 190,867 225,011
Inventory 816,425 875,485
Deferred fuel cost 327,213 183,518
Assets of discontinued operations - 490,429
Prepayments and other current assets 328,969 260,804
- ---------------------------------------------------------------------------------------------------------------
Total Current Assets 2,576,730 2,833,974
- ---------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 649,956 393,215
Nuclear decommissioning trust funds 883,837 796,844
Diversified business property, net 2,147,456 1,884,271
Miscellaneous other property and investments 446,026 463,776
Goodwill 3,719,327 3,719,327
Prepaid pension costs 52,575 60,169
Other assets and deferred debits 672,272 517,182
- ---------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 8,571,449 7,834,784
- ---------------------------------------------------------------------------------------------------------------
Total Assets $ 23,279,332 $ 21,324,992
- ---------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- ---------------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, 500,000,000 shares
authorized, 244,929,214 and 237,992,513 shares
issued and outstanding, respectively $ 5,223,644 $ 4,929,104
Unearned ESOP common stock (88,734) (101,560)
Accumulated other comprehensive loss (221,603) (237,762)
Retained earnings 2,366,769 2,087,227
- ---------------------------------------------------------------------------------------------------------------
Total Common Stock Equity 7,280,076 6,677,009
- ---------------------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries-Not Subject to Mandatory Redemption 92,831 92,831
Long-Term Debt 9,760,671 9,747,293
- ---------------------------------------------------------------------------------------------------------------
Total Capitalization 17,133,578 16,517,133
- ---------------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 868,008 275,397
Accounts payable 566,201 677,197
Income taxes accrued 156,928 -
Interest accrued 135,550 220,400
Dividends declared 136,398 132,232
Short-term obligations - 694,850
Customer deposits 167,755 158,214
Liabilities of discontinued operations - 124,767
Other current liabilities 453,366 429,222
- ---------------------------------------------------------------------------------------------------------------
Total Current Liabilities 2,484,206 2,712,279
- ---------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 753,423 932,813
Accumulated deferred investment tax credits 194,037 206,221
Regulatory liabilities 548,321 119,766
Asset retirement obligations 1,242,165 -
Other liabilities and deferred credits 923,602 836,780
- ---------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,661,548 2,095,580
- ---------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 15)
- ---------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 23,279,332 $ 21,324,992
- ---------------------------------------------------------------------------------------------------------------
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
7
Progress Energy, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS Nine Months Ended
(Unaudited) September 30,
(In thousands) 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 679,941 $ 405,081
Adjustments to reconcile net income to net cash provided by operating activities:
(Income) loss from discontinued operations 4,888 (2,013)
Impairment of long-lived assets and investments - 329,997
Depreciation and amortization 852,015 835,659
Deferred income taxes (208,260) (313,654)
Investment tax credit (12,184) (14,790)
Deferred fuel credit (143,695) (37,290)
Net increase in accounts receivable (91,003) (99,777)
Net (increase) decrease in inventories 62,951 (25,930)
Net (increase) decrease in prepayments and other current assets 43,440 (28,377)
Net increase in accounts payable (22,049) 59,184
Net increase in income taxes, net 140,450 162,213
Net decrease in other current liabilities 18,776 (52,906)
Other 109,805 74,330
- -----------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,435,075 1,291,727
- -----------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions (759,374) (771,309)
Diversified business property additions (475,992) (455,102)
Nuclear fuel additions (96,031) (56,029)
Acquisition of businesses, net of cash - (365,232)
Acquisition of intangibles (198,234) (3,079)
Proceeds from sales of subsidiaries and investments 477,502 11,931
Other (37,364) (94,861)
- -----------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (1,089,493) (1,733,681)
- -----------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net of issuance costs 283,846 31,916
Issuance of long-term debt, net of issuance costs 1,243,046 1,770,622
Net increase (decrease) in short-term indebtedness (695,899) 117,953
Net decrease in cash provided by checks drawn in excess of bank balances (53,476) (37,471)
Retirement of long-term debt (699,157) (1,045,380)
Dividends paid on common stock (403,383) (358,978)
Other 18,457 (31,126)
- -----------------------------------------------------------------------------------------------------------------------
Net Cash (Used In) Provided by Financing Activities (306,566) 447,536
- -----------------------------------------------------------------------------------------------------------------------
Cash Used in Discontinued Operations (228) (640)
- -----------------------------------------------------------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents 38,788 4,942
Cash and Cash Equivalents at Beginning of the Period 61,358 53,708
- -----------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of the Period $ 100,146 $ 58,650
- -----------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 516,081 $ 540,512
- income taxes (net of refunds) $ 97,301 $ 109,520
Noncash Activities
o On April 26, 2002, Progress Fuels Corporation, a subsidiary of the Company,
acquired 100% of Westchester Gas Company. In conjunction with the purchase,
the Company issued approximately $129.0 million in common stock.
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
8
Progress Energy, Inc.
NOTES TO CONSOLIDATED INTERIM FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
A. Organization
Progress Energy, Inc. (Progress Energy or the Company) is a registered
holding company under the Public Utility Holding Company Act of 1935
(PUHCA), as amended. Both the Company and its subsidiaries are subject to
the regulatory provisions of PUHCA. Effective January 1, 2003, Carolina
Power & Light Company, Florida Power Corporation and Progress Ventures,
Inc. (PVI) began doing business under the names Progress Energy Carolinas,
Inc. (PEC), Progress Energy Florida, Inc. (PEF) and Progress Energy
Ventures, Inc., respectively. The legal names of these entities have not
changed, and there was no restructuring of any kind related to the name
change. The current corporate and business unit structure remains
unchanged.
Through its wholly-owned subsidiaries, PEC and PEF, the Company is engaged
in the generation, purchase, transmission, distribution and sale of
electricity primarily in portions of North Carolina, South Carolina and
Florida. The Progress Ventures business unit consists of the Fuels and
Competitive Commercial Operations (CCO) operating segments. The Fuels
operating segment includes natural gas drilling and production, coal mining
and synthetic fuels production. The CCO operating segment includes
nonregulated generation and energy marketing activities. Through other
business units, the Company engages in other nonregulated business areas,
including energy management and related services, rail services and
telecommunications. 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 complete financial 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, 2002 and notes thereto included in Progress Energy's Form 10-K
for the year ended December 31, 2002.
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 $35.4 million and $39.1 million for the three months ended
September 30, 2003 and 2002, respectively, in order to maintain an
effective tax rate consistent with the estimated annual rate. Income tax
expense was decreased by $40.8 million and increased $40.5 million for the
nine months ended September 30, 2003 and 2002, respectively.
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 2002 have been reclassified to conform
to the 2003 presentation.
9
2. ACQUISITIONS
During the first quarter of 2003, Progress Fuels Corporation, a
wholly-owned subsidiary of Progress Energy, entered into three independent
transactions to acquire approximately 162 natural gas-producing wells with
proven reserves of approximately 180 billion cubic feet (Bcf) from Republic
Energy, Inc. and two other privately-owned companies, all headquartered in
Texas. The primary assets in the acquisitions have been contributed to
Progress Fuels North Texas Gas, L.P., a wholly-owned subsidiary of Progress
Fuels Corporation. The cash purchase price for the transactions totaled
$148 million.
On May 31, 2003, PVI acquired from Williams Energy Marketing and Trading, a
subsidiary of the Williams Companies, Inc., a long-term full-requirements
power supply agreement at fixed prices with Jackson Electric Membership
Corp. (Jackson), for $188 million. See Note 7 for additional information.
3. DIVESTITURES
A. NCNG Divestiture
On September 30, 2003, the Company completed the sale of 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. Net proceeds from the sale were used to reduce debt.
Based on net proceeds associated with the NCNG sale of $443.3 million, the
Company recorded an after-tax loss of $8.9 million during the third quarter
of 2003. In the fourth quarter of 2002, the Company recorded an estimated
after-tax loss of $29.4 million. The Company anticipates adjustments to the
loss on the divestiture during the fourth quarter of 2003 related to
employee benefit settlements and the finalization of other operating
estimates.
The accompanying consolidated interim financial statements have been
restated for all periods presented for the discontinued operations of NCNG.
The net income of these operations is reported as discontinued operations
in the Consolidated Statements of Income. Interest expense 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.
Interest expense allocated for the three months ended September 30, 2003
and 2002 was $3.3 million and $3.9 million, respectively. Amounts allocated
for the nine months ended September 30, 2003 and 2002 were $10.2 million
and $11.9 million, respectively. The Company ceased recording depreciation
upon classification of the assets as discontinued operations in the fourth
quarter of 2002. After-tax depreciation expense recorded by NCNG during the
three months ended September 30, 2002 was $3.1 million and during the nine
months ended September 30, 2002 was $8.9 million. Results of discontinued
operations were as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
(in thousands) 2003 2002 2003 2002
-------------- ------------- --------------- --------------
Revenues $ 59,348 $ 60,589 $ 284,389 $ 211,214
============== ============= =============== ==============
Earnings (loss) before income taxes $ (16,108) $ (6,527) $ 6,494 $ 2,423
Income tax expense (benefit) (6,313) (1,388) 2,486 410
-------------- ------------- --------------- --------------
Net earnings (loss) from discontinued
operations (9,795) (5,139) 4,008 2,013
-------------- ------------- --------------- --------------
Estimated loss on disposal of discontinued
operations, including applicable income
tax expense of $3,522 (8,896) - (8,896) -
-------------- ------------- --------------- --------------
Earnings (loss) from discontinued operations $ (18,691) $ (5,139) $ (4,888) $ 2,013
============== ============= =============== ==============
10
The major balance sheet classes included in assets and liabilities of
discontinued operations in the Consolidated Balance Sheets as of December
31, 2002 are as follows:
(in thousands)
Utility plant, net $ 398,931
Current assets 72,821
Deferred debits and other assets 18,677
---------------
Assets of discontinued operations $ 490,429
===============
Current liabilities $ 76,372
Deferred credits and other liabilities 48,395
---------------
Liabilities of discontinued operations $ 124,767
===============
The sale of ENCNG resulted in net proceeds of $7.5 million and a pre-tax
loss of $2.2 million, which is included in other, net on the Consolidated
Statements of Income for the three and nine months ended September 30,
2003. The Company's equity investment in ENCNG of $7.7 million as of
December 31, 2002 is included in miscellaneous other property and
investments in the Consolidated Balance Sheets.
B. Mesa Hydrocarbons, Inc. Divestiture
In September 2003, the Finance Committee as authorized by the Company's
Board of Directors adopted a resolution approving the sale of certain gas
producing properties owned by Mesa Hydrocarbons, LLC, a wholly-owned
subsidiary of Progress Fuels Corporation, which is included in the Fuels
segment. The $79.7 million book value of the assets to be sold has been
grouped as assets held for sale and are included in other current assets on
the accompanying Consolidated Balance Sheets as of September 30, 2003. The
primary components of assets held for sale are oil and gas leases and
wells.
On October 1, 2003, the Company completed the sale of these assets. Net
proceeds of approximately $97 million will be used to reduce debt. The
Company will record this transaction in the fourth quarter of 2003.
C. Railcar Ltd. Divestiture
In December 2002, the Progress Energy Board of Directors adopted a
resolution authorizing the sale of the majority of the assets of Railcar
Ltd., a leasing subsidiary included in the Rail Services segment. An
estimated impairment on assets held for sale was recognized in December
2002 to write-down the assets to fair value less costs to sell.
The assets of Railcar Ltd. have been grouped as assets held for sale and
are included in other current assets in the accompanying Consolidated
Balance Sheets as of September 30, 2003. The assets are recorded at $33.1
million and $23.6 million as of September 30, 2003 and December 31, 2002,
respectively.
On March 12, 2003, the Company signed a letter of intent with The
Andersons, Inc. to sell the majority of Railcar Ltd. assets. A definitive
purchase agreement was signed on November 6, 2003 with the buyers,
including Cap Acquire LLC. A significant portion of the proceeds from the
sale will be used by the Company to pay off certain Railcar Ltd. off
balance sheet lease obligations for railcars that will be transferred to
the buyers as part of the sales transaction. The transaction is targeted to
close in 2003, but is subject to various closing conditions including
financing.
4. FINANCIAL INFORMATION BY BUSINESS SEGMENT
The Company currently provides services through the following business
segments: PEC Electric, PEF, Fuels, Competitive Commercial Operations
(CCO), Rail and Other.
PEC Electric and PEF are 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 and the FPSC. PEC
Electric also distributes and sells electricity to other utilities,
primarily on the east coast of the United States.
11
Fuels' operations, which are located in the United States, include
synthetic fuel operations; natural gas production; and coal fuel
extraction, manufacturing and delivery.
CCO's operations, which are located in the southeastern United States,
include nonregulated generation and energy marketing activities.
Rail's operations include railcar repair, rail parts reconditioning and
sales, railcar leasing 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's operations are located in the United States, Canada and Mexico.
The Other segment, whose operations are primarily in the United States, is
made up of other nonregulated business areas including telecommunications
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." Included in this segment's 2002 losses
are asset impairments and certain other charges related to the
telecommunications operations of $224.8 million.
Prior to 2003, PEC Electric was referred to as CP&L Electric, PEF was
referred to as Florida Power Electric, and Fuels and CCO were collectively
referred to as Progress Ventures. The nature of the PEC Electric and PEF
segments is unchanged from previous years' reporting. With the expansion of
the nonregulated energy generation facilities and the current management
structure, CCO is now a distinct operating segment.
In addition to these reportable operating segments, the Company has other
corporate activities that include holding company operations, service
company operations and eliminations. These corporate activities have been
included in the Other segment in the past. Additionally, earnings from
wholesale customers of the regulated plants have previously been reported
in both the regulated utilities' results and the results of Progress
Ventures. With the realignment of the reportable business segments, this
activity is now included in the regulated utilities' results only. The
operations of NCNG, previously reported in the Other segment, were
reclassified to discontinued operations and therefore were not included in
the results from continuing operations during the periods reported. For
comparative purposes, the 2002 results have been restated to align with the
new business segment structure.
The profit or loss of the identified segments plus the loss of Corporate
represents the Company's total income from continuing operations.
Revenues
--------------------------------------------------- Segment
(in thousands) Unaffiliated Intersegment Total Profit (Loss)
------------ --------------- ---------------- ------------
Three Months Ended September 30, 2003
PEC Electric $ 1,009,889 $ - $ 1,009,889 $ 159,998
PEF 904,115 - 904,115 114,341
Fuels 236,691 135,739 372,430 79,752
CCO 66,653 - 66,653 12,671
Rail 208,795 951 209,746 706
Other 14,679 3,578 18,257 (3,588)
Corporate (56) (140,268) (140,324) (26,227)
------------ --------------- ---------------- ------------
Consolidated totals $ 2,440,766 $ - $ 2,440,766 $ 337,653
------------ --------------- ---------------- ------------
Three Months Ended September 30, 2002
PEC Electric $ 1,045,180 $ - $ 1,045,180 $ 179,308
PEF 863,637 - 863,637 123,774
Fuels 161,962 132,839 294,801 52,123
CCO 44,345 - 44,345 20,853
Rail 179,712 1,282 180,994 733
Other 17,543 3,562 21,105 (225,884)
Corporate - (137,683) (137,683) 6,166
------------ --------------- ---------------- ------------
Consolidated totals $ 2,312,379 $ - $ 2,312,379 $ 157,073
------------ --------------- ---------------- ------------
12
Revenues Segment
-----------------------------------------------
Profit
(in thousands) Unaffiliated Intersegment Total (Loss) Assets
------------ --------------- ---------------- ------------ -------------
Nine Months Ended September 30, 2003
PEC Electric $ 2,751,599 $ - $ 2,751,599 $ 383,262 $ 9,736,103
PEF 2,399,079 - 2,399,079 246,457 6,048,238
Fuels 639,159 380,813 1,019,972 160,139 1,117,205
CCO 137,486 - 137,486 23,579 1,700,765
Rail 600,344 951 601,295 (498) 595,104
Other 41,758 11,214 52,972 (2,648) 279,120
Corporate 53 (392,978) (392,925) (125,462) 3,802,797
------------ --------------- ---------------- ------------ -------------
Consolidated totals $ 6,569,478 $ - $ 6,569,478 $ 684,829 $ 23,279,332
------------ --------------- ---------------- ------------ -------------
Nine Months Ended September 30, 2002
PEC Electric $ 2,691,320 $ - $ 2,691,320 $ 396,530 $ 8,785,416
PEF 2,316,001 - 2,316,001 258,271 5,079,718
Fuels 435,657 389,434 825,091 140,450 843,422
CCO 77,291 - 77,291 25,478 1,538,285
Rail 529,818 2,632 532,450 2,979 579,947
Other 60,941 10,496 71,437 (239,254) 450,511
Corporate - (402,562) (402,562) (181,386) 3,840,874
------------ --------------- ---------------- ------------ -------------
Consolidated totals $ 6,111,028 $ - $ 6,111,028 $ 403,068 $ 21,118,173
------------ --------------- ---------------- ------------ -------------
5. IMPACT OF NEW ACCOUNTING STANDARDS
SFAS No. 148, "Accounting for 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 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 Company's information related to the pro forma impact on
earnings and earnings per share assuming stock options were expensed for
the three and nine months ended September 30 is as follows:
(in millions except per share data) Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2003 2002 2003 2002
--------------- ------------- ------------ --------------
Net income, as reported $ 318,962 $ 151,934 $ 679,941 $ 405,081
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 2,794 1,686 7,070 4,798
--------------- ------------- ------------ --------------
Pro forma net income $ 316,168 $ 150,248 $ 672,871 $ 400,283
=============== ============= ============ ==============
Basic earnings per share
As reported $ 1.34 $ 0.71 $ 2.88 $ 1.89
Pro forma $ 1.33 $ 0.70 $ 2.85 $ 1.87
Fully diluted earnings per share
As reported $ 1.34 $ 0.70 $ 2.87 $ 1.88
Pro forma $ 1.32 $ 0.69 $ 2.84 $ 1.86
13
During 2003, the Financial Accounting Standards Board (FASB) has approved
certain decisions in conjunction with its stock-based compensation project.
Some of the key decisions reached by the FASB were that stock-based
compensation should be recognized as an expense and that the expense should
be measured as of the grant date at fair value. The FASB continues to
deliberate additional issues in this project and plans to issue an exposure
draft in early 2004.
Derivative Instruments and Hedging Activities
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." The statement amends and
clarifies SFAS No. 133 on accounting for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. The new guidance incorporates decisions made as part of the
Derivatives Implementation Group (DIG) process, as well as decisions
regarding implementation issues raised in relation to the application of
the definition of a derivative. SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003. Interpretations and
implementation issues with regard to SFAS No. 149 continue to evolve. Based
on its analysis and understanding to date, and considering the types of
contracts historically entered into, the Company does not anticipate that
this statement will have a significant impact on its results of operations
or financial position.
In connection with the January 2003 FASB Emerging Issues Task Force (EITF)
meeting, the FASB was requested to reconsider an interpretation of SFAS No.
133. The interpretation, which is contained in the Derivative
Implementation Group's C11 guidance, relates to the pricing of contracts
that include broad market indices (e.g., CPI). In particular, that guidance
discusses whether the pricing in a contract that contains broad market
indices could qualify as a normal purchase or sale (the normal purchase or
sale term is a defined accounting term, and may not, in all cases, indicate
whether the contract would be "normal" from an operating entity viewpoint).
In late June 2003, the FASB issued final superseding guidance (DIG Issue
C20) on this issue, which is significantly different from the tentative
superseding guidance that was issued in April 2003. The new guidance is
effective October 1, 2003 for the Company. DIG Issue C20 specifies new
pricing-related criteria for qualifying as a normal purchase or sale, and
it requires a special transition adjustment as of October 1, 2003.
PEC determined that it has one existing "normal" contract that is affected
by this revised guidance. The contract is a purchase power agreement with
Broad River LLC, which is a subsidiary of Calpine Corporation. Pursuant to
the provisions of DIG Issue C20, PEC will record a pre-tax fair value loss
transition adjustment of $37.6 million in the fourth quarter of 2003, which
will be reported as a cumulative effect of a change in accounting
principle. The subject contract meets the DIG Issue C20 criteria for normal
purchase or sale and, therefore, was designated as a normal purchase as of
October 1, 2003. The liability of $37.6 million associated with the fair
value loss will be amortized to earnings over the term of the related
contract.
SFAS No. 150, "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity."
SFAS 150 establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. The financial instruments within the scope of SFAS No. 150 include
mandatorily redeemable stock, obligations to repurchase the issuer's equity
shares by transferring assets, and certain obligations to issue a variable
number of shares. SFAS No. 150 is effective immediately for such financial
instruments entered into or modified after May 31, 2003, and was effective
for previously issued financial instruments within its scope on July 1,
2003.
The FPC Capital I Preferred Securities, as discussed in Note 12, were
reported as debt prior to July 1, 2003. Therefore, the adoption of SFAS No.
150 did not have a material impact on the Company's financial position or
results of operations as of and for the periods ended September 30, 2003.
FIN No. 46, "Consolidation of Variable Interest Entities"
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
This interpretation provides guidance related to identifying variable
interest entities and determining whether such entities should be
consolidated. FIN No. 46 requires an enterprise to consolidate a variable
interest entity when the enterprise (a) absorbs a majority of the variable
interest entity's expected losses, (b) receives a majority of the entity's
expected residual returns, or both, as a result of ownership, contractual
or other financial interests in the entity. Prior to the effective date of
FIN No. 46, entities were generally consolidated by an enterprise that had
control through ownership of a majority voting interest in the entity. FIN
No. 46 applies immediately to variable interest entities created or
obtained after January 31, 2003. During the first nine months of 2003, the
Company did not participate in the creation of, or obtain a new variable
interest in, any variable interest entity. On October 9, 2003, the FASB
issued Staff Position No. FIN 46-6, which allowed for the optional deferral
of the effective date of FIN No. 46 from July 1, 2003 until December 31,
2003, for interests held by a public company in variable interest entities
created prior to February 1, 2003. Because the Company expects additional
transitional guidance to be issued, it has deferred its implementation of
FIN No. 46 until December 31, 2003.
14
The Company has entered into arrangements with several variable interest
entities through its Railcar, Ltd. subsidiary. These agreements include six
synthetic leases with a master trust, a servicing contract with the Railcar
Asset Financing Trust (RAFT), and a receivables securitization transaction
with a commercial paper conduit. Because the Company expects to divest of
its interests in all of these arrangements in 2003, the adoption of FIN No.
46 related to these variable interests is not expected to have a
significant effect on the Company's financial position or results of
operations. If the Company does not divest of its interests in 2003 as
expected, under the current guidance the Company would consolidate the
master trust and record an increase in both total assets and total
liabilities of approximately $25.8 million. As of September 30, 2003, the
maximum cash obligations under all three of these arrangements total
approximately $39.2 million. Management believes this maximum loss exposure
is significantly reduced based on the current fair values of the underlying
assets of the entities.
Upon adoption of FIN No. 46 as currently issued, the Company expects to
deconsolidate the FPC Capital I Trust (the Trust), which holds
FPC-obligated mandatorily redeemable preferred securities (see Note 12).
The Trust is a variable interest entity, but the Company does not absorb a
majority of the Trust's expected losses and therefore is not its primary
beneficiary. In connection with the planned deconsolidation as of December
31, 2003, the Company expects to record an additional equity investment in
the Trust of approximately $9.3 million, an increase in outstanding debt of
approximately $8.0 million, and a gain of approximately $1.3 million
relating to the cumulative effect of a change in accounting principle. See
Note 12 for a discussion of the Company's guarantees with the Trust.
The Company also has investments in 14 limited partnerships accounted for
under the equity method for which it may be the primary beneficiary. These
partnerships invest in and operate low-income housing and historical
renovation properties that qualify for federal and state tax credits. The
Company has not concluded whether it is the primary beneficiary of these
partnerships. These partnerships are partially funded with financing from
third party lenders, which is secured by the assets of the partnerships.
The creditors of the partnerships do not have recourse to the Company. As
of September 30, 2003, the maximum exposure to loss as a result of the
Company's investments for these limited partnerships is approximately $15.5
million. The Company expects to complete its evaluation of these
partnerships under FIN No. 46 during the fourth quarter of 2003. If the
Company had consolidated these 14 entities as of September 30, 2003, it
would have recorded an increase to both total assets and total liabilities
of approximately $45.8 million.
The Company is also evaluating several other potential variable interest
entities created before January 31, 2003, for which the Company would not
be the primary beneficiary based on the current guidance. These
arrangements include equity investments in approximately 20 limited
partnerships, limited liability corporations and venture capital funds, and
two building leases with special purpose entities. If all of these entities
were determined to be variable interest entities, the aggregate maximum
loss exposure as of September 30, 2003 under these arrangements totals
approximately $37.3 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. The Company expects to
complete its evaluation of these entities under FIN No. 46 during the
fourth quarter of 2003.
EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans"
In May 2003, the EITF reached consensus in EITF Issue No. 03-04 to
specifically address the accounting for certain cash balance pension plans.
The consensus reached in EITF Issue No. 03-04 requires certain cash balance
pension plans to be accounted for as defined benefit plans. For cash
balance plans described in the consensus, the consensus also requires the
use of the traditional unit credit method for purposes of measuring the
benefit obligation and annual cost of benefits earned as opposed to the
projected unit credit method. The Company has historically accounted for
its cash balance plans as defined benefit plans; however, the Company is
required to adopt the measurement provisions of EITF 03-04 at its cash
balance plans' next measurement date of December 31, 2003. Any differences
in the measurement of the obligations as a result of applying the consensus
will be reported as a component of actuarial gain or loss. The effect of
this standard on the Company is dependent on other factors that also affect
the determination of actuarial gains and losses and the subsequent
amortization of such gains and losses. However, the Company does not expect
the adoption of EITF 03-04 to have a material effect on its results of
operations or financial position.
15
6. ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, "Accounting for Asset Retirement Obligations," provides
accounting and disclosure requirements for retirement obligations
associated with long-lived assets and was adopted by the Company effective
January 1, 2003. This statement requires that the present value of
retirement costs for which the Company has a legal obligation be recorded
as liabilities with an equivalent amount added to the asset cost and
depreciated over an appropriate period. The liability is then accreted over
time by applying an interest method of allocation to the liability.
Cumulative accretion and accumulated depreciation were recognized for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect, to the date of adoption of
this statement. For assets acquired through acquisition, the cumulative
effect was based on the acquisition date.
Upon adoption of SFAS No. 143, the Company recorded asset retirement
obligations (AROs) totaling $1,182.5 million for nuclear decommissioning of
irradiated plant at PEC and PEF. The Company used an expected cash flow
approach to measure these obligations. This amount includes accruals
recorded prior to adoption totaling $775.2 million, which were previously
recorded in accumulated depreciation. The related asset retirement costs,
net of accumulated depreciation, recorded upon adoption totaled $367.5
million for regulated operations. The adoption of this statement had no
impact on the income of the regulated entities, as the effects were offset
by the establishment of a regulatory asset and a regulatory liability
pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation." A regulatory asset was recorded related to PEC in the amount
of $271.1 million, representing the cumulative accretion and accumulated
depreciation for the time period from the date the liability would have
been recognized had the provisions of this statement been in effect to the
date of adoption, less amounts previously recorded. A regulatory liability
was recorded related to PEF in the amount of $231.3 million, representing
the amount by which previously recorded accruals exceeded the cumulative
accretion and accumulated depreciation for the time period from the date
the liability would have been recognized had the provisions of this
statement been in effect at the date of the acquisition of the assets by
Progress Energy to the date of adoption.
Funds set aside in the Company's nuclear decommissioning trust fund for the
nuclear decommissioning liability totaled $883.8 million at September 30,
2003 and $796.8 million at December 31, 2002. In accordance with SFAS No.
143, unrealized gains and losses on the nuclear decommissioning trust fund
are now included in regulatory liabilities rather than accumulated
depreciation. The balances of these regulatory liabilities as of September
30, 2003 were $84.3 million for PEC and $78.1 million for PEF.
The Company also recorded AROs totaling $10.3 million for synthetic fuel
operations of PVI and coal mine operations, synthetic fuel operations and
gas production of Progress Fuels Corporation. The Company used an expected
cash flow approach to measure these obligations. This amount includes
accruals recorded prior to adoption totaling $4.6 million, which was
previously recorded in other liabilities and deferred credits. The related
asset retirement costs, net of accumulated depreciation, recorded upon
adoption totaled $7.0 million for nonregulated operations. The cumulative
effect of initial adoption of this statement related to nonregulated
operations was $1.3 million of pre-tax income, which is included in other,
net on the Consolidated Statements of Income for the nine months ended
September 30, 2003. The ongoing impact on earnings related to accretion and
depreciation was not significant for the three or nine months ended
September 30, 2003.
Pro forma net income has not been presented for prior years because the pro
forma application of SFAS No. 143 to prior years would result in pro forma
net income not materially different from the actual amounts reported.
The Company has identified but not recognized AROs related to electric
transmission and distribution, gas distribution and telecommunications
assets as the result of easements over property not owned by the Company.
These easements are generally perpetual and only require retirement action
upon abandonment or cessation of use of the property for the specified
purpose. The ARO liability is not estimable for such easements as the
Company intends to utilize these properties indefinitely. In the event the
Company decides to abandon or cease the use of a particular easement, an
ARO liability would be recorded at that time.
The utilities have previously recognized removal costs as a component of
depreciation in accordance with regulatory treatment. As of September 30,
2003, the portions of such costs not representing AROs under SFAS No. 143
were $908.7 million for PEC and $955.8 million for PEF. The amounts for PEC
and PEF are included in accumulated depreciation on the accompanying
Consolidated Balance Sheets. PEC and PEF have collected amounts for
non-irradiated areas at nuclear facilities, which do not represent asset
retirement obligations. The amounts at September 30, 2003 were $65.7
million for PEC and $61.5 million for PEF, which are included in
accumulated depreciation on the accompanying Consolidated Balance Sheets.
PEF previously collected amounts for dismantlement of its fossil generation
plants. As of September 30, 2003, this amounted to $142.4 million, which is
included in accumulated depreciation on the accompanying Consolidated
Balance Sheets. This collection was suspended pursuant to the rate case
settlement discussed in Note 13A.
16
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 initially denied the deferral of
the ongoing effects. During the second quarter of 2003, PEC ceased deferral
of the ongoing effects 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 $13.6 million,
which represented a decrease in non-ARO cost of removal expense, partially
offset by an increase in decommissioning expense. PEC requested
reconsideration from the NCUC regarding the ongoing effects. During the
third quarter of 2003, the NCUC issued an order allowing the deferral of
the ongoing effects of SFAS No. 143 and PEC reversed the second quarter
income statement impact in accordance with the NCUC's decision. Therefore,
the ongoing effects of SFAS No. 143 have no impact on the income of PEC for
the nine months ended September 30, 2003.
On April 8, 2003, the SCPSC approved a joint request by PEC, Duke Energy
and South Carolina Electric and Gas Company for an accounting order to
authorize the deferral of all cumulative and prospective effects related to
the adoption of SFAS No. 143.
On January 23, 2003, the Staff of the FPSC issued a notice of proposed rule
development to adopt provisions relating to accounting for asset retirement
obligations under SFAS No. 143. Accompanying the notice was a draft rule
presented by the Staff which adopts the provisions of SFAS No. 143 along
with the requirement to record the difference between amounts prescribed by
the FPSC and those used in the application of SFAS No. 143 as regulatory
assets or regulatory liabilities, which was accepted by all parties.
Therefore, the adoption of the statement had no impact on the income of PEF
due to the establishment of a regulatory liability pursuant to SFAS No. 71.
A final order was issued in the third quarter of 2003.
7. GOODWILL AND OTHER INTANGIBLE ASSETS
SFAS No. 142, "Goodwill and Other Intangible Assets," requires that
goodwill be tested for impairment at least annually and more frequently
when indicators of impairment exist. SFAS No. 142 requires a two-step fair
value-based test. The first step, used to identify potential impairment,
compares the fair value of the reporting unit with its carrying amount,
including goodwill. The second step, used to measure the amount of the
impairment loss if step one indicates a potential impairment, compares the
implied fair value of the reporting unit goodwill with the carrying amount
of the goodwill. This assessment could result in periodic impairment
charges. The Company performed the annual goodwill impairment test for the
CCO segment in the first quarter of 2003, and the annual goodwill
impairment test for the PEC Electric and PEF segments in the second quarter
of 2003, which indicated no impairment.
During 2002, the Company acquired Westchester Gas Company (Westchester).
The purchase price was finalized during the first quarter 2003 with the
purchase price being primarily allocated to fixed assets including oil and
gas properties. No goodwill was recorded.
The carrying amounts of goodwill at September 30, 2003, by reportable
segment, are $1.9 billion, $1.7 billion and $64.1 million for PEC Electric,
PEF and CCO, respectively.
The gross carrying amount and accumulated amortization of the Company's
intangible assets as of September 30, 2003 and December 31, 2002 are as
follows:
September 30, 2003 December 31, 2002
------------------------------------------- ------------------------------------------
(in thousands) Gross Carrying Amount Accumulated Gross Carrying Amount Accumulated
Amortization Amortization
--------------------- --------------------- --------------------- --------------------
Synthetic fuel intangibles $ 140,469 $(59,481) $ 140,469 $(45,189)
Power agreements acquired 221,218 (15,161) 33,000 (5,593)
Other 60,117 (10,357) 40,968 (7,792)
--------------------- --------------------- --------------------- --------------------
Total $ 421,804 $(84,999) $ 214,437 $(58,574)
--------------------- --------------------- --------------------- --------------------
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
(the Code) in December 2007.
On May 31, 2003, PVI acquired from Williams Energy Marketing and Trading, a
subsidiary of The Williams Companies, Inc., a long-term full-requirements
power supply agreement at fixed prices with Jackson Electric Membership
Corp., located in Jefferson, Georgia for $188 million. Assignment of
Williams' responsibilities under the contract began in June 2003 and
terminates in 2015, with a first refusal option to extend for five years.
The agreement includes the use of 640 megawatts (MW) of contracted Georgia
System generation comprised of nuclear, coal, gas and pumped-storage hydro
resources. The intangible related to this power agreement is being
amortized based on the economic benefits of the contract. As part of the
acquisition of generating assets from LG&E Energy Corp. on February 15,
2002, power agreements of $33.0 million were recorded and are amortized
based on the economic benefits of the contracts through December 31, 2004,
which approximates straight-line.
17
Other intangibles are primarily customer contracts and permits that are
amortized over their respective lives. Of the increase in other intangible
assets, $9.2 million relates to customer contracts acquired as part of the
Westchester acquisition, which was identified as an intangible in the final
purchase price allocation.
Net intangible assets are included in other assets and deferred debits in
the accompanying Consolidated Balance Sheets. Amortization expense recorded
on intangible assets for the three months ended September 30, 2003 and
2002, respectively, was $10.7 million and $8.3 million. Amortization
expense recorded on intangible assets for the nine months ended September
30, 2003 and 2002, respectively, was $26.4 million and $24.5 million. The
estimated annual amortization expense for intangible assets for 2003
through 2007, in millions, is approximately $36.8, $41.3, $34.8, $35.9 and
$36.1, respectively.
8. COMPREHENSIVE INCOME
Comprehensive income for the three and nine months ended September 30, 2003
was $337.9 million and $696.1 million, respectively. Comprehensive income
for the three and nine months ended September 30, 2002 was $141.8 million
and $398.2 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
On February 21, 2003, PEF issued $425 million of First Mortgage Bonds,
4.80% Series, Due March 1, 2013 and $225 million of First Mortgage Bonds,
5.90% Series, Due March 1, 2033. Proceeds from this issuance were used to
repay the balance of its outstanding commercial paper, to refinance its
secured and unsecured indebtedness, including $70 million of PEF's First
Mortgage Bonds, 6.125% Series, Due March 1, 2003, and to redeem on March
24, 2003, the $150 million aggregate outstanding balance of its First
Mortgage Bonds, 8% Series, Due December 1, 2022 at 103.75% of the principal
amount of such bonds.
In March 2003, Progress Genco Ventures, LLC (Genco), a wholly-owned
subsidiary of PVI, terminated its $50 million working capital credit
facility. A related construction facility initially provided for Genco to
draw up to $260 million. The amount outstanding under this facility is $241
million as of September 30, 2003. During the three months ended September
30, 2003, Genco determined it did not need to make any additional draws
under this facility.
On April 1, 2003, PEF entered into a new $200 million 364-day credit
agreement and a new $200 million three-year credit agreement, replacing its
prior credit facilities (which had been a $90 million 364-day facility and
a $200 million five-year facility). The new PEF credit facilities contain a
defined maximum total debt to total capital ratio of 65%; as of September
30, 2003 the calculated ratio, as defined, was 51.3%. The new credit
facilities also contain a requirement that the ratio of EBITDA, as defined
in the facilities, to interest expense to be at least 3 to 1; as of
September 30, 2003 the calculated ratio, as defined, was 8.1 to 1.
Also on April 1, 2003, PEC reduced the size of its existing 364-day credit
facility from $285 million to $165 million. The other terms of this
facility were not changed. On July 30, 2003, PEC renewed its $165 million
364-day credit agreement. PEC's $285 million three-year credit agreement
entered into in 2002 remains in place, for total facilities of $450
million.
On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5%
Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds;
PEC funded the redemption with commercial paper.
On July 1, 2003, $110 million of PEF's First Mortgage Bonds, 6.0% Series,
Due July 1, 2003 and $35 million of PEF's medium-term notes, 6.62% Series,
matured; PEF funded the redemption with commercial paper.
On August 15, 2003, PEC redeemed $100 million of First Mortgage Bonds,
6.875% Series, Due August 15, 2023 at 102.84%. PEC funded the redemption
with commercial paper.
On September 11, 2003, PEC issued $400 million of First Mortgage Bonds,
5.125% Series, Due September 15, 2013 and $200 million of First Mortgage
Bonds, 6.125% Series, Due September 15, 2033. Proceeds from this issuance
were used to reduce the balance of PEC's outstanding commercial paper and
short-term notes payable to affiliated companies, which notes represent
PEC's borrowings under an internal money pool operated by Progress Energy.
On September 30, 2003, Progress Energy completed the sale of NCNG and the
Company's equity investment in ENCNG. Net proceeds of approximately $450
million were used to reduce debt.
18
In addition, the Company received net proceeds of approximately $97 million
in October 2003 for the sale of its Mesa gas properties located in
Colorado. Net proceeds will primarily be used to reduce short-term debt.
For the three months ended September 30, 2003, the Company issued
approximately 2.7 million shares representing approximately $112 million in
proceeds from its Investor Plus Stock Purchase Plan and its employee
benefit plans. For the nine months ended September 30, 2003, the Company
issued approximately 6.9 million shares through these plans, resulting in
approximately $284 million of cash proceeds.
On October 31, 2003, PEF announced the redemption of $100 million of its
First Mortgage Bonds, 7% Series, Due 2023 at 103.19% of the principal
amount of such bonds. PEF intends to redeem the bonds on December 1, 2003
with commercial paper proceeds.
10. 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 is chaired by the Chief Financial Officer and 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 manages its market risk in accordance with its established risk
management policies, which may include entering into various derivative
transactions.
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. Treasury
rate lock agreements were terminated in conjunction with the pricing of the
PEF First Mortgage Bonds in February 2003. The loss on the agreements was
deferred and is being amortized over the life of the bonds as these
agreements had been designated as cash flow hedges for accounting purposes.
The amount of this loss was not material.
As of September 30, 2003, Progress Energy had $850 million of fixed rate
debt swapped to floating rate debt by executing interest rate derivative
agreements. Under terms of these swap rate agreements, Progress Energy will
receive a fixed rate and pay a floating rate based on 3-month LIBOR. These
agreements expire in March of 2006, April 2007 and October 2008.
In March, April, May and June of 2003, PEC entered into treasury rate locks
to hedge its exposure to interest rates with regard to a future issuance of
fixed-rate debt. These agreements had a computational period of ten years
and were designated as cash flow hedges for accounting purposes. The
agreements, with a total notional amount of $110 million, were terminated
simultaneously with the pricing of the PEC First Mortgage Bonds in
September 2003. The $4.2 million gain on the agreements was deferred and is
being amortized over the life of the bonds as these agreements had been
designated as cash flow hedges for accounting purposes.
Progress Fuels Corporation periodically enters into derivative instruments
to hedge its exposure to price fluctuations on natural gas sales. As of
September 30, 2003, Progress Fuels Corporation had approximately 12.6 Bcf
of cash flow hedges in place for its natural gas production. These
positions span the remainder of 2003 and extend through December 2004.
These instruments did not have a material impact on the Company's
consolidated financial position or results of operations.
Genco has a series of interest rate collars to hedge floating rate exposure
associated with the construction credit facility. These collars hedge 75%
of the drawn facility balance through March of 2007.
The notional amounts of the above contracts are not exchanged and do not
represent exposure to credit loss. In the event of default by a
counterparty, 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.
19
11. 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 thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- -------------------------------
2003 2002 2003 2002
------------- ------------ ------------ ---------------
Weighted-average common shares - basic 239,025 216,079 236,183 214,700
Restricted stock awards 959 746 965 709
Stock options 2 59 12 173
------------- ------------ ------------ ---------------
Weighted-average shares - fully dilutive 239,986 216,884 237,160 215,582
------------- ------------ ------------ ---------------
12. FPC-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF A SUBSIDIARY
HOLDING SOLELY FPC GUARANTEED NOTES
In April 1999, the Trust, an indirect wholly-owned subsidiary of FPC,
issued 12 million shares of $25 par cumulative FPC-obligated mandatorily
redeemable preferred securities (Preferred Securities) due 2039, with an
aggregate liquidation value of $300 million and an annual distribution rate
of 7.10%. Currently, all 12 million shares of the Preferred Securities that
were issued are outstanding. Concurrent with the issuance of the Preferred
Securities, the Trust issued to Florida Progress Funding Corporation
(Funding Corp.) all of the common securities of the Trust (371,135 shares)
for $9.3 million. Funding Corp. is a direct wholly-owned subsidiary of FPC.
The existence of the Trust is for the sole purpose of issuing the Preferred
Securities and the common securities and using the proceeds thereof to
purchase from Funding Corp. its 7.10% Junior Subordinated Deferrable
Interest Notes (subordinated notes) due 2039, for a principal amount of
$309.3 million. The subordinated notes and the Notes Guarantee (as
discussed below) are the sole assets of the Trust. Funding Corp.'s proceeds
from the sale of the subordinated notes were advanced to Progress Capital
and used for general corporate purposes including the repayment of a
portion of certain outstanding short-term bank loans and commercial paper.
FPC has fully and unconditionally guaranteed the obligations of Funding
Corp. under the subordinated notes (Notes Guarantee). In addition, FPC has
guaranteed the payment of all distributions required to be made by the
Trust, but only to the extent that the Trust has funds available for such
distributions (Preferred Securities Guarantee). The Preferred Securities
Guarantee, considered together with the Notes Guarantee, constitutes a full
and unconditional guarantee by FPC of the Trust's obligations under the
Preferred Securities.
The subordinated notes may be redeemed at the option of Funding Corp.
beginning in 2004 at par value plus accrued interest through the redemption
date. The proceeds of any redemption of the subordinated notes will be used
by the Trust to redeem proportional amounts of the Preferred Securities and
common securities in accordance with their terms. Upon liquidation or
dissolution of Funding Corp., holders of the Preferred Securities would be
entitled to the liquidation preference of $25 per share plus all accrued
and unpaid dividends thereon to the date of payment.
These Preferred Securities are classified as long-term debt on the
Company's accompanying Consolidated Balance Sheets. Upon adoption of the
current FIN No. 46 standard, the Company anticipates deconsolidating the
Trust which is not expected to have a material effect on the consolidated
financial position, results of operations or liquidity (See Note 5).
13. REGULATORY MATTERS
A. Retail Rate Matters
On March 27, 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 on April 23, 2002. The
Agreement provides that PEF will operate under a Revenue Sharing Incentive
Plan (the Plan) through 2005 and thereafter until terminated by the FPSC.
The Plan establishes annual revenue caps and sharing thresholds. The Plan
provides that all retail base revenues between an established threshold and
cap will be shared - a 2/3 share to be refunded to PEF's retail customers,
and a 1/3 share to be received by PEF's shareholders. All retail base rate
revenues above the retail base rate revenue caps established for each year
will be refunded 100% to retail customers on an annual basis. The retail
base rate revenue sharing threshold amounts for 2003 are $1.333 billion and
20
will increase $37 million each year thereafter. The retail base revenue cap
for 2003 is $1.393 billion and will increase $37 million each year
thereafter. As of December 31, 2002, $4.7 million was accrued and was
refunded to customers in March 2003. On February 24, 2003, the parties to
the Agreement filed a motion seeking an order from the FPSC to enforce the
Agreement. In this motion, the parties disputed PEF's calculation of retail
revenue subject to refund and contended that the refund should be
approximately $23 million. On July 9, 2003, the FPSC ruled that PEF must
provide an additional $18.4 million to its retail customers related to the
2002 revenue sharing calculation. PEF recorded this refund in the second
quarter of 2003 as a charge against electric operating revenue and refunded
this amount by October 31, 2003. For the nine months ended September 30,
2003, PEF recorded an additional accrual of $5.4 million related to
estimated 2003 revenue sharing.
On March 4, 2003, the FPSC approved PEF's petition to increase its fuel
factors due to continuing increases in oil and natural gas commodity
prices. New rates became effective on March 28, 2003.
On September 12, 2003, PEF asked the FPSC to approve a cost adjustment in
its annual fuel filing, primarily related to rising costs of fuel that will
increase retail customer bills beginning January 1, 2004. The total amount
of the fuel adjustment requested above current levels was approximately
$322 million. A decision from the FPSC is expected on November 12, 2003.
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 March 28, 2003.
The NCUC approved an increase of $19.6 million by order issued September
25, 2003.
On October 16, 2003, PEC made a filing with the North Carolina Utilities
Commission (NCUC) to seek permission to defer expenses incurred from
Hurricane Isabel and the February 2003 winter storms. As a result of rising
storm costs and the frequency of major storm damage, Progress Energy has
asked the NCUC to allow the company to create a deferred account in which
the company would place expenses incurred as a result of named tropical
storms, hurricanes and significant winter storms. The future amortization
of such deferred costs would be includable as allowable costs in base rate
filings. The Company estimates that it would charge $23.5 million in 2003
from Hurricane Isabel and from current year ice storms to the deferred
account, if approved. Any additional major storm activity in 2003 could
cause the amount to increase.
B. Regional Transmission Organizations
In early 2000, the FERC issued Order 2000 regarding regional transmission
organizations (RTOs). This Order set minimum characteristics and functions
that RTOs must meet, including independent transmission service. As a
result of Order 2000, PEF, along with Florida Power & Light Company and
Tampa Electric Company, filed with the FERC, in October 2000, an
application for approval of a GridFlorida RTO. In March 2001, the FERC
issued an order provisionally approving GridFlorida. PEC, along with Duke
Energy Corporation and South Carolina Electric & Gas Company, filed with
the FERC, for approval of a GridSouth RTO. In July 2001, the FERC issued an
order provisionally approving GridSouth. However, in July 2001, the FERC
issued orders recommending that companies in the Southeast engage in a
mediation to develop a plan for a single RTO for the Southeast. PEF and PEC
participated in the mediation. The FERC has not issued an order
specifically on this mediation. 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. PEF and
PEC, as subsidiaries of Progress Energy, filed comments on November 15,
2002 and supplemental comments on January 10, 2003. On April 28, 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. PEF and PEC, as subsidiaries of Progress Energy, plan to
file comments on the White Paper. The FERC has also indicated that it
expects to issue a final rule after Congress votes this fall on the
proposed House and Senate Energy Bills. The Company cannot predict the
outcome of these matters or the effect that they may have on the
GridFlorida and GridSouth proceedings currently ongoing before the FERC.
The Company has $31.3 million and an immaterial amount invested in
GridSouth and GridFlorida, respectively, at September 30, 2003. It is
unknown what impact the future proceedings will have on the Company's
earnings, revenues or prices.
In October 2002, the FPSC abated its proceedings regarding its review of
the proposed GridFlorida RTO. The FPSC action to abate the proceedings came
in response to the Florida Office of Public Counsel's appeal before the
State Supreme Court requesting review of the FPSC's order approving the
transfer of operational control of electric transmission assets to an RTO
under the jurisdiction of the FERC. On June 2, 2003 the Florida Supreme
Court dismissed the appeal without prejudice on the ground that certain
portions of the Commission's order constituted non-final action. The
dismissal is without prejudice to any party to challenge the Commission's
order after all portions are final. A technical conference for the state of
Florida was conducted by the FERC on September 15, 2003. It is unknown when
the FERC or the FPSC will take final action with regard to the status of
GridFlorida or what the impact of further proceedings will have on the
Company's earnings, revenues or prices.
21
14. OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income, gain on the sale of
investments, impairment of investments 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 Nine Months Ended
September 30, September 30,
------------------------------ -------------------------------
(in thousands) 2003 2002 2003 2002
-------------- ----------- ------------ ---------------
Other income
Net financial trading gain (loss) $ 607 $ (169) $ (2,026) $ (1,598)
Net energy brokered for resale (189) 1,909 (33) 2,664
Nonregulated energy and delivery services income 5,185 7,563 16,427 20,022
Contingent value obligation mark-to-market gain (loss) (3,945) 9,371 (3,945) 22,192
Investment gains - 8,000 - 10,960
AFUDC equity 1,986 2,728 7,900 6,806
Other 2,532 (2,755) 8,127 4,133
-------------- ----------- ------------ ---------------
Total other income $ 6,176 $ 26,647 $ 26,450 $ 65,179
-------------- ----------- ------------ ---------------
Other expense
Nonregulated energy and delivery services expenses $ 4,596 $ 6,492 $ 14,292 $ 15,933
Donations 3,910 3,447 10,920 10,453
Investment losses 558 952 9,201 6,704
Other (a) 179 4,950 6,987 17,840
-------------- ----------- ------------ ---------------
Total other expense $ 9,243 $ 15,841 $ 41,400 $ 50,930
-------------- ----------- ------------ ---------------
Other, net $ (3,067) $ 10,806 $ (14,950) $ 14,249
============== =========== ============ ===============
(a) 2003 includes reduction of approximately $6 million in the FPC
contractual environmental liability as discussed in Note 15.
Net financial trading gains and losses represent non-asset-backed trades of
electricity and gas. Net energy brokered for resale represents electricity
purchased for simultaneous sale to a third party. Nonregulated energy and
delivery services include power protection services and mass market
programs (surge protection, appliance services and area light sales) and
delivery, transmission and substation work for other utilities. Investment
losses primarily represent losses on limited partnership investment funds.
15. COMMITMENTS AND CONTINGENCIES
Contingencies and significant changes to the commitments discussed in Note
24 of the financial statements included in the Company's 2002 Annual Report
on Form 10-K are described below.
A. Guarantees
a) As a part of normal business, Progress Energy and certain subsidiaries
enter into various agreements providing financial or performance assurances
to third parties. Such agreements include guarantees, standby letters of
credit and surety bonds. These agreements are entered into primarily to
support or enhance the creditworthiness otherwise attributed to a
subsidiary on a stand-alone basis, thereby facilitating the extension of
sufficient credit to accomplish the subsidiaries' intended commercial
purposes. As of September 30, 2003, management does not believe conditions
are likely for significant performance under the guarantees of performance
issued by or on behalf of affiliates discussed herein.
22
Guarantees as of September 30, 2003, are summarized in the table below and
discussed more fully in the subsequent paragraphs.
(in millions)
Guarantees issued on behalf of affiliates
Guarantees supporting nonregulated portfolio and energy marketing
activities issued by Progress Energy $ 330.6
Guarantees supporting nuclear decommissioning 276.0
Guarantee supporting power supply agreements 312.0
Standby letters of credit 9.6
Surety bonds 1.6
Other guarantees 8.2
Guarantees issued on behalf of third parties
Other guarantees 26.4
------------
Total $ 964.4
============
Guarantees Supporting Nonregulated Portfolio and Energy Marketing
Activities
Progress Energy has issued approximately $330.6 million of guarantees on
behalf of Progress Ventures (the business unit) and its subsidiaries for
obligations under tolling agreements, transmission agreements, gas
agreements, construction agreements, fuel procurement agreements and
trading operations. Approximately $68 million of these guarantees were
issued during the year to support energy marketing activities. The majority
of the marketing contracts supported by the guarantees contain language
regarding downgrade events, ratings triggers, monthly netting of exposure
and/or payments and offset provisions in the event of a default. Based upon
current business levels at September 30, 2003, if the Company's ratings
were to decline below investment grade, the Company estimates that it may
have to deposit cash or provide letters of credit or other cash collateral
of approximately $145 million for the benefit of the Company's
counterparties to support ongoing operations within a 90-day period.
Guarantees Supporting Nuclear Decommissioning
In 2003, PEC determined that its external funding levels did not fully meet
the nuclear decommissioning financial assurance levels required by the NRC.
Therefore, PEC met the financial assurance requirements by obtaining
guarantees from Progress Energy in the amount of $276.0 million.
Guarantees Supporting Power Supply Agreements
On March 20, 2003, PVI entered into a definitive agreement with Williams
Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc.,
to acquire a long-term full-requirements power supply agreement at fixed
prices with Jackson. The power supply agreement included a performance
guarantee by Progress Energy. The transaction closed during the second
quarter of 2003. The Company issued a payment and performance guarantee to
Jackson related to the power supply agreement of $285.0 million. In the
event that Progress Energy's credit ratings fall below investment grade,
Progress Energy may be required to provide additional security for this
guarantee in form and amount (not to exceed $285 million) acceptable to
Jackson. During the third quarter, PVI entered into an agreement with
Morgan Stanley Capital Group Inc. to fulfill Morgan Stanley's obligations
to schedule resources and supply energy to Oglethorpe Power Corporation of
Georgia through March 31, 2005. The Company issued a payment and
performance guarantee to Morgan Stanley related to the power supply
agreement. In the event that Progress Energy's credit ratings fall below
investment grade, Progress Energy estimates that it may have to deposit
cash or provide letters of credit or other cash collateral of approximately
$27 million for the benefit of Morgan Stanley as of September 30, 2003.
Standby Letters of Credit
The Company has issued $9.6 million of standby letters of credit to
financial institutions for the benefit of third parties that have extended
credit to the Company and certain subsidiaries. These letters of credit
have been issued primarily for the purpose of supporting payments of trade
payables, securing performance under contracts and lease obligations and
self-insurance for workers' compensation. If a subsidiary does not pay
amounts when due under a covered contract, the counterparty may present its
claim for payment to the financial institution, which will in turn request
payment from the Company. Any amounts owed by the Company's subsidiaries
are reflected in the accompanying Consolidated Balance Sheets.
23
Surety Bonds
At September 30, 2003, the Company had $1.6 million in surety bonds
purchased primarily for purposes such as providing workers' compensation
coverage, obtaining licenses, permits and rights-of-way and project
performance. To the extent liabilities are incurred as a result of the
activities covered by the surety bonds, such liabilities are included in
the accompanying Consolidated Balance Sheets.
Other Guarantees
The Company has other guarantees outstanding of approximately $34.6
million. Included in the $34.6 million are $26.4 million of guarantees
issued on behalf of third parties of which $16.4 million is related to
obligations on leasing arrangements and $10 million in support of synfuel
operations at a third party plant. The Company estimates it will have to
perform under the guarantees related to the leasing agreements and as such
$2.4 million has been accrued and is reflected in the accompanying
Consolidated Balance Sheets. The remaining $8.2 million in affiliate
guarantees are related primarily to prompt performance payments, lease
obligations and other payments subject to contingencies.
B. Insurance
Both PEC and PEF are insured against public liability for a nuclear
incident. 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 pro rata
assessments for each reactor owned per occurrence. Effective August 20,
2003, the retroactive premium assessments increased to $100.6 million per
reactor from the previous amount of $88.1 million. The total limit
available to cover nuclear liability losses increased as well from $9.6
billion to $10.8 billion. The annual retroactive premium limit of $10
million per reactor owned did not change.
C. Claims and uncertainties
Environmental
a) The Company is subject to federal, state and local regulations
addressing hazardous and solid waste management, air and water quality and
other environmental matters.
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
both electric utilities have some connection. In this regard, both electric
utilities and the gas utility and other potentially responsible parties 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), the Florida Department of
Environmental Protection (FDEP) and the North Carolina Department of
Environment and Natural Resources, Division of Waste Management (DWM). In
addition, the Company and its subsidiaries are periodically notified by
regulators such as 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 There are 9 former MGP sites and 14 other sites or groups of 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 MGP sites. All eligible expenses related to these are
charged against a specific fund containing these proceeds. As of September
30, 2003, approximately $8.7 million remains in this centralized fund with
a related accrual of $8.7 million recorded for the associated expenses of
environmental issues. As PEC's share of costs for investigating and
remediating these sites becomes known, the fund is assessed to determine if
additional accruals will be required. PEC does not believe that it can
provide an estimate of the reasonably possible total remediation costs
beyond what remains in the environmental insurance recovery fund. This is
due to the fact that the sites are at different stages: investigation has
not begun at three sites, investigation has begun but remediation cannot be
estimated at five sites and remediation has begun at one site. PEC measures
its liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
24
The process often involves assessing and developing cost-sharing
arrangements with other potentially responsible parties. Once the
environmental insurance recovery fund is depleted, PEC will accrue costs
for the sites to the extent its liability is probable and the costs can be
reasonably estimated. Presently, PEC cannot determine the total costs that
may be incurred in connection with the remediation of all sites.
In September 2003, the Company sold NCNG to Piedmont Natural Gas Company,
Inc. As part of the sales agreement, the Company retained responsibility to
remediate five former NCNG MGP sites to state standards pursuant to an
Administrative Order by consent. These sites are anticipated to have
investigation or remediation costs associated with them. NCNG had
previously accrued approximately $2.2 million for probable and reasonably
estimable remediation costs at these sites. These accruals have been
recorded on an undiscounted basis. At the time of the sale, the liability
for these costs and the related accrual was transferred to a subsidiary of
PEC. PEC does not believe it can provide an estimate of the reasonably
possible total remediation costs beyond the accrual because two of the five
sites have not begun investigation activities. Therefore, PEC cannot
currently determine the total costs that may be incurred in connection with
the investigation and/or remediation of all sites. Based upon current
information, the Company does not expect the future costs at these sites to
be material to the Company's financial condition or results of operations.
PEF As of September 30, 2003, PEF has accrued $23.6 million for probable
and estimable costs related to various environmental sites. Of this
accrual, $16.6 million is for costs associated with the investigation and
remediation of transmission and distribution substations and transformers
which are more fully discussed below. The remaining $7.0 million is related
to two former MGP sites and 10 other active sites associated with PEF that
have required or are anticipated to require investigation and/or
remediation costs. PEF does not believe that it can provide an estimate of
the reasonably possible total remediation costs beyond what is currently
accrued.
In 2002, PEF accrued approximately $3.4 million for investigation and
remediation associated with transmission and distribution substations and
transformers and received approval from the FPSC for annual recovery of
these environmental costs through the Environmental Cost Recovery Clause
(ECRC). In September 2003, PEF also accrued an additional $15.1 million for
similar environmental costs as a result of increased sites and estimated
costs per site. PEF plans to seek approval from the FPSC to recover these
costs through the ECRC. As more activity occurs at these sites, PEF will
assess the need to adjust the accruals.
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 potentially responsible parties. Presently, PEF
cannot determine the total costs that may be incurred in connection with
the remediation of all sites.
Florida Progress Corporation In 2001, Progress Fuels sold its Inland Marine
Transportation business operated by MEMCO Barge Line, Inc. to AEP
Resources, Inc. Progress Fuels established an accrual to address
indemnities and retained an environmental liability associated with the
transaction. Progress Fuels estimates that its contractual liability to AEP
Resources, Inc., associated with Inland Marine Transportation is $3.5
million at September 30, 2003 and has accrued such amount. The previous
accrual of $9.9 million was reduced based on a change in estimate. This
accrual has been determined on an undiscounted basis. Progress Fuels
measures its liability for this site based on estimable and probable
remediation scenarios. The Company believes that it is not reasonably
probable that additional costs will be incurred related to the
environmental indemnification provision beyond the amount accrued. The
Company cannot predict the outcome of this matter.
Certain historical waste sites exist that are being addressed voluntarily
by Fuels. The Company cannot determine the total costs that may be incurred
in connection with these sites. The Company cannot predict the outcome of
this matter.
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. The Company cannot predict the outcome of this matter.
PEC, PEF and Fuels have filed claims with the Company's general liability
insurance carriers to recover costs arising out of actual or potential
environmental liabilities. Some claims have been settled and others are
still pending. The Company cannot predict the outcome of these matters.
The Company is also currently in the process of assessing potential costs
and exposures at other environmentally impaired 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.
25
Air Quality
There has been and may be further proposed federal legislation requiring
reductions in air emissions for nitrogen oxides, sulfur dioxide, 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. Some companies may seek
recovery of the related cost through rate adjustments or similar
mechanisms. 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.
Both PEC and PEF were asked to provide information to the EPA as part of
this initiative and cooperated in providing the requested information.
During the first quarter of 2003, PEC responded to a supplemental
information request from the EPA. PEF has received a similar supplemental
information request, and responded to it in the second quarter. 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 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 the EPA's initiative or its impact,
if any, on the Company.
In 1998, the EPA published a final rule addressing the regional transport
of ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule
requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, but not Florida, to further reduce nitrogen oxide emissions in
order to attain pre-set state NOx emission levels by May 31, 2004. PEC is
currently installing controls necessary to comply with the rule. Capital
expenditures needed to meet these measures in North and South Carolina
could reach approximately $370 million, which has not been adjusted for
inflation. 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. The Company cannot predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new
eight-hour ozone standard. In October 1999, the District of Columbia
Circuit Court of Appeals ruled against the EPA with regard to the federal
eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the
District of Columbia Circuit Court of Appeals' decision. Designation of
areas that do not attain the standard is proceeding, and further litigation
and rulemaking on this and other aspects of the standard are anticipated.
North Carolina adopted the federal eight-hour ozone standard and is
proceeding with the implementation process. North Carolina has promulgated
final regulations, which will require PEC to install nitrogen oxide
controls under the state's eight-hour standard. The costs of those controls
are included in the $370 million cost estimate set forth in the preceding
paragraph. 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.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule, as originally promulgated, required certain
sources to make reductions in nitrogen oxide emissions by May 1, 2003. The
final rule also includes a set of regulations that affect nitrogen oxide
emissions from sources included in the petitions. The North Carolina
coal-fired electric generating plants are included in these petitions.
Acceptable state plans under the NOx SIP Call can be approved in lieu of
the final rules the EPA approved as part of the Section 126 petitions. PEC,
other utilities, trade organizations and other states participated in
litigation challenging the EPA's action. On May 15, 2001, the District of
Columbia Circuit Court of Appeals ruled in favor of the EPA, which will
require North Carolina to make reductions in nitrogen oxide emissions by
May 1, 2003. However, the Court, in its May 15th decision, rejected the
EPA's methodology for estimating the future growth factors the EPA used in
calculating the emissions limits for utilities. In August 2001, the Court
granted a request by PEC and other utilities to delay the implementation of
the Section 126 rule for electric generating units pending resolution by
the EPA of the growth factor issue. The Court's order tolls the three-year
compliance period (originally set to end on May 1, 2003) for electric
generating units as of May 15, 2001. On April 30, 2002, the EPA published a
final rule harmonizing the dates for the Section 126 rule and the NOx SIP
Call. In addition, the EPA determined in this rule that the future growth
factor estimation methodology was appropriate. The new compliance date for
all affected sources is now May 31, 2004, rather than May 1, 2003. The EPA
has approved North Carolina's NOx SIP Call rule and has formally proposed
to rescind the Section 126 rule. This rulemaking is expected to become
final by early 2004. The Company expects a favorable outcome of this
matter.
26
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and
sulfur dioxide from coal-fired power plants. Progress Energy expects its
capital costs to meet these emission targets will be approximately $813
million by 2013. PEC currently has approximately 5,100 MW of coal-fired
generation capacity in North Carolina that is affected by this legislation.
The legislation 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 legislation 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 legislation 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. Pursuant to the new law, PEC entered into an agreement
with the state of North Carolina to transfer to the state any future
emissions allowances acquired as a result of compliance with the new law.
The new law also requires the state to undertake a study of mercury and
carbon dioxide emissions in North Carolina. Progress Energy cannot predict
the future regulatory interpretation, implementation or impact of this new
law. PEC did not record any clean air amortization in the third quarter of
2003 and recorded approximately $54 million of clean air amortization to
date in 2003. Clean air expenditures to date were $16.4 million as of
September 30, 2003.
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. The United States has not adopted the Kyoto Protocol;
however, a number of carbon dioxide emissions control proposals have been
advanced in Congress and by the Bush administration. The Bush
administration favors voluntary programs. Reductions in carbon dioxide
emissions to the levels specified by the Kyoto Protocol and some
legislative proposals could be materially adverse to Company financials and
operations if associated costs 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.
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. Pursuant to a Court Order, the EPA is developing a Maximum
Available Control Technology (MACT) standard, which is expected to become
final in December 2004, with compliance in 2008. Achieving compliance with
the MACT standard could be materially adverse to the Company's financial
condition and results of operations. However, the Company cannot predict
the outcome of this matter.
b) As required under the Nuclear Waste Policy Act of 1982, PEC and PEF each
entered into a contract with the U.S. 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 April 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.
27
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) has 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. PEC and PEF are in the process of evaluating whether they
should each file a similar action for damages.
On July 9, 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. PEC and PEF
cannot predict the outcome of this matter.
With certain modifications, and additional approval by the NRC, 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
current operating licenses for all of PEC's nuclear generating units.
Subsequent or prior to the expiration of these licenses, or any renewal of
these licenses, dry storage or acquisition of new shipping casks may be
necessary. PEC obtained approval from the NRC to use additional storage
space at the Harris Plant in December 2000. PEC is currently in the design
phase for adding dry storage capability at the Robinson Plant. PEF
currently is storing spent nuclear fuel onsite in spent fuel pools. If PEF
does not seek renewal of the Crystal River Nuclear Plant (CR3) operating
license, CR3 will have sufficient storage capacity in place for fuel
consumed through the end of the expiration of the license in 2016. If PEF
extends the CR3 operating license, dry storage may be necessary.
Other Contingencies
a) Progress Energy, through its subsidiaries, produces 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. Any synthetic fuel tax credit amounts
not utilized are carried forward indefinitely. 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 $1.121 billion, of which $489.1 million have been used
and $631.9 million are being carried forward as of September 30, 2003. The
current Section 29 tax credit program expires at the end of 2007.
One synthetic fuel entity, Colona Synfuel Limited Partnership, L.L.L.P.
(Colona), from which the Company (and FPC prior to its acquisition by the
Company) has been allocated approximately $286.6 million in tax credits to
date, is being audited by the IRS. The audit of Colona was expected. The
Company is audited regularly in the normal course of business, as are most
similarly situated companies.
In September 2002, all of the Company's majority-owned synthetic fuel
entities, including Colona, were accepted into the IRS Prefiling 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 June 2003, the Company was informed that IRS field auditors had raised
questions regarding the chemical change associated with coal-based
synthetic fuel manufactured at its Colona facility and the testing process
by which the chemical change is verified. (The questions arose in
connection with the Company's participation in the PFA program.) The
chemical change and the associated testing process were described as part
of the PLR request for Colona. Based on that application, the IRS ruled in
Colona's PLR that the synthetic fuel produced at Colona undergoes a
significant chemical change and thus qualifies for tax credits under
Section 29.
In October 2003, the National Office of the IRS informed the Company that
it had rejected the IRS field auditors' challenges regarding whether the
synthetic fuel produced at the Company's Colona facility was the result of
a significant chemical change. The National Office had concluded that the
experts, engaged by Colona who test the synthetic fuel for chemical change,
use reasonable scientific methods to reach their conclusions. Accordingly,
the National Office will not take any adverse action on the PLR that has
been issued for the Colona facility.
28
A written decision memorializing the National Office's conclusions should
be available within the next two months. At that time, the IRS field
auditors will have the right to ask for reconsideration of the National
Office's decision.
Although this ruling applies only to the Colona facility, the Company
believes that the National Office's reasoning should be equally applicable
to the other Progress Energy facilities, given that the Company applies
essentially the same chemical process and uses the same independent
laboratories to confirm chemical change in the synthetic fuel manufactured
at each of its other facilities. However, the IRS has not yet formally
informed the Company as to its position on the Company's other facilities.
Although this is a significant event, the audits of the Colona facility and
the Company's other facilities are not yet completed. Progress Energy
continues to believe that it operates its facilities in conformity with its
PLRs and Section 29. Accordingly, the Company has no current plans to alter
its synthetic fuel production schedule as a result of these matters.
In addition, the Company has retained an advisor to assist in selling an
interest in one or more synthetic fuel entities. The Company is pursuing
the sale of a portion of its synthetic fuel production capacity that is
underutilized due to limits on the amount of credits that can be generated
and utilized by the Company. The Company would expect to retain an
ownership interest and to operate any sold facility for a management fee.
The final outcome and timing of the Company's efforts to sell interests in
synthetic fuel facilities is uncertain and while the Company cannot predict
the outcome of this matter, the outcome is not expected to have a material
effect on the consolidated financial position, cash flows or results of
operations.
b) In November of 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. On March 4, 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 has asserted defenses to the
District's claims. SRS has amended its claims and asserted new claims
against the District and other parties, including a former SRS employee and
a former District employee.
On March 13, 2003, the City Attorney's office announced the filing of new
claims by the City Attorney and the District 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 City Attorney's announcement states that
the City and the District seek "more than $300 million in damages and
penalties."
The Company, SRS, and Progress Energy Solutions, Inc. all have filed
responsive pleadings denying the allegations, and the discovery process is
underway.
On October 2, 2003, the District filed a motion for leave to amend its
cross-complaint to add PEC as an additional defendant and the parties have
stipulated that the pleadings may be so amended. PEC will file a responsive
pleading denying the allegations.
The Company cannot predict the outcome of this matter, but the Company
believes that it and its subsidiaries have good defenses to all claims
asserted by the District and other claimants.
c) On August 21, 2003, PEC was served as a co-defendant in a purported
class action lawsuit styled as Collins v. Duke Energy Corporation, Civil
Action No. 03CP404050, in South Carolina's Circuit Court of Common Pleas
for the Fifth Judicial Circuit. PEC is one of three electric utilities
operating in South Carolina named in the suit. The plaintiffs are seeking
damages for the alleged improper use of electric easements but have not
asserted a dollar amount for their damage claims. The complaint alleges
that the licensing of attachments on electric utility poles, towers and
other structures to non-utility third parties or telecommunication
companies for other than the electric utilities' internal use along the
electric right-of-way constitutes a trespass.
On September 19, 2003, PEC filed a motion to dismiss all counts of the
complaint on substantive and procedural grounds. On October 6, 2003, the
plaintiffs filed a motion to amend their complaint. PEC believes the
amended complaint asserts the same factual allegations as are in the
original complaint and also seeks money damages and injunctive relief.
The court has not yet held any hearings or made any rulings in this case.
PEC intends to vigorously defend itself against the claims asserted by the
plaintiffs. PEC cannot predict the outcome of any future proceedings in
this case.
29
d) The Company and its subsidiaries are involved in various litigation
matters in the ordinary course of business, some of which involve claims
for substantial amounts. Where appropriate, accruals have been made in
accordance with SFAS No. 5, "Accounting for Contingencies," to provide for
such matters. The Company believes the final disposition of pending
litigation would not have a material adverse effect on the Company's
consolidated results of operations or financial position.
16. SUBSEQUENT EVENT
On November 3, 2003, Progress Telecom Corporation (PTC), Progress
Telecommunications Corporation (PTC Communications), and Caronet, Inc.
(Caronet), all of which are indirectly wholly-owned subsidiaries of
Progress Energy, agreed to enter into a Contribution Agreement (Agreement)
with EPIK Communications, Inc. (EPIK). EPIK is a wholly-owned subsidiary of
Odyssey Telecorp, Inc. (Odyssey). The Company plans to account for this
transaction as a business combination.
Under terms of the Agreement, on November 4, 2003, PTC was converted into a
limited liability company and renamed Progress Telecom, LLC (PTC LLC). The
Agreement provides that PTC Communications, Caronet and EPIK will
contribute substantially all of their assets and transfer certain
liabilities to PTC LLC in exchange for membership interests in PTC LLC.
Following the contribution of their respective net assets, PTC
Communications will hold a 55 percent membership interest in PTC LLC;
Caronet will hold a 5 percent membership interest; and EPIK will hold a 40
percent membership interest. After the contribution of net assets to PTC
LLC, the stock of Caronet will be sold to an affiliate of Odyssey for cash
and Caronet will then become an indirect wholly-owned subsidiary of
Odyssey. Following consummation of the transactions described above, PTC
Communications will hold a 55 percent ownership interest in PTC LLC, and
Odyssey will hold a 45 percent ownership interest in PTC LLC through EPIK
and Caronet. The Company anticipates closing the transaction by the end of
the year; however, the closing is subject to certain conditions precedent,
including receipt of applicable governmental and regulatory permits and
approvals.
30
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED INTERIM FINANCIAL STATEMENTS
September 30, 2003
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Nine Months Ended
(Unaudited) September 30, September 30,
- ----------------------------------------------------------------------------------------------------------------
(In thousands) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 1,009,889 $ 1,045,180 $ 2,751,599 $ 2,691,320
Diversified business 2,392 4,304 8,211 11,127
- ----------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,012,281 1,049,484 2,759,810 2,702,447
- ----------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 233,537 219,594 636,098 562,297
Purchased power 98,213 123,365 240,370 287,593
Operation and maintenance 205,667 183,686 605,838 571,009
Depreciation and amortization 135,129 130,530 415,773 405,375
Taxes other than on income 44,326 43,502 123,603 118,345
Diversified business 946 7,505 3,480 13,320
Impairment of diversified business long-lived assets - 101,251 - 101,251
- ----------------------------------------------------------------------------------------------------------------
Total Operating Expenses 717,818 809,433 2,025,162 2,059,190
- ----------------------------------------------------------------------------------------------------------------
Operating Income 294,463 240,051 734,648 643,257
- ----------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 985 330 4,426 5,198
Impairment of investment - (25,011) - (25,011)
Other, net (3,190) (5,551) (14,121) (3,870)
- ----------------------------------------------------------------------------------------------------------------
Total Other Expense (2,205) (30,232) (9,695) (23,683)
- ----------------------------------------------------------------------------------------------------------------
Interest Charges
Interest charges 46,893 49,390 144,609 167,289
Allowance for borrowed funds used during 318 276 (1,265) (5,597)
construction
- ----------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 47,211 49,666 143,344 161,692
- ----------------------------------------------------------------------------------------------------------------
Income before Income Taxes 245,047 160,153 581,609 457,882
Income Tax Expense 87,473 66,014 200,161 147,471
- ----------------------------------------------------------------------------------------------------------------
Net Income $ 157,574 $ 94,139 $ 381,448 $ 310,411
Preferred Stock Dividend Requirement 741 741 2,223 2,223
- ----------------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 156,833 $ 93,398 $ 379,225 $ 308,188
- ----------------------------------------------------------------------------------------------------------------
See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.
31
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands) September 30, December 31,
Assets 2003 2002
- ----------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 13,211,543 $ 12,675,761
Accumulated depreciation (6,190,180) (6,356,933)
- ----------------------------------------------------------------------------------------------------------
Utility plant in service, net 7,021,363 6,318,828
Held for future use 5,256 7,188
Construction work in progress 300,458 325,695
Nuclear fuel, net of amortization 147,343 176,622
- ----------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 7,474,420 6,828,333
- ----------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 63,435 18,284
Accounts receivable 306,242 301,178
Unbilled accounts receivable 119,477 151,352
Receivables from affiliated companies 18,266 36,870
Notes receivable from affiliated companies 122,577 49,772
Taxes receivable - 55,006
Inventory 332,757 342,886
Deferred fuel cost 135,063 146,015
Prepayments and other current assets 35,500 45,542
- ----------------------------------------------------------------------------------------------------------
Total Current Assets 1,133,317 1,146,905
- ----------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 522,036 252,083
Nuclear decommissioning trust funds 480,135 423,293
Diversified business property, net 13,584 9,435
Miscellaneous other property and investments 199,122 209,657
Other assets and deferred debits 106,519 104,978
- ----------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 1,321,396 999,446
- ----------------------------------------------------------------------------------------------------------
Total Assets $ 9,929,133 $ 8,974,684
- ----------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- ----------------------------------------------------------------------------------------------------------
Capitalization
- ----------------------------------------------------------------------------------------------------------
Common stock $ 1,950,392 $ 1,929,515
Unearned ESOP common stock (88,734) (101,560)
Accumulated other comprehensive loss (79,506) (82,769)
Retained earnings 1,395,525 1,343,929
- ----------------------------------------------------------------------------------------------------------
Total Common Stock Equity 3,177,677 3,089,115
- ----------------------------------------------------------------------------------------------------------
Preferred stock - not subject to mandatory redemption 59,334 59,334
Long-term debt, net 3,108,211 3,048,466
- ----------------------------------------------------------------------------------------------------------
Total Capitalization 6,345,222 6,196,915
- ----------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 300,000 -
Accounts payable 164,726 259,217
Payables to affiliated companies 77,022 98,572
Notes payable to affiliated companies 670 -
Taxes accrued 36,055 -
Interest accrued 47,468 58,791
Short-term obligations - 437,750
Current portion of accumulated deferred income taxes 39,607 66,088
Other current liabilities 109,076 93,171
- ----------------------------------------------------------------------------------------------------------
Total Current Liabilities 774,624 1,013,589
- ----------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,150,204 1,179,689
Accumulated deferred investment tax credits 150,657 158,308
Regulatory liabilities 145,976 7,774
Asset retirement obligations 918,441 -
Other liabilities and deferred credits 444,009 418,409
- ----------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,809,287 1,764,180
- ----------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 10)
- ----------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 9,929,133 $ 8,974,684
- ----------------------------------------------------------------------------------------------------------
See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.
32
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS Nine Months Ended
(Unaudited) September 30,
(In thousands) 2003 2002
- -----------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 381,448 $ 310,411
Adjustments to reconcile net income to net cash provided by operating
activities:
Impairment of long-lived assets and investments - 126,262
Depreciation and amortization 486,285 487,454
Deferred income taxes (46,413) (73,640)
Investment tax credit (7,651) (9,285)
Deferred fuel cost (credit) 10,952 (22,596)
Net (increase) decrease in accounts receivable 6,353 (36,966)
Net (increase) decrease in affiliated accounts receivable 31,706 (47,021)
Net increase in inventories 17,302 11,893
Net (increase) decrease in prepayments and other current assets 10,555 (9,173)
Net increase (decrease) in accounts payable (48,393) 27,621
Net increase (decrease) in affiliated accounts payable (36,783) 3,163
Net increase in other current liabilities 96,649 89,923
Other 54,870 63,341
- -----------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 956,880 921,387
- -----------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (347,193) (454,807)
Proceeds from sale of assets and investments 25,671 243,719
Diversified business property additions and acquisitions (358) (11,625)
Nuclear fuel additions (45,657) (56,051)
Contributions to nuclear decommissioning trust (25,656) (25,573)
Other investing activities (1,416) (12,333)
- -----------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (394,609) (316,670)
- -----------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of long-term debt, net 588,291 542,290
Net decrease in short-term obligations (437,750) (8,250)
Net increase in intercompany notes (72,806) (114,638)
Retirement of long-term debt (269,217) (706,747)
Dividends paid to parent (327,629) (300,000)
Dividends paid on preferred stock (2,223) (2,223)
Other 4,214 (22,488)
- -----------------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (517,120) (612,056)
- -----------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 45,151 (7,339)
- -----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of the Period 18,284 21,250
- -----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of the Period $ 63,435 $ 13,911
- -----------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 150,512 $ 169,092
- income taxes (net of refunds) $ 209,736 $ 181,444
Noncash Activities
o In February 2002, PEC transferred the Rowan plant to Progress Ventures,
Inc. and established an intercompany receivable. The property and inventory
transferred totaled approximately $244 million. In April 2002, PEC received
cash proceeds in settlement of the intercompany receivable totaling
approximately $244 million. This amount is reported in proceeds from sale
of assets and investments in the investing activities section.
See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.
33
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
Progress Energy Carolinas, Inc. (PEC) is a public service corporation
primarily engaged in the generation, transmission, distribution and sale of
electricity primarily in portions of North Carolina and South Carolina. 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.
Effective January 1, 2003, Carolina Power & Light Company began doing
business under the assumed name Progress Energy Carolinas, Inc. The legal
name has not changed and there was no restructuring of any kind related to
the name change. The current corporate and business unit structure remains
unchanged.
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 complete financial 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, 2002 and notes thereto included in PEC's Form 10-K/A for the
year ended December 31, 2002.
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, 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 2002 have been reclassified to conform
to the 2003 presentation.
2. 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 Federal
Energy Regulatory Commission (FERC), the North Carolina Utilities
Commission (NCUC), the Public Service Commission of South Carolina (SCPSC),
and the U.S. Nuclear Regulatory Commission (NRC).
The Other segment, whose operations are primarily in the United States, is
made up of other nonregulated business areas including telecommunications
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" and consolidation entities and
eliminations. Included are the telecommunications operations of Caronet,
Inc., which recognized an $87.4 million after-tax asset and investment
impairment in September 2002.
34
The financial information for PEC segments for the three and nine months
ended September 30, 2003 and 2002 is as follows:
(in thousands)
Three Months Ended
September 30, 2003 2002
----------------------------------------- ------------------------------------------
PEC Electric Other Total PEC Electric Other Total
----------------------------------------- ------------------------------------------
Total revenues $ 1,009,889 $ 2,392 $ 1,012,281 $ 1,045,180 $ 4,304 $ 1,049,484
Segment profit (loss) 159,998 (3,165) 156,833 179,308 (85,910) 93,398
Total segment assets $ 9,736,103 $ 193,030 $ 9,929,133 $ 8,785,416 $ 220,667 $ 9,006,083
=====================================================================================================================
(in thousands)
Nine Months Ended September
30, 2003 2002
----------------------------------------- ------------------------------------------
PEC Electric Other Total PEC Electric Other Total
----------------------------------------- ------------------------------------------
Total revenues $ 2,751,599 $ 8,211 $ 2,759,810 $ 2,691,320 $ 11,127 $ 2,702,447
Segment profit (loss) 383,262 (4,037) 379,225 396,530 (88,342) 308,188
Total segment assets $ 9,736,103 $ 193,030 $ 9,929,133 $ 8,785,416 $ 220,667 $ 9,006,083
=====================================================================================================================
3. IMPACT OF NEW ACCOUNTING STANDARDS
SFAS No. 148, "Accounting for Stock-Based Compensation"
For purposes of the pro forma disclosures required by 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. PEC's information related to the pro forma impact on earnings
assuming stock options were expensed for the three and nine months ended
September 30 is as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
(in thousands) 2003 2002 2003 2002
------------ ------------- ----------- ------------
Earnings for common stock, as reported $ 156,833 $ 93,398 $ 379,225 $ 308,188
Deduct: Total stock option expense determined under
fair value method for all awards, net of related
tax effects 2,357 1,018 4,136 2,312
------------ ------------- ----------- ------------
Pro forma earnings for common stock $ 154,476 $ 92,380 $ 375,089 $ 305,876
============ ============= =========== ============
During 2003, the Financial Accounting Standards Board (FASB) has approved
certain decisions in conjunction with its stock-based compensation project.
Some of the key decisions reached by the FASB were that stock-based
compensation should be recognized statement as an expense and that the
expense should be measured as of the grant date at fair value. The FASB
continues to deliberate additional issues in this project and plans to
issue an exposure draft in early 2004.
Derivative Instruments and Hedging Activities
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." The statement amends and
clarifies SFAS No. 133 on accounting for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. The new guidance incorporates decisions made as part of the
Derivatives Implementation Group (DIG) process, as well as decisions
regarding implementation issues raised in relation to the application of
the definition of a derivative. SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003. Interpretations and
implementation issued with regard to SFAS No. 149 continue to evolve. Based
on its analysis and understanding to date, and considering the types of
contracts historically entered into, PEC does not anticipate that this
statement will have a significant impact on its results of operations or
financial position.
In connection with the January 2003 FASB Emerging Issues Task Force (EITF)
meeting, the FASB was requested to reconsider an interpretation of SFAS No.
133. The interpretation, which is contained in the Derivatives
Implementation Group's C11 guidance, relates to the pricing of contracts
that include broad market indices (e.g., CPI). In particular, that guidance
discusses whether the pricing in a contract that contains broad market
indices could qualify as a normal purchase or sale (the normal purchase or
sale term is a defined accounting term, and may not, in all cases, indicate
whether the contract would be "normal" from an operating entity viewpoint).
35
In June 2003, the FASB issued final superseding guidance (DIG Issue C20) on
this issue, which is significantly different from the tentative superseding
guidance that was issued in April 2003. The new guidance is effective
October 1, 2003 for PEC. DIG Issue C20 specifies new pricing-related
criteria for qualifying as a normal purchase or sale, and it requires a
special transition adjustment as of October 1, 2003.
PEC determined that it has one existing "normal" contract that is affected
by this revised guidance. The contract is a purchase power agreement with
Broad River LLC, which is a subsidiary of Calpine Corporation. Pursuant to
the provisions of DIG Issue C20, PEC will record a pre-tax fair value loss
transition adjustment of $37.6 million in the fourth quarter of 2003, which
will be reported as a cumulative effect of a change in accounting
principle. The subject contract meets the DIG Issue C20 criteria for normal
purchase or sale and, therefore, was designated as a normal purchase as of
October 1, 2003. The liability of $37.6 million associated with the fair
value loss will be amortized to earnings over the term of the related
contract.
SFAS No. 150, "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity."
SFAS No. 150 establishes standards for how an issuer classifies and
measures certain financial instruments with characteristics of both
liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances). The financial instruments within the scope of SFAS No. 150
include mandatorily redeemable stock, obligations to repurchase the
issuer's equity shares by transferring assets, and certain obligations to
issue a variable number of shares. SFAS No. 150 is effective immediately
for such instruments entered into or modified after May 31, 2003, and was
effective for previously issued financial instruments within its scope on
July 1, 2003. The adoption of SFAS No. 150 did not have a material impact
on PEC's financial position or results of operations.
FIN No. 46, "Consolidation of Variable Interest Entities"
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
This interpretation provides guidance related to identifying variable
interest entities and determining whether such entities should be
consolidated. FIN No. 46 requires an enterprise to consolidate a variable
interest entity when the enterprise (a) absorbs a majority of the variable
interest entity's expected losses, (b) receives a majority of the entity's
expected residual returns, or both, as a result of ownership, contractual
or other financial interests in the entity. Prior to the effective date of
FIN No. 46, entities were generally consolidated by an enterprise that had
control through ownership of a majority voting interest in the entity. FIN
No. 46 applies immediately to variable interest entities created or
obtained after January 31, 2003. During the first nine months of 2003, PEC
did not participate in the creation of, or obtain a new variable interest
in, any variable interest entity. On October 9, 2003, the FASB issued Staff
Position No. FIN 46-6, which allowed for the optional deferral of the
effective date of FIN No. 46 from July 1, 2003 until December 31, 2003, for
interests held by a public company in variable interest entities created
prior to February 1, 2003. Because PEC expects additional transitional
guidance to be issued, it has deferred its implementation of FIN No. 46
until December 31, 2003.
PEC has investments in 14 limited partnerships accounted for under the
equity method for which it may be the primary beneficiary. These
partnerships invest in and operate low-income housing and historical
renovation properties that qualify for federal and state tax credits. PEC
has not concluded whether it is the primary beneficiary of these
partnerships. These partnerships are partially funded with financing from
third party lenders, which is secured by the assets of the partnerships.
The creditors of the partnerships do not have recourse to PEC. As of
September 30, 2003, the maximum exposure to loss as a result of PEC's
investments for these limited partnerships is approximately $15.5 million.
PEC expects to complete its evaluation of these partnerships under FIN No.
46 during the fourth quarter of 2003. If PEC had consolidated these 14
entities as of September 30, 2003, it would have recorded an increase to
both total assets and total liabilities of approximately $45.8 million.
PEC is also evaluating several other potential variable interest entities
created before January 31, 2003, for which PEC would not be the primary
beneficiary based on the current guidance. These arrangements include
equity investments in approximately 14 limited partnerships, limited
liability corporation and venture capital funds, and two building leases
with special purpose entities. If all of these entities were determined to
be variable interest entities, the aggregate maximum loss exposure as of
September 30, 2003 under these arrangements totals approximately $25.7
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. PEC expects to complete its evaluation of these entities
under FIN No. 46 during the fourth quarter of 2003.
36
EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans"
In May 2003, the EITF reached consensus in EITF Issue No. 03-04 to
specifically address the accounting for certain cash balance pension plans.
The consensus reached in EITF Issue No. 03-04 requires certain cash balance
pension plans to be accounted for as defined benefit plans. For cash
balance plans described in the consensus, the consensus also requires the
use of the traditional unit credit method for purposes of measuring the
benefit obligation and annual cost of benefits earned as opposed to the
projected unit credit method. PEC has historically accounted for its cash
balance plans as defined benefit plans; however, PEC is required to adopt
the measurement provisions of EITF 03-04 at its cash balance plans' next
measurement date of December 31, 2003. Any differences in the measurement
of the obligations as a result of applying the consensus will be reported
as a component of actuarial gain or loss. The effect of this standard on
PEC is dependent on other factors that also affect the determination of
actuarial gains and losses and the subsequent amortization of such gains
and losses. However, PEC does not expect the adoption of EITF 03-04 to have
a material effect on its results of operations or financial position.
4. ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, "Accounting for Asset Retirement Obligations," provides
accounting and disclosure requirements for retirement obligations
associated with long-lived assets and was adopted by the Company effective
January 1, 2003. This statement requires that the present value of
retirement costs for which PEC has a legal obligation be recorded as
liabilities with an equivalent amount added to the asset cost and
depreciated over an appropriate period. The liability is then accreted over
time by applying an interest method of allocation to the liability.
Cumulative accretion and accumulated depreciation were recognized for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect, to the date of adoption of
this statement.
Upon adoption of SFAS No. 143, PEC recorded asset retirement obligations
(AROs) for nuclear decommissioning of irradiated plant totaling $879.7
million. PEC used an expected cash flow approach to measure these
obligations. This amount includes accruals recorded prior to adoption
totaling $491.3 million, which were previously recorded in accumulated
depreciation. The related asset retirement costs, net of accumulated
depreciation, recorded upon adoption totaled $117.3 million. The cumulative
effect of adoption of this statement had no impact on the net income of
PEC, as the effects were offset by the establishment of a regulatory asset
in the amount of $271.1 million, pursuant to SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation." The regulatory asset
represents the cumulative accretion and accumulated depreciation for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect to the date of adoption, less
the amount previously recorded.
Funds set aside in PEC's nuclear decommissioning trust fund for the nuclear
decommissioning liability totaled $480.1 million at September 30, 2003 and
$423.3 million at December 31, 2002. In accordance with SFAS No. 143,
unrealized gains and losses on the nuclear decommissioning trust fund are
now included in regulatory liabilities rather than accumulated
depreciation. The balance of this regulatory liability as of September 30,
2003 was $84.3 million for PEC.
Pro forma net income has not been presented for prior years because the pro
forma application of SFAS No. 143 to prior years would result in pro forma
net income not materially different from the actual amounts reported.
PEC has identified but not recognized AROs related to electric transmission
and distribution and telecommunications assets as the result of easements
over property not owned by PEC. These easements are generally perpetual and
only require retirement action upon abandonment or cessation of use of the
property for the specified purpose. The ARO liability is not estimable for
such easements as PEC intends to utilize these properties indefinitely. In
the event PEC decides to abandon or cease the use of a particular easement,
an ARO liability would be recorded at that time.
PEC has previously recognized removal costs as a component of depreciation
in accordance with regulatory treatment. As of September 30, 2003, the
portion of such costs not representing AROs under SFAS No. 143 was $908.7
million. This amount is included in accumulated depreciation on the
accompanying Consolidated Balance Sheets. PEC has collected amounts for
non-irradiated areas at nuclear facilities, which do not represent asset
retirement obligations. These amounts totaled $65.7 million as of September
30, 2003, which is included in accumulated depreciation on the accompanying
Consolidated Balance Sheets.
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 10 under "Air Quality" contained a prohibition against cost deferrals
unless certain criteria are met, the NCUC initially denied the deferral of
the ongoing effects. During the second quarter of 2003, PEC ceased deferral
of the ongoing effects for the six months ended June 30, 2003 related to
its North Carolina retail jurisdiction. Pre-tax income for the three and
37
six months ended June 30, 2003 increased by approximately $13.6 million,
which represented a decrease in non-ARO cost of removal expense, partially
offset by an increase in decommissioning expense. PEC requested
reconsideration from the NCUC regarding the ongoing effects. During the
third quarter of 2003, the NCUC issued an order allowing the deferral of
the ongoing effects and PEC reversed the second quarter income statement
impact in accordance with the NCUC's decision. Therefore, the ongoing
effects of SFAS No. 143 have no impact on the income of PEC for the nine
months ended September 30, 2003.
On April 8, 2003, the SCPSC approved a joint request by PEC, Duke Energy
and South Carolina Electric and Gas Company for an accounting order to
authorize the deferral of all cumulative and prospective effects related to
the adoption of SFAS No. 143.
5. COMPREHENSIVE INCOME
Comprehensive income for the three and nine months ended September 30, 2003
was $161.5 million and $384.7 million, respectively. Comprehensive income
for the three and nine months ended September 30, 2002 was $89.7 million
and $307.9 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
On April 1, 2003, PEC reduced the size of its existing 364-day credit
facility from $285 million to $165 million. The other terms of this
facility were not changed. On July 30, 2003, PEC renewed its $165 million
364-day credit agreement. PEC's $285 million three-year credit agreement
entered into in 2002 remains in place, for total facilities of $450
million.
On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5%
Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds.
PEC funded the redemption with commercial paper.
On July 14, 2003, PEC announced the redemption of $100 million of First
Mortgage Bonds, 6.875% Series Due August 15, 2023 at 102.84%. The date of
the redemption was August 15, 2003. PEC funded the redemption with
commercial paper.
On September 11, 2003, PEC issued $400 million of First Mortgage Bonds,
5.125% Series, Due September 15, 2013 and $200 million of First Mortgage
Bonds, 6.125% Series, due September 15, 2033. Proceeds from this issuance
were used to reduce the balance of PEC's outstanding commercial paper and
short-term notes payable to affiliated companies, which represent PEC's
borrowings under an internal money pool operated by Progress Energy.
7. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS
PEC 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 March, April, May
and June of 2003, PEC entered into treasury rate locks to hedge its
exposure to interest rates with regard to a future issuance of fixed-rate
debt. These agreements had a computational period of ten years and were
designated as cash flow hedges for accounting purposes. These agreements,
with a total notional amount of $110 million, were terminated
simultaneously with the pricing of the PEC First Mortgage Bonds in
September 2003. The $4.2 million gain on the agreements was deferred and is
being amortized over the life of the bonds as these agreements had been
designated as cash flow hedges for accounting purposes.
The notional amounts of the above contracts 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. PEC only enters into interest rate swap agreements
with banks with credit ratings of single A or better.
8. REGULATORY MATTERS
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 March 28, 2003.
The NCUC approved an increase of $19.6 million by order issued September
25, 2003.
On October 16, 2003, PEC made a filing with the North Carolina Utilities
Commission (NCUC) to seek permission to defer expenses incurred from
Hurricane Isabel and the February 2003 winter storms. As a result of rising
storm costs and the frequency of major storm damage, Progress Energy has
asked the NCUC to allow the company to create a deferred account in which
the company would place expenses incurred as a result of named tropical
storms, hurricanes and significant winter storms. The future amortization
38
of such deferred costs would be includable as allowable costs in base rate
filings. The Company estimates that it would charge $23.5 million in 2003
from Hurricane Isabel and from current year ice storms to the deferred
account, if approved. Any additional major storm activity in 2003 could
cause the amount to increase.
9. OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income, gain on the sale of
investments, impairment of investments and other income and expense items
as discussed below. The components of other, net as shown on the
accompanying Consolidated Statements of Income for the three and nine
months ended September 30, 2003 and 2002 are as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
(in thousands) 2003 2002 2003 2002
-------------- -------------- ------------- -------------
Other income
Net financial trading gain (loss) $ 384 $ (169) $ (1,139) $ (1,598)
Net energy brokered for resale 246 440 516 888
Nonregulated energy and delivery services income 1,632 4,503 5,971 10,069
AFUDC equity (728) 2,367 1,136 6,028
Investment gains - - - 2,960
Other 4,000 (3,099) 9,522 3,098
-------------- -------------- ------------- -------------
Total other income $ 5,534 $ 4,042 $ 16,006 $ 21,445
-------------- -------------- ------------- -------------
Other expense
Nonregulated energy and delivery services expenses $ 1,979 $ 4,528 $ 5,974 $ 9,796
Donations 1,398 1,367 4,043 3,915
Investment losses 558 952 9,202 2,857
Other 4,789 2,746 10,908 8,747
-------------- -------------- ------------- -------------
Total other expense $ 8,724 $ 9,593 $ 30,127 $ 25,315
-------------- -------------- ------------- -------------
Other, net $ (3,190) $ (5,551) $(14,121) $ (3,870)
============== ============== ============= =============
Net financial trading gains and losses represent non-asset-backed trades of
electricity and gas. Net energy brokered for resale represents electricity
purchased for simultaneous sale to a third party. Nonregulated energy and
delivery services include power protection services and mass market
programs (surge protection, appliance services and area light sales) and
delivery, transmission and substation work for other utilities. Investment
losses primarily represent losses on limited partnership investment funds.
10. COMMITMENTS AND CONTINGENCIES
Contingencies existing as of the date of these statements are described
below. No significant changes have occurred since December 31, 2002, with
respect to the commitments discussed in Note 18 of the financial statements
included in PEC's 2002 Annual Report on Form 10-K/A.
Guarantees
In 2003, PEC determined that its external funding levels did not fully meet
the nuclear decommissioning financial assurance levels required by the NRC.
Therefore, PEC obtained parent company guarantees of $276 million to meet
the required levels. As of September 30, 2003, management does not believe
conditions are likely for performance under the agreements discussed
herein.
PEC has a small amount of guarantees outstanding as of September 30, 2003;
however, there have been no significant changes in these amounts since year
end.
Insurance
PEC is insured against public liability for a nuclear incident. 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), each
company would be subject to pro rata assessments for each reactor owned per
occurrence. Effective August 20, 2003, the retroactive premium assessments
39
increased to $100.6 million per reactor from the previous amount of $88.1
million. The total limit available to cover nuclear liability losses
increased as well from $9.6 billion to $10.8 billion. The annual
retroactive premium limit of $10 million per reactor owned did not change.
Contingencies
Claims and uncertainties
a) PEC is subject to federal, state and local regulations addressing
hazardous and solid waste management, air and water quality and other
environmental matters.
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, are participating in investigating and, if necessary,
remediating former MGP sites with several regulatory agencies, including,
but not limited to, the 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 their involvement or potential involvement in
sites, other than MGP sites, that may require investigation and/or
remediation.
There are 9 former MGP sites and 14 other sites or groups of 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 PEC environmental liabilities related to its
involvement with some MGP sites. All eligible expenses related to these are
charged against a specific fund containing these proceeds. As of September
30, 2003, approximately $8.7 million remains in this centralized fund with
a related accrual of $8.7 million recorded for the associated expenses of
environmental issues. As PEC's share of costs for investigating and
remediating these sites become known, the fund is assessed to determine if
additional accruals will be required. PEC does not believe that it can
provide an estimate of the reasonably possible total remediation costs
beyond what remains in the environmental insurance recovery fund. This is
due to the fact that the sites are at different stages: investigation has
not begun at three sites, investigation has begun but remediation cannot be
estimated at five sites and remediation has begun at one site. 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 potentially responsible parties. Once the
environmental insurance recovery fund is depleted, PEC will accrue costs
for the sites to the extent its liability is probable and the costs can be
reasonably estimated. Presently, PEC cannot determine the total costs that
may be incurred in connection with the remediation of all sites.
In September 2003, the Company sold NCNG to Piedmont Natural Gas Company,
Inc. As part of the sales agreement, the Company retained responsibility to
remediate five former NCNG MGP sites to state standards pursuant to an
Administrative Order by consent. These sites are anticipated to have
investigation or remediation costs associated with them. NCNG had
previously accrued approximately $2.2 million for probable and reasonably
estimable remediation costs at these sites. These accruals have been
recorded on an undiscounted basis. At the time of the sale, the liability
for these costs and the related accrual was transferred to a subsidiary of
PEC. PEC does not believe it can provide an estimate of the reasonably
possible total remediation costs beyond the accrual because two of the five
sites have not begun investigation activities. Therefore, PEC cannot
currently determine the total costs that may be incurred in connection with
the investigation and/or remediation of all sites. Based upon current
information, the Company does not expect the future costs at these sites to
be material to the Company's financial condition or results of operations.
PEC has filed claims with its general liability insurance carriers to
recover costs arising out of actual or potential environmental liabilities.
Some claims have settled and others are still pending. While management
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.
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.
40
Air Quality
There has been and may be further proposed federal legislation requiring
reductions in air emissions for nitrogen oxides, sulfur dioxide, carbon
dioxide and mercury. Some of these proposals establish nation-wide 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. Some companies may seek recovery of the
related cost through rate adjustments or similar mechanisms. 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. During the first
quarter of 2003, PEC responded to a supplemental information request from
the EPA. 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 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 the EPA's initiative
or its impact, if any, on the Company.
In 1998, the EPA published a final rule addressing the regional transport
of ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule
requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, to further reduce nitrogen oxide emissions in order to attain a
pre-set state NOx emission levels by May 31, 2004. PEC is currently
installing controls necessary to comply with the rule. Capital expenditures
needed to meet these measures in North and South Carolina could reach
approximately $370 million, which has not been adjusted for inflation.
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. PEC cannot
predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new
eight-hour ozone standard. In October 1999, the District of Columbia
Circuit Court of Appeals ruled against the EPA with regard to the federal
eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the
District of Columbia Circuit Court of Appeals decision. Designation of
areas that do not attain the standard is proceeding, and further litigation
and rulemaking on this and other aspects of the standard are anticipated.
North Carolina adopted the federal eight-hour ozone standard and is
proceeding with the implementation process. North Carolina has promulgated
final regulations, which will require PEC to install nitrogen oxide
controls under the State's eight-hour standard. The costs of those controls
are included in the $370 million cost estimate set forth in the preceding
paragraph. 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.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule as originally promulgated required certain sources
to make reductions in nitrogen oxide emissions by May 1, 2003. The final
rule also includes a set of regulations that affect nitrogen oxide
emissions from sources included in the petitions. The North Carolina
coal-fired electric generating plants are included in these petitions.
Acceptable state plans under the NOx SIP Call can be approved in lieu of
the final rules the EPA approved as part of the Section 126 petitions. PEC,
other utilities, trade organizations and other states participated in
litigation challenging the EPA's action. On May 15, 2001, the District of
Columbia Circuit Court of Appeals ruled in favor of the EPA, which will
require North Carolina to make reductions in nitrogen oxide emissions by
May 1, 2003. However, the Court in its May 15th decision rejected the EPA's
methodology for estimating the future growth factors the EPA used in
calculating the emissions limits for utilities. In August 2001, the Court
granted a request by PEC and other utilities to delay the implementation of
the Section 126 Rule for electric generating units pending resolution by
the EPA of the growth factor issue. The Court's order tolls the three-year
compliance period (originally set to end on May 1, 2003) for electric
generating units as of May 15, 2001. On April 30, 2002, the EPA published a
final rule harmonizing the dates for the Section 126 Rule and the NOx SIP
Call. In addition, the EPA determined in this rule that the future growth
factor estimation methodology was appropriate. The new compliance date for
all affected sources is now May 31, 2004, rather than May 1, 2003. The EPA
has approved North Carolina's NOx SIP Call rule and has formally proposed
to rescind the Section 126 rule. This rulemaking is expected to become
final by early 2004. PEC expects a favorable outcome of this matter.
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and
sulfur dioxide from coal-fired power plants. PEC expects its capital costs
to meet these emission targets will be approximately $813 million by 2013.
PEC currently has approximately 5,100 MW of coal-fired generation in North
Carolina that is affected by this legislation. The legislation requires the
41
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 legislation 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 legislation
allows the utilities to recover from their retail customers the projected
capital costs during the first seven years of the 10-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.
Pursuant to the new law, PEC entered into an agreement with the state of
North Carolina to transfer to the state any future emissions allowances
acquired as a result of compliance with the new law. The new law also
requires the state to undertake a study of mercury and carbon dioxide
emissions in North Carolina. PEC cannot predict the future regulatory
interpretation, implementation or impact of this new law. PEC did not
record any clean air amortization in the third quarter of 2003 and recorded
approximately $54 million of clean air amortization to date in 2003. Clean
air expenditures to date were $16.4 million as of September 30, 2003.
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. The United States has not adopted the Kyoto Protocol;
however, a number of carbon dioxide emissions control proposals have been
advanced in Congress and by the Bush administration. The Bush
administration favors voluntary programs. Reductions in carbon dioxide
emissions to the levels specified by the Kyoto Protocol and some
legislative proposals could be materially adverse to PEC's financials and
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.
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, EPA determined in
2000 that regulation of mercury emissions from coal-fired power plants was
appropriate. Pursuant to a Court Order, the EPA is developing a Maximum
Available Control Technology (MACT) standard, which is expected to become
final in December 2004, with compliance in 2008. Achieving compliance with
the MACT standard could be materially adverse to PEC's financial condition
and results of operations. However, PEC cannot predict the outcome of this
matter.
b) 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 April 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) has 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. PEC is in the process of evaluating whether it should file a
similar action for damages.
On July 9, 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. PEC cannot
predict the outcome of this matter.
42
With certain modifications and additional approval by the NRC, 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
current operating licenses for all of its nuclear generating units.
Subsequent or prior to the expiration of these licenses, or any renewal of
these licenses, dry storage or acquisition of new shipping casks may be
necessary. PEC obtained NRC approval to use additional storage space at the
Harris Plant in December 2000. PEC is currently in the design phase for
adding dry storage capability at the Robinson Plant.
c) On August 21, 2003, PEC was served as a co-defendant in a purported
class action lawsuit styled as Collins v. Duke Energy Corporation, Civil
Action No. 03CP404050, in South Carolina's Circuit Court of Common Pleas
for the Fifth Judicial Circuit. PEC is one of three electric utilities
operating in South Carolina named in the suit. The plaintiffs are seeking
damages for the alleged improper use of electric easements but have not
asserted a dollar amount for their damage claims. The complaint alleges
that the licensing of attachments on electric utility poles, towers and
other structures to non-utility third parties or telecommunication
companies for other than the electric utilities' internal use along the
electric right-of-way constitutes a trespass.
On September 19, 2003, PEC filed a motion to dismiss all counts of the
complaint on substantive and procedural grounds. On October 6, 2003, the
plaintiffs filed a motion to amend their complaint. PEC believes the
amended complaint asserts the same factual allegations as are in the
original complaint and also seeks money damages and injunctive relief.
The court has not yet held any hearings or made any rulings in this case.
PEC intends to vigorously defend itself against the claims asserted by the
plaintiffs. PEC cannot predict the outcome of any future proceedings in
this case.
d) PEC is involved in various litigation matters in the ordinary course of
business, some of which involve claims for substantial amounts. Where
appropriate, accruals have been made in accordance with SFAS No. 5,
"Accounting for Contingencies," to provide for such matters. PEC believes
the final disposition of pending litigation would not have a material
adverse effect on PEC's consolidated results of operations or financial
position.
11. SUBSEQUENT EVENT
On November 3, 2003, Progress Telecom Corporation (PTC), Progress
Telecommunications Corporation (PTC Communications), and Caronet, Inc.
(Caronet), all of which are indirectly wholly-owned subsidiaries of
Progress Energy, agreed to enter into a Contribution Agreement (Agreement)
with EPIK Communications, Inc. (EPIK). EPIK is a wholly-owned subsidiary of
Odyssey Telecorp, Inc. (Odyssey). The Company plans to account for this
transaction as a business combination.
Under terms of the Agreement, on November 4, 2003, PTC was converted into a
limited liability company and renamed Progress Telecom, LLC (PTC LLC). The
Agreement provides that PTC Communications, Caronet and EPIK will
contribute substantially all of their assets and transfer certain
liabilities to PTC LLC in exchange for membership interests in PTC LLC.
Following the contribution of their respective net assets, PTC
Communications will hold a 55 percent membership interest in PTC LLC;
Caronet will hold a 5 percent membership interest; and EPIK will hold a 40
percent membership interest. After the conbtribution of net assets to PTC
LLC, the stock of Caronet will be sold to an affiliate of Odyssey for cash
and Caronet will then become an indirect wholly-owned subsidiary of
Odyssey. Following consummation of the transactions described above, PTC
Communications will hold a 55 percent ownership interest in PTC LLC, and
Odyssey will hold a 45 percent ownership interest in PTC LLC through EPIK
and Caronet. The Company anticipates closing the transaction by the end of
the year; however, the closing of all of these transactions is subject to
certain conditions precedent, including receipt of applicable governmental
and regulatory permits and approvals.
43
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. Please review
"SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" 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 and the timing of maintenance on electric generating units, 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 2002 Form
10-K.
RESULTS OF OPERATIONS
In this section, earnings and the factors affecting earnings for the three and
nine months ended September 30, 2003 as compared to the same periods in 2002 are
discussed. The discussion begins with a general overview, then separately
discusses earnings by business segment.
OVERVIEW
The net income and basic earnings per share of Progress Energy, Inc. (Progress
Energy or the Company) were $319.0 million or $1.34 per share and $151.9 million
or $0.71 per share for the three months ended September 30, 2003 and 2002,
respectively. The Company's net income and basic earnings per share were $679.9
million or $2.88 per share and $405.1 million or $1.89 per share for the nine
months ended September 30, 2003 and 2002, respectively.
Net income for the three and nine months ended September 30, 2003 as compared to
the same period in 2002 increased primarily due to the inclusion in 2002 of a
$224.8 million impairment of assets in the telecommunications business. Absent
the impact of the impairment, net income decreased $57.7 million for the three
month period and increased $50.0 million for the nine month period. The decrease
quarter over quarter was primarily due to milder weather in 2003, higher
operations and maintenance (O&M) costs at the utilities, the loss from
discontinued operations of NCNG, and the negative impact of the change in the
fair value of contingent value obligations. These decreases were partially
offset by increased sales of natural gas and higher synthetic fuel earnings. The
increase for the nine month period was largely attributable to the impact of
levelizing the estimated effective tax rate throughout the year and continued
customer growth and usage, partially offset by the impact of the change in the
fair value of contingent value obligations, higher O&M costs at the utilities,
the net impact of the 2002 Florida rate settlement, and milder weather in 2003.
The Company's segments contributed segment profits or losses for the three and
nine months ended September 30, 2003 and 2002 as follows:
- ------------------------------------------------------------------------------------------------
(in millions) Three Months Ended Nine Months Ended
September 30, September 30,
- ------------------------------------------------------------------------------------------------
Business Segment 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------
PEC Electric $160.0 $179.3 $383.3 $396.5
PEF 114.3 123.8 246.5 258.3
Fuels 79.8 52.1 160.1 140.5
CCO 12.7 20.9 23.6 25.5
Rail 0.7 0.7 (0.5) 3.0
Other (3.6) (225.9) (2.6) (239.3)
--------------------------------------------------------
Total Segment Profit 363.9 150.9 810.4 584.5
Corporate (26.2) 6.2 (125.5) (181.4)
--------------------------------------------------------
Income from continuing operations 337.7 157.1 684.8 403.1
NCNG discontinued operations (18.7) (5.2) (4.9) 2.0
--------------------------------------------------------
Net income $319.0 $151.9 $679.9 $405.1
- ------------------------------------------------------------------------------------------------
(Totals may not foot due to rounding.)
44
The significant operating segments and their primary operations are:
o PEC Electric - engaged in the generation, transmission, distribution and
sale of electricity primarily in portions of North Carolina and South
Carolina (differences between the PEC Electric segment and the PEC
consolidated financial information relate to other non-electric operations
and elimination entries);
o PEF - engaged in the generation, transmission, distribution and sale of
electricity primarily in portions of Florida;
o Fuels - engaged in natural gas production, coal mining and synthetic fuels
production;
o Competitive Commercial Operations (CCO) - engaged in nonregulated
generation operations and energy marketing;
o Progress Rail Services (Rail) - engaged in various rail and railcar related
services; and
o Other Businesses (Other) - engaged in other nonregulated business areas,
primarily telecommunications and energy services operations.
In prior years' reporting, CCO and Fuels were components of the Progress
Ventures segment. With the expansion of the nonregulated energy generation
facilities and the current management structure, CCO is now a distinct operating
segment. In addition to the operating segments listed above, the Company has
other corporate activities that include holding company operations, service
company operations and eliminations. These corporate activities have been
included in the Other segment in the past. Additionally, earnings from wholesale
customers on the regulated plants have previously been reported in both the
regulated utilities' results and the results of Progress Ventures. With the
realignment of the reportable business segments, this activity is now included
in the regulated utilities' results only. For comparative purposes, the 2002
results have been restated to align with the new business segments.
In 2002, the operations of NCNG, previously reported in the Other segment, were
reclassified to discontinued operations and therefore were not included in the
results from continuing operations during the periods reported.
In March of 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 impact on the affiliates
is included in the segment discussion that follows. 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.
In accordance with an SEC order under PUHCA, effective in the second quarter of
2002, tax benefits not related to acquisition interest expense that were
previously held unallocated at the holding company must be allocated to the
profitable subsidiaries. The allocation has no impact on the Company's
consolidated tax expense or net income. The impacts on the business segments are
included in the discussions below and generally decrease the income tax expense
for the regulated utilities, while increasing income tax expense for the holding
company. The 2002 reallocation included impacts from 2001.
REGULATED ELECTRIC SEGMENTS
The operating results of both regulated electric utilities are primarily
influenced by customer demand for electricity, the ability to control costs and
regulatory return on equity. Demand for electricity is based on the number of
customers and their usage, with usage largely impacted by weather. In addition,
the current economic conditions in the service territories may impact the demand
for electricity.
Effective January 1, 2003, the Company implemented SFAS No. 143, "Accounting for
Asset Retirement Obligations," which requires that the present value of
retirement costs for which the Company has a legal obligation be recorded as
liabilities with an equivalent amount added to the asset cost and depreciated
over an appropriate period. The liability is then accreted over time by applying
an interest method of allocation to the liability. Both electric utilities
recorded asset retirement obligations (AROs) in the first quarter of 2003. At
September 30, 2003, PEC Electric's AROs totaled $918.4 million and PEF's AROs
totaled $315.1 million.
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 enacted in North Carolina
contained a prohibition against cost deferrals unless certain criteria are met,
45
the NCUC initially denied the deferral of the ongoing effects. During the second
quarter of 2003, PEC ceased deferral of the ongoing effects related to its North
Carolina retail jurisdiction. Pre-tax income for the six months ended June 30,
2003 increased by approximately $13.6 million, which represented a decrease in
non-ARO cost of removal expense, partially offset by an increase in
decommissioning expense. This second quarter earnings impact was reversed in the
third quarter when the NCUC issued an order allowing the deferral of the ongoing
effects of SFAS No. 143.
On April 8, 2003, the SCPSC approved a joint request by PEC Electric, Duke
Energy and South Carolina Electric and Gas Company for an accounting order to
authorize the deferral of all cumulative and prospective effects related to the
adoption of SFAS No. 143.
On January 23, 2003, the Staff of the FPSC issued a notice of proposed rule
development to adopt provisions relating to accounting for asset retirement
obligations under SFAS No. 143. Accompanying the notice was a draft rule
presented by the staff which adopts the provisions of SFAS No. 143 along with
the requirement to record the difference between amounts prescribed by the FPSC
and those used in the application of SFAS No. 143 as regulatory assets or
regulatory liabilities, which was accepted by all parties. Therefore, the
adoption of the statement had no impact on the income of PEF due to the
establishment of a regulatory liability pursuant to SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation." A final order was approved in the
third quarter of 2003.
PROGRESS ENERGY CAROLINAS ELECTRIC
PEC Electric contributed segment profits of $160.0 million and $179.3 million in
the three months ended September 30, 2003 and 2002, respectively, and $383.3
million and $396.5 million for the nine months ended September 30, 2003 and
2002, respectively. The decrease in the three months ended September 30, 2003 as
compared to the same period in 2002 is primarily due to milder weather
conditions which suppressed sales across most customer classes and higher storm
and other O&M costs, partially offset by higher customer growth and usage and
the effect of the tax benefit reallocation from Corporate. The decrease in the
nine months ended September 30, 2003 as compared to the same period in 2002 is
primarily due to milder weather, O&M costs related to the ice storms in the
first quarter of 2003 and Hurricane Isabel in the third quarter of 2003 and
higher benefit costs. These unfavorable impacts are offset partially by strong
wholesale sales, retail growth and usage and lower interest charges.
On October 16, 2003, PEC made a filing with the North Carolina Utilities
Commission (NCUC) to seek permission to defer expenses incurred from Hurricane
Isabel and the February 2003 winter storms. As a result of rising storm costs
and the frequency of major storm damage, Progress Energy has asked the NCUC to
allow the company to create a deferred account in which the company would place
expenses incurred as a result of named tropical storms, hurricanes and
significant winter storms. The future amortization of such deferred costs would
be includable as allowable costs in base rate filings. The Company estimates
that it would charge $23.5 million in 2003 from Hurricane Isabel and from
current year ice storms to the deferred account, if approved. Any additional
major storm activity in 2003 could cause the amount to increase.
PEC's electric revenues for the three and nine months ended September 30, 2003
and 2002 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 2003 Change % Change 2002 2003 Change % Change 2002
- ------------------------------------------------------------------------------------------------------------------
Residential $ 385.5 $ 0.9 0.2% $ 384.6 $ 990.1 $ 37.7 4.0% $ 952.3
Commercial 250.0 5.4 2.2% 244.6 649.7 19.0 3.0% 630.8
Industrial 178.9 (4.1) (2.2%) 183.0 481.5 (7.4) (1.5%) 488.9
Governmental 23.9 0.5 2.1% 23.4 60.3 1.4 2.4% 58.9
---------------------- ------------------------------- ----------
Total retail revenues 838.3 2.7 0.3% 835.6 2,181.6 50.7 2.4% 2,130.9
Wholesale 174.3 (19.6) (10.1%) 193.9 537.9 44.7 9.1% 493.2
Unbilled (24.4) (18.6) - (5.8) (31.9) (40.4) - 8.5
Miscellaneous 21.7 0.2 0.9% 21.5 64.0 5.3 9.0% 58.7
---------------------- ------------------------------- ----------
Total electric revenues $ 1,009.9 $ (35.3) (3.4%) $ 1,045.2 $ 2,751.6 $ 60.3 2.2% $ 2,691.3
- ------------------------------------------------------------------------------------------------------------------
46
PEC's electric energy sales for the three and nine months ended September 30,
2003 and 2002 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 2003 Change % Change 2002 2003 Change % Change 2002
- --------------------------------------- ----------- ------------ -------------------- ---------- ------------ ----------
Residential 4,424 (61) (1.4%) 4,485 12,063 331 2.8% 11,732
Commercial 3,687 12 0.3% 3,675 9,616 124 1.3% 9,492
Industrial 3,414 (155) (4.3%) 3,569 9,616 (301) (3.0%) 9,917
Governmental 420 (5) (1.2%) 425 1,081 (7) (0.6%) 1,088
----------- ----------- -------------------- ---------- ----------
Total retail energy sales 11,945 (209) (1.7%) 12,154 32,376 147 0.5% 32,229
Wholesale 3,950 (580) (12.8%) 4,530 11,870 514 4.5% 11,356
Unbilled (465) (247) - (218) (549) (576) - 27
----------- ----------- -------------------- ---------- ----------
Total mWh sales 15,430 (1,036) (6.3%) 16,466 43,697 85 0.2% 43,612
- --------------------------------------- ----------- ------------ -------------------- ---------- ------------ ----------
Three months ended September 30, 2003 compared to three months ended September
30, 2002
Milder weather in 2003 accounted for a retail revenue decline of approximately
$25 million, excluding fuel revenues which are primarily offset by fuel expenses
and thus have no earnings impact, with the average cooling degree days declining
16% when comparing the three months ended September 30, 2003 to the same period
in 2002. Retail customer growth and usage, excluding the impact of weather and
the effect of fuel costs, accounted for $4.8 million of additional revenue in
the three months ended September 30, 2003 as compared to the same period in
2002. PEC Electric had approximately 1,319,000 retail customers at September 30,
2003, which represents an increase of 22,000 from September 30, 2002. The
wholesale revenues decline is primarily attributable to a milder summer in 2003
as compared to 2002.
O&M costs were $205.7 million for the three months ended September 30, 2003,
which represents a $22.0 million increase compared to the same period in 2002.
Included in the 2003 spending is $13.5 million associated with Hurricane Isabel
restoration efforts. Rising benefit costs also negatively impacted O&M in 2003.
Income tax expense was $86.5 million for the three months ended September 30,
2003, a $23.5 million decrease compared to the same period in 2002. This
variance is due to an $8.0 million higher tax benefit reallocation in the three
months ended September 30, 2003 compared to the same period in 2002 and by the
tax impact of lower pre-tax income.
Nine months ended September 30, 2003 compared to nine months ended September 30,
2002
Mild weather in North and South Carolina during the late spring and summer
months of 2003 more than offset the favorable impact of colder weather
experienced in the first quarter of 2003, with a total unfavorable revenue
impact in the retail markets from weather of approximately $38.1 million
excluding the effect of fuel costs. Favorable wholesale revenues and retail
customer growth and usage, excluding the effect of weather, partially offset the
unfavorable weather impact. The wholesale favorability is primarily attributable
to weather-related sales of energy to the Northeastern United States markets
during the first half of 2003.
O&M costs increased $34.8 million when compared to $571.0 million for the nine
months ended September 30, 2002, primarily due to $10.9 million of ice storm
costs in the first quarter of 2003, $13.6 million of hurricane restoration costs
in September 2003, $21.5 million of costs associated with a planned nuclear
outage in 2003 and continued increases in benefit costs. These increases were
partially offset by a decrease in operation and maintenance expense of $15.9
million related to the previously discussed reallocation of prior years' Service
Company costs, as required by the SEC.
Depreciation and amortization expense increased $10.4 million compared to
depreciation and amortization expense of $405.4 million for the nine months
ended September 30, 2002. This increase results from $53.6 million of clean air
amortization in 2003 and $15.7 million of depreciation on additional assets
placed into service. These increases are partially offset by a $54.8 million
reduction in accelerated nuclear amortization. The clean air and accelerated
nuclear amortization programs allow flexibility in the amount amortized each
year. Both programs are currently meeting the appropriate amortization
requirements. The Company currently expects to recognize approximately $90
million of clean air amortization in 2003.
Other income and expense was $4.6 million of expense for the nine months ended
September 30, 2003 compared to $3.8 million of income during the nine months
ended September 30, 2002. The primary driver of the unfavorability was $10.0
million of losses on limited partnership investment funds recorded during the
nine months ended September 30, 2003.
Interest expense was $143.3 million for the nine months ended September 30,
2003, which represents a decrease of $18.3 million. This decrease was due to
both a decrease in average outstanding debt and slightly lower interest rates.
47
Income tax expense was $196.5 million for the nine months ended September 30,
2003 as compared to $190.0 million for the nine months ended September 30, 2002.
This variance is due to the tax impact of changes in pre-tax income and a $9.2
million lower tax benefit reallocation for the nine months ended September 30,
2003 compared to the same period in 2002.
PROGRESS ENERGY FLORIDA
PEF contributed segment profits of $114.3 million and $123.8 million in the
three months ended September 30, 2003 and 2002, respectively, and $246.5 million
and $258.3 million in the nine months ended September 30, 2003 and 2002,
respectively. The decrease in profits for the three months ended September 30,
2003 when compared to 2002 is primarily due to increased pension expense and an
unfavorable impact of the tax benefit reallocation from Corporate, partially
offset by favorable interest charges. Weather had a slight negative impact, but
was offset by customer growth and usage. The decrease in profits when comparing
the nine months periods results primarily from the net impact of the 2002 rate
settlement and higher pension expense, partially offset by a slightly favorable
weather impact, improved customer growth and usage and favorable interest
charges.
In March 2002, PEF settled a rate case which provided for a one-time retroactive
rate refund, decreased future retail rates by 9.25% (effective May 1, 2002),
provided for lower depreciation and amortization, provided for increases in
certain service revenue rates and provided for revenue sharing with the retail
customers if certain revenue thresholds were met. The impacts of the settlement
agreement are included below.
PEF's electric revenues for the three and nine months ended September 30, 2003
and 2002 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 2003 Change % Change 2002 2003 Change % Change 2002
- ------------------------------------------------------------------------------------------------------------------
Residential $ 501.8 $32.0 6.8% $469.8 $ 1,300.3 $55.6 4.5% $ 1,244.7
Commercial 214.3 14.8 7.4% 199.5 556.7 7.0 1.3% 549.7
Industrial 56.9 4.3 8.2% 52.6 160.4 2.7 1.7% 157.7
Governmental 49.3 4.2 9.3% 45.1 133.1 4.6 3.6% 128.5
Retroactive rate refund - - - - - 35.0 - (35.0)
Revenue sharing/rate
refund 4.1 4.1 - - (23.9) (23.9) - -
---------------------- ------------------------------- ----------
Total retail revenues 826.4 59.4 7.7% 767.0 2,126.6 81.0 4.0% 2,045.6
Wholesale 51.8 (6.1) (10.5%) 57.9 172.9 6.8 4.1% 166.1
Unbilled (3.9) (12.3) - 8.4 2.7 (17.5) - 20.2
Miscellaneous 29.8 (0.5) (1.7%) 30.3 96.9 12.8 15.2% 84.1
---------------------- ------------------------------- ----------
Total electric revenues $ 904.1 $40.5 4.7% $863.6 $ 2,399.1 $83.1 3.6% $ 2,316.0
- ------------------------------------------------------------------------------------------------------------------
PEF's electric energy sales for the three and nine ended September 30, 2003 and
2002 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 2003 Change % Change 2002 2003 Change % Change 2002
- ------------------------------------------------------------------------------------------------------------------
Residential 5,739 236 4.3% 5,503 14,996 918 6.5% 14,078
Commercial 3,334 127 4.0% 3,207 8,727 208 2.4% 8,519
Industrial 1,028 45 4.6% 983 2,951 92 3.2% 2,859
Governmental 805 46 6.1% 759 2,204 109 5.2% 2,095
---------------------- ------------------------------- ----------
Total retail energy sakes 10,906 454 4.3% 10,452 28,878 1,327 4.8% 27,551
sales
Wholesale 1,006 (14) (1.4%) 1,020 3,172 196 6.6% 2,976
Unbilled (112) (326) - 214 441 (248) - 689
---------------------- ------------------------------- ----------
Total mWh sales 11,800 114 1.0% 11,686 32,491 1,275 4.1% 31,216
- ------------------------------------------------------------------------------------------------------------------
Three months ended September 30, 2003 compared to three months ended September
30, 2002
Retail revenues, excluding fuel revenues of $370.0 million and $332.1 million
for the three months ended September 30, 2003 and 2002, respectively, increased
$21.5 million as a result of favorable customer growth, partially offset by
lower customer usage. Fuel revenues, which are primarily offset by fuel expenses
and thus have no earnings impact, increased compared to the prior year primarily
due to increased generation and higher fuel prices.
48
Operations and maintenance (O&M) costs increased $16.7 million, when compared to
the $146.8 million incurred during the three months ended September 30, 2002.
This increase is primarily related to increased pension expense and other
benefit costs.
Depreciation and amortization increased $8.7 million when compared to the $73.4
million incurred during the three months ended September 30, 2002 primarily due
to additional depreciable assets placed in service.
Interest charges decreased $17.7 million when compared to $25.8 million incurred
in the three months ended September 2002 primarily due to the reversal of a
regulatory liability for accrued interest related to previously resolved tax
matters.
Income tax expense increased $6.2 million when compared to $56.0 million
incurred during three months ended September 30, 2002 primarily from the $10.1
million lower tax benefit reallocation, in accordance with an SEC order,
partially offset by lower pretax income.
Nine months ended September 30, 2003 compared to nine months ended September 30,
2002
Retail revenues, excluding fuel revenues of $945.3 million and $898.9 million
for the nine months ending September 30, 2003 and 2002, respectively, increased
primarily due to the impact of the $35.0 million retroactive rate refund that
was recognized in 2002 as part of the settlement agreement, continued customer
growth and usage and favorable weather. Partially offsetting these gains were
the impact of the 9.25% rate reduction, the 2002 revenue sharing refund which
was resolved in 2003, and the 2003 revenue sharing accrual, all of which are
discussed previously. The average number of customers for the nine months ended
September 30, 2003 increased by approximately 35,200 or 2.4% in 2003 as compared
to the same period in 2002.
O&M costs increased $24.8 million when compared to the $433.4 million incurred
during the nine months ended September 30, 2002 primarily due to increased
pension expenses and other benefit costs.
Depreciation and amortization increased $23.0 million when compared to the
$218.0 million incurred during the nine months ended September 30, 2002
primarily due to increased assets placed into service, which accounted for $12.1
million of the increase, and the amortization of a purchased power contract.
This purchased power was completely amortized as of September 30, 2003. The
amortization of the purchased power contract is recovered through a cost
recovery clause and therefore has no impact on earnings.
Interest charges decreased $19.6 million when compared to the $82.1 million
incurred during the nine months ended September 30, 2002 primarily due to the
reversal of a regulatory liability for accrued interest related to previously
resolved tax matters.
Income tax expense decreased $7.9 million when compared to the $135.0 million
incurred during the nine months ended September 30, 2002. Fluctuations in income
tax expense result from the tax benefit reallocation and lower pretax income.
DIVERSIFIED BUSINESSES
The Company's diversified businesses consist of the Fuels segment, the CCO
segment, the Rail segment, Other segment. These businesses are explained in more
detail below.
FUELS
The Fuels segment's operations include synthetic fuels production, natural gas
production, coal extraction and terminals operations. Fuels' results for the
three and nine months ended September 30, 2003 as compared to the same periods
in 2002 were impacted most significantly by the increase in gas production and,
for the nine months then ended, by the timing of synthetic fuels production.
The following summarizes Fuels' segment profits for the three and nine
months ended September 30, 2003 and 2002.
- -----------------------------------------------------------------------------------------------------------
Three Months Ended September 30, Nine Months Ended September 30,
- -----------------------------------------------------------------------------------------------------------
(in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------
Synthetic fuel operations $58.7 $48.7 $125.9 $131.8
Gas production 11.1 2.5 25.8 3.7
Coal fuel and other operations 10.0 0.9 8.4 5.0
---------------------------------------------------------------------
Segment Profits $79.8 $52.1 $160.1 $140.5
- -----------------------------------------------------------------------------------------------------------
49
Synthetic Fuel Operations
The synthetic fuels operations generated net profits of $58.7 million and $48.7
million in the three months ended September 30, 2003 and 2002, respectively, and
$125.9 million and $131.8 million in the nine months ended September 30, 2003
and 2002, 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. In late June 2003, the IRS
announced that field auditors had raised questions associated with synthetic
fuel manufactured at the Colona facility regarding the scientific validity of
test procedures and results used to verify a significant chemical change, which
is a requirement of the synthetic fuel program. In October 2003, the National
Office of the IRS informed the Company it had rejected challenges regarding
whether the synthetic fuels produced at the Colona facility was the result of a
significant chemical change. After an extensive review of the process and
analysis involved, the National Office concluded that the experts, who test the
synthetic fuel for chemical change, use reasonable scientific methods to reach
their conclusions. See Note 15 to the Progress Energy Notes to the Consolidated
Interim Financial Statements.
The following summarizes the synthetic fuel operations for the three and nine
months ended September 30, 2003 and 2002.
- -----------------------------------------------------------------------------------------------------------
Three Months Ended September 30, Nine Months Ended September 30,
- -----------------------------------------------------------------------------------------------------------
(in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------
Tons produced 3.0 3.0 7.9 9.4
-----------------------------------------------------------------
Operating losses, excluding tax credits $ (34.0) $ (30.0) $(97.5) $ (122.0)
Tax credits generated 92.7 78.7 223.4 253.8
-----------------------------------------------------------------
Net profits $ 58.7 $ 48.7 $125.9 $ 131.8
- -----------------------------------------------------------------------------------------------------------
The change in synthetic fuel production between the nine months ended September
30, 2003 and the nine months ended September 30, 2002 is primarily due to an
internal change in the synthetic fuel production pattern for 2003. The Company
anticipates total synthetic fuel production of approximately 12 million tons for
2003, which is comparable to 2002 production levels. The 2003 tax credits also
include a $12.7 million favorable true-up from 2002.
Gas Production
Gas operations generated profits of $11.1 million and $2.5 million in the three
months ended September 30, 2003 and 2002, respectively, and $25.8 million and
$3.7 million in the nine months ended September 30, 2003 and 2002, respectively.
The increase in production resulting from the acquisitions of Westchester Gas in
2002 and North Texas Gas in the first quarter of 2003 drove increased revenue
and earnings in 2003 as compared to 2002. In October 2003, the Company completed
the sale of certain gas producing properties owned by Mesa Hydrocarbons, LLC for
net proceeds of approximately $97 million. See Note 3B of the Progress Energy
Notes to the Consolidated Interim Financial Statements for a further discussion
of this sale. The following summarizes the gas production and revenues for the
three and nine months ended September 30, 2003 and 2002 by production facility.
- --------------------------------------------------------------------------------------------------------
Gas Production Three Months Ended September 30, Nine Months Ended September 30,
- -------------------------------------------------------------------------------------------------------
(in millions of cubic feet) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------
Mesa 1.3 1.6 4.4 4.2
Westchester Gas 3.3 1.9 9.1 2.4
North Texas Gas 3.0 - 4.6 -
------------------------------------------------------------------
Total gas production 7.6 3.5 18.1 6.6
- ------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------
Gas Sales Three Months Ended September 30, Nine Months Ended September 30,
- ------------------------------------------------------------------------------------------------------
(in millions) 2003 2002 2003 2002
- ------------------------------------------------------------------------------------------------------
Mesa $ 4.0 $ 3.7 $ 12.8 $10.3
Westchester Gas 16.4 5.8 45.0 7.4
North Texas Gas 14.0 - 24.4 -
Other 1.8 1.6 4.4 2.4
------------------------------------------------------------------
Total gas sales $36.2 $11.1 $ 86.6 $20.1
- ------------------------------------------------------------------------------------------------------
50
COMPETiTIVE COMMERCIAL OPERATIONS
CCO generates and sells electricity to the wholesale market through nonregulated
plants. These operations also include marketing activities.
- ----------------------------------------------------------------------
Three Months Ended Nine Months Ended
(in millions) September 30, September 30
- ----------------------------------------------------------------------
2003 2002 2003 2002
--------------------------------------------------
Total Sales $ 66.7 $ 44.3 $ 137.5 $ 77.3
Segment Profits $ 12.7 $ 20.9 $ 23.6 $ 25.5
- ----------------------------------------------------------------------
Generating capacity increased from 1,554 megawatts at September 30, 2002 to
3,100 megawatts at September 30, 2003, with the Effingham, Rowan Phase 2 and
Washington plants being placed into service during 2003.
The increase in revenue for the three and nine months ended September 30, 2003
when compared to the same periods in 2002 is primarily due to increased
contracted capacity on newly constructed plants and energy revenue from a new
full-requirements power supply agreement. The increase during the nine months
ended September 30, 2003 in revenue and earnings is also related to a tolling
agreement termination payment received in the first quarter of 2003. The revenue
increases related to higher volumes were partially offset by higher depreciation
costs of $8.6 million and $12.2 million for the three and nine months ended
September 30, 2003, when compared to the same periods in 2002, related to the
additional facilities and by increases in interest charges, other fixed costs
and costs allocated from the Service Company. Additionally CCO capitalized
interest of $2.5 million and $10.5 million in the three and nine months ended
September 30, 2003, compared to $12.7 million and $14.5 million for the same
periods in 2002.
In the second quarter of 2003, PVI acquired from Williams Energy Marketing and
Trading a full-requirements power supply agreement with Jackson Electric
Membership Corp. (Jackson) in Georgia for $188 million, which resulted in
additional revenues of $10.8 million and $13.4 million for the three and nine
months ended September 30, 2003 when compared to the same periods in 2002.
The Company has contracts for 68%, 85% and 50% of planned production capacity
for 2003 through 2005, respectively. The 2005 decline results from the
expiration of four tolling contracts. The Company continues to pursue
opportunities with both current customers and other potential customers.
The 466-megawatt Rowan combined cycle unit and the 600-megawatt Washington
combustion turbine facilities were completed and placed into service in June
2003. The Washington plant has a tolling agreement with LG&E Power Trading &
Marketing through December 31, 2004. The 480-megawatt Effingham combined cycle
facility was placed into service in August 2003 and completes CCO's nonregulated
build-out with a total capacity of 3,100 megawatts.
RAIL
Rail's operations include railcar and locomotive repair, trackwork, rail parts
reconditioning and sales, scrap metal recycling, railcar leasing and other rail
related services. The Company intends to sell the assets of Railcar Ltd., a
leasing subsidiary, in 2003 and has classified these assets as assets held for
sale at September 30, 2003. See Note 3C of the Progress Energy Notes to the
Consolidated Interim Financial Statements.
Progress Rail contributed segment profit of $0.7 million for both the three
months ended September 30, 2003 and 2002, respectively, and a segment loss of
$0.5 million and segment profit of $3.0 million for the for the nine months
ended September 30, 2003 and 2002, respectively. As a result of an SEC order,
Rail incurred additional Service Company allocations during the three and nine
months ended September 30, 2003, respectively, when compared to the same periods
in 2002. These increased costs were partially offset by improvements in the
recycling business and reduced operating costs.
An SEC order approving the merger of FPC required the Company to divest Rail by
November 30, 2003. The Company is pursuing alternatives, but does not expect to
find the right divestiture opportunity by that date. Therefore, the Company
sought, and in October 2003, was granted approval of, a three year extension
from the SEC.
51
OTHER BUSINESSES SEGMENT
Progress Energy's Other segment primarily includes the operations of SRS and
Telecom. 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. Telecom provides broadband
capacity services, dark fiber and wireless services in Florida and the eastern
United States.
The Other segment contributed segment losses of $3.6 million and $225.9 million
in the three months ended September 30, 2003 and 2002, respectively, and $2.6
million and $239.3 million in the nine months ended September 30, 2003 and 2002,
respectively. Included in the 2002 segment losses is an asset impairment and
other charges in the telecommunications business of $224.8 million.
CORPORATE SERVICES
Corporate Services includes the operations of the Holding Company, the Service
Company, and consolidation entities, as summarized below.
- -----------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
- -----------------------------------------------------------------------------------------
Income (expense) in millions 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------
Other interest expense $ (77.5) $ (66.6) $ (221.8) $ (213.3)
Contingent value obligations (3.9) 9.4 (3.9) 22.2
Tax levelization 35.4 39.1 40.8 (40.5)
Tax reallocation (9.1) (4.1) (27.9) (37.1)
Other income taxes 31.4 24.0 93.5 90.3
Other income (expenses) (2.5) 4.4 (6.2) (3.0)
----------------------------------------------------
Segment profit (loss) $ (26.2) $ 6.2 $ (125.5) $ (181.4)
- -----------------------------------------------------------------------------------------
Progress Energy issued 98.6 million contingent value obligations (CVOs) in
connection with the 2000 FPC acquisition. 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, 2003 and 2002,
the CVOs had fair market values of approximately $17.8 million and $13.8
million, respectively. Progress Energy recorded an unrealized loss of $3.9
million and unrealized gain of $9.4 million for the three months ended September
30, 2003 and 2002, respectively, to record the changes in fair value of the
CVOs, which had average unit prices of $0.18 and $0.20 at September 30, 2003 and
2002, respectively. A $3.9 million unrealized loss and a $22.2 unrealized gain
was recorded for the for the nine months ended September 30, 2003 and 2002,
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 $35.4 million and $39.1 million for the three
months ended September 30, 2003 and 2002, respectively, in order to maintain an
effective tax rate consistent with the estimated annual rate. Income tax expense
was decreased by $40.8 million and increased $40.5 million for the nine months
ended September 30, 2003 and 2002, 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.
DISCONTINUED OPERATIONS
In 2002, the Company approved the sale of NCNG and the Company's equity
investment in ENCNG to Piedmont Natural Gas Company, Inc. As a result of this
action, the operating results of NCNG were reclassified to discontinued
operations for all reportable periods. A $29.4 million after-tax estimated loss
on the sale of the assets was recognized in the fourth quarter of 2002. The sale
closed on September 30, 2003, at which time an additional after-tax loss of $8.9
million was recognized. Net proceeds of approximately $450 million from the sale
of NCNG and ENCNG were used to reduce outstanding short-term debt.
LIQUIDITY AND CAPITAL RESOURCES
Progress Energy, Inc.
Cash provided by operating activities increased $143 million for the nine months
ended September 30, 2003, when compared to the corresponding period in the prior
year. The increase in cash from operating activities for the 2003 period is due
to reduced working capital needs at PVI and Progress Fuels, which offset lower
cash from operations at the utility operations. The lower working capital
requirements were due largely to reduced inventory levels at Progress Fuels.
52
Net cash used in investing activities decreased $644 million for the nine months
ended September 30, 2003, when compared to the corresponding period in the prior
year. The decrease in cash used in investing activities is primarily due to the
receipt of approximately $450 million from the sale of NCNG and ENCNG in
September which was used to reduce debt. In addition, lower capital spending at
PVI, which acquired generating assets from LG&E in February 2002 for
approximately $350 million, contributed to the decrease.
During the first nine months of 2003, $476 million was spent in diversified
business property additions. This amount includes the acquisition of the natural
gas reserves in February 2003 for $148 million. In addition to the $476 million
spent on diversified business property additions, PVI also purchased a wholesale
energy supply contract for approximately $190 million.
The increase in operating cash flow and lower capital expenditures resulted in
an increase of $787 million of net cash flow before common dividend payments and
other financing activity for the nine month period ending September 30, 2003
compared with the corresponding period for the prior year.
On February 21, 2003, PEF issued $425 million of First Mortgage Bonds, 4.80%
Series, Due March 1, 2013 and $225 million of First Mortgage Bonds, 5.90%
Series, Due March 1, 2033. Proceeds from this issuance were used to repay the
balance of its outstanding commercial paper, to refinance its secured and
unsecured indebtedness, including $70 million of PEF's First Mortgage Bonds
6.125% Series, Due March 1, 2003, which were retired on March 1, 2003, and to
redeem on March 24, 2003, the $150 million aggregate outstanding balance of its
8% First Mortgage Bonds due 2022 at 103.75% of the principal amount of such
bonds.
In March 2003, Progress Genco Ventures, LLC (Genco), a wholly-owned subsidiary
of PVI, terminated its $50 million working capital credit facility. A related
construction facility initially provided for Genco to draw up to $260 million.
The amount outstanding under this facility is $241 million as of September 30,
2003. During the three months ended September 30, 2003 Genco determined it did
not need to make any additional draws under this facility.
On April 1, 2003, PEF entered into a new $200 million 364-day credit agreement
and a new $200 million three-year credit agreement, replacing its prior credit
facilities (which had been a $90 million 364-day facility and a $200 million
five-year facility). The new PEF credit facilities contain a defined maximum
total debt to total capital ratio of 65%; as of September 30, 2003 the
calculated ratio, as defined, was 51.3%. The new credit facilities also contain
a requirement that the ratio of EDITDA, as defined in the facilities, to
interest expense to be at least 3 to 1; as of September 30, 2003 the calculated
ratio, as defined, was 8.1 to 1.
Also on April 1, 2003, PEC reduced the size of its existing 364-day credit
facility from $285 million to $165 million. The other terms of this facility
were not changed. On July 30, 2003, PEC renewed its $165 million 364-day credit
agreement PEC's $285 million three-year credit agreement entered into in July
2002 remains in place, for total facilities of $450 million.
On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5% Series,
Due March 1, 2023 at 103.22% of the principal amount of such bonds. PEC funded
the redemption with commercial paper.
On July 1, 2003, $110 million of PEF's First Mortgage Bonds, 6.0% Series, Due
July 1, 2003 and $35 million of PEF's medium-term notes, 6.62% Series, matured.
PEF funded the redemption with commercial paper.
On August 15, 2003, PEC redeemed $100 million of First Mortgage Bonds, 6.875%
Series Due August 15, 2023 at 102.84%.
On August 27, 2003, Standard & Poor's (S&P) credit rating agency announced that
it had lowered its corporate credit rating on Progress Energy Inc., PEC, PEF,
and Florida Progress to BBB from BBB+. The outlook of the ratings was changed
from negative to stable. These changes have not had a material impact on the
companies' access to capital or their financial results.
On September 11, 2003, PEC issued $400 million of First Mortgage Bonds, 5.125%
Series, Due September 15, 2013 and $200 million of First Mortgage Bonds, 6.125%
Series, Due September 15, 2033. Proceeds from this issuance were used to reduce
the balance of PEC's outstanding commercial paper, and short-term notes payable
to affiliated companies, which notes represent PEC's borrowings under an
internal money pool operated by Progress Energy.
In October 2003, the Company received net proceeds of approximately $97 million
for the sale of its Mesa gas properties located in Colorado.
53
On October 31, 2003, PEF announced the redemption of $100 million of its First
Mortgage Bonds, 7% Series Due 2023 at 103.19% of the principal amount of such
bonds. PEF intends to redeem the bonds on December 1, 2003 with commercial paper
proceeds.
For the three months ended September 30, 2003, the Company issued approximately
2.7 million shares representing approximately $112 million in proceeds from its
Investor Plus Stock Purchase Plan and its employee benefit plans. For the nine
months ended September 30, 2003, the Company has issued approximately 6.9
million shares through these plans, resulting in approximately $284 million of
cash proceeds.
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.
Future Commitments
As of September 30, 2003, the current portion of long-term debt of $868 million
includes $500 million of Progress Energy's 6.55% senior unsecured notes due
March 1, 2004. The Company expects to have sufficient commercial paper capacity
to retire this issue due to the application of net proceeds from the sale of
NCNG in September 2003 to reduce commercial paper balances. The current portion
of long-term debt also includes $300 million of secured debt issued by PEC.
These amounts are expected to be refinanced or retired through commercial paper,
capital market transactions and with internally-generated funds.
As of September 30, 2003, Progress Energy's guarantees issued on behalf of third
parties were approximately $26.4 million.
OTHER MATTERS
PEF Rate Case Settlement
On March 27, 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 on April 23, 2002. The Agreement provides
that PEF will operate under a Revenue Sharing Incentive Plan (the Plan) through
2005 and thereafter until terminated by the FPSC.
The Plan provides that all retail base revenues between an established threshold
and cap will be shared on a 2/3 - 1/3, customer/shareholder basis. All retail
base rate revenues above the retail base rate revenue caps established for each
year will be refunded 100% to retail customers on an annual basis. The retail
base revenue cap for 2003 is $1.393 billion and will increase $37 million each
year thereafter. As of December 31, 2002, $4.7 million was accrued and was
refunded to customers in March 2003. On February 24, 2003, the parties to the
Agreement filed a motion seeking an order from the FPSC to enforce the
Agreement. In this motion, the parties disputed PEF's calculation of retail
revenue subject to refund and contended that the refund should have been
approximately $23 million. On July 9, 2003, the FPSC ruled that PEF must provide
an additional $18.4 million to its retail customers related to the 2002 revenue
sharing calculation. PEF recorded this refund in the second quarter of 2003 as a
charge against electric operating revenue and refunded this amount by October
31, 2003. For the nine months ended September 30, 2003, PEF has recorded an
additional accrual of $5.4 million related to estimated 2003 revenue sharing.
Synthetic Fuels 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. Any synthetic fuel tax credit amounts not utilized are carried
forward indefinitely. 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 $1.121 billion, of which $489.1 million have been used and $631.9
million are being carried forward as of September 30, 2003. The current Section
29 tax credit program expires at the end of 2007.
54
One synthetic fuel entity, Colona Synfuel Limited Partnership, L.L.L.P.
(Colona), from which the Company (and FPC prior to its acquisition by the
Company) has been allocated approximately $286.6 million in tax credits to date,
is being audited by the IRS. The audit of Colona was expected. The Company is
audited regularly in the normal course of business, as are most similarly
situated companies.
In September 2002, all of the Company's majority-owned synthetic fuel entities,
including Colona, were accepted into the IRS Prefiling 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 June 2003, the Company was informed that IRS field auditors had raised
questions regarding the chemical change associated with coal-based synthetic
fuel manufactured at its Colona facility and the testing process by which the
chemical change is verified. (The questions arose in connection with the
Company's participation in the PFA program.) The chemical change and the
associated testing process were described as part of the PLR request for Colona.
Based on that application, the IRS ruled in Colona's PLR that the synthetic fuel
produced at Colona undergoes a significant chemical change and thus qualifies
for tax credits under Section 29.
In October 2003, the National Office of the IRS informed the Company that it had
rejected the IRS field auditors' challenges regarding whether the synthetic fuel
produced at the Company's Colona facility was the result of a significant
chemical change. The National office had concluded that the experts, engaged by
Colona who test the synthetic fuel for chemical change, use reasonable
scientific methods to reach their conclusions. Accordingly, the National Office
will not take any adverse action on the PLR that has been issued for the Colona
facility.
A written decision memorializing the National Office's conclusions should be
available within the next two months. At that time, the IRS field auditors will
have the right to ask for reconsideration of the National Office's decision.
Although this ruling applies only to the Colona facility, the Company believes
that the National Office's reasoning should be equally applicable to the other
Progress Energy facilities, given that the Company applies essentially the same
chemical process and uses the same independent laboratories to confirm chemical
change in the synthetic fuel manufactured at each of its other facilities.
However, the IRS has not yet formally informed the Company as to its position on
the Company's other facilities.
Although this is a significant event, the audits of the Colona facility and the
Company's other facilities are not yet completed. Progress Energy continues to
believe that it operates its facilities in conformity with its PLRs and Section
29. Accordingly, the Company has no current plans to alter its synthetic fuel
production schedule as a result of these matters.
In addition, the Company has retained an advisor to assist in selling an
interest in one or more synthetic fuel entities. The Company is pursuing the
sale of a portion of its synthetic fuel production capacity that is
underutilized due to limits on the amount of credits that can be generated and
utilized by the Company. The Company would expect to retain an ownership
interest and to operate any sold facility for a management fee. The final
outcome and timing of the Company's efforts to sell interests in synthetic fuel
facilities is uncertain and while the Company cannot predict the outcome of this
matter, the outcome is not expected to have a material effect on the
consolidated financial position, cash flows or results of operations.
Nuclear Matters
On August 9, 2002, the Nuclear Regulatory Commission (NRC) issued an additional
bulletin dealing with head leakage due to cracks near the control rod nozzles.
The NRC asked licensees to commit to high inspection standards to ensure the
more susceptible plants have no cracks. The Robinson Plant is in this category
and had a refueling outage in October 2002. The Company completed a series of
examinations in October 2002 of the entire reactor pressure vessel head and
found no indications of control rod drive mechanism penetration leakage and no
corrosion of the head itself. During the outage, a boric acid leakage walkdown
of the reactor coolant pressure boundary was also completed and no corrosion was
found.
The Company currently plans to re-inspect the Robinson Plant reactor head during
its next refueling outage in 2004 and replace the head in 2005. The Harris Plant
is ranked in the lowest susceptibility classification. During the Harris Plant's
2003 outage, the Company completed a series of examinations of the entire
reactor pressure vessel head and found no degradation or indication of leakage.
55
In October 2001, at PEF's Crystal River Plant (CR3), one nozzle was found to
have a crack and was repaired; however, no degradation of the reactor vessel
head was identified. The Company replaced the vessel head at CR3 during its
regularly scheduled refueling outage completed on November 5, 2003, when the
unit was returned to service.
In January 2003, the NRC issued a final order with regard to access control.
This order requires the Company to enhance its current access control program by
January 7, 2004. The Company expects that it will be in full compliance with the
order by the established deadline.
In February 2003, the NRC issued Order EA-03-009, requiring specific inspections
of the reactor pressure vessel head and associated penetration nozzles at
pressurized water reactors (PWRs). The Company responded to the Order, stating
that it intends to comply with the provisions of the Order. No adverse impact is
anticipated.
In April 2003, the STP Nuclear Operating Company, an unaffiliated entity,
notified the NRC of a potential leak indication on the bottom head of the
reactor vessel of one of its units. On August 21, 2003 the NRC issued Bulletin
2003-02 requesting PWR licensees to address inspection plans for reactor
pressure vessel lower head penetrations. The Company intends to comply with the
provisions of the order.
The NRC continues to issue additional orders designed to increase security at
nuclear facilities. In April 2003, one of the orders issued by the NRC imposes
revisions to the Design Basis Threat and requires power plants to implement
additional protective actions to protect against sabotage by terrorists and
other adversaries. The Company expects that it will be in full compliance with
the order by the established deadline. 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
Four cities, with a total of approximately 31,000 customers, have litigation
pending against PEF in various circuit courts in Florida. As discussed below,
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. Five circuit courts 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 cities to determine the value of PEF's
electric distribution system within the cities through arbitration. Arbitration
in one of the cases (the City of Casselberry) was held in August 2002. Following
arbitration, the parties entered settlement discussions, and on July 28, 2003
the City approved a settlement agreement and a new, 30-year franchise agreement
with PEF. The settlement resolves all pending litigation with that city. A
second arbitration (with the 13,000-customer City of Winter Park) was completed
in February 2003. That arbitration panel issued an award on May 29, 2003 setting
the value of PEF's distribution system within the City of Winter Park at
approximately $31.5 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 $10.7 million in stranded
costs. On September 9, 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. The City has not yet definitively decided
whether it will acquire the system, but has indicated that it will seek
wholesale power supply bids and bids to operate and maintain the distribution
system. At this time, whether and when there will be further proceedings
regarding the City of Winter Park cannot be determined. A third arbitration
(with the 2,500-customer Town of Belleair) was completed on June 16, 2003. On
September 2, 2003, the arbitration panel issued an award in that case setting
the value of the electric distribution system within the Town at approximately
$6.3 million. The panel further required the Town to pay to PEF its requested
$690,000 in separation and reintegration costs and approximately $1.5 million in
stranded costs. The Town has not yet decided whether it will attempt to acquire
the system. At this time, whether and when there will be further proceedings
regarding the Town of Belleair cannot be determined. A fourth arbitration (with
the 13,000-customer City of Apopka) has been scheduled for January 2004.
Arbitration in the remaining city's litigation (the 1,500-customer City of
Edgewood) has not yet been scheduled.
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 on August 27, 2003. Subsequently, the Court requested
briefing from the parties in the other appeal. Briefing likely will be completed
in the second appeal in early November. The Company cannot predict the outcome
of these matters at this time.
56
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 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 nine months ended September 30, 2003 and 2002 are not
material to PEC's consolidated financial statements.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities increased $35 million for the nine months
ended September 30, 2003, when compared to the corresponding period in the prior
year. The increase was caused primarily by changes in working capital.
Cash used in investing activities increased approximately $78 million for the
nine months ended September 30, 2003, when compared to the corresponding period
in the prior year. Excluding the $244 million in cash proceeds received in April
2002 for the sale of generating assets to Progress Ventures, cash used in
investing activities decreased $166 million primarily due to lower construction
spending. During the first nine months of 2003, $418.5 million was spent on
PEC's construction program, nuclear fuel additions and contributions to its
nuclear decommissioning fund. This amount was approximately $118 million less
than the corresponding period last year. The decrease was due to lower
construction expenditures associated with generation assets transferred to PVI
during 2002.
As of September 30, 2003, PEC's liquidity, contractual cash obligations and
other commercial commitments have not changed materially from what was reported
in the 2002 Annual Report on Form 10-K/A.
On April 1, 2003, PEC reduced the size of its existing 364-day credit facility
from $285 million to $165 million. The other terms of this facility were not
changed. On July 30, 2003, PEC renewed its $165 million 364-day credit
agreement. PEC's $285 million three-year credit agreement entered into in 2002
remains in place, for total facilities of $450 million.
On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5% Series,
Due March 1, 2023 at 103.22% of the principal amount of such bonds. PEC funded
the redemption with commercial paper.
On July 14, 2003, PEC announced the redemption of $100 million of First Mortgage
Bonds, 6.875% Series Due August 15, 2023 at 102.84%. The date of the redemption
was August 15, 2003 and the redemption was funded by PEC with commercial paper.
On September 11, 2003, PEC issued $400 million of First Mortgage Bonds, 5.125%
Series, Due September 15, 2013 and $200 million of First Mortgage Bonds, 6.125%
Series, Due September 15, 2033.
The current portion of long-term debt includes $300 million of secured debt
issued by PEC. The current portion of long-term debt is expected to be
refinanced or retired through commercial paper, capital market transactions and
internally generated of funds.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Progress Energy, Inc.
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.
The Company's exposure to return on marketable securities for the
decommissioning trust funds has not changed materially since December 31, 2002.
The Company's exposure to market value risk with respect to the CVOs has also
not changed materially since December 31, 2002.
57
In March, April, May and June of 2003, PEC entered into treasury rate locks to
hedge its exposure to interest rates with regard to a future issuance of debt.
These agreements had a computational period of ten years and were designated as
cash flow hedges for accounting purposes. The agreements have a total notional
amount of $110 million. The agreements were terminated simultaneously with the
pricing of the PEC First Mortgage Bonds in September 2003. The $4.2 million gain
on the agreements was deferred and is being amortized over the life of the bonds
as these agreements had been designated as cash flow hedges for accounting
purposes.
The exposure to changes in interest rates from the Company's fixed rate and
variable rate long-term debt at September 30, 2003 has changed from December 31,
2002. The total fixed rate long-term debt at September 30, 2003 was $9.3
billion, with an average interest rate of 6.60% and fair market value of $10.3
billion. The total variable rate long-term debt at September 30, 2003, was $1.1
billion, with an average interest rate of 1.29% and fair market value of $1.1
billion.
The exposure to changes in interest rates from the Company's commercial paper
and FPC mandatorily redeemable securities of trust at September 30, 2003, was
not materially different than at December 31, 2002.
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 return on
marketable securities for the decommission trust funds has not changed
materially since December 31, 2002.
In March, April, May and June of 2003, PEC entered into treasury rate locks to
hedge its exposure to interest rates with regard to a future issuance of debt.
These agreements had a computational period of ten years and were designated as
cash flow hedges for accounting purposes. The agreements, with a total notional
amount of $110 million, were terminated simultaneously with the pricing of the
PEC First Mortgage Bonds in September 2003. The $4.2 million gain on the
agreements was deferred and is being amortized over the life of the bonds as
these agreements had been designated as cash flow hedges for accounting
purposes.
The exposure to changes in interest rates from the PEC's fixed rate long-term
debt, variable rate long-term debt and commercial paper at September 30, 2003
was not materially different than at December 31, 2002.
58
Item 4. Controls and Procedures
Progress Energy, Inc.
Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, Progress
Energy carried out an evaluation, with the participation of Progress Energy's
management, including Progress Energy's Chairman and Chief Executive Officer,
and Chief Financial Officer, of the effectiveness of Progress Energy's
disclosure controls and procedures (as defined under Rule 13a-15(e) 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 Chairman 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 in Progress Energy's internal control over financial
reporting during the quarter ended September 30, 2003 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 Rule 13a-15(b) under the Securities Exchange Act of 1934, PEC
carried out an evaluation, with the participation of PEC's management, including
PEC's Chairman and Chief Executive Officer, and Chief Financial Officer, of the
effectiveness of PEC's disclosure controls and procedures (as defined under Rule
13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period
covered by this report. Based upon that evaluation, PEC's Chairman 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 in PEC's
internal control over financial reporting during the quarter ended September 30,
2003 that has materially affected, or is reasonably likely to materially affect,
PEC's internal control over financial reporting.
59
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 10
to the PEC's Consolidated Interim Financial Statements.
1. Strategic Resource Solutions Corp. ("SRS") v. San Francisco Unified School
District, et al., Sacramento Superior Court, Case No. 02AS033114
In November of 2001, 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. On March 4,
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 has asserted defenses
to the District's claims. SRS has amended its claims and asserted new claims
against the District and other parties, including a former SRS employee and a
former District employee.
On March 13, 2003, the City Attorney's office announced the filing of new claims
by the City Attorney and the District 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 City Attorney's
announcement states that the City and the District seek "more than $300 million
in damages and penalties."
The Company, SRS, and Progress Energy Solutions, Inc. all have filed responsive
pleadings denying the allegations, and the discovery process is underway.
On October 2, 2003, the District filed a motion for leave to amend its
cross-complaint to add PEC as an additional defendant and the parties have
stipulated that the pleadings may be so amended. PEC will file a responsive
pleading denying the allegations.
The Company cannot predict the outcome of this matter, but the Company believes
that it and its subsidiaries have good defenses to all claims asserted by the
District and other claimants.
2. Collins v. Duke Energy Corporation, Civil Action No. 03CP404050
On August 21, 2003, PEC was served as a co-defendant in a purported class action
lawsuit styled as Collins v. Duke Energy Corporation, Civil Action No.
03CP404050, in South Carolina's Circuit Court of Common Pleas for the Fifth
Judicial Circuit. PEC is one of three electric utilities operating in South
Carolina named in the suit. The plaintiffs are seeking damages for the alleged
improper use of electric easements but have not asserted a dollar amount for
their damage claims. The complaint alleges that the licensing of attachments on
electric utility poles, towers and other structures to non-utility third parties
or telecommunication companies for other than the electric utilities' internal
use along the electric right-of-way constitutes a trespass.
On September 19, 2003, PEC filed a motion to dismiss all counts of the complaint
on substantive and procedural grounds. On October 6, 2003, the plaintiffs filed
a motion to amend their complaint. PEC believes the amended complaint asserts
the same factual allegations as are in the original complaint and also seeks
money damages and injunctive relief.
The court has not yet held any hearings or made any rulings in this case. PEC
intends to vigorously defend itself against the claims asserted by the
plaintiffs. PEC cannot predict the outcome of any future proceedings in this
case.
60
Item 2. Changes in Securities and Use of Proceeds
RESTRICTED STOCK AWARDS:
(a) Securities Delivered. On September 16, 2003 and October 1, 2003, 4,800 and
8,000 restricted shares, respectively, of the Company's Common Shares were
granted to certain key employees pursuant to the terms of the Company's
2002 Equity Incentive Plan (Plan), which was approved by the Company's
shareholders on May 8, 2002. Section 9 of the Plan provides for the
granting of Restricted Stock by the Organization and Compensation Committee
of the Company's Board of Directors, (the Committee) to key employees of
the Company, including its Affiliates or any successor, and to outside
directors of the Company. The Common Shares delivered pursuant to the Plan
were acquired in market transactions directly for the accounts of the
recipients and do not represent newly issued shares of the Company.
(b) Underwriters and Other Purchasers. No underwriters were used in connection
with the delivery of Common Shares described above. The Common Shares were
delivered to certain key employees of the Company. The Plan defines "key
employee" as an officer or other employee of the Company who is selected
for participation in the Plan.
(c) Consideration. The Common Shares were delivered to provide an incentive to
the employee recipients to exert their utmost efforts on the Company's
behalf and thus enhance the Company's performance while aligning the
employee's interest with those of the Company's shareholders.
(d) Exemption from Registration Claimed. The Common Shares described in this
Item were delivered on the basis of an exemption from registration under
Section 4(2) of the Securities Act of 1933. Receipt of the Common Shares
required no investment decision on the part of the recipients. All award
decisions were made by the Committee, which consists entirely of
non-employee directors.
61
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit Progress Progress Energy
Number Description Energy, Inc. Carolinas, Inc.
10(i) Progress Energy, Inc. $250,000,000 364-Day Amended and X
Restated Credit Agreement dated as of November 10, 2003.
31(a) Certifications pursuant to Section 302 of the Sarbanes- X X
Oxley Act of 2002 - Chairman and Chief Executive Officer
31(b) Certifications pursuant to Section 302 of the Sarbanes- X X
Oxley Act of 2002 - Executive Vice President and Chief
Financial Officer
32(a) Certifications pursuant to Section 906 of the Sarbanes- X X
Oxley Act of 2002 - Chairman and Chief Executive Officer
32(b) Certifications pursuant to Section 906 of the Sarbanes- X X
Oxley Act of 2002 - Executive Vice President and Chief
Financial Officer
(b) Reports filed or furnished on Form 8-K since the beginning of the quarter:
Progress Energy, Inc.
Financial
Item Statements
Reported Included Date of Event Date Filed or Furnished
9, 12 Yes July 23, 2003 July 23, 2003
7, 9 Yes August 29, 2003 August 29, 2003
5 No August 29, 2003 September 2, 2003
9, 12 Yes October 22, 2003 October 22, 2003
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
Financial
Item Statements
Reported Included Date of Event Date Filed or Furnished
9, 12 Yes July 23, 2003 July 23, 2003
5 No August 29, 2003 September 2, 2003
5, 7 Yes September 8, 2003 September 8, 2003
5, 7 No September 8, 2003 September 12, 2003
9, 12 Yes October 22, 2003 October 22, 2003
62
SIGNATURES
Pursuant to 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
Date: November 12, 2003 (Registrants)
By: /s/ Peter M. Scott III
------------------------------
Peter M. Scott III
Executive Vice President and
Chief Financial Officer
By: /s/ Robert H. Bazemore, Jr.
------------------------------
Robert H. Bazemore, Jr.
Vice President and Controller
Chief Accounting Officer
63