7
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 June 30, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
------- -----
Exact name of registrants as specified in their charters, state of
Commission incorporation, address of principal executive offices, and telephone I.R.S. Employer
File Number 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 July 31, 2004, each
registrant had the following shares of common stock outstanding:
Registrant Description Shares
---------- ----------- ------
Progress Energy Common Stock (Without Par Value) 246,793,015
PEC Common Stock (Without Par Value) 159,608,055 (all of which
were held by Progress Energy, Inc.)
PROGRESS ENERGY, INC. AND PROGRESS ENERGY CAROLINAS, INC.
FORM 10-Q - For the Quarter Ended June 30, 2004
Glossary of Terms
Safe Harbor For Forward-Looking Statements
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Interim Financial Statements:
Progress Energy, Inc.
--------------------------------------------------------------
Unaudited Consolidated Statements of Income
Unaudited Consolidated Balance Sheets
Unaudited Consolidated Statements of Cash Flows
Notes to Consolidated Interim Financial Statements
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
---------------------------------------------------------------
Unaudited Consolidated Statements of Income
Unaudited Consolidated Balance Sheets
Unaudited Consolidated Statements of Cash Flows
Notes to Consolidated Interim Financial Statements
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities
Item 4. Submission of Matters to a Vote of Security Holders
Item 5. Other Information
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
the Act Medicare Prescription Drug, Improvement and Modernization Act of 2003
AFUDC Allowance for funds used during construction
the Agreement Stipulation and Settlement Agreement
Bcf Billion cubic feet
CCO Competitive Commercial Operations business segment
Colona Colona Synfuel Limited Partnership, LLLP
the Company or Progress Progress Energy, Inc. and subsidiaries
Energy
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
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
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
Fuels Fuels business segment
Genco Progress Genco Ventures, LLC
Jackson Jackson County EMC
MACT Maximum Available Control Technology
Mesa Mesa Hydrocarbons, LLC
MGP Manufactured gas plant
NCNG North Carolina Natural Gas Corporation
NCUC North Carolina Utilities Commission
NOx Nitrogen oxide
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
Progress Rail Progress Rail Services Corporation
PTC LLC Progress Telecom LLC
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.
PWR Pressurized water reactor
Rail Services or Rail Rail Services business segment
RTO Regional Transmission Organization
3
SCPSC Public Service Commission of South Carolina
Section 29 Section 29 of the Internal Revenue Code
Service Company Progress Energy Service Company, LLC
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"
SMD NOPR Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue
Discrimination through Open Access Transmission and Standard Market Design
SO2 Sulfur dioxide
SRS Strategic Resource Solutions Corp.
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-headings "Liquidity and
Capital Resources" and "Other Matters" about the effects of new environmental
regulations, nuclear decommissioning costs and the effect of electric utility
industry restructuring.
Any forward-looking statement speaks only as of the date on which such statement
is made, and neither Progress Energy, Inc. (Progress Energy or the Company) nor
Progress Energy Carolinas, Inc. (PEC) undertakes any obligation to update any
forward-looking statement or statements to reflect events or circumstances after
the date on which such statement is made.
Examples of factors that you should consider with respect to any forward-looking
statements made throughout this document include, but are not limited to, the
following: the impact of fluid and complex government laws and regulations,
including those relating to the environment; 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 Progress
Energy, Inc. and its subsidiaries' commercial and industrial customers; the
ability of the Company's subsidiaries to pay upstream dividends or distributions
to it; the impact on the facilities and the businesses of the Company from a
terrorist attack; the inherent risks associated with the operation of nuclear
facilities, including environmental, health, regulatory and financial risks; the
ability to successfully access capital markets on favorable terms; the impact
that increases in leverage may have on the Company; the ability of the Company
to maintain its current credit ratings; the impact of derivative contracts used
in the normal course of business by the Company; investment performance of
pension and benefit plans and the ability to control costs; the availability and
use of Internal Revenue Code Section 29 (Section 29) tax credits by synthetic
fuel producers and the Company's continued ability to use Section 29 tax credits
related to its coal and synthetic fuel businesses; the impact to our financial
condition and performance in the event it is determined the Company is not
entitled to previously taken Section 29 tax credits; the Company's ability to
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; the outcome of any ongoing or future
litigation or similar disputes and the impact of any such outcome or related
settlements; and unanticipated changes in operating expenses and capital
expenditures. Many of these risks similarly impact the Company's subsidiaries.
These and other risk factors are detailed from time to time in the Progress
Energy and PEC United States Securities and Exchange Commission (SEC) reports.
Many, but not all of the factors that may impact actual results are discussed in
the Risk Factors sections of Progress Energy's and PEC's annual report on Form
10-K for the year ended December 31, 2003, which were filed with the SEC on
March 12, 2004. These reports should be carefully read. 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
June 30, 2004
UNAUDITED CONSOLIDATED STATEMENTS of INCOME
Three Months Ended Six Months Ended
June 30 June 30
- ----------------------------------------------------------------------------------------------------------
(in millions except per share data) 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------
Operating Revenues
Utility $ 1,721 $ 1,583 $ 3,406 $ 3,237
Diversified business 704 467 1,270 1,000
- ----------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,425 2,050 4,676 4,237
- ----------------------------------------------------------------------------------------------------------
Operating Expenses
Utility
Fuel used in electric generation 468 394 961 805
Purchased power 219 210 402 413
Operation and maintenance 372 364 735 699
Depreciation and amortization 207 224 409 444
Taxes other than on income 109 94 214 197
Diversified business
Cost of sales 656 416 1,177 891
Depreciation and amortization 46 36 91 69
Other 45 38 88 88
- ----------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,122 1,776 4,077 3,606
- ----------------------------------------------------------------------------------------------------------
Operating Income 303 274 599 631
- ----------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 4 3 7 6
Other, net - (9) (25) (15)
- ----------------------------------------------------------------------------------------------------------
Total Other Income (Expense) 4 (6) (18) (9)
- ----------------------------------------------------------------------------------------------------------
Interest Charges
Net interest charges 160 159 326 315
Allowance for borrowed funds used during construction (2) (2) (3) (5)
- ----------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 158 157 323 310
- ----------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax and 149 111 258 312
Cumulative Effect of Change in Accounting Principle
Income Tax Benefit (4) (43) (3) (49)
- ----------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Cumulative Effect of 153 154 261 361
Change in Accounting Principle
Discontinued Operations, Net of Tax 1 3 1 14
- ----------------------------------------------------------------------------------------------------------
Income before Cumulative Effect of Change in Accounting 154 157 262 375
Principle
Cumulative Effect of Change in Accounting Principle, Net of
Tax - - - 1
- ----------------------------------------------------------------------------------------------------------
Net Income $ 154 $ 157 $ 262 $ 376
- ----------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 242 236 242 235
- ----------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
Income from Continuing Operations before Cumulative
Effect of Change in Accounting Principle $ 0.63 $ 0.65 $ 1.08 $ 1.54
Discontinued Operations, Net of Tax - 0.01 - 0.06
Net Income $ 0.63 $ 0.66 $ 1.08 $ 1.60
- ----------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share
Income from Continuing Operations before Cumulative
Effect of Change in Accounting Principle $ 0.63 $ 0.65 $ 1.08 $ 1.53
Discontinued Operations, Net of Tax - 0.01 - 0.06
Net Income $ 0.63 $ 0.66 $ 1.08 $ 1.59
- ----------------------------------------------------------------------------------------------------------
Dividends Declared per Common Share $ 0.575 $ 0.560 $ 1.150 $ 1.120
- ----------------------------------------------------------------------------------------------------------
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
6
PROGRESS ENERGY, INC.
UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions) June 30 December 31
ASSETS 2004 2003
- -------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 21,991 $ 21,675
Accumulated depreciation (8,240) (8,077)
Utility plant in service, net 13,751 13,598
Held for future use 13 13
Construction work in progress 643 634
Nuclear fuel, net of amortization 218 228
- -------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 14,625 14,473
- -------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 78 273
Accounts receivable 854 798
Unbilled accounts receivable 245 217
Inventory 775 795
Deferred fuel cost 304 317
Prepayments and other current assets 352 375
- -------------------------------------------------------------------------------------------------------
Total Current Assets 2,608 2,775
- -------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 645 612
Nuclear decommissioning trust funds 978 938
Diversified business property, net 2,197 2,158
Miscellaneous other property and investments 458 464
Goodwill 3,730 3,726
Prepaid pension costs 449 462
Intangibles, net 306 327
Other assets and deferred debits 239 253
- -------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 9,002 8,940
- -------------------------------------------------------------------------------------------------------
Total Assets $ 26,235 $ 26,188
- -------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- -------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, 500 million shares authorized,
247 and 246 million shares issued and outstanding, respectively $ 5,339 $ 5,270
Unearned restricted shares (17) (17)
Unearned ESOP shares (76) (89)
Accumulated other comprehensive loss (56) (50)
Retained earnings 2,313 2,330
- -------------------------------------------------------------------------------------------------------
Total Common Stock Equity 7,503 7,444
- -------------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries-Not Subject to Mandatory Redemption 93 93
Long-Term Debt, Affiliate 309 309
Long-Term Debt , Net 9,282 9,625
- -------------------------------------------------------------------------------------------------------
Total Capitalization 17,187 17,471
- -------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 343 868
Accounts payable 684 643
Interest accrued 189 209
Dividends declared 141 140
Short-term obligations 628 4
Customer deposits 172 167
Other current liabilities 836 580
- -------------------------------------------------------------------------------------------------------
Total Current Liabilities 2,993 2,611
- -------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 525 737
Accumulated deferred investment tax credits 184 190
Regulatory liabilities 3,053 2,977
Asset retirement obligations 1,306 1,271
Other liabilities and deferred credits 987 931
- -------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 6,055 6,106
- -------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 12)
- -------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 26,235 $ 26,188
- -------------------------------------------------------------------------------------------------------
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
7
PROGRESS ENERGY, INC.
UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
Six Months Ended June 30
(in millions) 2004 2003
- --------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 262 $ 376
Adjustments to reconcile net income to net cash provided by operating
activities:
Income from discontinued operations (1) (14)
Cumulative effect of change in accounting principle - (1)
Depreciation and amortization 557 572
Deferred income taxes (210) (118)
Investment tax credit (6) (8)
Deferred fuel cost (credit) 13 (94)
Cash provided (used) by changes in operating assets and liabilities:
Accounts receivable (101) (80)
Inventories 13 31
Prepayments and other current assets (53) 15
Accounts payable 72 (5)
Income taxes, net 207 105
Other current liabilities 47 35
Other 115 93
- --------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 915 907
- --------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions (483) (541)
Diversified business property additions (122) (367)
Nuclear fuel additions (47) (84)
Contributions to nuclear decommissioning trust (18) (18)
Investments in non-utility activities (7) (8)
Acquisition of intangibles - (191)
Proceeds from sales of investments and assets 92 1
Net decrease in restricted cash 5 17
Other (11) (4)
- --------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (591) (1,195)
- --------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock 58 172
Purchase of restricted shares (7) (7)
Issuance of long-term debt 1 655
Net increase in short-term indebtedness 624 163
Net decrease in cash provided by checks drawn in excess of bank balances (58) (44)
Retirement of long-term debt (865) (392)
Dividends paid on common stock (280) (268)
Other 8 (5)
- --------------------------------------------------------------------------------------------------------
Net Cash (Used in) Provided by Financing Activities (519) 274
- --------------------------------------------------------------------------------------------------------
Cash Used in Discontinued Operations - (1)
- --------------------------------------------------------------------------------------------------------
Net Decrease in Cash and Cash Equivalents (195) (15)
Cash and Cash Equivalents at Beginning of Period 273 61
- --------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 78 $ 46
========================================================================================================
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 341 $ 305
income taxes (net of refunds) $ 43 $ 22
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 holding company
headquartered in Raleigh, North Carolina. The Company is registered under
the Public Utility Holding Company Act of 1935 (PUHCA), as amended and as
such, the Company and its subsidiaries are subject to the regulatory
provisions of PUHCA.
Through its wholly-owned subsidiaries, Carolina Power & Light Company d/b/a
Progress Energy Carolinas, Inc. (PEC) and Florida Power Corporation d/b/a
Progress Energy Florida, Inc. (PEF), the Company's PEC Electric and PEF
segments are primarily engaged in the generation, transmission,
distribution and sale of electricity in portions of North Carolina, South
Carolina and Florida. The Progress Ventures business unit consists of the
Fuels (Fuels) and the Competitive Commercial Operations (CCO) business
segments. The Fuels segment is involved in natural gas drilling and
production, coal terminal services, coal mining, synthetic fuel production,
fuel transportation and delivery. The CCO segment includes nonregulated
electric generation and energy marketing activities. Through the Rail
Services (Rail) segment, the Company is involved in nonregulated railcar
repair, rail parts reconditioning and sales, and scrap metal recycling.
Through its other business units, the Company engages in other nonregulated
business areas, including telecommunications and energy management and
related services. Progress Energy's legal structure is not currently
aligned with the functional management and financial reporting of the
Progress Ventures business unit. Whether, and when, the legal and
functional structures will converge depends upon regulatory action, which
cannot currently be anticipated.
B. Basis of Presentation
These financial statements have been prepared in accordance with accounting
principles generally accepted in the United States of America (GAAP) for
interim financial information and with the instructions to Form 10-Q and
Regulation S-X. Accordingly, they do not include all of the information and
footnotes required by GAAP for annual statements. Because the accompanying
consolidated interim financial statements do not include all of the
information and footnotes required by GAAP, they should be read in
conjunction with the audited financial statements for the period ended
December 31, 2003, and notes thereto included in Progress Energy's Form
10-K for the year ended December 31, 2003.
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
increased by $5 million for both the three months ended June 30, 2004 and
2003, in order to maintain an effective tax rate consistent with the
estimated annual rate. Income tax expense was increased by $43 million and
decreased by $5 million for the six months ended June 30, 2004 and 2003,
respectively. The income tax provisions for the Company differ from amounts
computed by applying the Federal statutory tax rate to income before income
taxes, primarily due to the recognition of synthetic fuel tax credits.
PEC and PEF collect from customers certain excise taxes, which include
gross receipts tax, franchise taxes, and other excise taxes, levied by the
state or local government upon the customers. PEC and PEF account for
excise taxes on a gross basis. For the three months ended June 30, 2004 and
2003, excise taxes of approximately $61 million and $51 million,
respectively, are included in taxes other than on income in the
accompanying Consolidated Statements of Income. For the six months ended
June 30, 2004 and 2003, excise taxes of approximately $114 million and $102
million, respectively, are included in taxes other than on income in the
accompanying Consolidated Statements of Income. These approximate amounts
are also included in utility revenues.
The amounts included in the consolidated interim financial statements are
unaudited but, in the opinion of management, reflect all normal recurring
adjustments necessary to fairly present the Company's financial position
and results of operations for the interim periods. Due to seasonal weather
variations and the timing of outages of electric generating units,
especially nuclear-fueled units, the results of operations for interim
periods are not necessarily indicative of amounts expected for the entire
year or future periods.
9
In preparing financial statements that conform with GAAP, management must
make estimates and assumptions that affect the reported amounts of assets
and liabilities, disclosure of contingent assets and liabilities at the
date of the financial statements and amounts of revenues and expenses
reflected during the reporting period. Actual results could differ from
those estimates. Certain amounts for 2003 have been reclassified to conform
to the 2004 presentation.
The results of operations of the Rail Services segment are reported one
month in arrears.
C. Subsidiary Reporting Period Change
In the fourth quarter of 2003, the Company ceased recording portions of
Fuels' segment operations, primarily synthetic fuel operations, one month
in arrears. As a result, earnings for the year ended December 31, 2003 as
reported in the Company's Form 10-K, included 13 months of results for
these operations. The 2003 quarterly results for periods ended March 31,
June 30 and September 30 have been restated for the above-mentioned
reporting period change. This resulted in four months of earnings in the
first quarter of 2003. The impact of the reclassification of earnings
between quarters is outlined for the first two quarters of 2003 in the
table below:
Three Months Ended June 30, 2003 As Previously Quarter As
(in millions, except per share data) Reported Reclassification Restated
---------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Cumulative Effect $ 150 $ 4 $ 154
of Change in Accounting Principle
Net Income $ 153 $ 4 $ 157
Basic earnings per common share
Income from Continuing Operations before Cumulative
Effect of Change in Accounting Principle $ 0.64 $ 0.01 $ 0.65
Net Income $ 0.65 $ 0.01 $ 0.66
Diluted earnings per common share
Income from Continuing Operations before Cumulative
Effect of Change in Accounting Principle $ 0.63 $ 0.02 $ 0.65
Net Income $ 0.64 $ 0.02 $ 0.66
Six Months Ended June 30, 2003 As Previously Quarter As
(in millionas, except per share data) Reported Reclassification Restated
---------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Cumulative Effect $ 346 $ 15 $ 361
of Change in Accounting Principle
Net Income $ 361 $ 15 $ 376
Basic earnings per common share
Income from Continuing Operations before Cumulative
Effect of Change in Accounting Principle $ 1.48 $ 0.06 $ 1.54
Net Income $ 1.54 $ 0.06 $ 1.60
Diluted earnings per common share
Income from Continuing Operations before Cumulative
Effect of Change in Accounting Principle $ 1.47 $ 0.06 $ 1.53
Net Income $ 1.53 $ 0.06 $ 1.59
D. Stock-Based Compensation
The Company measures compensation expense for stock options as the
difference between the market price of its common stock and the exercise
price of the option at the grant date. The exercise price at which options
are granted by the Company equals the market price at the grant date, and
accordingly, no compensation expense has been recognized for stock option
grants. For purposes of the pro forma disclosures required by SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure - an
Amendment of FASB Statement No. 123" the estimated fair value of the
Company's stock options is amortized to expense over the options' vesting
period. The following table illustrates the effect on net income and
earnings per share if the fair value method had been applied to all
outstanding and unvested awards in each period:
10
Three Months Ended Six Months Ended
June 30 June 30
----------------------- ---------------------
(in millions except per share data) 2004 2003 2004 2003
---------- ----------- --------- ----------
Net Income, as reported $ 154 $ 157 $ 262 $ 376
Deduct: Total stock option expense determined under
fair value method for all awards, net of related tax
effects 3 2 6 4
---------- ----------- --------- ----------
Pro forma net income $ 151 $ 155 $ 256 $ 372
========== =========== ========= ==========
Basic earnings per share
As reported $ 0.63 $ 0.66 $ 1.08 $ 1.60
Pro forma $ 0.62 $ 0.65 $ 1.06 $ 1.58
Fully diluted earnings per share
As reported $ 0.63 $ 0.66 $ 1.08 $ 1.59
Pro forma $ 0.62 $ 0.65 $ 1.05 $ 1.57
E. Consolidation of Variable Interest Entities
The Company consolidates all voting interest entities in which it owns a
majority voting interest and all variable interest entities for which it is
the primary beneficiary in accordance with FASB Interpretation No. 46R,
"Consolidation of Variable Interest Entities - an Interpretation of ARB No.
51" (FIN No. 46R). During the first six months of 2004 and 2003, the
Company did not participate in the creation of, or obtain a significant new
variable interest in, any variable interest entity.
The Company is the primary beneficiary of a limited partnership which
invests in 17 low-income housing partnerships that qualify for federal and
state tax credits. The Company has requested but has not received all the
necessary information to determine the primary beneficiary of the limited
partnership's underlying 17 partnership investments, and has applied the
information scope exception in FIN No. 46R, paragraph 4(g) to the 17
partnerships. The Company has no direct exposure to loss from the 17
partnerships; the Company's only exposure to loss is from its investment of
approximately $1 million in the consolidated limited partnership. The
Company will continue its efforts to obtain the necessary information to
fully apply FIN No. 46R to the 17 partnerships. The Company believes that
if the limited partnership is determined to be the primary beneficiary of
the 17 partnerships, the effect of consolidating the 17 partnerships would
not be significant to the Company's Consolidated Balance Sheets.
The Company has variable interests in two power plants resulting from
long-term power purchase contracts. The Company has requested the necessary
information to determine if the counterparties are variable interest
entities or to identify the primary beneficiaries. Both entities declined
to provide the Company with the necessary financial information, and the
Company has applied the information scope exception in FIN No. 46R,
paragraph 4(g). The Company's only significant exposure to variability from
these contracts results from fluctuations in the market price of fuel used
by the two entities' plants to produce the power purchased by the Company.
The Company is able to recover these fuel costs under PEC's fuel clause.
Total purchases from these counterparties were approximately $21 million
and $19 million in the first six months of 2004 and 2003, respectively. The
Company will continue its efforts to obtain the necessary information to
fully apply FIN No. 46R to these contracts. The combined generation
capacity of the two entities' power plants is approximately 880 MW. The
Company believes that if it is determined to be the primary beneficiary of
these two entities, the effect of consolidating the entities would result
in increases to total assets, long-term debt and other liabilities, but
would have an insignificant or no impact on the Company's common stock
equity, net earnings, or cash flows. However, as the Company has not
received any financial information from these two counterparties, the
impact cannot be determined at this time.
The Company also has interests in several other variable interest entities
for which the Company is not the primary beneficiary. These arrangements
include investments in approximately 28 limited partnerships, limited
liability corporations and venture capital funds and two building leases
with special-purpose entities. The aggregate maximum loss exposure at June
30, 2004, that the Company could be required to record in its income
statement as a result of these arrangements totals approximately $38
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.
11
2. NEW ACCOUNTING STANDARDS
In December 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the Act) was signed into law. In accordance with
guidance issued by the FASB in FASB Staff Position FAS 106-1, the Company
has elected to defer accounting for the effects of the Act due to
uncertainties regarding the effects of the implementation of the Act and
the accounting for certain provisions of the Act. Therefore, OPEB
information presented in the financial statements does not reflect the
effects of the Act. The FASB recently issued definitive accounting guidance
for the Act in FASB Staff Position 106-2, which is effective for the
Company in the third quarter of 2004. FASB Staff Position 106-2 will result
in the recognition of lower OPEB costs to reflect prescription drug-related
federal subsidies to be received under the Act. The Company is in the
process of quantifying the impact of the Act on OPEB costs.
3. DIVESTITURES
A. Divestiture of Synthetic Fuel Partnership Interests
In June 2004, the Company through its subsidiary, Progress Fuels sold, in
two transactions, a combined 49.8 percent partnership interest in Colona
Synfuel Limited Partnership, LLLP, one of its synthetic fuel facilities.
Substantially all proceeds from the sales will be received over time, which
is typical of such sales in the industry. Gain from the sales will be
recognized on a cost recovery basis. The Company's book value of the
interests sold totaled approximately $5 million. Based on projected
production levels, the Company anticipates receiving total gross proceeds
of approximately $30 million per year, on an annualized basis. Under the
agreements, the buyers have a right to unwind the transactions if an IRS
reconfirmation private letter ruling (PLR) is not received by October 15,
2004. Therefore, no gain would be recognized prior to the expiration of
that right.
B. Railcar Ltd. Divestiture
In December 2002, the Progress Energy Board of Directors adopted a
resolution approving the sale of Railcar Ltd., a subsidiary included in the
Rail Services segment. In March 2003, the Company signed a letter of intent
to sell the majority of Railcar Ltd. assets to The Andersons, Inc., and the
transaction closed in February 2004. Proceeds from the sale were
approximately $82 million before transaction costs and taxes of
approximately $13 million. The assets of Railcar Ltd. were grouped as
assets held for sale and are included in other current assets on the
Consolidated Balance Sheets at June 30, 2004 and December 31, 2003. The
assets were recorded at approximately $6 million and $75 million at June
30, 2004 and December 31, 2003, respectively, which reflects the Company's
estimates of the fair value expected to be realized from the sale of these
assets less costs to sell. In July 2004, the Company sold the remaining
assets classified as held for sale to a third-party for net proceeds of $6
million.
C. NCNG Divestiture
In October 2002, the Company announced the Board of Directors' approval to
sell North Carolina Natural Gas Corporation (NCNG) and the Company's equity
investment in Eastern North Carolina Natural Gas Company (ENCNG) to
Piedmont Natural Gas Company, Inc. On September 30, 2003, the Company
completed the sale. The 2003 net income of these operations is reported as
discontinued operations in the Consolidated Statements of Income. Interest
expense of $3 million and $7 million for the three and six months ended
June 30, 2003, respectively, has been allocated to discontinued operations
based on the net assets of NCNG, assuming a uniform debt-to-equity ratio
across the Company's operations. Results of discontinued operations were as
follows:
(in millions) Three Months Ended Six Months Ended
June 30, 2003 June 30, 2003
-------------------------------------------
Revenues $ 71 $ 225
===================== ====================
Earnings before income taxes $ 4 $ 23
Income tax expense 1 9
--------------------- --------------------
Net earnings from discontinued operations $ 3 $ 14
===================== ====================
12
During the three months ended June 30, 2004, the Company recorded an
additional gain after taxes of approximately $1 million related to deferred
taxes on the loss from the NCNG sale.
4. REGULATORY MATTERS
A. Retail Rate Matters
PEC has exclusively utilized external funding for its decommissioning
liability since 1994. Prior to 1994, PEC retained funds internally to meet
its decommissioning liability. A North Carolina Utilities Commission (NCUC)
order issued in February 2004 found that by January 1, 2008, PEC must begin
transitioning these amounts to external funds. The transition of $131
million must be completed by December 31, 2017, and at least 10% must be
transitioned each year.
PEC filed with the Public Service Commission of South Carolina (SCPSC)
seeking permission to defer expenses incurred from the first quarter 2004
winter storm. The SCPSC approved PEC's request to defer the costs and
amortize them ratably over five years beginning in January 2005.
Approximately $10 million related to storm costs incurred during the first
quarter of 2004 was deferred in that quarter.
During the first quarter of 2004, PEC met the requirements of both the NCUC
and the SCPSC for the implementation of a depreciation study which allowed
the utility to reduce the rates used to calculate depreciation expense. As
a result, depreciation expense decreased $10 million for the three months
ended June 30, 2004 compared to the prior year quarter and decreased $18
million for the six months ended June 30, 2004 compared to the prior year
six month period.
On June 29, 2004, the FPSC approved a Stipulation and Settlement Agreement,
executed on April 29, 2004, by PEF, the Office of Public Counsel and the
Florida Industrial Power Users Group. The stipulation and settlement
resolved the issue pending before the FPSC regarding the costs PEF will be
allowed to recover through its Fuel and Purchased Power Cost Recovery
clause in 2004 and beyond for waterborne coal deliveries by the Company's
affiliated coal supplier, Progress Fuels Corporation. The settlement sets
fixed per ton prices based on point of origin for all waterborne coal
deliveries in 2004, and establishes a market-based pricing methodology for
determining recoverable waterborne coal transportation costs through a
competitive solicitation process or market price proxies beginning in 2005
and thereafter. The settlement reduces the amount that PEF will charge to
the Fuel and Purchased Power Cost Recovery clause for waterborne
transportation by approximately $13 million beginning in 2004. This
concludes the FPSC's investigation of PEF's recoverable waterborne coal
transportation costs.
B. Regional Transmission Organizations
In 2000, the Federal Energy Regulatory Commission (FERC) issued Order 2000
regarding regional transmission organizations (RTOs). This Order set
minimum characteristics and functions that RTOs must meet, including
independent transmission service. In July 2002, the FERC issued its Notice
of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue
Discrimination through Open Access Transmission Service and Standard
Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set
forth in the SMD NOPR would materially alter the manner in which
transmission and generation services are provided and paid for. In April
2003, the FERC released a White Paper on the Wholesale Market Platform. The
White Paper provides an overview of what the FERC currently intends to
include in a final rule in the SMD NOPR docket. The White Paper retains the
fundamental and most protested aspects of SMD NOPR, including mandatory
RTOs and the FERC's assertion of jurisdiction over certain aspects of
retail service. The FERC has not yet issued a final rule on SMD NOPR. The
Company cannot predict the outcome of these matters or the effect that they
may have on the GridSouth and GridFlorida proceedings currently ongoing
before the FERC. It is unknown what impact the future proceedings will have
on the Company's earnings, revenues or prices.
The Company has $33 million and $4 million invested in GridSouth and
GridFlorida, respectively, related to startup costs at June 30, 2004. The
Company expects to recover these startup costs in conjunction with the
GridSouth and GridFlorida original structures or in conjunction with any
alternate combined transmission structures that emerge.
13
C. Implementation of SFAS No. 143
In connection with the implementation of SFAS No. 143 in 2003, PEC filed a
request with the NCUC requesting deferral of the difference between expense
pursuant to SFAS No. 143 and expense as previously determined by the NCUC.
The NCUC granted the deferral of the January 1, 2003 cumulative adjustment.
Because the clean air legislation discussed in Note 10 under "Air Quality"
contained a prohibition against cost deferrals unless certain criteria are
met, the NCUC denied the deferral of the ongoing effects. Since the NCUC
order denied deferral of the ongoing effects, PEC ceased deferral of the
ongoing effects during the second quarter for the six months ended June 30,
2003 related to its North Carolina retail jurisdiction. Pre-tax income for
the three and six months ended June 30, 2003 increased by approximately $14
million, which represents a decrease in non-ARO cost of removal expense,
partially offset by an increase in decommissioning expense. The Company
provided additional information to the NCUC that demonstrated that deferral
of the ongoing effects should also be allowed. In August of 2003, the NCUC
revised its decision and approved the deferral of the ongoing effects of
SFAS No. 143 at which time the $14 million was reversed.
D. FERC Market Power Mitigation
A FERC order issued in November 2001 on certain unaffiliated utilities'
triennial market based wholesale power rate authorization updates required
certain mitigation actions that those utilities would need to take for
sales/purchases within their control areas and required those utilities to
post information on their websites regarding their power systems' status.
As a result of a request for rehearing filed by certain market
participants, FERC issued an order delaying the effective date of the
mitigation plan until after a planned technical conference on market power
determination. In December 2003, the FERC issued a staff paper discussing
alternatives and held a technical conference in January 2004. In April
2004, the FERC issued two orders concerning utilities' ability to sell
wholesale electricity at market based rates. In the first order, the FERC
adopted two new interim screens for assessing potential generation market
power of applicants for wholesale market based rates, and described
additional analyses and mitigation measures that could be presented if an
applicant does not pass one of these interim screens. In July 2004, the
FERC issued an order on rehearing affirming its conclusions in the April
order. In the second order, the FERC initiated a rulemaking to consider
whether the FERC's current methodology for determining whether a public
utility should be allowed to sell wholesale electricity at market-based
rates should be modified in any way. Management is unable to predict the
outcome of these actions by the FERC or their effect on future results of
operations and cash flows. However, the Company does not anticipate that
the current operations of PEC or PEF would be impacted materially if they
were unable to sell power at market-based rates in their respective control
areas.
5. GOODWILL AND OTHER INTANGIBLE ASSETS
The Company performed the annual goodwill impairment test in accordance
with FASB Statement No. 142, Goodwill and Other Intangible Assets, for the
CCO segment in the first quarter of 2004, and the annual goodwill
impairment test for the PEC Electric and PEF segments in the second quarter
of 2004, each of which indicated no impairment. The first annual impairment
test for the Other segment will be performed in the fourth quarter 2004,
since the goodwill was acquired in 2003.
The changes in the carrying amount of goodwill for the periods ended June
30, 2004 and December 31, 2003, by reportable segment, are as follows:
(in millions) PEC Electric PEF CCO Other Total
-----------------------------------------------------------
Balance as of January 1, 2003 $ 1,922 $ 1,733 $ 64 $ - $ 3,719
Acquisitions - - - 7 7
-----------------------------------------------------------
Balance as of December 31, 2003 $ 1,922 $ 1,733 $ 64 $ 7 $ 3,726
Purchase accounting adjustment - - - 4 4
-----------------------------------------------------------
Balance as of June 30, 2004 $ 1,922 $ 1,733 $ 64 $ 11 $ 3,730
===========================================================
14
The gross carrying amount and accumulated amortization of the Company's
intangible assets at June 30, 2004 and December 31, 2003, are as follows:
June 30, 2004 December 31, 2003
----------------------------------- -------------------------------
(in millions) Gross Gross
Carrying Accumulated Carrying Accumulated
Amount Amortization Amount Amortization
--------------- ----------------- -------------- ----------------
Synthetic fuel intangibles $ 134 $ (71) $ 140 $ (64)
Power agreements acquired 221 (29) 221 (20)
Other 64 (13) 62 (12)
--------------- ----------------- -------------- ----------------
Total $ 419 $ (113) $ 423 $ (96)
=============== ================= ============== ================
In June 2004, the Company sold, in two transactions, a combined 49.8
percent partnership interest in Colona Synfuel Limited Partnership, LLLP,
one of its synthetic fuel operations. Approximately $6 million in synthetic
fuel intangibles and $4 million in related accumulated amortization were
included in the sale of the partnership interest.
All of the Company's intangibles are subject to amortization. Synthetic
fuel intangibles represent intangibles for synthetic fuel technology. These
intangibles are being amortized on a straight-line basis until the
expiration of tax credits under Section 29 of the Internal Revenue Code
(Section 29) in December 2007. The intangibles related to power agreements
acquired are being amortized based on the economic benefits of the
contracts. Other intangibles are primarily acquired customer contracts and
permits that are amortized over their respective lives.
Amortization expense recorded on intangible assets for the three months
ended June 30, 2004 and 2003 was $12 million and $9 million, respectively.
Amortization expense recorded on intangible assets for the six months ended
June 30, 2004 and 2003 was $21 million and $16 million, respectively. The
estimated annual amortization expense for intangible assets for 2004
through 2008, in millions, is approximately $41, $34, $35, $35 and $17,
respectively.
6. EQUITY
A. Earnings Per Common Share
A reconciliation of the weighted-average number of common shares
outstanding for basic and dilutive earnings per share purposes is as
follows:
(in millions) Three Months Ended Six Months Ended
June 30 June 30
------------------------- -----------------------
2004 2003 2004 2003
----------- ---------- ---------- --------
Weighted-average common shares - basic 242 236 242 235
Restricted stock awards 1 1 1 1
----------- ---------- ---------- --------
Weighted-average shares - fully dilutive 243 237 243 236
----------- ---------- ---------- --------
B. Comprehensive Income
Comprehensive income for the three months ended June 30, 2004 and 2003 was
$159 million and $154 million, respectively. Comprehensive income for the
six months ended June 30, 2004 and 2003 was $256 million and $373 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.
7. FINANCING ACTIVITIES
Progress Energy took advantage of favorable market conditions and entered
into a new $1.1 billion five year line of credit, effective August 5, 2004,
and expiring August 4, 2009. This facility replaces Progress Energy's $250
million 364 day line of credit and its three year $450 million line of
credit, which were set to expire in November 2004.
15
On July 28, 2004, PEC extended its $165 million 364-day line of credit,
which was to expire on July 29, 2004. The line of credit will expire on
July 27, 2005.
On April 30, 2004, PEC redeemed $34.7 million of Darlington County 6.6%
Series Pollution Control Bonds at 102.5% of par, $1.795 million of New
Hanover County 6.3% Series Pollution Control Bonds at 101.5% of par, and
$2.58 million of Chatham County 6.3% Series Pollution Control Bonds at
101.5% of par with cash from operations.
On March 1, 2004, Progress Energy used available cash and proceeds from the
issuance of commercial paper to pay at maturity $500 million 6.55% senior
unsecured notes. Cash and commercial paper capacity for this retirement was
created primarily from proceeds of the sale of assets and early long-term
debt financings in 2003.
On February 9, 2004, Progress Capital Holdings, Inc. paid at maturity $25
million 6.48% medium term notes with excess cash.
On January 15, 2004, PEC paid at maturity $150 million 5.875% First
Mortgage Bonds with commercial paper proceeds. On April 15, 2004, PEC also
paid at maturity $150 million 7.875% First Mortgage Bonds with commercial
paper proceeds and cash from operations.
For the three months ended June 30, 2004, the Company issued approximately
0.6 million shares of its common stock for approximately $29 million in
proceeds from its Investor Plus Stock Purchase Plan and its employee
benefit plans. For the six months ended June 30, 2004, the Company issued
approximately 1.3 million shares of its common stock for approximately $58
million in proceeds from its Investor Plus Stock Purchase Plan and its
employee benefit plans. For the six months ended June 30, 2004 and 2003,
the dividends paid on common stock were approximately $280 million and $268
million, respectively.
8. BENEFIT PLANS
The Company and some of its subsidiaries have a non-contributory defined
benefit retirement (pension) plan for substantially all full-time
employees. The Company also has supplementary defined benefit pension plans
that provide benefits to higher-level employees. In addition to pension
benefits, the Company and some of its subsidiaries provide contributory
other postretirement benefits (OPEB), including certain health care and
life insurance benefits, for retired employees who meet specified criteria.
The components of the net periodic benefit cost for the three and six
months ended June 30 are:
Three Months Ended June 30 Other Postretirement
Pension Benefits Benefits
--------------------- ----------------------
(in millions) 2004 2003 2004 2003
--------------------- ----------------------
Service cost $ 13 $ 13 $ 4 $ 3
Interest cost 28 27 8 8
Expected return on plan assets (37) (36) (1) (1)
Amortization of actuarial (gain) loss 5 5 1 1
Other amortization, net - - 1 1
--------------------- ----------------------
Net periodic cost $ 9 $ 9 $ 13 $ 12
Additional cost / (benefit) recognition (a) (4) (4) 1 1
--------------------- ----------------------
Net periodic cost recognized $ 5 $ 5 $ 14 $ 13
===================== ======================
16
Six Months Ended June 30 Other Postretirement
Pension Benefits Benefits
---------------------- -----------------------
(in millions) 2004 2003 2004 2003
---------------------- -----------------------
Service cost $ 27 $ 26 $ 8 $ 7
Interest cost 55 54 17 15
Expected return on plan assets (75) (72) (2) (2)
Amortization of actuarial (gain) loss 11 9 2 2
Other amortization, net - - 1 2
---------------------- -----------------------
Net periodic cost $ 18 $ 17 $ 26 $ 24
Additional cost / (benefit) recognition (a) (8) (7) 1 1
---------------------- -----------------------
Net periodic cost recognized $ 10 $ 10 $ 27 $ 25
====================== =======================
(a) Due to the acquisition of FPC. See Note 16B of Progress Energy's
Form 10-K for year ended December 31, 2003.
9. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS
Progress Energy and its subsidiaries are exposed to various risks related
to changes in market conditions. The Company has a risk management
committee that includes senior executives from various business groups. The
risk management committee is responsible for administering risk management
policies and monitoring compliance with those policies by all subsidiaries.
Under its risk management policy, the Company may use a variety of
instruments, including swaps, options and forward contracts, to manage
exposure to fluctuations in commodity prices and interest rates. Such
instruments contain credit risk if the counterparty fails to perform under
the contract. The Company minimizes such risk by performing credit reviews
using, among other things, publicly available credit ratings of such
counterparties. Potential nonperformance by counterparties is not expected
to have a material effect on the consolidated financial position or
consolidated results of operations of the Company.
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.
As of June 30, 2004, Progress Energy had $1 billion 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 between March 2006 and March 2011. During the year,
Progress Energy has entered into $350 million notional of open interest
rate fair value hedges. In March 2004, two interest rate swap agreements
totaling $200 million were terminated. These swaps were associated with
Progress Energy 5.85% Notes due in 2008. The loss on the agreements was
deferred and is being amortized over the life of the bonds as these
agreements had been designated as fair value hedges for accounting
purposes.
As of June 30, 2004, PEC had $70 million notional of pay fixed forward
starting swaps, entered into in March 2004, to hedge its exposure to
interest rates with regard to a future issuance of debt and $26 million
notional of pay fixed forward starting swaps, entered into in April 2004,
to hedge its exposure to interest rates with regard to an upcoming railcar
lease. In July 2004, PEC entered into an additional $30 million notional
pay fixed forward swap related the future issuance of debt, increasing the
total notional of pay fixed forward starting swaps to $126 million. These
agreements have a computational period of ten years.
In May 2004, the Company terminated interest rate cash flow hedges, with a
total notional amount of $400 million, related to projected outstanding
balances of commercial paper. Amounts in accumulated other comprehensive
income related to these terminated hedges will be reclassified to earnings
as the hedged interest payments occur.
The Company holds interest rate collars with a varying notional amount
(currently at the maximum of $195 million) to hedge floating rate exposure
associated with variable rate long-term debt at Progress Ventures. The
Company is required to hedge 50% of the amount outstanding under its bank
facility through March 2007.
17
The notional amounts of interest rate derivatives are not exchanged and do
not represent exposure to credit loss. In the event of default by a
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.
PEF has entered into derivative instruments to hedge its exposure to price
fluctuations on fuel oil purchases. These instruments did not have a
material impact on the Company's consolidated financial position or results
of operations.
Progress Fuels Corporation, through Progress Ventures, Inc. (PVI),
periodically enters into derivative instruments to hedge its exposure to
price fluctuations on natural gas sales. As of June 30, 2004, Progress
Fuels Corporation is hedging exposures to the price variability of portions
of its natural gas production through December 2005. These instruments did
not have a material impact on the Company's consolidated financial position
or results of operations.
Nonhedging derivatives, primarily electricity and natural gas contracts,
are entered into for trading purposes and for economic hedging purposes.
While management believes the economic hedges mitigate exposures to
fluctuations in commodity prices, these instruments are not designated as
hedges for accounting purposes and are monitored consistent with trading
positions.
The Company 's July 2004 forward mark-to-market losses were $7 million for
the first quarter of 2004 and $3 million for the second quarter of 2004 .
These mark-to-market losses are reflected in diversified business revenues
and were related to an agreement to provide energy needed to fulfill a
contract obligation and economic hedges used to mitigate exposures to
fluctuations in commodity prices.
10. FINANCIAL INFORMATION BY BUSINESS SEGMENT
The Company currently provides services through the following business
segments: PEC Electric, PEF, Fuels, CCO, Rail Services and Other.
PEC Electric and PEF are primarily engaged in the generation, transmission,
distribution and sale of electric energy in portions of North Carolina,
South Carolina and Florida. These electric operations are subject to the
rules and regulations of the FERC, the NCUC, the SCPSC, the FPSC and the
United States Nuclear Regulatory Commission (NRC). These electric
operations also distribute and sell electricity to other utilities,
primarily on the east coast of the United States.
Fuels' operations, which are located throughout the United States, are
involved in natural gas drilling and production, coal terminal services,
coal mining, synthetic fuel production, fuel transportation and delivery.
CCO's operations, which are located in the southeastern United States,
include nonregulated electric generation operations and marketing
activities.
Rail Services' operations include railcar repair, rail parts reconditioning
and sales, and scrap metal recycling. These activities include maintenance
and reconditioning of salvageable scrap components of railcars, locomotive
repair and right-of-way maintenance. Rail Services' operations are located
in the United States, Canada and Mexico.
The Other segment, whose operations are in the United States, is composed
of other nonregulated business areas including telecommunications and
energy service operations and other nonregulated subsidiaries that do not
separately meet the disclosure requirements of SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information."
In addition to these reportable operating segments, the Company has other
corporate activities that include holding company operations, service
company operations and eliminations. The profit or loss of the identified
segments plus the loss of Corporate represents the Company's total income
from continuing operations before cumulative effect of change in accounting
principle.
18
Revenues
---------------------------------------
Income from
Continuing
(in millions) Unaffiliated Intersegment Total Operations Assets
------------ ------------ ---------- ------------- -----------
FOR THE THREE MONTHS
ENDED
JUNE 30, 2004
PEC Electric $ 861 $ - $ 861 $ 97 $ 10,711
PEF 860 - 860 84 7,457
Fuels 325 68 393 56 1,156
CCO 72 - 72 5 1,784
Rail Services 285 - 285 4 532
Other 22 1 23 (30) 312
Corporate - (69) (69) (63) 4,283
------------ ------------ ---------- ------------- -----------
Consolidated totals $ 2,425 $ - $ 2,425 $ 153 $ 26,235
------------ ------------ ---------- ------------- -----------
FOR THE THREE MONTHS
ENDED
JUNE 30, 2003
PEC Electric $ 816 $ - $ 816 $ 89
PEF 767 - 767 61
Fuels 206 88 294 58
CCO 33 - 33 2
Rail Services 214 - 214 2
Other 14 3 17 -
Corporate - (91) (91) (58)
------------ ------------ ---------- -------------
Consolidated totals $ 2,050 $ - $ 2,050 $ 154
------------ ------------ ---------- -------------
Revenues
---------------------------------------
Income from
Continuing
(in millions) Unaffiliated Intersegment Total Operations
------------ ------------ ---------- -------------
FOR THE SIX MONTHS
ENDED JUNE 30, 2004
PEC Electric $ 1,762 $ - $ 1,762 $ 213
PEF 1,644 - 1,644 133
Fuels 598 151 749 104
CCO 105 - 105 (3)
Rail Services 523 - 523 9
Other 44 1 45 (31)
Corporate - (152) (152) (164)
------------ ------------ ---------- -------------
Consolidated totals $ 4,676 $ - $ 4,676 $ 261
------------ ------------ ---------- -------------
FOR THE SIX MONTHS
ENDED JUNE 30, 2003
PEC Electric $ 1,742 $ - $ 1,742 $ 223
PEF 1,495 - 1,495 132
Fuels 510 169 679 97
CCO 71 - 71 11
Rail Services 392 - 392 (1)
Other 27 8 35 1
Corporate - (177) (177) (102)
------------ ------------ ---------- -------------
Consolidated totals $ 4,237 $ - $ 4,237 $ 361
------------ ------------ ---------- -------------
11. OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income and other income and
expense items as discussed below. The components of other, net as shown on
the accompanying Consolidated Statements of Income are as follows:
19
Three Months Ended Six Months Ended
June 30 June 30
(in millions) 2004 2003 2004 2003
Other income
Net financial trading gain (loss) $ 4 $ (1) $ 5 $ (1)
Nonregulated energy and delivery services income 5 5 11 11
Investment gains 3 - - -
AFUDC equity 2 4 4 6
Other 3 9 8 9
---------- ---------- ---------- ----------
Total other income $ 17 $ 17 $ 28 $ 25
---------- ---------- ---------- ----------
Other expense
Nonregulated energy and delivery services expenses $ 5 $ 5 $ 9 $ 10
Donations 2 3 10 7
Investment losses - 9 - 8
Contingent value obligations unrealized loss 5 2 13 -
Loss from equity investments 1 - 2 3
Write-off of non-trade receivable - - 7 -
Other 4 7 12 12
---------- ---------- ---------- ----------
Total other expense $ 17 $ 26 $ 53 $ 40
---------- ---------- ---------- ----------
Other, net $ - $ (9) $ (25) $ (15)
--------------------------------------------------------------------------------------------------------
Net financial trading gains and losses represent non-asset-backed trades of
electricity and gas. Nonregulated energy and delivery services include
power protection services and mass-market programs such as surge
protection, appliance services and area light sales, and delivery,
transmission and substation work for other utilities.
12. COMMITMENTS AND CONTINGENCIES
Contingencies and significant changes to the commitments discussed in Note
21 of the Company's 2003 Annual Report on Form 10-K are described below.
A. Guarantees
As a part of normal business, Progress Energy and certain 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 Progress
Energy and subsidiaries on a stand-alone basis, thereby facilitating the
extension of sufficient credit to accomplish the subsidiaries' intended
commercial purposes. At June 30, 2004, management does not believe
conditions are likely for significant performance under the guarantees of
performance issued by or on behalf of affiliates discussed herein.
Guarantees at June 30, 2004, 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 $ 405
Guarantees supporting nuclear decommissioning 181
Guarantee supporting power supply agreements 457
Standby letters of credit 54
Surety bonds 132
Guarantees supporting nonregulated portfolio and energy marketing
activities issued by subsidiaries of Progress Energy 82
Guarantees issued on behalf of third parties
Other guarantees 24
-----------
Total $ 1,335
===========
20
Guarantees Supporting Nonregulated Portfolio and Energy Marketing
Activities Issued by Progress Energy
Progress Energy has issued approximately $404 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 $19 million and $57 million of these
guarantees were issued during the second three and six months ended June
30, 2004, respectively, to support Fuels and energy-marketing activities.
The majority of the marketing contracts supported by the guarantees contain
provisions that trigger guarantee obligations based on 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
June 30, 2004, 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 $115 million
for the benefit of the Company's counterparties to support ongoing
operations within a 90-day period. The remaining $1 million in guarantees
issued by Progress Energy on behalf of affiliates is primarily related to
performance and payments subject to other contingencies.
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 million. On May 12,
2004, PEC sent notice to the NRC informing them that due to the Renewed
Facility Operating License for Robinson 2, the parent guarantee related to
Robinson, would be cancelled as of June 30, 2004. As a result, the total
parent guarantees for decommissioning decreased from $276 million to $181
million during the second quarter.
Guarantees Supporting Power Supply Agreements
In March 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 County EMC (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
$280 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 $280 million)
acceptable to Jackson.
During the third quarter of 2003, PVI entered into an agreement with Morgan
Stanley Capital Group Inc. (Morgan Stanley) 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 June 30, 2004.
In June 2004, PVI entered into a definitive agreement with five electric
cooperatives in Georgia to provide long term full requirements power. The
transaction closed during the second quarter of 2004. The Company issued a
payment and performance guarantee to the cooperatives related to the power
supply agreement totaling $150 million. In the event that Progress Energy's
credit ratings fall below investment grade, Progress Energy would be
required to provide additional security for this guarantee in form and
amount acceptable to the cooperatives. The Company would immediately be
required to deposit cash or provide letters of credit or other cash
collateral up to 50% of the coverage amount of the guarantees issued (for a
maximum of $75 million) in the event of a downgrade. Beyond that
requirement, additional security requirements would be determined based
upon a calculation of mark-to-market exposure, not to exceed $150 million.
21
Standby Letters of Credit
As of June 30, 2004, financial institutions have issued $54 million of
standby letters of credit to financial institutions for the Company 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.
Surety Bonds
At June 30, 2004, the Company had $132 million in surety bonds purchased
primarily for purposes such as providing workers' compensation coverage,
obtaining licenses, permits, 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.
Guarantees Supporting Nonregulated Portfolio and Energy Marketing
Activities Issued by Subsidiaries of Progress Energy
Subsidiaries of Progress Energy have issued approximately $82 million of
guarantees for obligations under tolling agreements, transmission
agreements, gas agreements, construction agreements, fuel procurement
agreements and trading operations.
Other Guarantees
The Company has other guarantees outstanding of approximately $24 million.
Included in the $24 million are $10 million of guarantees issued on behalf
of third parties, which is in support of synthetic fuel operations at a
third-party plant. The remaining $14 million in affiliate guarantees is
related primarily to prompt performance payments and other payments subject
to contingencies.
In connection with the sale of partnership interests in Colona (see Note
3.A), Progress Fuels indemnified the buyers against any claims related to
Colona resulting from violations of any environmental laws. Although the
terms of the agreement provide for no limitation to the maximum potential
future payments under the indemnification, the Company has estimated that
the maximum total of such payments would be insignificant.
B. Insurance
Both PEC and PEF are insured against public liability for a nuclear
incident up to $10.76 billion per occurrence. Under the current provisions
of the Price Anderson Act, which limits liability for accidents at nuclear
power plants, each company, as an owner of nuclear units, can be assessed a
portion of any third-party liability claims arising from an accident at any
commercial nuclear power plant in the United States. In the event that
public liability claims from an insured nuclear incident exceed $300
million (currently available through commercial insurers), each company
would be subject to assessments of up to $101 million for each reactor
owned per occurrence. Payment of such assessments would be made over time
as necessary to limit the payment in any one year to no more than $10
million per reactor owned. Congress is considering revisions to the Price
Anderson Act during 2004 that could include increased limits and
assessments per reactor owned. The final outcome of this matter cannot be
predicted at this time.
PEC and PEF self-insure their transmission and distribution lines against
loss due to storm damage and other natural disasters. PEF accrues $6
million annually to a storm damage reserve pursuant to a regulatory order
and may defer losses in excess of the reserve.
22
C. Claims and Uncertainties
The Company is subject to federal, state and local regulations addressing
hazardous and solid waste management, air and water quality and other
environmental matters.
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. Both electric utilities and other
potentially responsible parties (PRPs) are participating in, investigating
and, if necessary, remediating former MGP sites with several regulatory
agencies, including, but not limited to, the U.S. Environmental Protection
Agency (EPA), 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, PEF and Progress Fuels Corporation 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. While the Company cannot predict the
outcome of these matters, the outcome is not expected to have a material
effect on the consolidated financial position or results of operations.
The Company is also currently in the process of assessing potential costs
and exposures at other 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.
PEC There are nine former MGP sites and other sites associated with PEC
that have required or are anticipated to require investigation and/or
remediation costs. PEC received insurance proceeds to address costs
associated with environmental liabilities related to its involvement with
some sites. All eligible expenses related to these are charged against a
specific fund containing these proceeds. At June 30, 2004, approximately $8
million remains in this centralized fund with a related accrual of $8
million recorded for the associated expenses of environmental issues. PEC
is unable to provide an estimate of the reasonably possible total
remediation costs beyond what is currently accrued due to the fact that
investigations have not been completed at all sites. This accrual has been
recorded on an undiscounted basis. PEC measures its liability for these
sites based on available evidence including its experience in investigating
and remediating environmentally impaired sites. The process often involves
assessing and developing cost-sharing arrangements with other PRPs. PEC
will accrue costs for the sites to the extent its liability is probable and
the costs can be reasonably estimated. 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, all of which also are associated with
PEC, to state standards pursuant to an Administrative Order on Consent.
These sites are anticipated to have investigation or remediation costs
associated with them. NCNG had previously accrued approximately $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 PEC. PEC does not believe it can provide an estimate of the
reasonably possible total remediation costs beyond the accrual because
investigations have not been completed at all sites. Therefore, PEC cannot
currently determine the total costs that may be incurred in connection with
the investigation and/or remediation of all sites.
23
PEF At June 30, 2004, PEF has accrued $27 million for probable and
estimable costs related to various environmental sites. Of this accrual,
$17 million is for costs associated with the remediation of distribution
and substation transformers for which PEF has received approval from the
FPSC for recovery through the Environmental Cost Recovery Clause (ECRC).
For the six months ended June 30, 2004, PEF accrued an additional $8
million related to the remediation of transformers and a regulatory asset
for the probable recovery through the ECRC. The remaining $10 million is
related to two former MGP sites and other sites associated with PEF that
have required or are anticipated to require investigation and/or
remediation costs. PEF is unable to provide an estimate of the reasonably
possible total remediation costs beyond what is currently accrued.
These accruals have been recorded on an undiscounted basis. PEF measures
its liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
This process often includes assessing and developing cost-sharing
arrangements with other PRPs. Presently, PEF cannot determine the total
costs that may be incurred in connection with the remediation of all sites.
As more activity occurs at these sites, PEF will assess the need to adjust
the accruals.
Florida Progress Corporation (FPC) In 2001, FPC sold its Inland Marine
Transportation business operated by MEMCO Barge Line, Inc. to AEP
Resources, Inc. FPC established an accrual to address indemnities and
retained an environmental liability associated with the transaction. FPC
estimates that its contractual liability to AEP Resources, Inc., associated
with Inland Marine Transportation, is $4 million at June 30, 2004 and has
accrued such amount. The previous accrual of $10 million was reduced in
2003 based on a change in estimate. This accrual has been determined on an
undiscounted basis. FPC measures its liability for this site based on
estimable and probable remediation scenarios.
Certain historical sites exist that are being addressed voluntarily by FPC.
An immaterial accrual has been established to address investigation
expenses related to these sites. The Company cannot determine the total
costs that may be incurred in connection with these sites.
Rail Rail Services is voluntarily addressing certain historical waste
sites. The Company cannot determine the total costs that may be incurred in
connection with these sites.
Air Quality
There has been and may be further proposed legislation requiring reductions
in air emissions for NOx, SO2, carbon dioxide and mercury. Some of these
proposals establish nationwide caps and emission rates over an extended
period of time. This national multi-pollutant approach to air pollution
control could involve significant capital costs which could be material to
the Company's consolidated financial position or results of operations.
Control equipment that will be installed on North Carolina fossil
generating facilities as part of the North Carolina legislation discussed
below may address some of the issues outlined above. However, the Company
cannot predict the outcome of this matter.
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
Both PEC and PEF were asked to provide information to the EPA as part of
this initiative and cooperated in providing the requested information. The
EPA initiated civil enforcement actions against other unaffiliated
utilities as part of this initiative. Some of these actions resulted in
settlement agreements calling for expenditures by these unaffiliated
utilities, ranging from $1.0 billion to $1.4 billion. A utility that was
not subject to a civil enforcement action settled its New Source Review
issues with the EPA for $300 million. These settlement agreements have
generally called for expenditures to be made over extended time periods,
and some of the companies may seek recovery of the related cost through
rate adjustments or similar mechanisms. The Company cannot predict the
outcome of this matter.
24
In 2003, the EPA published a final rule addressing routine equipment
replacement under the New Source Review program. The rule defines routine
equipment replacement and the types of activities that are not subject to
New Source Review requirements or New Source Performance Standards under
the Clean Air Act. The rule was challenged in the Federal Appeals Court and
its implementation stayed. In July 2004, the EPA announced it will
reconsider certain issues arising from the final routine equipment
replacement rule. Reconsideration does not impact the court-approved stay.
The agency plans to issue a final decision on these reconsidered issues by
year end. The Company cannot predict the outcome of this matter.
In 1998, the EPA published a final rule at Section 110 of the Clean Air Act
addressing the regional transport of ozone (NOx SIP Call). The EPA's rule
requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, but not Florida, to further reduce NOx emissions in order to
attain a preset emission level during each year's "ozone season," beginning
May 31, 2004. The EPA rule allows credit to companies taking early action
to meet the May 31, 2004 deadline. PEC is currently installing controls
necessary to comply with the rule and, with the use of early action
credits, expects to be in compliance as required by the final rule. Total
capital expenditures to meet these measures in North and South Carolina
could reach approximately $370 million, which has not been adjusted for
inflation. The Company has spent approximately $265 million to date related
to these expenditures. Increased operation and maintenance costs relating
to the NOx SIP Call are not expected to be material to the Company's
results of operations. Further controls are anticipated as electricity
demand increases.
In 1997, the EPA issued final regulations establishing a new 8-hour ozone
standard. In 1999, the District of Columbia Circuit Court of Appeals ruled
against the EPA with regard to the federal 8-hour ozone standard. The U.S.
Supreme Court has upheld, in part, the District of Columbia Circuit Court
of Appeals' decision. In April 2004, the EPA identified areas that do not
meet the standard. The states with identified areas, including North and
South Carolina are proceeding with the implementation of the federal 8-hour
ozone standard. Both states promulgated final regulations, which will
require PEC to install NOx controls under the states' 8-hour standard. The
costs of those controls are included in the $370 million cost estimate
above. However, further technical analysis and rulemaking may result in a
requirement for additional controls at some units. The Company cannot
predict the outcome of this matter.
In June 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of NOx and SO2 from
coal-fired power plants. Progress Energy expects its capital costs to meet
these emission targets will be approximately $813 million by 2013. PEC has
expended approximately $45 million of these capital costs through June 30,
2004. PEC currently has approximately 5,100 MW of coal-fired generation
capacity in North Carolina that is affected by this legislation. The law
requires the emissions reductions to be completed in phases by 2013, and
applies to each utility's total system rather than setting requirements for
individual power plants. The law also freezes the utilities' base rates for
five years unless there are extraordinary events beyond the control of the
utilities or unless the utilities persistently earn a return substantially
in excess of the rate of return established and found reasonable by the
NCUC in the utilities' last general rate case. Further, the law allows the
utilities to recover from their retail customers the projected capital
costs during the first seven years of the ten-year compliance period
beginning on January 1, 2003. The utilities must recover at least 70% of
their projected capital costs during the five-year rate freeze period. PEC
recognized amortization of $15 million and $34 million in the quarters
ended June 30, 2004 and 2003, respectively. PEC recognized amortization of
$31 million and $54 million in the six months ended June 30, 2004 and 2003,
respectively. Pursuant to the law, PEC entered into an agreement with the
state of North Carolina to transfer to the state certain NOx and SO2
emissions allowances that result from compliance with the collective NOx
and SO2 emissions limitations set out in the law. The law also requires the
state to undertake a study of mercury and carbon dioxide emissions in North
Carolina. Operation and maintenance costs will increase due to the
additional personnel, materials and general maintenance associated with the
equipment. Operation and maintenance expenses are recoverable through base
rates, rather than as part of this program. Progress Energy cannot predict
the future regulatory interpretation, implementation or impact of this law.
25
In 1997, the EPA's Mercury Study Report and Utility Report to Congress
conveyed that mercury is not a risk to the average American and expressed
uncertainty about whether reductions in mercury emissions from coal-fired
power plants would reduce human exposure. Nevertheless, the EPA determined
in 2000 that regulation of mercury emissions from coal-fired power plants
was appropriate. In 2003, the EPA proposed alternative control plans that
would limit mercury emissions from coal-fired power plants. The first, a
Maximum Achievable Control Technology (MACT) standard applicable to every
coal-fired plant, would require compliance in 2008. The second, which the
EPA has stated it prefers, is a mercury cap and trade program that would
require limits to be met in two phases, 2010 and 2018. The EPA expects to
finalize the mercury rule in March 2005. Achieving compliance with the
proposal could involve significant capital costs which could be material
and adverse to the Company's consolidated financial position or results of
operations. The Company cannot predict the outcome of this matter.
In conjunction with the proposed mercury rule, the EPA proposed a MACT
standard to regulate nickel emissions from residual oil-fired units. The
agency estimates the proposal will reduce national nickel emissions to
approximately 103 tons. The EPA expects to finalize the nickel rule in
March 2005. The Company cannot predict the outcome of this matter.
In December 2003, the EPA released its proposed Interstate Air Quality
Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The
EPA's proposal requires 28 jurisdictions, including North Carolina, South
Carolina, Georgia and Florida, to further reduce NOx and SO2 emissions in
order to attain preset state NOx and SO2 emissions levels. The rule is
expected to become final in 2004. The air quality controls already
installed for compliance with the NOx SIP Call and currently planned by the
Company for compliance with the North Carolina law will reduce the costs
required to meet the CAIR requirements for the Company's North Carolina
units. Additional compliance costs will be determined later this year once
the rule is finalized.
In March 2004, the North Carolina Attorney General filed a petition with
the EPA under Section 126 of the Clean Air Act, asking the federal
government to force coal-fired power plants in thirteen other states,
including South Carolina to reduce their NOx and SO2 emissions. The state
of North Carolina contends these out-of-state polluters are interfering
with North Carolina's ability to meet national air quality standards for
ozone and particulate matter. The EPA has not made a determination on the
Section 126 petition, and the Company cannot predict the outcome of this
matter.
Water Quality
As a result of the operation of certain control equipment needed to address
the air quality issues outlined above, new wastewater streams may be
generated at the applicable facilities. Integration of these new wastewater
streams into the existing wastewater treatment processes may result in
permitting, construction and treatment requirements imposed on PEC and PEF
in the immediate and extended future.
After many years of litigation and settlement negotiations the EPA adopted
regulations in February 2004 for the implementation of Section 316(b) of
the Clean Water Act. These regulations become effective September 7, 2004.
The purpose of these regulations is to minimize adverse environmental
impacts caused by cooling water intake structures and intake systems. Over
the next several years these regulations will impact the larger base load
generation facilities and may require the facilities to mitigate the
effects to aquatic organisms by constructing intake modifications or
undertaking other restorative activities. Substantial costs could be
incurred by the facilities in order to comply with the new regulation. The
Company cannot predict the outcome and impacts to the facilities at this
time.
The EPA has published for comment a draft Environmental Impact Statement
(EIS) for surface coal mining (sometimes referred to as "mountaintop
mining") and valley fills in the Appalachian coal region, where Progress
Fuels currently operates a surface mine and may operate others in the
future. The final EIS, when published, may affect regulations for the
permitting of mining operations and the cost of compliance with
environmental regulations. Regulatory changes for mining may also affect
the cost of fuel for the coal-fueled electric generating plants. The
Company cannot predict the outcome of this matter.
26
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 has stated it 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 the Company's
consolidated financial position or results of 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.
Other Contingencies
1. As required under the Nuclear Waste Policy Act of 1982, PEC and PEF each
entered into a contract with the United States Department of Energy (DOE)
under which the DOE agreed to begin taking spent nuclear fuel by no later
than January 31, 1998. All similarly situated utilities were required to
sign the same standard contract.
In 1995, the DOE issued a final interpretation that it did not have an
unconditional obligation to take spent nuclear fuel by January 31, 1998. In
Indiana Michigan Power v. DOE, the Court of Appeals vacated the DOE's final
interpretation and ruled that the DOE had an unconditional obligation to
begin taking spent nuclear fuel. The Court did not specify a remedy because
the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana Michigan Power
v. DOE, a group of utilities petitioned the Court of Appeals in Northern
States Power (NSP) v. DOE, seeking an order requiring the DOE to begin
taking spent nuclear fuel by January 31, 1998. The DOE took the position
that their delay was unavoidable, and the DOE was excused from performance
under the terms and conditions of the contract. The Court of Appeals found
that the delay was not unavoidable, but did not order the DOE to begin
taking spent nuclear fuel, stating that the utilities had a potentially
adequate remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31,
1998, a group of utilities filed a motion with the Court of Appeals to
enforce the mandate in NSP v. DOE. Specifically, this group of utilities
asked the Court to permit the utilities to escrow their waste fee payments,
to order the DOE not to use the waste fund to pay damages to the utilities,
and to order the DOE to establish a schedule for disposal of spent nuclear
fuel. The Court denied this motion based primarily on the grounds that a
review of the matter was premature, and that some of the requested remedies
fell outside of the mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal
Circuit) ruled that utilities may sue the DOE for damages in the Federal
Court of Claims instead of having to file an administrative claim with the
DOE.
In January 2004, PEC and PEF filed a complaint with the DOE claiming that
the DOE breached the Standard Contract for Disposal of Spent Nuclear Fuel
by failing to accept spent nuclear fuel from various Progress Energy
facilities on or before January 31, 1998. Damages due to DOE's breach will
likely exceed $100 million. Similar suits have been initiated by over two
dozen other utilities.
In July 2002, Congress passed an override resolution to Nevada's veto of
DOE's proposal to locate a permanent underground nuclear waste storage
facility at Yucca Mountain, Nevada. DOE plans to submit a license
application for the Yucca Mountain facility by the end of 2004. In November
2003, Congressional negotiators approved $580 million for fiscal year 2004
for the Yucca Mountain project, $123 million more than the previous year.
In January 2003, the State of Nevada, Clark County, Nevada, and the City of
Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia
Circuit for review of the Congressional override resolution. On July 9,
2004, the Court rejected the challenge to the constitutionality of the
resolution approving Yucca Mountain, but ruled that the EPA was wrong to
set a 10,000-year compliance period. The DOE continues to state it plans to
begin operation of the repository at Yucca Mountain in 2010. PEC and PEF
cannot predict the outcome of this matter.
27
With certain modifications and additional approval by the NRC including the
installation of onsite dry storage facilities at Robinson (2005) and
Brunswick (2010), PEC's spent nuclear fuel storage facilities will be
sufficient to provide storage space for spent fuel generated on PEC's
system through the expiration of the operating licenses for all of PEC's
nuclear generating units.
PEF is currently storing spent nuclear fuel onsite in spent fuel pools.
PEF's nuclear unit, Crystal River Unit No. 3 (CR3), has sufficient storage
capacity in place for fuel consumed through the end of the expiration of
the current license in 2016. PEF will seek renewal of the CR3 operating
license and if approved, additional dry storage may be necessary.
2. In November 2001, Strategic Resource Solutions Corp. (SRS) filed a claim
against the San Francisco Unified School District (the District) and other
defendants claiming that SRS is entitled to approximately $10 million in
unpaid contract payments and delay and impact damages related to the
District's $30 million contract with SRS. In March 2002, the District filed
a counterclaim, seeking compensatory damages and liquidated damages in
excess of $120 million, for various claims, including breach of contract
and demand on a performance bond. SRS asserted defenses to the District's
claims. SRS amended its claims and asserted new claims against the District
and other parties, including a former SRS employee and a former District
employee.
In March 2003, the City Attorney and the District filed new claims in the
form of a cross-complaint against SRS, Progress Energy, Inc., Progress
Energy Solutions, Inc., and certain individuals, alleging fraud, false
claims, violations of California statutes, and seeking compensatory
damages, punitive damages, liquidated damages, treble damages, penalties,
attorneys' fees and injunctive relief. The filing stated that the City and
the District seek "more than $300 million in damages and penalties." PEC
was later added as a cross-defendant. In November 2003, PEC filed a motion
to dismiss the plaintiffs' first amended complaint.
In June 2004, the Company reached a settlement agreement with the District
in this matter. The settlement totaled approximately $43.1 million and is
included in diversified business cost of sales in the accompanying
Consolidated Statement of Income for the three-months and six-months ended
June 30, 2004. The accrual of the settlement was recorded on an
undiscounted basis. The terms of the settlement require SRS to pay the
District $10.1 million upon approval, and an additional $16 million in 2005
and $17 million 2006. In addition, during a transition period ending
September 10, 2004, SRS will provide maintenance and training on the
equipment and software it installed and maintained for the District. The
agreement, upon approval, settles all claims and cross-claims related to
SRS, Progress Energy, Progress Energy Solutions and PEC.
3. In August 2003, PEC was served as a co-defendant in a purported class
action lawsuit styled as Collins v. Duke Energy Corporation et al, 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 nonutility third
parties or telecommunication companies for other than the electric
utilities' internal use along the electric right-of-way constitutes a
trespass.
In September 2003, PEC filed a motion to dismiss all counts of the
complaint on substantive and procedural grounds. In October 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. In
March 2004, the plaintiffs in this case filed a notice of dismissal without
prejudice of their claims against PEC and Duke Energy Corporation.
4. In 2001, PEC entered into a contract to purchase coal from Dynegy
Marketing and Trade (DMT). After DMT experienced financial difficulties,
including credit ratings downgrades by certain credit reporting agencies,
PEC requested credit enhancements in accordance with the terms of the coal
purchase agreement in July 2002. When DMT did not offer credit
enhancements, as required by a provision in the contract, PEC terminated
the contract in July 2002.
28
PEC initiated a lawsuit seeking a declaratory judgment that the termination
was lawful. DMT counterclaimed, stating the termination was a breach of
contract. On March 23, 2004, the United States District Court for the
Eastern District of North Carolina ruled that PEC was liable for breach of
contract, but ruled against DMT on its unfair and deceptive trade practices
claim. On April 6, 2004, the Court entered a judgment against PEC in the
amount of approximately $10 million. The Court did not rule on DMT's
pending motion for attorneys' fees.
On May 4, 2004, PEC authorized its outside counsel to file a notice of
appeal of the April 6, 2004, judgment and on May 7, 2004, the notice of
appeal was filed with the United States Court of Appeals for the Fourth
Circuit. On June 8, 2004, DMT filed a motion to dismiss the appeal in the
appeals court on the ground that PEC's notice of appeal should have been
filed on or before May 6, 2004. On June 16, 2004, PEC filed a motion with
the trial court requesting an extension of the deadline for the filing of
the notice of appeal. On July 7, 2004, the parties agreed to postpone the
appellate proceedings to allow the trial court to resolve PEC's motion for
an extension of the notice of appeal deadline.
PEC recorded a liability for the judgment of approximately $10 million and
a regulatory asset for the probable recovery through its fuel adjustment
clause in the first quarter of 2004. The Company cannot predict the outcome
of this matter.
5. The Company, through its subsidiaries, is a majority owner in five
entities and a minority owner in one entity that owns facilities that
produce synthetic fuel as defined under the Internal Revenue Code (Code).
The production and sale of the synthetic fuel from these facilities
qualifies for tax credits under Section 29 if certain requirements are
satisfied, including a requirement that the synthetic fuel differs
significantly in chemical composition from the coal used to produce such
synthetic fuel and that the fuel was produced from a facility that was
placed in service before July 1, 1998. Synthetic fuel tax credit amounts
not utilized are carried forward indefinitely as alternative minimum tax
credits. All entities have received private letter rulings (PLRs) from the
Internal Revenue Service (IRS) with respect to their synthetic fuel
operations. The PLRs do not limit the production on which synthetic fuel
credits may be claimed. Total Section 29 credits generated to date
(including those generated by FPC prior to its acquisition by the Company)
are approximately $1.4 billion, of which $584 million have been used and
$807 million are being carried forward as deferred tax credits. The current
Section 29 tax credit program expires at the end of 2007.
In September 2002, all of Progress Energy's majority-owned synthetic fuel
entities were accepted into the IRS's Pre-Filing Agreement (PFA) program.
The PFA program allows taxpayers to voluntarily accelerate the IRS exam
process in order to seek resolution of specific issues. Either the Company
or the IRS can withdraw from the program at any time, and issues not
resolved through the program may proceed to the next level of the IRS exam
process.
In July 2004, Progress Energy was notified that the Internal Revenue
Service (IRS) field auditors anticipate taking an adverse position
regarding the placed-in-service date of the Company's four Earthco
synthetic fuel facilities. Due to the auditors' position, the IRS has
decided to exercise its right to withdraw from the Pre-Filing Agreement
(PFA) program with Progress Energy. With the IRS's withdrawal from the PFA
program, the review of Progress Energy's Earthco facilities is back on the
normal procedural audit path of the Company's tax returns. The IRS has
indicated that the field audit team will provide its written recommendation
later this year. After the field audit team's written recommendation is
received, the Company will begin the Appeals process within the IRS.
Through June 30, 2004 the Company, on a consolidated basis, has claimed $1
billion of tax credits generated by Earthco facilities. If these credits
were disallowed, the Company's one time exposure for cash tax payments
would be $229 million (excluding interest), and earnings and equity would
be reduced by $1 billion, excluding interest. The Company believes that the
appeals process could take up to two years to complete, however, it cannot
control the actual timing of resolution and cannot predict the outcome of
this matter.
In February 2004, subsidiaries of the Company finalized execution of the
Colona Closing Agreement with the IRS concerning their Colona synthetic
fuel facilities. The Colona Closing Agreement provided that the Colona
facilities were placed in service before July 1, 1998, which is one of the
qualification requirements for tax credits under Section 29. The Colona
Closing Agreement further provides that the fuel produced by the Colona
facilities in 2001 is a "qualified fuel" for purposes of the Section 29 tax
credits. This action concluded the IRS PFA program with respect to Colona.
29
In October 2003, the United States Senate Permanent Subcommittee on
Investigations began a general investigation concerning synthetic fuel tax
credits claimed under Section 29. The investigation is examining the
utilization of the credits, the nature of the technologies and fuels
created, the use of the synthetic fuel and other aspects of Section 29 and
is not specific to the Company's synthetic fuel operations. Progress Energy
is providing information in connection with this investigation. The Company
cannot predict the outcome of this matter.
In management's opinion, the Company is complying with all the necessary
requirements to be allowed such credits under Section 29, and, although it
cannot provide certainty, it believes that it will prevail in these
matters. Accordingly, the Company has no current plans to alter its
synthetic fuel production schedule as a result of these matters. However,
should the Company fail to prevail in these matters, there could be
material liability for previously taken Section 29 credits, with a material
adverse impact on earnings and cash flows.
6. The Company and its subsidiaries are involved in various litigation
matters in the ordinary course of business, some of which involve
substantial amounts. Where appropriate, accruals and disclosures have been
made in accordance with SFAS No. 5, "Accounting for Contingencies," to
provide for such matters. In the opinion of management, the final
disposition of pending litigation would not have a material adverse effect
on the Company's consolidated results of operations or financial position.
30
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED INTERIM FINANCIAL STATEMENTS
June 30, 2004
UNAUDITED CONSOLIDATED STATEMENTS of INCOME
Three Months Ended June 30 Six Months Ended June 30
(in millions) 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 861 $ 816 $ 1,762 $ 1,742
Diversified business 1 3 1 6
- -------------------------------------------------------------------------------------------------------
Total Operating Revenues 862 819 1,763 1,748
- -------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 193 177 417 403
Purchased power 80 69 142 142
Operation and maintenance 226 210 435 400
Depreciation and amortization 127 142 254 281
Taxes other than on income 45 35 88 79
Diversified business - 2 - 3
- -------------------------------------------------------------------------------------------------------
Total Operating Expenses 671 635 1,336 1,308
- -------------------------------------------------------------------------------------------------------
Operating Income 191 184 427 440
- -------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 1 2 2 3
Other, net 4 (8) (8) (10)
- -------------------------------------------------------------------------------------------------------
Total Other Income (Expense) 5 (6) (6) (7)
- -------------------------------------------------------------------------------------------------------
Interest Charges
Interest charges 47 49 96 98
Allowance for borrowed funds used during construction - (1) (1) (2)
- -------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 47 48 95 96
- -------------------------------------------------------------------------------------------------------
Income before Income Tax 149 130 326 337
Income Tax Expense 53 41 115 113
- -------------------------------------------------------------------------------------------------------
Net Income 96 89 211 224
Preferred Stock Dividend Requirement - - 1 1
- -------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 96 $ 89 $ 210 $ 223
- -------------------------------------------------------------------------------------------------------
See Notes to Consolidated Interim Financial Statements.
31
CAROLINA POWER & Light Company
d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONSOLIDATED BALANCE SHEETS
(in millions) June 30 December 31
ASSETS 2004 2003
- -------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 13,516 $ 13,331
Accumulated depreciation (5,390) (5,258)
- -------------------------------------------------------------------------------------------------------
Utility plant in service, net 8,126 8,073
Held for future use 5 5
Construction work in progress 294 306
Nuclear fuel, net of amortization 161 159
- -------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 8,586 8,543
- -------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 44 238
Accounts receivable 253 265
Unbilled accounts receivable 146 145
Receivables from affiliated companies 11 27
Inventory 307 348
Deferred fuel cost 126 113
Prepayments and other current assets 57 82
- -------------------------------------------------------------------------------------------------------
Total Current Assets 944 1,218
- -------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 506 477
Nuclear decommissioning trust funds 542 505
Miscellaneous other property and investments 169 169
Other assets and deferred debits 115 118
- -------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 1,332 1,269
- -------------------------------------------------------------------------------------------------------
Total Assets $ 10,862 $ 11,030
- -------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- -------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, authorized 200 million shares,
160 million shares issued and outstanding $ 1,971 $ 1,953
Unearned ESOP common stock (76) (89)
Accumulated other comprehensive loss (4) (7)
Retained earnings 1,361 1,380
- -------------------------------------------------------------------------------------------------------
Total Common Stock Equity 3,252 3,237
- -------------------------------------------------------------------------------------------------------
Preferred Stock - Not Subject to Mandatory Redemption 59 59
Long-Term Debt, Net 2,748 3,086
- -------------------------------------------------------------------------------------------------------
Total Capitalization 6,059 6,382
- -------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 300 300
Accounts payable 181 188
Payables to affiliated companies 77 136
Notes payable to affiliated companies 26 25
Interest accrued 57 64
Short-term obligations 68 4
Other current liabilities 229 166
- -------------------------------------------------------------------------------------------------------
Total Current Liabilities 938 883
- -------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,132 1,125
Accumulated deferred investment tax credits 145 148
Regulatory liabilities 1,262 1,197
Asset retirement obligations 959 932
Other liabilities and deferred credits 367 363
- -------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,865 3,765
- -------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 10)
- -------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 10,862 $ 11,030
- -------------------------------------------------------------------------------------------------------
See Notes to Consolidated Interim Financial Statements.
32
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
UNAUDITED CONSOLIDATED STATEMENTS of CASH FLOWS
Six Months Ended June 30
(in millions) 2004 2003
- ---------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 211 $ 224
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 297 326
Deferred income taxes 4 (38)
Investment tax credit (4) (5)
Deferred fuel cost (13) 9
Cash provided (used) by changes in operating assets and liabilities:
Accounts receivable 23 35
Inventories 32 (1)
Prepayments and other current assets 8 14
Accounts payable (50) 2
Other current liabilities 61 58
Other 53 42
- ---------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 622 666
- ---------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (248) (259)
Nuclear fuel additions (47) (46)
Contributions to nuclear decommissioning trust (18) (18)
Other investing activities - (4)
- ---------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (313) (327)
- ---------------------------------------------------------------------------------------------------------------
Financing Activities
Net increase (decrease) in short-term obligations 64 (74)
Net change in intercompany notes 1 99
Retirement of long-term debt (339) (165)
Dividends paid to parent (228) (203)
Dividends paid on preferred stock (1) (1)
- ---------------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (503) (344)
- ---------------------------------------------------------------------------------------------------------------
Net Decrease in Cash and Cash Equivalents (194) (5)
Cash and Cash Equivalents at Beginning of Period 238 18
- ----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 44 $ 13
- ---------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 100 $ 95
income taxes (net of refunds) $ 82 $ 120
- ----------------------------------------------------------------------------------------------------------------
See Notes to 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
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)
is a public service corporation primarily engaged in the generation,
transmission, distribution and sale of electricity in portions of North
Carolina and South Carolina. Through its wholly-owned subsidiaries, PEC is
also involved in nonregulated business activities. PEC is a wholly-owned
subsidiary of Progress Energy, Inc. (the Company or Progress Energy). The
Company is a registered holding company under the Public Utility Holding
Company Act of 1935 (PUHCA). Both the Company and its subsidiaries are
subject to the regulatory provisions of PUHCA. PEC is regulated by the
North Carolina Utilities Commission (NCUC), the Public Service Commission
of South Carolina (SCPSC), the Federal Energy Regulatory Commission (FERC)
and the United States Nuclear Regulatory Commission (NRC).
B. Basis of Presentation
These financial statements have been prepared in accordance with accounting
principles generally accepted in the United States of America (GAAP) for
interim financial information and with the instructions to Form 10-Q and
Regulation S-X. Accordingly, they do not include all of the information and
footnotes required by GAAP for annual statements. Because the accompanying
consolidated interim financial statements do not include all of the
information and footnotes required by GAAP, they should be read in
conjunction with the audited financial statements for the period ended
December 31, 2003 and notes thereto included in PEC's Form 10-K for the
year ended December 31, 2003.
PEC collects from customers certain excise taxes, which include gross
receipts tax, franchise taxes, and other excise taxes, levied by the state
or local government upon the customers. PEC accounts for excise taxes on a
gross basis. For the three months ended June 30, 2004 and 2003, excise
taxes of approximately $23 million and $18 million, respectively, are
included in taxes other than income in the accompanying Consolidated
Statements of Income. For the six months ended June 30, 2004 and 2003,
excise taxes of approximately $45 million and $40 million, respectively,
are included in taxes other than income in the accompanying Consolidated
Statements of Income. These approximate amounts are also included in
utility revenues.
The amounts included in the consolidated interim financial statements are
unaudited but, in the opinion of management, reflect all normal recurring
adjustments necessary to fairly present PEC's financial position and
results of operations for the interim periods. Due to seasonal weather
variations and the timing of outages of electric generating units,
especially nuclear-fueled units, the results of operations for interim
periods are not necessarily indicative of amounts expected for the entire
year or future periods.
In preparing financial statements that conform with GAAP, management must
make estimates and assumptions that affect the reported amounts of assets
and liabilities, disclosure of contingent assets and liabilities at the
date of the financial statements and amounts of revenues and expenses
reflected during the reporting period. Actual results could differ from
those estimates. Certain amounts for 2003 have been reclassified to conform
to the 2004 presentation.
C. Stock-Based Compensation
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" (SFAS No. 148), the estimated fair
value of the Company's stock options is amortized to expense over the
options' vesting period. The following table illustrates the effect on net
income and earnings per share if the fair value method had been applied to
all outstanding and unvested awards in each period:
34
Three Months Ended Six Months Ended
June 30 June 30
-------------------- ---------------------
(in millions) 2004 2003 2004 2003
---------- --------- --------- -----------
Net Income, as reported $ 96 $ 89 $ 211 $ 224
Deduct: Total stock option expense determined under
fair value method for all awards, net of related tax 2 1 4 2
effects
---------- --------- --------- -----------
Pro forma net income $ 94 $ 88 $ 207 $ 222
========== ========= ========= ===========
D. Consolidation of Variable Interest Entities
PEC consolidates all voting interest entities in which it owns a majority
voting interest and all variable interest entities for which it is the
primary beneficiary in accordance with FASB Interpretation No. 46R,
"Consolidation of Variable Interest Entities - an Interpretation of ARB No.
51" (FIN No. 46R). During the first six months of 2004 and 2003, PEC did
not participate in the creation of, or obtain a significant new variable
interest in, any variable interest entity.
PEC is the primary beneficiary of a limited partnership which invests in 17
low-income housing partnerships that qualify for federal and state tax
credits. PEC has requested but has not received all the necessary
information to determine the primary beneficiary of the limited
partnership's underlying 17 partnership investments, and has applied the
information scope exception in FIN No. 46R, paragraph 4(g) to the 17
partnerships. PEC has no direct exposure to loss from the 17 partnerships;
PEC's only exposure to loss is from its investment of approximately $1
million in the consolidated limited partnership. PEC will continue its
efforts to obtain the necessary information to fully apply FIN No. 46R to
the 17 partnerships. PEC believes that if the limited partnership is
determined to be the primary beneficiary of the 17 partnerships, the effect
of consolidating the 17 partnerships would not be significant to PEC's
Consolidated Balance Sheets.
PEC has variable interests in two power plants resulting from long-term
power purchase contracts. PEC has requested the necessary information to
determine if the counterparties are variable interest entities or to
identify the primary beneficiaries. Both entities declined to provide PEC
with the necessary financial information, and PEC has applied the
information scope exception in FIN No. 46R, paragraph 4(g). PEC's only
significant exposure to variability from these contracts results from
fluctuations in the market price of fuel used by the two entities' plants
to produce the power purchased by PEC. PEC is able to recover these fuel
costs under its fuel clause. Total purchases from these counterparties were
approximately $21 million and $19 million in the first six months of 2004
and 2003, respectively. PEC will continue its efforts to obtain the
necessary information to fully apply FIN No. 46R to these contracts. The
combined generation capacity of the two entities' power plants is
approximately 880 MW. PEC believes that if it is determined to be the
primary beneficiary of these two entities, the effect of consolidating the
entities would result in increases to total assets, long-term debt and
other liabilities, but would have an insignificant or no impact on PEC's
common stock equity, net earnings, or cash flows. However, as PEC has not
received any financial information from these two counterparties, the
impact cannot be determined at this time.
PEC also has interests in several other variable interest entities for
which PEC is not the primary beneficiary. These arrangements include
investments in approximately 22 limited partnerships, limited liability
corporations and venture capital funds and two building leases with
special-purpose entities. The aggregate maximum loss exposure at June 30,
2004, that PEC could be required to record in its income statement as a
result of these arrangements totals approximately $23 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.
35
2. NEW ACCOUNTING STANDARDS
In December 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the Act) was signed into law. In accordance with
guidance issued by the FASB in FASB Staff Position FAS 106-1, PEC elected
to defer accounting for the effects of the Act due to uncertainties
regarding the effects of the implementation of the Act and the accounting
for certain provisions of the Act. Therefore, OPEB information presented in
the financial statements does not reflect the effects of the Act. The FASB
recently issued definitive accounting guidance for the Act in FASB Staff
Position 106-2, which is effective for PEC in the third quarter of 2004.
FASB Staff Position 106-2 will result in the recognition of lower OPEB
costs to reflect prescription drug-related federal subsidies to be received
under the Act. PEC is in the process of quantifying the impact of the Act
on OPEB costs.
3. REGULATORY MATTERS
A. Retail Rate Matters
PEC has exclusively utilized external funding for its decommissioning
liability since 1994. Prior to 1994, PEC retained funds internally to meet
its decommissioning liability. An NCUC order issued in February 2004 found
that by January 1, 2008 PEC must begin transitioning these amounts to
external funds. The transition of $131 million must be completed by
December 31, 2017, and at least 10% must be transitioned each year.
PEC filed with the SCPSC seeking permission to defer expenses incurred from
the first quarter 2004 winter storm. The SCPSC approved PEC's request to
defer the costs and amortize them ratably over five years beginning in
January 2005. Approximately $10 million related to storm costs incurred
during the first quarter of 2004 was deferred in that quarter.
During the first quarter of 2004, PEC met the requirements of both the NCUC
and the SCPSC for the implementation of a depreciation study which allowed
the utility to reduce the rates used to calculate depreciation expense. As
a result, depreciation expense decreased $10 million for the three months
ended June 30, 2004 compared to the prior year quarter and decreased $18
million for the six months ended June 30, 2004 compared to the prior year
six month period.
B. Regional Transmission Organizations
In 2000, the FERC issued Order No. 2000 on RTOs, which set minimum
characteristics and functions that RTOs must meet, including independent
transmission service. In July 2002, the FERC issued its Notice of Proposed
Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination
through Open Access Transmission Service and Standard Electricity Market
Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD
NOPR would materially alter the manner in which transmission and generation
services are provided and paid for. In April 2003, the FERC released a
White Paper on the Wholesale Market Platform. The White Paper provides an
overview of what the FERC currently intends to include in a final rule in
the SMD NOPR docket. The White Paper retains the fundamental and most
protested aspects of SMD NOPR, including mandatory RTOs and the FERC's
assertion of jurisdiction over certain aspects of retail service. The FERC
has not yet issued a final rule on SMD NOPR. PEC cannot predict the outcome
of these matters or the effect that they may have on the GridSouth
proceedings currently ongoing before the FERC. It is unknown what impact
the future proceedings will have on PEC's earnings, revenues or prices.
PEC has $33 million invested in GridSouth related to startup costs at June
30, 2004. PEC expects to recover these startup costs in conjunction with
the GridSouth original structure or in conjunction with any alternate
combined transmission structures that emerge.
C. Implementation of SFAS No. 143
In connection with the implementation of SFAS No. 143 in 2003, PEC filed a
request with the NCUC requesting deferral of the difference between expense
pursuant to SFAS No. 143 and expense as previously determined by the NCUC.
The NCUC granted the deferral of the January 1, 2003 cumulative adjustment.
Because the clean air legislation discussed in Note 12 under "Air Quality"
contained a prohibition against cost deferrals unless certain criteria are
met, the NCUC denied the deferral of the ongoing effects. Since the NCUC
36
order denied deferral of the ongoing effects, PEC ceased deferral of the
ongoing effects during the second quarter for the six months ended June 30,
2003 related to its North Carolina retail jurisdiction. Pre-tax income for
the three and six months ended June 30, 2003 increased by approximately $14
million, which represents a decrease in non-ARO cost of removal expense,
partially offset by an increase in decommissioning expense. The Company
provided additional information to the NCUC that demonstrated that deferral
of the ongoing effects should also be allowed. In August of 2003, the NCUC
revised its decision and approved the deferral of the ongoing effects of
SFAS No. 143 at which time the $14 million was reversed.
D. FERC Market Power Mitigation
A FERC order issued in November 2001 on certain unaffiliated utilities'
triennial market based wholesale power rate authorization updates required
certain mitigation actions that those utilities would need to take for
sales/purchases within their control areas and required those utilities to
post information on their websites regarding their power systems' status.
As a result of a request for rehearing filed by certain market
participants, FERC issued an order delaying the effective date of the
mitigation plan until after a planned technical conference on market power
determination. In December 2003, the FERC issued a staff paper discussing
alternatives and held a technical conference in January 2004. In April
2004, the FERC issued two orders concerning utilities' ability to sell
wholesale electricity at market based rates. In the first order, the FERC
adopted two new interim screens for assessing potential generation market
power of applicants for wholesale market based rates, and described
additional analyses and mitigation measures that could be presented if an
applicant does not pass one of these interim screens. In July 2004, the
FERC issued an order on rehearing affirming its conclusions in the April
order. In the second order, the FERC initiated a rulemaking to consider
whether the FERC's current methodology for determining whether a public
utility should be allowed to sell wholesale electricity at market-based
rates should be modified in any way. Management is unable to predict the
outcome of these actions by the FERC or their effect on future results of
operations and cash flows. However, PEC does not anticipate that its
current operations would be impacted materially if they were unable to sell
power at market-based rates in their respective control areas.
4. COMPREHENSIVE INCOME
Comprehensive income for the three months ended June 30, 2004 and 2003 was
$98 million and $88 million, respectively. Comprehensive income for the six
months ended June 30, 2004 and 2003 was $214 million and $223 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.
5. FINANCING ACTIVITIES
On July 28, 2004, PEC extended its $165 million 364-day line of credit,
which was to expire on July 29, 2004. The line of credit will expire on
July 27, 2005.
On April 30, 2004, PEC redeemed $34.7 million of Darlington County 6.6%
Series Pollution Control Bonds at 102.5% of par, $1.795 million of New
Hanover County 6.3% Series Pollution Control Bonds at 101.5% of par, and
$2.58 million of Chatham County 6.3% Series Pollution Control Bonds at
101.5% of par with cash from operations.
On January 15, 2004, PEC paid at maturity $150 million 5.875% First
Mortgage Bonds with commercial paper proceeds. On April 15, 2004, PEC also
paid at maturity $150 million 7.875% First Mortgage Bonds with commercial
paper proceeds and cash from operations.
6. BENEFIT PLANS
PEC has a non-contributory defined benefit retirement (pension) plan for
substantially all full-time employees. PEC also has supplementary defined
benefit pension plans that provide benefits to higher-level employees. In
addition to pension benefits, PEC provides contributory other
postretirement benefits (OPEB), including certain health care and life
insurance benefits, for retired employees who meet specified criteria. The
components of the net periodic benefit cost for the three and six months
ended June 30 are:
37
Three Months Ended June 30 Other Postretirement
Pension Benefits Benefits
----------------------- ---------------------
(in millions) 2004 2003 2004 2003
----------------------- ---------------------
Service cost $ 6 $ 5 $ 2 $ 2
Interest cost 13 12 4 3
Expected return on plan assets (17) (16) (1) (1)
Amortization, net - - 1 1
----------------------- ---------------------
Net periodic cost $ 2 $ 1 $ 6 $ 5
======================= =====================
Six Months Ended June 30 Other Postretirement
Pension Benefits Benefits
----------------------- ---------------------
(in millions) 2004 2003 2004 2003
----------------------- ---------------------
Service cost $ 12 $ 11 $ 4 $ 3
Interest cost 26 24 8 7
Expected return on plan assets (34) (33) (2) (1)
Amortization, net 1 - 2 2
----------------------- ---------------------
Net periodic cost $ 5 $ 2 $ 12 $ 11
======================= =====================
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.
As of June 30, 2004, PEC had $70 million notional of pay fixed forward
starting swaps, entered into in March 2004, to hedge its exposure to
interest rates with regard to a future issuance of debt and $26 million
notional of pay fixed forward starting swaps, entered into in April 2004,
to hedge its exposure to interest rates with regard to an upcoming railcar
lease. In July 2004, PEC entered into an additional $30 million notional
pay fixed forward swap, increasing the total notional of pay fixed forward
starting swaps to $126 million. These agreements have a computational
period of ten years.
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. PEC only enters into interest rate
derivative agreements with banks with credit ratings of single A or better.
8. FINANCIAL INFORMATION BY BUSINESS SEGMENT
PEC's operations consist primarily of the PEC Electric segment which is
engaged in the generation, transmission, distribution and sale of electric
energy primarily in portions of North Carolina and South Carolina. These
electric operations are subject to the rules and regulations of the FERC,
the NCUC, the SCPSC and the NRC. PEC Electric also distributes and sells
electricity to other utilities, primarily on the east coast of the United
States.
The Other segment, whose operations are primarily in the United States, is
made up of other nonregulated business areas 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.
The financial information for PEC segments for the three and six months
ended June 30, 2004 and 2003 is as follows:
Three Months Ended June 30 2004 2003
---------------------------------- ---------------------------------
PEC PEC
(in millions) Electric Other Total Electric Other Total
---------------------------------- ---------------------------------
Total revenues $ 861 $ 1 $ 862 $ 816 $ 3 $ 819
Earnings available
for common 97 (1) 96 89 - 89
38
Six Months Ended June 30 2004 2003
---------------------------------- ---------------------------------
PEC PEC
(in millions) Electric Other Total Electric Other Total
----------- ---------- ----------- ----------- ---------- ----------
Total revenues $ 1,762 $ 1 $ 1,763 $ 1,742 $ 6 $ 1,748
Earnings available
for common 213 (3) 210 223 - 223
9. OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income and other income and
expense items as discussed below. The components of other, net as shown on
the accompanying Consolidated Statements of Income for the three and six
months ended June 30 are as follows:
Three Months Ended Six Months Ended
June 30 June 30
-------------------------- -------------------------
(in millions) 2004 2003 2004 2003
---------- ----------- ---------- -----------
Other income
Net financial trading gain (loss) $ 4 $ - $ 5 $ (1)
Nonregulated energy and delivery services income 2 2 4 4
Investment gains 2 - - -
AFUDC equity 1 1 2 2
Other - 4 3 4
---------- ----------- ---------- -----------
Total other income $ 9 $ 7 $ 14 $ 9
---------- ----------- ---------- -----------
Other expense
Nonregulated energy and delivery services expenses $ 2 $ 2 $ 4 $ 4
Donations 1 1 5 3
Investment losses - 9 - 8
Write-off of non-trade receivable - - 7 -
Other 2 3 6 4
---------- ----------- ---------- -----------
Total other expense $ 5 $ 15 $ 22 $ 19
---------- ----------- ---------- -----------
Other, net $ 4 $ (8) $ (8) $ (10)
========== =========== ========== ===========
Net financial trading gains and losses represent non-asset-backed trades of
electricity and gas. Nonregulated energy and delivery services include
power protection services and mass market programs such as surge
protection, appliance services and area light sales, and delivery,
transmission and substation work for other utilities.
10. COMMITMENTS AND CONTINGENCIES
Contingencies and significant changes to the commitments discussed in Note
16 of the Company's 2003 Annual Report on Form 10-K are described below.
A. Guarantees
As a part of normal business, PEC enters into various agreements providing
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 PEC and subsidiaries on a
stand-alone basis, thereby facilitating the extension of sufficient credit
to accomplish PEC and the subsidiaries' intended commercial purposes.
Guarantees at June 30, 2004, are summarized in the table and discussed in
the subsequent paragraphs.
At June 30, 2004, outstanding guarantees consisted of the following:
(in millions)
Standby letters of credit $ 3
Surety bonds 18
------------
Total $ 21
============
39
Standby Letters of Credit
Financial institutions have issued standby letters of credit to financial
institutions for PEC and certain subsidiaries for the benefit of third
parties that have extended credit to PEC and certain subsidiaries. As of
June 30, 2004, PEC and certain subsidiaries have outstanding letters of
credit totaling $3 million. These letters of credit have been issued
primarily for the purpose of securing performance under contracts and
supporting payments on interest payments on outstanding debt obligations
and self insurance for workers compensation. If PEC or 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 PEC. Any amounts owed by its subsidiaries are
reflected in the PEC Consolidated Balance Sheets.
Surety Bonds
At June 30, 2004, PEC had $18 million in surety bonds purchased primarily
for purposes such as providing workers' compensation coverage and obtaining
licenses, permits and rights-of-way. To the extent liabilities are incurred
as a result of the activities covered by the surety bonds, such liabilities
are included in the Consolidated Balance Sheets.
Guarantees Issued by the Parent
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. On May 12, 2004 PEC sent notice to the NRC that due to
the Renewed Facility Operating License for Robinson 2, the parent guarantee
related to Robinson, would be cancelled as of June 30, 2004. As a result,
the total parent guarantees for decommissioning decreased from $276 million
to $181 million during the second quarter.
B. Insurance
PEC is insured against public liability for a nuclear incident up to $10.76
billion per occurrence. Under the current provisions of the Price Anderson
Act, which limits liability for accidents at nuclear plants, PEC, as an
owner of nuclear units, can be assessed a portion of any third-party
liability claims arising from an accident at any commercial nuclear power
plant in the United States. In the event that public liability claims from
an insured nuclear incident exceed $300 million (currently available
through commercial insurers), PEC would be subject to assessments of up to
$101 million for each reactor owned per occurrence. Payment of such
assessments would be made over time as necessary to limit the payment in
any one year to no more than $10 million per reactor owned. Congress is
considering revisions to the Price Anderson Act during 2004 that could
include increased limits and assessments per reactor owned. The final
outcome of this matter cannot be predicted at this time.
PEC self-insures its transmission and distribution lines against loss due
to storm damage and other natural disasters.
C. Claims and Uncertainties
PEC is subject to federal, state and local regulations addressing hazardous
and solid waste management, air and water quality and other environmental
matters.
40
Hazardous and Solid Waste Management
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The principal regulatory agency that is responsible for a
specific former manufactured gas plant (MGP) site depends largely upon the
state in which the site is located. There are several MGP sites to which
PEC has some connection. In this regard, PEC and other potentially
responsible parties (PRPs) are participating in, investigating and, if
necessary, remediating former MGP sites with several regulatory agencies,
including, but not limited to, the U.S. Environmental Protection Agency
(EPA) and the North Carolina Department of Environment and Natural
Resources, Division of Waste Management (DWM). In addition, PEC is
periodically notified by regulators such as the EPA and various state
agencies of its involvement or potential involvement in sites, other than
MGP sites, that may require investigation and/or remediation.
PEC has filed claims with its general liability insurance carriers to
recover costs arising out of actual or potential environmental liabilities.
All claims have been settled other than with insolvent carriers. These
settlements have not had a material effect on the consolidated financial
position or results of operations.
PEC is also currently in the process of assessing potential costs and
exposures at other environmentally impaired sites. As the assessments are
developed and analyzed, PEC will accrue costs for the sites to the extent
the costs are probable and can be reasonably estimated.
There are nine former MGP sites and other sites associated with PEC that
have required or are anticipated to require investigation and/or
remediation costs. PEC received insurance proceeds to address costs
associated with PEC environmental liabilities related to its involvement
with some sites. All eligible expenses related to these are charged against
a specific fund containing these proceeds. At June 30, 2004, approximately
$8 million remains in this centralized fund with a related accrual of $8
million recorded for the associated expenses of environmental issues. PEC
is unable to provide an estimate of the reasonably possible total
remediation costs beyond what is currently accrued due to the fact that
investigations have not been completed at all sites. This accrual has been
recorded on an undiscounted basis. PEC measures its liability for these
sites based on available evidence including its experience in investigating
and remediating environmentally impaired sites. The process often involves
assessing and developing cost-sharing arrangements with other PRPs. PEC
will accrue costs for the sites to the extent its liability is probable and
the costs can be reasonably estimated. 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, all of which also are associated with
PEC, to state standards pursuant to an Administrative Order on Consent.
These sites are anticipated to have investigation or remediation costs
associated with them. NCNG had previously accrued approximately $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 PEC. PEC does not believe it can provide an estimate of the
reasonably possible total remediation costs beyond the accrual because
investigations have not been completed at all sites. Therefore, PEC cannot
currently determine the total costs that may be incurred in connection with
the investigation and/or remediation of all sites.
Air Quality
There has been and may be further proposed legislation requiring reductions
in air emissions for NOx, SO2, carbon dioxide and mercury. Some of these
proposals establish nationwide caps and emission rates over an extended
period of time. This national multi-pollutant approach to air pollution
control could involve significant capital costs which could be material to
PEC's consolidated financial position or results of operations. Control
equipment that will be installed on North Carolina fossil generating
facilities as part of the North Carolina legislation discussed below may
address some of the issues outlined above. However, PEC cannot predict the
outcome of this matter.
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
PEC was asked to provide information to the EPA as part of this initiative
and cooperated in providing the requested information. The EPA initiated
civil enforcement actions against other unaffiliated utilities as part of
41
this initiative. Some of these actions resulted in settlement agreements
calling for expenditures by these unaffiliated utilities, ranging from $1.0
billion to $1.4 billion. A utility that was not subject to a civil
enforcement action settled its New Source Review issues with the EPA for
$300 million. These settlement agreements have generally called for
expenditures to be made over extended time periods, and some of the
companies may seek recovery of the related cost through rate adjustments or
similar mechanisms. PEC cannot predict the outcome of this matter.
In 2003, the EPA published a final rule addressing routine equipment
replacement under the New Source Review program. The rule defines routine
equipment replacement and the types of activities that are not subject to
New Source Review requirements or New Source Performance Standards under
the Clean Air Act. The rule was challenged in the Federal Appeals Court and
its implementation stayed. In July 2004, the EPA announced it will
reconsider certain issues arising from the final routine equipment
replacement rule. Reconsideration does not impact the court-approved stay.
The agency plans to issue a final decision on these reconsidered issues by
year's end. PEC cannot predict the outcome of this matter.
In 1998, the EPA published a final rule at Section 110 of the Clean Air Act
addressing the regional transport of ozone (NOx SIP Call). The EPA's rule
requires 23 jurisdictions, including North Carolina and South Carolina, to
further reduce NOx emissions in order to attain a preset emission level
during each year's "ozone season," beginning May 31, 2004. PEC is currently
installing controls necessary to comply with the rule and, with the use of
early action credits, expects to be in compliance as required by the final
rule. Total capital expenditures to meet these measures in North and South
Carolina could reach approximately $370 million, which has not been
adjusted for inflation. PEC has spent approximately $265 million to date
related to these expenditures. Increased operation and maintenance costs
relating to the NOx SIP Call are not expected to be material to PEC's
results of operations. Further controls are anticipated as electricity
demand increases.
In 1997, the EPA issued final regulations establishing a new 8-hour ozone
standard. In 1999, the District of Columbia Circuit Court of Appeals ruled
against the EPA with regard to the federal 8-hour ozone standard. The U.S.
Supreme Court has upheld, in part, the District of Columbia Circuit Court
of Appeals decision. In April 2004, the EPA identified areas that do not
meet the standard. The states with identified areas, including North and
South Carolina are proceeding with the implementation of the federal 8-hour
ozone standard . Both states promulgated final regulations, which will
require PEC to install NOx controls under the states' 8-hour standard. The
costs of those controls are included in the $370 million cost estimate
above. However, further technical analysis and rulemaking may result in a
requirement for additional controls at some units. PEC cannot predict the
outcome of this matter.
In June 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of NOx and SO2 from
coal-fired power plants. PEC expects its capital costs to meet these
emission targets will be approximately $813 million by 2013. PEC has
expended approximately $45 million of these capital costs through June 30,
2004. PEC currently has approximately 5,100 MW of coal-fired generation
capacity in North Carolina that is affected by this legislation. The law
requires the emissions reductions to be completed in phases by 2013, and
applies to each utility's total system rather than setting requirements for
individual power plants. The law also freezes the utilities' base rates for
five years unless there are extraordinary events beyond the control of the
utilities or unless the utilities persistently earn a return substantially
in excess of the rate of return established and found reasonable by the
NCUC in the utilities' last general rate case. Further, the law allows the
utilities to recover from their retail customers the projected capital
costs during the first seven years of the ten-year compliance period
beginning on January 1, 2003. The utilities must recover at least 70% of
their projected capital costs during the five-year rate freeze period. PEC
recognized amortization of $15 million and $34 million in the quarters
ended June 30, 2004 and 2003, respectively. PEC recognized amortization of
$31 million and $54 million in the six months ended June 30, 2004 and 2003,
respectively. Pursuant to the law, PEC entered into an agreement with the
state of North Carolina to transfer to the state certain NOx and SO2
emissions allowances that result from compliance with the collective NOx
and SO2 emissions limitations set out in the law. The law also requires the
state to undertake a study of mercury and carbon dioxide emissions in North
Carolina. Operation and maintenance costs will increase due to the
additional personnel, materials and general maintenance associated with the
equipment. Operation and maintenance expenses are recoverable through base
rates, rather than as part of this program. PEC cannot predict the future
regulatory interpretation, implementation or impact of this law.
42
In 1997, the EPA's Mercury Study Report and Utility Report to Congress
conveyed that mercury is not a risk to the average American and expressed
uncertainty about whether reductions in mercury emissions from coal-fired
power plants would reduce human exposure. Nevertheless, the EPA determined
in 2000 that regulation of mercury emissions from coal-fired power plants
was appropriate. In 2003, the EPA proposed alternative control plans that
would limit mercury emissions from coal-fired power plants. The first, a
Maximum Achievable Control Technology (MACT) standard applicable to every
coal-fired plant, would require compliance in 2008. The second, which the
EPA has stated it prefers, is a mercury cap and trade program that would
require limits to be met in two phases, 2010 and 2018. The EPA expects to
finalize the mercury rule in March 2005. Achieving compliance with the
proposal could involve significant capital costs which could be material to
PEC's consolidated financial position or results of operations. PEC cannot
predict the outcome of this matter.
In conjunction with the proposed mercury rule, the EPA proposed a MACT
standard to regulate nickel emissions from residual oil-fired units. The
agency estimates the proposal will reduce national nickel emissions to
approximately 103 tons. The EPA expects to finalize the nickel rule in
March 2005. PEC cannot predict the outcome of this matter.
In December 2003, the EPA released its proposed Interstate Air Quality
Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The
EPA's proposal requires 28 jurisdictions, including North Carolina, South
Carolina, Georgia and Florida, to further reduce NOx and SO2 emissions in
order to attain preset state NOx and SO2 emissions levels. The rule is
expected to become final in 2004. The air quality controls already
installed for compliance with the NOx SIP Call and currently planned by PEC
for compliance with the North Carolina law will reduce the costs required
to meet the CAIR requirements for PEC's North Carolina units. Additional
compliance costs will be determined later this year once the rule is
finalized.
In March 2004, the North Carolina Attorney General filed a petition with
the EPA under Section 126 of the Clean Air Act, asking the federal
government to force coal-fired power plants in thirteen other states,
including South Carolina, to reduce their NOx and SO2 emissions. The state
of North Carolina contends these out-of-state polluters are interfering
with North Carolina's ability to meet national air quality standards for
ozone and particulate matter. The EPA has not made a determination on the
Section 126 petition, and PEC cannot predict the outcome of this matter.
Water Quality
As a result of the operation of certain control equipment needed to address
the air quality issues outlined above, new wastewater streams may be
generated at the applicable facilities. Integration of these new wastewater
streams into the existing wastewater treatment processes may result in
permitting, construction and requirements imposed on PEC in the immediate
and extended future.
After many years of litigation and settlement negotiations the EPA adopted
regulations in February 2004 for the implementation of Section 316(b) of
the Clean Water Act. These regulations will become effective September 7,
2004. The purpose of these regulations is to minimize adverse environmental
impacts caused by cooling water intake structures and intake systems. Over
the next several years these regulations will impact the larger base load
generation facilities and may require the facilities to mitigate the
effects to aquatic organisms by constructing intake modifications or
undertaking other restorative activities. Substantial costs could be
incurred by the facilities in order to comply with the new regulation. PEC
cannot predict the outcome and impacts to the facilities at this time.
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 has stated it 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
consolidated financial position or results of operations if associated
costs cannot be recovered from customers. PEC favors the voluntary program
approach recommended by the administration and is evaluating options for
the reduction, avoidance, and sequestration of greenhouse gases. However,
PEC cannot predict the outcome of this matter.
43
Other Contingencies
1. As required under the Nuclear Waste Policy Act of 1982, PEC entered into
a contract with the DOE under which the DOE agreed to begin taking spent
nuclear fuel by no later than January 31, 1998. All similarly situated
utilities were required to sign the same standard contract.
In 1995, the DOE issued a final interpretation that it did not have an
unconditional obligation to take spent nuclear fuel by January 31, 1998. In
Indiana Michigan Power v. DOE, the Court of Appeals vacated the DOE's final
interpretation and ruled that the DOE had an unconditional obligation to
begin taking spent nuclear fuel. The Court did not specify a remedy because
the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana Michigan Power
v. DOE, a group of utilities petitioned the Court of Appeals in Northern
States Power (NSP) v. DOE, seeking an order requiring the DOE to begin
taking spent nuclear fuel by January 31, 1998. The DOE took the position
that its delay was unavoidable, and the DOE was excused from performance
under the terms and conditions of the contract. The Court of Appeals found
that the delay was not unavoidable, but did not order the DOE to begin
taking spent nuclear fuel, stating that the utilities had a potentially
adequate remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31,
1998, a group of utilities filed a motion with the Court of Appeals to
enforce the mandate in NSP v. DOE. Specifically, this group of utilities
asked the Court to permit the utilities to escrow their waste fee payments,
to order the DOE not to use the waste fund to pay damages to the utilities,
and to order the DOE to establish a schedule for disposal of spent nuclear
fuel. The Court denied this motion based primarily on the grounds that a
review of the matter was premature, and that some of the requested remedies
fell outside of the mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal
Circuit) ruled that utilities may sue the DOE for damages in the Federal
Court of Claims instead of having to file an administrative claim with DOE.
In January 2004, PEC filed a complaint with the DOE claiming that the DOE
breached the Standard Contract for Disposal of Spent Nuclear Fuel by
failing to accept spent nuclear fuel from various Progress Energy
facilities on or before January 31, 1998. Damages due to DOE's breach will
likely exceed $100 million. Similar suits have been initiated by over two
dozen other utilities.
In July 2002, Congress passed an override resolution to Nevada's veto of
DOE's proposal to locate a permanent underground nuclear waste storage
facility at Yucca Mountain, Nevada. DOE plans to submit a license
application for the Yucca Mountain facility by the end of 2004. In November
2003, Congressional negotiators approved $580 million for fiscal year 2004
for the Yucca Mountain project, $123 million more than the previous year.
In January 2003, the State of Nevada, Clark County, Nevada, and the City of
Las Vegas petitioned the U.S. Court of Appeals for the District of Columbia
Circuit for review of the Congressional override resolution. On July 9,
2004, the Court rejected the challenge to the constitutionality of the
resolution approving Yucca Mountain, but ruled that the EPA was wrong to
set a 10,000-year compliance period. The DOE continues to state it plans to
begin operation of the repository at Yucca Mountain in 2010. PEC cannot
predict the outcome of this matter.
With certain modifications and additional approval by the NRC including the
installation of onsite dry storage facilities at Robinson (2005) and
Brunswick (2010), PEC's spent nuclear fuel storage facilities will be
sufficient to provide storage space for spent fuel generated on its system
through the expiration of the operating licenses for all of its nuclear
generating units.
2. In August 2003, PEC was served as a co-defendant in a purported class
action lawsuit styled as Collins v. Duke Energy Corporation et al, 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.
44
In September 2003, PEC filed a motion to dismiss all counts of the
complaint on substantive and procedural grounds. In October 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. In
November 2003, PEC filed a motion to dismiss the plaintiffs' first amended
complaint. In March 2004, the plaintiffs in this case filed a notice of
dismissal without prejudice of their claims against PEC and Duke Energy
Corporation.
3. In 2001, PEC entered into a contract to purchase coal from Dynegy
Marketing and Trade (DMT). After DMT experienced financial difficulties,
including credit ratings downgrades by certain credit reporting agencies,
PEC requested credit enhancements in accordance with the terms of the coal
purchase agreement in July 2002. When DMT did not offer credit
enhancements, as required by a provision in the contract, PEC terminated
the contract in July 2002.
PEC initiated a lawsuit seeking a declaratory judgment that the termination
was lawful. DMT counterclaimed, stating the termination was a breach of
contract. On March 23, 2004, the United States District Court for the
Eastern District of North Carolina ruled that PEC was liable for breach of
contract, but ruled against DMT on its unfair and deceptive trade practices
claim. On April 6, 2004, the Court entered a judgment against PEC in the
amount of approximately $10 million. The Court did not rule on DMT's
pending motion for attorneys' fees.
On May 4, 2004, PEC authorized its outside counsel to file a notice of
appeal of the April 6, 2004 judgment and on May 7, 2004, the notice of
appeal was filed with the United States Court of Appeals for the Fourth
Circuit. On June 8, 2004 DMT filed a motion to dismiss the appeal in the
appeals court on the ground that PEC's notice of appeal should have been
filed on or before May 6, 2004. On June 16, 2004, PEC filed a motion with
the trial court requesting an extension of the deadline for the filing of
the notice of appeal. On July 7, 2004, the parties agreed to postpone the
appellate proceedings to allow the trial court to resolve PEC's motion for
an extension of the notice of appeal deadline.
PEC recorded a liability of approximately $10 million for the judgment and
a regulatory asset for the probable recovery through its fuel adjustment
clause in the first quarter of 2004. PEC cannot predict the outcome of this
matter.
4. PEC and its subsidiaries are involved in various litigation matters in
the ordinary course of business, some of which involve substantial amounts.
Where appropriate, accruals have been made in accordance with SFAS No. 5,
"Accounting for Contingencies," to provide for such matters. In the opinion
of management, the final disposition of pending litigation would not have a
material adverse effect on PEC's consolidated results of operations or
financial position.
45
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following Management's Discussion and Analysis contains forward-looking
statements that involve estimates, projections, goals, forecasts, assumptions,
risks and uncertainties that could cause actual results or outcomes to differ
materially from those expressed in the forward-looking statements. Many, but not
all of the factors that may impact actual results are discussed in the Risk
Factors sections of Progress Energy's and PEC's annual report on Form 10-K for
the year ended December 31, 2003, which were filed with the SEC on March 12,
2004. Please review "SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" 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 , timing of maintenance on electric generating units and timing of
synthetic fuel production, among other factors.
This discussion should be read in conjunction with the accompanying financial
statements found elsewhere in this report and in conjunction with the 2003 Form
10-K.
RESULTS OF OPERATIONS
Progress Energy is an integrated energy company, with its primary focus on the
end-use and wholesale electricity markets. The Company's reportable business
segments and their primary operations include:
o Progress Energy Carolinas Electric (PEC Electric) - primarily engaged in
the generation, transmission, distribution and sale of electricity in
portions of North Carolina and South Carolina;
o Progress Energy Florida (PEF) - primarily engaged in the generation,
transmission, distribution and sale of electricity in portions of Florida;
o Competitive Commercial Operations (CCO) - engaged in nonregulated electric
generation operations and marketing activities primarily in the
southeastern United States;
o Fuels - primarily engaged in natural gas drilling and production in Texas
and Louisiana, coal terminal services, coal mining, the production of
synthetic fuels and related services, and fuel transportation and delivery,
all of which are located in Kentucky, West Virginia, and Virginia;
o Rail Services (Rail) - engaged in various rail and railcar related services
in 23 states, Mexico and Canada; and
o Other Businesses (Other) - engaged in other nonregulated business areas,
including telecommunications primarily in the eastern United States and
energy service operations, which do not meet the requirements for separate
segment reporting disclosure.
In this section, earnings and the factors affecting earnings for the three and
six months ended June 30, 2004 as compared to the same periods in 2003 are
discussed. The discussion begins with a summarized overview of the Company's
consolidated earnings, which is followed by a more detailed discussion and
analysis by business segment.
OVERVIEW
For the quarter ended June 30, 2004, Progress Energy's net income was $154
million or $0.63 per share compared to $157 million or $0.66 per share for the
same period in 2003. For the six months ended June 30, 2004, Progress Energy's
net income was $262 million or $1.08 per share compared to $376 million or $1.60
per share for the same period in 2003. The decrease in net income as compared to
prior year was due primarily to:
o Lower off-system wholesale sales, primarily by PEC Electric.
o Higher operations and maintenance (O&M) costs at the utilities due to
increased spending for plant outages in both the Carolinas and Florida and
planned reliability improvements in Florida.
o Recording of litigation settlement reached in the civil suit by SRS.
o Decreased nonregulated generation earnings due to receipt of a contract
termination payment on a tolling agreement in 2003 and higher fixed costs
and interest charges in 2004.
o Unrealized losses recorded on contingent value obligations.
o The impact of tax levelization.
46
Partially offsetting these items were:
o Favorable weather in the Carolinas.
o Reduction in revenue sharing provisions in Florida
o Utility customer growth in both the Carolinas and Florida.
o Lower depreciation and amortization costs at the utilities.
o Increased natural gas earnings.
Basic earnings per share decreased in 2004 due in part to the factors outlined
above. Dilution related to the issuances under the Company's Investor Plus Stock
Purchase Plan and employee benefit programs in 2003 and 2004 also reduced basic
earnings per share by $0.02 for the second quarter of 2004 and $0.04 for the six
months ended June 30, 2004.
Beginning in the fourth quarter of 2003, the Company ceased recording portions
of Fuels segment's operations, primarily synthetic fuel facilities, one month in
arrears. As a result, earnings for the year ended December 31, 2003 included 13
months of operations, resulting in a net income increase of $2 million for the
year. The Company restated previously reported consolidated quarterly earnings
to reflect the new reporting periods which resulted in four months earnings in
the first quarter of 2003 and changed reported net income for subsequent
quarters. Earnings increased $4 million and $15 million, respectively, for the
three and six months ended June 30, 2003 as compared to amounts originally
reported.
The Company's segments contributed the following profits or losses for the three
and six months ended June 30, 2004 and 2003:
- --------------------------------------------------------------------------------------
(in millions) Three Months Ended Six Months Ended
June 30 June 30
- --------------------------------------------------------------------------------------
Business Segment 2004 2003 2004 2003
- -------------------------------------------------------------------------------------
PEC Electric $ 97 $ 89 $ 213 $ 223
PEF 84 61 133 132
Fuels 56 58 104 97
CCO 5 2 (3) 11
Rail 4 2 9 (1)
Other (30) - (31) 1
-----------------------------------------
Total Segment Profit 216 212 425 463
Corporate (63) (58) (164) (102)
-----------------------------------------
Income from continuing operations 153 154 261 361
NCNG discontinued operations 1 3 1 14
Cumulative effect of change in accounting
principle, net of tax - - - 1
-----------------------------------------
Net income $ 154 $ 157 $ 262 $ 376
- -------------------------------------------------------------------------------------
In March 2003, the SEC completed an audit of Progress Energy Service Company,
LLC (Service Company) and recommended that the Company change its cost
allocation methodology for allocating Service Company costs. As part of the
audit process, the Company was required to change the cost allocation
methodology for 2003 and record retroactive reallocations between its affiliates
in the first quarter of 2003 for allocations originally made in 2001 and 2002.
This change in allocation methodology and the related retroactive adjustments
have no impact on consolidated expense or earnings. The new allocation
methodology, as compared to the previous allocation methodology, generally
decreases expenses in the regulated utilities and increases expenses in the
nonregulated businesses. The regulated utilities' reallocations are within
operation and maintenance (O&M) expense, while the diversified businesses'
reallocations are generally within diversified business expenses. The impact on
the individual lines of business is included in the following discussions.
47
PROGRESS ENERGY CAROLINAS ELECTRIC
PEC Electric contributed segment profits of $97 million and $89 million for the
three months ended March 31, 2004 and 2003, respectively, and $213 million and
$223 million for the six months ended June 30, 2004 and 2003, respectively. The
increase in profits for the three months ended June 30, 2004 as compared to the
same period in 2003 is due primarily to favorable weather, increased revenue
from customer growth, lower depreciation and amortization charges and the impact
of losses booked on investments in limited partnerships in 2003, partially
offset by higher operations and maintenance charges and lower wholesale sales.
The decrease in profits for the six months ended June 30, 2004 as compared to
the same period in 2003 is primarily due to lower off-system wholesale sales and
higher O&M charges, partially offset by the favorable impact of weather,
increased revenues from customer growth and lower depreciation and amortization
charges.
PEC Electric's revenues for the three and six months ended June 30, 2004 and
2003, and the percentage change by customer class are as follows:
- -----------------------------------------------------------------------------------------------------
(in millions of $) Three Months Ended June 30 Six Months Ended June 30
- -----------------------------------------------------------------------------------------------------
Customer Class 2004 Change % Change 2003 2004 Change % Change 2003
- -----------------------------------------------------------------------------------------------------
Residential $ 284 $ 36 14.5 $ 248 $ 655 $ 50 8.3 $ 605
Commercial 213 14 7.0 199 420 20 5.0 400
Industrial 161 5 3.2 156 308 6 2.0 302
Governmental 19 1 5.6 18 38 2 5.6 36
------------------ -------------------------- ---------
Total retail revenues 677 56 9.0 621 1,421 78 5.8 1,343
Wholesale 139 (15) (9.7) 154 295 (69) (19.0) 364
Unbilled 24 1 23 1 8 (7)
Miscellaneous 21 3 16.7 18 45 3 7.1 42
------------------ -------------------------- ---------
Total electric revenues $ 861 $ 45 5.5 $ 816 $ 1,762 $ 20 1.1 $ 1,742
- -----------------------------------------------------------------------------------------------------
PEC Electric's energy sales for the three and six months ended June 30, 2004 and
2003, and the amount and percentage change by customer class are as follows:
- -------------------------------------------------------------------------------------------------------
(in thousands of mWh) Three Months Ended June 30 Six Months Ended June 30
- -------------------------------------------------------------------------------------------------------
Customer Class 2004 Change % Change 2003 2004 Change % Change 2003
- -------------------------------------------------------------------------------------------------------
Residential 3,525 473 15.5 3,052 8,266 627 8.2 7,639
Commercial 3,172 226 7.7 2,946 6,230 300 5.1 5,930
Industrial 3,280 83 2.6 3,197 6,273 71 1.1 6,202
Governmental 337 20 6.3 317 682 22 3.3 660
------------------ -------------------------- ---------
Total retail revenues 10,314 802 8.4 9,512 21,451 1,020 5.0 20,431
Wholesale 3,114 (187) (5.7) 3,301 6,904 (1,016) (12.8) 7,920
Unbilled 404 8 396 20 104 (84)
------------------ -------------------------- ---------
Total mWh sales 13,832 623 4.7 13,209 28,375 108 0.4 28,267
- -------------------------------------------------------------------------------------------------------
Three months ended June 30, 2004 compared to the three months ended June 30,
2003
PEC Electric's revenues, excluding recoverable fuel revenues of $156 million and
$137 million for the three months ended June 30, 2004 and 2003, respectively,
increased $26 million. The increase in revenues was due primarily to favorable
weather, with cooling degree days 59% above prior year. In addition, customer
growth was favorable compared to prior year. PEC Electric has approximately
26,000 additional customers as of June 30, 2004 compared to June 30, 2003. The
increase in retail revenues was offset partially by a reduction in wholesale
revenues. Revenues for the quarter ended June 30, 2003 included strong
off-system wholesale sales to the Northeastern United States in the month of
April as a result of favorable market conditions.
Fuel and purchased power costs represent the costs of generation, which includes
fuel purchases for generation, as well as energy purchased in the market to meet
customer load. Fuel and purchased power expenses are recovered primarily through
cost recovery clauses and, as such, changes in these expenses do not have a
material impact on earnings. The difference between fuel and purchased power
costs incurred and associated fuel revenues that is subject to recovery is
deferred for future collection or refund to customers.
48
Fuel and purchased power expenses increased $27 million from $246 million for
the three months ended June 30, 2003 to $273 million for the three months ended
June 30, 2004. Fuel used in electric generation increased $16 million to $193
compared to the same period in the prior year. This increase is primarily due to
higher system requirements caused by favorable weather and customer growth.
Purchased power expenses increased $11 million to $80 million compared to prior
year due primarily to an increase in price.
O&M costs were $226 million for the three months ended June 30, 2004, which
represents a $16 million increase compared to the same period in 2003. O&M costs
increased $13 million primarily due to an increase in outage scope and duration
at the nuclear plants.
Depreciation and amortization expense decreased $15 million from $142 million
for the quarter ended June 30, 2003 to $127 million for the quarter ended June
30, 2004. During the first half of 2004, PEC Electric filed with the North
Carolina Utilities Commission (NCUC) and obtained approval from the South
Carolina Public Service Commission (SCPSC) for a depreciation study which
allowed the utility to reduce the rates used to calculate depreciation expense.
The new depreciation study provides support for reducing depreciation expense on
an annual basis by approximately $40 million for 2004. The reduction in
depreciation expense is primarily attributable to extended lives of nuclear
generation, offset by increases for distribution assets. As a result
depreciation expense decreased $10 million compared to the prior year quarter.
In addition, clean air amortization decreased $18 million compared to the prior
year. These items were partially offset by higher depreciation expense due to
assets placed in service of $4 million and the impact of a $14 million
adjustment booked in 2003 related to the implementation of SFAS No. 143. In the
prior year, PEC filed a request with the NCUC requesting deferral of the
difference between expense pursuant to SFAS No. 143 and expense as previously
determined by the NCUC. The NCUC granted deferral of the cumulative adjustment
but denied deferral of the ongoing effects. As a result, PEC ceased deferral of
the ongoing effects during the second quarter of 2003 related to its North
Carolina retail rate jurisdictions. This resulted in a reduction of depreciation
and amortization expense for the quarter ended June 30, 2003 of $14 million
which represented a decrease in non-ARO cost of removal expense partially offset
by an increase in decommissioning expense. In August of 2003, the NCUC revised
its decision and approved deferral of the ongoing effects of SFAS No. 143 at
which time the $14 million reduction was reversed.
Other expenses have decreased $12 million for the three months ended June 30,
2004 as compared to the same period in the prior year. This decrease is
primarily due to losses on limited investment partnerships recorded in 2003.
Taxes other than on income have increased $10 million from $35 million for the
three months ended June 30, 2003 to $45 million for the three months ended June
30, 2004. This increase is due to an increase in gross receipts taxes of $5
million related to an increase in revenues and a 2004 adjustment related to the
prior year, and an increase in payroll taxes of $3 million.
Six months ended June 30, 2004 compared to the six months ended June 30, 2003
PEC Electric's revenues, excluding recoverable fuel revenues of $322 million and
$293 million for the six months ended June 30, 2004 and 2003, respectively,
decreased $9 million. The decrease in revenues was due primarily to lower
wholesale sales. Revenues for the six months ended June 30, 2003 included strong
sales to the Northeastern United States as a result of favorable market
conditions. The decline in wholesale revenues was partially offset by increased
retail revenues as a result of favorable weather, with cooling degree days 58%
above prior year. In addition, favorable customer growth partially offset the
decrease in wholesale sales.
Fuel and purchased power costs represent the costs of generation, which includes
fuel purchases for generation, as well as energy purchased in the market to meet
customer load. Fuel and purchased power expenses are recovered primarily through
cost recovery clauses and, as such, changes in these expenses do not have a
material impact on earnings. The difference between fuel and purchased power
costs incurred and associated fuel revenues that is subject to recovery is
deferred for future collection or refund to customers.
Fuel and purchased power expenses were $559 million for the six months ended
June 30, 2004, which represents a $14 million increase compared to the same
period in the prior year. This increase is primarily due to higher system
requirements caused by favorable weather and customer growth.
49
O&M costs were $435 million for the six months ended June 30, 2004, which
represents a $35 million increase compared to the same period in 2003. O&M
charges were favorably impacted by $16 million related to the retroactive
reallocation of Service Company costs in the prior year. In addition, O&M costs
increased $18 million primarily due to an increase in outage scope and duration
at the nuclear plants.
Depreciation and amortization expense decreased $27 million from $281 million
for the six months ended June 30, 2003 to $254 million for the six months ended
June 30, 2004. As previously discussed, PEC filed a depreciation study which
allowed the utility to reduce the rates used to calculate depreciation expense.
The impact of the study for the six months ended June 30, 2004 was a reduction
of depreciation of $18 million compared to the same prior year period. In
addition, clean air amortization for the six months ended June 30, 2004
decreased $23 million compared to the same prior year period. These items were
partially offset by higher depreciation expense due to assets placed in service
of $8 million and the $14 million impact of the adjustment booked in 2003
related to the implementation of SFAS No. 143 as previously discussed.
Taxes other than on income have increased $9 million from $79 million for the
six months ended June 30, 2003 to $88 million for the six months ended June 30,
2004. This increase is due to an increase in gross receipts taxes of $5 million
related to an increase in revenues and a 2004 adjustment related to the prior
year, and an increase in property taxes of $2 million.
PROGRESS ENERGY FLORIDA
PEF contributed segment profits of $84 million and $61 million for the three
months ended June 30, 2004 and 2003, respectively, and $133 million and $132
million for the six months ended June 30, 2004 and 2003, respectively. The
increase in profits for the three months ended June 30, 2004 when compared to
2003 is primarily due to a reduction in the provision for revenue sharing, the
additional return on investment for the Hines 2 plant and favorable customer
growth. Profits for the six months ended June 30, 2004 increased slightly due to
a reduction in the provision for revenue sharing, favorable customer growth, and
the additional return on investment on the Hines 2 plant, partially offset by
higher O&M charges and increased depreciation expense from assets placed in
service.
PEF's electric revenues for the three and six months ended June 30, 2004 and
2003, and the amount and percentage change by customer class are as follows:
- --------------------------------------------------------------------------------------------------------
(in millions of $) Three Months Ended June 30 Six Months Ended June 30
- --------------------------------------------------------------------------------------------------------
Customer Class 2004 Change % Change 2003 2004 Change % Change 2003
- --------------------------------------------------------------------------------------------------------
Residential $ 422 $ 8 1.9 $ 414 $ 824 $ 26 3.3 $ 798
Commercial 214 22 11.5 192 395 53 15.5 342
Industrial 66 10 17.9 56 128 24 23.1 104
Governmental 52 6 13.0 46 99 15 17.9 84
Retail revenue sharing (3) 25 (28) (7) 21 (28)
----------------- --------------------------- ----------
Total retail revenues 751 71 10.4 680 1,439 139 10.7 1,300
Wholesale 53 3 6.0 50 120 (1) (0.8) 121
Unbilled 24 17 7 18 11 7
Miscellaneous 32 2 6.7 30 67 - - 67
----------------- --------------------------- ----------
Total electric revenues $ 860 $ 93 12.1 $ 767 $ 1,644 $ 149 10.0 $ 1,495
- --------------------------------------------------------------------------------------------------------
PEF's electric energy sales for the three and six months ended June 30, 2004 and
2003, and the amount and percentage change by customer class are as follows:
- --------------------------------------------------------------------------------------------------------
(in thousands of mWh) Three Months Ended June 30 Six Months Ended June 30
- --------------------------------------------------------------------------------------------------------
Customer Class 2004 Change % Change 2003 2004 Change % Change 2003
- --------------------------------------------------------------------------------------------------------
Residential 4,505 (198) (4.2) 4,703 8,797 (459) (5.0) 9,256
Commercial 2,941 (10) (0.3) 2,951 5,431 38 0.7 5,393
Industrial 1,051 43 4.3 1,008 2,074 150 7.8 1,924
Governmental 751 9 1.2 742 1,423 25 1.8 1,398
----------------- --------------------------- ----------
Total retail energy sales 9,248 (156) (1.7) 9,404 17,725 (246) (1.4) 17,971
Wholesale 1,093 203 22.8 890 2,415 249 11.5 2,166
Unbilled 790 292 498 655 101 554
----------------- --------------------------- ----------
Total mWh sales 11,131 339 3.1 10,792 20,795 104 0.5 20,691
- --------------------------------------------------------------------------------------------------------
50
Three months ended June 30, 2004 compared to the three months ended June 30,
2003
PEF's revenues, excluding recoverable fuel and other pass-through revenues of
$479 million and $422 million for the three months ended June 30, 2004 and 2003,
respectively, increased $36 million. This increase was due primarily to a
reduction in the provision for revenue sharing of $25 million. The provision for
revenue sharing in the prior year included an additional $18 million related to
2002 as ordered by the FPSC and the year to date accrual for 2003 which was $7
million higher than the provisions recorded during 2004. Revenues were also
increased $11 million and $10 million, respectively, due to favorable customer
growth and the return on investment on Hines Unit 2 which was placed in service
December 2003. PEF has approximately 37,000 additional customers as of June 30,
2004 compared to June 30, 2003. Based on the Stipulation and Settlement
Agreement reached with the FPSC in April 2002, beginning with the in-service
date of PEF's Hines Unit 2 and continuing through December 2005, PEF will be
allowed to recover through the fuel cost recovery clause a return on average
investment and depreciation expense for Hines Unit 2, to the extent such costs
do not exceed the Unit's cumulative fuel savings over the recovery period. These
increases were partially offset by the impact of milder weather in the current
year of approximately $5 million.
Fuel and purchased power costs represent the costs of generation, which includes
fuel purchases for generation, as well as energy purchased in the market to meet
customer load. Fuel and purchased power expenses are recovered primarily through
cost recovery clauses and, as such, changes in these expenses do not have a
material impact on earnings. The difference between fuel and purchased power
costs incurred and associated fuel revenues that is subject to recovery is
deferred for future collection or refund to customers.
Fuel and purchased power expenses increased $57 million from $358 million for
the three months ended June 30, 2003 to $415 million for the three months ended
June 30, 2004. This increase is attributable primarily to an increase in fuel
used in electric generation which increased $59 million. Higher system
requirements and increased fuel costs in the current year account for $32
million of the increase in fuel used in electric generation. The remaining
increase is due to the recovery of fuel expenses that were deferred in the prior
year, as well as the deferral of current year expenses.
O&M costs decreased $2 million, when compared to the $154 million incurred
during the three months ended June 30, 2003. This decrease is primarily related
to the timing of outages and maintenance at generation facilities of $3 million
and a reduction in costs allocated from the Service Company of $1 million
partially offset by higher costs associated with planned reliability
improvements of approximately $2 million.
Depreciation and amortization decreased $8 million when compared to the $80
million incurred during the three months ended June 30, 2003, primarily due to
the amortization of the Tiger Bay regulatory asset in the prior year. The Tiger
Bay regulatory asset, for contract termination costs, was recovered pursuant to
an agreement between PEF which was approved by the FPSC in 1997 and as such
fluctuations in this expense did not have an impact on earnings. During the
second quarter of 2003, Tiger Bay amortization was $15 million. The Tiger Bay
asset was fully amortized in September 2003. The decrease in Tiger Bay
amortization was partially offset by additional depreciation for assets placed
in service.
Six months ended June 30, 2004 compared to the six months ended June 30, 2003
PEF's revenues, excluding recoverable fuel and other pass-through revenues of
$926 million and $794 million for the six months ended June 30, 2004 and 2003,
respectively, increased $17 million. This increase was due primarily to a
reduction in the provision for revenue sharing of $21 million. Results for 2003
included the accrual of an additional $18 million related to the 2002 revenue
sharing provision as ordered by the FPSC in June of 2003. In addition, the
return on investment on Hines 2 and favorable customer growth increased revenues
by $19 million and $9 million, respectively. These increases were partially
offset by the impact of milder weather in the current year of approximately $17
million.
Fuel and purchased power costs represent the costs of generation, which includes
fuel purchases for generation, as well as energy purchased in the market to meet
customer load. Fuel and purchased power expenses are recovered primarily through
cost recovery clauses and, as such, changes in these expenses do not have a
material impact on earnings. The difference between fuel and purchased power
costs incurred and associated fuel revenues that is subject to recovery is
deferred for future collection or refund to customers.
51
Fuel and purchased power expenses were $805 million for the six months ended
June 30, 2004, which represents a $132 million increase compared to the same
period in the prior year. This increase is due to an increase in fuel used in
electric generation of $143 million offset by a reduction in purchased power
costs. This increase in fuel used in electric generation is due to the recovery
of fuel expenses that were deferred in the prior year, as well as the deferral
of current year fuel expenses. In November 2003, the FPSC approved PEF's request
for a cost adjustment in its annual fuel filing due to the rising costs of fuel.
The new rates became effective January 2004. The decrease in purchased power
expense of $11 million is attributable primarily to the Hines 2 Plant being
placed in service in December of 2003, thereby reducing the need for purchased
power.
O&M costs increased $17 million, when compared to the $295 million incurred
during the six months ended June 30, 2003. This increase is primarily related to
higher costs associated with scheduled plant outages and planned reliability
improvements of approximately $9 million each.
Depreciation and amortization decreased $18 million when compared to the $159
million incurred during the six months ended June 30, 2003, primarily due to the
amortization of the Tiger Bay regulatory asset in the prior year. The Tiger Bay
regulatory asset, for contract termination costs, was recovered pursuant to an
agreement between PEF which was approved by the FPSC in 1997, and as such
fluctuations in this expense did not have an impact on earnings. During the six
months ended June 30, 2003, Tiger Bay amortization was $30 million. The Tiger
Bay asset was fully amortized in September 2003. The decrease in Tiger Bay
amortization was partially offset by additional depreciation for assets placed
in service.
DIVERSIFIED BUSINESSES
The Company's diversified businesses consist of the Fuels segment, the CCO
segment, the Rail segment and the Other segment. These businesses are explained
in more detail below.
FUELS
The Fuels' segment operations include synthetic fuels production, natural gas
production, coal extraction and terminal operations. Fuels' results for the six
months ended June 30, 2003 were restated to reflect seven months of earnings for
certain operations, primarily synthetic fuel facilities.
The following summarizes Fuels' segment profits for the three and six months
ended June 30, 2004 and 2003:
- -----------------------------------------------------------------------------------------
Three Months Ended June 30 Six Months Ended June 30
- -----------------------------------------------------------------------------------------
(in millions) 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------
Synthetic fuel operations $ 36 $49 $ 72 $83
Gas production 12 9 25 16
Coal fuel and other operations 8 - 7 (2)
---------------------------------------------------
Segments Profits $ 56 $58 $ 104 $97
- -----------------------------------------------------------------------------------------
Synthetic Fuel Operations
The synthetic fuel operations generated net profits of $36 million and $49
million for the three months ended June 30, 2004 and 2003, respectively, and $72
million and $83 million for the six months ended June 30, 2004 and 2003,
respectively. The production and sale of synthetic fuel generate operating
losses, but qualify for tax credits under Section 29 of the Code, which more
than offset the effect of such losses. See Note 12 to the Progress Energy Notes
to the Consolidated Interim Financial Statements for further discussion of
synthetic fuel tax credit matters.
The operations resulted in the following for the three and six months ended June
30, 2004 and 2003:
- --------------------------------------------------------------------------------------------------
Three Months Ended June 30 Six Months Ended June 30
- --------------------------------------------------------------------------------------------------
(in millions) 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------
Tons sold 2.7 3.0 5.7 5.5
-------------------------------------------------------
Operating losses, excluding tax credits $ (35) $ (33) $ (77) $ (65)
Tax credits generated 71 82 149 148
-------------------------------------------------------
Net profits $ 36 $ 49 $ 72 $ 83
- --------------------------------------------------------------------------------------------------
52
Synthetic fuels' net profits decreased in the three months ended June 30, 2004
as compared to the same period in 2003 due primarily to a reduction in credits
earned of $4 million as a result of a decrease in tons sold and an increase in
operating cost of $4 million after-tax. Synthetic fuel profits decreased in the
six months ended June 30, 2004 due primarily to increases in operating cost of
$10 million. The Company anticipates total synthetic fuel production of
approximately 11 to 12 million tons for 2004 which is comparable to 2003
production levels.
Natural Gas Operations
Natural gas operations generated profits of $12 million and $9 million for the
three months ended June 30, 2004 and 2003, respectively, and $25 million and $16
million for the six months ended June 30, 2004 and 2003. The increase in
production resulting from the acquisition of North Texas Gas in late February
2003 and increased drilling and higher gas prices in 2004 contributed to
increased earnings in 2004 as compared to 2003. In October 2003, the Company
completed the sale of certain gas producing properties owned by Mesa
Hydrocarbons, LLC. The following summarizes the gas production, revenues and
gross margins for the three and six months ended June 30, 2004 and 2003 by
production facility:
- -----------------------------------------------------------------------------------------------------
Three Months Ended June 30 Six Months Ended June 30
- -----------------------------------------------------------------------------------------------------
2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------
Production in Bcf equivalent
Mesa - 1.5 - 3.2
Westchester 4.9 3.1 9.0 6.3
North Texas Gas 2.7 1.8 5.3 2.4
--------------------------------------------------------
Total Production 7.6 6.4 14.3 11.9
--------------------------------------------------------
Revenues in millions
Mesa $ - $ 3 $ - $ 8
Westchester 26 16 48 31
North Texas Gas 14 10 27 14
--------------------------------------------------------
Total Revenues $ 40 $ 29 $ 75 $ 53
--------------------------------------------------------
Gross Margin
in millions of $ $ 33 $ 24 $ 60 $ 43
As a % of revenues 83% 83% 80% 81%
- -----------------------------------------------------------------------------------------------------
Coal Fuel and Other Operations
Coal fuel and other operations generated segment profits of $8 million for the
three months ended June 30, 2004 compared to zero segment profits for the
comparable period in the prior year. For the six months ended June 30, 2004,
coal fuel and other operations generated segment profits of $7 million compared
to a segment loss of $2 million for the comparable period in the prior year.
This increase in profits for the quarter and year to date is due to higher
volumes and margins for coal fuel operations of $9 million after-tax offset by a
reduction in profits of $4 million after-tax for fuel transportation operations
related to the waterborne transportation ruling by the FPSC. See Note 4A of the
Progress Energy Consolidated Interim Financial Statements. The increase in
profits is also due to the impact of the retroactive Service Company allocation
in the prior year. Results in the same period for the prior year were negatively
impacted by the retroactive reallocation of Service Company costs of $4 million
after-tax.
COMPETiTIVE COMMERCIAL OPERATIONS
CCO's operations generated segment profits of $5 million for the three months
ended June 30, 2004 compared to $2 million of segment profits for the comparable
period in the prior year. Results for the three months ended June 30, 2004 were
favorably impacted by margins on new contracts and market sales of $15 million
partially offset by an increase in fixed costs. Fixed costs increased $6 million
from additional depreciation and amortization on plants placed in service and
from an increase in interest expense of $4 million due primarily to interest no
longer being capitalized due to the completion of construction in the prior
year.
CCO's operations generated segment losses of $3 million for the six months ended
June 30, 2004 compared to $11 million of segment profits for the comparable
period in the prior year. Results for the six months ended June 30, 2004 were
favorably impacted by increased gross margin which was offset by higher fixed
costs. Revenues increased a net of $34 million in the six months ended June 30,
2004 due to increased revenues from marketing and tolling contracts offset by a
termination payment received on a marketing contract in 2003 and mark to market
losses of $10 million. Expenses for the cost of fuel and purchased power to
53
supply our marketing contracts offset the increased revenues of $34M netting to
an increase in gross margin of $4 million for the six months ended June 30, 2004
as compared to the same prior year period. Fixed costs increased $14 million
from additional depreciation and amortization on plants placed into service in
2003 and from an increase in interest expense of $10 million due primarily to
interest no longer being capitalized due to the completion of construction in
the prior year. Expenses were favorably impacted by a reduction in Service
Company allocations. Results for 2003 were negatively impacted by the
retroactive reallocation of Service Company costs of $3 million ($2 million
after-tax).
- --------------------------------------------------------------------------------
Three Months Ended June 30 Six Months Ended June 30
- --------------------------------------------------------------------------------
(in millions) 2004 2003 2004 2003
- --------------------------------------------------------------------------------
Total revenues $ 72 $ 33 $ 105 $ 71
-----------------------------------------------------
Gross margin
In millions of $ $ 42 $ 27 $ 65 $ 61
As a % of revenues 58% 82% 62% 86%
-----------------------------------------------------
Segment profits (losses) $ 5 $ 2 $ (3) $ 11
- --------------------------------------------------------------------------------
The Company has contracts for 93% of planned production capacity for 2004 and
approximately 77% in both 2005 and 2006. The 2005 decline results from the
expiration of three tolling contracts. The Company continues to pursue
opportunities with both current and new potential customers.
RAIL
Rail's operations include railcar and locomotive repair, trackwork, rail parts
reconditioning and sales, scrap metal recycling and other rail related services.
The Company sold the majority of the assets of Railcar Ltd., a leasing
subsidiary, in 2004. See Note 3B of the Progress Energy Notes to the
Consolidated Interim Financial Statements.
Rail contributed segment profits of $4 million and $2 million for the three
months ended June 30, 2004 and 2003, respectively. Revenues have increased $71
million to $285 million for the three months ended June 30, 2004 compared to the
same period in the prior year. This increase is due primarily to increased
volumes and higher prices in recycling operations and in part to increased
production and sales in locomotive and railcar services and engineering and
track services. Cost of goods sold increased $62 million compared to $188
million in the prior year. The increase in costs of good sold is due to
increased costs for inventory, labor and operations as a result of the increased
volume in the recycling operations, locomotive and railcar services and
engineering and track services. The increase in margins of $9 million was
partially offset by an increase in general and administrative costs related
primarily to higher professional fees.
Rail contributed segment profit of $9 million for the six months ended June 30,
2004 compared with a segment loss of $1 million for the same period in the prior
year. Revenues have increased $130 million to $523 million for the six months
ended June 30, 2004 compared to the same period in the prior year. This increase
is due primarily to increased volumes and higher prices in recycling operations
and in part to increased production and sales in locomotive and railcar services
and engineering and track services. Cost of goods sold increased $112 million
compared to $455 million in the prior year. The increase in costs of good sold
is due to increased costs for inventory, labor and operations as a result of the
increased volume in the recycling operations, locomotive and railcar services
and engineering and track services. Results in the prior year were negatively
impacted by the retroactive reallocation of Service Company costs of $3 million
after-tax. The favorability related to the reallocation was offset by an
increase in general and administrative costs in the current year related
primarily to higher professional fees.
OTHER BUSINESSES SEGMENT
Progress Energy's Other segment primarily includes the operations of SRS and the
telecommunications operations of PTC LLC. SRS is engaged in providing energy
services to industrial, commercial and institutional customers to help manage
energy costs and currently focuses its activities in the southeastern United
States. PTC LLC operations provide broadband capacity services, dark fiber and
wireless services in Florida and the eastern United States.
SRS recorded a net loss of $29 million for the three months ended June 30, 2004
compared with profits of less than $1 million for the same period in the prior
year. SRS recorded a net loss of $29 million for the six months ended June 30,
2004 compared to a net loss of less than $1 million for the six months ended
June 30, 2004. The increased segment loss compared to the prior year is due
primarily to the recording of the litigation settlement reached with San
Francisco United School District related to civil proceedings. In June of 2004,
SRS reached a settlement with the District which settled all outstanding claims
for approximately $43 million pre-tax ($29 million after-tax).
54
CORPORATE SERVICES
Corporate Services includes the operations of the Holding Company, the Service
Company and consolidation entities, as summarized below:
- ------------------------------------------------------------------------------------------
Three Months Ended June 30 Six Months Ended June 30
- ------------------------------------------------------------------------------------------
(in millions) 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------
Other interest expense $ (66) $ (70) $ (139) $ (141)
Contingent value obligations (5) (2) (13) -
Tax levelization (5) (5) (43) 5
Tax reallocation (9) (9) (18) (18)
Other income taxes 28 31 65 62
Other (6) (3) (16) (10)
-------------------------------------------------------
Segment profit (loss) $ (63) $ (58) $ (164) $ (102)
- ------------------------------------------------------------------------------------------
Other interest expense decreased $4 million compared to $70 million for the
three months ended June 30, 2003 and it decreased $2 million compared to $141
million for the six months ended June 30, 2003. Interest expense decreased
during the current periods due to the repayment of a $500 million unsecured note
by the Holding company on March 1, 2004 which reduced interest expense by $8
million pre-tax for the quarter and year to date. This reduction was offset by
interest no longer being capitalized due to the completion of construction at
the CCO segment in the prior year. Approximately $4 million ($2 million
after-tax) and $10 million ($6 after-tax) was capitalized in the three and six
months ended June 30, 2003, respectively.
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 June 30, 2004 and 2003, the
CVOs had fair market values of approximately $36 million and $14 million,
respectively. Progress Energy recorded an unrealized loss of $5 million and $2
million for the three months ended June 30, 2004 and 2003, respectively, to
record the changes in fair value of the CVOs, which had average unit prices of
$0.36 and $0.14 at June 30, 2004 and 2003, respectively. Progress Energy
recorded an unrealized loss of $13 million for six months ended June 30, 2004.
The CVO values at June 30, 2003 were unchanged from the January 1, 2003 values,
thus requiring no recognition of unrealized gain or loss for the six months
ended June 30, 2003.
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 increased by $5 million for the three months ended June 30, 2004
and 2003, respectively, in order to maintain an effective tax rate consistent
with the estimated annual rate. Income tax expense was increased by $43 million
and decreased by $5 million for the six months ended June 30, 2004 and 2003,
respectively. The tax credits associated with the Company's synthetic fuel
operations primarily drive the required levelization amount. Fluctuations in
estimated annual earnings and tax credits can also cause large swings in the
effective tax rate for interim periods. Therefore, this adjustment will vary
each quarter, but will have no effect on net income for the year.
Other expenses increased $3 million and $6 million for the three and six months
ended June 30, 2004 and 2003, respectively, as compared to the same prior year
periods. This increase is due primarily to an increase in depreciation expense
at the Service Company due to assets being placed in service.
DISCONTINUED OPERATIONS
In 2002, the Company approved the sale of NCNG to Piedmont Natural Gas Company,
Inc. The sale closed on September 30, 2003. Net proceeds of approximately $443
million from the sale of NCNG were used to reduce outstanding short-term debt.
NCNG contributed $1 million of net income for the three months ended June 30,
2004 compared with $3 million of net income for the same prior year period.
During the three months ended June 30, 2004, the Company recorded an additional
gain after taxes of approximately $1 million related to deferred taxes on the
loss from the NCNG sale. NCNG contributed $1 million of net income for the six
months ended June 30, 2004 compared to $14 million for the comparable prior year
period.
55
LIQUIDITY AND CAPITAL RESOURCES
Progress Energy, Inc.
Progress Energy is a registered holding company and, as such, has no operations
of its own. As a holding company, Progress Energy's primary cash obligations are
its common dividend and interest expense. The ability to meet its obligations is
primarily dependent on the earnings and cash flows of its two electric utilities
and nonregulated subsidiaries, and the ability of those subsidiaries to pay
dividends or repay funds to Progress Energy.
Net cash provided by operating activities of $915 million increased $8 million
for the six months ended June 30, 2004, when compared to $907 million in the
corresponding period in the prior year. The slight improvement in cash from
operating activities for the 2004 period is primarily due to approximately $100
million of lower operating cash flow at PEF for the period in 2003, which
resulted from an under recovery of fuel costs, and reduced working capital needs
of nearly $50 million in the current year. These improvements in cash from
operating activities were partially offset by a $114 million decrease in net
income for the period.
Net cash used in investing activities of $591 million decreased $604 million for
the six months ended June 30, 2004, when compared to $1.2 billion in the
corresponding period in the prior year. The decrease is primarily due to reduced
nonregulated capital expenditures, primarily the purchase of North Texas Gas
assets and a long-term power supply contract during the first half of 2003. In
addition, proceeds from the sale of Railcar Ltd. assets reduced net investing
cash requirements during the first half of 2004.
For the first six months of 2004, Progress Energy's cash from operations less
cash used in investing activities increased approximately $600 million. The
improvement was due to the reduction in capital expenditures discussed above.
The positive cash flow combined with the equity issuance of $58 million, helped
reduce the Company's consolidated leverage to 58.2% from 58.9% as of December
31, 2003.
Progress Energy took advantage of favorable market conditions and entered into a
new $1.1 billion five year line of credit, effective August 5, 2004, and
expiring August 4, 2009. This facility replaces Progress Energy's $250 million
364 day line of credit and its three-year $450 million line of credit, which
were set to expire in November 2004.
On July 28, 2004, PEC extended its $165 million 364-day line of credit, which
was to expire on July 29, 2004. The line of credit will expire on July 27, 2005.
On April 30, 2004, PEC redeemed $34.7 million of Darlington County 6.6% Series
Pollution Control Bonds at 102.5% of par, $1.795 million of New Hanover County
6.3% Series Pollution Control Bonds at 101.5% of par, and $2.58 million of
Chatham County 6.3% Series Pollution Control Bonds at 101.5% of par with cash
from operations.
On March 1, 2004, Progress Energy used available cash and proceeds from the
issuance of commercial paper to retire $500 million 6.55% senior unsecured
notes. Cash and commercial paper capacity were created primarily from the sale
of assets and early long term debt financings in 2003.
On January 15, 2004, PEC paid at maturity $150 million 5.875% First Mortgage
Bonds with commercial paper proceeds. On April 15, 2004, PEC also paid at
maturity $150 million 7.875% First Mortgage Bonds with commercial paper proceeds
and cash from operations.
On February 9, 2004, Progress Capital Holdings, Inc. paid at maturity $25
million 6.48% medium term notes with excess cash.
For the six months ended June 30, 2004, the Company issued approximately 1.3
million shares representing approximately $58 million in proceeds from its
Investor Plus Stock Purchase Plan and its employee benefit plans. For the six
months ended June 30, 2004 and 2003, the dividends paid on common stock were
approximately $280 million and $268 million, respectively.
PEC has exclusively utilized external funding for its decommissioning liability
since 1994. Prior to 1994, PEC retained its funds internally to meet its
decommissioning liability. A North Carolina Utilities Commission (NCUC) order
issued in February 2004 found that by January 1, 2008, PEC must begin
transitioning these amounts to external funds. The transition of $131 million
must be completed by December 31, 2017, and at least 10% must be transitioned
each year.
56
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 June 30, 2004, Progress Energy's contractual cash obligations and other
commercial commitments have not changed materially from what was reported in the
2003 Annual Report on Form 10-K.
The total amount of liquidity requirements associated with guarantees for the
company's nonregulated portfolio and power supply agreements is $497 million.
As of June 30, 2004, the current portion of long-term debt is $343 million.
As of June 30, 2004, Progress Energy's guarantees issued on behalf of third
parties were approximately $24 million.
OTHER MATTERS
PEF Rate Case Settlement
In March 2002, the parties in PEF's rate case entered into a Stipulation and
Settlement Agreement (the Agreement) related to retail rate matters. The
Agreement was approved by the FPSC and is generally effective from May 1, 2002
through December 31, 2005; provided, however, that if PEF's base rate earnings
fall below a 10% return on equity, PEF may petition the FPSC to amend its base
rates.
Synthetic Fuels Tax Credits
Progress Energy's synthetic fuel operations are subject to numerous risks that
may impact the Company, its operations, and the value of its securities. Many of
these risks are discussed in the Company's 2003 10-K, particularly the Risk
Factors section. You should carefully read about these risks.
Progress Energy, through its subsidiaries, produces a coal-based solid synthetic
fuel. The production and sale of the synthetic fuel from these facilities
qualifies for tax credits under Section 29 of the Code (Section 29) if certain
requirements are satisfied, including a requirement that the synthetic fuel
differs significantly in chemical composition from the coal used to produce such
synthetic fuel and that the fuel was produced from a facility that was placed in
service before July 1, 1998. Synthetic fuel tax credit amounts not utilized are
carried forward indefinitely as alternative minimum tax credits. All of Progress
Energy's synthetic fuel facilities have received private letter rulings (PLRs)
from the Internal Revenue Service (IRS) with respect to their synthetic fuel
operations. These tax credits are subject to review by the IRS, and if Progress
Energy fails to prevail through the administrative or legal process, there could
be a significant tax liability owed for previously taken Section 29 credits,
with a significant impact on earnings and cash flows. Additionally, the ability
to use tax credits currently being carried forward could be denied. Total
Section 29 credits generated to date (including those generated by FPC prior to
its acquisition by the Company) are approximately $1.4 billion, of which $584
million have been used and $807 million are being carried forward as deferred
tax credits. The current Section 29 tax credit program expires at the end of
2007.
In September 2002, all of the Company's majority-owned synthetic fuel entities
were accepted into the IRS's Pre-filing Agreement (PFA) program. The PFA program
allows taxpayers to voluntarily accelerate the IRS exam process in order to seek
resolution of specific issues. Either the Company or the IRS can withdraw from
the program, and issues not resolved through the program may proceed to the next
level of the IRS exam process.
In July 2004, Progress Energy was notified that the Internal Revenue Service
(IRS) field auditors anticipate taking an adverse position regarding the
placed-in-service date of the Company's four Earthco synthetic fuel facilities.
Due to the auditors' position, the IRS has decided to exercise its right to
withdraw from the Pre-Filing Agreement (PFA) program with Progress Energy. With
the IRS's withdrawal from the PFA program, the review of Progress Energy's
Earthco facilities is back on the normal procedural audit path of the Company's
tax returns. The IRS has indicated that the field audit team will provide its
written recommendation later this year. After the field audit team's written
recommendation is received, the Company will begin the Appeals process within
the IRS. Through June 30, 2004 the Company, on a consolidated basis, has claimed
$1 billion of tax credits generated by Earthco facilities. If these credits were
57
disallowed, the Company's one time exposure for cash tax payments would be $229
million (excluding interest), and earnings and equity would be reduced by $1
billion, excluding interest. The Company believes that the appeals process could
take up to two years to complete, however, it cannot control the actual timing
of resolution and cannot predict the outcome of this matter.
In February 2004, subsidiaries of the Company finalized execution of the Colona
Closing Agreement with the IRS concerning their Colona synthetic fuel
facilities. The Colona Closing Agreement provided that the Colona facilities
were placed in service before July 1, 1998, which is one of the qualification
requirements for tax credits under Section 29. The Colona Closing Agreement
further provides that the fuel produced by the Colona facilities in 2001 is a
"qualified fuel" for purposes of the Section 29 tax credits. This action
concluded the IRS PFA program with respect to Colona.
In June 2004, the Company through its subsidiary, Progress Fuels sold, in two
transactions, a combined 49.8 percent partnership interest in Colona Synfuel
Limited Partnership, LLLP, one of its synthetic fuel facilities. Substantially
all proceeds from the sales will be received over time, which is typical of such
sales in the industry. Gain from the sales will be recognized on a cost recovery
basis. The Company's book value of the interests sold totaled approximately $5
million. Based on projected production levels, the Company anticipates receiving
total gross proceeds of approximately $30 million per year, on an annualized
basis. Under the agreements, the buyers have a right to unwind the transactions
if an IRS reconfirmation private letter ruling (PLR) is not received by October
15, 2004. Therefore, no gain would be recognized prior to the expiration of that
right.
In October 2003, the United States Senate Permanent Subcommittee on
Investigations began a general investigation concerning synthetic fuel tax
credits claimed under Section 29. The investigation is examining the utilization
of the credits, the nature of the technologies and fuels created, the use of the
synthetic fuel and other aspects of Section 29 and is not specific to the
Company's synthetic fuel operations. Progress Energy is providing information in
connection with this investigation. The Company cannot predict the outcome of
this matter.
In management's opinion, Progress Energy is complying with all the necessary
requirements to be allowed such credits under Section 29, and, although it
cannot provide certainty, it believes that it will prevail in these matters.
Accordingly, the Company has no current plans to alter its synthetic fuel
production schedule as a result of these matters. However, should the Company
fail to prevail in these matters, there could be material liability for
previously taken Section 29 credits, with a material adverse impact on earnings
and cash flows.
Nuclear Matters
The United States Nuclear Regulatory Commission (NRC) on April 19, 2004,
announced that it has renewed the operating license for PEC's Robinson Nuclear
Plant (Robinson) for an additional 20 years through July 2030. The original
operating license of 40 years was set to expire in 2010. NRC operating licenses
held by PEC currently expire in December 2014 and September 2016 for Brunswick
Units 2 and 1, respectively. An application to extend these licenses 20 years is
expected to be submitted in October 2004. The NRC operating license held by PEC
for the Shearon Harris Nuclear Plant (Harris Plant) currently expires in October
2026. An application to extend this license 20 years is expected to be submitted
in the fourth quarter of 2006.
The NRC operating license held by PEF for Crystal River Unit No. 3 (CR3)
currently expires in December 2016. An application to extend this license 20
years is expected to be submitted in the first quarter 2009.
On February 27, 2004, PEC requested to have its license for the Independent
Spent Fuel Storage Installation at the Robinson Plant extended 20 years with an
exemption request for an additional 20-year extension. Its current license is
due to expire in August 2006. PEC expects to receive this extension.
During the first quarter of 2004, PEC met the requirements of both the NCUC and
the SCPSC for the implementation of a depreciation study which allowed the
utility to reduce the rates used to calculate depreciation expense. The
reduction in depreciation expense is primarily attributable to assumption
changes for nuclear generation.
In February 2004, the NRC issued a revised Order for inspection requirements for
reactor pressure vessel heads at PWRs. Progress Energy has reviewed the required
inspection frequencies and has incorporated them into long range plans. Harris
will complete the required non-visual NDE inspection prior to February 2008.
Both CR3 and Robinson will be required to inspect their new heads within 7 years
or four refueling outages after replacement. CR3 plans to inspect its new head
prior to the end of 2009 and Robinson will need to inspect its new head prior to
2012.
58
The NRC has issued various orders since September 2001 with regard to security
at nuclear plants. These orders include additional restrictions on access,
increased security measures at nuclear facilities and closer coordination with
the Company's partners in intelligence, military, law enforcement and emergency
response at the federal, state and local levels. The Company is completing the
requirements as outlined in the orders by the established deadlines. As the NRC,
other governmental entities and the industry continue to consider security
issues, it is possible that more extensive security plans could be required.
Franchise Litigation
Three cities, with a total of approximately 18,000 customers, have litigation
pending against PEF in various circuit courts in Florida. As 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 in
July 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 in May 2003
setting the value of PEF's distribution system within the City of Winter Park at
approximately $32 million, not including separation and reintegration costs and
construction work in progress, which could add several million dollars to the
award. The panel also awarded PEF approximately $11 million in stranded costs,
which according to the award decreases over time. In September 2003, Winter Park
voters passed a referendum that would authorize the City to issue bonds of up to
approximately $50 million to acquire PEF's electric distribution system. While
the City has not yet definitively decided whether it will acquire the system, on
April 26, 2004, the City Commission voted to enter into a hedge agreement to
lock into interest rates for the acquisition of the system and to proceed with
the acquisition. The City sought and received wholesale power supply bids and on
June 23, 2004, executed a wholesale power supply contract with PEF. On May 12,
2004, the City solicited bids to operate and maintain the distribution system.
The City received bids on July 1, 2004, and expects to make its selection in
August 2004. The City has indicated that its goal is to begin electric
operations in June 2005. At this time, whether and when there will be further
proceedings regarding the City of Winter Park cannot be determined.
A third arbitration (with the 2,500-customer Town of Belleair) was completed in
June 2003. In September 2003, the arbitration panel issued an award in that case
setting the value of the electric distribution system within the Town at
approximately $6 million. The panel further required the Town to pay to PEF its
requested $1 million in separation and reintegration costs and approximately $2
million in stranded costs. The Town has not yet decided whether it will attempt
to acquire the system. 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) had been
scheduled for January 2004. In December 2003, the Apopka City Commission voted
on first reading to approve a settlement agreement and a 30-year franchise with
PEF. The settlement and franchise became effective upon approval by the
Commission at a second reading of the franchise in January 2004. The settlement
resolves all outstanding litigation between the parties.
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 in August 2003. Subsequently, the Court requested briefing
from the parties in the other appeal, which was completed in November 2003. The
Company cannot predict the outcome of these matters at this time.
59
Progress Energy Carolinas, Inc.
The information required by this item is incorporated herein by reference to the
following portions of Progress Energy's Management's Discussion and Analysis of
Financial Condition and Results of Operations, insofar as they relate solely to
PEC: RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES and OTHER MATTERS.
RESULTS OF OPERATIONS
The results of operations for the PEC Electric segment are identical between PEC
and Progress Energy. The results of operations for PEC's non-utility
subsidiaries for the three and six months ended June 30, 2004 and 2003 are not
material to PEC's consolidated financial statements.
LIQUIDITY AND CAPITAL RESOURCES
As of June 30, 2004, PEC's contractual cash obligations and other commercial
commitments have not changed materially from what was reported in the 2003
Annual Report on Form 10-K.
Cash provided by operating activities decreased $45 million for the six months
ended June 30, 2004, when compared to the corresponding period in the prior
year. The decrease was caused primarily by a $34 million increase in working
capital requirements.
Cash used in investing activities decreased $13 million for the six months ended
June 30, 2004, when compared to the corresponding period in the prior year
primarily due to lower construction spending.
$150 million of First Mortgage Bonds matured on January 15, 2004 and $150
million of First Mortgage Bonds matured on April 15, 2004. The remaining $300
million current portion of long-term debt will be refinanced or retired through
commercial paper, capital market transactions and internally generated funds.
On July 28, 2004, PEC extended its $165 million 364-day line of credit, which
was to expire on July 29, 2004. The line of credit will expire on July 27, 2005.
PEC has exclusively utilized external funding for its decommissioning liability
since 1994. Prior to 1994, PEC retained its funds internally to meet its
decommissioning liability. A North Carolina Utilities Commission (NCUC) order
issued in February 2004 found that by January 1, 2008, PEC must begin
transitioning these amounts to external funds. The transition of $131 million
must be completed by December 31, 2017, and at least 10% must be transitioned
each year.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Progress Energy, Inc.
Other than described below, the various risks that the Company is exposed to has
not materially changed since December 31, 2003.
Market risk represents the potential loss arising from adverse changes in market
rates and prices. Certain market risks are inherent in the Company's financial
instruments, which arise from transactions entered into in the normal course of
business. The Company's primary exposures are changes in interest rates with
respect to its long-term debt and commercial paper, and fluctuations in the
return on marketable securities with respect to its nuclear decommissioning
trust funds. The Company manages its market risk in accordance with its
established risk management policies, which may include entering into various
derivative transactions.
The Company's exposure to return on marketable securities for the
decommissioning trust funds has not changed materially since December 31, 2003.
The Company's exposure to market value risk with respect to the CVOs has also
not changed materially since December 31, 2003. The exposure to changes in
interest rate from the Company's commercial paper was not materially different
than at December 31, 2003.
The exposure to changes in interest rates from the Company's fixed rate and
variable rate long-term debt at June 30, 2004 has changed from December 31,
2003. The total fixed rate long-term debt at June 30, 2004 was $8.6 billion,
with an average interest rate of 6.53% and fair market value of $9.3 billion.
The total variable rate long-term debt at June 30, 2004, was $1.1 billion, with
an average interest rate of 1.70% and fair market value of $1.1 billion.
The company maintains a portion of its outstanding debt with floating interest
rates. As of June 30, 2004 approximately 22% of consolidated debt was in
floating rate mode compared to 18% at the end of 2003.
Progress Energy uses interest rate derivative instruments to adjust the fixed
and variable rate debt components of its debt portfolio and to hedge interest
rates with regard to future fixed rate debt issuances.
As of June 30, 2004, Progress Energy had $1 billion 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 between
March 2006 and March 2011. During the year, Progress Energy has entered into
$350 million notional of open interest rate fair value hedges. In March 2004,
two interest rate swap agreements totaling $200 million were terminated. These
swaps were associated with Progress Energy 5.85% Notes due in 2008. The loss on
the agreements was deferred and is being amortized over the life of the bonds as
these agreements had been designated as fair value hedges for accounting
purposes.
As of June 30, 2004, PEC had $70 million notional of pay fixed forward starting
swaps, entered into in March 2004, to hedge its exposure to interest rates with
regard to a future issuance of debt and $26 million notional of pay fixed
forward starting swaps, in April 2004, to hedge its exposure to interest rates
with regard to an upcoming railcar lease. In July 2004, PEC entered into an
additional $30 million notional pay fixed forward swap, increasing the total to
$126 million. These agreements have a computational period of ten years.
In May 2004, the Company terminated interest rate cash flow hedges, with a total
notional amount of $400 million, related to projected outstanding balances of
commercial paper. Amounts in accumulated other comprehensive income related to
these terminated hedges will be reclassified to earnings as the hedged interest
payments occur.
The Company holds interest rate collars with a varying notional amount
(currently at the maximum of $195 million) to hedge floating rate exposure
associated with variable rate long-term debt at Progress Ventures. The Company
is required to hedge 50% of the amount outstanding under its bank facility
through March 2007.
The notional amounts of interest rate derivatives are not exchanged and do not
represent exposure to credit loss. In the event of default by a 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.
61
PEF has entered into derivative instruments to hedge its exposure to price
fluctuations on fuel oil purchases. These instruments did not have a material
impact on the Company's consolidated financial position or results of
operations.
Progress Fuels Corporation, through Progress Ventures, Inc. (PVI), periodically
enters into derivative instruments to hedge its exposure to price fluctuations
on natural gas sales. As of June 30, 2004, Progress Fuels Corporation is hedging
exposures to the price variability of portions of its natural gas production
through December 2005. These instruments did not have a material impact on the
Company's consolidated financial position or results of operations.
Nonhedging derivatives, primarily electricity and natural gas contracts, are
entered into for trading purposes and for economic hedging purposes. While
management believes the economic hedges mitigate exposures to fluctuations in
commodity prices, these instruments are not designated as hedges for accounting
purposes and are monitored consistent with trading positions.
Progress Energy Carolinas, Inc.
Other than described below, the various risks that PEC is exposed to has not
materially changed since December 31, 2003.
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, 2003.
The exposure to changes in interest rates from PEC's fixed rate long-term debt,
variable rate long-term debt and commercial paper at June 30, 2004 was not
materially different than at December 31, 2003.
As of June 30, 2004, PEC had $70 million notional of pay fixed forward starting
swaps, entered into in March 2004, to hedge its exposure to interest rates with
regard to a future issuance of debt and $26 million notional of pay fixed
forward starting swaps, in April 2004, to hedge its exposure to interest rates
with regard to an upcoming railcar lease. In July 2004, PEC entered into an
additional $30 million notional pay fixed forward swap, increasing the total to
$126 million. These agreements have a computational period of ten years.
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. PEC only enters into interest rate derivative agreements with
banks with credit ratings of single A or better.
62
Item 4: Controls and Procedures
Progress Energy, Inc.
Pursuant to the Securities Exchange Act of 1934, Progress Energy carried out an
evaluation, with the participation of Progress Energy's management, including
Progress Energy's President and Chief Executive Officer, and Chief Financial
Officer, of the effectiveness of Progress Energy's disclosure controls and
procedures (as defined under the Securities Exchange Act of 1934) as of the end
of the period covered by this report. Based upon that evaluation, Progress
Energy's President and Chief Executive Officer, and Chief Financial Officer
concluded that Progress Energy's disclosure controls and procedures are
effective in timely alerting them to material information relating to Progress
Energy (including its consolidated subsidiaries) required to be included in
Progress Energy's periodic SEC filings.
There has been no change identified in Progress Energy's internal control over
financial reporting during the quarter ended June 30, 2004 that has materially
affected, or is reasonably likely to materially affect, Progress Energy's
internal control over financial reporting.
Progress Energy Carolinas, Inc.
Pursuant to the Securities Exchange Act of 1934, PEC carried out an evaluation,
with the participation of PEC's management, including PEC's President and Chief
Executive Officer, and Chief Financial Officer, of the effectiveness of PEC's
disclosure controls and procedures (as defined under the Securities Exchange Act
of 1934) as of the end of the period covered by this report. Based upon that
evaluation, PEC's President and Chief Executive Officer, and Chief Financial
Officer concluded that PEC's disclosure controls and procedures are effective in
timely alerting them to material information relating to PEC (including its
consolidated subsidiaries) required to be included in PEC's periodic SEC
filings.
There has been no change identified in PEC's internal control over financial
reporting during the quarter ended June 30, 2004 that has materially affected,
or is reasonably likely to materially affect, PEC's internal control over
financial reporting.
63
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Legal aspects of certain matters are set forth in Part I, Item 1. See Note 12 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 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. In March 2002,
the District filed a counterclaim, seeking compensatory damages and liquidated
damages in excess of $120 million, for various claims, including breach of
contract and demand on a performance bond. SRS asserted defenses to the
District's claims. SRS amended its claims and asserted new claims against the
District and other parties, including a former SRS employee and a former
District employee.
In March 2003, the City Attorney and the District filed new claims in the form
of a cross-complaint against SRS, Progress Energy, Inc., Progress Energy
Solutions, Inc., and certain individuals, alleging fraud, false claims,
violations of California statutes, and seeking compensatory damages, punitive
damages, liquidated damages, treble damages, penalties, attorneys' fees and
injunctive relief. The filing stated that the City and the District seek "more
than $300 million in damages and penalties." PEC was later added as a
cross-defendant. In November 2003, PEC filed a motion to dismiss the plaintiffs'
first amended complaint.
In June 2004, the Company reached a settlement agreement with the District in
this matter. The settlement totaled approximately $43.1 million and was recorded
as a charge to diversified business cost of sales in the Company's Consolidated
Statement of Income for the three-months ended June 30, 2004. The accrual of the
settlement was recorded on an undiscounted basis. The terms of the settlement
require SRS to pay the District $10.1 million upon approval, and an additional
$16 million in 2005 and $17 million 2006. In addition, during a transition
period ending September 10, 2004, SRS will provide maintenance and training on
the equipment and software it installed and maintained for the District. The
agreement, upon approval, settles all claims and cross-claims related to SRS,
Progress Energy, Progress Energy Solutions and PEC.
2. U.S. Global, LLC v. Progress Energy, Inc. et al, Case No. 03004028-03 and
Progress Synfuel Holdings, Inc. et al, v. U.S. Global, LLC, Case No.
03004028-03
A number of Progress Energy, Inc. subsidiaries and affiliates are parties to two
lawsuits arising out of an Asset Purchase Agreement dated as of October 19,
1999, by and among U.S. Global LLC (Global), EARTHCO, certain affiliates of
EARTHCO (collectively the EARTHCO Sellers), EFC Synfuel LLC (which is owned
indirectly be Progress Energy, Inc.) and certain of its affiliates, including
Solid Energy LLC, Solid Fuel LLC, Ceredo Synfuel LLC, Gulf Coast Synfuel LLC
(currently named Sandy River Synfuel LLC) (Collectively the Progress
Affiliates), as amended by an amendment to Purchase Agreement as of August 23,
2000 (the Asset Purchase Agreement). Global has asserted that pursuant to the
Asset Purchase Agreement it is entitled to (1) an interest in two synthetic fuel
facilities currently owned by the Progress Affiliates, and (2) an option to
purchase additional interests in the two synthetic fuel facilities.
The first suit, U.S. Global, LLC v. Progress Energy, Inc. et al, was filed in
the Circuit Court for Broward County, Florida in March 2003 (the Florida Global
Case). The Florida Global Case asserts claims for breach of the Asset Purchase
Agreement and other contract and tort claims related to the Progress Affiliates'
alleged interference with Global's rights under the Asset Purchase Agreement.
The Florida Global Case requests an unspecified amount of compensatory damages,
as well as declaratory relief. On December 15, 2003, the Progress Affiliates
filed a motion to dismiss the Third Amended Complaint in the Florida Global
Case. The motion to dismiss filed on behalf of the Progress Energy, Inc.
subsidiaries and affiliates that are parties to the case was heard by the
Circuit Court of Broward County, Florida on June 7, 2004. The case was dismissed
on procedural issues, but allowed the plaintiff to refile. The case was refiled
on June 23, 2004.
64
The second suit, Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC, was
filed by the Progress Affiliates in the Superior Court for Wake County, North
Carolina seeking declaratory relief consistent with the Company's interpretation
of the asset Purchase Agreement (the North Carolina Global Case). Global was
served with the North Carolina Global Case on April 17, 2003.
On May 15, 2003, Global moved to dismiss the North Carolina Global Case for lack
of personal jurisdiction over Global. In the alternative, Global requested that
the court decline to exercise its discretion to hear the Progress Affiliates'
declaratory judgment action. On August 7, 2003, the Wake County Superior court
denied Global's motion to dismiss and entered an order staying the North
Carolina Global Case, pending the outcome of the Florida Global Case. The
Progress Affiliates have appealed the Superior court's order staying the case;
Global has cross appealed the denial of its motion to dismiss for lack of
personal jurisdiction. The North Carolina Court of Appeals heard argument on the
Progress Affiliates' Appeal and the Global's cross appeal on May 26, 2004. There
has been no ruling on the appeal or the cross appeal. The Company cannot predict
the outcome of these matters, but will vigorously defend against the
allegations.
3. In re Progress Energy, Inc. Securities Litigation, Master File No.
04-CV-636 (JES)
On February 3, 2004, Progress Energy, Inc. was served with a class action
complaint alleging violations of federal security laws in connection with the
Company's issuance of Contingent Value Obligations (CVOs). The action was filed
by Gerber Asset Management LLC in the United States District Court for the
Southern District of New York and names Progress Energy, Inc.'s former Chairman
William Cavanaugh III and Progress Energy, Inc. as defendants. The Complaint
alleges that Progress Energy failed to timely disclose the impact of the
Alternative Minimum Tax required under Sections 55-59 of the Internal Revenue
Code (Code) on the value of certain CVOs issued in connection with the Florida
Progress Corporation merger. The suit seeks unspecified compensatory damages, as
well as, attorneys' fees and litigation costs.
On March 31, 2004, a second class action complaint was filed by Stanley Fried,
Raymond X. Talamantes and Jacquelin Talamantes against William Cavanaugh III and
Progress Energy, Inc. in the United States District Court for the Southern
District of New York alleging violations of federal securities laws arising out
of the Company's issuance of CVOs nearly identical to those alleged in the
February 3, 2004 Gerber Asset Management complaint. On April 29, 2004, the
Honorable John E. Sprizzo ordered among other things that (1) the two class
action cases be consolidated, (2) Peak6 Capital Management LLC shall serve as
the lead plaintiff in the consolidated action, and (3) the lead plaintiff shall
file a consolidated amended complaint on or before June 14, 2004.
The lead plaintiffs filed a consolidated amended complaint on June 15, 2004. In
addition to the allegations asserted in the Gerber Asset Management and Fried
complaints, the consolidated amended complaint alleges that the Company failed
to disclose that excess fuel credits could not be carried over from one tax year
into later years. On July 30, 2004, the Company filed a motion to dismiss the
complaint.
The Company cannot predict the outcome of this matter, but will vigorously
defend against the allegations.
65
Item 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity
Securities
RESTRICTED STOCK AWARDS:
(a) Securities Delivered. On April 28, 2004, 23,300 restricted shares 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.
66
Item 4. Submission of Matters to a Vote of Security Holders
Progress Energy Inc.
(a) The Annual Meeting of the Shareholders of Progress Energy, Inc. was held on
May 12, 2004.
(b) The meeting involved the election of five Class III directors to serve for
three-year terms. Proxies for the meeting were solicited pursuant to
Regulation 14, there was no solicitation in opposition to management's
nominees as listed below, and all nominees were elected.
(c) The total votes for the election of directors were as follows:
Class III Votes For Votes Withheld
(Term Expiring in 2007)
Charles W. Coker 208,883,229 4,775,358
Robert B. McGehee 209,390,084 4,268,503
E. Marie McKee 209,566,761 4,091,826
Peter S. Rummell 209,456,069 4,202,518
Jean Giles Wittner 207,028,428 6,630,159
(d) The shareholder proposal relating to stock options for Directors and
certain Executive Officers was presented, but was not approved by the
shareholders.
The number of shares voted for the proposal was 23,184,068
The number of shares voted against the proposal was 148,433,662
The number of abstaining votes was 4,850,014
The delivered not voted total was 37,190,843
Carolina Power & Light Company, doing business as Progress Energy Carolinas,
Inc.
(a) The Annual Meeting of the Shareholders of Carolina Power & Light Company
was held on May 12, 2004.
(b) The meeting involved the election of five Class III directors to serve
three-year terms. Proxies for the meeting were solicited pursuant to
Regulation 14, there was no solicitation in opposition to management's
nominees as listed below, and all nominees were elected.
(c) The total votes for the election of directors were as follows:
Class III Votes For Votes Withheld
(Term Expiring in 2007)
Charles W. Coker 1 59,964,384 6,387
Robert B. McGehee 159,964,895 5,876
E. Marie McKee 159,965,517 5,254
Peter S. Rummell 159,964,707 6,064
Jean Giles Wittner 159,964,687 6,064
67
Item 5. Other Information
Appointment of Presiding Director
John H. Mullin, III was appointed Chairman of the Corporate Governance Committee
of the Company's Board of Directors at the Board meeting that immediately
followed the Company's Annual Meeting of Shareholders on May 12, 2004. By virtue
of that position, Mr. Mullin is also the Presiding Director of the Board. (Mr.
Mullin succeeds J. Tylee Wilson, who retired from the Board on May 12, 2004.) As
Presiding Director, Mr. Mullin chairs the executive sessions of the non-employee
Directors. Mr. Mullin can be contacted by writing to John H. Mullin, III,
Presiding Director, Progress Energy Board of Directors, c/o Corporate Secretary,
P.O. Box 1551, Raleigh, NC 27602. Progress Energy screens mail addressed to Mr.
Mullin for security purposes and to ensure that it relates to discrete business
matters that are relevant to Progress Energy. Mail addressed to Mr. Mullin which
satisfies these screening criteria will be forwarded to him.
68
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. $1,130,000,00 5-Year X
Revolving Credit Agreement dated as of
August 5, 2004
31(a) Certifications pursuant to Section 302 of the X X
Sarbanes-Oxley Act of 2002 - Chairman, President
and Chief Executive Officer
31(b) Certifications pursuant to Section 302 of the X X
Sarbanes-Oxley Act of 2002 - Executive Vice
President and Chief Financial Officer
32(a) Certifications pursuant to Section 906 of the X X
Sarbanes-Oxley Act of 2002 - Chairman, President
and Chief Executive Officer
32(b) Certifications pursuant to Section 906 of the X X
Sarbanes-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 21, 2004 July 21, 2004
5, 9 No July 7, 2004 July 7, 2004
7, 9 Yes June 15, 2004 June 16, 2004
7, 9 No May 28, 2004 May 28, 2004
7, 9 No May 13, 2004 May 18, 2004
7, 9 No April 28, 2004 April 28, 2004
7, 11 No April 5, 2004 April 23, 2004
9, 12 Yes April 21, 2004 April 21, 2004
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 21, 2004 July 21, 2004
9, 12 Yes April 21, 2004 April 21, 2004
69
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: August 6, 2004 (Registrants)
By: /s/ Geoffrey S. Chatas
----------------------------
Geoffrey S. Chatas
Executive Vice President and
Chief Financial Officer
By: /s/ Robert H. Bazemore, Jr.
----------------------------
Robert H. Bazemore, Jr.
Vice President and Controller
Chief Accounting Officer