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, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to .
---- ----
Commission Exact name of registrants as specified in their charters, state of I.R.S. Employer
File Number incorporation, address of principal executive offices, and telephone number Identification Number
1-15929 Progress Energy, Inc. 56-2155481
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone: (919) 546-6111
State of Incorporation: North Carolina
1-3382 Carolina Power & Light Company 56-0165465
d/b/a Progress Energy Carolinas, Inc.
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone: (919) 546-6111
State of Incorporation: North Carolina
NONE
(Former name, former address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has 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 registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark whether Progress Energy, Inc. 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,
Inc. (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, 2003, each
registrant had the following shares of common stock outstanding:
Registrant Description Shares
---------- ----------- ------
Progress Energy, Inc. Common Stock (Without Par Value) 243,437,696
Carolina Power & Light Company Common Stock (Without Par Value) 159,608,055 (all of which
were held by Progress Energy, Inc.)
1
PROGRESS ENERGY, INC. AND PROGRESS ENERGY CAROLINAS, INC.
FORM 10-Q - For the Quarter Ended June 30, 2003
Glossary of Terms
Safe Harbor For Forward-Looking Statements
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Interim Financial Statements:
Progress Energy, Inc.
--------------------------------------------------------------
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Notes to Consolidated Interim Financial Statements
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
---------------------------------------------------------------
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Notes to Consolidated Interim Financial Statements
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
Item 6. Exhibits and Reports on Form 8-K
Signatures
2
GLOSSARY OF TERMS
The following abbreviations or acronyms used in the text of this combined Form
10-Q are defined below:
TERM DEFINITION
AFUDC Allowance for funds used during construction
the Agreement Stipulation and Settlement Agreement
ARO Asset retirement obligations
Bcf Billion cubic feet
CCO Competitive Commercial Operations
the Code Internal Revenue Service Code
Colona Colona Synfuel Limited Partnership, L.L.L.P.
the Company Progress Energy, Inc. and subsidiaries
CP&L Energy CP&L Energy, Inc., now known as Progress Energy, Inc.
CPI Consumer Price Index
CR3 Progress Energy Florida's nuclear generating plant, Crystal River Unit No. 3
CVO Contingent value obligation
DIG Derivatives Implementation Group
DOE United States Department of Energy
Dt Dekatherm
DWM North Carolina Department of Environment and Natural Resources, Division of Waste
Management
EITF Emerging Issues Task Force
ENCNG Eastern North Carolina Natural Gas Company, formerly referred to as Eastern NC
EPA United States Environmental Protection Agency
FASB Financial Accounting Standards Board
FDEP Florida Department of Environment and Protection
Federal Circuit U.S. 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"
FPC Florida Progress Corporation
FPSC Florida Public Service Commission
Funding Corp. Florida Progress Funding Corporation
GAAP Accounting principles generally accepted in the United States of America
Genco Progress Genco Ventures, LLC
IRS Internal Revenue Service
Jackson Jackson Electric Membership Corp.
KWh Kilowatt-hour
MACT Maximum Available Control Technology
MGP Manufactured gas plant
MW Megawatt
NCNG North Carolina Natural Gas Corporation
NCUC North Carolina Utilities Commission
NOx SIP Call EPA rule which requires 23 jurisdictions including North and South
Carolina and Georgia to further reduce nitrogen oxide emissions
NRC United States Nuclear Regulatory Commission
NSP Northern States Power
PCH Progress Capital Holdings, Inc.
PEC Progress Energy Carolinas, Inc., formerly referred to as Carolina Power & Light Company
PEF Progress Energy Florida, Inc., formerly referred to as Florida Power Corporation
PFA IRS Prefiling Agreement
the Plan Revenue Sharing Incentive Plan
PLRs Private Letter Rulings
Preferred Securities FPC-obligated mandatorily redeemable preferred securities
3
Progress Energy Progress Energy, Inc.
Progress Rail Progress Rail Services Corporation
Progress Telecom Progress Telecommunications Corporation
Progress Ventures Business segment of Progress Energy primarily made up of nonregulated
energy generation, gas, coal and synthetic fuel operations and energy
marketing and trading
PUHCA Public Utility Holding Company Act of 1935, as amended
PVI Legal entity of Progress Ventures, Inc., formerly referred to as CPL Energy Ventures, Inc.
PWR Pressurized water reactor
RAFT Railcar Asset Financing Trust
Rail Rail Services
RTO Regional Transmission Organization
SCPSC Public Service Commission of South Carolina
SEC United States Securities and Exchange Commission
Section 29 Section 29 of the Internal Revenue Service Code
Section 42 Section 42 of the Internal Revenue Service Code
Service Company Progress Energy Service Company, LLC
SFAS No. 5 Statement of Financial Accounting Standards No. 5, "Accounting for Contingencies"
SFAS No. 71 Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation"
SFAS No. 131 Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an
Enterprise and Related Information"
SFAS No. 133 Statement of Financial Accounting Standards No. 133, "Accounting for Derivative and
Hedging Activities"
SFAS No. 142 Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible
Assets"
SFAS No. 143 Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations"
SFAS No. 148 Statement of Financial Accounting Standards No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - An Amendment of FASB Statement No. 123"
SFAS No. 149 Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities"
SFAS No. 150 Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity"
SMD NOPR Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination
through Open Access Transmission and Standard Market Design
SRS Strategic Resource Solutions Corp.
the Trust FPC Capital I
4
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
This combined report contains forward-looking statements within the meaning of
the safe harbor provisions of the Private Securities Litigation Reform Act of
1995. The matters discussed throughout this combined Form 10-Q that are not
historical facts are forward-looking and, accordingly, involve estimates,
projections, goals, forecasts, assumptions, risks and uncertainties that could
cause actual results or outcomes to differ materially from those expressed in
the forward-looking statements.
In addition, forward-looking statements are discussed in "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
including, but not limited to, statements under the sub-heading "Other Matters"
about the effects of new environmental regulations, nuclear decommissioning
costs and the effect of electric utility industry restructuring.
Any forward-looking statement speaks only as of the date on which such statement
is made, and neither Progress Energy, Inc. (Progress Energy) nor Progress Energy
Carolinas, Inc. (PEC) undertakes any obligation to update any forward-looking
statement or statements to reflect events or circumstances after the date on
which such statement is made.
Examples of factors that you should consider with respect to any forward-looking
statements made throughout this document include, but are not limited to, the
following: the impact of fluid and complex government laws and regulations,
including those relating to the environment; the impact of recent events in the
energy markets that have increased the level of public and regulatory scrutiny
in the energy industry and in the capital markets; deregulation or restructuring
in the electric industry that may result in increased competition and
unrecovered (stranded) costs; the uncertainty regarding the timing, creation and
structure of regional transmission organizations; weather conditions that
directly influence the demand for electricity and natural gas; recurring
seasonal fluctuations in demand for electricity and natural gas; fluctuations in
the price of energy commodities and purchased power; economic fluctuations and
the corresponding impact on the Company's commercial and industrial customers;
the ability of the Company's subsidiaries to pay upstream dividends or
distributions to it; the impact on the facilities and the businesses of the
Company from a terrorist attack; the inherent risks associated with the
operation of nuclear facilities, including environmental, health, regulatory and
financial risks; the ability to successfully access capital markets on favorable
terms; the impact that increases in leverage may have on the Company; 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; the
outcome of the IRS's audit and inquiry into the availability and use of Section
29 tax credits by synthetic fuel producers and the Company's continued ability
to use Section 29 tax credits related to its coal and synthetic fuels
businesses; the continued depressed state of the telecommunications industry and
the Company's ability to realize future returns from Progress Telecommunications
Corporation and Caronet, Inc.; the Company's ability to successfully integrate
newly acquired assets, properties or businesses into its operations as quickly
or as profitably as expected; the Company's ability to successfully complete the
sale of North Carolina Natural Gas and apply the proceeds therefrom to reduce
outstanding indebtedness; the Company's ability to manage the risks involved
with the construction and operation of its nonregulated plants, including
construction delays, 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 and trading operations; the Company's
ability to obtain an extension of the Securities and Exchange Commission's order
requiring us to divest of Progress Rail Services Corporation by November 30,
2003; and unanticipated changes in operating expenses and capital expenditures.
Most of these risks similarly impact the Company's subsidiaries including PEC.
These and other risk factors are detailed from time to time in the Progress
Energy and PEC SEC reports. Many, but not all of the factors that may impact
actual results are discussed in the Risk Factors sections of Progress Energy's
and PEC's annual report on Form 10-K for the year ended December 31, 2002, which
were filed with the SEC on March 21, 2003. 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, 2003
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Six Months Ended
(Unaudited) June 30, June 30,
- -----------------------------------------------------------------------------------------------------------------------
(In thousands except per share data) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------------------------------------
Operating Revenues
Utility $ 1,582,787 $ 1,600,581 $ 3,236,674 $ 3,098,503
Diversified business 429,897 358,274 792,015 647,653
- -----------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 2,012,684 1,958,855 4,028,689 3,746,156
- -----------------------------------------------------------------------------------------------------------------------
Operating Expenses
Utility
Fuel used in electric generation 393,331 366,757 804,954 736,809
Purchased power 209,825 224,685 412,567 405,958
Operation and maintenance 364,766 346,358 699,079 675,332
Depreciation and amortization 223,595 210,485 443,683 422,373
Taxes other than on income 94,446 93,306 197,278 189,227
Diversified business
Cost of sales 379,710 347,438 686,651 647,963
Depreciation and amortization 33,680 29,329 61,948 56,664
Other 38,996 35,209 89,254 64,562
- -----------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 1,738,349 1,653,567 3,395,414 3,198,888
- -----------------------------------------------------------------------------------------------------------------------
Operating Income 274,335 305,288 633,275 547,268
- -----------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 3,531 6,153 6,297 8,106
Other, net (9,432) (2,340) (11,883) 3,718
- -----------------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) (5,901) 3,813 (5,586) 11,824
- -----------------------------------------------------------------------------------------------------------------------
Income before Interest Charges and Income Taxes 268,434 309,101 627,689 559,092
- -----------------------------------------------------------------------------------------------------------------------
Interest Charges
Net interest charges 159,520 170,161 315,768 340,330
Allowance for borrowed funds used during construction (2,222) (3,353) (5,109) (6,906)
- -----------------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 157,298 166,808 310,659 333,424
- -----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax 111,136 142,293 317,030 225,668
Income Tax Expense (Benefit) (39,174) 20,360 (30,146) (20,326)
- -----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations 150,310 121,933 347,176 245,994
Discontinued Operations, Net of Tax 2,513 (1,313) 13,803 7,153
- -----------------------------------------------------------------------------------------------------------------------
Net Income $ 152,823 $ 120,620 $ 360,979 $ 253,147
- -----------------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 236,057 215,007 234,755 213,999
- -----------------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
Income from Continuing Operations $ 0.64 $ 0.57 $ 1.48 $ 1.15
Discontinued Operations, Net of Tax $ 0.01 $ (0.01) $ 0.06 $ 0.03
Net Income $ 0.65 $ 0.56 $ 1.54 $ 1.18
- -----------------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share
Income from Continuing Operations $ 0.63 $ 0.56 $ 1.47 $ 1.15
Discontinued Operations, Net of Tax $ 0.01 $ 0.00 $ 0.06 $ 0.03
Net Income $ 0.64 $ 0.56 $ 1.53 $ 1.18
- -----------------------------------------------------------------------------------------------------------------------
Dividends Declared per Common Share $ 0.560 $ 0.545 $ 1.120 $ 1.090
- -----------------------------------------------------------------------------------------------------------------------
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
6
Progress Energy, Inc.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands except share data) June 30, December 31,
Assets 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 20,991,295 $ 20,152,787
Accumulated depreciation (9,990,819) (10,480,880)
- -----------------------------------------------------------------------------------------------------------------------------
Utility plant in service, net 11,000,476 9,671,907
Held for future use 12,864 15,109
Construction work in progress 842,520 752,336
Nuclear fuel, net of amortization 234,515 216,882
- -----------------------------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 12,090,375 10,656,234
- -----------------------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 45,654 61,358
Accounts receivable 824,233 737,369
Unbilled accounts receivable 217,586 225,011
Inventory 846,928 875,485
Deferred fuel cost 277,480 183,518
Assets of discontinued operations 491,784 490,429
Prepayments and other current assets 213,209 260,804
- -----------------------------------------------------------------------------------------------------------------------------
Total Current Assets 2,916,874 2,833,974
- -----------------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 640,891 393,215
Nuclear decommissioning trust funds 861,752 796,844
Diversified business property, net 2,213,623 1,884,271
Miscellaneous other property and investments 443,428 463,776
Goodwill 3,719,327 3,719,327
Prepaid pension costs 57,919 60,169
Other assets and deferred debits 684,764 517,182
- -----------------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 8,621,704 7,834,784
- -----------------------------------------------------------------------------------------------------------------------------
Total Assets $ 23,628,953 $ 21,324,992
- -----------------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- -----------------------------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, 500,000,000 shares authorized, 242,187,774 and
237,992,513 shares issued and outstanding,
respectively $ 5,109,564 $ 4,929,104
Unearned ESOP common stock (88,734) (101,560)
Accumulated other comprehensive loss (240,508) (237,762)
Retained earnings 2,182,440 2,087,227
- -----------------------------------------------------------------------------------------------------------------------------
Total Common Stock Equity 6,962,762 6,677,009
- -----------------------------------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries-Not Subject to Mandatory Redemption 92,831 92,831
Long-Term Debt 9,223,632 9,747,293
- -----------------------------------------------------------------------------------------------------------------------------
Total Capitalization 16,279,225 16,517,133
- -----------------------------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 1,130,308 275,397
Accounts payable 606,658 756,287
Interest accrued 222,896 220,400
Dividends declared 135,280 132,232
Short-term obligations 858,991 694,850
Customer deposits 161,539 158,214
Liabilities of discontinued operations 119,058 124,767
Other current liabilities 478,419 350,132
- -----------------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 3,713,149 2,712,279
- -----------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 824,961 932,813
Accumulated deferred investment tax credits 198,098 206,221
Regulatory liabilities 542,210 119,766
Asset retirement obligations 1,225,605 -
Other liabilities and deferred credits 845,705 836,780
- -----------------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,636,579 2,095,580
- -----------------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 15)
- -----------------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 23,628,953 $ 21,324,992
- -----------------------------------------------------------------------------------------------------------------------------
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
7
Progress Energy, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS Six Months Ended
(Unaudited) June 30,
(In thousands) 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 360,979 $ 253,147
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations (13,803) (7,153)
Depreciation and amortization 568,328 567,106
Deferred income taxes (118,442) (44,234)
Investment tax credit (8,123) (10,126)
Deferred fuel cost (credit) (93,962) 22,718
Net increase in accounts receivable (85,314) (35,229)
Net (increase) decrease in inventories 26,591 (38,637)
Net (increase) decrease in prepayments and other current assets 23,120 (14,993)
Net decrease in accounts payable (15,332) (62,655)
Net increase in income taxes, net 104,997 78,837
Net increase in other current liabilities 52,538 30,661
Other 92,666 39,896
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 894,243 779,338
- ------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions (541,205) (520,872)
Diversified business property additions and acquisitions (366,494) (627,042)
Nuclear fuel additions (84,050) (49,346)
Net contributions to nuclear decommissioning trust (17,959) (19,917)
Investments in non-utility activities (5,792) (10,301)
Acquisition of intangibles (190,168) -
Net decrease (increase) in restricted cash 16,784 (105,721)
Other (1,136) 5,257
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (1,190,020) (1,327,942)
- ------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net of issuance costs 171,771 -
Purchase of restricted shares (6,560) (5,393)
Issuance of long-term debt, net of issuance costs 654,824 1,013,633
Net increase in short-term indebtedness 163,092 14,499
Net decrease in cash provided by checks drawn in excess of bank balances (43,707) (33,605)
Retirement of long-term debt (392,054) (108,381)
Dividends paid on common stock (267,608) (238,404)
Other 815 47,407
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Financing Activities 280,573 689,756
- ------------------------------------------------------------------------------------------------------------------------
Cash Used in Discontinued Operations (500) (584)
- ------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (15,704) 140,568
Cash and Cash Equivalents at Beginning of the Period 61,358 53,708
- ------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of the Period $ 45,654 $ 194,276
- ------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 305,206 $ 324,234
income taxes (net of refunds) $ 22,241 $ 15,977
Noncash Activities
o On April 26, 2002, Progress Fuels Corporation, a subsidiary of the
Company, acquired 100% of Westchester Gas Company. In conjunction with
the purchase, the Company issued approximately $129.0 million in common
stock.
See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.
8
Progress Energy, Inc.
NOTES TO CONSOLIDATED INTERIM FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
A. Organization
Progress Energy, Inc. (Progress Energy or the Company) is a registered
holding company under the Public Utility Holding Company Act of 1935
(PUHCA), as amended. Both the Company and its subsidiaries are subject to
the regulatory provisions of PUHCA. Effective January 1, 2003, Carolina
Power & Light Company, Florida Power Corporation and Progress Ventures,
Inc. (PVI) began doing business under the names Progress Energy Carolinas,
Inc. (PEC), Progress Energy Florida, Inc. (PEF) and Progress Energy
Ventures, Inc., respectively. The legal names of these entities have not
changed, and there was no restructuring of any kind related to the name
change. The current corporate and business unit structure remains
unchanged.
Through its wholly owned subsidiaries, Progress Energy Carolinas, Inc. and
Progress Energy Florida, Inc., the Company is engaged in the generation,
purchase, transmission, distribution and sale of electricity primarily in
portions of North Carolina, South Carolina and Florida. The Progress
Ventures business unit consists of the Fuels and Competitive Commercial
Operations (CCO) operating segments. The Fuels operating segment includes
natural gas drilling and production, coal mining and synthetic fuels
production. The CCO operating segment includes nonregulated generation and
energy marketing and limited trading activities. Through other business
units, the Company engages in other nonregulated business areas, including
energy management and related services, rail services and
telecommunications. Progress Energy's legal structure is not currently
aligned with the functional management and financial reporting of the
Progress Ventures business unit. Whether, and when, the legal and
functional structures will converge depends upon legislative and regulatory
action, which cannot currently be anticipated.
B. Basis of Presentation
These financial statements have been prepared in accordance with accounting
principles generally accepted in the United States of America (GAAP) for
interim financial information and with the instructions to Form 10-Q and
Regulation S-X. Accordingly, they do not include all of the information and
footnotes required by GAAP for complete financial statements. Because the
accompanying consolidated interim financial statements do not include all
of the information and footnotes required by GAAP, they should be read in
conjunction with the audited financial statements for the period ended
December 31, 2002 and notes thereto included in Progress Energy's Form 10-K
for the year ended December 31, 2002.
In accordance with the provisions of APB 28, 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 $4.8 million and $58.4 million for the second quarter of 2003
and 2002, respectively, in order to maintain an effective tax rate
consistent with the estimated annual rate. Income tax expense was decreased
by $5.4 million and increased $79.6 million for the first half of 2003 and
2002, respectively.
The amounts included in the consolidated interim financial statements are
unaudited but, in the opinion of management, reflect all normal recurring
adjustments necessary to fairly present the Company's financial position
and results of operations for the interim periods. Due to seasonal weather
variations and the timing of outages of electric generating units,
especially nuclear-fueled units, the results of operations for interim
periods are not necessarily indicative of amounts expected for the entire
year or future periods.
In preparing financial statements that conform with GAAP, management must
make estimates and assumptions that affect the reported amounts of assets
and liabilities, disclosure of contingent assets and liabilities at the
date of the financial statements and amounts of revenues and expenses
reflected during the reporting period. Actual results could differ from
those estimates. Certain amounts for 2002 have been reclassified to conform
to the 2003 presentation.
2. ACQUISITIONS
During the first quarter of 2003, Progress Fuels Corporation, a wholly
owned subsidiary of Progress Energy, entered into three independent
transactions to acquire approximately 162 natural gas-producing wells with
proven reserves of approximately 195 billion cubic feet (Bcf) from Republic
Energy, Inc. and two other privately-owned companies, all headquartered in
Texas. The primary assets in the acquisition have been contributed to
9
Progress Fuels North Texas Gas, L.P., a wholly owned subsidiary of Progress
Fuels Corporation. The cash purchase price for the transactions totaled
$148 million.
On May 31, 2003, PVI acquired from Williams Energy Marketing and Trading, a
subsidiary of the Williams Companies, Inc., a long-term full-requirements
power supply agreement at fixed prices with Jackson Electric Membership
Corp. (Jackson), for $188.2 million. See Note 7 for additional information.
3. DIVESTITURES
A. NCNG Divestiture
On October 16, 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., for approximately $400 million in net
proceeds. By order issued June 26, 2003, the North Carolina Utilities
Commission (NCUC) approved the Company's application to sell NCNG to
Piedmont Natural Gas Company, Inc. The closing of the acquisition is
subject to the approval of the Securities and Exchange Commission (SEC).
The sale is expected to close during the summer of 2003. Net proceeds from
the sale will be used to pay down debt obligations.
The accompanying consolidated interim financial statements have been
restated for all periods presented for the discontinued operations of NCNG.
The net income of these operations is reported as discontinued operations
in the Consolidated Statements of Income. Interest expense has been
allocated to discontinued operations based on the net assets of NCNG,
assuming a uniform debt-to-equity ratio across the Company's operations.
Interest expense allocated for the three months ended June 30, 2003 and
2002 was $3.3 million and $4.0 million, respectively. Amounts allocated for
the six months ended June 30, 2003 and 2002 were $6.9 million and $8.0
million, respectively. The Company ceased recording depreciation upon
classification of the assets as discontinued operations. After-tax
depreciation expense recorded by NCNG during the second quarter of 2002 was
$2.9 million and during the first half of 2002 was $5.8 million. The asset
group, including goodwill, has been recorded at fair value less cost to
sell, resulting in an estimated loss on disposal of approximately $29.4
million, which was recorded in the fourth quarter of 2002. The estimated
loss is reviewed quarterly and will be finalized once the disposition is
complete and the actual loss can be determined. Results of discontinued
operations were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
(in thousands) 2003 2002 2003 2002
-------------- ------------- --------------- --------------
Revenues $ 70,815 $ 64,510 $ 225,041 $ 150,625
============== ============= =============== ==============
Earnings (loss) before income taxes $ 4,119 $(5,514) $ 22,602 $ 8,522
Income tax expense (benefit) 1,606 (4,201) 8,799 1,369
-------------- ------------- --------------- --------------
Net earnings (loss) from discontinued
operations $ 2,513 $(1,313) $ 13,803 $ 7,153
============== ============= =============== ==============
The major balance sheet classes included in assets and liabilities of
discontinued operations in the Consolidated Balance Sheets are as follows:
June 30, December 31,
(in thousands) 2003 2002
--------------- ----------------
Utility plant, net $ 403,515 $398,931
Current assets 69,743 72,821
Deferred debits and other assets 18,526 18,677
--------------- ----------------
Assets of discontinued operations $ 491,784 $490,429
=============== ================
Current liabilities $ 68,884 $ 76,372
Deferred credits and other liabilities 50,174 48,395
--------------- ----------------
Liabilities of discontinued operations $119,058 $124,767
=============== ================
The Company's equity investment in ENCNG of $7.7 million as of June 30,
2003 and December 31, 2002 is included in miscellaneous other property and
investments in the Consolidated Balance Sheets.
10
B. Railcar Ltd. Divestiture
In December 2002, the Progress Energy Board of Directors adopted a
resolution to sell the assets of Railcar Ltd., a leasing subsidiary
included in the Rail Services segment. A series of sales transactions is
expected to take place throughout 2003. An estimated impairment on assets
held for sale was recognized in December 2002 to write-down the assets to
fair value less costs to sell.
The assets of Railcar Ltd. have been grouped as assets held for sale and
are included in other current assets in the accompanying Consolidated
Balance Sheets as of June 30, 2003. The assets are recorded at $24.0
million and $23.6 million as of June 30, 2003 and December 31, 2002,
respectively.
On March 12, 2003, the Company signed a letter of intent to sell the
majority of Railcar Ltd. assets to The Andersons, Inc. The majority of the
proceeds from the sale will be used by the Company to pay off certain
Railcar Ltd. off balance sheet lease obligations for railcars that will be
transferred to The Andersons, Inc. as part of the sales transaction. The
transaction is subject to various closing conditions including financing,
due diligence and the completion of a definitive purchase agreement.
4. FINANCIAL INFORMATION BY BUSINESS SEGMENT
The Company currently has the following business segments: Progress Energy
Carolinas Electric (PEC Electric), Progress Energy Florida (PEF), Fuels,
Competitive Commercial Operations (CCO), Rail Services (Rail) and Other
Businesses (Other). Prior to 2003, Fuels and CCO were reported together as
the Progress Ventures business segment and corporate costs were included in
the Other segment. These reportable segment changes reflect the current
management structure. Additionally, earnings from wholesale customers of
the regulated plants have previously been reported in both the regulated
utilities' results and the results of Progress Ventures. With the
realignment of the reportable business segments, these results are now
included in each of the respective regulated utilities' results only.
The PEC Electric and PEF segments are engaged in the generation,
transmission, distribution and sale of electric energy primarily in
portions of North Carolina, South Carolina and Florida. These electric
operations are subject to the rules and regulations of the Federal Energy
Regulatory Commission (FERC), the NCUC, the Public Service Commission of
South Carolina (SCPSC), the Florida Public Service Commission (FPSC) and
the U.S. Nuclear Regulatory Commission (NRC).
Fuels' operations, which are located in the United States, include natural
gas drilling and production, coal mining and terminals, and the production
of synthetic fuels.
CCO operations, which are located in the United States, include
nonregulated electric generation operations and limited trading activities.
The increase in revenue and income from continuing operations for the six
months ended June 30, 2003 is primarily due to a tolling agreement
termination payment from Dynegy.
Rail operations include railcar repair, rail parts reconditioning and
sales, railcar leasing (primarily through Railcar Ltd.) and sales, and
scrap metal recycling. These activities include maintenance and
reconditioning of salvageable scrap components of railcars, locomotive
repair and right-of-way maintenance. Rail's primary operations are located
in the United States, with limited operation in Mexico and Canada.
Other primarily includes operations in the United States of Progress
Telecommunications Corporation and Caronet, Inc. (collectively referred to
as Progress Telecom) and other nonregulated subsidiaries that do not meet
the disclosure requirements of SFAS No. 131, "Disclosures about Segments of
an Enterprise and Related Information."
The Company's corporate operations include the operations of the holding
company, Progress Energy Service Company, LLC and intercompany elimination
transactions. The operating business segments combined with the corporate
operations represent the total continuing operations of the Company. In
prior periods, Corporate was reported as a component of the Other segment.
The discontinued operations related to NCNG are not included as an
operating segment.
The following summarizes the revenues, income from continuing operations
and assets (excluding assets of discontinued operations) for the business
segments, corporate and total Progress Energy. The 2002 information has
been restated to align with the 2003 segment structure.
11
Income
Revenues from
--------------------------------------------------- Continuing
(in thousands) Unaffiliated Intersegment Total Operations
------------ --------------- ---------------- ------------
Three Months Ended June 30, 2003
PEC Electric $ 816,240 $ - $ 816,240 $ 88,394
PEF 766,547 - 766,547 61,359
Fuels 166,918 89,861 256,779 53,807
CCO 33,283 - 33,283 2,383
Rail 213,740 - 213,740 2,192
Other 15,903 1,460 17,363 1,200
Corporate 53 (91,321) (91,268) (59,025)
------------ --------------- ---------------- ------------
Consolidated totals $ 2,012,684 $ - $ 2,012,684 $ 150,310
------------ --------------- ---------------- ------------
Three Months Ended June 30, 2002
PEC Electric $ 834,658 $ - $ 834,658 $ 131,690
PEF 765,923 - 765,923 76,753
Fuels 112,558 74,896 187,454 46,729
CCO 23,902 - 23,902 6,738
Rail 196,489 - 196,489 2,947
Other 25,325 1,454 26,779 (8,353)
Corporate - (76,350) (76,350) (134,571)
------------ --------------- ---------------- ------------
Consolidated totals $ 1,958,855 $ - $ 1,958,855 $ 121,933
------------ --------------- ---------------- ------------
Income
Revenues from
--------------------------------------------------- Continuing
(in thousands) Unaffiliated Intersegment Total Operations Assets
------------ --------------- ---------------- ------------ -------------
Six Months Ended June 30, 2003
PEC Electric $ 1,741,710 $ - $ 1,741,710 $ 223,264 $ 9,568,769
PEF 1,494,964 - 1,494,964 132,116 5,912,152
Fuels 297,769 174,068 471,837 80,385 1,215,374
CCO 70,833 - 70,833 10,909 1,712,985
Rail 391,549 - 391,549 (1,204) 503,897
Other 31,758 2,957 34,715 1,869 305,535
Corporate 106 (177,025) (176,919) (100,163) 3,918,457
------------ --------------- ---------------- ------------ -------------
Consolidated totals $ 4,028,689 $ - $ 4,028,689 $ 347,176 $ 23,137,169
------------ --------------- ---------------- ------------ -------------
Six Months Ended June 30, 2002
PEC Electric $ 1,646,139 $ - $ 1,646,139 $ 217,222 $ 8,669,993
PEF 1,452,364 - 1,452,364 134,496 4,967,998
Fuels 215,824 150,003 365,827 88,324 963,109
CCO 32,949 - 32,949 4,627 1,277,824
Rail 351,456 - 351,456 2,246 607,617
Other 47,424 2,908 50,332 (13,202) 803,837
Corporate - (152,911) (152,911) (187,719) 4,008,041
------------ --------------- ---------------- ------------ -------------
Consolidated totals $ 3,746,156 $ - $ 3,746,156 $ 245,994 $ 21,298,419
------------ --------------- ---------------- ------------ -------------
5. IMPACT OF NEW ACCOUNTING STANDARDS
SFAS No. 148, "Accounting for Stock-Based Compensation"
The Company measures compensation expense for stock options as the
difference between the market price of its common stock and the exercise
price of the option at the grant date. Accordingly, no compensation expense
has been recognized for stock option grants.
For purposes of the pro forma disclosures required by SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure - an
Amendment of FASB Statement No. 123," the estimated fair value of the
Company's stock options is amortized to expense over the options' vesting
period. The Company's information related to the pro forma impact on
earnings and earnings per share assuming stock options were expensed for
the three and six months ended June 30 is as follows:
12
(in thousands except per share data) Three Months Ended June 30, Six Months Ended June 30,
------------------------------ ----------------------------
2003 2002 2003 2002
--------------- ------------- ------------ --------------
Net income, as reported $ 152,823 $ 120,620 $ 360,979 $ 253,147
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 1,697 1,320 4,276 3,112
--------------- ------------- ------------ --------------
Pro forma net income $ 151,126 $ 119,300 $ 356,703 $ 250,035
=============== ============= ============ ==============
Basic earnings per share
As reported $ 0.65 $ 0.56 $ 1.54 $ 1.18
Pro forma $ 0.64 $ 0.55 $ 1.52 $ 1.17
Fully diluted earnings per share
As reported $ 0.64 $ 0.56 $ 1.53 $ 1.18
Pro forma $ 0.64 $ 0.55 $ 1.51 $ 1.16
In April 2003, the Financial Accounting Standards Board (FASB) approved
certain decisions on its stock-based compensation project. Some of the key
decisions reached by the FASB were that stock-based compensation should be
recognized in the income statement as an expense and that the expense
should be measured as of the grant date at fair value. A significant issue
yet to be resolved by the FASB is the determination of the appropriate fair
value measure. The FASB continues to deliberate additional issues in this
project; however, the FASB plans to issue an exposure draft in 2003 that
could become effective in 2004.
Derivative Instruments and Hedging Activities
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." The statement amends and
clarifies SFAS No. 133 on accounting for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. The new guidance incorporates decisions made as part of the
Derivatives Implementation Group (DIG) process, as well as decisions
regarding implementation issues raised in relation to the application of
the definition of a derivative. SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003. The Company is
currently evaluating what effects, if any, this statement will have on its
results of operations and financial position.
In connection with the January 2003 FASB Emerging Issues Task Force (EITF)
meeting, the FASB was requested to reconsider an interpretation of SFAS No.
133. The interpretation, which is contained in the Derivative
Implementation Group's C11 guidance, relates to the pricing of contracts
that include broad market indices (e.g., CPI). In particular, that guidance
discusses whether the pricing in a contract that contains broad market
indices could qualify as a normal purchase or sale (the normal purchase or
sale term is a defined accounting term, and may not, in all cases, indicate
whether the contract would be "normal" from an operating entity viewpoint).
In late June 2003, the FASB issued final superseding guidance (DIG Issue
C20) on this issue, which is significantly different from the tentative
superseding guidance that was issued in April 2003. The new guidance is
effective October 1, 2003 for the Company. DIG Issue C20 specifies new
pricing-related criteria for qualifying as a normal purchase or sale, and
it requires a special transition adjustment as of October 1, 2003.
PEC has determined that it has one existing "normal" contract that is
affected by this revised guidance. PEC is in the process of evaluating the
revised guidance and related contract to determine the transition
adjustment that will be necessary and to determine if the contract will be
required to be recorded at fair value subsequent to October 1, 2003.
SFAS No. 150, "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity."
SFAS 150 establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. The financial instruments within the scope of SFAS No. 150 include
mandatorily redeemable stock, obligations to repurchase the issuer's equity
shares by transferring assets, and certain obligations to issue a variable
number of shares. SFAS No. 150 is effective immediately for such financial
instruments entered into or modified after May 31, 2003, and is effective
for previously issued financial instruments within its scope on July 1,
2003.
13
Upon the Company's adoption of the FIN No. 46, "Consolidation of Variable
Interest Entities" (see below), the FPC Capital I Preferred Securities, as
discussed in Note 12, are anticipated to be deconsolidated from the
Company's financial statements effective July 1, 2003. Therefore, the
Company does not expect the adoption of SFAS No. 150 to have a material
impact on its financial position or results of operations.
FIN No. 46, "Consolidation of Variable Interest Entities"
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
This interpretation provides guidance related to identifying variable
interest entities (previously known as special purpose entities or SPEs)
and determining whether such entities should be consolidated. Certain
disclosures are required if it is reasonably possible that a company will
consolidate or disclose information about a variable interest entity when
it initially applies FIN No. 46. This interpretation must be applied
immediately to variable interest entities created or obtained after January
31, 2003. During the first six months of 2003, the Company did not
participate in the creation of, or obtain a new variable interest in, any
variable interest entity. For those variable interest entities created or
obtained on or before January 31, 2003, the Company must apply the
provisions of FIN No. 46 in the third quarter of 2003.
The Company is currently evaluating what effects, if any, this
interpretation will have on its results of operations and financial
position. During this evaluation process, several arrangements through its
Railcar Ltd. subsidiary have been identified to which this interpretation
may apply. These arrangements include an agreement with Railcar Asset
Financing Trust (RAFT), a receivables securitization trust, and seven
synthetic leases. Because the Company expects to sell the majority of
Railcar Ltd. during 2003 (See Note 3B) and divest of its interests in these
arrangements, the application of FIN No. 46 is not expected to have a
material impact with respect to these arrangements. If these interests are
not divested as currently expected, the maximum cash obligations under
these arrangements total approximately $54 million. However, management
believes the maximum loss exposure would be significantly reduced based on
the current fair values of the underlying assets related to these
arrangements.
In addition, the Company is also evaluating certain other investments to
determine if they require consolidation or disclosure upon adoption of FIN
No. 46. These include investments in approximately 50 Affordable Housing
properties eligible for Section 42 tax credits of the Internal Revenue
Service Code (Section 42). The Company divested approximately 30 of these
Affordable Housing investments in July 2003, and therefore the application
of FIN No. 46 is not expected to have a material impact with respect to
these 30 investments. It is reasonably possible that the Company will be
required to consolidate some of the remaining 20 Affordable Housing
entities that are currently accounted for under the equity method. The
maximum exposure to loss as a result of the Company's total funding
commitments for the remaining 20 Affordable Housing investments is
approximately $23.9 million. However, management believes the total loss of
its investments is unlikely given the nature of the investments and the
utilization of certain Section 42 tax credits to date.
The implementation of FIN No. 46 may require deconsolidation of certain
previously consolidated entities. Upon adoption, the company anticipates
deconsolidating the FPC Capital I Trust, which holds FPC-obligated
mandatorily redeemable preferred securities. The Company will reflect it
subordinate note obligation to the Trust as detailed in Note 12. Therefore,
the deconsolidation is not expected to have a material effect.
The Company is in the final stages of completing the adoption of FIN No.
46, but having considered the facts described herein, does not expect the
results to have a material impact on its consolidated financial position,
results of operations or liquidity.
EITF Issue No. 03-04, "Accounting for 'Cash Balance' Pension Plans"
In May 2003, the EITF reached consensus in EITF Issue No. 03-04 to
specifically address the accounting for certain cash balance pension plans.
The consensus reached in EITF Issue No. 03-04 requires certain cash balance
pension plans to be accounted for as defined benefit plans. For cash
balance plans described in the consensus, the consensus also requires the
use of the traditional unit credit method for purposes of measuring the
benefit obligation and annual cost of benefits earned as opposed to the
projected unit credit method. The Company has historically accounted for
its cash balance plans as defined benefit plans; however, the Company is
required to adopt the measurement provisions of EITF 03-04 at its cash
balance plans' next measurement date of December 31, 2003. Any differences
in the measurement of the obligations as a result of applying the consensus
will be reported as a component of actuarial gain or loss. The Company is
currently evaluating what effects EITF 03-04 will have on its results of
operations and financial position.
14
6. ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, "Accounting for Asset Retirement Obligations," provides
accounting and disclosure requirements for retirement obligations
associated with long-lived assets and was adopted by the Company effective
January 1, 2003. This statement requires that the present value of
retirement costs for which the Company has a legal obligation be recorded
as liabilities with an equivalent amount added to the asset cost and
depreciated over an appropriate period. The liability is then accreted over
time by applying an interest method of allocation to the liability.
Cumulative accretion and accumulated depreciation were recognized for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect, to the date of adoption of
this statement. For assets acquired through acquisition, the cumulative
effect was based on the acquisition date.
Upon adoption of SFAS No. 143, the Company recorded asset retirement
obligations (AROs) totaling $1,182.5 million for nuclear decommissioning of
radiated plant at PEC and PEF. The Company used an expected cash flow
approach to measure these obligations. This amount includes accruals
recorded prior to adoption totaling $775.2 million, which were previously
recorded in accumulated depreciation. The related asset retirement costs,
net of accumulated depreciation, recorded upon adoption totaled $367.5
million for regulated operations. The adoption of this statement had no
impact on the income of the regulated entities, as the effects were offset
by the establishment of a regulatory asset and a regulatory liability
pursuant to SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation." A regulatory asset was recorded related to PEC in the amount
of $271.1 million, representing the cumulative accretion and accumulated
depreciation for the time period from the date the liability would have
been recognized had the provisions of this statement been in effect to the
date of adoption, less amounts previously recorded. A regulatory liability
was recorded related to PEF in the amount of $231.3 million, representing
the amount by which previously recorded accruals exceeded the cumulative
accretion and accumulated depreciation for the time period from the date
the liability would have been recognized had the provisions of this
statement been in effect at the date of the acquisition of the assets by
Progress Energy to the date of adoption.
Funds set aside in the Company's nuclear decommissioning trust fund for the
nuclear decommissioning liability totaled $861.8 million at June 30, 2003
and $796.8 million at December 31, 2002.
The Company also recorded AROs totaling $10.3 million for synthetic fuel
operations of PVI and coal mine operations, synthetic fuel operations and
gas production of Progress Fuels Corporation. The Company used an expected
cash flow approach to measure these obligations. This amount includes
accruals recorded prior to adoption totaling $4.6 million, which was
previously recorded in other liabilities and deferred credits. The related
asset retirement costs, net of accumulated depreciation, recorded upon
adoption totaled $7.0 million for nonregulated operations. The cumulative
effect of initial adoption of this statement related to nonregulated
operations was $1.3 million of pre-tax income. The ongoing impact on
earnings related to accretion and depreciation was not significant for the
three or six months ended June 30, 2003.
Pro forma net income has not been presented for prior years because the pro
forma application of SFAS No. 143 to prior years would result in pro forma
net income not materially different from the actual amounts reported.
The Company has identified but not recognized AROs related to electric
transmission and distribution, gas distribution and telecommunications
assets as the result of easements over property not owned by the Company.
These easements are generally perpetual and only require retirement action
upon abandonment or cessation of use of the property for the specified
purpose. The ARO liability is not estimable for such easements as the
Company intends to utilize these properties indefinitely. In the event the
Company decides to abandon or cease the use of a particular easement, an
ARO liability would be recorded at that time.
The utilities have previously recognized removal costs as a component of
depreciation in accordance with regulatory treatment. As of June 30, 2003,
the portions of such costs not representing AROs under SFAS No. 143 were
$882.6 million for PEC, $940.1 million for PEF and $39.2 million for NCNG.
The amounts for PEC and PEF are included in accumulated depreciation on the
accompanying Consolidated Balance Sheets. The amount for NCNG is included
as an offset to assets of discontinued operations on the accompanying
Consolidated Balance Sheets. PEC and PEF have collected amounts for
non-radiated areas at nuclear facilities, which do not represent asset
retirement obligations. The amounts at June 30, 2003 were $63.5 million for
PEC and $61.5 million for PEF, which are included in accumulated
depreciation on the accompanying Consolidated Balance Sheets. PEF
previously collected amounts for dismantlement of its fossil generation
plants. As of June 30, 2003, this amounted to $142.2 million, which is
included in accumulated depreciation on the accompanying Consolidated
Balance Sheets. This collection was suspended pursuant to the rate case
settlement discussed in Note 13A.
15
PEC filed a request with the NCUC requesting deferral of the difference
between expense pursuant to SFAS No. 143 and expense as previously
determined by the NCUC. The NCUC granted the deferral of the January 1,
2003 cumulative adjustment. Because the clean air legislation discussed in
Note 15 under "Air Quality" contained a prohibition against cost deferrals
unless certain criteria are met, the NCUC denied the deferral of the
ongoing effects. The Company has provided additional information to the
NCUC that it believes will demonstrate that deferral of the ongoing effects
should also be allowed. 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 $13.6 million, which
represents a decrease in non-ARO cost of removal expense, partially offset
by an increase in decommissioning expense.
On April 8, 2003, the SCPSC approved a joint request by PEC, Duke Energy
and South Carolina Electric and Gas Company for an accounting order to
authorize the deferral of all cumulative and prospective effects related to
the adoption of SFAS No. 143.
On January 23, 2003, the Staff of the FPSC issued a notice of proposed rule
development to adopt provisions relating to accounting for asset retirement
obligations under SFAS No. 143. Accompanying the notice was a draft rule
presented by the Staff which adopts the provisions of SFAS No. 143 along
with the requirement to record the difference between amounts prescribed by
the FPSC and those used in the application of SFAS No. 143 as regulatory
assets or regulatory liabilities, which was accepted by all parties. The
Commission approved the draft rule in June 2003, and a final order is
expected in the third quarter of 2003.
7. GOODWILL AND OTHER INTANGIBLE ASSETS
SFAS No. 142, "Goodwill and Other Intangible Assets," requires that
goodwill be tested for impairment at least annually and more frequently
when indicators of impairment exist. SFAS No. 142 requires a two-step fair
value-based test. The first step, used to identify potential impairment,
compares the fair value of the reporting unit with its carrying amount,
including goodwill. The second step, used to measure the amount of the
impairment loss if step one indicates a potential impairment, compares the
implied fair value of the reporting unit goodwill with the carrying amount
of the goodwill. This assessment could result in periodic impairment
charges. The Company performed the annual goodwill impairment test for the
CCO segment in the first quarter of 2003, and the annual goodwill
impairment test for the PEC Electric and PEF segments in the second quarter
of 2003, both of which indicated no impairment.
During 2002, the Company acquired Westchester Gas Company (Westchester).
The purchase price was finalized during the first quarter 2003 with the
purchase price being primarily allocated to fixed assets including oil and
gas properties. No goodwill was recorded.
The carrying amounts of goodwill at June 30, 2003, by reportable segment,
are $1.9 billion, $1.7 billion and $64.1 million for PEC Electric, PEF and
CCO, respectively.
The gross carrying amount and accumulated amortization of the Company's
intangible assets as of June 30, 2003 and December 31, 2002 are as follows:
June 30, 2003 December 31, 2002
------------------------------ -----------------------------
(in thousands) Gross Carrying Accumulated Gross Carrying Accumulated
Amount Amortization Amount Amortization
-------------- --------------- -------------- --------------
Synthetic fuel intangibles $ 140,469 $(54,717) $ 140,469 $(45,189)
Power agreements 221,192 (10,073) 33,000 (5,593)
Other 53,182 (9,453) 40,968 (7,792)
-------------- --------------- -------------- --------------
Total $ 414,843 $(74,243) $ 214,437 $(58,574)
-------------- --------------- -------------- --------------
All of the Company's intangibles are subject to amortization. Synthetic
fuel intangibles represent intangibles for synthetic fuel technology. These
intangibles are being amortized on a straight-line basis until the
expiration of tax credits under Section 29 of the Internal Revenue Service
Code (the Code) in December 2007.
On May 31, 2003, PVI acquired from Williams Energy Marketing and Trading, a
subsidiary of The Williams Companies, Inc., a long-term full-requirements
power supply agreement at fixed prices with Jackson, located in Jefferson,
Georgia for $188.2 million. Assignment of Williams' responsibilities under
the contract began in June 2003 and terminates in 2015, with a first
refusal option to extend for five years. The agreement includes the use of
640 megawatts (MW) of contracted Georgia System generation comprised of
nuclear, coal, gas and pumped-storage hydro resources. The intangible
16
related to this power agreement is being amortized based on the economic
benefits of the contract. As part of the acquisition of generating assets
from LG&E Energy Corp. on February 15, 2002, power agreements of $33
million were recorded and are amortized based on the economic benefits of
the contracts through December 31, 2004, which approximates straight-line.
Other intangibles are primarily customer contracts and permits that are
amortized over their respective lives. Of the increase in other intangible
assets, $9.2 million relates to customer contracts acquired as part of the
Westchester acquisition, which was identified as an intangible in the final
purchase price allocation.
Net intangible assets are included in other assets and deferred debits in
the accompanying Consolidated Balance Sheets. Amortization expense recorded
on intangible assets for the three months ended June 30, 2003 and 2002,
respectively, was $8.5 million and $8.1 million. Amortization expense
recorded on intangible assets for the six months ended June 30, 2003 and
2002, respectively, was $15.7 million and $16.2 million. The estimated
amortization expense for intangible assets for 2003 through 2007, in
millions, is approximately $36.7, $41.3, $34.8, $35.9 and $36.1,
respectively.
8. COMPREHENSIVE INCOME
Comprehensive income for the three and six months ended June 30, 2003 was
$150.6 million and $358.2 million, respectively. Comprehensive income for
the three and six months ended June 30, 2002 was $119.6 million and $256.4
million, respectively. Items of other comprehensive income for the three
month periods consisted primarily of changes in the fair value of
derivatives used to hedge cash flows related to interest on long-term debt
and gas sales.
9. FINANCING ACTIVITIES
On February 21, 2003, PEF issued $425 million of First Mortgage Bonds,
4.80% Series, Due March 1, 2013 and $225 million of First Mortgage Bonds,
5.90% Series, Due March 1, 2033. Proceeds from this issuance were used to
repay the balance of its outstanding commercial paper, to refinance its
secured and unsecured indebtedness, including PEF's First Mortgage Bonds
6.125% Series Due March 1, 2003, and to redeem the aggregate outstanding
balance of its 8% First Mortgage Bonds Due 2022.
On March 1, 2003, $70 million of PEF First Mortgage Bonds, 6.125% Series,
matured and were retired.
On March 24, 2003, PEF redeemed $150 million of First Mortgage Bonds, 8%
Series, Due December 1, 2022 at 103.75% of the principal amount of such
bonds.
In March 2003, Progress Genco Ventures, LLC (Genco), a wholly owned
subsidiary of PVI, terminated its $50 million working capital credit
facility. A related construction facility initially provided for Genco to
draw up to $260 million. The amount outstanding under this facility is $241
million as of June 30, 2003. During the second quarter of 2003 Genco
determined it did not need to make any additional draws under this
facility. As a result of this decision, the drawn amount of $241 million
will not increase.
On April 1, 2003, PEF entered into a new $200 million 364-day credit
agreement and a new $200 million three-year credit agreement, replacing its
prior credit facilities (which had been a $90 million 364-day facility and
a $200 million five-year facility). The new PEF credit facilities contain a
defined maximum total debt to total capital ratio of 65%; as of June 30,
2003 the calculated ratio was 52.6%. The new credit facilities also contain
a requirement that the ratio of EBITDA, as defined in the facilities, to
interest expense to be at least 3 to 1; as of June 30, 2003 the calculated
ratio was 8.7 to 1.
Also on April 1, 2003, PEC reduced the size of its existing 364-day credit
facility from $285 million to $165 million. The other terms of this
facility were not changed. On July 30, 2003, PEC renewed its $165 million
364-day credit agreement. PEC's $285 million three-year credit agreement
entered into in July 2002 remains in place, for total facilities of $450
million.
On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5%
Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds;
PEC funded the redemption with commercial paper.
17
On July 14, 2003, PEC announced the redemption of $100 million of First
Mortgage Bonds, 6.875% Series Due August 15, 2023 at 102.84%. The date of
the redemption will be August 15, 2003. PEC will fund the redemption with
commercial paper.
For the three months ended June 30, 2003, the Company issued approximately
2.4 million shares representing approximately $98 million in proceeds from
its Investor Plus Stock Purchase Plan and its employee benefit plans during
the second quarter. For the six months ended June 30, 2003, the Company has
issued 4.2 million shares through these plans, resulting in approximately
$172 million of cash proceeds.
10. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS
Progress Energy and its subsidiaries are exposed to various risks related
to changes in market conditions. The Company has a risk management
committee that is chaired by the Chief Financial Officer and includes
senior executives from various business groups. The risk management
committee is responsible for administering risk management policies and
monitoring compliance with those policies by all subsidiaries.
The Company manages its market risk in accordance with its established risk
management policies, which may include entering into various derivative
transactions.
Progress Energy uses interest rate derivative instruments to adjust the
fixed and variable rate debt components of its debt portfolio and to hedge
interest rates with regard to future fixed rate debt issuances. Treasury
rate lock agreements were terminated in conjunction with the pricing of the
PEF First Mortgage Bonds in February 2003. The loss on the agreements was
deferred and is being amortized over the life of the bonds as these
agreements had been designated as cash flow hedges for accounting purposes.
Progress Energy currently has $850 million of fixed rate debt swapped to
floating rate debt by executing interest rate derivative agreements. Under
terms of these swap rate agreements, Progress Energy will receive a fixed
rate and pay a floating rate based on 3-month LIBOR. These agreements
expire in March of 2006, April 2007 and October 2008.
In March, April and June of 2003, PEC entered into treasury rate locks to
hedge its exposure to interest rates with regard to a future issuance of
debt. These agreements have a computational period of ten years and are
designated as cash flow hedges for accounting purposes. The agreements have
a total notional amount of $60 million.
Progress Fuels Corporation periodically enters into derivative instruments
to hedge its exposure to price fluctuations on natural gas sales. As of
June 30, 2003, Progress Fuels Corporation had approximately 16.6 Bcf of
cash flow hedges in place for its natural gas production. These positions
span the remainder of 2003 and extend through December 2004. These
instruments did not have a material impact on the Company's consolidated
financial position or results of operations.
Genco has a series of interest rate collars to hedge floating rate exposure
associated with the construction credit facility. These collars hedge 75%
of the drawn facility balance through March of 2007.
The notional amounts of the above contracts are not exchanged and do not
represent exposure to credit loss. In the event of default by a
counterparty, the risk in the transaction is the cost of replacing the
agreements at current market rates. Progress Energy only enters into
interest rate derivative agreements with banks with credit ratings of
single A or better.
11. EARNINGS PER COMMON SHARE
A reconciliation of the weighted-average number of common shares
outstanding for basic and dilutive earnings per share purposes is as
follows (in thousands):
Three Months Ended June 30, Six Months Ended June 30,
----------------------------- -------------------------------
2003 2002 2003 2002
------------- ------------ ------------ ---------------
-------------
Weighted-average common shares - basic 236,057 215,007 234,755 213,999
Restricted stock awards 1,004 734 967 690
Stock options 140 333 23 224
------------- ------------ ------------ ---------------
------------- ------------
Weighted-average shares - fully dilutive 237,201 216,074 235,745 214,913
------------- ------------ ------------ ---------------
18
12. FPC-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF A SUBSIDIARY
HOLDING SOLELY FPC GUARANTEED NOTES
In April 1999, FPC Capital I (the Trust), an indirect wholly owned
subsidiary of FPC, issued 12 million shares of $25 par cumulative
FPC-obligated mandatorily redeemable preferred securities (Preferred
Securities) due 2039, with an aggregate liquidation value of $300 million
and an annual distribution rate of 7.10%. Currently, all 12 million shares
of the Preferred Securities that were issued are outstanding. Concurrent
with the issuance of the Preferred Securities, the Trust issued to Florida
Progress Funding Corporation (Funding Corp.) all of the common securities
of the Trust (371,135 shares) for $9.3 million. Funding Corp. is a direct
wholly owned subsidiary of FPC.
The existence of the Trust is for the sole purpose of issuing the Preferred
Securities and the common securities and using the proceeds thereof to
purchase from Funding Corp. its 7.10% Junior Subordinated Deferrable
Interest Notes (subordinated notes) due 2039, for a principal amount of
$309.3 million. The subordinated notes and the Notes Guarantee (as
discussed below) are the sole assets of the Trust. Funding Corp.'s proceeds
from the sale of the subordinated notes were advanced to Progress Capital
and used for general corporate purposes including the repayment of a
portion of certain outstanding short-term bank loans and commercial paper.
FPC has fully and unconditionally guaranteed the obligations of Funding
Corp. under the subordinated notes (Notes Guarantee). In addition, FPC has
guaranteed the payment of all distributions required to be made by the
Trust, but only to the extent that the Trust has funds available for such
distributions (Preferred Securities Guarantee). The Preferred Securities
Guarantee, considered together with the Notes Guarantee, constitutes a full
and unconditional guarantee by FPC of the Trust's obligations under the
Preferred Securities.
The subordinated notes may be redeemed at the option of Funding Corp.
beginning in 2004 at par value plus accrued interest through the redemption
date. The proceeds of any redemption of the subordinated notes will be used
by the Trust to redeem proportional amounts of the Preferred Securities and
common securities in accordance with their terms. Upon liquidation or
dissolution of Funding Corp., holders of the Preferred Securities would be
entitled to the liquidation preference of $25 per share plus all accrued
and unpaid dividends thereon to the date of payment.
These Preferred Securities are classified as long-term debt on the
Company's Consolidated Balance Sheets. Upon adoption of FIN No. 46, the
Company anticipates deconsolidating the FPC Capital I Trust which is not
expected to have a material effect on the consolidated financial position,
results of operations or liquidity (See Note 5).
13. REGULATORY MATTERS
A. Retail Rate Matters
In conjunction with the acquisition of NCNG, PEC agreed to cap base retail
electric rates in North Carolina and South Carolina through December 2004.
The cap on base retail electric rates in South Carolina was extended to
December 2005 in conjunction with regulatory approval to form a holding
company. NCNG also agreed to cap its North Carolina margin rates for gas
sales and transportation services, with limited exceptions, through
November 1, 2003. On May 16, 2002, NCNG filed a request to increase its
margin rates and rebalance its rates with the NCUC, requesting an annual
rate increase of $4.1 million to recover costs associated with specific
system improvements. In September 2002, the NCUC issued its order approving
the $4.1 million rate increase. The rate increase was effective October 1,
2002. NCNG filed a general rate case with the NCUC on March 31, 2003. NCNG
anticipates that new rates, if approved, will go into effect in November
2003, after the terms of the joint stipulation agreement expire (See Note
3A).
On March 27, 2002, the parties in PEF's rate case entered into a
Stipulation and Settlement Agreement (the Agreement) related to retail rate
matters. The Agreement was approved by the FPSC on April 23, 2002. The
Agreement provides that PEF will operate under a Revenue Sharing Incentive
Plan (the Plan) through 2005 and thereafter until terminated by the FPSC.
The Plan establishes annual revenue caps and sharing thresholds. The Plan
provides that all retail base revenues between an established threshold and
cap will be shared - a 2/3 share to be refunded to PEF's retail customers,
and a 1/3 share to be received by PEF's shareholders. All retail base rate
revenues above the retail base rate revenue caps established for each year
will be refunded 100% to retail customers on an annual basis. For 2002, the
refund to customers was limited to 67.1% of the retail base rate revenues
that exceeded the 2002 cap. The retail base rate revenue sharing threshold
amounts for 2003 are $1.333 billion and will increase $37 million each year
thereafter. The retail base revenue cap for 2003 is $1.393 billion and will
increase $37 million each year thereafter. As of December 31, 2002, $4.7
million was accrued and was refunded to customers in March 2003. On
February 24, 2003, the parties to the Agreement filed a motion seeking an
order from the FPSC to enforce the Agreement. In this motion, the parties
19
disputed PEF's calculation of retail revenue subject to refund and
contended that the refund should be approximately $23 million. On July 9,
2003, the FPSC ruled that PEF must provide an additional $18.4 million to
its retail customers related to the 2002 revenue sharing calculation. PEF
recorded this refund in the second quarter of 2003 as a charge against
electric operating revenue and will refund this amount by no later than
October 31, 2003. In the second quarter of 2003, PEF also recorded an
additional accrual of $9.5 million related to estimated 2003 revenue
sharing.
On March 4, 2003, the FPSC approved PEF's petition to increase its fuel
factors due to continuing increases in oil and natural gas commodity
prices. The crisis in the Middle East along with the recent Venezuelan oil
workers' strike have put upward pressure on commodity prices that was not
anticipated by PEF when fuel factors for 2003 were approved by the FPSC in
November 2002. New rates became effective on March 28, 2003.
B. Regional Transmission Organizations
In early 2000, the FERC issued Order 2000 regarding regional transmission
organizations (RTOs). This Order set minimum characteristics and functions
that RTOs must meet, including independent transmission service. As a
result of Order 2000, PEF, along with Florida Power & Light Company and
Tampa Electric Company, filed with the FERC, in October 2000, an
application for approval of a GridFlorida RTO. In March 2001, the FERC
issued an order provisionally approving GridFlorida. PEC, along with Duke
Energy Corporation and South Carolina Electric & Gas Company, filed with
the FERC, for approval of a GridSouth RTO. In July 2001, the FERC issued an
order provisionally approving GridSouth. However, in July 2001, FERC issued
orders recommending that companies in the Southeast engage in a mediation
to develop a plan for a single RTO for the Southeast. PEF and PEC
participated in the mediation. The FERC has not issued an order
specifically on this mediation. In July 2002, the FERC issued its Notice of
Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue
Discrimination through Open Access Transmission Service and Standard
Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set
forth in the SMD NOPR would materially alter the manner in which
transmission and generation services are provided and paid for. PEF and
PEC, as subsidiaries of Progress Energy, filed comments on November 15,
2002 and supplemental comments on January 10, 2003. On April 28, 2003, the
FERC released a White Paper on the Wholesale Market Platform. The White
Paper provides an overview of what the FERC currently intends to include in
a final rule in the SMD NOPR docket. The White Paper retains the
fundamental and most protested aspects of SMD NOPR, including mandatory
RTOs and the FERC's assertion of jurisdiction over certain aspects of
retail service. PEF and PEC, as subsidiaries of Progress Energy, plan to
file comments on the White Paper. The FERC has also indicated that it
expects to issue a final rule after Congress votes this fall on the
proposed House and Senate Energy Bills. The Company cannot predict the
outcome of these matters or the effect that they may have on the
GridFlorida and GridSouth proceedings currently ongoing before the FERC.
The Company has $31.2 million and an immaterial amount invested in
GridSouth and GridFlorida, respectively, at June 30, 2003. It is unknown
what impact the future proceedings will have on the Company's earnings,
revenues or prices.
In October 2002, the FPSC abated its proceedings regarding its review of
the proposed GridFlorida RTO. The FPSC action to abate the proceedings came
in response to the Florida Office at Public Counsel's appeal before the
State Supreme Court requesting review of the FPSC's order approving the
transfer of operational control of electric transmission assets to an RTO
under the jurisdiction of the FERC. On June 2, 2003 the Florida Supreme
Court dismissed the appeal without prejudice on the ground that certain
portions of the Commission's order constituted non-final action. The
dismissal is without prejudice to any party to challenge the Commission's
order after all portions are final. A technical conference for the state of
Florida to be conducted by the FERC is scheduled for September 15, 2003. It
is unknown when the FERC or the FPSC will take final action with regard to
the status of GridFlorida or what the impact of further proceedings will
have on the Company's earnings, revenues or prices.
14. OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income, gain on the sale of
investments, impairment of investments and other income and expense items
as discussed below. The components of other, net as shown on the
Consolidated Statements of Income are as follows:
20
Three Months Ended June 30, Six Months Ended June 30,
------------------------------ -------------------------------
(in thousands) 2003 2002 2003 2002
-------------- ----------- ------------ ---------------
Other income
Net financial trading gain (loss) $ 67 $ 792 $ (2,632) $ (1,429)
Net energy brokered for resale (1,369) 124 157 (141)
Nonregulated energy and delivery services income 5,652 5,862 11,242 12,459
Contingent value obligation mark-to-market (1,677) 1,479 - 12,821
Investment gains - 2,960 - 2,960
AFUDC equity 4,035 1,833 5,914 4,077
Other 5,299 7,905 10,937 13,049
-------------- ----------- ------------ ---------------
Total other income $ 12,007 $ 20,955 $ 25,618 $ 43,796
-------------- ----------- ------------ ---------------
Other expense
Nonregulated energy and delivery services expenses 5,479 6,248 9,696 9,383
Donations 3,377 2,736 6,721 7,007
Investment losses 8,644 - 8,644 -
Other 3,939 14,311 12,440 23,688
-------------- ----------- ------------ ---------------
Total other expense $ 21,439 $ 23,295 $ 37,501 $ 40,078
-------------- ----------- ------------ ---------------
Other, net $ (9,432) $ (2,340) $ (11,883) $ 3,718
============== =========== ============ ===============
Net financial trading gains and losses represent non-asset-backed trades of
electricity and gas. Net energy brokered for resale represents electricity
purchased for sale to a third party. Nonregulated energy and delivery
services include power protection services and mass market programs (surge
protection, appliance services and area light sales) and delivery,
transmission and substation work for other utilities. Investment losses
represent losses on limited partnership investment funds.
15. COMMITMENTS AND CONTINGENCIES
Contingencies and significant changes to the commitments discussed in Note
24 of the financial statements included in the Company's 2002 Annual Report
on Form 10-K are described below.
A. Guarantees
As a part of normal business, Progress Energy and certain subsidiaries
enter into various agreements providing financial or performance
assessments to third parties. Such agreements include guarantees, standby
letters of credit and surety bonds. These agreements are entered into
primarily to support or enhance the creditworthiness otherwise attributed
to a subsidiary on a stand-alone basis, thereby facilitating the extension
of sufficient credit to accomplish the subsidiaries' intended commercial
purposes.
Guarantees as of June 30, 2003, are summarized in the table below and
discussed more fully in the subsequent paragraphs.
(in millions)
Guarantees of performance issued by or on behalf of affiliates
Guarantees supporting nonregulated portfolio expansion
and energy marketing and trading activities issued by Progress Energy $ 290.5
Guarantees supporting energy marketing and trading activities issued by
subsidiaries of Progress Energy 12.0
Guarantees supporting nuclear decommissioning 276.0
Guarantee supporting power supply agreements 285.0
Standby letters of credit 49.5
Surety bonds 104.3
Other guarantees 44.1
Guarantees issued on behalf of third parties
Other guarantees 16.4
-------------------
Total $ 1,077.8
===================
21
Guarantees Supporting Nonregulated Portfolio Expansion and Energy Marketing
and Trading Activities
Progress Energy has issued approximately $290.5 million of guarantees on
behalf of PVI and its subsidiaries for obligations under tolling
agreements, transmission agreements, gas agreements, construction
agreements and trading operations. Approximately $26.9 million of these
guarantees were issued during the year to support energy and trading
activities. The majority of the marketing and trading contracts supported
by the guarantees contain language regarding downgrade events, ratings
triggers, monthly netting of exposure and/or payments and offset provisions
in the event of a default. Based upon the amount of trading positions
outstanding at June 30, 2003, if the Company's ratings were to decline
below investment grade, the Company would have to deposit cash or provide
letters of credit or other cash collateral of approximately $40.0 million
for the benefit of the Company's counterparties.
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 parent
company guarantees.
Guarantee Supporting Power Supply Agreements
On March 20, 2003, PVI entered into a definitive agreement with Williams
Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc.,
to acquire a long-term full-requirements power supply agreement at fixed
prices with Jackson. The power supply agreement included a performance
guarantee by Progress Energy. The transaction closed during the second
quarter of 2003. The Company issued a payment and performance guarantee to
Jackson related to the power supply agreement of $285.0 million. In the
event that Progress Energy's credit ratings fall below investment grade,
Progress Energy will be required to provide additional security for this
guarantee in form and amount (not to exceed $285 million) acceptable to
Jackson.
Standby Letters of Credit
The Company has issued standby letters of credit to financial institutions
for the benefit of third parties that have extended credit to the Company
and certain subsidiaries. These letters of credit have been issued
primarily for the purpose of supporting payments of trade payables,
securing performance under contracts and lease obligations and
self-insurance for workers' compensation. If a subsidiary does not pay
amounts when due under a covered contract, the counterparty may present its
claim for payment to the financial institution, which will in turn request
payment from the Company. Any amounts owed by the Company's subsidiaries
are reflected in the accompanying Consolidated Balance Sheets.
Surety Bonds
At June 30, 2003, the Company had $104.3 million in surety bonds purchased
primarily for purposes such as providing workers' compensation coverage,
obtaining licenses, permits and rights-of-way and project performance. To
the extent liabilities are incurred as a result of the activities covered
by the surety bonds, such liabilities are included in the accompanying
Consolidated Balance Sheets.
Other Guarantees
The Company has other guarantees outstanding related primarily to prompt
performance payments, lease obligations and other payments subject to
contingencies.
As of June 30, 2003, management does not believe conditions are likely for
performance under the agreements discussed in this Note 15.
B. Insurance
Both PEC and PEF are insured against public liability for a nuclear
incident. Under the current provisions of the Price Anderson Act, which
limits liability for accidents at nuclear power plants, each company, as an
owner of nuclear units, can be assessed a portion of any third-party
liability claims arising from an accident at any commercial nuclear power
plant in the United States. In the event that public liability claims from
an insured nuclear incident exceed $300 million (currently available
through commercial insurers), each company would be subject to pro rata
assessments for each reactor owned per occurrence. Effective August 20,
2003, the retroactive premium assessments will increase to $100.6 million
per reactor from the current amount of $88.1 million. The total limit
available to cover nuclear liability losses will increase as well from $9.6
billion to $10.6 billion. The annual retroactive premium limit of $10
million per reactor owned will not change.
22
C. Claims and uncertainties
a) The Company is subject to federal, state and local regulations
addressing hazardous and solid waste management, air and water quality and
other environmental matters.
Hazardous and Solid Waste Management
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The principal regulatory agency that is responsible for a
specific former manufactured gas plant (MGP) site depends largely upon the
state in which the site is located. There are several MGP sites to which
both electric utilities and the gas utility have some connection. In this
regard, both electric utilities and the gas utility and other potentially
responsible parties are participating in investigating and, if necessary,
remediating former MGP sites with several regulatory agencies, including,
but not limited to, the U.S. Environmental Protection Agency (EPA), the
Florida Department of Environmental Protection (FDEP) and the North
Carolina Department of Environment and Natural Resources, Division of Waste
Management (DWM). In addition, the Company and its subsidiaries are
periodically notified by regulators such as the EPA and various state
agencies of their involvement or potential involvement in sites, other than
MGP sites, that may require investigation and/or remediation. A discussion
of these sites by legal entity follows.
PEC There are 12 former MGP sites and 14 other sites or groups of sites
associated with PEC that have required or are anticipated to require
investigation and/or remediation costs. PEC received insurance proceeds to
address costs associated with environmental liabilities related to its
involvement with some MGP sites. All eligible expenses related to these are
charged against a specific fund containing these proceeds. As of June 30,
2003, approximately $5.2 million remains in this centralized fund with a
related accrual of $5.2 million recorded for the associated expenses of
environmental issues. As PEC's share of costs for investigating and
remediating these sites becomes known, the fund is assessed to determine if
additional accruals will be required. PEC does not believe that it can
provide an estimate of the reasonably possible total remediation costs
beyond what remains in the environmental insurance recovery fund. This is
due to the fact that the sites are at different stages: investigation has
not begun at 15 sites, investigation has begun but remediation cannot be
estimated at seven sites and four sites have begun remediation. PEC
measures its liability for these sites based on available evidence
including its experience in investigating and remediating environmentally
impaired sites. The process often involves assessing and developing
cost-sharing arrangements with other potentially responsible parties. Once
the environmental insurance recovery fund is depleted, PEC will accrue
costs for the sites to the extent its liability is probable and the costs
can be reasonably estimated. Presently, PEC cannot determine the total
costs that may be incurred in connection with the remediation of all sites.
PEF There are two former MGP sites and 11 other active sites associated
with PEF that have required or are anticipated to require investigation
and/or remediation costs. As of June 30, 2003, PEF has accrued
approximately $9.4 million, for probable and reasonably estimable costs at
these sites. PEF does not believe that it can provide an estimate of the
reasonably possible total remediation costs beyond what is currently
accrued. In 2002, PEF filed a petition for annual recovery of approximately
$4.0 million in environmental costs through the Environmental Cost Recovery
Clause with the FPSC. PEF was successful with this filing and will recover
costs through rates for investigation and remediation associated with
transmission and distribution substations and transformers. As more
activity occurs at these sites, PEF will assess the need to adjust the
accruals. These accruals have been recorded on an undiscounted basis. PEF
measures its liability for these sites based on available evidence
including its experience in investigating and remediating environmentally
impaired sites. This process often includes assessing and developing
cost-sharing arrangements with other potentially responsible parties.
Presently, PEF cannot determine the total costs that may be incurred in
connection with the remediation of all sites.
NCNG There are five former MGP sites associated with NCNG that have or are
anticipated to have investigation or remediation costs associated with
them. As of June 30, 2003, NCNG has accrued approximately $2.3 million for
probable and reasonably estimable remediation costs at these sites. These
accruals have been recorded on an undiscounted basis. NCNG measures its
liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
This process often involves assessing and developing cost-sharing
arrangements with other potentially responsible parties. NCNG does not
believe it can provide an estimate of the reasonably possible total
remediation costs beyond the accrual because two of the five sites
associated with NCNG have not begun investigation activities. Therefore,
NCNG cannot currently determine the total costs that may be incurred in
23
connection with the investigation and/or remediation of all sites. Based
upon current information, the Company does not expect the future costs at
the NCNG sites to be material to the Company's financial condition or
results of operations. In October 2002, the Company announced plans to sell
NCNG to Piedmont Natural Gas Company, Inc. The Company will retain the
environmental liability associated with the five former MGP sites.
Florida Progress Corporation 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 maximum contractual liability to AEP Resources, Inc.,
associated with Inland Marine Transportation is $60 million. The balance in
this accrual is $9.9 million at June 30, 2003. This accrual has been
determined on an undiscounted basis. FPC measures its liability for this
site based on estimable and probable remediation scenarios. The Company
believes that it is reasonably probable that additional costs, which cannot
be currently estimated, may be incurred related to the environmental
indemnification provision beyond the amount accrued. The Company cannot
predict the outcome of this matter.
Certain historical waste sites exist that are being addressed voluntarily
by Fuels. The Company cannot determine the total costs that may be incurred
in connection with these sites. The Company cannot predict the outcome of
this matter.
Rail Services is voluntarily addressing certain historical waste sites. The
Company cannot determine the total costs that may be incurred in connection
with these sites. The Company cannot predict the outcome of this matter.
PEC, PEF, Fuels and NCNG have filed claims with the Company's general
liability insurance carriers to recover costs arising out of actual or
potential environmental liabilities. Some claims have been settled and
others are still pending. The Company cannot predict the outcome of this
matter.
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.
Air Quality
There has been and may be further proposed federal legislation requiring
reductions in air emissions for nitrogen oxides, sulfur dioxide, carbon
dioxide and mercury. Some of these proposals establish nationwide caps and
emission rates over an extended period of time. This national
multi-pollutant approach to air pollution control could involve significant
capital costs which could be material to the Company's consolidated
financial position or results of operations. Some companies may seek
recovery of the related cost through rate adjustments or similar
mechanisms. Control equipment that will be installed on North Carolina
fossil generating facilities as part of the North Carolina legislation
discussed below may address some of the issues outlined above. However, the
Company cannot predict the outcome of this matter.
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
Both PEC and PEF were asked to provide information to the EPA as part of
this initiative and cooperated in providing the requested information.
During the first quarter of 2003, PEC responded to a supplemental
information request from the EPA. PEF has received a similar supplemental
information request, and responded to it in the second quarter. The EPA
initiated civil enforcement actions against other unaffiliated utilities as
part of this initiative. Some of these actions resulted in settlement
agreements calling for expenditures, ranging from $1.0 billion to $1.4
billion. A utility that was not subject to a civil enforcement action
settled its New Source Review issues with the EPA for $300 million. These
settlement agreements have generally called for expenditures to be made
over extended time periods, and some of the companies may seek recovery of
the related cost through rate adjustments or similar mechanisms. The
Company cannot predict the outcome of the EPA's initiative or its impact,
if any, on the Company.
In 1998, the EPA published a final rule addressing the regional transport
of ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule
requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, but not Florida, to further reduce nitrogen oxide emissions in
order to attain pre-set state NOx emission levels by May 31, 2004. PEC is
currently installing controls necessary to comply with the rule. Capital
expenditures needed to meet these measures in North and South Carolina
could reach approximately $370 million, which has not been adjusted for
inflation. Increased operation and maintenance costs relating to the NOx
SIP Call are not expected to be material to the Company's results of
operations. Further controls are anticipated as electricity demand
increases. The Company cannot predict the outcome of this matter.
24
In July 1997, the EPA issued final regulations establishing a new
eight-hour ozone standard. In October 1999, the District of Columbia
Circuit Court of Appeals ruled against the EPA with regard to the federal
eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the
District of Columbia Circuit Court of Appeals' decision. Designation of
areas that do not attain the standard is proceeding, and further litigation
and rulemaking on this and other aspects of the standard are anticipated.
North Carolina adopted the federal eight-hour ozone standard and is
proceeding with the implementation process. North Carolina has promulgated
final regulations, which will require PEC to install nitrogen oxide
controls under the state's eight-hour standard. The costs of those controls
are included in the $370 million cost estimate set forth in the preceding
paragraph. However, further technical analysis and rulemaking may result in
a requirement for additional controls at some units. The Company cannot
predict the outcome of this matter.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule, as originally promulgated, required certain
sources to make reductions in nitrogen oxide emissions by May 1, 2003. The
final rule also includes a set of regulations that affect nitrogen oxide
emissions from sources included in the petitions. The North Carolina
coal-fired electric generating plants are included in these petitions.
Acceptable state plans under the NOx SIP Call can be approved in lieu of
the final rules the EPA approved as part of the Section 126 petitions. PEC,
other utilities, trade organizations and other states participated in
litigation challenging the EPA's action. On May 15, 2001, the District of
Columbia Circuit Court of Appeals ruled in favor of the EPA, which will
require North Carolina to make reductions in nitrogen oxide emissions by
May 1, 2003. However, the Court, in its May 15th decision, rejected the
EPA's methodology for estimating the future growth factors the EPA used in
calculating the emissions limits for utilities. In August 2001, the Court
granted a request by PEC and other utilities to delay the implementation of
the Section 126 rule for electric generating units pending resolution by
the EPA of the growth factor issue. The Court's order tolls the three-year
compliance period (originally set to end on May 1, 2003) for electric
generating units as of May 15, 2001. On April 30, 2002, the EPA published a
final rule harmonizing the dates for the Section 126 rule and the NOx SIP
Call. In addition, the EPA determined in this rule that the future growth
factor estimation methodology was appropriate. The new compliance date for
all affected sources is now May 31, 2004, rather than May 1, 2003. The EPA
has approved North Carolina's NOx SIP Call rule and has formally proposed
to rescind the Section 126 rule. This rulemaking is expected to become
final during the summer of 2003. The Company expects a favorable outcome of
this matter.
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and
sulfur dioxide from coal-fired power plants. Progress Energy expects its
capital costs to meet these emission targets will be approximately $813
million by 2013. PEC currently has approximately 5,100 MW of coal-fired
generation capacity in North Carolina that is affected by this legislation.
The legislation requires the emissions reductions to be completed in phases
by 2013, and applies to each utility's total system rather than setting
requirements for individual power plants. The legislation also freezes the
utilities' base rates for five years unless there are extraordinary events
beyond the control of the utilities or unless the utilities persistently
earn a return substantially in excess of the rate of return established and
found reasonable by the NCUC in the utilities' last general rate case.
Further, the legislation allows the utilities to recover from their retail
customers the projected capital costs during the first seven years of the
ten-year compliance period beginning on January 1, 2003. The utilities must
recover at least 70% of their projected capital costs during the five-year
rate freeze period. Pursuant to the new law, PEC entered into an agreement
with the state of North Carolina to transfer to the state any future
emissions allowances acquired as a result of compliance with the new law.
The new law also requires the state to undertake a study of mercury and
carbon dioxide emissions in North Carolina. Progress Energy cannot predict
the future regulatory interpretation, implementation or impact of this new
law. PEC recorded $33.5 million in the second quarter of 2003 and
approximately $54 million of clean air amortization to date in 2003. Clean
air expenditures to date are $8.4 million.
Other Environmental Matters
The Kyoto Protocol was adopted in 1997 by the United Nations to address
global climate change by reducing emissions of carbon dioxide and other
greenhouse gases. The United States has not adopted the Kyoto Protocol;
however, a number of carbon dioxide emissions control proposals have been
advanced in Congress and by the Bush administration. The Bush
administration favors voluntary programs. Reductions in carbon dioxide
emissions to the levels specified by the Kyoto Protocol and some
legislative proposals could be materially adverse to Company financials and
operations if associated costs cannot be recovered from customers. The
Company favors the voluntary program approach recommended by the
administration, and is evaluating options for the reduction, avoidance and
sequestration of greenhouse gases. However, the Company cannot predict the
outcome of this matter.
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. Pursuant to a Court Order, the EPA is developing a Maximum
Available Control Technology (MACT) standard, which is expected to become
final in December 2004, with compliance in 2008. Achieving compliance with
the MACT standard could be materially adverse to the Company's financial
condition and results of operations. However, the Company cannot predict
the outcome of this matter.
b) As required under the Nuclear Waste Policy Act of 1982, PEC and PEF each
entered into a contract with the U.S. Department of Energy (DOE) under
which the DOE agreed to begin taking spent nuclear fuel by no later than
January 31, 1998. All similarly situated utilities were required to sign
the same standard contract.
In April 1995, the DOE issued a final interpretation that it did not have
an unconditional obligation to take spent nuclear fuel by January 31, 1998.
In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's
final interpretation and ruled that the DOE had an unconditional obligation
to begin taking spent nuclear fuel. The Court did not specify a remedy
because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan
Power v. DOE, a group of utilities petitioned the Court of Appeals in
Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to
begin taking spent nuclear fuel by January 31, 1998. The DOE took the
position that their delay was unavoidable, and the DOE was excused from
performance under the terms and conditions of the contract. The Court of
Appeals found that the delay was not unavoidable, but did not order the DOE
to begin taking spent nuclear fuel, stating that the utilities had a
potentially adequate remedy by filing a claim for damages under the
contract.
After the DOE failed to begin taking spent nuclear fuel by January 31,
1998, a group of utilities filed a motion with the Court of Appeals to
enforce the mandate in NSP v. DOE. Specifically, this group of utilities
asked the Court to permit the utilities to escrow their waste fee payments,
to order the DOE not to use the waste fund to pay damages to the utilities,
and to order the DOE to establish a schedule for disposal of spent nuclear
fuel. The Court denied this motion based primarily on the grounds that a
review of the matter was premature, and that some of the requested remedies
fell outside of the mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal
Circuit) has ruled that utilities may sue the DOE for damages in the
Federal Court of Claims instead of having to file an administrative claim
with the DOE. PEC and PEF are in the process of evaluating whether they
should each file a similar action for damages.
On July 9, 2002, Congress passed an override resolution to Nevada's veto of
DOE's proposal to locate a permanent underground nuclear waste storage
facility at Yucca Mountain, Nevada. DOE plans to submit a license
application for the Yucca Mountain facility by the end of 2004. PEC and PEF
cannot predict the outcome of this matter.
With certain modifications, and additional approval by the NRC, PEC's spent
nuclear fuel storage facilities will be sufficient to provide storage space
for spent fuel generated on PEC's system through the expiration of the
current operating licenses for all of PEC's nuclear generating units.
Subsequent or prior to the expiration of these licenses, or any renewal of
these licenses, dry storage or acquisition of new shipping casks may be
necessary. PEC obtained approval from the NRC to use additional storage
space at the Harris Plant in December 2000. PEF currently is storing spent
nuclear fuel onsite in spent fuel pools. If PEF does not seek renewal of
the Crystal River Nuclear Plant (CR3) operating license, CR3 will have
sufficient storage capacity in place for fuel consumed through the end of
the expiration of the license in 2016. If PEF extends the CR3 operating
license, dry storage may be necessary.
c) Progress Energy, through its subsidiaries, produces synthetic fuel from
coal fines. The production and sale of the synthetic fuel from these
facilities qualifies for tax credits under Section 29 of the Code (Section
29) if certain requirements are satisfied, including a requirement that the
synthetic fuel differs significantly in chemical composition from the coal
used to produce such synthetic fuel. Any synthetic fuel tax credit amounts
not utilized are carried forward indefinitely. All of Progress Energy's
synthetic fuel facilities have received private letter rulings (PLRs) from
the Internal Revenue Service (IRS) with respect to their synthetic fuel
operations. These tax credits are subject to review by the IRS, and if
Progress Energy fails to prevail through the administrative or legal
process, there could be a significant tax liability owed for previously
taken Section 29 credits, with a significant impact on earnings and cash
flows. Additionally, the ability to use tax credits currently being carried
forward could be denied. Total Section 29 credits generated to date
(including FPC prior to its acquisition by the Company) are approximately
$1.028 billion, of which $445.6 million have been used and $582.4 million
are being carried forward as of June 30, 2003. The current Section 29 tax
credit program expires in 2007.
26
One synthetic fuel entity, Colona Synfuel Limited Partnership, L.L.L.P.
(Colona), from which the Company (and FPC prior to its acquisition by the
Company) has been allocated approximately $273.1 million in tax credits to
date, is being audited by the IRS. The audit of Colona was expected. The
Company is audited regularly in the normal course of business, as are most
similarly situated companies.
In September 2002, all of the Company's majority-owned synthetic fuel
entities, including Colona, were accepted into the IRS Prefiling Agreement
(PFA) program. The PFA program allows taxpayers to voluntarily accelerate
the IRS exam process in order to seek resolution of specific issues. Either
the Company or the IRS can withdraw from the program at any time, and
issues not resolved through the program may proceed to the next level of
the IRS exam process.
In late June 2003, the Company was informed that IRS field auditors have
raised questions regarding the chemical change associated with coal-based
synthetic fuel manufactured at its Colona facility and the testing process
by which the chemical change is verified. (The questions arose in
connection with the Company's participation in the PFA program.) The
chemical change and the associated testing process were described as part
of the PLR request for Colona. Based on that application, the IRS ruled in
Colona's PLR that the synthetic fuel produced at Colona undergoes a
significant chemical change and thus qualifies for tax credits under
Section 29 of the Internal Revenue Code. While the IRS has announced that
they may revoke PLRs if test procedures and results do not demonstrate that
a significant chemical change has occurred, based on the information
received to date, the Company does not believe the issues warrant reversal
by the IRS National Office of its prior position in the Colona PLR.
The information provided by the IRS field auditors addresses only Progress
Energy's Colona facility. The Company, however, applies essentially the
same chemical process and uses the same independent laboratories to confirm
chemical change in the synthetic fuel manufactured at each of its four
other facilities. The independent laboratories used by the Company to
determine significant chemical change are the leading experts in their
field and are used by many other industry participants. The Company
believes that the laboratories' work and the chemical change process are
consistent with the bases upon which the PLRs were issued.
The Company is working to resolve this matter as quickly as possible. At
this time, the Company cannot predict how long the IRS process will take;
however, the Company intends to continue working cooperatively with the
IRS. The Company firmly believes that it is operating the Colona facility
and its other plants in compliance with its PLRs and Section 29 of the
Internal Revenue Code. Accordingly, the Company has no current plans to
alter its synthetic fuel production schedules as a result of these matters.
In addition, the Company has retained an advisor to assist in selling an
interest in one or more synthetic fuel entities. The Company is pursuing
the sale of a portion of its synthetic fuel production capacity that is
underutilized due to limits on the amount of credits that can be generated
and utilized by the Company. The Company would expect to retain an
ownership interest and to operate any sold facility for a management fee.
However, the IRS has suspended issuance of PLRs relating to synthetic fuel
production (typically a closing condition to the sale of an interest in a
synthetic fuel entity). Unless that suspension on new PLRs is lifted, it
will be difficult to consummate the successful sale of interests in the
Company's synthetic fuel facilities. The Company cannot predict when or if
the IRS will recommence issuing such PLRs. The final outcome and timing of
the Company's efforts to sell interests in synthetic fuel facilities is
uncertain and while the Company cannot predict the outcome of this matter,
the outcome is not expected to have a material effect on the consolidated
financial position, cash flows or results of operations.
d) In November of 2001, Strategic Resource Solutions Corp. (SRS) filed a
claim against the San Francisco Unified School District ("the District")
and other defendants claiming that SRS is entitled to approximately $10
million in unpaid contract payments and delay and impact damages related to
the District's $30 million contract with SRS. On March 4, 2002, the
District filed a counterclaim, seeking compensatory damages and liquidated
damages in excess of $120 million, for various claims, including breach of
contract and demand on a performance bond. SRS has asserted defenses to the
District's claims.
On March 13, 2003, the City Attorney's office announced the filing of new
claims by the City Attorney and the District in the form of a
cross-complaint against SRS, Progress Energy, Inc., Progress Energy
Solutions, Inc., and certain individuals, alleging fraud, false claims,
violations of California statutes, and seeking compensatory damages,
punitive damages, liquidated damages, treble damages, penalties, attorneys'
fees and injunctive relief. The City Attorney's announcement states that
the City and the District seek "more than $300 million in damages and
penalties."
27
The Company has reviewed the District's earlier pleadings against SRS and
believes that those claims are not meritorious. SRS filed its answer to the
new pleadings on April 14, 2003. The Company has reviewed the new pleadings
and the Company believes that the new claims are not meritorious. The
Company has filed responsive pleadings denying the allegations, and the
discovery process is underway. SRS, the Company and Progress Energy
Solutions, Inc. will vigorously defend and litigate all of these claims.
The Company cannot predict the outcome of this matter, but the Company
believes that it and its subsidiaries have good defenses to all claims
asserted by both the District and the City.
e) The Company and its subsidiaries are involved in various litigation
matters in the ordinary course of business, some of which involve claims
for substantial amounts. Where appropriate, accruals have been made in
accordance with SFAS No. 5, "Accounting for Contingencies," to provide for
such matters. The Company believes the final disposition of pending
litigation would not have a material adverse effect on the Company's
consolidated results of operations or financial position.
28
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED INTERIM FINANCIAL STATEMENTS
June 30, 2003
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Six Months Ended
(Unaudited) June 30, June 30,
- ----------------------------------------------------------------------------------------------------------------
(In thousands) 2003 2002 2003 2002
- ----------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 816,240 $ 834,658 $ 1,741,710 $ 1,646,139
Diversified business 2,423 3,434 5,819 6,823
- ----------------------------------------------------------------------------------------------------------------
Total Operating Revenues 818,663 838,092 1,747,529 1,652,962
- ----------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 177,020 170,977 402,562 342,703
Purchased power 68,977 90,918 142,157 164,228
Operation and maintenance 210,295 193,887 400,170 387,324
Depreciation and amortization 141,848 133,459 280,644 274,844
Taxes other than on income 35,101 36,075 79,277 74,843
Diversified business 1,595 2,754 2,535 5,815
- ----------------------------------------------------------------------------------------------------------------
Total Operating Expenses 634,836 628,070 1,307,345 1,249,757
- ----------------------------------------------------------------------------------------------------------------
Operating Income 183,827 210,022 440,184 403,205
- ----------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 2,075 3,202 3,441 4,868
Other, net (8,380) 4,652 (10,931) 1,680
- ----------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) (6,305) 7,854 (7,490) 6,548
- ----------------------------------------------------------------------------------------------------------------
Interest Charges
Interest charges 48,412 56,255 97,715 117,899
Allowance for borrowed funds used during (658) (2,779) (1,583) (5,873)
construction
- ----------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 47,754 53,476 96,132 112,026
- ----------------------------------------------------------------------------------------------------------------
Income before Income Taxes 129,768 164,400 336,562 297,727
Income Tax Expense 40,956 33,248 112,688 81,456
- ----------------------------------------------------------------------------------------------------------------
Net Income 88,812 131,152 223,874 216,271
Preferred Stock Dividend Requirement 741 741 1,482 1,482
- ----------------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 88,071 $ 130,411 $ 222,392 $ 214,789
- ----------------------------------------------------------------------------------------------------------------
See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.
29
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands) June 30, December 31,
Assets 2003 2002
- ----------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 13,072,200 $ 12,675,761
Accumulated depreciation (6,077,374) (6,356,933)
- ----------------------------------------------------------------------------------------------------------
Utility plant in service, net 6,994,826 6,318,828
Held for future use 4,942 7,188
Construction work in progress 334,269 325,695
Nuclear fuel, net of amortization 168,148 176,622
- ----------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 7,502,185 6,828,333
- ----------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 12,998 18,284
Accounts receivable 260,691 301,178
Unbilled accounts receivable 143,870 151,352
Receivables from affiliated companies 32,270 36,870
Notes receivable from affiliated companies - 49,772
Taxes receivable - 55,006
Inventory 348,239 342,886
Deferred fuel cost 137,301 146,015
Prepayments and other current assets 35,459 45,542
- ----------------------------------------------------------------------------------------------------------
Total Current Assets 970,828 1,146,905
- ----------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 515,257 252,083
Nuclear decommissioning trust funds 465,043 423,293
Diversified business property, net 51,771 9,435
Miscellaneous other property and investments 184,029 209,657
Other assets and deferred debits 98,947 104,978
- ----------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 1,315,047 999,446
- ----------------------------------------------------------------------------------------------------------
Total Assets $ 9,788,060 $ 8,974,684
- ----------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- ----------------------------------------------------------------------------------------------------------
Capitalization
- ----------------------------------------------------------------------------------------------------------
Common stock $ 3,135,690 $ 3,089,115
Preferred stock - not subject to mandatory redemption 59,334 59,334
Long-term debt, net 2,516,941 3,048,466
- ----------------------------------------------------------------------------------------------------------
Total Capitalization 5,711,965 6,196,915
- ----------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 400,000 -
Accounts payable 176,387 259,217
Payables to affiliated companies 121,081 98,572
Notes payable to affiliated companies 49,359 -
Taxes accrued 4,031 -
Interest accrued 56,678 58,791
Short-term obligations 363,900 437,750
Current portion of accumulated deferred income taxes 44,197 66,088
Other current liabilities 92,016 93,171
- ----------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,307,649 1,013,589
- ----------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,156,722 1,179,689
Accumulated deferred investment tax credits 153,207 158,308
Regulatory liabilities 131,994 7,774
Asset retirement obligations 905,338 -
Other liabilities and deferred credits 421,185 418,409
- ----------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,768,446 1,764,180
- ----------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 9)
- ----------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 9,788,060 $ 8,974,684
- ----------------------------------------------------------------------------------------------------------
See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.
30
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS Six Months Ended
(Unaudited) June 30,
(In thousands) 2003 2002
- -----------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 223,874 $ 216,271
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation and amortization 324,975 329,437
Deferred income taxes (38,115) (25,358)
Investment tax credit (5,100) (6,240)
Deferred fuel cost 8,714 12,757
Net (increase) decrease in accounts receivable 20,169 (13,408)
Net decrease in affiliated accounts receivable 14,743 (38,213)
Net increase in inventories (5,353) (1,229)
Net (increase) decrease in prepayments and other current assets 8,315 (14,916)
Net decrease in accounts payable (14,632) (5,109)
Net increase in affiliated accounts payable 17,487 33,340
Net increase in other current liabilities 58,183 93,975
Other 50,783 21,921
- -----------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 664,043 603,228
- -----------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (258,526) (333,308)
Proceeds from assets transferred to affiliate - 243,719
Nuclear fuel additions (45,642) (49,380)
Contributions to nuclear decommissioning trust (17,959) (17,915)
Diversified business property additions (262) (10,439)
Investments in non-utility activities (2,258) (6,886)
- -----------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (324,647) (174,209)
- -----------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt - 46,505
Net decrease in short-term obligations (73,850) (207,535)
Net increase (decrease) in intercompany notes 99,131 (36,374)
Retirement of long-term debt (165,208) (49,754)
Dividends paid to parent (203,273) (190,599)
Dividends paid on preferred stock (1,482) (1,482)
- -----------------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (344,682) (439,239)
- -----------------------------------------------------------------------------------------------------------------
Net Decrease in Cash and Cash Equivalents (5,286) (10,220)
- -----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of the Period 18,284 21,250
- -----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of the Period $ 12,998 $ 11,030
- -----------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 95,287 $ 103,911
income taxes (net of refunds) $ 119,638 $ 61,163
Noncash Activities
- - In February 2002, CP&L transferred the Rowan plant to Progress Ventures,
Inc. and established an intercompany receivable. The property and inventory
transferred totaled approximately $244 million. In April 2002, CP&L
received cash proceeds in settlement of the intercompany receivable
totaling approximately $244 million. This amount is reported in proceeds
from assets transferred to affiliates in the investing activities section.
See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.
31
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
NOTES TO CONSOLIDATED INTERIM FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
A. Organization.
Progress Energy Carolinas, Inc. (PEC) is a public service corporation
primarily engaged in the generation, transmission, distribution and sale of
electricity primarily in portions of North Carolina and South Carolina. PEC
is a wholly owned subsidiary of Progress Energy, Inc. (the Company or
Progress Energy). The Company is a registered holding company under the
Public Utility Holding Company Act of 1935 (PUHCA). Both the Company and
its subsidiaries are subject to the regulatory provisions of PUHCA.
Effective January 1, 2003, Carolina Power & Light Company (CP&L) began
doing business under the assumed name Progress Energy Carolinas, Inc. The
legal name has not changed and there was no restructuring of any kind
related to the name change. The current corporate and business unit
structure remains unchanged.
B. Basis of Presentation.
These financial statements have been prepared in accordance with accounting
principles generally accepted in the United States of America (GAAP) for
interim financial information and with the instructions to Form 10-Q and
Regulation S-X. Accordingly, they do not include all of the information and
footnotes required by GAAP for complete financial statements. Because the
accompanying consolidated interim financial statements do not include all
of the information and footnotes required by GAAP, they should be read in
conjunction with the audited financial statements for the period ended
December 31, 2002 and notes thereto included in PEC's Form 10-K, as amended
for the year ended December 31, 2002.
The amounts included in the consolidated interim financial statements are
unaudited but, in the opinion of management, reflect all 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 2002 have been reclassified to conform
to the 2003 presentation, with no effect on previously reported net income
or common stock equity.
2. FINANCIAL INFORMATION BY BUSINESS SEGMENT
PEC's operations consist primarily of the PEC Electric segment with no
other material segments.
The financial information for the PEC Electric segment for the three and
six months ended June 30, 2003 and 2002 is as follows:
(in thousands)
Three Months Ended June 30, Six Months Ended June 30,
--------------------------- -------------------------
2003 2002 2003 2002
--------------------------------------------------------------------------------------------
Revenues $ 816,240 $ 834,658 $ 1,741,710 $ 1,646,139
Segment income $ 88,394 $ 131,690 $ 223,264 $ 217,222
Total segment assets $ 9,568,769 $ 8,669,993 $ 9,568,769 $ 8,669,993
============================================================================================
The primary differences between the PEC Electric segment and PEC
consolidated financial information relate to other non-electric operations
and elimination entries.
32
3. IMPACT OF NEW ACCOUNTING STANDARDS
SFAS No. 148, "Accounting for Stock-Based Compensation"
For purposes of the pro forma disclosures required by SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure - an
Amendment of FASB Statement No. 123," the estimated fair value of the
Company's stock options is amortized to expense over the options' vesting
period. PEC's information related to the pro forma impact on earnings
assuming stock options were expensed for the three and six months ended
June 30:
Three Months Ended June 30, Six Months Ended June 30,
(in thousands) 2003 2002 2003 2002
------------ ------------- ----------- ------------
Earnings for common stock, as reported $ 88,071 $ 130,411 $ 222,392 $ 214,789
Deduct: Total stock option expense determined under
fair value method for all awards, net of related tax
effects 706 535 1,779 1,294
------------ ------------- ----------- ------------
Pro forma earnings for common stock $ 87,365 $ 129,876 $ 220,613 $ 213,495
============ ============= =========== ============
In April 2003, the Financial Accounting Standards Board (FASB) approved
certain decisions on its stock-based compensation project. Some of the key
decisions reached by the FASB were that stock-based compensation should be
recognized in the income statement as an expense and that the expense
should be measured as of the grant date at fair value. A significant issue
yet to be resolved by the FASB is the determination of the appropriate fair
value measure. The FASB continues to deliberate additional issues in this
project; however, the FASB plans to issue an exposure draft in 2003 that
could become effective in 2004.
Derivative Instruments and Hedging Activities
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." The statement amends and
clarifies SFAS No. 133 on accounting for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. The new guidance incorporates decisions made as part of the
Derivatives Implementation Group (DIG) process, as well as decisions
regarding implementation issues raised in relation to the application of
the definition of a derivative. SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003. PEC is currently
evaluating what effects, if any, this statement will have on its results of
operations and financial position.
In connection with the January 2003 FASB Emerging Issues Task Force (EITF)
meeting, the FASB was requested to reconsider an interpretation of SFAS No.
133. The interpretation, which is contained in the Derivatives
Implementation Group's C11 guidance, relates to the pricing of contracts
that include broad market indices (e.g., CPI). In particular, that guidance
discusses whether the pricing in a contract that contains broad market
indices could qualify as a normal purchase or sale (the normal purchase or
sale term is a defined accounting term, and may not, in all cases, indicate
whether the contract would be "normal" from an operating entity viewpoint).
In late June 2003, the FASB issued final superseding guidance (DIG Issue
C20) on this issue, which is significantly different from the tentative
superseding guidance that was issued in April 2003. The new guidance is
effective October 1, 2003 for PEC. DIG Issue C20 specifies new
pricing-related criteria for qualifying as a normal purchase or sale, and
it requires a special transition adjustment as of October 1, 2003.
PEC has determined that it has one existing "normal" contract that is
affected by this revised guidance. PEC is in the process of evaluating the
revised guidance and related contract to determine the transition
adjustment that will be necessary and to determine if the contract will be
required to be recorded at fair value subsequent to October 1, 2003.
SFAS No. 150, "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity."
SFAS No. 150 establishes standards for how an issuer classifies and
measures certain financial instruments with characteristics of both
liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances). The financial instruments within the scope of SFAS No. 150
include mandatorily redeemable stock, obligations to repurchase the
issuer's equity shares by transferring assets, and certain obligations to
issue a variable number of shares. SFAS No. 150 is effective immediately
for such instruments entered into or modified after May 31, 2003, and is
effective for previously issued financial instruments within its scope on
July 1, 2003. PEC believes that the adoption of SFAS No. 150 will not have
a material impact on its financial position or results of operations.
33
FIN No. 46, "Consolidation of Variable Interest Entities"
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
This interpretation provides guidance related to identifying variable
interest entities (previously know as special purpose entities or SPEs) and
determining whether such entities should be consolidated. Certain
disclosures are required if it is reasonably possible that a company will
consolidate or disclose information about a variable interest entity when
it initially applies FIN No. 46. This interpretation must be applied
immediately to variable interest entities created or obtained after January
31, 2003. During the first six months of 2003, PEC did not participate in
the creation of, or obtain a new variable interest in, any variable
interest entity. For those variable interest entities created or obtained
on or before January 31, 2003, PEC must apply the provisions of FIN No. 46
in the third quarter of 2003.
PEC is currently evaluating what effects, if any, this interpretation will
have on its results of operations and financial position. During this
evaluation process, several arrangements have been identified to which this
interpretation may apply. These arrangements include investments in
approximately 50 Affordable Housing properties eligible for Section 42 tax
credits. PEC divested approximately 30 of these Affordable Housing
investments in July 2003, and therefore the application of FIN No. 46 is
not expected to have a material impact with respect to those 30
investments. It is reasonably possible that the Company will be required to
consolidate some of the remaining 20 Affordable Housing entities that are
currently accounted for under the equity method. The maximum exposure to
loss as a result of PEC's total funding commitments for the remaining 20
Affordable Housing investments is approximately $23.9 million. However,
management believes the total loss of its investments is unlikely given the
nature of the investments and the utilization of certain Section 42 tax
credits to date.
PEC is in the final stages of completing the adoption of FIN No. 46, but
having considered the facts described herein, does not expect the results
to have a material impact on its consolidated financial position, results
of operation or liquidity.
EITF Issue No. 03-04, "Accounting for 'Cash Balance' Pension Plans"
In May 2003, the EITF reached consensus in EITF Issue No. 03-04 to
specifically address the accounting for certain cash balance pension plans.
The consensus reached in EITF Issue No. 03-04 requires certain cash balance
pension plans to be accounted for as defined benefit plans. For cash
balance plans described in the consensus, the consensus also requires the
use of the traditional unit credit method for purposes of measuring the
benefit obligation and annual cost of benefits earned as opposed to the
projected unit credit method. PEC has historically accounted for its cash
balance plans as defined benefit plans; however, PEC is required to adopt
the measurement provisions of EITF 03-04 at its cash balance plans' next
measurement date of December 31, 2003. Any differences in the measurement
of the obligations as a result of applying the consensus will be reported
as a component of actuarial gain or loss. PEC is currently evaluating what
effects EITF 03-04 will have on its results of operations and financial
position.
4. ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, "Accounting for Asset Retirement Obligations," provides
accounting and disclosure requirements for retirement obligations
associated with long-lived assets and was adopted by the Company effective
January 1, 2003. This statement requires that the present value of
retirement costs for which PEC has a legal obligation be recorded as
liabilities with an equivalent amount added to the asset cost and
depreciated over an appropriate period. The liability is then accreted over
time by applying an interest method of allocation to the liability.
Cumulative accretion and accumulated depreciation were recognized for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect, to the date of adoption of
this statement.
Upon adoption of SFAS No. 143, PEC recorded asset retirement obligations
(AROs) for nuclear decommissioning of radiated plant totaling $879.7
million. PEC used an expected cash flow approach to measure these
obligations. This amount includes accruals recorded prior to adoption
totaling $491.3 million, which were previously recorded in accumulated
depreciation. The related asset retirement costs, net of accumulated
depreciation, recorded upon adoption totaled $117.3 million. The cumulative
effect of adoption of this statement had no impact on the net income of
PEC, as the effects were offset by the establishment of a regulatory asset
in the amount of $271.1 million, pursuant to SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation." The regulatory asset
represents the cumulative accretion and accumulated depreciation for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect to the date of adoption, less
the amount previously recorded.
Funds set aside in PEC's nuclear decommissioning trust fund for the nuclear
decommissioning liability totaled $465.0 million at June 30, 2003 and
$423.3 million at December 31, 2002.
34
Pro forma net income has not been presented for prior years because the pro
forma application of SFAS No. 143 to prior years would result in pro forma
net income not materially different from the actual amounts reported.
PEC has identified but not recognized AROs related to electric transmission
and distribution and telecommunications assets as the result of easements
over property not owned by PEC. These easements are generally perpetual and
only require retirement action upon abandonment or cessation of use of the
property for the specified purpose. The ARO liability is not estimable for
such easements as PEC intends to utilize these properties indefinitely. In
the event PEC decides to abandon or cease the use of a particular easement,
an ARO liability would be recorded at that time.
PEC has previously recognized removal costs as a component of depreciation
in accordance with regulatory treatment. As of June 30, 2003, the portion
of such costs not representing AROs under SFAS No. 143 was $882.6 million.
This amount is included in accumulated depreciation on the accompanying
Consolidated Balance Sheets. PEC has collected amounts for non-radiated
areas at nuclear facilities, which do not represent asset retirement
obligations. These amounts totaled $63.5 million as of June 30, 2003, which
is included in accumulated depreciation on the accompanying Consolidated
Balance Sheets.
PEC filed a request with the NCUC requesting deferral of the difference
between expense pursuant to SFAS No. 143 and expense as previously
determined by the NCUC. The NCUC granted the deferral of the January 1,
2003 cumulative adjustment. Because the clean air legislation discussed in
Note 9 under "Air Quality" contained a prohibition against cost deferrals
unless certain criteria are met, the NCUC denied the deferral of the
ongoing effects. The Company has provided additional information to the
NCUC that it believes will demonstrate that deferral of the ongoing effects
should also be allowed. 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 $13.6 million, which
represents a decrease in non-ARO cost of removal expense, partially offset
by an increase in decommissioning expense.
On April 8, 2003, the Public Service Commission of South Carolina (SCPSC)
approved a joint request by PEC, Duke Energy and South Carolina Electric
and Gas Company for an accounting order to authorize the deferral of all
cumulative and prospective effects related to the adoption of SFAS No. 143.
5. COMPREHENSIVE INCOME
Comprehensive income for the three and six months ended June 30, 2003 was
$88.0 million and $223.2 million, respectively. Comprehensive income for
the three and six months ended June 30, 2002 was $129.6 million and $218.2
million, respectively. Items of other comprehensive income for the periods
consisted primarily of changes in fair value of derivatives used to hedge
cash flows related to interest on long-term debt.
6. FINANCING ACTIVITIES
On April 1, 2003, PEC reduced the size of its existing 364-day credit
facility from $285 million to $165 million. The other terms of this
facility were not changed. On July 30, 2003, PEC renewed its $165 million
364-day credit agreement. PEC's $285 million three-year credit agreement
entered into in July 2002 remains in place, for total facilities of $450
million.
On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5%
Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds.
PEC funded the redemption with commercial paper.
On July 14, 2003, PEC announced the redemption of $100 million of First
Mortgage Bonds, 6.875% Series Due August 15, 2023 at 102.84%. The date of
the redemption will be August 15, 2003. PEC will fund the redemption with
commercial paper.
7. RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS
PEC uses interest rate derivative instruments to adjust the fixed and
variable rate debt components of its debt portfolio and to hedge interest
rates with regard to future fixed rate debt issuances. In March, April and
June of 2003, PEC entered into treasury rate locks to hedge its exposure to
35
interest rates with regard to a future issuance of debt. These agreements
have a computational period of ten years and are designated as cash flow
hedges for accounting purposes. These agreements have a total notional
amount of $60 million.
The notional amounts of the above contracts are not exchanged and do not
represent exposure to credit loss. In the event of default by a counter
party, the risk in the transaction is the cost of replacing the agreements
at current market rates. PEC only enters into interest rate swap agreements
with banks with credit ratings of single A or better.
8. OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income, gain on the sale of
investments, impairment of investments and other income and expense items
as discussed below. The components of other, net as shown on the
Consolidated Statements of Income for the three and six months ended June
30, 2003 and 2002 are as follows:
Three Months Ended June 30, Six Months Ended June 30,
(in thousands) 2003 2002 2003 2002
-------------- -------------- ------------- -------------
Other income
Net financial trading gain (loss) $ 1,175 $ 792 $ (1,524) $ (1,429)
Net energy brokered for resale (68) (89) 270 (446)
Nonregulated energy and delivery services income 2,052 3,016 4,338 5,567
AFUDC equity 774 1,602 1,864 3,662
Investment gains - 2,960 - 2,960
Other 2,767 4,711 5,523 5,981
-------------- -------------- ------------- -------------
Total other income $ 6,700 $ 12,992 $ 10,471 $ 16,295
-------------- -------------- ------------- -------------
Other expense
Nonregulated energy and delivery services expenses $ 2,022 $ 3,632 $ 3,995 $ 5,267
Donations 1,339 1,178 2,645 2,548
Investment losses 8,643 - 8,643 -
Other 3,076 3,530 6,119 6,800
-------------- -------------- ------------- -------------
Total other expense $ 15,080 $ 8,340 $ 21,402 $ 14,615
-------------- -------------- ------------- -------------
Other, net $ (8,380) $ 4,652 $ (10,931) $ 1,680
============== ============== ============= =============
Net financial trading gains and losses represent non-asset-backed trades of
electricity and gas. Net energy brokered for resale represents electricity
purchased externally for sale to a third party. Nonregulated energy and
delivery services include power protection services and mass market
programs (surge protection, appliance services and area light sales) and
delivery, transmission and substation work for other utilities. Investment
losses represent losses on limited partnership investment funds.
9. COMMITMENTS AND CONTINGENCIES
Contingencies existing as of the date of these statements are described
below. No significant changes have occurred since December 31, 2002, with
respect to the commitments discussed in Note 18 of the financial statements
included in PEC's 2002 Annual Report on Form 10-K, as amended.
In 2003, PEC determined that its external funding levels did not fully meet
the nuclear decommissioning financial assurance levels required by the NRC.
Therefore, PEC obtained parent company guarantees of $276 million to meet
the required levels. As of June 30, 2003, management does not believe
conditions are likely for performance under the agreements discussed in
this Note 9.
Insurance
PEC is insured against public liability for a nuclear incident. Under the
current provisions of the Price Anderson Act, which limits liability for
accidents at nuclear plants, PEC, as an owner of nuclear units, can be
assessed a portion of any third-party liability claims arising from an
accident at any commercial nuclear power plant in the United States. In the
event that public liability claims from an insured nuclear incident exceed
$300 million (currently available through commercial insurers), each
company would be subject to pro rata assessments for each reactor owned per
occurrence. Effective August 20, 2003, the retroactive premium assessments
will increase to $100.6 million per reactor from the current amount of
$88.1 million. The total limit available to cover nuclear liability losses
will increase as well from $9.6 billion to $10.6 billion. The annual
retroactive premium limit of $10 million per reactor owned will not change.
36
Contingencies
Claims and uncertainties
a) PEC is subject to federal, state and local regulations addressing
hazardous and solid waste management, air and water quality and other
environmental matters.
Hazardous and Solid Waste Management
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The principal regulatory agency that is responsible for a
specific former MGP site depends largely upon the state in which the site
is located. There are several MGP sites to which PEC has some connection.
In this regard, PEC and other potentially responsible parties, are
participating in investigating and, if necessary, remediating former MGP
sites with several regulatory agencies, including, but not limited to, the
EPA and the North Carolina Department of Environment and Natural Resources,
Division of Waste Management (DWM). In addition, PEC is periodically
notified by regulators such as the EPA and various state agencies of their
involvement or potential involvement in sites, other than MGP sites, that
may require investigation and/or remediation.
There are 12 former MGP sites and 14 other sites or groups of sites
associated with PEC that have required or are anticipated to require
investigation and/or remediation costs. PEC received insurance proceeds to
address costs associated with PEC environmental liabilities related to its
involvement with some MGP sites. All eligible expenses related to these are
charged against a specific fund containing these proceeds. As of June 30,
2003, approximately $5.2 million remains in this centralized fund with a
related accrual of $5.2 million recorded for the associated expenses of
environmental issues. As PEC's share of costs for investigating and
remediating these sites become known, the fund is assessed to determine if
additional accruals will be required. PEC does not believe that it can
provide an estimate of the reasonably possible total remediation costs
beyond what remains in the environmental insurance recovery fund. This is
due to the fact that the sites are at different stages: investigation has
not begun at 15 sites, investigation has begun but remediation cannot be
estimated at seven sites and four sites have begun remediation. PEC
measures its liability for these sites based on available evidence
including its experience in investigating and remediating environmentally
impaired sites. The process often involves assessing and developing
cost-sharing arrangements with other potentially responsible parties. Once
the environmental insurance recovery fund is depleted, PEC will accrue
costs for the sites to the extent its liability is probable and the costs
can be reasonably estimated. Presently, PEC cannot determine the total
costs that may be incurred in connection with the remediation of all sites.
PEC has filed claims with its general liability insurance carriers to
recover costs arising out of actual or potential environmental liabilities.
Some claims have settled and others are still pending. While management
cannot predict the outcome of these matters, the outcome is not expected to
have a material effect on the consolidated financial position or results of
operations.
PEC is also currently in the process of assessing potential costs and
exposures at other environmentally impaired sites. As the assessments are
developed and analyzed, PEC will accrue costs for the sites to the extent
the costs are probable and can be reasonably estimated.
Air Quality
There has been and may be further proposed federal legislation requiring
reductions in air emissions for nitrogen oxides, sulfur dioxide, carbon
dioxide and mercury. Some of these proposals establish nation-wide caps and
emission rates over an extended period of time. This national
multi-pollutant approach to air pollution control could involve significant
capital costs which could be material to PEC's consolidated financial
position or results of operations. Some companies may seek recovery of the
related cost through rate adjustments or similar mechanisms. Control
equipment that will be installed on North Carolina fossil generating
facilities as part of the North Carolina legislation discussed below may
address some of the issues outlined above. However, PEC cannot predict the
outcome of this matter.
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
PEC was asked to provide information to the EPA as part of this initiative
and cooperated in providing the requested information. During the first
quarter of 2003, PEC responded to a supplemental information request from
the EPA. The EPA initiated civil enforcement actions against other
unaffiliated utilities as part of this initiative. Some of these actions
resulted in settlement agreements calling for expenditures, ranging from
37
$1.0 billion to $1.4 billion. A utility that was not subject to a civil
enforcement action settled its New Source Review issues with the EPA for
$300 million. These settlement agreements have generally called for
expenditures to be made over extended time periods, and some of the
companies may seek recovery of the related cost through rate adjustments or
similar mechanisms. PEC cannot predict the outcome of the EPA's initiative
or its impact, if any, on the Company.
In 1998, the EPA published a final rule addressing the regional transport
of ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule
requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, to further reduce nitrogen oxide emissions in order to attain a
pre-set state NOx emission levels by May 31, 2004. PEC is currently
installing controls necessary to comply with the rule. Capital expenditures
needed to meet these measures in North and South Carolina could reach
approximately $370 million, which has not been adjusted for inflation.
Increased operation and maintenance costs relating to the NOx SIP Call are
not expected to be material to PEC's results of operations. Further
controls are anticipated as electricity demand increases. PEC cannot
predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new
eight-hour ozone standard. In October 1999, the District of Columbia
Circuit Court of Appeals ruled against the EPA with regard to the federal
eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the
District of Columbia Circuit Court of Appeals decision. Designation of
areas that do not attain the standard is proceeding, and further litigation
and rulemaking on this and other aspects of the standard are anticipated.
North Carolina adopted the federal eight-hour ozone standard and is
proceeding with the implementation process. North Carolina has promulgated
final regulations, which will require PEC to install nitrogen oxide
controls under the State's eight-hour standard. The costs of those controls
are included in the $370 million cost estimate set forth in the preceding
paragraph. However, further technical analysis and rulemaking may result in
a requirement for additional controls at some units. PEC cannot predict the
outcome of this matter.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule as originally promulgated required certain sources
to make reductions in nitrogen oxide emissions by May 1, 2003. The final
rule also includes a set of regulations that affect nitrogen oxide
emissions from sources included in the petitions. The North Carolina
coal-fired electric generating plants are included in these petitions.
Acceptable state plans under the NOx SIP Call can be approved in lieu of
the final rules the EPA approved as part of the Section 126 petitions. PEC,
other utilities, trade organizations and other states participated in
litigation challenging the EPA's action. On May 15, 2001, the District of
Columbia Circuit Court of Appeals ruled in favor of the EPA, which will
require North Carolina to make reductions in nitrogen oxide emissions by
May 1, 2003. However, the Court in its May 15th decision rejected the EPA's
methodology for estimating the future growth factors the EPA used in
calculating the emissions limits for utilities. In August 2001, the Court
granted a request by PEC and other utilities to delay the implementation of
the 126 Rule for electric generating units pending resolution by the EPA of
the growth factor issue. The Court's order tolls the three-year compliance
period (originally set to end on May 1, 2003) for electric generating units
as of May 15, 2001. On April 30, 2002, the EPA published a final rule
harmonizing the dates for the Section 126 Rule and the NOx SIP Call. In
addition, the EPA determined in this rule that the future growth factor
estimation methodology was appropriate. The new compliance date for all
affected sources is now May 31, 2004, rather than May 1, 2003. The EPA has
approved North Carolina's NOx SIP Call rule and has formally proposed to
rescind the Section 126 rule. This rulemaking is expected to become final
during the summer of 2003. PEC expects a favorable outcome of this matter.
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and
sulfur dioxide from coal-fired power plants. PEC expects its capital costs
to meet these emission targets will be approximately $813 million by 2013.
PEC currently has approximately 5,100 MW of coal-fired generation in North
Carolina that is affected by this legislation. The legislation requires the
emissions reductions to be completed in phases by 2013, and applies to each
utility's total system rather than setting requirements for individual
power plants. The legislation also freezes the utilities' base rates for
five years unless there are extraordinary events beyond the control of the
utilities or unless the utilities persistently earn a return substantially
in excess of the rate of return established and found reasonable by the
NCUC in the utilities' last general rate case. Further, the legislation
allows the utilities to recover from their retail customers the projected
capital costs during the first seven years of the 10-year compliance period
beginning on January 1, 2003. The utilities must recover at least 70% of
their projected capital costs during the five-year rate freeze period.
Pursuant to the new law, PEC entered into an agreement with the state of
North Carolina to transfer to the state any future emissions allowances
acquired as a result of compliance with the new law. The new law also
requires the state to undertake a study of mercury and carbon dioxide
emissions in North Carolina. PEC cannot predict the future regulatory
interpretation, implementation or impact of this new law. PEC recorded
$33.5 million in the second quarter of 2003 and approximately $54 million
of clean air amortization to date in 2003. Clean air expenditures to date
are $8.4 million.
38
Other Environmental Matters
a) The Kyoto Protocol was adopted in 1997 by the United Nations to address
global climate change by reducing emissions of carbon dioxide and other
greenhouse gases. The United States has not adopted the Kyoto Protocol;
however, a number of carbon dioxide emissions control proposals have been
advanced in Congress and by the Bush administration. The Bush
administration favors voluntary programs. Reductions in carbon dioxide
emissions to the levels specified by the Kyoto Protocol and some
legislative proposals could be materially adverse to PEC's financials and
operations if associated costs cannot be recovered from customers. PEC
favors the voluntary program approach recommended by the administration,
and is evaluating options for the reduction, avoidance, and sequestration
of greenhouse gases. However, PEC cannot predict the outcome of this
matter.
In 1997, the EPA's Mercury Study Report and Utility Report to Congress
conveyed that mercury is not a risk to the average American and expressed
uncertainty about whether reductions in mercury emissions from coal-fired
power plants would reduce human exposure. Nevertheless, EPA determined in
2000 that regulation of mercury emissions from coal-fired power plants was
appropriate. Pursuant to a Court Order, the EPA is developing a Maximum
Available Control Technology (MACT) standard, which is expected to become
final in December 2004, with compliance in 2008. Achieving compliance with
the MACT standard could be materially adverse to PEC's financial condition
and results of operations. However, PEC cannot predict the outcome of this
matter.
b) As required under the Nuclear Waste Policy Act of 1982, PEC entered into
a contract with the DOE under which the DOE agreed to begin taking spent
nuclear fuel by no later than January 31, 1998. All similarly situated
utilities were required to sign the same standard contract.
In April 1995, the DOE issued a final interpretation that it did not have
an unconditional obligation to take spent nuclear fuel by January 31, 1998.
In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's
final interpretation and ruled that the DOE had an unconditional obligation
to begin taking spent nuclear fuel. The Court did not specify a remedy
because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan
Power v. DOE, a group of utilities petitioned the Court of Appeals in
Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to
begin taking spent nuclear fuel by January 31, 1998. The DOE took the
position that its delay was unavoidable, and the DOE was excused from
performance under the terms and conditions of the contract. The Court of
Appeals found that the delay was not unavoidable, but did not order the DOE
to begin taking spent nuclear fuel, stating that the utilities had a
potentially adequate remedy by filing a claim for damages under the
contract.
After the DOE failed to begin taking spent nuclear fuel by January 31,
1998, a group of utilities filed a motion with the Court of Appeals to
enforce the mandate in NSP v. DOE. Specifically, this group of utilities
asked the Court to permit the utilities to escrow their waste fee payments,
to order the DOE not to use the waste fund to pay damages to the utilities,
and to order the DOE to establish a schedule for disposal of spent nuclear
fuel. The Court denied this motion based primarily on the grounds that a
review of the matter was premature, and that some of the requested remedies
fell outside of the mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal
Circuit) 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.
PEC is in the process of evaluating whether it should file a similar action
for damages.
On July 9, 2002, Congress passed an override resolution to Nevada's veto of
DOE's proposal to locate a permanent underground nuclear waste storage
facility at Yucca Mountain, Nevada. DOE plans to submit a license
application for the Yucca Mountain facility by the end of 2004. PEC cannot
predict the outcome of this matter.
With certain modifications and additional approval by the NRC, PEC's spent
nuclear fuel storage facilities will be sufficient to provide storage space
for spent fuel generated on its system through the expiration of the
current operating licenses for all of its nuclear generating units.
Subsequent or prior to the expiration of these licenses, or any renewal of
these licenses, dry storage or acquisition of new shipping casks may be
necessary. PEC obtained NRC approval to use additional storage space at the
Harris Plant in December 2000.
39
c) PEC is involved in various litigation matters in the ordinary course of
business, some of which involve claims for substantial amounts. Where
appropriate, accruals have been made in accordance with SFAS No. 5,
"Accounting for Contingencies," to provide for such matters. PEC believes
the final disposition of pending litigation would not have a material
adverse effect on PEC's consolidated results of operations or financial
position.
40
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following Management's Discussion and Analysis contains forward-looking
statements that involve estimates, projections, goals, forecasts, assumptions,
risks and uncertainties that could cause actual results or outcomes to differ
materially from those expressed in the forward-looking statements. Please review
"SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for a discussion of the factors
that may impact any such forward-looking statements made herein.
Amounts reported in the interim Consolidated Statements of Income are not
necessarily indicative of amounts expected for the respective annual or future
periods due to the effects of seasonal temperature variations on energy
consumption and the timing of maintenance on electric generating units, among
other factors.
This discussion should be read in conjunction with the accompanying financial
statements found elsewhere in this report and in conjunction with the 2002 Form
10-K.
RESULTS OF OPERATIONS
In this section, earnings and the factors affecting earnings for the three and
six months ended June 30, 2003 as compared to the same periods in 2002 are
discussed. The discussion begins with a general overview, then separately
discusses earnings by business segment.
OVERVIEW
The net income and basic earnings per share of Progress Energy, Inc. (Progress
Energy or the Company) were $152.8 million or $0.65 per share and $120.6 million
or $0.56 per share for the second quarter of 2003 and 2002, respectively. The
Company's net income and basic earnings per share were $361.0 million or $1.54
per share and $253.1 million or $1.18 per share for the first half of 2003 and
2002, respectively.
The increase in net income for the second quarter of 2003, as compared to the
second quarter of 2002, is primarily due to customer growth and usage at the
utilities, increased sales of natural gas, a decrease in interest expense and
the impact of levelizing the estimated effective tax rate throughout the year.
These items were partially offset by the impact of unfavorable weather, PEF's
retail revenue sharing and higher costs associated with a planned nuclear
outage. The Company's operating segments impacted earnings for the quarter and
first half of the year as follows:
- ---------------------------------------------------------------------------------------------------------
(in millions) Three Months Ended June 30, Six Months Ended June 30,
- ---------------------------------------------------------------------------------------------------------
Business Segment 2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------
PEC Electric $ 88.4 $ 131.7 $ 223.3 $ 217.2
PEF 61.4 76.8 132.1 134.5
Fuels 53.8 46.7 80.4 88.3
CCO 2.4 6.7 10.9 4.6
Rail 2.2 2.9 (1.2) 2.2
Other 1.2 (8.4) 1.9 (13.2)
Corporate (59.1) (134.5) (100.2) (187.6)
------------------------------------------------------------
Total income from continuing operations 150.3 121.9 347.2 246.0
NCNG discontinued operations 2.5 (1.3) 13.8 7.1
------------------------------------------------------------
Net income $ 152.8 $ 120.6 $ 361.0 $ 253.1
- -------------------------------------------------------------------------------------------------------
A detailed discussion of each of the Company's significant operating segments
follows. The Company's significant operating segments and their primary
operations are:
o PEC Electric - engaged in the generation, transmission, distribution and
sale of electricity in portions of North Carolina and South Carolina
(differences between the PEC Electric segment and the PEC consolidated
financial information relate to other non-electric operations and
elimination entries);
o PEF - engaged in the generation, transmission, distribution and sale of
electricity in portions of Florida;
o Fuels - engaged in natural gas drilling and production, coal mining and the
production of synthetic fuels;
o Competitive Commercial Operations (CCO) - engaged in nonregulated
generation operations and limited trading activities;
o Progress Rail Services (Rail) - engaged in various rail and railcar related
services; and
o Other Businesses (Other) - engaged in other nonregulated business areas
including telecommunications and energy services operations.
41
In prior years' reporting, CCO and Fuels were components of the Progress
Ventures segment. With the expansion of the nonregulated energy generation
facilities and the current management structure, CCO is now a distinct
operating segment. In addition to the operating segments listed above, the
Company has other corporate activities that include holding company
operations, service company operations and eliminations. These corporate
activities have been included in the Other segment in the past.
Additionally, earnings from wholesale customers on the regulated plants
have previously been reported in both the regulated utilities' results and
the results of Progress Ventures. With the realignment of the reportable
business segments, this activity is now included in the regulated
utilities' results only. For comparative purposes, the 2002 results have
been restated to align with the new business segments.
In 2002, the operations of NCNG, previously reported in the Other segment,
were reclassified to discontinued operations and therefore were not
included in the results from continuing operations during the periods
reported. A discussion of the planned divestiture of NCNG is provided in
the Discontinued Operations section that follows.
In March of 2003, the SEC completed an audit of Progress Energy Service
Company, LLC (Service Company) and recommended that the Company change its
cost allocation methodology for allocating Service Company costs. As part
of the audit process, the Company was required to change the cost
allocation methodology for 2003 and record retroactive reallocations
between its affiliates in the first quarter of 2003 for allocations
originally made in 2001 and 2002. This change in allocation methodology and
the related retroactive adjustments have no impact on consolidated expense
or earnings. The impact on the affiliates is included in the segment
discussion that follows. The new allocation methodology, as compared to the
previous allocation methodology, generally decreases expenses in the
regulated utilities and increases expenses in the nonregulated businesses.
The regulated utilities' reallocations are within operation and maintenance
expense, while the diversified businesses' reallocations are generally
within diversified business expenses.
In accordance with an SEC order under PUHCA, effective in the second
quarter of 2002, tax benefits not related to acquisition interest expense
that were previously held unallocated at the holding company must be
allocated to the profitable subsidiaries. The allocation has no impact on
the Company's consolidated tax expense or net income. The impacts on the
business segments are included in the discussions below and generally
decrease the income tax expense for the regulated utilities, while
increasing income tax expense for the holding company. The second quarter
2002 reallocation included impacts from 2001 and the first two quarters of
2002, while the second quarter 2003 reallocation was for one quarter only.
REGULATED ELECTRIC SEGMENTS
The operating results of both regulated electric utilities are primarily
influenced by customer demand for electricity, the ability to control costs
and regulatory return on equity. Demand for electricity is based on the
number of customers and their usage, with usage largely impacted by
weather. In addition, the current economic conditions in the service
territories may impact the demand for electricity.
Effective January 1, 2003, the Company implemented SFAS No. 143,
"Accounting for Asset Retirement Obligations," which requires that the
present value of retirement costs for which the Company has a legal
obligation be recorded as liabilities with an equivalent amount added to
the asset cost and depreciated over an appropriate period. The liability is
then accreted over time by applying an interest method of allocation to the
liability. Both electric utilities recorded asset retirement obligations
(AROs) in the first quarter of 2003. At June 30, 2003, PEC Electric's AROs
totaled $905.3 million and PEF's AROs totaled $310.9 million.
PEC filed a request with the NCUC requesting deferral of the difference
between expense pursuant to SFAS No. 143 and expense as previously
determined by the NCUC. The NCUC granted the deferral of the January 1,
2003, cumulative adjustment. Because the clean air legislation enacted in
North Carolina contained a prohibition against cost deferrals unless
certain criteria are met, the NCUC denied the deferral of the ongoing
effects. The Company has provided additional information to the NCUC that
it believes will demonstrate that deferral of the ongoing effects should
also be allowed. Since the NCUC order denied deferral of the ongoing
effects, PEC ceased deferral of the ongoing effects during the second
quarter of 2003 for the six months ended June 30, 2003 related to its North
Carolina retail jurisdiction. Pre-tax income for the second quarter of 2003
increased by approximately $13.6 million, which represents a decrease in
non-ARO cost of removal expense, partially offset by an increase in
decommissioning expense. This earnings impact will be reversed if and when
the NCUC issues an order granting deferral of the ongoing effects.
42
On April 8, 2003, the SCPSC approved a joint request by PEC Electric, Duke
Energy and South Carolina Electric and Gas Company for an accounting order
to authorize the deferral of all cumulative and prospective effects related
to the adoption of SFAS No. 143.
On January 23, 2003, the Staff of the FPSC issued a notice of proposed rule
development to adopt provisions relating to accounting for asset retirement
obligations under SFAS No. 143. Accompanying the notice was a draft rule
presented by the staff which adopts the provisions of SFAS No. 143 along
with the requirement to record the difference between amounts prescribed by
the FPSC and those used in the application of SFAS No. 143 as regulatory
assets or regulatory liabilities, which was accepted by all parties.
Therefore, the adoption of the statement had no impact on the income of PEF
due to the establishment of a regulatory liability pursuant to SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." The Commission
approved the draft rule in June 2003, and a final order is expected in the
third quarter of 2003.
PROGRESS ENERGY CAROLINAS ELECTRIC
PEC Electric contributed net income of $88.4 million and $131.7 million in
the second quarter of 2003 and 2002, respectively, and $223.3 million and
$217.2 million for the first half of 2003 and 2002, respectively. The
decrease in the second quarter of 2003 compared to the second quarter of
2002 is primarily due to unfavorable weather conditions resulting in lower
usage across all customer classes, the effect of the tax benefit
reallocation and higher planned nuclear outage costs, partially offset by
favorable retail customer growth and usage. The increase in the first half
of 2003 compared to the first half of 2002 was primarily due to strong
wholesale sales, retail growth and usage and lower interest charges, offset
partially by the effect of the tax benefit reallocation, higher operation
and maintenance costs related to planned nuclear outages and costs incurred
for the February 2003 ice storm.
PEC's electric revenues for the second quarter and first half of 2003 are
as follows:
------------------------------------------------------------------------------------------------------------------
(in millions of $) Three Months Ended June 30, Six Months Ended June 30,
------------------------------------------------------------------------------------------------------------------
Customer Class 2003 Change % Change 2002 2003 Change % Change 2002
------------------------------------------------------------------------------------------------------------------
Residential $ 247.7 $ (10.8) (4.2) $ 258.5 $ 604.7 $ 37.0 6.5 $ 567.7
Commercial 198.8 (0.1) (0.1) 198.9 399.7 13.6 3.5 386.1
Industrial 155.9 (4.3) (2.7) 160.2 302.6 (3.3) (1.1) 305.9
Governmental 17.8 (0.1) (0.6) 17.9 36.4 0.9 2.5 35.5
---------------------- ------------------------------- ----------
Total retail revenues 620.2 (15.3) (2.4) 635.5 1,343.4 48.2 3.7 1,295.2
Wholesale 154.2 (2.5) (1.6) 156.7 363.6 64.3 21.5 299.3
Unbilled 23.5 (0.6) - 24.1 (7.5) (21.9) - 14.4
Miscellaneous 18.3 (0.1) (0.5) 18.4 42.2 5.0 13.4 37.2
---------------------- ------------------------------- ----------
Total electric revenues $ 816.2 $ (18.5) (2.2) $ 834.7 $ 1,741.7 $ 95.6 5.8 $ 1,646.1
------------------------------------------------------------------------------------------------------------------
PEC's electric energy sales for 2003 and 2002 and the amount and percentage
change by quarter and by customer class are as follows:
------------------------------------------------------------------------------------------------------------------
(in thousands of mWh) Three Months Ended June 30, Six Months Ended June 30,
------------------------------------------------------------------------------------------------------------------
Customer Class 2003 Change % Change 2002 2003 Change % Change 2002
------------------------------------------------------------------------------------------------------------------
Residential 3,052 (210) (6.4) 3,262 7,639 392 5.4 7,247
Commercial 2,946 (81) (2.7) 3,027 5,930 112 1.9 5,818
Industrial 3,197 (164) (4.9) 3,361 6,202 (145) (2.3) 6,347
Governmental 317 (21) (6.2) 338 660 (3) (0.5) 663
---------------------- ------------------------------- ----------
Total retail energy 9,512 (476) (4.8) 9,988 20,431 356 1.8 20,075
sales
Wholesale 3,301 (194) (5.6) 3,495 7,920 1,094 16.0 6,826
Unbilled 396 (35) - 431 (84) (329) - 245
---------------------- ------------------------------- ----------
Total mWh sales 13,209 (705) (5.1) 13,914 28,267 1,121 4.1 27,146
------------------------------------------------------------------------------------------------------------------
Second Quarter of 2003 Compared to Second Quarter of 2002
Unfavorable weather accounted for a revenue decline of $34.1 million, with
the average cooling degree days declining 37% when comparing the second
quarter of 2003 to the second quarter of 2002. Retail customer growth and
usage, excluding the impact of weather, accounted for $18.1 million of
additional revenue in the second quarter of 2003 as compared to the second
quarter of 2002, with 22,364 additional retail customers during the second
quarter of 2003 as compared to 2002.
43
Operation and maintenance costs were $210.3 million for the second quarter
of 2003, which represents a $16.4 million increase compared to the second
quarter of 2002. A planned nuclear outage at the Harris plant during 2003
accounted for $15.1 million of this increase.
Depreciation and amortization expense was $141.8 million for the second
quarter of 2003, which represents an $8.3 million increase compared to the
second quarter of 2002. This increase in depreciation and amortization
expense results from $33.5 million in clean air amortization expensed
during the second quarter of 2003 and a $7.0 million increase related to
additional plant in service. These increases are partially offset by a
$16.7 million reduction in accelerated nuclear amortization and the $13.6
million decrease in depreciation expense related to the ongoing effects of
SFAS No. 143 in the North Carolina retail jurisdiction, as previously
discussed under "REGULATED ELECTRIC SEGMENTS." The clean air legislation
allows flexibility in the recognition of the clean air amortization, with a
maximum of $174 million per year. The Company currently plans to amortize
approximately $100 million of clean air costs in 2003. An NCUC order
allowed the reduction in the accelerated nuclear amortization and extended
the recovery time.
Other income and expense was $6.9 million of expense for the second quarter
of 2003 compared to $8.6 million of income during the second quarter of
2002. The primary driver of the unfavorability was $9.4 million of losses
on limited partnership investment funds recorded during the second quarter
of 2003.
Interest expense was $47.7 million for the second quarter of 2003, which
represents a $5.8 million decrease compared to the same period in 2002.
This decrease was due to both a decrease in average outstanding debt and a
slightly lower interest rate.
Income tax expense was $40.0 million for the second quarter of 2003 as
compared to $32.7 million for the second quarter of 2002. This variance is
due to a $22.8 million lower tax benefit reallocation in the second quarter
of 2003 compared to the same period in 2002, partially offset by the tax
impact of changes in pre-tax income.
First Half of 2003 Compared to First Half of 2002
Favorable wholesale revenues are the primary driver of the revenue increase
for the first half of 2003 compared to 2002. This favorability is
attributable to weather-related sales of energy to the Northeastern United
States markets during the first half of 2003. For its retail customers,
mild weather in North and South Carolina during the second quarter of 2003
more than offset the favorable impact of cold weather experienced in the
first quarter of 2003. Retail customer growth has increased during the
first half of 2003 when compared to 2002, with residential and commercial
customer growth of two percent.
Operation and maintenance costs increased $12.9 million compared to
operation and maintenance costs of $387.3 million for the first half of
2002, primarily due to $10.4 million of storm costs in the first quarter of
2003 and $16.7 million of costs associated with a planned nuclear outage in
the second quarter of 2003. These costs were partially offset by a decrease
in operation and maintenance expense of $15.9 million related to the
previously discussed reallocation of prior years' Service Company costs, as
required by the SEC.
Depreciation and amortization expense increased $5.8 million compared to
depreciation and amortization expense of $278.4 million for the first half
of 2002. This increase results from $53.5 million of clean air amortization
in 2003 and $10.4 million of depreciation on additional assets placed into
service. These increases are partially offset by a $41.6 million reduction
in accelerated nuclear amortization and the $13.6 million decrease in
depreciation related to the ongoing effects of SFAS No. 143 in the North
Carolina retail jurisdiction, all of which are discussed previously.
Other income and expense was $7.5 million of expense for the first half of
2003 compared to $6.9 million of income during the first half of 2002. The
primary driver of the unfavorability was $9.4 million of losses on limited
partnership investment funds recorded during the second quarter of 2003.
Interest expense was $96.1 million for the first half of 2003, which
represents a decrease of $15.9 million. This decrease was due to both a
decrease in average outstanding debt and a slightly lower interest rate.
Income tax expense was $110.1 million for the first half of 2003 as
compared to $80.0 million for the first half of 2002. This variance is due
to the tax impact of changes in pre-tax income and a $17.3 million lower
tax benefit reallocation in the first half of 2003 compared to the same
period in 2002.
44
PROGRESS ENERGY FLORIDA
PEF contributed earnings for common stock of $61.4 million and $76.8
million in the second quarter of 2003 and 2002, respectively, and $132.1
million and $134.5 million in the first half of 2003 and 2002,
respectively. These decreases are primarily attributed to impacts of the
2002 rate case and are partially offset by favorable retail customer growth
and usage and the impact of the tax benefit reallocation, previously
discussed.
In March 2002, PEF settled a rate case which provided for a one-time
retroactive rate refund, decreased future retail rates by 9.25% (effective
May 1, 2002), provided for lower depreciation and amortization, provided
for increases in certain service revenue rates and provided for revenue
sharing with the retail customers if certain revenue thresholds were met.
The impacts of the settlement agreement are included below.
PEF's electric revenues for the second quarter and first half of 2003 and
2002 and the amount and percentage change by quarter and by customer class
are as follows:
------------------------------------------------------------------------------------------------------------------
(in millions of $) Three Months Ended June 30, Six Months Ended June 30,
------------------------------------------------------------------------------------------------------------------
Customer Class 2003 Change % Change 2002 2003 Change % Change 2002
------------------------------------------------------------------------------------------------------------------
Residential $ 413.5 $ 17.9 4.5 $ 395.6 $ 798.5 $ 23.7 3.1 $ 774.8
Commercial 192.1 8.7 4.7 183.4 342.5 (7.7) (2.2) 350.2
Industrial 56.1 1.0 1.8 55.1 103.5 (1.6) (1.5) 105.1
Governmental 45.8 2.3 5.3 43.5 83.8 0.3 0.4 83.5
Retroactive rate refund - - - - - 35.0 100.0 (35.0)
Revenue sharing/rate
refund (28.1) (28.1) - - (28.1) (28.1) - -
---------------------- ------------------------------- ----------
Total retail revenues 679.4 1.8 0.3 677.6 1,300.2 21.6 1.7 1,278.6
Wholesale 49.8 (6.0) (10.8) 55.8 121.1 12.8 11.8 108.3
Unbilled 7.3 1.9 - 5.4 6.6 (5.2) - 11.8
Miscellaneous 30.0 2.9 10.7 27.1 67.1 13.4 25.0 53.7
---------------------- ------------------------------- ----------
Total electric revenues $ 766.5 $ 0.6 0.1 $ 765.9 $ 1,495.0 $ 42.6 2.9 $ 1,452.4
------------------------------------------------------------------------------------------------------------------
PEF's electric energy sales for the second quarter and first half of 2003
and 2002 and the amount and percentage change by quarter and by customer
class are as follows:
------------------------------------------------------------------------------------------------------------------
(in thousands of mWh) Three Months Ended June 30, Six Months Ended June 30,
------------------------------------------------------------------------------------------------------------------
Customer Class 2003 Change % Change 2002 2003 Change % Change 2002
------------------------------------------------------------------------------------------------------------------
Residential 4,703 188 4.2 4,515 9,256 681 7.9 8,575
Commercial 2,951 94 3.3 2,857 5,393 80 1.5 5,313
Industrial 1,008 14 1.4 994 1,924 48 2.6 1,876
Governmental 726 11 1.5 715 1,383 48 3.6 1,335
---------------------- ------------------------------- ----------
Total retail energy sales 9,388 307 3.4 9,081 17,956 857 5.0 17,099
sales
Wholesale 890 (86) (8.8) 976 2,166 210 10.7 1,956
Unbilled 498 55 - 443 553 79 - 474
---------------------- ------------------------------- ----------
Total mWh sales 10,776 276 2.6 10,500 20,675 1,146 5.9 19,529
------------------------------------------------------------------------------------------------------------------
Second Quarter of 2003 Compared to Second Quarter of 2002
Retail revenues, excluding fuel revenues of $286.3 million and $259.8
million for the second quarter of 2003 and 2002, respectively, decreased as
a result of the impact of the final resolution of the revenue sharing
provisions in the 2002 rate settlement agreement. Fuel revenues increased
compared to the prior year primarily due to increased generation. On July
9, 2003, the FPSC issued an order that required PEF to refund an additional
$18.4 million related to 2002 revenue sharing. In the second quarter of
2003, PEF also recorded an additional accrual of $9.5 million related to
estimated 2003 revenue sharing. This accrual will be reviewed and adjusted,
if necessary, on a quarterly basis. Revenues were further reduced due to
the impact of the 9.25% rate reduction that went into effect in May 2002,
as part of the settlement agreement.
45
These decreases were partially offset by additional retail revenues of
$11.4 million related to customer growth and usage.
Operation and maintenance costs increased $0.6 million, compared to the
$153.3 million incurred during the second quarter of 2002. A decrease in
the pension credit of $5.4 million, due to continued weak market
performance, is offset by lower spending by PEF's business units.
Income tax expense was $28.0 million for the second quarter of 2003,
compared to $45.6 million during the second quarter of 2002. Fluctuations
in income tax expense result from the tax benefit reallocation, discussed
previously, and changes in pre-tax income.
First Half of 2003 Compared to First Half of 2002
Retail revenues, excluding fuel revenues of $529.3 million and $498.1
million for the first half of 2003 and 2002, respectively, decreased due to
the impact of the 9.25% rate reduction, 2002 revenue sharing resolution,
and the 2003 revenue sharing accrual, all of which are discussed
previously. Partially offsetting these items was the absence of the impact
of the $35.0 million rate refund that was recognized in 2002 as part of the
settlement agreement.
Strong customer growth and usage and favorable weather positively impacted
revenues in 2003. The average number of customers during the first half of
the year increased by approximately 34,000 or 2.3% in 2003 as compared to
the same period in 2002.
Operation and maintenance costs increased $8.1 million, compared to the
$286.6 million incurred during the first half of 2002. The higher operation
and maintenance costs were primarily due to a $10.7 million decrease in the
pension credit.
Income tax expense was $64.9 million for the first half of 2003, compared
to $79.0 million during the first half of 2002. Fluctuations in income tax
expense result from the tax benefit reallocation, discussed previously, and
changes in pre-tax income.
DIVERSIFIED BUSINESSES
The Company's diversified businesses consist primarily of the Fuels
segment, the CCO segment, the Rail segment, Progress Telecom and SRS. These
businesses are explained in more detail below.
Fuels
The Fuels segment's operations include synthetic fuel operations, natural
gas exploration and production, coal extraction and terminals operations.
Fuels' results for the second quarter and first half of 2003 were impacted
most significantly by the timing of synthetic fuel production and the
increase in gas production.
The following summarizes the net income of the Fuels segment for the second
quarter and first half of 2003 and 2002.
-------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
-------------------------------------------------------------------------------------------------------
(in millions) 2003 2002 2003 2002
-------------------------------------------------------------------------------------------------------
Synthetic fuel operations $ 41.7 $ 44.3 $ 67.2 $ 83.1
Gas production and coal fuel operations 11.1 1.1 16.3 1.6
Other earnings (losses) 1.0 1.3 (3.1) 3.6
-------------------------------------------------------------
Income from continuing operations $ 53.8 $ 46.7 $ 80.4 $ 88.3
-------------------------------------------------------------------------------------------------------
Synthetic Fuel Operations
The synthetic fuels operations generated net income of $41.7 million and
$44.3 million in the second quarter of 2003 and 2002, respectively, and
$67.2 million and $83.1 million in the first half of 2003 and 2002,
respectively. The production and sale of synthetic fuel generate operating
losses, but qualify for tax credits under Section 29 of the Code, which
more than offset the effect of such losses. In late June 2003, the IRS
announced that field auditors have raised questions associated with
synthetic fuel manufactured at the Colona facility regarding the scientific
validity of test procedures and results used to verify a significant
chemical change, which is a requirement of the synthetic fuel program. The
impact of this review on the Company's synthetic fuel tax credits
previously taken or expected to be taken in the future cannot be predicted
at this time. See the "OTHER MATTERS" section for a further discussion of
the IRS review. The following summarizes the synthetic fuel operations for
the second quarter and first half of 2003 and 2002.
46
-------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
-------------------------------------------------------------------------------------------------------
(in millions) 2003 2002 2003 2002
-------------------------------------------------------------------------------------------------------
Tons produced 2.9 3.4 4.9 6.4
-------------------------------------------------------
Operating losses, excluding tax credits $ (36.4) $ (46.9) $ (63.5) $ (92.0)
Tax credits generated 78.1 91.2 130.7 175.1
-------------------------------------------------------
Income from continuing operations $ 41.7 $ 44.3 $ 67.2 $ 83.1
-------------------------------------------------------------------------------------------------------
Total 2003 synthetic fuel sales as compared to 2002 decreased $2.6 million
and $9.4 million for the second quarter and first half, respectively,
primarily due to a change in the synthetic fuel production pattern for
2003. The Company anticipates total synthetic fuel production of
approximately 12 million tons for 2003, which is comparable to 2002
production levels.
Gas Production and Coal Fuel Operations
Gas operations generated net income of $9.8 million and $0.9 million in the
second quarter of 2003 and 2002, respectively, and of $14.7 million and
$1.2 million in the first half of 2003 and 2002, respectively. The increase
in production resulting from the acquisitions of Westchester Gas in 2002
and North Texas Gas in the first quarter of 2003 drove increased revenue
and earnings. Although the Mesa operations continue to produce gas, no
additional wells are being drilled at Mesa as various divestiture options
are being explored. The following summarizes the gas revenues for the
second quarter and first half of 2003 and 2002 by production facility.
---------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
-------------------------------------------------------------------------------------------------------
(in millions) 2003 2002 2003 2002
-------------------------------------------------------------------------------------------------------
Mesa $ 4.0 $ 3.5 $ 8.7 $ 6.6
Westchester Gas 13.4 1.6 28.6 1.6
North Texas Gas 10.4 - 10.4 -
Other 2.7 0.8 2.6 0.8
-------------------------------------------------------------
Total gas sales $ 30.5 $ 5.9 $ 50.3 $ 9.0
-------------------------------------------------------------------------------------------------------
Coal fuel operations and other operations within the Fuels segment have
immaterial impacts on comparative earnings.
COMPETITIVE COMMERCIAL OPERATIONS
CCO generates and sells electricity to the wholesale market through
nonregulated plants. These operations also include limited financial
trading activities. The following summarizes the net income, sales and
generating capacity of the nonregulated plants for the second quarter and
first half of 2003 and 2002.
--------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
--------------------------------------------------------------------------------------------------
(in millions except megawatts) 2003 2002 2003 2002
--------------------------------------------------------------------------------------------------
Operating revenue $ 33.3 $ 23.9 $ 70.8 $ 32.9
Income from continuing operations $ 2.4 $ 6.7 $ 10.9 $ 4.6
Generation capacity (MW) - June 30 2,620 1,239 2,620 1,239
--------------------------------------------------------------------------------------------------
The second quarter increase in revenue is primarily due to increased
contracted capacity and energy sales from additional plants with tolling
agreements. The increase during the first half of 2003 in revenue and
earnings is also related to a tolling agreement termination payment from
Dynegy. The revenue increases related to higher volumes were partially
offset by lower prices in the wholesale energy market, higher depreciation
cost of $2.4 million related to the additional facilities and by increases
in costs allocated from the Service Company of $2.1 million in accordance
with the SEC audit.
In the second quarter of 2003, PVI acquired from Williams Energy Marketing
and Trading a full-requirements power supply agreement with Jackson
Electric Membership Corp. (Jackson) in Georgia for $188 million.
During 2002, the Company completed the acquisition of two electric
generation projects, Walton County Power, LLC and Washington County Power,
LLC. The acquisition resulted in goodwill of $64.1 million. The Company
performed the annual goodwill impairment test in the first quarter of 2003
which indicated no impairment. However, modest changes in either
assumptions or market conditions could cause some or all of the $64 million
of goodwill related to the CCO operating segment to become impaired.
47
The 466-megawatt Rowan combined cycle unit and the 600-megawatt Washington
combustion turbine facilities were completed and placed into service in
June 2003. The Washington plant has a tolling agreement with LG&E Power
Trading & Marketing through December 31, 2004. The 480-megawatt Effingham
combined cycle facility is expected to be placed into service in August
2003 and will complete CCO's nonregulated build-out with a total capacity
of 3,100 megawatts.
Including the Jackson contract and the impact of the Dynegy contract
termination, mentioned previously, the Company has contracts for 68%, 74%
and 50% of planned production capacity for 2003 through 2005, respectively.
The 2005 decline results from the expiration of four contracts. The Company
continues to pursue opportunities with both current customers and other
potential customers.
Rail
Rail's operations include railcar and locomotive repair, trackwork, rail
parts reconditioning and sales, scrap metal recycling, railcar leasing and
other rail related services. The Company intends to sell the assets of
Railcar Ltd., a leasing subsidiary, in 2003 and has classified these assets
as assets held for sale at June 30, 2003.
Progress Rail contributed net income of $2.2 million and $2.9 million for
the second quarter of 2003 and 2002, respectively, and a net loss of $1.2
million and net income of $2.2 million for the first half of 2003 and 2002,
respectively. As a result of the SEC order, Rail incurred additional
Service Company allocations of $1.2 and $6.9 million in the first quarter
and first half of 2003, respectively. These increased costs were partially
offset by improvements in the recycling business and reduced operating
costs.
An SEC order approving the merger of FPC requires the Company to divest
Rail by November 30, 2003. The Company is pursuing alternatives, but does
not expect to find the right divestiture opportunity by that date.
Therefore, the Company has sought a three year extension from the SEC.
Other Businesses Segment
Progress Energy's Other segment primarily includes the operations of SRS,
Progress Telecom and small nonregulated subsidiaries of PEC. Holding
company operations and other corporate functions that have previously been
included in the Other segment have been removed and are being reported
separately. The segment contributed income from continuing operations of
$1.2 million and a loss from continuing operations of $8.4 million in the
second quarter of 2003 and 2002, respectively, and income from continuing
operations of $1.9 million and a loss of $13.2 million in the first half of
2003 and 2002, respectively.
The improvement in both the quarter and the half is related to Progress
Telecom's lower depreciation charges resulting from the impairment of a
significant portion of its assets in the third quarter of 2002.
Additionally, SRS recognized a loss in the second quarter of 2002 related
to the sale of certain portions of its operations.
CORPORATE SERVICES
Corporate Services includes the operations of the Holding Company, the
Service Company, and consolidation entities, as summarized below (expenses
are indicated by positive numbers).
-------------------------------------------------------------------------------------------------------
Three Months Ended June 30, Six Months Ended June 30,
-------------------------------------------------------------------------------------------------------
(in millions) 2003 2002 2003 2002
-------------------------------------------------------------------------------------------------------
Interest expense $ 73.3 $ 75.7 $ 144.3 $ 146.7
Contingent value obligations 1.7 (1.5) - (12.8)
Tax reallocation 9.3 30.0 18.6 30.0
Tax levelization 4.8 58.4 (5.4) 79.6
Other income taxes (31.3) (31.5) (62.4) (63.4)
Other expenses 1.2 3.5 5.1 7.6
-----------------------------------------------------------
Loss from continuing operations $ 59.0 $ 134.6 $ 100.2 $ 187.7
-------------------------------------------------------------------------------------------------------
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, 2003 and
2002, the CVOs had fair market values of approximately $13.8 million and
$29.1 million, respectively. Progress Energy recorded an unrealized loss of
$1.7 million and unrealized gain of $1.5 million for the second quarter of
48
2003 and 2002, respectively, to record the changes in fair value of the
CVOs, which had average unit prices of $0.14 and $0.30 at June 30, 2003 and
2002, respectively. The CVO values at June 30, 2003 were unchanged from the
January 1, 2003 values, thus requiring no recognition of an unrealized gain
or loss in the first half. A $12.8 million unrealized gain was recorded for
the first half of 2002.
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 $4.8 million and $58.4 million for the
second quarter of 2003 and 2002, respectively, in order to maintain an
effective tax rate consistent with the estimated annual rate. Income tax
expense was decreased by $5.4 million and increased $79.6 million for the
first half of 2003 and 2002, respectively. The tax credits associated with
the Company's synthetic fuel operations primarily drive the required
levelization amount. Fluctuations in estimated annual earnings and tax
credits can also cause large swings in the effective tax rate for interim
periods. Therefore, this adjustment will vary each quarter, but will have
no effect on net income for the year.
DISCONTINUED OPERATIONS
In the fourth quarter of 2002, the Company's Board of Directors approved
the sale of NCNG to Piedmont Natural Gas Company, Inc. As a result of this
action, the operating results of NCNG were reclassified to discontinued
operations for all reportable periods. Progress Energy expects the sale to
close during the third quarter of 2003 for net proceeds of approximately
$400 million. An estimated loss on the sale of NCNG of $29.4 million was
recognized in the fourth quarter of 2002.
LIQUIDITY AND CAPITAL RESOURCES
Progress Energy, Inc.
Statement of Cash Flows and Financing Activities
Cash provided by operating activities increased $114.9 million for the six
months ended June 30, 2003, when compared to the corresponding period in
the prior year. The increase in cash from operating activities for the 2003
period is due to improved operating cash flow at PVI and Progress Fuels,
which offset lower cash from operations at the utility operations.
Net cash used in investing activities decreased $137.9 million for the six
months ended June 30, 2003, when compared to the corresponding period in
the prior year. The decrease in cash used in investing activities is
primarily due to lower capital spending at PVI, which acquired generating
assets from LG&E in February 2002 for approximately $350 million.
During the first six months of 2003, $366.5 million was spent in
diversified business property additions. This amount includes the
acquisition of the natural gas reserves in February 2003 for $148 million.
In addition to the $366.5 million spent on diversified business property
additions, PVI also purchased a wholesale energy supply contract for
approximately $190 million.
The increase in operating cash flow and lower capital expenditures resulted
in an increase of $253 million of net cash flow before common dividend
payments and other financing activity for the six month period ending June
30, 2003 compared with the corresponding period for the prior year.
On February 21, 2003, PEF issued $425 million of First Mortgage Bonds,
4.80% Series, Due March 1, 2013 and $225 million of First Mortgage Bonds,
5.90% Series, Due March 1, 2033. Proceeds from this issuance were used to
repay the balance of its outstanding commercial paper, to refinance its
secured and unsecured indebtedness, including PEF's First Mortgage Bonds
6.125% Series Due March 1, 2003, which were retired on March 1, 2003, and
to redeem on March 24, 2003, the $150 million aggregate outstanding balance
of its 8% First Mortgage Bonds due 2022 at 103.75% of the principal amount
of such bonds.
On April 1, 2003, PEF entered into a new $200 million 364-day credit
agreement and a new $200 million three-year credit agreement, replacing its
prior credit facilities (which had been a $90 million 364-day facility and
a $200 million five-year facility). The new PEF credit facilities contain a
defined maximum total debt to total capital ratio of 65%; as of June 30,
2003 the calculated ratio was 52.6%. The new credit facilities also contain
a requirement that the ratio of EDITDA, as defined in the facilities, to
interest expense to be at least 3 to 1; as of June 30, 2003 the calculated
ratio was 8.7 to 1.
Also on April 1, 2003, PEC reduced the size of its existing 364-day credit
facility from $285 million to $165 million. The other terms of this
facility were not changed. On July 30, 2003, PEC renewed its $165 million
49
364-day credit agreement PEC's $285 million three-year credit agreement
entered into in July 2002 remains in place, for total facilities of $450
million.
On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5%
Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds.
PEC funded the redemption with commercial paper.
In March 2003, Progress Genco Ventures, LLC (Genco), a wholly owned
subsidiary of PVI, terminated its $50 million working capital credit
facility. A related construction facility initially provided for Genco to
draw up to $260 million. The amount outstanding under this facility is $241
million as of June 30, 2003. During the second quarter of 2003 Genco
determined it did not need to make any additional draws under this
facility. As a result of this decision, the drawn amount of $241 million
will not increase.
On July 14, 2003, PEC announced the redemption of $100 million of First
Mortgage Bonds, 6.875% Series Due August 15, 2023 at 102.84%. The date of
the redemption will be August 15, 2003. PEC will fund the redemption with
commercial paper.
For the three months ended June 30, 2003, the Company issued approximately
2.4 million shares representing approximately $98 million in proceeds from
its Investor Plus Stock Purchase Plan and its employee benefit plans during
the second quarter ended June 30, 2003. For the six months ended June 30,
2003, the Company has issued 4.2 million shares through these plans,
resulting in $172 million of cash proceeds.
Future Commitments
The current portion of long-term debt of $1.1 billion includes $500 million
of Progress Energy's 6.55% senior unsecured notes due March 1, 2004. The
Company expects to have sufficient commercial paper capacity to retire this
issue due to the proceeds from the sale of North Carolina Natural Gas
(NCNG) in the summer of 2003. The proceeds from the sale of NCNG are
expected to be approximately $400 million and will be used to reduce
commercial paper. The current portion of long-term debt also includes $400
million of secured debt issued by PEC. These amounts are expected to be
refinanced or retired through commercial paper, capital market transactions
and with internal generation of funds.
As of June 30, 2003, Progress Energy's guarantees were approximately $1
billion, up from approximately $785 million as of March 31, 2003. The
increase is due primarily to a $285 million performance guarantee
associated with the purchase of a wholesale power supply contract, as
discussed previously.
OTHER MATTERS
PEF Rate Case Settlement
On March 27, 2002, the parties in PEF's rate case entered into a
Stipulation and Settlement Agreement (the Agreement) related to retail rate
matters. The Agreement was approved by the FPSC on April 23, 2002. The
Agreement provides that PEF will operate under a Revenue Sharing Incentive
Plan (the Plan) through 2005 and thereafter until terminated by the FPSC.
The Plan provides that all retail base revenues between the established
threshold and cap will be shared on a 2/3 - 1/3, customer/shareholder
basis. All retail base rate revenues above the retail base rate revenue
caps established for each year will be refunded 100% to retail customers on
an annual basis. For 2002, the refund to customers was limited to 67.1% of
the retail base rate revenues that exceeded the 2002 cap. The retail base
revenue cap for 2003 is $1.393 billion and will increase $37 million each
year thereafter. As of December 31, 2002, $4.7 million was accrued and was
refunded to customers in March 2003. On February 24, 2003, the parties to
the Agreement filed a motion seeking an order from the FPSC to enforce the
Agreement. In this motion, the parties disputed PEF's calculation of retail
revenue subject to refund and contended that the refund should have been
approximately $23 million. On July 9, 2003, the FPSC ruled that PEF must
provide an additional $18.4 million to its retail customers related to the
2002 revenue sharing calculation. PEF recorded this refund in the second
quarter 2003 as a charge against electric operating revenue and will refund
this amount by no later than October 31, 2003. In the second quarter of
2003, PEF also recorded an additional accrual of $9.5 million related to
estimated 2003 revenue sharing.
50
Synthetic Fuels Tax Credits
Progress Energy, through its subsidiaries, produces synthetic fuel from
coal fines. The production and sale of the synthetic fuel from these
facilities qualifies for tax credits under Section 29 of the Code (Section
29) if certain requirements are satisfied, including a requirement that the
synthetic fuel differs significantly in chemical composition from the coal
used to produce such synthetic fuel. Any synthetic fuel tax credit amounts
not utilized are carried forward indefinitely. All of Progress Energy's
synthetic fuel facilities have received private letter rulings (PLRs) from
the Internal Revenue Service (IRS) with respect to their synthetic fuel
operations. These tax credits are subject to review by the IRS, and if
Progress Energy fails to prevail through the administrative or legal
process, there could be a significant tax liability owed for previously
taken Section 29 credits, with a significant impact on earnings and cash
flows. Additionally, the ability to use tax credits currently being carried
forward could be denied. Total Section 29 credits generated to date
(including FPC prior to its acquisition by the Company) are approximately
$1.028 billion, of which $445.6 million have been used and $582.4 million
are being carried forward as of June 30, 2003.
One synthetic fuel entity, Colona Synfuel Limited Partnership, L.L.L.P.
(Colona), from which the Company (and FPC prior to its acquisition by the
Company) has been allocated approximately $273.1 million in tax credits to
date, is being audited by the IRS. The audit of Colona was expected. The
Company is audited regularly in the normal course of business, as are most
similarly situated companies.
In September 2002, all of the Company's majority-owned synthetic fuel
entities, including Colona, were accepted into the IRS Prefiling Agreement
(PFA) program. The PFA program allows taxpayers to voluntarily accelerate
the IRS exam process in order to seek resolution of specific issues. Either
the Company or the IRS can withdraw from the program, and issues not
resolved through the program may proceed to the next level of the IRS exam
process.
In late June 2003, the Company was informed that IRS field auditors have
raised questions regarding the chemical change associated with coal-based
synthetic fuel manufactured at its Colona facility and the testing process
by which the chemical change is verified. (The questions arose in
connection with the Company's participation in the PFA program.) The
chemical change and the associated testing process were described as part
of the PLR request for Colona. Based upon that application, the IRS ruled
in Colona's PLR that the synthetic fuel produced at Colona undergoes a
significant chemical change and thus qualifies for tax credits under
Section 29 of the Internal Revenue Code. While the IRS has announced that
they may revoke PLRs if test procedures and results do not demonstrate that
a significant chemical change has occurred, based on the information
received to date, the Company does not believe the issues warrant reversal
by the IRS National Office of its prior position in the Colona PLR.
The information provided by the IRS field auditors addresses only Progress
Energy's Colona facility. The Company, however, applies essentially the
same chemical process and uses the same independent laboratories to confirm
chemical change in the synthetic fuel manufactured at each of its four
other facilities. The independent laboratories used by the Company to
determine significant chemical change are the leading experts in their
field and are used by many other industry participants. The Company
believes that the laboratories' work and the chemical change process are
consistent with the bases upon which its PLRs were issued.
The Company is working to resolve this matter as quickly as possible. At
this time, the Company cannot predict how long the IRS process will take;
however, the Company intends to continue working cooperatively with the
IRS. The Company firmly believes that it is operating the Colona facility
and its other plants in compliance with its PLRs and Section 29 of the
Internal Revenue Code. Accordingly, the Company has no current plans to
alter its synthetic fuel production schedules as a result of these matters.
In addition, the Company has retained an advisor to assist in selling an
interest in one or more synthetic fuel entities. The Company is pursuing
the sale of a portion of its synthetic fuel production capacity that is
underutilized due to limits on the amount of credits that can be generated
and utilized by the Company. The Company would expect to retain an
ownership interest and to operate any sold facility for a management fee.
However, the IRS has suspended issuance of PLRs relating to synthetic fuel
production (typically a closing condition to the sale of an interest in a
synthetic fuel entity). Unless that suspension on new PLRs is lifted, it
will be difficult to consummate the successful sale of interests in the
Company's synthetic fuel facilities. The Company cannot predict when or if
the IRS will recommence issuing such PLRs. The final outcome and timing of
the Company's efforts to sell interests in synthetic fuel facilities is
uncertain and while the Company cannot predict the outcome of this matter,
the outcome is not expected to have a material effect on the consolidated
financial position, cash flows or results of operations.
51
Nuclear Matters
The Shearon Harris Nuclear Plant in New Hill, North Carolina completed a
successful refueling outage on May 18, 2003, when the unit was returned to
service.
On August 9, 2002, the NRC issued an additional bulletin dealing with head
leakage due to cracks near the control rod nozzles. The NRC has asked
licensees to commit to high inspection standards to ensure the more
susceptible plants have no cracks. The Robinson Plant is in this category
and had a refueling outage in October 2002. The Company completed a series
of examinations in October 2002 of the entire reactor pressure vessel head
and found no indications of control rod drive mechanism penetration leakage
and no corrosion of the head itself. During the outage, a boric acid
leakage walkdown of the reactor coolant pressure boundary was also
completed and no corrosion was found.
The Company currently plans to re-inspect the Robinson Plant reactor head
during its next refueling outage in the spring of 2004 and replace the head
in the fall of 2005. The Harris Plant is ranked in the lowest
susceptibility classification. During the Harris Plant's Spring 2003
outage, the Company completed a series of examinations of the entire
reactor pressure vessel head and found no degradation or indication of
leakage.
In October 2001 at the Crystal River Plant (CR3), one nozzle was found to
have a crack and was repaired; however, no degradation of the reactor
vessel head was identified. Current plans are to replace the vessel head at
CR3 during its next regularly scheduled refueling outage in the fall of
2003.
In February 2003, the NRC issued Order EA-03-009, requiring specific
inspections of the reactor pressure vessel head and associated penetration
nozzles at pressurized water reactors (PWRs). The Company has responded to
the Order, stating that the Company intends to comply with the provisions
of the Order. No adverse impact is anticipated.
In April 2003, the STP Nuclear Operating Company, an unaffiliated entity,
notified the NRC of a potential leak indication on the bottom head of the
reactor vessel of one of its units. The Company is continuing to monitor
this development for applicability to our plants and will take appropriate
action if and when necessary.
In January 2003, the NRC issued a final order with regard to access
control. This order requires the Company to enhance its current access
control program by January 7, 2004. The Company expects that it will be in
full compliance with the order by the established deadline.
The NRC continues to issue additional orders designed to increase security
at nuclear facilities. In April 2003, one of the orders issued by the NRC
imposes revisions to the Design Basis Threat and requires power plants to
implement additional protective actions to protect against sabotage by
terrorists and other adversaries. The Company expects that it will be in
full compliance with the order by the established deadline. As the NRC,
other governmental entities and the industry continue to consider security
issues, it is possible that more extensive security plans could be
required.
Franchise Litigation
Six cities, with a total of approximately 49,000 customers, have sued PEF
in various circuit courts in Florida. As discussed below, two of the six
cities, with a total of approximately 21,000 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. To date, no city has
attempted to actually exercise the option to purchase any portion of PEF's
electric distribution system. Arbitration in one of the cases (the City of
Casselberry) was held in August 2002 and an award was issued in October
2002 setting the value of PEF's distribution system within that city at
approximately $22 million. On April 2, 2003, PEF filed a rate filing with
the FERC to recover $10.6 million in stranded costs from the City of
Casselberry in the event the City ultimately chooses and is allowed to form
a municipal electric utility. PEF's rate filing has been abated pending
settlement discussions between the parties. On July 28, 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 City of Winter Park) was completed in February 2003.
That arbitration panel issued an award on May 29, 2003 setting the value of
PEF's distribution system within the City of Winter Park at approximately
$31.5 million, not including separation and reintegration and construction
52
work in progress, which could add several million dollars to the award. The
panel also awarded PEF approximately $10.7 million in stranded costs. The
City of Winter Park has scheduled a September 9, 2003 referendum where
citizens will decide whether to issue bonds of up to approximately $50
million to acquire PEF's electric distribution system. At this time,
whether and when there will be further proceedings regarding the City of
Winter Park cannot be determined. A third arbitration (with the Town of
Belleair) was completed on June 16, 2003. A decision from the arbitration
panel has not yet been issued in that case. A fourth arbitration (with the
City of Apopka) has been scheduled for January 2004. On August 4, 2003, the
City of Longwood approved a 30-year franchise and a settlement agreement
with PEF, which will resolve all pending litigation with the City of
Longwood. Arbitration in the remaining city's litigation (the 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 has set oral argument for August 27, 2003. The Company cannot
predict the outcome of these matters at this time.
Progress Energy Carolinas, Inc.
The information required by this item is incorporated herein by reference
to the following portions of Progress Energy's Management's Discussion and
Analysis of Financial Condition and Results of Operations, insofar as they
relate to PEC: RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES and
OTHER MATTERS.
RESULTS OF OPERATIONS
The results of operations for the PEC Electric segment are identical
between PEC and Progress Energy. The results of operations for PEC's
non-utility subsidiaries for the six months ended June 30, 2003 and 2002
are not material to PEC's consolidated financial statements.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities increased $61 million for the six
months ended June 30, 2003, when compared to the corresponding period in
the prior year. The increase was caused primarily by changes in working
capital.
Cash used in investing activities increased approximately $150 million for
the six months ended June 30, 2003, when compared to the corresponding
period in the prior year. The increase was mostly due to $244 million in
cash proceeds received during the second quarter of 2002 for the sale of
generating assets to Progress Ventures during the first quarter of 2002.
The sales proceeds were offset by a decrease in construction spending.
During the first six months of 2003, $322 million was spent on PEC's
construction program, nuclear fuel additions and contributions to its
nuclear decommissioning fund. This amount was approximately $80 million
less than the corresponding period last year. The decrease was due to lower
construction expenditures associated with generation assets transferred to
PVI during 2002.
As of June 30, 2003, PEC's liquidity, contractual cash obligations and
other commercial commitments have not changed materially from what was
reported in the 2002 Annual Report on Form 10-K, as amended.
On April 1, 2003, PEC reduced the size of its existing 364-day credit
facility from $285 million to $165 million. The other terms of this
facility were not changed. On July 30, 2003, PEC renewed its $165 million
364-day credit agreement PEC's $285 million three-year credit agreement
entered into in July 2002 remains in place, for total facilities of $450
million.
On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5%
Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds.
PEC funded the redemption with commercial paper.
On July 14, 2003, PEC announced the redemption of $100 million of First
Mortgage Bonds, 6.875% Series Due August 15, 2023 at 102.84%. The date of
the redemption will be August 15, 2003 and the redemption will be funded by
PEC with commercial paper.
The current portion of long-term debt includes $400 million of secured debt
issued by PEC. The current portion of long-term debt is expected to be
refinanced or retired through commercial paper, capital market transactions
and internal generation of funds.
54
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Progress Energy, Inc.
Market risk represents the potential loss arising from adverse changes in
market rates and prices. Certain market risks are inherent in the Company's
financial instruments, which arise from transactions entered into in the
normal course of business. The Company's primary exposures are changes in
interest rates with respect to its long-term debt and commercial paper, and
fluctuations in the return on marketable securities with respect to its
nuclear decommissioning trust funds. The Company manages its market risk in
accordance with its established risk management policies, which may include
entering into various derivative transactions.
The Company's exposure to return on marketable securities for the
decommissioning trust funds has not changed materially since December 31,
2002. The Company's exposure to market value risk with respect to the CVOs
has also not changed materially since December 31, 2002.
On February 21, 2003, PEF issued $425 million of First Mortgage Bonds,
4.80% Series, Due March 1, 2013 and $225 million of First Mortgage Bonds,
5.90% Series, Due March 1, 2033. Proceeds from this issuance were used to
repay the balance of its outstanding commercial paper, to refinance its
secured and unsecured indebtedness, including PEF's First Mortgage Bonds
6.125% Series Due March 1, 2003, and to redeem the aggregate outstanding
balance of its 8% First Mortgage Bonds Due 2022.
In March, April and June of 2003, PEC entered into treasury rate locks to
hedge its exposure to interest rates with regard to a future issuance of
debt. These agreements have a computational period of ten years and are
designated as cash flow hedges for accounting purposes. The agreements have
a total notional amount of $60 million.
Effective March 24, 2003, PEF redeemed $150 million of First Mortgage
Bonds, 8% Series, Due December 1, 2022 at 103.75% of the principle amount
of such bonds.
The exposure to changes in interest rates from the Company's fixed rate and
variable rate long-term debt at June 30, 2003 has changed from December 31,
2002. The total fixed rate long-term debt at June 30, 2003 was $9.27
billion, with an average interest rate of 6.70% and fair market value of
$10.68 billion. The total variable rate long-term debt at June 30, 2003,
was $1.10 billion, with an average interest rate of 1.41% and fair market
value of $1.11 billion.
The exposure to changes in interest rates from the Company's commercial
paper and FPC mandatorily redeemable securities of trust at June 30, 2003,
was not materially different than at December 31, 2002.
Progress Energy Carolinas, Inc.
PEC has certain market risks inherent in its financial instruments, which
arise from transactions entered into in the normal course of business.
PEC's primary exposures are changes in interest rates with respect to
long-term debt and commercial paper, and fluctuations in the return on
marketable securities with respect to its nuclear decommissioning trust
funds. PEC's exposure to return on marketable securities for the
decommission trust funds has not changed materially since December 31,
2002.
In March, April and June of 2003, PEC entered into treasury rate locks to
hedge its exposure to interest rates with regard to a future issuance of
debt. These agreements have a computational period of ten years and are
designated as cash flow hedges for accounting purposes.
The exposure to changes in interest rates from the PEC's fixed rate
long-term debt, variable rate long-term debt and commercial paper at June
30, 2003 was not materially different than at December 31, 2002.
54
Item 4. Controls and Procedures
Progress Energy, Inc.
Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934,
Progress Energy carried out an evaluation, with the participation of
Progress Energy's management, including Progress Energy's Chairman and
Chief Executive Officer, and Chief Financial Officer, of the effectiveness
of Progress Energy's disclosure controls and procedures (as defined under
Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of
the period covered by this report. Based upon that evaluation, Progress
Energy's Chairman and Chief Executive Officer, and Chief Financial Officer
concluded that Progress Energy's disclosure controls and procedures are
effective in timely alerting them to material information relating to
Progress Energy (including its consolidated subsidiaries) required to be
included in Progress Energy's periodic SEC filings. There has been no
change in Progress Energy's internal control over financial reporting
during the quarter ended June 30, 2003 that has materially affected, or is
reasonably likely to materially affect, Progress Energy's internal control
over financial reporting.
Progress Energy Carolinas, Inc.
Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, PEC
carried out an evaluation, with the participation of PEC's management,
including PEC's Chairman and Chief Executive Officer, and Chief Financial
Officer, of the effectiveness of PEC's disclosure controls and procedures
(as defined under Rule 13a-15(e) under the Securities Exchange Act of 1934)
as of the end of the period covered by this report. Based upon that
evaluation, PEC's Chairman and Chief Executive Officer, and Chief Financial
Officer concluded that PEC's disclosure controls and procedures are
effective in timely alerting them to material information relating to PEC
(including its consolidated subsidiaries) required to be included in PEC's
periodic SEC filings. There has been no change in PEC's internal control
over financial reporting during the quarter ended June 30, 2003 that has
materially affected, or is reasonably likely to materially affect, PEC's
internal control over financial reporting.
55
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Legal aspects of certain matters are set forth in Part I, Item 1. See Note 15 to
the Progress Energy, Inc. Consolidated Interim Financial Statements and Note 9
to the PEC's Consolidated Interim Financial Statements.
1. Strategic Resource Solutions Corp. ("SRS") v. San Francisco Unified School
District, et al., Sacramento Superior Court, Case No. 02AS033114
In November of 2001, SRS filed a claim against the San Francisco Unified School
District ("the District") and other defendants claiming that SRS is entitled to
approximately $10 million in unpaid contract payments and delay and impact
damages related to the District's $30 million contract with SRS. On March 4,
2002, the District filed a counterclaim, seeking compensatory damages and
liquidated damages in excess of $120 million, for various claims, including
breach of contract and demand on a performance bond. SRS has asserted defenses
to the District's claims.
On March 13, 2003, the City Attorney's office announced the filing of new claims
by the City Attorney and the District in the form of a cross-complaint against
SRS, Progress Energy, Inc., Progress Energy Solutions, Inc., and certain
individuals, alleging fraud, false claims, violations of California statutes,
and seeking compensatory damages, punitive damages, liquidated damages, treble
damages, penalties, attorneys' fees and injunctive relief. The City Attorney's
announcement states that the City and the District seek "more than $300 million
in damages and penalties."
The Company has reviewed the District's earlier pleadings against SRS and
believes that those claims are not meritorious. SRS filed its answer to the new
pleadings on April 14, 2003. The Company has reviewed the new pleadings and the
Company believes that the new claims are not meritorious. The Company has filed
responsive pleadings denying the allegations, and the discovery process is
underway. SRS, the Company and Progress Energy Solutions, Inc. will vigorously
defend and litigate all of these claims. The Company cannot predict the outcome
of this matter, but the Company believes that it and its subsidiaries have good
defenses to all claims asserted by both the District and the City.
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 14, 2003.
(b) The meeting involved the election of five Class II 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) Results of matters voted on were as follows:
Election of Directors
Class II Votes For Votes Withheld
(Term Expiring in 2006)
Edwin B. Borden 193,007,893 4,613,431
James E. Bostic, Jr. 192,204,838 5,416,487
David L. Burner 192,182,065 5,439,259
Richard L. Daugherty 192,186,613 5,434,712
Richard A. Nunis 193,138,277 4,483,047
56
Shareholder Proposals
The shareholder proposal requesting that the Board adopt a policy requiring that
all stock option grants to senior executives be performance-based was presented,
but was not approved by the shareholders.
The number of shares voted for the proposal was 32,819,916.
The number of shares voted against the proposal was 129,021,383.
The number of abstaining votes was 4,662,102.
The delivered not voted total was 31,157,923.
The shareholder proposal requesting that the Board establish a policy of
expensing stock options on its annual income statement was presented, but was
not approved by the shareholders.
The number of shares voted for the proposal was 72,431,261.
The number of shares voted against the proposal was 88,376,736
The number of abstaining votes was 5,655,400.
The delivered not voted total was 31,157,926.
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 14, 2003.
(b) The meeting involved the election of five Class II 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 II Votes For Votes Withheld
(Term Expiring in 2006)
Edwin B. Borden 159,941,669 1,470
James E. Bostic, Jr. 159,941,819 1,320
David L. Burner 159,941,802 1,339
Richard L. Daugherty 159,941,826 1,313
Richard A. Nunis 159,941,437 1,702
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit Progress Progress Energy
Number Description Energy, Inc. Carolinas, Inc.
------ ----------- ------------ ---------------
10(i) Amended and Restated Progress Energy, Inc. Restoration X X
Retirement Plan, effective as of July 10, 2002
10(ii) Progress Energy, Inc. Non-Employee Director Stock Unit X X
Plan, amended and restated effective July 10, 2002
10(iii) Amended and Restated Supplemental Senior Executive X X
Retirement Plan of Progress Energy, Inc., effective
January 1, 1984 (As last amended effective July 10, 2002)
10(iv) Amended Management Incentive Compensation Plan of X X
Progress Energy, Inc., as amended January 1, 2003
57
10(v) Amendment and Restatement, dated as of July 30, 2003, to X
the 364-Day Revolving Credit Agreement among Carolina
Power & Light Company (d/b/a Progress Energy Carolinas,
Inc.) and certain Lenders
31(a) Certifications pursuant to Section 302 of the X X
Sarbanes-Oxley Act of 2002 - Chairman 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 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 on Form 8-K since the beginning of the quarter:
Progress Energy, Inc.
Financial
Item Statements
Reported Included Date of Event Date Filed
5 No April 1, 2003 April 1, 2003
9, 12 Yes April 23, 2003 April 23, 2003
7, 9 No April 30, 2003 April 30, 2003
9 No May 30, 2003 May 30, 2003
7, 9 No May 30, 2003 June 11, 2003
5 No June 24, 2003 June 24, 2003
9, 12 Yes July 23, 2003 July 23, 2003
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
Financial
Item Statements
Reported Included Date of Event Date Filed
5 No April 1, 2003 April 1, 2003
9, 12 Yes April 23, 2003 April 23, 2003
9, 12 Yes July 23, 2003 July 23, 2003
58
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 11, 2003 (Registrants)
By: /s/ Peter M. Scott III
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Peter M. Scott III
Executive Vice President and
Chief Financial Officer
By: /s/ Robert H. Bazemore, Jr.
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Robert H. Bazemore, Jr.
Vice President and Controller
Chief Accounting Officer
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