SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of report (date of earliest event reported):
February 18, 2003
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
1-3382 56-0165465
Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone (919) 546-6111
State of Incorporation: North Carolina
The address of the registrant has not changed since the last report.
================================================================================
1
ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND EXHIBITS
The registrants file this combined Form 8-K Current Report for the purpose
of filing the exhibits listed below. Exhibit 99 is expected to be filed in
identical form with the registrant's combined Form 10-K Annual Report for the
year ended December 31, 2002.
(c) Exhibits.
23.1 Consent of Deloitte & Touche LLP
99 Carolina Power & Light Company financial statements:
Independent Auditors' Report - Deloitte & Touche LLP
Consolidated Statements of Income and Comprehensive Income for
the Years Ended December 31, 2002, 2001, and 2000
Consolidated Balance Sheets as of December 31, 2002 and 2001
Consolidated Statements of Cash Flows for the Years Ended December
31, 2002, 2001 and 2000
Consolidated Schedules of Capitalization as of December 31, 2002
and 2001
Consolidated Statements of Retained Earnings for the Years Ended
December 31, 2002, 2001, and 2000
Consolidated Quarterly Financial Data (Unaudited)
Notes to Consolidated Financial Statements
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
CAROLINA POWER & LIGHT COMPANY
Registrant
By: /s/ Robert H. Bazemore, Jr
Robert H. Bazemore, Jr.
Vice President and Controller
Date: February 18, 2003
2
INDEX TO EXHIBITS
Exhibit
Number Description of Exhibit
23.1 Consent of Deloitte & Touche LLP
99 Carolina Power & Light Company financial statements:
Independent Auditors' Report - Deloitte & Touche LLP
Consolidated Statements of Income and Comprehensive Income
for the Years Ended December 31, 2002, 2001, and 2000
Consolidated Balance Sheets as of December 31, 2002 and
2001
Consolidated Statements of Cash Flows for the Years
Ended December 31, 2002, 2001, and 2000
Consolidated Schedules of Capitalization as of December 31, 2002 and
2001
Consolidated Statements of Retained Earnings for the
Years Ended December 31, 2002, 2001, and 2000
Consolidated Quarterly Financial Data (Unaudited)
Notes to Consolidated Financial Statements
3
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT
We also consent to the incorporation by reference in Registration Statement
No. 333-58800 on Form S-3 of Carolina Power & Light Company of our report dated
February 12, 2003, appearing in this Form 8-K of Carolina Power & Light Company.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
February 18, 2003
4
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT COMPANY:
We have audited the accompanying consolidated balance sheets and schedules
of capitalization of Carolina Power & Light Company and its subsidiaries (CP&L)
as of December 31, 2002 and 2001, and the related consolidated statements of
income and comprehensive income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 2002. These financial
statements are the responsibility of CP&L's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of CP&L at December 31, 2002 and
2001, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 12, 2003
5
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of INCOME and COMPREHENSIVE INCOME
Years ended December 31
(In thousands) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 3,538,957 $ 3,343,720 $ 3,308,215
Natural gas - - 147,448
Diversified business 14,863 16,441 72,783
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,553,820 3,360,161 3,528,446
- ---------------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 761,379 647,263 627,463
Purchased power 347,420 353,551 325,366
Gas purchased for resale - - 103,734
Operation and maintenance 792,660 701,703 741,466
Depreciation and amortization 523,846 521,910 708,249
Taxes other than on income 157,568 149,719 148,037
Diversified business 115,733 9,985 135,258
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,698,606 2,384,131 2,789,573
- ---------------------------------------------------------------------------------------------------------------------
Operating Income 855,214 976,030 738,873
- ---------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 6,868 13,728 17,420
Gain on sale of investment - - 200,000
Impairment of investment (25,011) (156,712) -
Other, net 12,757 (4,155) 17,089
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) (5,386) (147,139) 234,509
- ---------------------------------------------------------------------------------------------------------------------
Interest Charges
Interest charges 217,010 257,141 240,620
Allowance for borrowed funds used during construction (5,474) (15,714) (18,537)
- ---------------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 211,536 241,427 222,083
- ---------------------------------------------------------------------------------------------------------------------
Income before Income Taxes 638,292 587,464 751,299
Income Tax Expense 207,360 223,233 290,271
- ---------------------------------------------------------------------------------------------------------------------
Net Income 430,932 364,231 461,028
Preferred Stock Dividend Requirement 2,964 2,964 2,966
- ---------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 427,968 $ 361,267 $ 458,062
- ---------------------------------------------------------------------------------------------------------------------
Comprehensive Income, Net of Tax:
Net Income $ 430,932 $ 364,231 $ 461,028
SFAS No. 133 transition adjustment (net of tax of $474) - (738) -
Change in net unrealized losses on cash flow hedges (net of
tax of $9,080 and $7,565, respectively) (14,144) (11,784) -
Reclassification adjustment for amounts included in net
income (net of tax of $7,583 and $3,515, respectively) 11,811 5,476 -
Minimum pension liability adjustment (net of tax of $47,317) (73,390) - -
- ---------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 355,209 $ 357,185 $ 461,028
- ---------------------------------------------------------------------------------------------------------------------
See Carolina Power & Light Company Notes to Consolidated Financial Statements.
6
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands) December 31
Assets 2002 2001
- --------------------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 12,675,761 $ 12,024,291
Accumulated depreciation (6,356,933) (5,952,206)
- --------------------------------------------------------------------------------------------------------------------
Utility plant in service, net 6,318,828 6,072,085
Held for future use 7,188 7,105
Construction work in progress 325,695 711,129
Nuclear fuel, net of amortization 176,622 200,332
- --------------------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 6,828,333 6,990,651
- --------------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 18,284 21,250
Accounts receivable 301,178 302,781
Unbilled accounts receivable 151,352 136,514
Receivables from affiliated companies 36,870 26,182
Notes receivable from affiliated companies 49,772 998
Taxes receivable 5,890 17,543
Inventory 342,886 372,725
Deferred fuel cost 146,015 131,505
Prepayments and other current assets 94,658 78,056
- --------------------------------------------------------------------------------------------------------------------
Total Current Assets 1,146,905 1,087,554
- --------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 252,083 277,550
Nuclear decommissioning trust funds 423,293 416,721
Diversified business property, net 9,435 111,802
Miscellaneous other property and investments 209,657 224,101
Other assets and deferred debits 104,978 150,306
- --------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 999,446 1,180,480
- --------------------------------------------------------------------------------------------------------------------
Total Assets $ 8,974,684 $ 9,258,685
- --------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- --------------------------------------------------------------------------------------------------------------------
Capitalization (see consolidated schedules of capitalization)
- --------------------------------------------------------------------------------------------------------------------
Common stock $ 3,089,115 $ 3,095,456
Preferred stock - not subject to mandatory redemption 59,334 59,334
Long-term debt, net 3,048,466 2,698,318
- --------------------------------------------------------------------------------------------------------------------
Total Capitalization 6,196,915 5,853,108
- --------------------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt - 600,000
Accounts payable 259,217 300,829
Payables to affiliated companies 98,572 106,114
Notes payable to affiliated companies - 47,913
Interest accrued 58,791 61,124
Short-term obligations 437,750 260,535
Current portion of accumulated deferred income taxes 66,088 67,975
Other current liabilities 93,171 140,670
- --------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,013,589 1,585,160
- --------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,179,689 1,316,823
Accumulated deferred investment tax credits 158,308 170,302
Regulatory liabilities 7,774 7,494
Other liabilities and deferred credits 418,409 325,798
- --------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 1,764,180 1,820,417
- --------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 18)
- --------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 8,974,684 $ 9,258,685
- --------------------------------------------------------------------------------------------------------------------
See Carolina Power & Light Company Notes to Consolidated Financial Statements.
7
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of CASH FLOWS
Years ended December 31
(In thousands) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 430,932 $ 364,231 $ 461,028
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of long-lived assets and investments 126,262 156,712 -
Depreciation and amortization 631,401 616,206 803,211
Deferred income taxes (81,916) (149,895) (83,554)
Investment tax credit (11,994) (14,928) (4,511)
Gain on sale of assets - - (200,000)
Deferred fuel credit (14,510) (11,652) (40,763)
Net (increase) decrease in accounts receivable 222,293 304,106 (185,640)
Net (increase) decrease in inventories 9,998 (139,854) (3,699)
Net (increase) decrease in prepayments and other current assets (14,953) 21,679 87,575
Net increase (decrease) in accounts payable 20,490 (261,606) 314,267
Net increase (decrease) in other current liabilities (2,332) 52,704 146,802
Other 51,801 47,140 26,019
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,367,472 984,843 1,320,735
- ---------------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (624,202) (823,952) (821,991)
Nuclear fuel additions (80,515) (72,576) (59,752)
Proceeds from sale of assets - - 200,000
Contributions to nuclear decommissioning trust (30,708) (30,678) (30,727)
Diversified business property additions (11,836) (13,500) (56,489)
Investments in non-utility activities (17,053) (32,674) (111,516)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (764,314) (973,380) (880,475)
- ---------------------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt 542,290 296,124 783,052
Net increase (decrease) in short-term obligations 177,215 (225,762) 123,697
Net increase (decrease) in intercompany notes (96,687) 187,560 (275,628)
Retirement of long-term debt (806,809) (134,611) (695,163)
Equity contribution from parent - 115,000 -
Dividends paid to parent (396,680) (255,630) -
Dividends paid on preferred stock (2,964) (2,964) (2,966)
Dividends paid on common stock - - (432,325)
Other (22,489) - 21,027
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (606,124) (20,283) (478,306)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Decrease in Cash and Cash Equivalents (2,966) (8,820) (38,046)
- ---------------------------------------------------------------------------------------------------------------------------------
Decrease in Cash from Stock Distribution (See Note 1A) - - (11,755)
Cash and Cash Equivalents at Beginning of Year 21,250 30,070 79,871
- ---------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 18,284 $ 21,250 $ 30,070
- ---------------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $208,283 $230,828 $205,250
income taxes (net of refunds) $319,973 $395,433 $434,908
Noncash Investing and Financing Activities
o On June 28, 2000, Caronet, Inc., a wholly owned subsidiary of CP&L,
contributed net assets in the amount of $93 million in exchange for a 35%
ownership interest (15% voting interest) in a newly formed company.
o On July 1, 2000, CP&L distributed its ownership interest in the stock of
North Carolina Natural Gas Corporation, Strategic Resource Solutions Corp.,
Monroe Power Company and Progress Ventures Holdings, Inc. to Progress
Energy, Inc. This resulted in a noncash dividend to its parent of
approximately $556 million (See Note 1A).
o In January 2001, CP&L transferred certain assets, through a noncash
dividend to parent in the amount of $19 million, to Progress Energy Service
Company, LLC.
o In February 2002, CP&L transferred the Rowan plant to Progress Ventures
Holdings, Inc. The property and inventory transferred totaled approximately
$245 million.
See Carolina Power & Light Company Notes to Consolidated Financial Statements.
8
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED SCHEDULES of CAPITALIZATION
December 31
(In thousands except share data) 2002 2001
-------------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, authorized 200,000,000 shares,
159,608,055 shares issued and outstanding at December 31 $ 1,929,515 $ 1,904,246
Unearned ESOP common stock (101,560) (114,385)
Accumulated other comprehensive loss (82,769) (7,046)
Retained earnings 1,343,929 1,312,641
-------------------------------------------------------------------------------------------------------------
Total Common Stock Equity $ 3,089,115 $ 3,095,456
-------------------------------------------------------------------------------------------------------------
Preferred Stock - not subject to mandatory redemption
Authorized - 300,000 shares, cumulative, $100 par value Preferred
Stock; 20,000,000 shares, cumulative, $100 par value Serial
Preferred Stock
$5.00 Preferred - 236,997 shares (redemption price $110.00) $ 24,349 $ 24,349
$4.20 Serial Preferred - 100,000 shares outstanding
redemption price $102.00) 10,000 10,000
$5.44 Serial Preferred -249,850 shares (redemption price
$101.00) 24,985 24,985
-------------------------------------------------------------------------------------------------------------
Total Preferred Stock $ 59,334 $ 59,334
-------------------------------------------------------------------------------------------------------------
Long-Term Debt (maturities and weighted-average interest rates as
of December 31, 2002)
First mortgage bonds, maturing 2004-2023 6.92% $ 1,550,000 $ 1,800,000
Pollution control obligations, maturing 2010-2024 1.86% 707,800 707,800
Unsecured notes, maturing 2012 6.50% 500,000 -
Extendible notes, maturing 2002 - - 500,000
Medium-term notes, maturing 2008 6.65% 300,000 300,000
Miscellaneous notes 6.44% 6,910 7,234
Unamortized premium and discount, net (16,244) (16,716)
Current portion of long-term debt - (600,000)
-------------------------------------------------------------------------------------------------------------
Total Long-Term Debt, Net 3,048,466 2,698,318
-------------------------------------------------------------------------------------------------------------
Total Capitalization $ 6,196,915 $ 5,853,108
-------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS of RETAINED EARNINGS
Years ended December 31
(In thousands) 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------
Retained Earnings at Beginning of Year $ 1,312,641 $ 1,226,144 $ 1,807,345
Net income 430,932 364,231 461,028
Preferred stock dividends at stated rates (2,964) (2,964) (2,966)
Common stock dividends (396,680) (274,770) (1,039,263)
- --------------------------------------------------------------------------------------------------------------
Retained Earnings at End of Year $ 1,343,929 $ 1,312,641 $ 1,226,144
- --------------------------------------------------------------------------------------------------------------
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
(In thousands) First Quarter Second Quarter Third Quarter Fourth Quarter
- -----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2002
Operating revenues $ 814,871 $ 838,092 $ 1,049,484 $ 851,373
Operating income 193,185 210,022 240,051 211,956
Net income 85,119 131,152 94,139 120,522
- -----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2001
Operating revenues $ 826,603 $ 783,379 $ 976,891 $ 773,288
Operating income 231,641 184,390 322,477 237,522
Net income (loss) 120,845 84,879 167,874 (9,367)
o In the opinion of management, all adjustments necessary to fairly present
amounts shown for interim periods have been made. Results of operations for
an interim period may not give a true indication of results for the year.
o Fourth quarter 2001 includes impairment and other charges related to
Interpath Communications, Inc. of $156.7 million ($107.2 million, after
tax) (See Note 5).
o Third quarter 2002 includes impairment and other charges related to
Caronet, Inc. and Interpath Communications, Inc. of $133.3 million ($87.4
million, after tax) (See Note 5).
See Carolina Power & Light Company Notes to Consolidated Financial Statements.
9
CAROLINA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Carolina Power & Light Company (CP&L) is a public service corporation
primarily engaged in the generation, transmission, distribution and sale of
electricity in portions of North Carolina and South Carolina. Through its
wholly owned subsidiaries, CP&L is involved in several nonregulated business
activities, the most significant of which is its telecommunications
operation. CP&L is a wholly owned subsidiary of Progress Energy, Inc. (the
Company or Progress Energy), which was formed as a result of the
reorganization of CP&L into a holding company structure on June 19, 2000.
All shares of common stock of CP&L were exchanged for an equal number of
shares of CP&L Energy, Inc. On December 4, 2000, the Company changed its
name from CP&L Energy, Inc. to Progress Energy, Inc. 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.
On July 1, 2000, CP&L distributed its ownership interest in the stock of
North Carolina Natural Gas Corporation (NCNG), Strategic Resource Solutions
Corp. (SRS), Monroe Power Company (Monroe Power) and Progress Ventures
Holdings, Inc. (PVHI) to the Company. As a result, those companies are
direct subsidiaries of Progress Energy and are not included in CP&L's
results of operations and financial position subsequent to July 1, 2000.
Effective January 1, 2003, CP&L began doing business under the assumed name
Progress Energy Carolinas, Inc. The legal name has not changed and there is
no restructuring of any kind related to the name change. The current
corporate and business unit structure remains unchanged.
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America
(GAAP) and include the activities of CP&L and its majority-owned
subsidiaries. Significant intercompany balances and transactions have been
eliminated in consolidation except as permitted by Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation," which provides that profits on intercompany sales to
regulated affiliates are not eliminated if the sales price is reasonable and
the future recovery of the sales price through the ratemaking process is
probable.
The accounting records are maintained in accordance with uniform systems of
accounts prescribed by the Federal Energy Regulatory Commission (FERC), the
North Carolina Utilities Commission (NCUC) and the Public Service Commission
of South Carolina (SCPSC).
Unconsolidated investments in companies over which CP&L does not have
control, but has the ability to exercise influence over operating and
financial policies (generally, 20% - 50% voting interest) are accounted for
under the equity method of accounting. Other investments are stated
principally at cost. These equity and cost investments, which total
approximately $95.0 million and $114.3 million at December 31, 2002 and
2001, respectively, are included as miscellaneous property and investments
in the Consolidated Balance Sheets. The primary component of this balance is
CP&L's investments in affordable housing of $63.4 million and $54.3 million
as of December 31, 2002 and 2001, respectively. Included in the December 31,
2001 investment balance is CP&L's investment in Interpath Communications,
Inc. of $27.0 million (See Note 5).
Certain amounts for 2001 and 2000 have been reclassified to conform to the
2002 presentation.
C. Use of Estimates and Assumptions
In preparing consolidated 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 consolidated financial statements and amounts
of revenues and expenses reflected during the reporting period. Actual
results could differ from those estimates.
10
D. Utility Plant
Utility plant in service is stated at historical cost less accumulated
depreciation. CP&L capitalizes all construction-related direct labor and
material costs of units of property as well as indirect construction costs.
The costs of renewals and betterments are also capitalized. Maintenance and
repairs of property, and replacements and renewals of items determined to be
less than units of property, are charged to maintenance expense as incurred.
The cost of units of property replaced, renewed or retired, plus removal or
disposal costs, less salvage, is charged to accumulated depreciation.
Generally, electric utility plant, other than nuclear fuel is pledged as
collateral for the first mortgage bonds of CP&L (See Note 6).
The balances of utility plant in service at December 31 are listed below (in
thousands), with a range of depreciable lives for each:
2002 2001
------------ ------------
Production plant (7-33 years) $ 7,629,539 $ 7,301,225
Transmission plant (30-75 years) 1,128,097 1,092,024
Distribution plant (12-50 years) 3,344,662 3,063,753
General plant and other (8-75 years) 573,463 567,289
------------ ------------
Utility plant in service $ 12,675,761 $ 12,024,291
============ ============
Allowance for funds used during construction (AFUDC) represents the
estimated debt and equity costs of capital funds necessary to finance the
construction of new regulated assets. As prescribed in the regulatory
uniform systems of accounts, AFUDC is charged to the cost of the plant. The
equity funds portion of AFUDC is credited to other income and the borrowed
funds portion is credited to interest charges. Regulatory authorities
consider AFUDC an appropriate charge for inclusion in the rates charged to
customers by the utilities over the service life of the property. The total
equity funds portion of AFUDC was $6.4 million, $8.8 million and $14.5
million in 2002, 2001 and 2000, respectively. The composite AFUDC rate for
CP&L's electric utility plant was 6.2% in both 2002 and 2001 and 8.2% in
2000.
E. Depreciation and Amortization - Utility Plant
For financial reporting purposes, substantially all depreciation of utility
plant other than nuclear fuel is computed on the straight-line method based
on the estimated remaining useful life of the property, adjusted for
estimated net salvage. Depreciation provisions, including decommissioning
costs (See Note 1G) and excluding accelerated cost recovery of nuclear
generating assets, as a percent of average depreciable property other than
nuclear fuel, were approximately 3.8% in 2002, 2001 and 2000. Depreciation
and decommissioning provisions, including accelerated cost recovery, totaled
$504.5 million, $504.9 million and $688.8 million in 2002, 2001 and 2000,
respectively.
With approval from the NCUC and the SCPSC, CP&L accelerated the cost
recovery of its nuclear generating assets beginning January 1, 2000. During
2002, the NCUC and the SCPSC approved modifications to CP&L's ongoing
accelerated cost recovery of its nuclear generating assets including
extension of the recovery period. Cumulative accelerated depreciation
ranging from $530 million to $750 million will be recorded by December 31,
2009. The accelerated cost recovery of these assets resulted in additional
depreciation expense of approximately $53 million, $75 million and $275
million in 2002, 2001 and 2000, respectively. Total accelerated depreciation
recorded through December 31, 2002 was $326 million for the North Carolina
jurisdiction and $77 million for the South Carolina jurisdiction (See Note
9B).
Amortization of nuclear fuel costs, including disposal costs associated with
obligations to the U.S. Department of Energy (DOE), is computed primarily on
the units-of-production method and charged to fuel expense. Costs related to
obligations to the DOE for the decommissioning and decontamination of
enrichment facilities are also charged to fuel expense. The total of these
costs for the years ended December 31, 2002, 2001 and 2000 were $109.1
million, $101.0 million and $112.1 million, respectively.
11
F. Diversified Business Property
Diversified business property is stated at cost less accumulated
depreciation. If CP&L recognizes an impairment of an asset, the fair value
becomes its new cost basis. The costs of renewals and betterments are
capitalized. The cost of repairs and maintenance is charged to expense as
incurred. Depreciation is computed on a straight-line basis.
The following is a summary of diversified business property (in thousands)
as of December 31, with ranges of depreciable lives:
2002 2001
---------- ----------
Telecommunications equipment (5 - 20 years) $ 1,687 $ 94,164
Other equipment (3 - 10 years) 8,363 11,657
Construction work in progress 497 21,622
Accumulated depreciation (1,112) (15,641)
---------- ----------
Diversified business property, net $ 9,435 $ 111,802
========== ==========
The decrease from 2001 to 2002 is attributable to an impairment of assets
discussed in Note 5. Diversified business depreciation expense was $3.6
million, $6.4 million and $3.2 million in 2002, 2001 and 2000, respectively.
G. Decommissioning and Dismantlement Provisions
In CP&L's retail jurisdictions, provisions for nuclear decommissioning costs
are approved by the NCUC and the SCPSC, and are based on site-specific
estimates that include the costs for removal of all radioactive and other
structures at the site. In the wholesale jurisdictions, the provisions for
nuclear decommissioning costs are approved by FERC. Decommissioning cost
provisions, which are included in depreciation and amortization expense,
were $30.7 million in 2002, 2001 and 2000.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were $611.3 million and $604.8 million at December 31, 2002
and 2001, respectively. These costs include amounts retained internally and
amounts funded in externally managed decommissioning trusts. Trust earnings
increase the trust balance with a corresponding increase in the accumulated
decommissioning balance. These balances are adjusted for net unrealized
gains and losses related to changes in the fair value of trust assets.
CP&L's most recent site-specific estimates of decommissioning costs were
developed in 1998, using 1998 cost factors, and are based on prompt
dismantlement decommissioning, which reflects the cost of removal of all
radioactive and other structures currently at the site, with such removal
occurring shortly after operating license expiration. These estimates, in
1998 dollars, are $281.5 million for Robinson Unit No. 2, $299.6 million for
Brunswick Unit No. 1, $298.7 million for Brunswick Unit No. 2 and $328.1
million for the Harris Plant. The estimates are subject to change based on a
variety of factors including, but not limited to, cost escalation, changes
in technology applicable to nuclear decommissioning and changes in federal,
state or local regulations. The cost estimates exclude the portion
attributable to North Carolina Eastern Municipal Power Agency (Power
Agency), which holds an undivided ownership interest in the Brunswick and
Harris nuclear generating facilities. Operating licenses for CP&L's nuclear
units expire in the years 2010 for Robinson Unit No. 2, 2016 for Brunswick
Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant. An
application to extend the Robinson license 20 years was submitted in 2002
and a similar application will be made for Brunswick in December 2004. An
extension will also be sought for the Harris Plant, tentatively in 2009.
Management believes that the decommissioning costs that have been and will
be recovered through rates will be sufficient to provide for the costs of
decommissioning.
The Financial Accounting Standards Board (FASB) has issued SFAS No. 143,
"Accounting for Asset Retirement Obligations," that will impact the
accounting for decommissioning and dismantlement provisions (See Note 1P).
12
H. Excise Taxes
CP&L, as an agent for a state or local government, collects from customers
certain excise taxes levied by the state or local government upon the
customer. CP&L accounts for excise taxes on a gross basis. Excise taxes are
included in CP&L's base rates. For the years ended December 31, 2002, 2001
and 2000, gross receipts tax and other excise taxes of approximately $79.3
million, $76.8 million and $75.1 million, respectively, are included in
taxes other than on income on the Consolidated Statements of Income and
Comprehensive Income. These approximate amounts are also included in
electric operating revenues.
I. Inventory
CP&L accounts for inventory using the average-cost method. As of December
31, inventory was comprised of (in thousands):
2002 2001
---------- ----------
Fuel $ 117,946 $ 137,236
Materials and supplies 224,940 235,489
---------- ----------
Total inventory $ 342,886 $ 372,725
========== ==========
J. Other Policies
CP&L recognizes electric utility revenue as service is rendered to
customers. Operating revenues include unbilled electric utility revenues
earned when service has been delivered but not billed by the end of the
accounting period. Revenues related to design and construction of wireless
infrastructure are recognized upon completion of services for each completed
phase of design and construction.
Fuel expense includes fuel costs or recoveries that are deferred through
fuel clauses established by CP&L's regulators. These clauses allow CP&L to
recover fuel costs and portions of purchased power costs through surcharges
on customer rates.
CP&L maintains an allowance for doubtful accounts receivable, which totaled
approximately $11.3 million and $12.2 million at December 31, 2002 and 2001,
respectively.
Long-term debt premiums, discounts and issuance expenses for the utilities
are amortized over the life of the related debt using the straight-line
method. Any expenses or call premiums associated with the reacquisition of
debt obligations by the utilities are amortized over the remaining life of
the original debt using the straight-line method consistent with ratemaking
treatment.
CP&L considers all highly liquid investments with original maturities of
three months or less to be cash equivalents.
CP&L participates in a money pool arrangement with other Progress Energy
subsidiaries to better manage cash and working capital requirements. Under
this arrangement, subsidiaries with surplus short-term funds provide
short-term loans to participating affiliates (See Note 4).
The Company follows the guidance in SFAS No. 87, "Employers' Accounting for
Pensions," to account for its defined benefit retirement plans. In addition
to pension benefits, the Company provides other postretirement benefits
which are accounted for under SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." See Note 13 for related
disclosures for these plans.
K. Impairment of Long-Lived Assets and Investments
CP&L reviews the recoverability of long-lived and intangible assets whenever
indicators exist. Examples of these indicators include current period
losses, combined with a history of losses or a projection of continuing
losses, or a significant decrease in the market price of a long-lived asset
group. If an indicator exists, then the asset group is tested for
recoverability by comparing the carrying value to the sum of undiscounted
expected future cash flows directly attributable to the asset group. If the
asset group is not recoverable through undiscounted cash flows, then an
impairment loss is recognized for the difference between the carrying value
and the fair value of the asset group. The accounting for impairment of
assets is based on SFAS No. 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," which was adopted by CP&L effective January 1, 2002.
Prior to the adoption of this standard, impairments were accounted for under
13
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," which was superceded by SFAS No. 144.
See Note 5 for discussion of impairment evaluations performed and charges
taken.
L. Income Taxes
Progress Energy and its affiliates file a consolidated federal income tax
return. The consolidated income tax of Progress Energy is allocated to CP&L
in accordance with the Inter-company Income Tax Allocation Agreement. The
agreement provides an allocation that recognizes positive and negative
corporate taxable income. The agreement provides for an equitable method of
apportioning the carry over of uncompensated tax benefits. Progress Energy
Holding Company tax benefits not related to acquisition interest expense are
allocated to profitable subsidiaries, beginning in 2002, in accordance with
a PUHCA order. Income taxes are provided as if CP&L filed a separate return.
Deferred income taxes have been provided for temporary differences. These
occur when there are differences between the book and tax carrying amounts
of assets and liabilities. Investment tax credits related to regulated
operations have been deferred and are being amortized over the estimated
service life of the related properties (See Note 14).
M. Derivatives
Effective January 1, 2001, CP&L adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138.
SFAS No. 133, as amended, establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. SFAS No. 133 requires that an
entity recognize all derivatives as assets or liabilities in the balance
sheet and measure those instruments at fair value. See Note 10 for
information regarding risk management activities and derivative
transactions.
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. In particular, that guidance discusses
whether the pricing in a contract that contains broad market indices (e.g.,
CPI) 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).
CP&L is currently reevaluating which contracts, if any, that have previously
been designated as normal purchases or sales would now not qualify for this
exception. CP&L is currently evaluating the effects that this guidance will
have on its results of operation and financial position.
N. Environmental
The Company accrues environmental remediation liabilities when the criteria
for SFAS No. 5, "Accounting for Contingencies," has been met. Environmental
expenditures are expensed as incurred or capitalized depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic benefits are
expensed. Accruals for estimated losses from environmental remediation
obligations generally are recognized no later than completion of the
remedial feasibility study. Such accruals are adjusted as additional
information develops or circumstances change. Costs of future expenditures
for environmental remediation obligations are not discounted to their
present value. Recoveries of environmental remediation costs from other
parties are recognized when their receipt is deemed probable (See Note 18D).
O. Cost-Based Regulation
CP&L's regulated operations are subject to SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation." SFAS No. 71 allows a regulated
company to record costs that have been or are expected to be allowed in the
ratemaking process in a period different from the period in which the costs
would be charged to expense by a nonregulated enterprise. Accordingly, CP&L
records assets and liabilities that result from the regulated ratemaking
process that would not be recorded under GAAP for nonregulated entities.
These regulatory assets and liabilities represent expenses deferred for
future recovery from customers or obligations to be refunded to customers
and are primarily classified in the accompanying Consolidated Balance Sheets
as regulatory assets and regulatory liabilities (See Note 9A).
14
P. Impact of New Accounting Standards
SFAS No. 143, "Accounting for Asset Retirement Obligations"
The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations,"
in July 2001. This statement provides accounting and disclosure requirements
for retirement obligations associated with long-lived assets and is
effective January 1, 2003. This statement requires that the present value of
retirement costs for which CP&L 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 will be 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. The cumulative effect of implementing this Statement is
recognized as a change in accounting principle. The adoption of this
statement will have no impact on CP&L's net income, as the effects are
expected to be offset by the establishment of regulatory assets and
liabilities pursuant to SFAS No. 71.
CP&L's review identified legal retirement obligations for nuclear
decommissioning of radiated plant. CP&L will record liabilities pursuant to
SFAS No. 143 beginning in 2003. CP&L used an expected cash flow approach to
measure the obligations. The proforma amounts for nuclear decommissioning of
radiated plant as if SFAS No. 143 had been applied during all periods are
$879.7 million and $830.5 million at December 31, 2002 and 2001,
respectively.
Nuclear decommissioning has previously-recorded liabilities. Amounts
recorded for nuclear decommissioning of radiated plant were $491.3 million
and $460.9 million at December 31, 2002 and 2001, respectively.
Proforma net income has not been presented for the years ended December 31,
2002, 2001 and 2000 because the proforma application of SFAS No. 143 to
prior periods would result in proforma net income not materially different
from the actual amounts reported for those periods in the accompanying
Consolidated Statements of Income and Comprehensive Income.
CP&L has identified but not recognized asset retirement obligation (ARO)
liabilities related to electric transmission and distribution and
telecommunications assets as the result of easements over property not owned
by CP&L. 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
CP&L intends to utilize these properties indefinitely. In the event CP&L
decides to abandon or cease the use of a particular easement, an ARO
liability would be recorded at that time.
CP&L has previously recognized removal costs as a component of depreciation
in accordance with regulatory treatment. To the extent these amounts do not
represent SFAS No. 143 legal retirement obligations, they will be disclosed
as regulatory liabilities upon adoption of the standard.
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" In April 2002, the FASB
issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections." This newly
issued statement rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt (an amendment of APB Opinion No. 30)," which required
all gains and losses from the extinguishment of debt to be aggregated and,
if material, classified as an extraordinary item, net of related income tax
effect. As a result, the criteria set forth by APB Opinion 30 will now be
used to classify those gains and losses. Any gain or loss on extinguishment
will be recorded in the most appropriate line item to which it relates
within net income before extraordinary items. For CP&L, any expenses or call
premiums associated with the reacquisition of debt obligations are amortized
over the remaining life of the original debt using the straight-line method
consistent with ratemaking treatment. SFAS No. 145 also amends SFAS No. 13
to require that certain lease modifications that have economic effects
similar to sale-leaseback transactions be accounted for in the same manner
as sale-leaseback transactions. In addition, SFAS No. 145 amends other
existing authoritative pronouncements to make various technical corrections,
clarify meanings or describe their applicability under changed conditions.
For the provisions related to the rescission of SFAS No. 4, SFAS No. 145 is
effective for CP&L beginning in fiscal year 2004. The remaining provisions
of SFAS No. 145 are effective for CP&L in fiscal year 2003. CP&L is
currently evaluating the effects, if any, that this statement will have on
its results of operations and financial position.
15
SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure"
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure -- an Amendment of FASB Statement
No. 123," and provided alternative methods of transition for a voluntary
change to the fair value-based method of accounting for stock-based employee
compensation. In addition, this statement amends the disclosure requirements
of SFAS No. 123, "Accounting for Stock-Based Compensation," to require
prominent disclosures in both annual and interim financial statements about
the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. This statement requires that
companies having a year-end after December 15, 2002 follow the prescribed
format and provide the additional disclosures in their annual reports. CP&L
applies the recognition and measurement principles of APB Opinion No. 25,
"Accounting for Stock Issued to Employees" as allowed by SFAS Nos. 123 and
148, and related interpretations in accounting for its stock-based
compensation plans as described in Note 12.
The following table illustrates the effect on CP&L's net income if CP&L had
applied the fair value recognition provisions of SFAS No. 123 to the stock
option plan. The stock option plan was not in effect in 2000.
(In thousands) 2002 2001 2000
--------- --------- ---------
Net income, as reported $ 430,932 $ 364,231 $ 461,028
Deduct: Total stock option expense
determined under fair value method
for all awards, net of related tax effects 4,704 1,200 -
--------- --------- ---------
Proforma net income $ 426,228 $ 363,031 $ 461,028
========= ========= =========
FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others"
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others - an Interpretation of FASB Statements
No. 5, 57 and 107 and Rescission of FASB Interpretation No. 34" (FIN No.
45). This interpretation clarifies the disclosures to be made by a guarantor
in its interim and annual financial statements about obligations under
certain guarantees that it has issued. It also clarifies that a guarantor is
required to recognize, at the inception of certain guarantees, a liability
for the fair value of the obligation undertaken in issuing the guarantee.
The initial recognition and initial measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements are effective
for financial statements of interim or annual periods ending after December
15, 2002. The applicable disclosures required by FIN No. 45 have been made
in Note 18B. CP&L is currently evaluating the effects, if any, that this
interpretation will have on its results of operations and financial
position.
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 when FIN No. 46 becomes effective 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. For those variable interest
entities created or obtained on or before January 31, 2003, CP&L must apply
the provisions of FIN No. 46 in the third quarter of 2003. CP&L is currently
evaluating what effects, if any, this interpretation will have on its
results of operations and financial position.
EITF Issue 02-03, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities"
In June 2002, the EITF reached a consensus on a portion of Issue 02-03,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." EITF Issue 02-03 requires all gains and losses (realized or
unrealized) on energy trading contracts to be shown net in the income
statement. CP&L's policy already required the gains and losses to be
recorded on a net basis. The net of the gains and losses are recorded in
other, net on the Consolidated Statements of Income and Comprehensive
16
Income. CP&L does not recognize a dealer profit or unrealized gain or loss
at the inception of a derivative unless the fair value of that instrument,
in its entirety, is evidenced by quoted market prices or current market
transactions.
2. Divestitures
In September 2000, Caronet, Inc. (Caronet), a wholly owned subsidiary of
CP&L, sold its 10% limited partnership interest in BellSouth Carolinas PCS
for $200 million. The sale resulted in an after-tax gain of $121.1 million.
3. Financial Information by Business Segment
As described in Note 1A, on July 1, 2000, CP&L distributed its ownership
interest in the stock of NCNG, SRS, Monroe Power and PVHI to Progress
Energy. As a result, those companies are direct subsidiaries of Progress
Energy and are not included in CP&L's results of operations and financial
position subsequent to July 1, 2000.
Through June 30, 2000, the business segments, operations and assets of
Progress Energy and CP&L were substantially the same. Subsequent to July 1,
2000, CP&L's operations consisted primarily of the CP&L Electric segment.
The financial information for the CP&L Electric segment for the years ended
December 31, 2002, 2001 and 2000 is as follows:
Year Ended Year Ended Year Ended
(In thousands) December 31, 2002 December 31, 2001 December 31, 2000
- ----------------------------------------------------------------------------------------------------
Revenues $3,538,957 $ 3,343,720 $ 3,308,215
Depreciation and amortization 523,846 521,910 698,633
Net interest charges 211,536 241,427 221,856
Income taxes 237,362 264,078 227,705
Net income 513,115 468,328 373,764
Total segment assets 8,659,297 8,884,385 8,840,736
Capital and investment expenditures 624,202 823,952 821,991
====================================================================================================
The primary differences between the CP&L Electric segment and the CP&L
consolidated financial information relate to other non-electric operations
and elimination entries. CP&L's non-electric operations had combined revenue
of $14.9 million in 2002 and assets of $315.4 million at December 31, 2002.
Included in the 2002 operations of the telecommunications subsidiary,
Caronet, is an impairment of assets and investments of $87.4 million,
after-tax (See Note 5A). Excluding this impairment, the earnings of CP&L's
non-electric operations are negligible.
4. Related Party Transactions
CP&L participates in an internal money pool, operated by Progress Energy, to
more effectively utilize cash resources and to reduce outside short-term
borrowings. Short-term borrowing needs are met first by available funds of
the money pool participants. Borrowing companies pay interest at a rate
designed to approximate the cost of outside short-term borrowings.
Subsidiaries which invest in the money pool earn interest on a basis
proportionate to their average monthly investment. The interest rate used to
calculate earnings approximates external interest rates. Funds may be
withdrawn from or repaid to the pool at any time without prior notice. At
December 31, 2002, CP&L had $49.8 million of amounts receivable from the
money pool that are included in notes receivable from affiliated companies
on the Consolidated Balance Sheets. At December 31, 2001, CP&L had $47.9
million of amounts payable to the money pool that are included in notes
payable to affiliated companies on the Consolidated Balance Sheets. The
weighted-average interest rates associated with such money pool balances
were 2.18% and 4.47% at December 31, 2002 and 2001, respectively. CP&L
recorded $0.3 million and $1.6 million of interest income and $1.6 million
and $1.7 million of interest expense related to the money pool for 2002 and
2001, respectively. Amounts recorded for interest income and interest
expense related to the money pool for 2000 were not significant.
During 2000, the Company formed Progress Energy Service Company, LLC (PESC)
to provide specialized services, at cost, to the Company and its
subsidiaries, as approved by the U.S. Securities and Exchange Commission
(SEC). CP&L has an agreement with PESC under which services, including
purchasing, accounting, treasury, tax, marketing, legal and human resources,
are rendered to CP&L at cost. Amounts billed to CP&L by PESC for these
17
services during 2002, 2001 and 2000 amounted to $260.5 million, $173.9
million and $52.4 million, respectively. At December 31, 2002 and 2001, CP&L
had net payables of $63.2 million and $46.0 million, respectively, to PESC
that are included in payables to affiliated companies on the Consolidated
Balance Sheets. Subsidiaries of CP&L had amounts payable to PESC of $0.5
million at December 31, 2002 and amounts receivable from PESC of $13.7
million at December 31, 2001. During 2002, the Office of Public Utility
Regulation within the SEC completed an audit examination of the Company's
books and records. This examination is a standard process for all PUHCA
registrants. Based on the review, the method for allocating PESC costs to
the Company and its affiliates will change in 2003. CP&L does not anticipate
the reallocation of costs will have a material impact on the results of
operations.
During the years ended December 31, 2002, 2001 and 2000, gas sales from NCNG
to CP&L amounted to $18.2 million, $14.7 million and $5.9 million,
respectively.
In August 2002, CP&L transferred reservation payments for the manufacture of
two combustion turbines to Florida Power at CP&L's original cost of $20
million.
For the year ended December 31, 2001 and the period from July 1, 2000 to
December 31, 2000, the Consolidated Statements of Income and Comprehensive
Income contain interest income received from NCNG in the amount of $4.8
million and $4.1 million, respectively, related to a note that was
outstanding between the two companies. Prior to July 1, 2000, the interest
income received from NCNG was eliminated in consolidation. There were no
balances outstanding on the note at December 31, 2002 and 2001.
At December 31, 2001, CP&L had a payable to Progress Energy in the amount of
$40.2 million related to a short-term cash advance. This amount was repaid
during February 2002. The remaining receivables from and payables to
affiliated companies at December 31, 2002 and 2001 represent intercompany
amounts generated through CP&L's normal course of operations.
5. Impairments of Long-Lived Assets and Investments
Effective January 1, 2002, CP&L adopted SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 provides guidance
for the accounting and reporting of impairment or disposal of long-lived
assets. The statement supersedes SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of." In 2002 and 2001, CP&L recorded pre-tax asset and investment
impairments of approximately $133.3 million and $156.7 million,
respectively. There were no impairments recorded in 2000.
A. Long-Lived Assets
Due to the decline of the telecommunications industry and continued
operating losses, CP&L initiated an independent valuation study to assess
the recoverability of Caronet's long-lived assets. Based on this assessment,
CP&L recorded asset impairments of $101.2 million on a pre-tax basis and
other charges of $7.1 million on a pre-tax basis primarily related to
inventory adjustments in the third quarter of 2002. These amounts are
included in diversified business expenses on the Consolidated Statements of
Income and Comprehensive Income. This write-down constitutes a significant
reduction in the book value of these long-lived assets.
The long-lived asset impairments include an impairment of property, plant
and equipment, construction work in process and intangible assets. The
impairment charge represents the difference between the fair value and
carrying amount of these long-lived assets. The fair value of these assets
was determined using a valuation study heavily weighted on the discounted
cash flow methodology, while using market approaches as supporting
information.
B. Investments
CP&L continually reviews its investments to determine whether a decline in
fair value below the cost basis is other than temporary. Effective June 28,
2000, Caronet entered into an agreement with Bain Capital whereby it
contributed the net assets used in its application service provider business
to a newly formed company, named Interpath Communications, Inc. (Interpath),
in exchange for a 35% ownership interest (15% voting interest) in Interpath.
18
CP&L obtained a valuation study to assess its investment in Interpath based
on current valuations in the technology sector during 2001. As a result,
CP&L recorded investment impairments for other-than-temporary declines in
the fair value of its investment in Interpath. The investment write-down was
$156.7 million on a pre-tax basis for the year ended December 31, 2001. In
May 2002, Interpath merged with a third party. Pursuant to the terms of the
merger agreement and due to additional funds being contributed by Bain
Capital, CP&L's ownership was diluted to approximately 19% of Interpath (7%
voting interest). As a result, CP&L reviewed the Interpath investment for
impairment and wrote off the remaining amount of its cost-basis investment
in Interpath, recording a pre-tax impairment of $25.0 million in the third
quarter of 2002. In the fourth quarter of 2002, CP&L sold its remaining
interest in Interpath for a nominal amount.
6. Debt and Credit Facilities
A. Lines of Credit
At December 31, 2002, CP&L had committed lines of credit totaling $570
million, all of which are used to support its commercial paper borrowings.
CP&L is required to pay minimal annual commitment fees to maintain its
credit facilities. The following table summarizes CP&L's credit facilities
used to support the issuance of commercial paper (in millions):
Description Total
----------------------------------------------------------------------
364-Day (expiring 7/30/03) $ 285
3-Year (expiring 7/31/05) 285
-----------------
$ 570
=================
There were no loans outstanding under these facilities at December 31, 2002.
As of December 31, 2002 and 2001, CP&L had $437.8 million and $260.5
million, respectively, of outstanding commercial paper and other short term
debt classified as short term obligations. The weighted average interest
rates of such short-term obligations at December 31, 2002 and 2001 were
1.74% and 3.07%, respectively. CP&L no longer reclassifies commercial paper
to long term debt. Certain amounts for 2001 have been reclassified to
conform to 2002 presentation, with no effect on previously reported net
income or common stock equity.
The combined aggregate maturities of long-term debt for 2004, 2005 and 2007
are approximately $300 million, $307 million and $200 million, respectively.
There are no maturities of debt scheduled for 2003 or 2006.
B. Covenants and Default Provisions
Financial Covenants
CP&L's credit line contains various terms and conditions that could affect
CP&L's ability to borrow under these facilities. These include a maximum
debt to total capital ratio, a material adverse change clause and a
cross-default provision.
CP&L's credit line requires a maximum total debt to total capital ratio of
65%. Indebtedness as defined by the bank agreement includes certain letters
of credit and guarantees which are not recorded on the Consolidated Balance
Sheets. As of December 31, 2002, CP&L's total debt to total capital ratio
was 52.7%.
Material adverse change clause
The credit facility of CP&L includes a provision under which lenders could
refuse to advance funds in the event of a material adverse change in the
borrower's financial condition.
Default provisions
CP&L's credit lines include cross-default provisions for defaults of
indebtedness in excess of $10 million. CP&L's cross-default provisions only
apply to defaults of indebtedness by CP&L and its subsidiaries,
respectively, and not to other affiliates of CP&L. In addition, the credit
lines of the Company include a similar provision. Progress Energy's
cross-default provisions only apply to defaults of indebtedness by Progress
Energy and its significant subsidiaries, which includes CP&L.
19
The lenders may accelerate payment of any outstanding debt if cross-default
provisions are triggered. Any such acceleration would cause a material
adverse change in the respective company's financial condition. Certain
agreements underlying CP&L's indebtedness also limit CP&L's ability to incur
additional liens or engage in certain types of sale and leaseback
transactions.
Other restrictions
CP&L's mortgage indenture provides that so long as any first mortgage bonds
are outstanding, cash dividends and distributions on CP&L's common stock,
and purchases of CP&L's common stock, are restricted to aggregate net income
available for CP&L, since December 31, 1948, plus $3 million, less the
amount of all preferred stock dividends and distributions, and all common
stock purchases, since December 31, 1948. At December 31, 2002, none of
CP&L's retained earnings of $1.3 billion was restricted.
Refer to Note 11 for additional dividend restrictions related to CP&L's
Articles of Incorporation.
C. Secured Obligations
CP&L's first mortgage bonds are secured by their respective mortgage
indentures. CP&L's mortgage constitutes a first lien on substantially all of
its fixed properties, subject to certain permitted encumbrances and
exceptions. The CP&L mortgage also constitutes a lien on subsequently
acquired property. At December 31, 2002, CP&L had approximately $2.3 billion
in first mortgage bonds outstanding including those related to pollution
control obligations. The CP&L mortgage allows the issuance of additional
mortgage bonds upon the satisfaction of certain conditions.
D. Hedging Activities
CP&L uses interest rate derivatives to adjust the fixed and variable rate
components of its debt portfolio and to hedge cash flow risk of fixed rate
debt to be issued in the future. See discussion of risk management and
derivative transactions at Note 10.
7. Leases
CP&L leases office buildings, computer equipment, vehicles, and other
property and equipment with various terms and expiration dates. Rent expense
(under operating leases) totaled $9.5 million, $21.7 million and $13.8
million for 2002, 2001 and 2000, respectively.
Assets recorded under capital leases consist of (in thousands):
2002 2001
-------- --------
Buildings $ 27,633 $ 27,626
Less: Accumulated amortization (9,329) (8,752)
-------- --------
$ 18,304 $ 18,874
======== ========
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases as of
December 31, 2002 are (in thousands):
Capital Operating
Leases Leases
2003 $ 2,189 $ 9,557
2004 2,189 7,695
2005 2,189 6,302
2006 2,189 3,835
2007 2,189 3,829
Thereafter 20,274 13,142
------- --------
$31,219 $44,360
=======
Less amount representing imputed interest (12,214)
--------
Present value of net minimum lease payments
under capital leases $19,005
=======
20
CP&L is the lessor of electric poles and streetlights. Rents received are
contingent upon usage and totaled $28.4 million, $30.9 million and $23.3
million for 2002, 2001 and 2000, respectively.
8. Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents and short-term obligations
approximate fair value due to the short maturities of these instruments. At
December 31, 2002 and 2001, there were miscellaneous investments consisting
primarily of investments in company-owned life insurance and other benefit
plan assets with carrying amounts totaling approximately $54.2 million and
$50.0 million, respectively, included in miscellaneous other property and
investments. The carrying amount of these investments approximates fair
value due to the short maturity of certain instruments. Other instruments
are presented at fair value in accordance with GAAP. The carrying amount of
CP&L's long-term debt, including current maturities, was $3.1 billion at
December 31, 2002 and $3.3 billion at December 31, 2001. The estimated fair
value of this debt, as obtained from quoted market prices for the same or
similar issues, was $3.3 billion and $3.4 billion at December 31, 2002 and
2001, respectively.
External funds have been established as a mechanism to fund certain costs of
nuclear decommissioning (See Note 1G). These nuclear decommissioning trust
funds are invested in stocks, bonds and cash equivalents. Nuclear
decommissioning trust funds are presented at amounts that approximate fair
value. Fair value is obtained from quoted market prices for the same or
similar investments.
9. Regulatory Matters
A. Regulatory Assets and Liabilities
As a regulated entity, CP&L is subject to the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." Accordingly,
CP&L records certain assets and liabilities resulting from the effects of
the ratemaking process, which would not be recorded under GAAP for
nonregulated entities. CP&L's ability to continue to meet the criteria for
application of SFAS No. 71 may be affected in the future by competitive
forces and restructuring in the electric utility industry. In the event that
SFAS No. 71 no longer applied to a separable portion of CP&L's operations,
related regulatory assets and liabilities would be eliminated unless an
appropriate regulatory recovery mechanism was provided. Additionally, these
factors could result in an impairment of utility plant assets as determined
pursuant to SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" (See Note 5).
At December 31, 2002 and 2001, the balances of CP&L's regulatory assets
(liabilities) were as follows (in thousands):
2002 2001
--------- ---------
Deferred fuel (included in current assets) $ 146,015 $ 131,505
--------- ---------
Income taxes recoverable through future rates 197,402 208,702
Harris Plant deferred costs 16,888 32,476
Loss on reacquired debt 13,223 5,801
Deferred DOE enrichment facilities-related costs 24,570 30,571
--------- ---------
Total long-term regulatory assets 252,083 277,550
--------- ---------
Emission allowance gains (7,774) (7,494)
--------- ---------
Net regulatory assets $ 390,324 $ 401,561
========= =========
Except for portions of deferred fuel, all regulatory assets earn a return or
the cash has not yet been expended, in which case, the assets are offset by
liabilities that do not incur a carrying cost.
B. Retail Rate Matters
The NCUC and SCPSC approved proposals to accelerate cost recovery of CP&L's
nuclear generating assets beginning January 1, 2000, and continuing through
2004. On June 14, 2002, the NCUC approved modification of CP&L's ongoing
accelerated cost recovery of its nuclear generating assets. Effective
January 1, 2003, the NCUC will no longer require a minimum annual
depreciation. The aggregate minimum and maximum amounts of accelerated
21
depreciation, $415 million and $585 million respectively, are unchanged from
the original NCUC order. The date by which the minimum amount must be
depreciated was extended from December 31, 2004 to December 31, 2009. On
October 29, 2002, the SCPSC approved similar modifications. The order was
effective November 1, 2002, and the aggregate minimum and maximum of $115
million and $165 million established for accelerated cost recovery by the
SCPSC is unchanged. The accelerated cost recovery of these assets resulted
in additional depreciation expense of approximately $53 million, $75 million
and $275 million in 2002, 2001 and 2000, respectively. Recovering the costs
of its nuclear generating assets on an accelerated basis will better
position CP&L for the uncertainties associated with potential restructuring
of the electric utility industry. Total accelerated depreciation recorded
through December 31, 2002 was $326 million for the North Carolina
jurisdiction and $77 million for the South Carolina jurisdiction.
On May 30, 2001, the NCUC issued an order allowing CP&L to offset a portion
of its annual accelerated cost recovery of nuclear generating assets by the
amount of sulfur dioxide (SO2) emission allowance expense. CP&L offset
accelerated depreciation expense against emission allowance expense by
approximately $5.8 million in 2002. CP&L did not offset accelerated
depreciation expense against emission allowance expense in 2001. CP&L is
allowed to recover emission allowance expense through the fuel clause
adjustment in its South Carolina retail jurisdiction.
In conjunction with the acquisition of NCNG, CP&L 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. In North Carolina, legislation enacted pursuant to the North
Carolina Clean Air Act in June of 2002 freezes CP&L's base rates for five
years, subject to certain conditions. See Note 18D for further discussion of
this matter.
In conjunction with the Company's merger with Florida Progress Corporation,
CP&L reached a settlement with the Public Staff of the NCUC in which it
agreed to reduce rates to all of its non-real time pricing customers by $3.0
million in 2002, $4.5 million in 2003, $6.0 million in 2004 and $6.0 million
in 2005. CP&L also agreed to write off and forego recovery of $10 million of
unrecovered fuel costs in each of its 2000 NCUC and SCPSC fuel cost recovery
proceedings.
10. Risk Management Activities and Derivatives Transactions
Under its risk management policy, CP&L may use a variety of instruments,
including swaps, options and forward contracts, to manage exposure to
fluctuations in commodity prices and interest rates. Such instruments
contain credit risk if the counterparty fails to perform under the contract.
CP&L minimizes such risk by performing credit reviews using, among other
things, publicly available credit ratings of such counterparties. Potential
non-performance by counterparties is not expected to have a material effect
on the consolidated financial position or consolidated results of operations
of CP&L.
A. Commodity Contracts - General
Most of CP&L's commodity contracts either are not derivatives pursuant to
SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No.
133. Therefore, such contracts are not recorded at fair value.
B. Commodity Derivatives - Economic Hedges and Trading
Nonhedging derivatives, primarily electricity forward contracts, are entered
into for trading purposes and for economic hedging purposes. While
management believes the economic hedges mitigate exposures to fluctuations
in commodity prices, these instruments are not designated as hedges for
accounting purposes and are monitored consistent with trading positions.
CP&L manages open positions with strict policies that limit its exposure to
market risk and require daily reporting to management of potential financial
exposures. Gains and losses from such contracts were not material during
2002, 2001 or 2000, and CP&L did not have material outstanding positions in
such contracts at December 31, 2002 or 2001.
C. Interest Rate Derivatives - Fair Value or Cash Flow Hedges
CP&L manages its interest rate exposure in part by maintaining its
variable-rate and fixed-rate exposures within defined limits. In addition,
CP&L also enters into financial derivative instruments including, but not
limited to, interest rate swaps and lock agreements to manage and mitigate
interest rate risk exposure.
22
CP&L uses cash flow hedging strategies to hedge variable interest rates on
long-term debt and to hedge interest rates with regard to future fixed-rate
debt issuances. At December 31, 2002, CP&L held no interest rate cash flow
hedges. As of December 31, 2002, $0.8 million of net after-tax deferred
losses in accumulated other comprehensive income, related to terminated
hedges, will be reclassified to earnings during the next 12 months as the
hedged interest payments occur. At December 31, 2001, CP&L held interest
rate cash flow hedges with notional amounts totaling $500.0 million and a
total fair value of $18.5 million liability position.
CP&L uses fair value hedging strategies to manage its exposure to fixed
interest rates on long-term debt. At December 31, 2002 and 2001, CP&L had no
open interest rate fair value hedges.
The notional amounts of interest rate derivatives are not exchanged and do
not represent exposure to credit loss. In the event of default by a
counterparty, the risk in these transactions is the cost of replacing the
agreements at current market rates.
11. Capitalization
As of December 31, 2002, CP&L was authorized to issue up to 200,000,000
shares of common stock. All shares issued and outstanding are held by the
Company, effective with the share exchange on June 19, 2000 (See Note 1A).
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. As of December 31, 2002,
there were no significant restrictions on the use of retained earnings.
CP&L's Articles of Incorporation provide that cash dividends on common stock
shall be limited to 75% of net income available for dividends if common
stock equity falls below 25% of total capitalization, and to 50% if common
stock equity falls below 20%. On December 31, 2002, CP&L's common stock
equity was approximately 46.6% of total capitalization.
Refer to Note 6 for additional dividend restrictions related to CP&L's
mortgage.
12. Stock-Based Compensation Plans
CP&L accounts for stock-based compensation in accordance with the provisions
of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
to Employees," and related interpretations as permitted under SFAS No. 123,
"Accounting for Stock-Based Compensation."
A. Employee Stock Ownership Plan
Progress Energy sponsors the Progress Energy 401(k) Savings and Stock
Ownership Plan (401(k)) for which substantially all full-time non-bargaining
unit employees and certain part-time non-bargaining employees within
participating subsidiaries are eligible. CP&L is a participating subsidiary
of the 401(k), which has matching and incentive goal features, encourages
systematic savings by employees and provides a method of acquiring Progress
Energy common stock and other diverse investments. The 401(k), as amended in
1989, is an Employee Stock Ownership Plan (ESOP) that can enter into
acquisition loans to acquire Progress Energy common stock to satisfy 401(k)
common stock needs. Qualification as an ESOP did not change the level of
benefits received by employees under the 401(k). Common stock acquired with
the proceeds of an ESOP loan is held by the 401(k) Trustee in a suspense
account. The common stock is released from the suspense account and made
available for allocation to participants as the ESOP loan is repaid. Such
allocations are used to partially meet common stock needs related to
Progress Energy matching and incentive contributions and/or reinvested
dividends.
There were 4,616,400 and 5,199,388 ESOP suspense shares at December 31, 2002
and 2001, respectively, with a fair value of $200.1 million and $234.1
million, respectively. CP&L's matching and incentive goal compensation cost
under the 401(k) is determined based on matching percentages and incentive
goal attainment as defined in the plan. Such compensation cost is allocated
to participants' accounts in the form of Progress Energy common stock, with
the number of shares determined by dividing compensation cost by the common
stock market value at the time of allocation. The 401(k) common stock share
needs are met with open market purchases, with shares released from the ESOP
23
suspense account and with newly issued shares. CP&L's matching and incentive
cost met with shares released from the suspense account totaled
approximately $13.3 million, $12.7 million and $14.7 million for the years
ended December 31, 2002, 2001 and 2000, respectively. CP&L has a long-term
note receivable from the 401(k) Trustee related to the purchase of common
stock from CP&L in 1989 (now Progress Energy common stock). The balance of
the note receivable from the 401(k) Trustee is included in the determination
of unearned ESOP common stock, which reduces common stock equity. Interest
income on the note receivable is not recognized for financial statement
purposes.
B. Stock Option Agreements
Pursuant to Progress Energy's 1997 Equity Incentive Plan and 2002 Equity
Incentive Plan, as amended and restated as of July 10, 2002, Progress Energy
may grant options to purchase shares of common stock to directors, officers
and eligible employees. During 2002 and 2001, approximately 2.9 million and
2.4 million common stock options were granted. Of these amounts,
approximately 1.2 million and 1.0 million were granted to officers and
eligible employees of CP&L in 2002 and 2001, respectively. No compensation
expense was recognized under the provisions of Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," and related
interpretations. For purposes of the proforma disclosures required by SFAS
No. 123, the estimated fair value of the options is amortized to expense
over the options' vesting period. Under SFAS No. 148, compensation expense
would have been $7.9 million and $2.0 million in 2002 and 2001,
respectively.
C. Other Stock-Based Compensation Plans
Progress Energy has additional compensation plans for officers and key
employees that are stock-based in whole or in part. CP&L participates in
these plans. The two primary active stock-based compensation programs are
the Performance Share Sub-Plan (PSSP) and the Restricted Stock Awards
program (RSA), both of which were established pursuant to Progress Energy's
1997 Equity Incentive Plan and were continued under the 2002 Equity
Incentive Plan, as amended and restated as of July 10, 2002.
Under the terms of the PSSP, officers and key employees are granted
performance shares on an annual basis that vest over a three-year
consecutive period. Each performance share has a value that is equal to, and
changes with, the value of a share of Progress Energy's common stock, and
dividend equivalents are accrued on, and reinvested in, the performance
shares. The PSSP has two equally weighted performance measures, both of
which are based on Progress Energy's results as compared to a peer group of
utilities. Compensation expense is recognized over the vesting period based
on the expected ultimate cash payout and is reduced by any forfeitures.
The RSA allows the Company to grant shares of restricted common stock to
officers and key employees of the Company. The restricted shares generally
vest on a graded vesting schedule over a minimum of three years.
Compensation expense, which is based on the fair value of common stock at
the grant date, is recognized over the applicable vesting period and is
reduced by any forfeitures.
The total amount expensed by CP&L for other stock-based compensation plans
was $6.9 million, $5.9 million and $9.8 million in 2002, 2001 and 2000,
respectively.
13. Postretirement Benefit Plans
CP&L and some of its subsidiaries have a non-contributory defined benefit
retirement (pension) plan for substantially all eligible employees. CP&L
also has a supplementary defined benefit pension plan that provides benefits
to higher-level employees.
The components of net periodic pension cost are (in thousands):
2002 2001 2000
---------- ---------- ---------
Expected return on plan assets $ (72,876) $ (71,955) $(76,508)
Service cost 19,343 16,960 18,804
Interest cost 50,717 46,729 49,821
Amortization of transition obligation 97 116 121
Amortization of prior service (benefit) cost 195 (1,230) (1,282)
Amortization of actuarial (gain) loss 440 (4,352) (5,607)
---------- ---------- ----------
Net periodic pension benefit $ (2,084) $ (13,732) $ (14,651)
========== ========== ==========
24
In addition to the net periodic benefit reflected above, in 2000 CP&L
recorded a charge of approximately $14.1 million to adjust its supplementary
defined benefit pension plan. The effect of the adjustment for this plan is
reflected in the actuarial loss line in the pension obligation
reconciliation below.
Prior service costs and benefits are amortized on a straight-line basis over
the average remaining service period of active participants. Actuarial gains
and losses in excess of 10% of the greater of the pension obligation or the
market-related value of assets are amortized over the average remaining
service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the
plan's funded status are (in thousands):
2002 2001
---------- ----------
Projected benefit obligation at January 1 $ 681,989 $ 638,067
Interest cost 50,717 46,729
Service cost 19,343 16,960
Benefit payments (46,059) (43,636)
Actuarial loss 96,929 5,621
Transfers (635) -
Plan amendments - 18,248
----------- ----------
Projected benefit obligation at December 31 $ 802,284 $ 681,989
Fair value of plan assets at December 31 574,367 716,799
----------- ----------
Funded status $ (227,917) $ 34,810
Unrecognized transition obligation 241 338
Unrecognized prior service cost 3,928 4,123
Unrecognized actuarial (gain) loss 237,864 (28,416)
Minimum pension liability adjustment (124,867) -
----------- ----------
Prepaid (accrued) pension cost at December 31, net $ (110,751) $ 10,855
=========== ==========
The accrued pension cost at December 31, 2002 is included in other
liabilities and deferred credits in the accompanying Consolidated Balance
Sheets. The net prepaid pension cost of $10.9 million at December 31, 2001
is included in the accompanying Consolidated Balance Sheets as prepaid
pension cost of $25.7 million, which is included in other assets and
deferred debits, and accrued benefit cost of $14.8 million, which is
included in other liabilities and deferred credits. The defined benefit
plans with accumulated benefit obligations in excess of plan assets had
projected benefit obligations totaling $802.3 million and $16.0 million at
December 31, 2002 and 2001, respectively. Those plans had accumulated
benefit obligations totaling $685.1 million and $15.4 million, respectively,
plan assets totaling $574.4 million at December 31, 2002, and no plan assets
at December 31, 2001.
Due to a combination of decreases in the fair value of plan assets and a
decrease in the discount rate used to measure the pension obligation, a
minimum pension liability adjustment of $124.9 million was recorded at
December 31, 2002. This adjustment resulted in a charge of $4.2 million to
intangible assets, included in other assets and deferred debits in the
accompanying Consolidated Balance Sheets, and a pre-tax charge of $120.7
million to accumulated other comprehensive loss, a component of common stock
equity.
25
Reconciliations of the fair value of pension plan assets are (in thousands):
2002 2001
---------- ----------
Fair value of plan assets at January 1 $ 716,799 $ 777,435
Actual return on plan assets (96,915) (18,160)
Benefit payments (46,059) (43,636)
Employer contributions 1,177 1,160
Transfers (635) -
---------- ----------
Fair value of plan assets at December 31 $ 574,367 $ 716,799
========== ==========
The weighted-average discount rate used to measure the pension obligation
was 6.6% in 2002 and 7.5% in 2001. The assumed rate of increase in future
compensation used to measure the pension obligation was 4.0% in 2002 and
2001. The expected long-term rate of return on pension plan assets used in
determining the net periodic pension cost was 9.25% in 2002, 2001 and 2000.
In addition to pension benefits, CP&L and some of its subsidiaries provide
contributory postretirement benefits (OPEB), including certain health care
and life insurance benefits, for retired employees who meet specified
criteria.
The components of net periodic OPEB cost are (in thousands):
2002 2001 2000
--------- --------- --------
Expected return on plan assets $ (3,532) $ (3,676) $(3,852)
Service cost 6,301 7,374 8,868
Interest cost 14,308 14,191 13,677
Amortization of prior service cost - - 54
Amortization of transition obligation 2,708 4,298 5,551
Amortization of actuarial gain (851) (531) (779)
--------- --------- --------
Net periodic OPEB cost $ 18,934 $ 21,656 $23,519
========= ========= ========
Prior service costs and benefits are amortized on a straight-line basis over
the average remaining service period of active participants. Actuarial gains
and losses in excess of 10% of the greater of the OPEB obligation or the
market-related value of assets are amortized over the average remaining
service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the
plan's funded status are (in thousands):
2002 2001
---------- ----------
OPEB obligation at January 1 $ 192,088 $ 187,563
Interest cost 14,308 14,191
Service cost 6,301 7,374
Benefit payments (9,003) (7,137)
Actuarial loss 30,222 19,242
Transfers (179) -
Plan amendment - (29,145)
---------- ----------
OPEB obligation at December 31 $ 233,737 $ 192,088
Fair value of plan assets at December 31 32,890 38,182
---------- ----------
Funded status $(200,847) $(153,906)
Unrecognized transition obligation 25,555 28,263
Unrecognized actuarial (gain) loss 38,434 (1,284)
--------- ----------
Accrued OPEB cost at December 31 $(136,858) $(126,927)
========== ==========
The accrued OPEB cost is included in other liabilities and deferred credits
in the accompanying Consolidated Balance Sheets. The plan amendment in 2001,
which resulted in a 15.5% reduction in the OPEB liability, implemented a cap
on CP&L's contributions toward future medical cost increases.
26
Reconciliations of the fair value of OPEB plan assets are (in thousands):
2002 2001
--------- ---------
Fair value of plan assets at January 1 $ 38,182 $ 39,048
Actual return on plan assets (5,292) (866)
Employer contributions 9,003 7,137
Benefits paid (9,003) (7,137)
--------- ---------
Fair value of plan assets at December 31 $ 32,890 $ 38,182
========= =========
The assumptions used to measure the OPEB obligation are:
2002 2001
------ ------
Weighted-average discount rate 6.60% 7.50%
Initial medical cost trend rate for
pre-Medicare benefits 7.50% 7.50%
Initial medical cost trend rate for
post-Medicare benefits 7.50% 7.50%
Ultimate medical cost trend rate 5.25% 5.00%
Year ultimate medical cost trend rate is achieved 2009 2008
The expected weighted-average long-term rate of return on plan assets used
in determining the net periodic OPEB cost was 9.25% in 2002, 2001 and 2000.
The medical cost trend rates were assumed to decrease gradually from the
initial rates to the ultimate rates. Assuming a 1% increase in the medical
cost trend rates, the aggregate of the service and interest cost components
of the net periodic OPEB cost for 2002 would increase by $3.2 million, and
the OPEB obligation at December 31, 2002, would increase by $23.1 million.
Assuming a 1% decrease in the medical cost trend rates, the aggregate of the
service and interest cost components of the net periodic OPEB cost for 2002
would decrease by $2.8 million and the OPEB obligation at December 31, 2002,
would decrease by $21.0 million.
14. Income Taxes
Deferred income taxes are provided for temporary differences between book
and tax bases of assets and liabilities. Investment tax credits related to
regulated operations are amortized over the service life of the related
property. A regulatory asset or liability has been recognized for the impact
of tax expenses or benefits that are recovered or refunded in different
periods by the utilities pursuant to rate orders.
Net accumulated deferred income tax liabilities at December 31 are (in
thousands):
2002 2001
Accelerated depreciation and property
cost differences $ 1,313,604 $ 1,359,083
Minimum pension liability (47,317) -
Deferred costs, net (9,771) 42,688
Income tax credit carryforward (10,384) (640)
Valuation allowance 8,167 3,767
Miscellaneous other temporary differences, net (8,522) (20,100)
------------ ------------
Net accumulated deferred income tax liability $ 1,245,777 $ 1,384,798
============ ============
Total deferred income tax liabilities were $1.952 billion and $2.046 billion
at December 31, 2002 and 2001, respectively. Total deferred income tax
assets were $706 million and $661 million at December 31, 2002 and 2001,
respectively. The net of deferred income tax liabilities and deferred income
tax assets is included on the Consolidated Balance Sheets under the captions
other current liabilities and accumulated deferred income taxes.
CP&L had a valuation allowance of $3.8 million at December 31, 2001 and
established additional valuation allowances of $4.4 million during 2002 due
to the uncertainty of realizing certain future state income tax benefits.
CP&L believes that it is more likely than not that the results of future
operations will generate sufficient taxable income to allow for the
utilization of the remaining deferred tax assets.
27
Reconciliations of CP&L's effective income tax rate to the statutory federal
income tax rate are:
2002 2001 2000
---------- ---------- ----------
Effective income tax rate 32.5% 38.0% 38.6%
State income taxes, net of federal benefit (3.1) (3.2) (4.5)
Investment tax credit amortization 1.9 2.5 3.7
Progress Energy tax benefit allocation (Note 1L) 5.0 - -
Other differences, net (1.3) (2.3) (2.8)
---------- ---------- ----------
Statutory federal income tax rate 35.0% 35.0% 35.0%
========== ========= ==========
The provisions for income tax expense are comprised of (in thousands):
2002 2001 2000
---------- ---------- ----------
Income tax expense (credit):
Current - federal $ 265,231 $ 348,921 $ 328,982
state 36,039 39,135 62,228
Deferred - federal (75,784) (140,486) (71,929)
state (6,132) (9,409) (11,625)
Investment tax credit (11,994) (14,928) (17,385)
---------- ---------- ----------
Total income tax expense $ 207,360 $ 223,233 $ 290,271
========== ========== ==========
15. Joint Ownership of Generating Facilities
CP&L holds undivided ownership interests in certain jointly owned generating
facilities. CP&L is entitled to shares of the generating capability and
output of each unit equal to their respective ownership interests. CP&L also
pays its ownership share of additional construction costs, fuel inventory
purchases and operating expenses. CP&L's share of expenses for the jointly
owned facilities is included in the appropriate expense category.
CP&L's ownership interest in the jointly-owned generating facilities is
listed below with related information as of December 31, 2002 and 2001
(dollars in thousands):
2002
Company Construction
Megawatt Ownership Plant Accumulated Accumulated Work in
Facility Capability Interest Investment Depreciation Decommissioning Progress
-------- ---------- -------- ---------- ------------ --------------- --------
Mayo Plant 745 83.83% $ 464,202 $ 239,971 $ - $14,089
Harris Plant 900 83.83% 3,159,946 1,432,245 95,643 6,117
Brunswick Plant 1,683 81.67% 1,476,534 867,530 339,521 26,436
Roxboro Unit No. 4 700 87.06% 316,491 138,408 - 8,079
2001
Company Construction
Megawatt Ownership Plant Accumulated Accumulated Work in
Facility Capability Interest Investment Depreciation Decommissioning Progress
-------- ---------- -------- ---------- ------------ --------------- --------
Mayo Plant 745 83.83% $ 460,026 $ 230,630 $ - $ 7,116
Harris Plant 860 83.83% 3,154,183 1,321,694 93,637 14,416
Brunswick Plant 1,631 81.67% 1,427,842 828,480 339,945 41,455
Roxboro Unit No. 4 700 87.06% 309,032 126,007 - 7,881
In the tables above, plant investment and accumulated depreciation are not
reduced by the regulatory disallowances related to the Harris Plant.
28
16. 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 and Comprehensive Income for years ended December 31,
are as follows (in thousands):
2002 2001 2000
--------- --------- ---------
Other income
Net financial trading gain (loss) $ (1,942) $ 3,262 $ 15,603
Net energy purchased for resale gain 1,248 3,074 2,132
Nonregulated energy and delivery services income 11,816 11,528 23,996
Investment gains 22,218 2,500 6,722
AFUDC equity 6,432 8,764 14,502
Other 19,891 12,963 11,594
--------- --------- ---------
Total other income $ 59,663 $ 42,091 $ 74,549
--------- --------- ---------
Other expense
Nonregulated energy and delivery services expenses 13,625 21,352 23,554
Donations 7,594 11,045 9,219
Investment losses 14,389 4,365 6,672
Other 11,298 9,484 18,015
--------- --------- --------
Total other expense $ 46,906 $ 46,246 $ 57,460
--------- --------- ---------
Other, net $ 12,757 $(4,155) $ 17,089
========= ========= =========
Net financial trading gain (loss) represents non-asset-backed trades of
electricity and gas. 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.
17. Accumulated Other Comprehensive Loss
Components of accumulated other comprehensive loss are as follows (in
thousands):
2002 2001
---------- ---------
Loss on cash flow hedges $ (9,379) $ (7,046)
Minimum pension liability adjustments (73,390) -
---------- ---------
Total accumulated other comprehensive loss $ (82,769) $ (7,046)
========== =========
18. Commitments and Contingencies
A. Fuel and Purchased Power
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between CP&L and Power Agency, CP&L is obligated to purchase a percentage of
Power Agency's ownership capacity of, and energy from, the Harris Plant. In
1993, CP&L and Power Agency entered into an agreement to restructure
portions of their contracts covering power supplies and interests in jointly
owned units. Under the terms of the 1993 agreement, CP&L increased the
amount of capacity and energy purchased from Power Agency's ownership
interest in the Harris Plant, and the buyback period was extended six years
through 2007. The estimated minimum annual payments for these purchases,
which reflect capacity costs, total approximately $32 million. These
contractual purchases totaled $35.9 million, $33.3 million and $33.9 million
for 2002, 2001 and 2000, respectively. In 1987, the NCUC ordered CP&L to
reflect the recovery of the capacity portion of these costs on a levelized
basis over the original 15-year buyback period, thereby deferring for future
recovery the difference between such costs and amounts collected through
rates. In 1988, the SCPSC ordered similar treatment, but with a 10-year
levelization period. At December 31, 2002 and 2001, CP&L had deferred
purchased capacity costs, including carrying costs accrued on the deferred
balances, of $16.9 million and $32.5 million, respectively. Increased
purchases (which are not being deferred for future recovery) resulting from
the 1993 agreement with Power Agency were approximately $32.2 million, $28.6
million and $26.0 million for 2002, 2001 and 2000, respectively.
29
CP&L has a long-term agreement for the purchase of power and related
transmission services from Indiana Michigan Power Company's Rockport Unit
No. 2 (Rockport). The agreement provides for the purchase of 250 megawatts
of capacity through 2009 with estimated minimum annual payments of
approximately $31 million, representing capital-related capacity costs.
Total purchases (including transmission use charges) under the Rockport
agreement amounted to $58.6 million, $62.8 million and $61.0 million for
2002, 2001 and 2000, respectively.
Effective June 1, 2001, CP&L executed a long-term agreement for the purchase
of power from Skygen Energy LLC's Broad River facility (Broad River). The
agreement provides for the purchase of approximately 500 megawatts of
capacity through 2021 with an original minimum annual payment of
approximately $16 million, primarily representing capital-related capacity
costs. A separate long-term agreement for additional power from Broad River
commenced June 1, 2002. This agreement provided for the additional purchase
of approximately 300 megawatts of capacity through 2022 with an original
minimum annual payment of approximately $16 million representing
capital-related capacity costs. Total purchases under the Broad River
agreements amounted to $37.7 million and $21.2 million in 2002 and 2001,
respectively.
CP&L has various pay-for-performance purchased power contracts with certain
cogenerators (qualifying facilities) for approximately 300 megawatts of
capacity expiring at various times through 2009. These purchased power
contracts generally provide for capacity and energy payments. Payments for
both capacity and energy are contingent upon the qualifying facilities'
ability to generate. Payments made under these contracts were $144.5 million
in 2002, $145.1 million in 2001 and $168.4 million in 2000.
CP&L has entered into various long-term contracts for coal, gas and oil
requirements of its generating plants. Total payments under these
commitments were $694.0 million, $675.2 million and $558.9 million in 2002,
2001 and 2000, respectively. Estimated annual payments for firm commitments
of fuel purchases and transportation costs under these contracts are
approximately $499.7 million, $434.0 million, $351.1 million, $312.1 million
and $199.0 million for 2003 through 2007, respectively.
B. Guarantees
As a part of normal business, CP&L enters into various agreements providing
financial or performance assessments to third parties. Such agreements
include, for example, guarantees, stand-by 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.
At December 31, 2002 and 2001, outstanding guarantees consisted of the
following (in millions):
December 31, 2002 December 31, 2001
----------------- -----------------
Standby letters of credit $ 4.7 $ 4.9
Surety bonds 0.6 2.0
----------------- -----------------
Total $ 5.3 $ 6.9
================= =================
Stand-by Letters of Credit
CP&L has issued stand-by letters of credit to financial institutions for the
benefit of third parties that have extended credit to CP&L 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 interest payments on outstanding debt obligations. 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 CP&L. Any amounts owed by its
subsidiaries are reflected in the Consolidated Balance Sheets.
Surety Bonds
At December 31, 2002, CP&L had $0.6 million in surety bonds purchased
primarily for purposes such as providing worker compensation coverage and
obtaining licenses, permits and rights-of-way. To the extent liabilities are
incurred, as a result of the activities covered by the surety bonds, such
liabilities are included in the Consolidated Balance Sheets.
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As of December 31, 2002, management does not believe conditions are likely
for performance under these agreements.
C. Insurance
CP&L is a member of Nuclear Electric Insurance Limited (NEIL), which
provides primary and excess insurance coverage against property damage to
members' nuclear generating facilities. Under the primary program, CP&L is
insured for $500 million at each of its nuclear plants. In addition to
primary coverage, NEIL also provides decontamination, premature
decommissioning and excess property insurance with limits of $2.0 billion on
the Brunswick and Harris Plants and $1.1 billion on the Robinson Plant.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. CP&L is insured thereunder, following a
twelve-week deductible period, for 52 weeks in the amount of $3.5 million
per week at each of the nuclear units. An additional 110 weeks of coverage
is provided at 80% of the above weekly amount. For the current policy
period, CP&L is subject to retrospective premium assessments of up to
approximately $24.1 million with respect to the primary coverage, $25.7
million with respect to the decontamination, decommissioning and excess
property coverage, and $17.4 million for the incremental replacement power
costs coverage, in the event covered losses at insured facilities exceed
premiums, reserves, reinsurance and other NEIL resources. Pursuant to
regulations of the Nuclear Regulatory Commission (NRC), CP&L's property
damage insurance policies provide that all proceeds from such insurance be
applied, first, to place the plant in a safe and stable condition after an
accident and, second, to decontaminate, before any proceeds can be used for
decommissioning, plant repair or restoration. CP&L is responsible to the
extent losses may exceed limits of the coverage described above.
CP&L is insured against public liability for a nuclear incident up to $9.55
billion per occurrence. Under the current provisions of the Price Anderson
Act, which limits liability for accidents at nuclear power plants, CP&L, as
an owner of nuclear units, can be assessed for 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), CP&L would be subject to pro rata assessments of up to
$88.1 million for each reactor owned per occurrence. Payment of such
assessments would be made over time as necessary to limit the payment in any
one year to no more than $10 million per reactor owned. Congress is expected
to approve revisions to the Price Anderson Act in the first quarter of 2003,
that will include increased limits and assessments per reactor owned. The
final outcome of this matter cannot be predicted at this time.
There have been recent revisions made to the nuclear property and nuclear
liability insurance policies regarding the maximum recoveries available for
multiple terrorism occurrences. Under the NEIL policies, if there were
multiple terrorism losses occurring within one year after the first loss
from terrorism, NEIL would make available one industry aggregate limit of
$3.2 billion, along with any amounts it recovers from reinsurance,
government indemnity or other sources up to the limits for each claimant. If
terrorism losses occurred beyond the one-year period, a new set of limits
and resources would apply. For nuclear liability claims arising out of
terrorist acts, the primary level available through commercial insurers is
now subject to an industry aggregate limit of $300 million. The second level
of coverage obtained through the assessments discussed above would continue
to apply to losses exceeding $300 million and would provide coverage in
excess of any diminished primary limits due to the terrorist acts aggregate.
CP&L self-insures its transmission and distribution lines against loss due
to storm damage and other natural disasters.
D. Claims and Uncertainties
1. CP&L is subject to federal, state and local regulations addressing
hazardous and solid waste management, air and water quality and other
environmental matters.
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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
CP&L has some connection. In this regard, CP&L 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) and the
North Carolina Department of Environment and Natural Resources, Division of
Waste Management (DWM). In addition, CP&L 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 associated with CP&L that
have required or are anticipated to require investigation and/or remediation
costs. CP&L received insurance proceeds to address costs associated with
CP&L environmental liabilities related to its involvement with MGP sites.
All eligible expenses related to these are charged against a specific fund
containing these proceeds. As of December 31, 2002, approximately $8.0
million remains in this centralized fund with a related accrual of $8.0
million recorded for the associated expenses of environmental issues. As
CP&L's share of costs for investigating and remediating these sites become
known, the fund is assessed to determine if additional accruals will be
required. CP&L 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. CP&L 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, CP&L will accrue costs for the sites to the extent its liability
is probable and the costs can be reasonably estimated. Presently, CP&L
cannot determine the total costs that may be incurred in connection with the
remediation of all sites. According to current information, these future
costs at the CP&L sites are not expected to be material to CP&L's financial
condition or results of operations. A rollforward of the balance in this
fund is not provided due to the immateriality of this activity in the
periods presented.
CP&L 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.
CP&L is also currently in the process of assessing potential costs and
exposures at other environmentally impaired sites. As the assessments are
developed and analyzed, CP&L 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 CP&L'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, CP&L cannot predict the
outcome of this matter.
32
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.
CP&L was asked to provide information to the EPA as part of this initiative
and cooperated in providing the requested information. The EPA initiated
civil enforcement actions against other unaffiliated utilities as part of
this initiative. Some of these actions resulted in settlement agreements
calling for expenditures, 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. CP&L cannot predict the
outcome of this matter.
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. CP&L 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 CP&L's results of operations. Further
controls are anticipated as electricity demand increases. CP&L 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 CP&L 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 above. However, further technical analysis
and rulemaking may result in a requirement for additional controls at some
units. CP&L 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 126 petitions. CP&L, 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 CP&L 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 indicated it will rescind the Section 126 rule in a future
rule making. CP&L 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. CP&L expects its capital costs
to meet these emission targets will be approximately $813 million by 2013.
CP&L 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, CP&L entered into an agreement with the state of
North Carolina to transfer to the state all future emissions allowances it
generates from over-complying with the new federal emission limits when
these units are completed. The new law also requires the state to undertake
a study of mercury and carbon dioxide emissions in North Carolina. CP&L
cannot predict the future regulatory interpretation, implementation or
impact of this new law.
33
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 CP&L's financials and operations if associated
costs cannot be recovered from customers. CP&L favors the voluntary program
approach recommended by the administration, and is evaluating options for
the reduction, avoidance, and sequestration of greenhouse gases. However,
CP&L 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. EPA is currently 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 CP&L's financials and operations. However,
CP&L cannot predict the outcome of this matter.
2. CP&L, like other electric power companies in North Carolina, pays a
franchise tax levied by the state pursuant to North Carolina General
Statutes ss. 105-116, a state-level annual franchise tax (State Franchise
Tax). Part of the revenue generated by the State Franchise Tax is required
by North Carolina General Statutes ss. 105-116.1(b) to be distributed to
North Carolina cities in which CP&L maintains facilities. CP&L has paid and
continues to pay the State Franchise Tax to the state when such taxes are
due. However, pursuant to an Executive Order issued on February 5, 2002, by
the Governor of North Carolina, the Secretary of Revenue withheld
distributions of State Franchise Tax revenues to cities for two quarters of
fiscal year 2001-2002 in an effort to balance the state's budget.
In response to the state's failure to distribute the State Franchise Tax
proceeds, certain cities in which CP&L maintains facilities adopted
municipal franchise tax ordinances purporting to impose on CP&L a local
franchise tax. The local taxes are intended to be collected for as long as
the state withholds distribution of the State Franchise Tax proceeds from
the cities. The first local tax payments were due August 15, 2002. On August
2, 2002, CP&L filed a lawsuit against the cities seeking to enjoin the
enforcement of the local taxes and to have the local ordinances struck down
because the ordinances are beyond the cities' statutory authority and
violate provisions of the North Carolina and United States Constitutions.
On September 14, 2002, the Governor of North Carolina signed into law a
provision that prevents cities and counties from levying local franchise
taxes on electric utilities. This new legislation makes the lawsuit CP&L
filed in August against certain cities that were seeking to enforce local
franchise tax ordinances moot. As a result of the enactment of this
legislation, the parties have agreed to an Order of Dismissal by Consent,
which has been signed by the judge and filed with the Clerk of Court in
Caswell County.
3. As required under the Nuclear Waste Policy Act of 1982, CP&L 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.
34
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 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. In a recent decision, 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. CP&L is in the process of evaluating whether it should file
a similar action for damages.
CP&L also continues to monitor legislation that has been introduced in
Congress which might provide some limited relief. CP&L cannot predict the
outcome of this matter.
With certain modifications and additional approval by the NRC, CP&L'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 to
the expiration of these licenses, dry storage may be necessary. CP&L
obtained NRC approval to use additional storage space at the Harris Plant in
December 2000.
4. CP&L is involved in various litigation matters in the ordinary course of
business, some of which involve substantial amounts. Where appropriate,
accruals have been made in accordance with SFAS No. 5, "Accounting for
Contingencies," to provide for such matters. In the opinion of management,
the final disposition of pending litigation would not have a material
adverse effect on CP&L's consolidated results of operations or financial
position.
35