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 26, 1999
CAROLINA POWER & LIGHT COMPANY
(Exact name of registrant as specified in its charter)
North Carolina 1-3382 56-0165465
- --------------------------------------------------------------------------------
(State or Other (Commission (IRS Employer
jurisdiction of File Number) Identification No.)
incorporation)
411 Fayetteville Street, Raleigh, North Carolina 27601-1748
- --------------------------------------------------------------------------------
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: (919) 546-6111
--------------
Item 7 Financial Statements and Exhibits
Page No.
--------
Independent Auditors' Report 3
Financial Statements:
Consolidated Statements of Income for the Years Ended 4
December 31, 1998, 1997 and 1996
Consolidated Balance Sheets as of December 31, 1998 and 1997 5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 6
and 1996
Consolidated Schedules of Capitalization as of December 31, 1998 and 1997 7
Consolidated Statements of Retained Earnings for the Years Ended December 31, 8
1998, 1997 and 1996
Consolidated Quarterly Financial Data (Unaudited) 8
Notes to Consolidated Financial Statements 9
Exhibits:
(23) - Independent Auditors' Consent 23
(27) - Financial Data Schedule 24
2
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF CAROLINA POWER & LIGHT COMPANY:
We have audited the accompanying consolidated balance sheets and schedules of
capitalization of Carolina Power & Light Company and subsidiaries as of December
31, 1998 and 1997, and the related consolidated statements of income, retained
earnings and cash flows for each of the three years in the period ended December
31, 1998. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 the Company and subsidiaries at
December 31, 1998 and 1997, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 9, 1999
3
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31
(IN THOUSANDS EXCEPT PER SHARE DATA) 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES $3,130,045 $3,024,089 $2,995,715
- ----------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Fuel 571,419 534,268 515,050
Purchased power 382,547 387,296 412,554
Other operation and maintenance 642,478 661,466 730,140
Depreciation and amortization 487,097 481,650 386,927
Taxes other than on income 141,504 139,478 140,479
Harris Plant deferred costs, net 7,489 24,296 26,715
- ----------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,232,534 2,228,454 2,211,865
- ----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 897,511 795,635 783,850
- ----------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Diversified business operations (70,345) (25,278) (4,729)
Interest income 9,526 18,335 4,063
Harris Plant carrying costs 3,785 4,626 7,299
Other, net (9,509) 6,003 42,080
- ----------------------------------------------------------------------------------------------------------------------
Total other income (expense) (66,543) 3,686 48,713
- ----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES AND INCOME TAXES 830,968 799,321 832,563
- ----------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES
Long-term debt 169,901 163,468 172,622
Other interest charges 11,156 18,743 19,155
Allowance for borrowed funds used during construction (6,821) (4,923) (6,407)
- ----------------------------------------------------------------------------------------------------------------------
Total interest charges, net 174,236 177,288 185,370
- ----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 656,732 622,033 647,193
INCOME TAXES 257,494 233,716 255,916
- ----------------------------------------------------------------------------------------------------------------------
NET INCOME $399,238 $388,317 $391,277
- ----------------------------------------------------------------------------------------------------------------------
PREFERRED STOCK DIVIDEND REQUIREMENTS (2,967) (6,052) (9,609)
- ----------------------------------------------------------------------------------------------------------------------
EARNINGS FOR COMMON STOCK $396,271 $382,265 $381,668
- ----------------------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING 143,941 143,645 143,621
- ----------------------------------------------------------------------------------------------------------------------
BASIC AND DILUTED EARNINGS PER COMMON SHARE $2.75 $2.66 $2.66
- ----------------------------------------------------------------------------------------------------------------------
DIVIDENDS DECLARED PER COMMON SHARE $1.955 $1.895 $1.835
- ----------------------------------------------------------------------------------------------------------------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
4
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS) DECEMBER 31
ASSETS 1998 1997
- -------------------------------------------------------------------------------------------------------
Electric utility plant
Electric utility plant in service $10,280,638 $10,113,334
Accumulated depreciation (4,496,632) (4,181,417)
- -------------------------------------------------------------------------------------------------------
Electric utility plant in service, net 5,784,006 5,931,917
Held for future use 11,984 12,255
Construction work in progress 306,866 158,347
Nuclear fuel, net of amortization 196,684 190,991
- -------------------------------------------------------------------------------------------------------
Total electric utility plant, net 6,299,540 6,293,510
- -------------------------------------------------------------------------------------------------------
Current assets
Cash and cash equivalents 28,872 14,426
Accounts receivable 406,418 406,872
Fuel 78,086 47,551
Materials and supplies 146,615 136,253
Deferred fuel cost 42,647 20,630
Prepayments 63,809 62,040
Other current assets 34,409 47,034
- -------------------------------------------------------------------------------------------------------
Total current assets 800,856 734,806
- -------------------------------------------------------------------------------------------------------
Deferred debits and other assets
Income taxes recoverable through future rates 277,894 328,818
Abandonment costs 16,083 38,557
Harris Plant deferred costs 60,021 63,727
Unamortized debt expense 27,010 48,407
Nuclear decommissioning trust funds 310,702 245,523
Miscellaneous other property and investments 294,678 212,291
Other assets and deferred debits 260,622 211,089
- -------------------------------------------------------------------------------------------------------
Total deferred debits and other assets 1,247,010 1,148,412
- -------------------------------------------------------------------------------------------------------
Total assets $ 8,347,406 $ 8,176,728
- -------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
- -------------------------------------------------------------------------------------------------------
CAPITALIZATION (SEE CONSOLIDATED SCHEDULES OF
CAPITALIZATION)
- -------------------------------------------------------------------------------------------------------
Common stock equity $ 2,949,305 $ 2,818,807
Preferred stock - redemption not required 59,376 59,376
Long-term debt, net 2,614,414 2,415,656
- -------------------------------------------------------------------------------------------------------
Total capitalization 5,623,095 5,293,839
- -------------------------------------------------------------------------------------------------------
Current liabilities
Current portion of long-term debt 53,172 207,979
Accounts payable 265,163 246,352
Interest accrued 39,941 43,620
Dividends declared 74,400 72,266
Other current liabilities 108,824 116,609
- -------------------------------------------------------------------------------------------------------
Total current liabilities 541,500 686,826
- -------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities
Accumulated deferred income taxes 1,678,924 1,722,908
Accumulated deferred investment tax credits 211,822 222,028
Other liabilities and deferred credits 292,065 251,127
- -------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,182,811 2,196,063
- -------------------------------------------------------------------------------------------------------
Commitments and contingencies (Note 12)
- -------------------------------------------------------------------------------------------------------
Total capitalization and liabilities $ 8,347,406 $ 8,176,728
- -------------------------------------------------------------------------------------------------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
5
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31
(IN THOUSANDS) 1998 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------------
Operating activities
Net income $399,238 $388,317 $391,277
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 578,348 565,212 446,508
Harris Plant deferred costs 3,704 19,670 19,416
Deferred income taxes (38,517) (66,546) 130,818
Investment tax credit (10,205) (10,232) (10,445)
Deferred fuel credit (22,017) (24,969) (23,156)
Net increase in receivables, inventories and prepaid expenses (62,351) (111,216) (64,793)
Net increase (decrease) in payables and accrued expenses 15,863 (6,414) 4,671
Miscellaneous 56,329 59,191 17,911
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 920,392 813,013 912,207
- -----------------------------------------------------------------------------------------------------------------------------------
Investing activities
Gross property additions (424,263) (322,205) (369,308)
Nuclear fuel additions (102,511) (61,509) (87,265)
Contributions to nuclear decommissioning trust (30,848) (30,726) (30,683)
Contributions to retiree benefit trusts - (21,096) (24,700)
Net cash flow of company-owned life insurance program (1,954) 138,508 46,930
Investments in non-electric activities (103,543) (54,733) (28,035)
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (663,119) (351,761) (493,061)
- -----------------------------------------------------------------------------------------------------------------------------------
Financing activities
Proceeds from issuance of long-term debt 6,255 199,075 -
Net decrease in short-term debt (maturity less than 90 days) - (62,224) (8,858)
Net increase (decrease) in commercial paper classified as long-term debt (Note 4) 242,100 (104,100) 350,000
Retirement of long-term debt (208,050) (103,410) (467,810)
Redemption of preferred stock - (85,850) -
Purchase of Company common stock - (23,418) (25,208)
Dividends paid on common and preferred stock (282,684) (277,840) (270,818)
Miscellaneous (448) - -
- -----------------------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (242,827) (457,767) (422,694)
- -----------------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents 14,446 3,485 (3,548)
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 14,426 10,941 14,489
- -----------------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 28,872 $ 14,426 $ 10,941
- -----------------------------------------------------------------------------------------------------------------------------------
Supplemental disclosures of cash flow information
Cash paid during the year - interest $179,526 $171,511 $194,391
income taxes $329,739 $289,693 $141,350
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
6
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED SCHEDULES OF CAPITALIZATION
DECEMBER 31
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1998 1997
----------------------------------------------------------------------------------------------------------------------------------
Common stock equity
Common stock without par value, authorized 200,000,000 shares, issued and
outstanding 151,337,503 and 151,340,394 shares, respectively (Note 8) $1,374,773 $1,371,520
Unearned ESOP common stock (152,979) (165,804)
Capital stock issuance expense (790) (790)
Retained earnings (Note 6) 1,728,301 1,613,881
----------------------------------------------------------------------------------------------------------------------------------
Total common stock equity $2,949,305 $2,818,807
----------------------------------------------------------------------------------------------------------------------------------
Cumulative preferred stock, without par value
(entitled to $100 a share plus accumulated dividends in the event of
liquidation; outstanding shares are as of December 31, 1998)
----------------------------------------------------------------------------------------------------------------------------------
Preferred stock - redemption not required:
Authorized - 300,000 shares $5.00 Preferred Stock; 20,000,000 shares
Serial Preferred Stock
$5.00 Preferred - 237,259 shares outstanding (redemption price $110.00) $ 24,376 $ 24,376
4.20 Serial Preferred - 100,000 shares outstanding (redemption price $102.00) 10,000 10,000
5.44 Serial Preferred - 250,000 shares outstanding (redemption price $101.00) 25,000 25,000
----------------------------------------------------------------------------------------------------------------------------------
Total preferred stock - redemption not required $59,376 $59,376
----------------------------------------------------------------------------------------------------------------------------------
Long-term debt (interest rates are as of December 31, 1998) First mortgage
bonds:
5.375% and 6.875% due 1998 $ - $140,000
6.125% due 2000 150,000 150,000
6.75% due 2002 100,000 100,000
5.875% and 7.875% due 2004 300,000 300,000
6.80% due 2007 200,000 200,000
6.875% to 8.625% due 2021-2023 500,000 500,000
First mortgage bonds - secured medium-term notes:
5.00% to 5.06% due 1998 - 65,000
7.15% due 1999 50,000 50,000
First mortgage bonds - pollution control series:
6.30% to 6.90% due 2009-2014 93,530 93,530
3.399% and 3.55% due 2024 122,600 122,600
----------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 1,516,130 1,721,130
----------------------------------------------------------------------------------------------------------------------------------
Other long-term debt:
Pollution control obligations backed by letter of credit, 2.982% to 5.350% due 2014-2017 442,000 442,000
Other pollution control obligations, 4.10% due 2019 55,640 55,640
Unsecured subordinated debentures, 8.55% due 2025 125,000 125,000
Commercial paper reclassified to long-term debt (Note 4) 488,000 245,900
Miscellaneous notes 56,691 53,486
----------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 1,167,331 922,026
----------------------------------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net (15,875) (19,521)
Current portion of long-term debt (53,172) (207,979)
----------------------------------------------------------------------------------------------------------------------------------
Total long-term debt, net $2,614,414 $2,415,656
----------------------------------------------------------------------------------------------------------------------------------
Total capitalization $5,623,095 $5,293,839
----------------------------------------------------------------------------------------------------------------------------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
7
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
YEARS ENDED DECEMBER 31
(IN THOUSANDS EXCEPT PER SHARE DATA) 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------------------
Retained earnings at beginning of year $ 1,613,881 $1,503,658 $1,385,378
Net income 399,238 388,317 391,277
Preferred stock dividends at stated rates (2,967) (4,627) (9,609)
Common stock dividends at annual per share rate of
$1.955, $1.895 and $1.835, respectively (281,851) (272,011) (263,388)
Other adjustments - (1,456) -
- ---------------------------------------------------------------------------------------------------------------------------
Retained earnings at end of year $1,728,301 $1,613,881 $1,503,658
- ---------------------------------------------------------------------------------------------------------------------------
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
(IN THOUSANDS EXCEPT PER SHARE DATA) FIRST QUARTER SECOND THIRD QUARTER FOURTH
QUARTER QUARTER
- ----------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1998
Operating revenues $752,296 $736,151 $946,188 $695,410
Operating income 207,688 171,734 363,088 155,001
Net income 86,571 65,469 186,024 61,174
Common stock data:
Basic earnings per common share .60 .45 1.29 .42
Diluted earnings per common share .60 .45 1.28 .42
Dividend paid per common share .485 .485 .485 .485
Price per share - high 45 3/4 45 1/2 46 5/8 49 1/16
low 40 5/8 39 1/2 39 15/16 45 1/16
- ----------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1997
Operating revenues $716,084 $666,023 $906,841 $735,141
Operating income 183,791 108,824 326,494 176,526
Net income 82,262 54,289 167,829 83,937
Common stock data:
Basic and diluted earnings per common share .56 .37 1.15 .58
Dividend paid per common share .470 .470 .470 .470
Price per share - high 37 7/8 36 1/4 36 5/8 42 1/2
low 36 1/8 33 33 3/4 34 5/16
- ----------------------------------------------------------------------------------------------------------------------------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Basis of Presentation
a. Organization
Carolina Power & Light Company (the Company) is a public service corporation
primarily engaged in the generation, transmission, distribution and sale of
electricity in portions of North and South Carolina. The Company has no other
material segments of business. At December 31, 1998 and 1997, the total assets
of the Company's non-electric segments were $210 million and $97 million,
respectively. Revenues from external customers for the non-electric segments
were $62 million, $19 million and $4 million for 1998, 1997 and 1996,
respectively; those revenues are included in the results reported as diversified
business operations.
b. Basis of Presentation
The consolidated financial statements are prepared in accordance with generally
accepted accounting principles. The accounting records of the Company are
maintained in accordance with uniform systems of accounts prescribed by the
Federal Energy Regulatory Commission, the North Carolina Utilities Commission
(NCUC) and the South Carolina Public Service Commission (SCPSC). Certain amounts
for 1997 and 1996 have been reclassified to conform to the 1998 presentation,
with no effect on previously reported net income or common stock equity.
2. NCNG Merger
On November 10, 1998, the Company and North Carolina Natural Gas Corporation
(NCNG) entered into an Agreement and Plan of Merger (Merger Agreement),
providing for the strategic business combination of the Company and NCNG in a
stock-for-stock transaction. Upon consummation of the proposed merger, NCNG will
be a wholly owned subsidiary of the Company. The Company will issue
approximately $354 million in stock to NCNG shareholders to complete the merger.
The merger transaction is intended to constitute a tax-free reorganization for
federal income tax purposes and to be accounted for as a pooling-of-interests.
The Merger Agreement has been approved by the Boards of Directors of the Company
and NCNG, and consummation of the merger is expected in mid-1999. There are
certain closing conditions, including approval by the shareholders of NCNG and
certain regulatory agencies, and the filing of notifications required by the
Hart-Scott-Rodino Antitrust Improvements Act of 1976. The Company and NCNG filed
a joint application for approval of the merger with the NCUC on January 11,
1999. The Company filed a similar request with the SCPSC on February 9, 1999.
3. Summary of Significant Accounting Policies
a. Principles of Consolidation
The consolidated financial statements include the activities of the Company and
its majority-owned subsidiaries. These subsidiaries have invested in areas such
as communications technology, energy-management services and affordable housing.
Significant intercompany balances and transactions have been eliminated.
b. Use of Estimates and Assumptions
In preparing financial statements that conform with generally accepted
accounting principles, management must make estimates and assumptions that
affect the reported amounts of assets and liabilities, disclosure of contingent
assets and liabilities at the date of the financial statements and amounts of
revenues and expenses reflected during the reporting period. Actual results
could differ from those estimates.
9
c. Electric Utility Plant
The cost of additions, including betterments and replacements of units of
property, is charged to electric utility plant. Maintenance and repairs of
property, and replacements and renewals of items determined to be less than
units of property, are charged to maintenance expense. 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 subject to the lien of the Company's mortgage.
The balances of electric utility plant in service at December 31 are listed
below (in millions):
1998 1997
------- -------
Production plant $6,295 $6,297
Transmission plant 987 952
Distribution plant 2,470 2,327
General plant and other 529 537
------- -------
Electric utility plant in service $10,281 $10,113
======= =======
As prescribed in regulatory uniform systems of accounts, an allowance for the
cost of borrowed and equity funds used to finance electric utility plant
construction (AFUDC) is charged to the cost of plant. Regulatory authorities
consider AFUDC an appropriate charge for inclusion in the Company's utility
rates to customers over the service life of the property. The equity funds
portion of AFUDC is credited to other income and the borrowed funds portion is
credited to interest charges. The composite AFUDC rate was 5.6% in both 1998 and
1997, and 5.8% in 1996.
d. Depreciation and Amortization
For financial reporting purposes, depreciation of electric 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 3e), as a
percent of average depreciable property other than nuclear fuel, were
approximately 3.9% in 1998, 1997 and 1996. Depreciation provisions totaled
$394.4 million, $382.1 million and $363.2 million in 1998, 1997 and 1996,
respectively.
Depreciation and amortization expense also includes amortization of deferred
operation and maintenance expenses associated with Hurricane Fran, which struck
significant portions of the Company's service territory in September 1996. In
1996, the NCUC authorized the Company to defer these expenses (approximately $40
million) with amortization over a 40-month period.
Pursuant to authorizations from the NCUC and the SCPSC, the Company began to
accelerate the amortization of certain regulatory assets over a three-year
period beginning January 1997. The accelerated amortization of these regulatory
assets results in additional depreciation and amortization expenses of
approximately $68 million in each year of the three-year period. Depreciation
and amortization expense also includes amortization of plant abandonment costs
(see Note 7c).
Amortization of nuclear fuel costs, including disposal costs associated with
obligations to the U.S. Department of Energy (DOE), is computed primarily on the
unit-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.
10
e. Nuclear Decommissioning
In the Company'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 jurisdiction, the provisions for
nuclear decommissioning costs are based on amounts agreed upon in applicable
rate agreements. Decommissioning cost provisions, which are included in
depreciation and amortization expense, were $33.3 million, $33.2 million and
$33.1 million in 1998, 1997 and 1996, respectively.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were $496.3 million and $428.7 million at December 31, 1998 and
1997, respectively. These costs include amounts retained internally and amounts
funded in an external decommissioning trust. The balance of the nuclear
decommissioning trust was $310.7 million and $245.5 million at December 31, 1998
and 1997, respectively. 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. Based on the site-specific estimates discussed
below, and using an assumed after-tax earnings rate of 7.75% and an assumed cost
escalation rate of 4%, current levels of rate recovery for nuclear
decommissioning costs are adequate to provide for decommissioning of the
Company's nuclear facilities.
The Company'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 $279.8 million for Robinson Unit No. 2, $299.3 million for
Brunswick Unit No. 1, $298.5 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 the Company's nuclear units expire in the year 2010 for
Robinson Unit No. 2, 2016 for Brunswick Unit No. 1, 2014 for Brunswick Unit No.
2 and 2026 for the Harris Plant.
The Financial Accounting Standards Board is proceeding with its project
regarding accounting practices related to obligations associated with the
retirement of long-lived assets, and an exposure draft of a proposed accounting
standard is expected to be issued during the first half of 1999. It is uncertain
when a final statement will be issued and what effects it may ultimately have on
the Company's accounting for nuclear decommissioning and other retirement costs.
f. Other Policies
Customers' meters are read and bills are rendered on a cycle basis. Revenues are
accrued for services rendered but unbilled at the end of each accounting period.
Fuel expense includes fuel costs or recoveries that are deferred through fuel
clauses established by the Company's regulators. These clauses allow the Company
to recover fuel costs and the fuel component of purchased power costs through
the fuel component of customer rates.
Other property and investments are stated principally at cost. The Company
maintains an allowance for doubtful accounts receivable, which totaled
approximately $13.8 million and $3.4 million at December 31, 1998 and 1997,
respectively. Fuel inventory and materials and supplies inventory are carried on
a first-in, first-out or average cost basis. Long-term debt premiums, discounts
and issuance expenses are amortized over the life of the related debt using the
straight-line method. Any expenses or call premiums associated
11
with the reacquisition of debt obligations are amortized over the remaining life
of the original debt using the straight-line method, except that the balance
existing at December 31, 1996 is being amortized on a three-year accelerated
basis (see Note 7a). The Company considers all highly liquid investments with
original maturities of three months or less to be cash equivalents.
g. New Accounting Standard
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities", (SFAS-133) effective for fiscal years beginning after
June 15, 1999. SFAS-133 establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. It requires the recognition of all
derivative instruments as assets or liabilities in the statement of financial
position and measurement of those instruments at fair value. The accounting
treatment of changes in fair value is dependent upon whether or not an
instrument qualifies as a hedge and, if so, the type of hedge. The Company has
not completed its analysis of the provisions of SFAS-133 nor its effect on the
Company.
4. Revolving Credit Facilities and Commercial Paper
As of December 31, 1998, the Company's revolving credit facilities totaled $750
million, all of which are long-term agreements supporting its commercial paper
borrowings. The Company is required to pay minimal annual commitment fees to
maintain its credit facilities. Consistent with management's intent to maintain
its commercial paper on a long-term basis, and as supported by its long-term
revolving credit facilities, the Company included in long-term debt all
commercial paper outstanding as of December 31, 1998 and 1997, which amounted to
$488.0 million and $245.9 million, respectively. The weighted-average interest
rates of these borrowings were 5.22% and 5.85% at December 31, 1998 and 1997,
respectively.
5. Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents approximate fair value due to
the short maturities of these instruments. The carrying amount of the Company's
long-term debt was $2.70 billion and $2.66 billion at December 31, 1998 and
1997, respectively. The estimated fair value of this debt, as obtained from an
independent pricing service, was $2.80 billion and $2.71 billion at December 31,
1998 and 1997, respectively. There are inherent limitations in any estimation
technique, and these estimates are not necessarily indicative of the amount the
Company could realize in current transactions.
External funds have been established, as required by the Nuclear Regulatory
Commission (NRC), as a mechanism to fund certain costs of nuclear
decommissioning (see Note 3e). 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.
6. Capitalization
As of December 31, 1998, the Company had 20,656,571 shares of authorized but
unissued common stock reserved and available for issuance, primarily to satisfy
the requirements of the Company's stock plans. The Company intends, however, to
meet the requirements of these stock plans with issued and outstanding shares
presently held by the Trustee of the Stock Purchase-Savings Plan or with open
market purchases of common stock shares, as appropriate. In addition, the
Company's Board of Directors has authorized the issuance of shares in
conjunction with the planned merger with NCNG (see Note 2).
The Company's mortgage, as supplemented, and charter contain provisions limiting
the use of retained earnings for the payment of dividends under certain
circumstances. As of December 31, 1998, there were no significant restrictions
on the use of retained earnings.
12
As of December 31, 1998, long-term debt maturities for the years 1999, 2000,
2002 and 2003 amounted to $53 million, $198 million, $100 million and $5
million, respectively, excluding commercial paper reclassified as long-term
debt. There are no long-term debt maturities in 2001.
7. Regulatory Matters
a. Regulatory Assets
As a regulated entity, the Company is subject to the provisions of Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation," (SFAS-71). See Note 12c for additional discussion of
SFAS-71. Accordingly, the Company records certain assets resulting from the
effects of the ratemaking process, which would not be recorded under generally
accepted accounting principles for unregulated entities. At December 31, 1998,
the balances of the Company's regulatory assets were as follows (in millions):
Income taxes recoverable through future rates* $ 278
Harris Plant deferred costs 60
Abandonment costs* 16
Loss on reacquired debt (included in unamortized debt expense)* 21
Deferred fuel 43
Items included in other assets and deferred debits:
Deferred DOE enrichment facilities-related costs 46
Deferred hurricane-related costs 12
Emission allowance carrying costs* 4
-----
Total $ 480
=====
* ALL OR CERTAIN PORTIONS OF THESE REGULATORY ASSETS ARE SUBJECT TO ACCELERATED
AMORTIZATION (SEE NOTE 3D).
b. Retail Rate Matters
A petition was filed in July 1996 by the Carolina Industrial Group for Fair
Utility Rates (CIGFUR) with the NCUC, requesting that the NCUC conduct an
investigation of the Company's base rates or treat its petition as a complaint
against the Company. The petition alleged that the Company's return on equity
(which was authorized by the NCUC in the Company's last general rate proceeding
in 1988) and earnings are too high. In December 1996, the NCUC issued an order
denying CIGFUR's petition and stating that it tentatively found no reasonable
grounds to proceed with CIGFUR's petition as a complaint. Subsequently, CIGFUR
filed a Motion for Reconsideration with the NCUC and a Notice of Appeal with the
North Carolina Court of Appeals, both of which were denied. On December 4, 1998,
a petition for Discretionary Review filed by CIGFUR was denied by the North
Carolina Supreme Court.
In late 1998 and early 1999, the Company filed, and the respective commissions
subsequently approved, proposals in the North and South Carolina retail
jurisdictions to accelerate cost recovery of its nuclear generating assets
beginning January 1, 2000 and continuing through 2004. The accelerated cost
recovery begins immediately after the 1999 expiration of the accelerated
amortization of certain regulatory assets (see Note 3d). Pursuant to the orders,
the Company's depreciation expense for nuclear generating assets will increase
by $106 million to $150 million per year. Recovering the costs of the nuclear
generating assets on an accelerated basis will better position the Company for
the uncertainties associated with potential restructuring of the of the electric
utility industry.
13
c. Plant-Related Deferred Costs
The Company abandoned efforts to complete Mayo Unit No. 2 in March 1987. The
NCUC and SCPSC each allowed the Company to recover the cost of the abandoned
unit over a ten-year period without a return on the unamortized balance. The
cost recovery was substantially completed during 1998.
In the 1988 rate orders, the Company was ordered to remove from rate base and
treat as abandoned plant certain costs related to the Harris Plant. Abandoned
plant amortization related to the 1988 rate orders was completed in 1998 for the
wholesale and North Carolina retail jurisdictions and will be completed in 1999
for the South Carolina retail jurisdiction.
Amortization of plant abandonment costs is included in depreciation and
amortization expense and totaled $24.2 million, $30.8 million and $17.6 million
in 1998, 1997 and 1996, respectively. The unamortized balances of plant
abandonment costs are reported at the present value of future recoveries of
these costs. The associated accretion of the present value was $1.7 million,
$3.5 million and $26.4 million in 1998, 1997 and 1996, respectively, and is
reported in other, net. The accretion for 1996 includes a $22.9 million
adjustment to the unamortized balance of plant abandonment costs related to the
Harris Plant. This adjustment was made to reflect the present value impact of
the shorter recovery period resulting from accelerated amortization of this
asset (see Note 3d).
8. Employee Stock Ownership Plan
The Company sponsors the Stock Purchase-Savings Plan (SPSP) for which
substantially all full-time employees and certain part-time employees are
eligible. The SPSP, which has Company matching and incentive goal features,
encourages systematic savings by employees and provides a method of acquiring
Company common stock and other diverse investments. The SPSP, as amended in
1989, is an employee stock ownership plan (ESOP) that can enter into acquisition
loans to acquire Company common stock to satisfy SPSP common share needs.
Qualification as an ESOP did not change the level of benefits received by
employees under the SPSP. Common stock acquired with the proceeds of an ESOP
loan is held by the SPSP 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 participant contributions, Company matching
and incentive contributions and/or reinvested dividends. All or a portion of the
dividends paid on ESOP suspense shares and on ESOP shares allocated to
participants may be used to repay ESOP acquisition loans. To the extent used to
repay such loans, the dividends are deductible for income tax purposes.
There were 6,953,612 ESOP suspense shares at December 31, 1998, with a fair
value of $327.3 million. ESOP shares allocated to plan participants totaled
12,416,040 at December 31, 1998. The Company has a long-term note receivable
from the SPSP Trustee related to the purchase of common stock from the Company
in 1989. The balance of the note receivable from the SPSP Trustee is included in
the determination of unearned ESOP common stock, which reduces common stock
equity. ESOP shares that have not been committed to be released to participants'
accounts are not considered outstanding for the determination of earnings per
common share. Interest income on the note receivable and dividends on
unallocated ESOP shares are not recognized for financial statement purposes.
9. Postretirement Benefit Plans
The Company has a noncontributory defined benefit retirement (pension) plan for
substantially all full-time employees.
14
The components of net periodic pension cost are (in thousands):
1998 1997 1996
--------- -------- --------
Actual return on plan assets $ (87,382) $(110,346) $ (76,347)
Variance from expected return,
deferred 17,462 57,368 27,056
--------- -------- --------
Expected return on plan assets (69,920) (52,978) (49,291)
Service cost 18,357 18,643 19,257
Interest cost 45,877 42,468 39,505
Amortization of transition obligation 106 106 106
Amortization of prior service cost (benefit) (158) 967 724
Amortization of actuarial gain (6,440) (36) (364)
--------- -------- --------
Net periodic pension cost (benefit) $ (12,178) $ 9,170 $ 9,937
========= ======== ========
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):
1998 1997
--------- ---------
Pension obligation
Pension obligation at January 1 $ 598,160 $ 558,688
Interest cost 45,877 42,468
Service cost 18,357 18,643
Benefit payments (25,466) (25,557)
Actuarial loss 77,785 3,918
Plan amendments (36,503) -
--------- ---------
Pension obligation at December 31 678,210 598,160
Fair value of plan assets at December 31 830,213 768,297
--------- ---------
Funded status 152,003 170,137
Unrecognized transition obligation 688 793
Unrecognized prior service cost (benefit) (25,429) 10,916
Unrecognized actuarial gain (145,657) (212,419)
--------- ---------
Accrued pension obligation at December 31 $ (18,395) $ (30,573)
========= =========
15
Reconciliations of the fair value of pension plan assets are (in thousands):
1998 1997
--------- ---------
Fair value of plan assets at January 1 $ 768,297 $ 683,508
Actual return on plan assets 87,382 110,346
Benefit payments (25,466) (25,557)
--------- ---------
Fair value of plan assets at December 31 $ 830,213 $ 768,297
========= =========
The weighted-average discount rate used to measure the pension obligation was
7.0% in 1998 and 7.75% in 1997. The assumed rate of increase in future
compensation used to measure the pension obligation was 4.20% in both 1998 and
1997. The expected long-term rate of return on pension plan assets used in
determining the net periodic pension cost was 9.25% in 1998, 1997 and 1996.
In addition to pension benefits, the Company provides contributory
postretirement benefits (OPEB), including certain health care and life insurance
benefits, for substantially all retired employees.
The components of net periodic OPEB cost are (in thousands):
1998 1997 1996
-------- -------- --------
Actual return on plan assets $ (3,877) $ (4,628) $ (2,656)
Variance from expected return,
deferred 785 2,186 726
-------- -------- --------
Expected return on plan assets (3,092) (2,442) (1,930)
Service cost 7,182 7,988 8,412
Interest cost 13,402 11,065 10,629
Amortization of transition obligation 5,641 5,889 5,889
Amortization of actuarial gain (549) -- --
-------- -------- --------
Net periodic OPEB cost $ 22,584 $ 22,500 $ 23,000
======== ======== ========
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):
16
1998 1997
--------- ---------
OPEB obligation
OPEB obligation at January 1 $ 181,324 $ 164,487
Interest cost 13,402 11,065
Service cost 7,182 7,988
Benefit payments (4,774) (5,235)
Actuarial loss 3,428 3,019
Plan amendment (3,716) --
--------- ---------
OPEB obligation at December 31 196,846 181,324
Fair value of plan assets at December 31 37,304 33,427
--------- ---------
Funded status (159,542) (147,897)
Unrecognized transition obligation 78,978 88,336
Unrecognized actuarial gain (7,314) (10,506)
--------- ---------
Accrued OPEB obligation at December 31 $ (87,878) $ (70,067)
========= =========
Reconciliations of the fair value of OPEB plan assets are (in thousands):
1998 1997
------- -------
Fair value of plan assets at January 1 $33,427 $28,799
Actual return on plan assets 3,877 4,628
------- -------
Fair value of plan assets at December 31 $37,304 $33,427
======= =======
The assumptions used to measure the OPEB obligation are:
1998 1997
---- ----
Weighted-average discount rate 7.00% 7.75%
Initial medical cost trend rate for
pre-Medicare benefits 6.60% 7.20%
Initial medical cost trend rate for
post-Medicare benefits 6.40% 7.00%
Ultimate medical cost trend rate 4.50% 5.25%
Year ultimate medical cost trend rate is achieved 2006 2005
The expected long-term rate of return on plan assets used in determining the net
periodic OPEB cost was 9.25% in 1998, 1997 and 1996. 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
17
the service and interest cost components of the net periodic OPEB cost for 1998
would increase by $3.3 million, and the OPEB obligation at December 31, 1998
would increase by $24.8 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 1998 would decrease by $2.7 million and the OPEB
obligation at December 31, 1998 would decrease by $21.2 million.
10. Income Taxes
Deferred income taxes are provided for temporary differences between book and
tax bases of assets and liabilities. Investment tax credits related to operating
income are amortized over the service life of the related property.
Net accumulated deferred income tax liabilities at December 31 are (in
thousands):
1998 1997
----------- -----------
Accelerated depreciation and property
cost differences $ 1,632,119 $ 1,676,505
Deferred costs, net 66,757 87,829
Miscellaneous other temporary
differences, net 10,885 300
----------- -----------
Net accumulated deferred income tax liability $ 1,709,761 $ 1,764,634
=========== ===========
Total deferred income tax liabilities were $2.21 billion and $2.24 billion at
December 31, 1998 and 1997, respectively. Total deferred income tax assets were
$501 million and $472 million at December 31, 1998 and 1997, respectively.
Reconciliations of the Company's effective income tax rate to the statutory
federal income tax rate are:
1998 1997 1996
------------- ------------- -------------
Effective income tax rate 39.2% 37.5% 39.5%
State income taxes, net of federal
income tax benefit (4.7) (4.9) (4.9)
Investment tax credit amortization 1.5 1.7 1.6
Other differences, net (1.0) 0.7 (1.2)
------------- ------------- -------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
============= ============= =============
The provisions for income tax expense are comprised of (in thousands):
1998 1997 1996
-------- --------- --------
Income tax expense (credit)
Current - federal $254,400 $ 258,050 $ 110,188
state 51,817 56,747 25,355
Deferred - federal (34,842) (61,384) 107,589
state (3,675) (9,465) 23,229
Investment tax credit (10,206) (10,232) (10,445)
-------- --------- --------
Total income tax expense $257,494 $ 233,716 $255,916
======== ========= ========
18
11. Joint Ownership of Generating Facilities
Power Agency holds undivided ownership interests in certain generating
facilities of the Company. The Company and Power Agency are entitled to shares
of the generating capability and output of each unit equal to their respective
ownership interests. Each also pays its ownership share of additional
construction costs, fuel inventory purchases and operating expenses. The
Company's share of expenses for the jointly owned units is included in the
appropriate expense category.
The Company's ownership interest in the jointly owned generating facilities is
listed below with related information as of December 31, 1998 (dollars in
millions):
Company
Facility Megawatt Ownership Plant Accumulated Under
Capability Interest Investment Depreciation Construction
---------- -------- ---------- ------------ ------------
Mayo Plant 745 83.83% $ 450 $ 193 $ 2
Harris Plant 860 83.83% $ 2,997 $ 1,008 $ 48
Brunswick Plant 1631 81.67% $ 1,414 $ 978 $ 3
Roxboro Unit No. 4 700 87.06% $ 231 $ 110 $ 6
In the table above, plant investment and accumulated depreciation, which
includes accumulated nuclear decommissioning, are not reduced by the regulatory
disallowances related to the Harris Plant.
12. Commitments and Contingencies
a. Purchased Power
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between the Company and Power Agency, the Company is obligated to purchase a
percentage of Power Agency's ownership capacity of, and energy from, the Harris
Plant. In 1993, the Company 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, the Company
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 capital-related capacity costs, total approximately $26 million.
These contractual purchases, including purchases from the Mayo Plant that ended
in 1997, totaled $34.4 million, $36.2 million and $36.7 million for 1998, 1997
and 1996, respectively. In 1987, the NCUC ordered the Company 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, 1998 and 1997, the Company had deferred purchased capacity costs,
including carrying costs accrued on the deferred balances, of $60.0 million and
$63.7 million, respectively. Increased purchases (which are not being deferred
for future recovery) resulting from the 1993 agreement with Power Agency were
approximately $19 million, $17 million and $13 million for 1998, 1997 and 1996,
respectively.
The Company has two long-term agreements for the purchase of power and related
transmission services from other utilities. The first agreement provides for the
purchase of 250 megawatts of capacity through 2009 from Indiana Michigan Power
Company's Rockport Unit No. 2 (Rockport). The second agreement is with Duke
Energy (Duke) for the purchase of 400 megawatts of firm capacity through
mid-1999. The estimated minimum annual payments for power purchases under these
agreements are approximately $31
19
million for Rockport and $48 million for Duke, representing capital-related
capacity costs. Total purchases (including transmission use charges) under the
Rockport agreement amounted to $59.3 million, $61.9 million and $60.9 million
for 1998, 1997 and 1996, respectively. Total purchases (including transmission
use charges) under the agreement with Duke amounted to $75.5 million, $69.5
million and $65.4 million for 1998, 1997 and 1996, respectively.
b. Insurance
The Company 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, the Company
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 $1.4 billion on the Brunswick
Plant, $2 billion on the Harris Plant and $800 million 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. The Company is insured thereunder for six weeks
(beginning 17 weeks after the outage begins) in the amount of $3.5 million per
week. For accidental outages extending beyond 23 weeks, the Company is covered
for the next 52 weeks in weekly amounts of $1.85 million at Brunswick Unit No.
1, $1.83 million at Brunswick Unit No. 2, $1.9 million at the Harris Plant and
$1.6 million at Robinson Unit No. 2. An additional 104 weeks of coverage is
provided at 80% of the above weekly amounts. For the current policy period, the
Company is subject to retrospective premium assessments of up to approximately
$12.1 million with respect to the primary coverage, $17.5 million with respect
to the decontamination, decommissioning and excess property coverage and $6.3
million for the incremental replacement power costs coverage in the event
covered expenses at insured facilities exceed premiums, reserves, reinsurance
and other NEIL resources. These resources at present total approximately $3.9
billion. Pursuant to regulations of the NRC, the Company'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 decontamination costs, before any proceeds can be used for
decommissioning, plant repair or restoration. The Company is responsible to the
extent losses may exceed limits of the coverage described above. Power Agency
would be responsible for its ownership share of such losses and for certain
retrospective premium assessments on jointly owned nuclear units.
The Company is insured against public liability for a nuclear incident up to
$9.8 billion per occurrence, which is the maximum limit on public liability
claims pursuant to the Price-Anderson Act. In the event that public liability
claims from an insured nuclear incident exceed $200 million, the Company would
be subject to a pro rata assessment of up to $83.9 million, plus a 5% surcharge,
for each reactor owned for each incident. Payment of such assessment would be
made over time as necessary to limit the payment in any one year to no more than
$10 million per reactor owned. Power Agency would be responsible for its
ownership share of the assessment on jointly owned nuclear units.
c. Applicability of SFAS-71
The Company's ability to continue to meet the criteria for application of
SFAS-71 (see Note 7a) may be affected in the future by competitive forces and
restructuring in the electric utility industry. In the event that SFAS-71 no
longer applied to a separable portion of the Company's operations, related
regulatory assets and liabilities would be eliminated unless an appropriate
regulatory recovery mechanism is provided. Additionally, these factors could
result in an impairment of electric utility plant assets as determined pursuant
to Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of".
20
d. Claims and Uncertainties
1. The Company is subject to federal, state and local regulations addressing air
and water quality, hazardous and solid waste management and other
environmental matters.
Various organic materials associated with the production of manufactured gas,
generally referred to as coal tar, are regulated under various federal and
state laws. There are several manufactured gas plant (MGP) sites to which the
Company and certain entities that were later merged into the Company had some
connection. In this regard, the Company, along with others, is participating
in a cooperative effort with the North Carolina Department of Environment and
Natural Resources, Division of Waste Management (DWM), which has established
a uniform framework to address MGP sites. The investigation and remediation
of specific MGP sites will be addressed pursuant to one or more
Administrative Orders on Consent (AOC) between the DWM and the potentially
responsible party or parties. The Company has signed AOCs to investigate
certain sites. The Company continues to investigate the identities of parties
connected to individual MGP sites, the relative relationships of the Company
and other parties to those sites and the degree to which the Company will
undertake efforts with others at individual sites. The Company does not
expect the costs associated with these sites to be material to the financial
position and results of operations of the Company.
The Company has been notified by regulators of its involvement or potential
involvement in several sites, other than MGP sites, that may require
investigation and/or remediation. Although the Company may incur costs at
these sites, the investigation and/or remediation of the sites has not
advanced to a stage where reasonable cost estimates can be made. The Company
cannot predict the outcome of these matters.
The Company carries a liability for the estimated costs associated with
certain remedial activities. This liability is not material to the financial
position of the Company.
2. As required under the Nuclear Waste Policy Act of 1982, the Company entered
into a contract with the U.S. Department of Energy (DOE) under which the DOE
agreed to begin taking spent nuclear fuel by January 31, 1998. The DOE
defaulted on its January 31, 1998 obligation to begin taking spent nuclear
fuel, and a group of utilities, including the Company, has undertaken
measures to force the DOE to take spent nuclear fuel. To date, the courts
have rejected these attempts. In addition, several utilities have filed
actions for damages in the United States Court of Claims, and in some of
those cases the Court has agreed that the DOE has breached its contract for
disposal of spent nuclear fuel. The Company is in the process of evaluating
whether it should file a similar action for damages. The Company will also
monitor legislation that has been introduced in Congress that would provide
for interim storage of spent nuclear fuel at a storage facility operated by
the DOE. The Company cannot predict the outcome of this matter.
With certain modifications and additional approval by the NRC, the Company's
spent nuclear fuel storage facilities will be sufficient to provide storage
space for spent fuel generated on the Company's system through the expiration
of the current operating licenses for all of the Company's nuclear generating
units. Subsequent to the expiration of these licenses, dry storage may be
necessary. The Company has initiated the process of obtaining the additional
NRC approval.
3. In the opinion of management, liabilities, if any, arising under other
pending claims would not have a material effect on the financial position and
results of operations of the Company.
21
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)
Date: February 26, 1999 By: /s/ Glenn E. Harder
-------------------
Glenn E. Harder
Executive Vice President and
Chief Financial Officer
22