<PAGE>
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
DUKE POWER COMPANY
422 South Church Street
Charlotte, North Carolina 28242
704-382-8127
<PAGE>
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) Not Applicable
DUKE POWER COMPANY
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C> <C>
NORTH CAROLINA 1-4928 56-0205520
(State or other jurisdiction (Commission (IRS Employer
of incorporation) File Number) Identification No.)
</TABLE>
422 SOUTH CHURCH STREET, CHARLOTTE, NORTH CAROLINA 28242
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (704) 382-8127
No change
(Former name or former address, if changed since last report)
<PAGE>
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1993 1992 1991
<S> <C> <C> <C>
ELECTRIC REVENUES (Notes 1 and 2).....................$4,281,876 $3,961,484 $3,816,960
ELECTRIC EXPENSES
Operation
Fuel used in electric generation (Note 1)...........732,246 659,593 657,725
Net interchange and purchased power (Note 3)........535,033 540,840 545,840
Wages, benefits and materials......................701,994 636,729 622,121
Maintenance of plant facilities........................375,457 403,162 354,679
Depreciation and amortization (Note 1).................488,441 491,339 431,624
General taxes..........................................231,680 215,493 204,688
Income taxes (Notes 1 and 4)...........................402,960 289,633 293,460
Total electric expenses...........................3,467,811 3,236,789 3,110,137
Electric operating income.........................814,065 724,695 706,823
OTHER INCOME (Notes 1, 4, 11 and 14)
Allowance for equity funds used during construction.....17,221 15,476 50,704
Other, net..............................................61,769 83,216 102,884
Income taxes -- other, net.............................(24,092) (27,475) (25,472)
Income taxes -- credit.................................16,371 13,790 22,789
Total other income...................................71,269 85,007 150,905
Income before interest deductions.................885,334 809,702 857,728
INTEREST DEDUCTIONS
Interest on long-term debt.............................256,347 265,646 274,662
Other interest..........................................12,431 41,736 18,834
Allowance for borrowed funds used
during construction (Notes 1 and 4)..................(9,859) (5,763) (19,391)
Total interest deductions..........................258,919 301,619 274,105
NET INCOME...............................................626,415 508,083 583,623
Dividends on preferred and preference stock.............52,429 56,407 54,683
EARNINGS FOR COMMON STOCK.............................$ 573,986 $ 451,676 $ 528,940
COMMON STOCK DATA (Note 6)
Average shares outstanding (thousands).................204,859 204,819 203,431
Earnings per share.......................................$2.80 $2.21 $2.60
Dividends per share..................................... $1.84 $1.76 $1.68
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
1
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1993 1992 1991
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income..........................................$ 626,415 $ 508,083 $ 583,623
Adjustments to reconcile net income to
net cash provided by operating activities:
Non-cash items
Depreciation and amortization (Note 1)............. 657,068 660,896 619,823
Deferred income taxes and investment tax credit,
net of amortization (Note 4).......................56,315 44,518 27,456
Allowance for equity funds used during
construction.....................................(17,221) (15,476) (50,704)
Purchased capacity levelization (Note 3)............(20,049) (66,511) (70,605)
Other, net (Note 15).................................36,864 (16,258) (32,149)
(Increase) Decrease in
Accounts receivable.............................(36,948) 14,255 (45,412)
Inventory........................................29,150 (9,383) 6,866
Prepayments........................................(452) (939) 181
Increase (Decrease) in Accounts payable............(54,275) 69,739 44,265
Taxes accrued (Notes 1 and 4).....................26,583 4,514 11,739
Interest accrued and other liabilities
(Notes 1, 9 and 13)...........................30,185 (22,825) 12,863
Total adjustments..................................707,220 662,530 524,323
Net cash provided by operating activities...1,333,635 1,170,613 1,107,946
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures...........................(543,563) (465,292) (572,705)
Investment in nuclear fuel..........................(111,731) (122,565) (183,803)
External funding for decommissioning (Note 16).......(52,524) (61,246) --
Pre-funded pension cost (Note 12)....................(50,000) -- --
Net change in investment securities and joint
ventures (Notes 1, 11 and 15).....................(12,379) (96,475) (35,807)
Net cash used in investing activities.......(770,197) (745,578) (792,315)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of
First and refunding mortgage bonds..............1,395,682 926,650 414,297
Preferred stock.................................215,633 281,089 --
Pollution-control bonds...........................76,265 -- --
Short-term notes payable, net (Note 5)..........(108,000) 40,000 (99,000)
Common stock................................... -- -- 48,014
Payments for the redemption of First and
refunding mortgage bonds......................(1,399,336) (1,013,218) (279,970)
Preferred stock...............................(224,295) (246,414) (9,650)
Pollution-control bonds........................ (79,310) -- --
Dividends paid.................................. (427,868) (417,443) (381,589)
Other (Note 15).................................. (5,926) 3,313 (5,662)
Net cash used in financing activities... (557,155) (426,023) (313,560)
Net increase (decrease) in cash..................... 6,283 (988) 2,071
Cash at beginning of year............................ 9,293 10,281 8,210
Cash at end of year............................... $ 15,576 $ 9,293 $ 10,281
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
2
<PAGE>
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
Dollars in Thousands December 31, 1993 1992
<S> <C> <C>
ELECTRIC PLANT (at original cost --
Notes 1, 3, 9, 13, 15 and 16)
Electric plant in service.........................$12,573,012 $12,193,888
Less accumulated depreciation and amortization......4,431,460 4,197,505
Electric plant in service, net....................8,141,552 7,996,383
Nuclear fuel..........................................705,994 718,420
Less accumulated amortization.........................405,910 425,088
Nuclear fuel, net...................................300,084 293,332
Construction work in progress (including nuclear
fuel in process:
1993 -- $113,904; 1992 -- $148,945).................482,473 490,408
Total electric plant, net.......................8,924,109 8,780,123
OTHER PROPERTY AND INVESTMENTS
Other property -- at cost (less accumulated
depreciation:
1993 -- $90,191; 1992 -- $83,108) (Note 15).........311,241 295,098
Investments in joint ventures (Notes 11 and 15).......101,612 31,268
Other investments, at cost or less.....................90,301 127,632
Nuclear decommissioning trust funds (Notes 10,
15 and 16)....................................... 118,456 61,812
Pre-funded pension cost (Note 12)......................50,000 --
Total other property and investments..............671,610 515,810
CURRENT ASSETS
Cash (Notes 5 and 10)................................. 15,576 9,293
Short-term investments (Note 10)......................120,651 141,285
Receivables (less allowance for losses:
1993 -- $6,392; 1992 -- $5,207) (Note 1)............531,592 494,644
Inventory -- at average cost
Coal................................................69,155 101,550
Other..............................................199,733 196,489
Prepayments..........................................12,062 11,610
Total current assets.............................948,769 954,871
DEFERRED DEBITS (Notes 1, 3, 4, 13 and 15)
Purchased capacity costs.............................768,099 378,095
Debt expense.........................................197,963 115,436
Regulatory asset related to income taxes.............486,440 --
Regulatory asset related to DOE assessment fee.......116,731 101,785
Other.................................................79,386 104,267
Total deferred debits......................... 1,648,619 699,583
TOTAL ASSETS.......................................$12,193,107 $10,950,387
<CAPTION>
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION (See Consolidated Statements of
Capitalization).................................... $ 8,404,131 $ 8,218,257
CURRENT LIABILITIES
Accounts payable........................................337,391 394,721
Taxes accrued (Note 1).................................. 82,824 36,885
Interest accrued.........................................68,868 68,078
Other (Note 13).........................................211,207 75,613
Total................................................700,290 575,297
Notes payable (Notes 5 and 10)...........................18,000 126,000
Current maturities of long-term debt and preferred
stock (Notes 9 and 15).................................91,898 9,434
Total current liabilities...........................810,188 710,731
ACCUMULATED DEFERRED INCOME TAXES (Notes 1 and 4).......2,207,708 1,369,677
DEFERRED CREDITS AND OTHER LIABILITIES
Investment tax credit (Notes 1 and 4)...................282,505 296,165
DOE assessment fee (Note 1).............................116,731 101,785
Nuclear decommissioning costs externally funded
(Notes 15 and 16).....................................118,456 61,812
Other...................................................253,388 191,960
Total deferred credits and other liabilities........771,080 651,722
COMMITMENTS AND CONTINGENCIES (Note 13)..................
TOTAL CAPITALIZATION AND LIABILITIES..................$12,193,107 $10,950,387
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
3
<PAGE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION AND RETAINED EARNINGS
<TABLE>
<CAPTION>
Dollars in Thousands December 31, 1993 1992
<S> <C> <C>
CAPITALIZATION
<S> <C> <C>
COMMON STOCK EQUITY (Notes 6 and 7)
Common stock, no par, 300,000,000 shares
authorized; 204,859,339 shares outstanding
for 1993 and 1992..............................$1,926,909 $1,926,909
Retained earnings................................2,410,825 2,223,718
Total common stock equity...................4,337,734 4,150,627
PREFERRED AND PREFERENCE STOCK WITHOUT SINKING
FUND REQUIREMENTS (Note 7)........................ 500,000 500,000
PREFERRED STOCK WITH SINKING FUND REQUIREMENTS
(Notes 8 and 10).................................. 281,000 279,519
LONG-TERM DEBT (Notes 9, 10 and 15)
Parent company long-term debt...................3,199,032 3,202,437
Subsidiary long-term debt..........................86,365 85,674
Total consolidated long-term debt..........3,285,397 3,288,111
TOTAL CAPITALIZATION.............................$8,404,131 $8,218,257
</TABLE>
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1993 1992 1991
<S> <C> <C> <C>
RETAINED EARNINGS
<S> <C> <C> <C>
BALANCE -- Beginning of year........................ $2,223,718 $2,141,259 $1,953,779
ADD -- Net income.......................................626,415 508,083 583,623
Total........................................ 2,850,133 2,649,342 2,537,402
DEDUCT
Dividends
Common stock...................................... 376,937 360,475 341,801
Preferred and preference stock......................52,429 56,407 54,683
Capital stock transactions, net........................9,942 8,742 (341)
Total deductions.................................439,308 425,624 396,143
BALANCE -- End of year...............................$2,410,825 $2,223,718 $2,141,259
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
4
<PAGE>
Notes To Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
A. Revenues
Revenues are recorded as service is rendered to customers. "Receivables"
on the Consolidated Balance Sheets include $175,726,000 and $167,610,000
as of December 31, 1993 and 1992, respectively, for service that has been
rendered but not yet billed to customers.
B. Additions to Electric Plant
The Company capitalizes all construction-related direct labor and
materials as well as indirect construction costs. Indirect costs include
general engineering, taxes and the cost of money (allowance for funds used
during construction). The cost of renewals and betterments of units of
property is capitalized. The cost of repairs and replacements
representing less than a unit of property is charged to electric expenses.
The original cost of property retired, together with removal costs less
salvage value, is charged to accumulated depreciation.
C. Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds that
are necessary to finance the construction of new facilities. AFUDC, a non-
cash item, is recognized as a cost of "Construction work in progress"
(CWIP), with offsetting credits to "Other income" and "Interest
deductions." After construction is completed, the Company is permitted to
recover these construction costs, including a fair return, through their
inclusion in rate base and in the provision for depreciation.
The 1993 AFUDC rate of 9.29 percent reflects "Allowance for borrowed
funds used during construction" calculated using a pre-tax cost of debt.
The rates for 1992 and 1991 of 8.07 percent and 8.86 percent have been
calculated using a net of tax cost of debt. Rates for all periods are
compounded semiannually. The change in calculation from a net of income
tax to a pre-tax basis is a result of the adoption of Statement of
Financial Accounting Standards No. 109 (SFAS 109). (See Note 4.)
D. Depreciation and Amortization
Provisions for depreciation are recorded using the straight-line method.
The year-end composite weighted-average depreciation rates were 3.47
percent for 1993 and 3.48 percent for 1992 and 1991. Effective with the
implementation of new retail rates in November 1991, all coal-fired
generating units are depreciated at a rate of 2.57 percent and all nuclear
units are depreciated at a rate of 4.70 percent, of which 1.61 percent is
for decommissioning. (See Note 16.)
Amortization of nuclear fuel is included in "Fuel used in electric
generation" in the Consolidated Statements of Income. The amortization is
recorded using the units-of-production method.
Under provisions of the Nuclear Waste Policy Act of 1982, the Company
has entered into contracts with the Department of Energy (DOE) for the
disposal of spent nuclear fuel. Payments made to the DOE for disposal
costs are based on nuclear output and are included in "Fuel used in
electric generation" in the Consolidated Statements of Income.
A provision in the Energy Policy Act of 1992 established a fund for the
decontamination and decommissioning of the DOE's uranium enrichment
plants. Licensees are subject to an annual assessment for 15 years based
on their pro rata share of past enrichment services. The annual assessment
is recorded as fuel expense. The Company paid $8,338,000 during 1993
related to its ownership interest in nuclear plants. The Company has
reflected the remaining liability and regulatory asset of $116,731,000 in
the Consolidated Balance Sheets.
E. Subsidiaries
The Company's consolidated financial statements reflect consolidation of
all of its wholly-owned subsidiaries. Intercompany transactions have been
eliminated in consolidation. (See Note 11 and "Subsidiary Highlights,"
page 25.)
F. Income Taxes
The Company implemented SFAS 109, "Accounting for Income Taxes," effective
January 1, 1993. (See Note 4.)
The Company and its subsidiaries file a consolidated federal income tax
return. Income taxes have been allocated to each company based on its
separate company taxable income or loss.
Income taxes are allocated to non-electric operations under "Other
income" and to electric operating expense. The "Income taxes - credit"
classified under "Other income" results from tax deductions of interest
costs relating primarily to deferred purchased capacity costs and CWIP.
Deferred income taxes have been provided for temporary differences
between book and tax income, principally resulting from accelerated tax
depreciation and levelization of purchased power costs. Investment tax
credits have been deferred and are being amortized over the estimated
useful lives of the related properties.
5
<PAGE>
G. Unamortized Debt Premium, Discount and Expense
Expenses incurred in connection with the issuance of presently outstanding
long-term debt, and premiums and discounts
relating to such debt, are being amortized over the terms of the
respective issues. Also, any expenses or call premiums associated with
refinancing higher-cost debt obligations are being amortized over the
lives of the new issues of long-term debt.
H. Fuel Cost Adjustment Procedures
Fuel costs are reviewed semiannually in the wholesale and South Carolina
retail jurisdictions, with provisions for changing such costs in base
rates. In the North Carolina retail jurisdiction, a review of fuel costs
in rates is required annually and during general rate case proceedings.
All jurisdictions allow the Company to adjust rates for past over- or
under-recovery of fuel costs. Therefore, the Company reflects in revenues
the difference between actual fuel costs incurred and fuel costs recovered
through rates.
The North Carolina legislature ratified a bill in July 1987 assuring
the legality of such adjustments in rates. In 1991, the statute was
extended through June 30, 1997.
I. Consolidated Statements of Cash Flows
For purposes of the Consolidated Statements of Cash Flows,
the Company's investments in highly liquid debt instruments, with an
original maturity of three months or less, are included in cash flows from
investing activities and thus are not considered cash equivalents.
Total income taxes paid were $352,697,000, $215,465,000 and
$245,945,000 for years ended December 31, 1993, 1992 and 1991,
respectively.
Interest paid, net of amount capitalized, was $244,829,000,
$298,455,000 and $269,330,000 for the years ended December 31, 1993, 1992
and 1991, respectively.
Note 2. Rate Matters
The North Carolina Utilities Commission (NCUC) and The Public Service
Commission of South Carolina (PSCSC) must approve rates for retail sales
within their respective states. The Federal Energy Regulatory Commission
(FERC) must approve the Company's rates for sales to wholesale customers.
Sales to the other joint owners of the Catawba Nuclear Station, which
represent a substantial majority of the Company's wholesale revenues, are
set through contractual agreements. (See Note 3.)
During 1991, the Company filed in both the North Carolina and the South
Carolina retail jurisdictions its only requests for general rate increases
since 1986. The rate increase requested by the Company in North Carolina
was 9.22 percent; a 4.15 percent increase was granted resulting in $100.1
million in additional annual revenues. In South Carolina, a rate increase
of 7.29 percent was requested; a 3.0 percent increase was granted
resulting in $30.2 million in additional annual revenues. These increases
were requested primarily to recover costs associated with the Bad Creek
Hydroelectric Station.
In 1991, the Company filed a request with the FERC seeking a 7.47
percent rate increase for its wholesale customers, who represent
approximately 2 percent of the Company's total revenues. A negotiated
settlement between the Company and the wholesale customers was approved by
the FERC on March 31, 1992. The approved agreement, effective April 1,
1992, provided for a 3.3 percent rate increase, resulting in $2.1 million
in additional annual revenues.
The North Carolina Supreme Court on April 22, 1992, remanded for the
second time the Company's 1986 rate order to the NCUC. In this ruling, the
Court held that the record from the 1986 proceedings failed to support the
rate of return of 13.2 percent on common equity authorized by the NCUC
after the initial decision of the Court remanding the 1986 rate order. The
NCUC issued a final order dated October 26, 1992, authorizing a 12.8
percent return on common equity for the period October 31, 1986, through
November 11, 1991, that resulted in a refund to North Carolina retail
customers in 1992 of approximately $95 million, including interest.
The Company has a bulk power sales agreement with Carolina Power &
Light Company (CP&L) to provide CP&L 400 megawatts of capacity as well as
associated energy when needed for a six-year period which began July 1,
1993. Electric rates in all regulatory jurisdictions were reduced by
adjustment riders to reflect capacity revenues received from this CP&L
bulk power sales agreement.
Note 3. Joint Ownership of Generating Facilities
The Company has sold interests in both units of the Catawba Nuclear
Station. The other owners of portions of the Catawba Nuclear Station and
supplemental information regarding their ownership are as follows:
<TABLE>
<CAPTION>
Ownership
Interest
Owner in the Station
<S> <C>
North Carolina Municipal Power Agency
Number 1 (NCMPA) 37.5%
North Carolina Electric Membership
Corporation (NCEMC) 28.125%
Piedmont Municipal Power Agency
(PMPA) 12.5%
Saluda River Electric Cooperative, Inc.
(Saluda River) 9.375%
</TABLE>
Each participant has provided its own financing for its ownership interest
in the plant.
The Company retains a 12.5 percent ownership interest in the Catawba
Nuclear Station. As of December 31, 1993, $498,930,000 of Electric plant
in service and Nuclear fuel
6
<PAGE>
represents the Company's investment in Units 1 and 2. Accumulated
depreciation and amortization of $152,698,000 associated with Catawba had
been recorded as of year-end. The Company's share of operating costs of
Catawba are included in the corresponding electric expenses in the
Consolidated Statements of Income.
In connection with the joint ownership, the Company has entered into
contractual agreements with the other joint owners to purchase declining
percentages of the generating capacity and energy from the plant. These
agreements were effective beginning with the commercial operation of each
unit. Unit 1 and Unit 2 began commercial operation in June 1985 and in
August 1986, respectively. Such agreements were established for 15 years
for NCMPA and PMPA and 10 years for NCEMC and Saluda River.
Energy cost payments are based on variable operating costs, a function
of the generation output. Capacity payments are based on the fixed costs
of the plant. The estimated purchased capacity obligations through 1998
are $392,000,000 for 1994, $293,000,000 for 1995, $55,000,000 for 1996,
$44,000,000 for 1997 and $32,000,000 for 1998. Payment obligations include
the terms of a proposed settlement agreement between the Company and two
of the four joint owners of the Catawba Nuclear Station which was executed
in January 1994 and is subject to regulatory approval. (See Note 13.)
Effective in its November 1991 rate order, the North Carolina Utilities
Commission (NCUC) reaffirmed the Company's recovery, on a levelized basis,
of the capital costs and fixed operating and maintenance costs of capacity
purchased from the other joint owners. The new NCUC rate order changed the
levelized basis to a 15-year period ending 2001 for all of the other joint
owners compared to the previous 15-year levelization period for NCMPA and
PMPA and 10-year levelization period for NCEMC and Saluda River. The
Public Service Commission of South Carolina (PSCSC), in its November 1991
rate order, reaffirmed the Company's recovery on a levelized basis of the
capital costs of capacity purchased from the other joint owners. The new
PSCSC rate order retained the levelized basis of a 7 1/2-year period for
PMPA and NCMPA; for NCEMC and Saluda River, the new levelized basis
reflects the projected purchased capacity payments for the twelve-month
period ended October 1992. The Federal Energy Regulatory Commission
granted the Company recovery on a levelized basis of the capital costs and
fixed operating and maintenance costs of capacity purchased from the other
joint owners over their contractual purchased power buyback periods. As
currently provided in rates in all jurisdictions, the Company recovers the
costs of purchased energy and a portion of purchased capacity. The portion
of costs not currently recovered through rates is being accumulated, and
the Company is recording a carrying charge on the accumulated balance.
The Company recovers the accumulated balance including the carrying charge
when the capacity payments drop below the levelized revenues. In the North
Carolina and
wholesale jurisdictions, purchased capacity payments continue to exceed
levelized revenues. In the South Carolina jurisdiction, cumulative
levelized revenues have exceeded purchased capacity payments.
Jurisdictional levelizations are intended to recover total costs,
including allowed returns, and are subject to adjustments, including final
true-ups.
For the years ended December 31, 1993, 1992 and 1991, the Company
recorded purchased capacity and energy costs from the other joint owners
of $547,900,000, $514,300,000 and $536,500,000, respectively. These
amounts, adjusted for the cost of capacity purchased not reflected in
current rates, are included in "Net interchange and purchased power" in
the Consolidated Statements of Income. As of December 31, 1993 and 1992,
$768,099,000 pre-tax and $378,095,000 net of income tax, respectively,
associated with the costs of capacity purchased but not reflected in
current rates had been accumulated in the Consolidated Balance Sheets as
"Purchased capacity costs." Accumulated deferred income taxes associated
with "Purchased capacity costs" were $254,789,000 as of December 31, 1993.
As of December 31, 1992, deferred income taxes reduced "Purchased capacity
costs" on the Consolidated Balance Sheet by $265,255,000. The change in
presentation from a net of tax to pre-tax basis is a result of the
adoption of SFAS 109. (See Note 4.)
Note 4. Income Tax Expense
The Company implemented Statement of Financial Accounting Standards No.
109 (SFAS 109), "Accounting for Income Taxes," effective January 1, 1993.
No prior periods have been restated.
SFAS 109 requires a liability approach for financial accounting and
reporting of income taxes. While classification of certain items on the
Consolidated Balance Sheets has changed, principally because of certain
items previously reported net of tax now being reported on a gross basis,
there is no material effect on the Company's results of operations. As a
result of implementing SFAS 109, the December 1993 Consolidated Balance
Sheet reflects an increase of $778 million in both Total assets and
Accumulated deferred income taxes (ADIT). The increase was primarily
because of a change in presentation from a net of tax to pre-tax basis
which resulted in an increase in "Purchased capacity costs" of $255
million and in the creation of the "Regulatory asset related to income
taxes" of $486 million. Effective January 1, 1993, "Allowance for borrowed
funds used during construction" on the Consolidated Statement of Income
reflects a pre-tax cost of debt.
Accumulated deferred income taxes after implementation of SFAS 109
consist primarily of the following temporary differences (dollars in
thousands):
7
<PAGE>
(continued from page 7)
<TABLE>
<CAPTION>
December 31, 1993
<S> <C>
Excess tax over book depreciation at historical tax rates $1,289,205
Regulatory liability related to adjusting deferred taxes
to the current statutory tax rate (124,952)*
Net excess tax over book depreciation $1,164,253
Regulatory asset related to restating to a pre-tax basis 611,392*
Deferred Catawba purchased capacity costs 254,789
Book versus tax basis difference 110,594
Loss on bond redemptions 74,438
Other (7,758)
Total deferred income taxes $2,207,708
</TABLE>
* The net regulatory asset related to income taxes is $486,440,000.
Total deferred income tax liability was $2,701,374,000 as of December 31,
1993. Total deferred income tax asset was $493,666,000 as of December 31,
1993.
Income tax expense consisted of the following (dollars in thousands):
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Income taxes related to electric expenses
Current income taxes
Federal $278,279 $215,726 $232,121
State 60,948 47,116 54,335
339,227 262,842 286,456
Deferred taxes, net
Excess tax over book depreciation 60,760 86,046 60,976
Loss on bond redemptions 33,016 9,950 1,995
Pre-funded pension cost 19,751 -- --
Amortization of canceled construction
costs (17,890) (23,959) (23,959)
Deferred Catawba purchased capacity costs 2,841 7,271 8,163
Property taxes (5,806) (15,499) (11,987)
Other (17,682) (25,756) (16,977)
74,990 38,053 18,211
Investment tax credit
Deferred -- -- 2,273
Amortization of deferrals (credit) (11,257) (11,262) (13,480)
(11,257) (11,262) (11,207)
Total income taxes related to electric
expenses 402,960 289,633 293,460
Income taxes related to other income
Income taxes - return on deferred Catawba
purchased capacity costs 20,702 18,845 20,675
Income taxes - other, net 3,390 8,630 4,797
Income taxes - (credit) (16,371) (13,790) (22,789)
Total income taxes related to other income 7,721 13,685 2,683
Total income tax expense $410,681 $303,318 $296,143
</TABLE>
Total current income taxes were $354,366,000 for 1993, $258,800,000 for
1992 and $268,686,000 for 1991. Of these amounts, state income taxes were
$61,237,000 for 1993, $44,149,000 for 1992 and $48,671,000 for 1991.
Total deferred income taxes were $67,572,000 for 1993, $55,780,000 for
1992 and $38,664,000 for 1991. Of these amounts, deferred state income
taxes were $14,279,000 for 1993, $13,786,000 for 1992 and $10,833,000 for
1991.
8
<PAGE>
Income taxes differ from amounts computed by applying the statutory tax
rate to pre-tax income as follows (dollars in thousands):
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Income taxes on pre-tax income at the
statutory federal rate of 35% - 1993;
34% - 1992 and 1991 $362,984 $275,876 $299,120
Increase (reduction) in tax resulting from:
Allowance for funds used during construction
(AFUDC) (6,027) (7,221) (23,832)
Amortization of electric investment tax
credit deferrals (11,257) (11,262) (13,480)
AFUDC in book depreciation/amortization 25,694 25,114 25,923
Deferred income tax flowback at rates
higher than statutory (9,091) (21,685) (22,561)
State income taxes, net of federal
income tax benefits 49,292 37,878 39,345
Other items, net (914) 4,618 (8,372)
Total income tax expense (see above) $410,681 $303,318 $296,143
</TABLE>
On August 10, 1993, President Clinton signed the Omnibus Budget
Reconciliation Act of 1993 which includes an increase in the federal
corporate income tax rate from 34% to 35%, retroactive to January 1, 1993.
Accordingly, the Company's income tax expense reflects an increase of
approximately $10 million for 1993.
Note 5. Short-Term Borrowings and Compensating-Balance Arrangements
To support short-term obligations, the Company had credit facilities of
$324,980,000, $329,385,000 and $340,385,000 as of December 31, 1993, 1992
and 1991, with 29, 49 and 52 commercial banks, respectively. Included in
these facilities is a three-year, $300,000,000 revolving credit agreement
with the balance in separate, annually-renewable lines of credit. These
facilities are on a fee or compensating-balance basis. No short-term debt
resulting from these credit facilities was outstanding as of December 31,
1993, 1992 and 1991.
Cash balances maintained at the banks on deposit were $12,988,000 and
$7,243,000 as of December 31, 1993 and 1992, respectively. Cash balances
and fees compensate banks for their services, even though the Company has
no formal compensating-balance arrangements. To compensate certain banks
for credit facilities, the Company maintained balances of $49,000 and
$509,000 as of December 31, 1993 and 1992, respectively. The Company
retains the right of withdrawal with respect to the funds used for
compensating-balance arrangements.
A summary of short-term borrowings is as follows (dollars in thousands):
<TABLE>
<CAPTION>
December 31, 1993 December 31, 1992 December 31, 1991
<S> <C> <C> <C>
Amount outstanding at end of period -
average rate of 3.27% as of December 31,
1993, 3.57% as of December 31, 1992
and 4.65% as of December 31, 1991 $ 18,000 $126,000 $ 86,000
Maximum amount outstanding during the period $ 178,000 $219,000 $285,500
Average amount outstanding during the period $ 35,187 $ 48,851 $ 92,090
Weighted-average interest rate for the period -
computed on a daily basis 3.17% 4.02% 6.47%
</TABLE>
Note 6. Common Stock and Retained Earnings
Common Stock
Effective April 1, 1991, the Company began issuing common stock in lieu of
purchasing shares on the open market for its various stock purchase plans.
The Company discontinued issuances of common stock, effective December 1,
1991, and resumed open market purchases to satisfy the requirements of the
various stock purchase plans. Except as discussed earlier, open market
purchases were used to satisfy the requirements of the Company's various
stock plans from 1991 through 1993.
During 1991 and through April 6, 1992, the Company issued common stock
to satisfy the conversion rights of preference stock. (See Note 7.)
As of December 31, 1993, a total of 7,004,659 shares was reserved for
issuance to stock plans.
Retained Earnings
As of December 31, 1993, none of the Company's retained earnings were
restricted as to the declaration or payment of dividends.
9
<PAGE>
Note 7. Preferred and Preference Stock Without Sinking Fund Requirements
The following shares of stock were authorized with or without sinking fund
requirements as of December 31, 1993 and 1992:
<TABLE>
<CAPTION>
Par Value Shares
<S> <C> <C>
Preferred Stock $100 12,500,000
Preferred Stock A 25 10,000,000
Preference Stock 100 1,500,000
</TABLE>
On April 6, 1992, the Company redeemed all outstanding shares of the
Cumulative Preference Stock, 63/4% Convertible Series AA at its par value
of $100 per share.
In 1992 and 1991, shares of preference stock were converted into shares
of common stock as follows:
<TABLE>
<CAPTION>
Year Preference Shares Common Shares
<S> <C> <C>
1992 19,060 159,386
1991 1,846 15,440
</TABLE>
Preferred and preference stock without sinking fund requirements as of
December 31, 1993 and 1992, were as follows (dollars in
thousands):
<TABLE>
<CAPTION>
Rate/Series Year Shares
Issued Outstanding 1993 1992
<S> <C> <C> <C> <C>
4.50% C 1964 350,000 $ 35,000 $35,000
5.72% D 1966 350,000 35,000 35,000
6.72% E 1968 350,000 35,000 35,000
8.20% G 1971 600,000 - 60,000
7.80% H 1972 600,000 - 60,000
8.28% K 1977 500,000 - 50,000
7.85% S 1992 600,000 60,000 60,000
7.00% W 1993 500,000 50,000 -
7.04% Y 1993 600,000 60,000 -
7.72% (Preferred Stock A) 1992 1,600,000 40,000 40,000
6.375% (Preferred Stock A) 1993 2,400,000 60,000 -
Adjustable Rate A 1986 500,000 50,000 50,000
Auction Series A 1990 750,000 75,000 75,000
$500,000 $500,000
</TABLE>
Note 8. Preferred Stock With Sinking Fund Requirements
The following shares of stock were authorized with or without sinking fund
requirements as of December 31, 1993 and 1992:
<TABLE>
<CAPTION>
Par Value Shares
<S> <C> <C>
Preferred Stock $100 12,500,000
Preferred Stock A 25 10,000,000
Preference Stock 100 1,500,000
</TABLE>
Preferred stock with sinking fund requirements as of December 31, 1993 and
1992, was as follows (dollars in thousands):
<TABLE>
<CAPTION>
Year Shares
Rate/Series Issued Outstanding 1993 1992
<S> <C> <C> <C> <C>
5.95% B (Preferred Stock A) 1992 800,000 $20,000 $20,000
6.10% C (Preferred Stock A) 1992 800,000 20,000 20,000
6.20% D (Preferred Stock A) 1992 800,000 20,000 20,000
7.875% P 1986 485,000 - 48,500
7.12% Q 1987 485,000 48,500 48,519
7.50% R 1992 850,000 85,000 85,000
6.20% T 1992 130,000 13,000 13,000
6.30% U 1992 130,000 13,000 13,000
6.40% V 1992 130,000 13,000 13,000
6.75% X 1993 500,000 50,000 -
Less: Current sinking fund
requirements
7.875% P - (1,500)
7.12% Q (1,500) -
$281,000 $279,519
</TABLE>
The annual sinking fund requirements through 1998 are
$1,500,000 in 1994, 1995, 1996 and 1997 and $5,750,000 in 1998. Some
additional redemptions are permitted at the Company's option. The Company
reacquired 15,000 shares of 7.12% Series Q Preferred Stock in 1992 to
satisfy 1993 sinking fund requirements.
The call provisions for the outstanding preferred stock specify various
redemption prices not exceeding 105 percent of par value, plus accumulated
dividends to the redemption date.
10
<PAGE>
Note 9. Long-Term Debt
Long-term debt outstanding as of December 31, 1993 and 1992, was as
follows (dollars in thousands):
<TABLE>
<CAPTION>
Series Year Due 1993 1992
<S> <C> <C> <C>
First and refunding mortgage bonds:
6.06%-6.23% 1994 $81,700 $81,700
6.47%-6.60% 1995 40,300 40,300
4 1/2% 1995 40,000 40,000
6.59% 1996 3,000 3,000
7 7/8% 1996 - 100,000
5 3/8% 1997 72,600 72,600
5 5/8% 1997 100,000 100,000
6 3/8% 1998 - 68,500
5.17% 1998 50,000 -
7% 1999 - 56,075
7.5% 1999 100,000 100,000
6 1/4% 1999 65,000 65,000
5.76% 1999 5,000 -
5.78% 1999 25,000 -
5.79% 1999 30,000 -
7% 2000 100,000 100,000
7% B 2000 100,000 100,000
7 1/2% 2001 - 97,900
7 3/8% B 2001 - 38,050
5 7/8% 2001 150,000 -
7 3/4% 2002 - 78,100
7 3/8% B 2002 - 67,900
6 5/8% B 2003 100,000 -
7 3/4% 2003 - 94,872
5 7/8% C 2003 75,000 -
6.125% 2003 75,000 -
8% 2004 75,000 75,000
6 1/4% B 2004 100,000 -
7.37%-7.41% 2004 100,000 100,000
7% 2005 200,000 200,000
8 1/8% 2007 - 119,500
6 3/8% 2008 125,000 -
9% 2016 - 175,000
8 1/2% 2017 - 150,000
9 5/8% 2020 46,982 200,000
10 1/8% B 2020 24,854 150,000
8 3/4% 2021 150,000 150,000
8 3/8% B 2021 150,000 150,000
8 5/8% 2022 100,000 100,000
7 3/8% 2023 200,000 -
6 7/8% 2023 200,000 -
6 3/4% 2025 150,000 -
8.95% 2027 15,851 15,925
7% 2033 150,000 -
Pollution-Control bonds:
9 1/8% 2013 - 77,000
7.70% 2012 20,000 20,000
7.75% B 2017 10,000 10,000
7.50% 2017 25,000 25,000
2.55% 2014 40,000 -
2.60% 2014 - 40,000
5.80% 2014 77,000 -
Subtotal 3,172,287 3,061,422
Other long-term debt:
Capitalized leases 47,029 53,782
Other long-term debt 130,000 130,000
Unamortized debt discount
and premium, net (61,128) (35,940)
Current maturities of
long-term debt (89,156) (6,827)
Subtotal (a) 3,199,032 3,202,437
Subsidiary long-term debt:
Crescent Resources, Inc. (b) 54,149 53,207
Nantahala Power and Light (c) 33,458 33,574
Current maturities of long-term debt (1,242) (1,107)
Subtotal 86,365 85,674
Total consolidated long-term debt $3,285,397 $3,288,111
</TABLE>
(a) Substantially all the Company's electric plant was mortgaged as of
December 31, 1993.
(b) Substantial amounts of Crescent Resources, Inc.'s real estate
development projects, land and buildings are pledged as collateral.
(c) Nantahala Power and Light's loan agreements impose net worth
restrictions and limitations on disposal of assets and payment of cash
dividends.
As of December 31, 1993 and 1992, the Company had $40,000,000 in
pollution-control revenue bonds backed by an unused, two-year revolving
credit facility of $40,000,000 and $130,000,000 in commercial paper backed
by an unused, three-year $130,000,000 revolving credit facility. These
facilities are on a fee basis. Both the $40,000,000 in pollution-control
bonds and the $130,000,000 in commercial paper are included in long-term
debt.
As of December 31, 1993, Crescent Resources, Inc. had $52,064,000 in
mortgage loans which mature in 1997 and require monthly payments of
principal. Interest rates are variable and ranged from 4.21 percent to
5.08 percent as of December 31, 1993. Nantahala Power and Light had
$33,000,000 in senior notes maturing in 2011 and 2012 as of December 31,
1993. The two notes carry fixed interest rates of 9.21 percent and 7.45
percent and require prepayments beginning 1997 and 1998, respectively.
The annual maturities of consolidated long-term debt, including
capitalized lease principal payments through 1998, are $90,398,000 in
1994; $89,888,000 in 1995; $13,264,000 in 1996; $223,810,000 in 1997 and
$54,522,000 in 1998.
11
<PAGE>
Note 10. Fair Value of Financial Instruments
Estimated fair value amounts have been determined by the Company using
available market information and appropriate valuation methodologies.
Judgment is required in interpreting market data to develop the estimates
of fair value. Accordingly, the estimates determined as of December 31,
1993, are not necessarily indicative of the amounts that the Company could
realize in a current market exchange.
Cash, Short-term investments and Notes payable
The carrying amount approximates fair value because of the short maturity
of these instruments.
Long-term debt (excluding Capitalized leases) and Preferred stock with
sinking fund requirements
Fair value is based on market price estimates. As a result of substantial
refinancing activity in 1993 and 1992, the Company's book value of
consolidated long-term debt and preferred stock is not materially
different from fair market value as of December 31, 1993.
Nuclear decommissioning trust funds
External funds have been established, as required by the Nuclear
Regulatory Commission, as a mechanism to fund certain costs of nuclear
decommissioning. (See Note 16.) These nuclear decommissioning trust funds
are primarily invested in intermediate-term municipal bonds. As of
December 31, 1993, the Company's book value of its nuclear decommissioning
trust funds is not materially different from fair market value.
Note 11. Investment in Joint Ventures
Certain investments in joint ventures are accounted for by the equity
method. The Company's ownership in domestic and international joint
ventures is 50 percent or less. Total assets of these joint ventures as of
December 31, 1993 and 1992, were $972 million and $433 million,
respectively. The Company's proportionate share of these assets was $241
million and $163 million, respectively. Total liabilities of these joint
ventures as of December 31, 1993 and 1992, were $413 million and $321
million, respectively. The Company's proportionate share of the
liabilities was $139 million and $132 million, respectively. Of the $413
million total liabilities outstanding at December 31, 1993, $290 million
represents non-recourse debt for which the Company bears no responsibility
in the event the joint venture defaults on the debt. The Company's portion
of net income from the joint ventures for the years ended December 31,
1993 and 1992, was $2,601,000 and ($1,179,000).
Note 12. Retirement Benefits
A. Retirement Plan
The Company and its operating subsidiaries, with the exception of
Nantahala Power and Light Company, which maintains its own retirement
plans, have a non-contributory, defined benefit retirement plan covering
substantially all their employees. The benefit is based on years of
creditable service and the employee's average compensation based on the
highest compensation during a consecutive sixty-month period. Prior to
1992, benefits have been reduced by a Social Security adjustment for
employees age sixty-five and over and for early retirees with no
creditable service prior to September 1, 1980. During 1991, the Company
amended its plan for employees who retire after December 31, 1991. The
effect of this amendment was to reduce benefits by a Social Security
adjustment for all retirees. The plan was amended in 1992 to permit
participants with 30 years of creditable service to retire as early as age
51. The Company's policy is to fund pension costs as accrued. During 1993,
the Company made a one-time contribution of $50,000,000 to enhance the
funded position of the plan.
Net periodic pension cost for the years ended December 31, 1993, 1992 and
1991, include the following components (dollars in
thousands):
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Service cost benefit earned during the year $39,514 $35,701 $37,286
Interest cost on projected benefit obligation 93,347 85,613 79,175
Actual return on plan assets (117,898) (50,897) (127,978)
Amount deferred for recognition 35,652 (32,277) 52,574
Expected return on plan assets (82,246) (83,174) (75,404)
Net amortization 4,137 3,812 4,347
Net periodic pension cost $54,752 $41,952 $45,404
</TABLE>
12
<PAGE>
A reconciliation of the funded status of the plan to the amounts
recognized in the Consolidated Balance Sheets as of December 31, 1993 and
1992, is as follows (dollars in thousands):
<TABLE>
<CAPTION>
1993 1992
<S> <C> <C>
Accumulated benefit obligation:
Vested benefits $(1,087,705) $(920,228)
Nonvested benefits (3,946) (2,915)
Accumulated benefit obligation $(1,091,651) $(923,143)
Fair market value of plan assets,
consisting primarily of short-term
investments and cash equivalents,
common stocks, real estate investments
and government and industrial bonds $1,137,992 $980,661
Projected benefit obligation (1,311,921) (1,132,410)
Unrecognized net experience loss 265,566 204,145
Unrecognized prior service cost reduction (42,705) (45,911)
Remaining unrecognized transitional obligation 1,068 1,202
Prepaid pension cost $50,000 $7,687
</TABLE>
In determining the projected benefit obligation, the weighted-average
assumed discount rate used was 7.50 percent in 1993 and 8.25 percent in
1992 and 1991. The assumed increase in future compensation level for
determining the projected benefit obligation is based on an age-related
basis. The weighted-average salary increase was 4.50 percent in 1993, 5.40
percent in 1992 and 5.65 percent in 1991. The expected long-term rate of
return on plan assets used in determining pension cost was 8.40 percent in
1993 and 9.25 percent in 1992 and 1991.
During 1993 the Company offered an enhanced early retirement option,
Limited Period Separation Opportunity (LPSO), for eligible employees. The
Company recorded an additional one-time expense for special termination
benefits associated with LPSO of approximately $7,611,000.
B. Postretirement Benefits
The Company and its operating subsidiaries, with the exception of
Nantahala Power and Light Company, which maintains its own postretirement
benefit plans, currently provides certain health care and life insurance
benefits for retired employees. Employees become eligible for these
benefits if they retire at age 55 or greater with 10 years of service; or
if they retire as early as age 51 with 30 years or more of service.
Employees retiring after January 1, 1992, receive a fixed Company
allowance, based on years of service, to be used to pay medical insurance
premiums. The Company reserves the right to terminate, suspend, withdraw,
amend or modify the plans in whole or in part at any time.
In 1992, the Company commenced funding the maximum amount allowable
under section 401(h) of the Internal Revenue Code, which provides for tax
deductions for contributions and tax-free accumulation of investment
income. Such amounts partially fund the Company's medical and dental
postretirement benefits. The Company has also established a Retired Lives
Reserve, which has tax attributes similar to 401(h) funding, to partially
fund its postretirement life insurance obligation. The Company contributed
$14,648,000 into these funding mechanisms in 1993 and $19,338,000 in 1992.
In 1992, the Company implemented a new accounting standard that
requires postretirement benefits to be recognized as earned by employees
rather than recognized as paid. Prior to 1992, the cost of retiree
benefits was recognized as the benefits were paid. Amounts paid by the
Company for 1991 amounted to $11,900,000.
13
<PAGE>
(continued from page 13)
Net periodic postretirement benefit cost for the years ended December 31,
1993 and 1992, include the following components (dollars in thousands):
<TABLE>
<CAPTION>
1993 1992
<S> <C> <C>
Service cost benefit earned during the year $4,974 $4,644
Interest cost on accumulated postretirement benefit
obligation 25,482 23,347
Actual return on plan assets (4,143) (2,953)
Amount deferred for recognition 334 1,061
Expected return on plan assets (3,809) (1,892)
Straight line - 20 year amortization of transition
obligation 13,479 13,479
Other amortization 278 160
Net periodic postretirement benefit cost $40,404 $39,738
</TABLE>
A reconciliation of the funded status of the plan to the amounts
recognized in the Consolidated Balance Sheets as of December 31,
1993 and 1992, is as follows (dollars in thousands):
<TABLE>
<CAPTION>
1993 1992
<S> <C> <C>
Fair market value of plan assets, consisting primarily
of short-term investments and cash equivalents, common stocks,
real estate investments and government and industrial bonds $57,840 $41,634
Actives eligible to retire (21,810) (14,954)
Actives not eligible to retire (90,621) (74,900)
Retirees and surviving spouses (238,522) (213,018)
Accumulated postretirement benefit obligation (350,953) (302,872)
Unrecognized prior service cost 1,923 2,083
Unrecognized net experience (gain)/loss 29,127 (2,501)
Unrecognized transitional obligation 242,629 256,108
(Accrued) postretirement benefit cost $(19,434) $(5,548)
</TABLE>
In determining the accumulated postretirement benefit obligation (APBO),
the weighted-average assumed discount rate used was 7.50 percent in 1993
and 8.25 percent in 1992. The assumed increase in future compensation
level is determined on an age-related basis. The weighted-average salary
increase was 4.50 percent in 1993, 5.40 percent in 1992 and 5.65 percent
in 1991. The expected long-term rate of return on 401(h) assets used in
determining postretirement benefits cost was 8.40 percent in 1993 and 9.25
percent in 1992. For Retired Lives Reserve assets, 7.125 percent was used
in 1993 and 1992.
The assumed medical inflation rate was approximately 13 percent in
1993. This rate decreases by 0.5 percent to 1.0 percent per year until a
rate of 5.5 percent is achieved in the year 2002, which remains fixed
thereafter.
A 1.0 percent increase in the medical and dental trend rates produces a
6.25 percent ($1,903,213) increase in the aggregate service and interest
cost. The increase in the APBO attributable to a 1.0 percent increase in
the medical and dental trend rates is 6.69 percent ($23,483,182) as of
December 31, 1993.
Note 13. Commitments and Contingencies
A. Construction Program
Projected construction and nuclear fuel costs, both including allowance
for funds used during construction, are $2.3 billion and $394 million,
respectively, for 1994 through 1996. The program is subject to periodic
review and revisions, and actual construction costs incurred may vary from
such estimates. Cost variances are due to various factors, including
revised load estimates, environmental matters and cost and availability of
capital.
B. Nuclear Insurance
The Company maintains nuclear insurance coverage in three areas: liability
coverage, property, decontamination and decommissioning coverage, and
extended accidental outage coverage to cover increased generating costs
and/or replacement power purchases. The Company is being reimbursed by the
other joint owners of the Catawba Nuclear Station for certain expenses
associated with nuclear insurance premiums paid by the Company.
Pursuant to the Price-Anderson Act, the Company is required to insure
against public liability claims resulting from nuclear incidents to the
full limit of liability of approximately $9.4 billion. The maximum
required private primary insurance of $200 million has been purchased
along with a like amount to cover certain worker tort claims. The
remaining amount, currently $9.2 billion, which will be increased by $75.5
million as each additional commercial nuclear reactor is
14
<PAGE>
licensed, has been provided through a mandatory industry-wide excess
secondary insurance program of risk pooling. The $9.2 billion could also
be reduced by $75.5 million for certain nuclear reactors that are no
longer operational and may be exempted from the risk pooling insurance
program. Under this program, licensees could be assessed retrospective
premiums to compensate for damages in the event of a nuclear incident at
any licensed facility in the nation. If such an incident occurs and public
liability damages exceed primary insurances, licensees may be assessed up
to $75.5 million for each of their licensed reactors, payable at a rate
not to exceed $10 million a year per licensed reactor for each incident.
The $75.5 million amount is subject to indexing for inflation. This amount
is further subject to a surcharge of 5 percent (which is included in the
above $9.4 billion figure) if funds are insufficient to pay claims and
associated costs. If retrospective premiums were to be assessed, the other
joint owners of the Catawba Nuclear Station are obligated to assume their
pro rata share of such assessment.
The Company is a member of Nuclear Mutual Limited (NML), which provides
$500 million in primary property damage coverage for each of the Company's
nuclear facilities. If NML's losses ever exceed its reserves, the Company
will be liable, on a pro rata basis, for additional assessments of up to
$42 million. This amount represents 5 times the Company's annual premium
to NML.
The Company is also a member of Nuclear Electric Insurance Limited
(NEIL) and purchases $1.4 billion of insurance through NEIL's excess
property, decontamination and decommissioning liability insurance program.
If losses ever exceed the accumulated funds available to NEIL for the
excess property, decontamination and decommissioning liability program,
the Company will be liable, on a pro rata basis, for additional
assessments of up to $46 million. This amount is limited to 7.5 times the
Company's annual premium to NEIL for excess property, decontamination and
decommissioning liability insurance. The other joint owners of Catawba
are obligated to assume their pro rata share of any liability for
retrospective premiums and other premium assessments resulting from the
NEIL policies applicable to Catawba. The Company has also purchased an
additional $400 million of excess property damage insurance for its Oconee
and McGuire plants and $800 million for its Catawba plant through a pool
of stock and mutual insurance companies.
The Company participates in a NEIL program that provides insurance for
the increased cost of generation and/or purchased power resulting from an
accidental outage of a nuclear unit. Each unit of the Oconee, McGuire and
Catawba Nuclear Stations is insured for up to approximately $3.5 million
per week, after a 21-week deductible period, with declining amounts per
unit where more than one unit is involved in an accidental outage.
Coverages continue at 100 percent for 52 weeks, and 67 percent for the
next 104 weeks. If NEIL's losses for this program ever exceed its
reserves, the Company will be liable, on a pro rata basis, for additional
assessments of up to $30 million. This amount represents 5 times the
Company's annual premium to NEIL for insurance for the increased cost of
generation and/or purchased power resulting from an accidental outage of a
nuclear unit. The other joint owners of Catawba are obligated to assume
their pro rata share of any liability for retrospective premiums and other
premium assessments resulting from the NEIL policies applicable to the
joint ownership agreements.
C. Other
The other joint owners of the Catawba Nuclear Station and the Company are
involved in various proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding is that
certain calculations affecting bills under these agreements should be
performed differently. These items are covered by the agreements between
the Company and the other Catawba joint owners which have been previously
approved by the Company's retail regulatory commissions. (For additional
information, see Note 3.) The Company and two of the four joint owners
have entered into a proposed settlement agreement which, if approved by
the regulators, will resolve all issues in contention in such proceedings
between the Company and these owners. The Company recorded a liability as
an increase to Other current liabilities on its Consolidated Balance
Sheets of approximately $105 million in 1993 to reflect this proposed
settlement. In addition, future estimated obligations in connection with
the settlement are reflected in estimates of purchased capacity
obligations in Note 3. As the Company expects the costs associated with
this settlement will be recovered as part of the purchased capacity
levelization, the Company has included approximately $105 million as an
increase to Purchased capacity costs on its Consolidated Balance Sheets.
Therefore, the Company believes the ultimate resolution of these matters
should not have a material adverse effect on the results of operations or
financial position of the Company.
Although the two other Catawba joint owners, who are not parties to the
above settlement, have not fully quantified the dollars associated with
their claims in the presently outstanding proceedings, information
associated with these proceedings indicates that the amount in contention
could be as high as $110 million through December 31, 1993. Arbitration
hearings were held in 1992 involving substantially all the disputed
amounts, and a decision interpreting the language of the agreements on
certain of these matters was issued on October 1, 1993. Further
proceedings will be required to determine the amounts associated with this
decision as it relates to these owners, some of which may involve refunds.
However, the Company expects the costs associated with this decision will
be included in and recovered as part of the purchased capacity
levelization consistent with prior orders of the retail regulatory
commissions. Therefore, the Company believes the ultimate resolution of
these matters should not have a material adverse effect on the results of
operations or financial position of the Company.
The Company is also involved in legal, tax and regulatory proceedings
before various courts, regulatory commissions and governmental agencies
regarding matters arising in the ordinary course of business, some of
which involve substantial amounts. Management is of the opinion that the
final disposition of these proceedings will not have a material adverse
effect on the results of operations or the financial position of the
Company.
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Note 14. Other Income
For the years ended December 31, 1993, 1992 and 1991, the Company reported
carrying charges on purchased capacity levelization deferral related to
the joint ownership of the Catawba Nuclear Station of $32,180,000,
$28,820,000 and $28,765,000 (net of taxes), respectively, as components of
"Other, net" and "Income taxes - other, net"on the Consolidated Statements
of Income. (For additional information on purchased capacity levelization,
see Note 3.)
Also included in "Other, net" and "Income taxes - other, net" on the
Consolidated Statements of Income is income provided by diversified
activities and the Company's subsidiaries of $21,996,000, $25,728,000 and
$23,587,000 (net of taxes) for years ended December 31, 1993, 1992 and
1991, respectively. The activities of Crescent Resources, Inc., the
Company's real estate development and forest management subsidiary,
generated the majority of subsidiary and non-electric earnings. Other
components include subsidiary investment income, fees for engineering
services, construction and operation of generation and transmission
facilities outside the Company's current service area, water operations
and merchandising.
For the year ended December 31, 1991, the Company recorded a net of tax
carrying charge of $36,765,000 on costs incurred on the Bad Creek
Hydroelectric Station after commercial operation but prior to recovery of
costs through rates. This carrying charge is a component of "Other, net"
in the Consolidated Statements of Income.
Note 15. Reclassification
In the Consolidated Statements of Cash Flows, Consolidated Balance Sheets
and the Consolidated Statements of Capitalization, certain prior-year
information has been reclassified to conform with 1993 classifications.
Note 16. Nuclear Decommissioning Costs
Estimated site-specific nuclear decommissioning costs, including the cost
of decommissioning plant components not subject to radioactive
contamination, total approximately $955 million stated in 1990 dollars.
This amount includes the Company's 12.5 percent ownership in the Catawba
Nuclear Station. The other joint owners of the Catawba Nuclear Station are
liable for providing decommissioning related to their ownership interests
in the station. Both the NCUC and the PSCSC have granted the Company
recovery of the estimated site-specific decommissioning costs through
retail rates over the expected remaining service periods of the Company's
nuclear plants. Such estimates presume that units will be decommissioned
as soon as possible following the end of their license life. Although
subject to extension, the current operating licenses for the Company's
nuclear units expire as follows: Oconee 1 and 2 - 2013, Oconee 3 - 2014;
McGuire 1 - 2021, McGuire 2 - 2023; and Catawba 1 - 2024, Catawba 2 -
2026.
The Nuclear Regulatory Commission (NRC) issued a rule-making in 1988
which requires an external mechanism to fund the estimated cost to
decommission certain components of a nuclear unit subject to radioactive
contamination. In addition to the required external funding, the Company
maintains an internal reserve to provide for decommissioning costs of
plant components not subject to radioactive contamination. During 1993,
the Company expensed approximately $52.5 million which was contributed to
the external funds and accrued an additional $5.0 million to the internal
reserve. The balance of the external funds as of December 31, 1993, was
$118.5 million. The balance of the internal reserve as of December 31,
1993, was $200.0 million and is reflected in Accumulated depreciation and
amortization on the Consolidated Balance Sheets. Management's opinion is
that the estimated site-specific decommissioning costs being recovered
through rates, when coupled with assumed after-tax fund earnings of 4.5
percent to 5.5 percent, are currently sufficient to provide for the cost
of decommissioning based on the Company's current decommissioning
schedule.
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Independent Auditors' Report
Duke Power Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Duke Power Company and subsidiaries (the
Company) as of December 31, 1993 and 1992, and the related consolidated
statements of income, retained earnings and cash flows for each of the three
years in the period ended December 31, 1993. 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
at December 31, 1993 and 1992, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1993 in
conformity with generally accepted accounting principles. As discussed in Note
4 to the consolidated financial statements, the Company changed its method of
accounting for income taxes to conform with Statement of Financial Accounting
Standards No. 109.
Deloitte & Touche
Deloitte & Touche
Charlotte, North Carolina
February 11, 1994
Responsibility for Financial Statements
The financial statements of Duke Power Company are prepared by management,
which is responsible for their integrity and objectivity. The statements are
prepared in conformity with generally accepted accounting principles
appropriate in the circumstances to reflect in all material respects the
substance of events and transactions which should be included. The other
information in the annual report is consistent with the financial statements.
In preparing these statements, management makes informed judgments and
estimates of the expected effects of events and transactions that are currently
being reported.
The Company's system of internal accounting control is designed to provide
reasonable assurance that assets are safeguarded and transactions
are executed according to management's authorization. Internal accounting
controls also provide reasonable assurance that transactions are recorded
properly, so that financial statements can be prepared according to generally
accepted accounting principles. In addition, the Company's accounting controls
provide reasonable assurance that errors or irregularities which could be
material to the financial statements are prevented or are detected by employees
within a timely period as they perform their assigned functions. The Company's
accounting controls are continually reviewed for effectiveness. In addition,
written policies, standards and procedures, and a strong internal audit
program augment the Company's accounting controls.
The Board of Directors pursues its oversight role for the financial statements
through the audit committee, which is composed entirely of
directors who are not employees of the Company. The audit committee meets with
management and internal auditors periodically to review the work of each
group and to monitor each group's discharge of its responsibilities. The audit
committee also meets periodically with the Company's independent auditors,
Deloitte & Touche. The independent auditors have free access to the audit
committee and the Board of Directors to discuss internal accounting control,
auditing and financial reporting matters without the presence of management.
David L. Hauser
David L. Hauser
Controller
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Management's Discussion and Analysis of Results of Operations and Financial
Condition
Results of Operations
Earnings and Dividends
Earnings per share increased 27 percent from $2.21 in 1992 to $2.80 in 1993.
The increase was primarily due to higher kilowatt-hour sales and a one-time
charge taken in 1992 related to a rate refund to North Carolina retail
customers of $.32 per share. (For additional information on the refund, see
Liquidity and Resources "Rate Matters," page 19.) The increase was partially
offset by higher operating and maintenance expenses, additional charitable
contributions to the Duke Power Company Foundation and an increase in the
federal income tax rate caused by the Omnibus Budget Reconciliation Act of
1993. Higher general taxes also decreased earnings.
Earnings per share increased from $2.60 in 1991 to $2.80 in 1993, indicating
an average annual growth rate of 4 percent. Total Company earned return on
average common equity was 13.6 percent in 1993 compared to 11.1 percent in
1992 and 13.5 percent in 1991.
The Company continued its practice of increasing the common stock dividend
annually. Common dividends per share increased from $1.68 in 1991 to $1.84 in
1993, rising at an average annual rate of 5 percent. Indicated annual
dividends per share increased to $1.88.
Revenue and Sales
Revenues increased at an average annual rate of 6 percent from 1991 to 1993,
primarily because of increased overall kilowatt-hour sales and the November
1991 rate increases.
Kilowatt-hour sales for 1993 increased 7 percent compared to 1992. Sales to
residential customers increased by 9 percent reflecting colder winter weather
and a hotter-than-normal summer. General service customer kilowatt-hour sales
increased by 7 percent as a result of both continued economic growth and
weather trends cited above. Sales to other-industrial customers and textile
customers increased by 6 percent and 2 percent, respectively, as a result of
the continued economic growth in the Company's service area.
Operating Expenses
From 1992 to 1993, non-fuel operating and maintenance expenses rose 4 percent.
Administrative and general expenses increased partly because of increased
pension expenses to reflect more conservative investment return assumptions
and one-time costs associated with a voluntary separation option offered
during the first quarter of 1993. A winter storm during the first quarter of
1993 also increased non-fuel operating and maintenance expenses. These
increases from 1992 to 1993 were partially offset by lower nuclear and fossil
maintenance expenses resulting from lower outage costs.
Non-fuel operating and maintenance expenses increased at an average annual
rate of 5 percent from 1991 to 1993. Administrative and general expenses
increased over this period because of the implementation of a new accounting
standard in January 1992 that reflects accrual basis accounting for certain
postretirement health care and life insurance benefits, in addition to the
reasons cited in the preceding paragraph. Operating and maintenance expenses
for fossil and hydro plants also increased from 1991 to 1993. Fossil increases
were caused by bringing refurbished units back on-line, and hydro increases
were the result of the completion of the Bad Creek Hydroelectric Station in
late 1991.
Net interchange and purchased power decreased at an average annual rate of 1
percent from 1991 to 1993. A slight decline in the amount of purchased power
from the other Catawba joint owners as recognized on the income statement was
substantially offset by increased purchases from other utilities. (For
additional information on the Catawba purchase power agreements, see Note 3 to
the Consolidated Financial Statements.)
Fuel expense increased at an average annual rate of 6 percent from 1991 to
1993. The increase was due primarily to higher system production requirements
that were satisfied by increased fossil generation. A continued decline of
fuel prices over this period helped to offset the overall increase in fuel
expenses.
From 1991 to 1993, depreciation and amortization expense increased at an
average annual rate of 6 percent primarily because of the completion of the
Bad Creek Hydroelectric Station in 1991 and added investment in distribution
property.
Other Income and Interest Deductions
Allowance for funds used during construction (AFUDC) represented 5 percent of
earnings for common stock in 1993 compared to 13 percent in 1991. The decrease
is primarily the result of the completion of the Bad Creek Hydroelectric
Station in 1991. AFUDC is expected to represent less than 10 percent of total
earnings during the next three years.
The carrying charge, net of associated taxes, on the purchased capacity
levelization deferral related to the joint ownership of the Catawba Nuclear
Station represented 6 percent of total earnings in 1993, compared to 6 percent
in 1992 and 5 percent in 1991. This carrying charge and the related tax
benefits are included in Other, net and Income taxes---other, net,
respectively. The growth in this carrying charge is due to the increasing
cumulative impact of the Company's funding of purchased power costs which
current rates are expected to collect in future periods. The Company recovers
the accumulated balance, including the carrying charge, when the declining
purchased capacity payments drop below the levelized revenues. (For additional
information on purchased capacity levelization, see Capital Needs "Purchased
Capacity Levelization," page 20.)
Interest on long-term debt decreased at an average annual rate of 3 percent
from 1991 to 1993. The decrease is due to the Company's refinancing of higher
cost debt beginning in late 1991 and continuing throughout 1993. From 1992 to
1993, Other interest decreased as a result of the one-time impact in 1992 of
approximately $27 million in interest paid to North Carolina retail customers
due to a rate refund.
Income provided by diversified activities and the Company's subsidiaries was
$22.0 million in 1993 compared to $25.7 million in 1992 and $23.6 million in
1991. The activities of Crescent Resources, Inc., the Company's real estate
development and forest management subsidiary, generated the majority of
subsidiary and non-electric earnings. Other components include subsidiary
investment income, fees for engineering services, construction and operation
of generation and transmission
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facilities outside the Company's service area, water operations and
merchandising.
Liquidity and Resources
Rate Matters
During 1991, the Company filed in both the North Carolina and South Carolina
retail jurisdictions its only requests for general rate increases since 1986.
The rate increases were primarily needed to recover costs associated with the
construction of the Bad Creek Hydroelectric Station. In North Carolina, the
Company requested a 9.22 percent rate increase and was granted a 4.15 percent
increase, which resulted in additional annual revenues of $100.1 million. In
South Carolina, a 7.29 percent increase was requested and a 3.0 percent rate
increase was granted, resulting in additional annual revenues of $30.2
million.
Also in 1991, the Company filed a request for a wholesale rate increase with
the Federal Energy Regulatory Commission (FERC). A negotiated settlement
between the Company and the wholesale customers was approved by the FERC on
March 31, 1992. The approved agreement, effective April 1, 1992, provided for
a 3.3 percent rate increase, resulting in $2.1 million in additional annual
revenues.
The North Carolina Supreme Court on April 22, 1992, remanded for the second
time the Company's 1986 rate order to the North Carolina Utilities Commission
(NCUC). In this ruling, the Court held that the record from the 1986
proceedings failed to support the rate of return on common equity of 13.2
percent authorized by the NCUC after the initial decision of the Court
remanding the 1986 rate order. The NCUC issued a final order dated October 26,
1992, authorizing a 12.8 percent return on common equity for the period
October 31, 1986, through November 11, 1991. This order resulted in a 1992
refund to North Carolina retail customers of approximately $95 million,
including interest.
The Company has a bulk power sales agreement with Carolina Power & Light
Company (CP&L) to provide CP&L 400 megawatts of capacity as well as associated
energy when needed for a six-year period which began July 1, 1993. Electric
rates in all regulatory jurisdictions were reduced by adjustment riders to
reflect capacity revenues received from this CP&L bulk power sales agreement.
The other joint owners of the Catawba Nuclear Station and the Company are
involved in various proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding is that
certain calculations affecting bills under these agreements should be
performed differently. These items are covered by the agreements between the
Company and the other Catawba joint owners which have been previously approved
by the Company's retail regulatory commissions. (For additional information on
Catawba joint ownership, see Note 3 to the Consolidated Financial Statements.)
The Company and two of the four joint owners have entered into a proposed
settlement agreement which, if approved by the regulators, will resolve all
issues in contention in such proceedings between the Company and these owners.
The Company recorded a liability as an increase to Other current liabilities
on its Consolidated Balance Sheets of approximately $105 million in 1993 to
reflect this proposed settlement. In addition, future estimated obligations in
connection with the settlement are reflected in estimates of purchased
capacity obligations in Note 3. As the Company expects the costs associated
with this settlement will be recovered as part of the purchased capacity
levelization, the Company has included approximately $105 million as an
increase to Purchased capacity costs on its Consolidated Balance Sheets.
Therefore, the Company believes the ultimate resolution of these matters
should not have a material adverse effect on the results of operations or
financial position of the Company.
Although the two other Catawba joint owners, who are not parties to the above
settlement, have not fully quantified the dollars associated with their claims
in the presently outstanding proceedings, information associated with these
proceedings indicates that the amount in contention could be as high as $110
million, through December 31, 1993. Arbitration hearings were held in 1992
involving substantially all the disputed amounts, and a decision interpreting
the language of the agreements on certain of these matters was issued on
October 1, 1993. Further proceedings will be required to determine the amounts
associated with this decision as it relates to these owners, some of which may
involve refunds. However, the Company expects the costs associated with this
decision will be included in and recovered as part of the purchased capacity
levelization consistent with prior orders of the retail regulatory
commissions. Therefore, the Company believes the ultimate resolution of these
matters should not have a material adverse effect on the results of operations
or financial position of the Company.
The Company is also involved in legal, tax and regulatory proceedings before
various courts, regulatory commissions and governmental agencies regarding
matters arising in the ordinary course of business, some of which involve
substantial amounts. Management is of the opinion that the final disposition
of these proceedings will not have a material adverse effect on the results of
operations or the financial position of the Company.
Cash From Operations
In 1993, net cash provided by operating activities accounted for 46 percent of
total cash from operating, financing and investing activities compared to 50
percent in 1992 and 77 percent in 1991. For 1993 and 1992, essentially all the
Company's capital needs, exclusive of refinancing activities, were met by cash
generated from operations.
Financing and Investing Activities
The Company's capital structure, including subsidiary capitalization, at year-
end 1993 was 52 percent common equity, 39 percent long-term debt and 9 percent
preferred stock. This structure is consistent with the Company's target to
maintain an "AA" credit rating. As of December 31, 1993, the Company's bonds
were rated "AA" by Fitch Investors Service, "Aa2" by Moody's Investors
Service, and "AA-" by Standard & Poor's Ratings Group and Duff & Phelps.
As a result of favorable market conditions, the Company continued refinancing
activities to retire higher cost debt and preferred stock. During 1993, the
Company obtained proceeds from the issuance of $1.5 billion in long-term debt
and $220 million in preferred stock, most of which were used to retire $1.4
billion of long-term debt and $216 million of preferred stock.
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In 1992, the Company issued $940 million in long-term debt. Most of these
proceeds, combined with the proceeds from bonds issued in late 1991, were used
to redeem $884 million of long-term debt. During 1992, the Company also issued
$284 million of preferred stock, most of which was used to redeem $229 million
of preferred stock.
Also on April 6, 1992, the Company redeemed all outstanding shares of the
Cumulative Preference Stock 6 3/4 percent Convertible Series AA at its par
value of $100 per share.
The Company's embedded cost of long-term debt for 1993 decreased to 8.01
percent compared to 8.39 percent in 1992 and 8.72 percent in 1991. The
embedded cost of preferred stock declined to 6.76 percent in 1993 from 7.05
percent in 1992 and 7.48 percent in 1991. These decreases are primarily the
result of the Company's refinancing activities. Downward trends in embedded
costs may level off because of fewer refinancing opportunities.
Fixed Charges Coverage
Fixed charges coverage using the SEC method increased to 4.68 times for 1993
compared to 3.48 and 3.85 times, respectively, in 1992 and 1991. Fixed charges
coverage, excluding AFUDC and the return on purchased capacity levelization,
was 4.40 times in 1993 compared to 3.27 in 1992 and 3.46 in 1991 and the
Company goal of 3.5 times. In 1992, the coverage under both methods was lower
because of the impact of the rate refund.
Capital Needs
Property Additions and Retirements
Additions to property and nuclear fuel of $676 million and retirements of $312
million resulted in an increase in gross plant of $364 million in 1993.
Since January 1, 1991, additions to property and nuclear fuel of $2.1 billion
and retirements of $780 million have resulted in an increase in gross plant of
$1.3 billion.
Construction Expenditures
Plant construction costs for generating facilities, including AFUDC, decreased
from $232 million in 1991 to $182 million in 1993. Completion of the Bad Creek
Hydroelectric Station in 1991 was a significant part of the decrease.
Construction costs for distribution plant, including AFUDC, decreased from
$275 million in 1991 to $240 million in 1993.
Projected construction and nuclear fuel costs, both including AFUDC, are $2.3
billion and $394 million, respectively, for 1994 through 1996. Total projected
construction costs include expenditures for the construction of the Lincoln
Combustion Turbine Station and replacement of certain steam generators at the
McGuire Nuclear Station and the Catawba Nuclear Station. (For additional
information on steam generator replacement, see Current Issues "Stress
Corrosion Cracking," page 22.) For 1994 through 1996, the Company anticipates
funding its projected construction and nuclear fuel costs through the internal
generation of funds and, to a lesser extent, through the issuance of
securities, primarily First and Refunding Mortgage Bonds.
Purchased Capacity Levelization
The rates established in the Company's retail jurisdictions permit the Company
to recover its investment in both units of the Catawba Nuclear Station and the
costs associated with contractual purchases of capacity from the other Catawba
joint owners. The contracts relating to the sales of portions of the station
obligate the Company to purchase a declining amount of capacity from the other
joint owners. In the North Carolina retail jurisdiction, regulatory treatment
of these contracts provides revenue for recovery of the capital costs and the
fixed operating and maintenance costs of purchased capacity on a levelized
basis. In the South Carolina retail jurisdiction, revenues are provided for
the recovery of the capital costs of purchased capacity on a levelized basis,
while current rates include recovery of fixed operating and maintenance
expenses.
These rate treatments require the Company to fund portions of the purchased
power payment until these costs, including carrying charges, are recovered at
a later date. The Company recovers the accumulated costs and carrying charges
when the declining purchased capacity payments drop below the levelized
revenues. In the North Carolina and wholesale jurisdictions, purchased
capacity payments continue to exceed levelized revenues. In the South Carolina
jurisdiction, cumulative levelized revenues have exceeded purchased capacity
payments. Jurisdictional levelizations are intended to recover total costs,
including allowed returns, and are subject to adjustments, including final
true-ups.
Meeting Future Power Needs
The Company's strategy for meeting customers' present and future energy needs
is composed of three components: supply-side resources, demand-side resources
and purchased power resources. To assist in determining the optimal
combination of these three resources, the Company uses its integrated resource
planning process. The goal is to provide adequate and reliable electricity in
an environmentally responsible manner through cost-effective power management.
The Company is building a combustion turbine facility in Lincoln County, North
Carolina. The Lincoln Combustion Turbine Station will consist of 16 combustion
turbines with a total generating capacity of 1,184 megawatts. The estimated
total cost of the project is approximately $500 million. Current plans are for
ten units to begin commercial operation by the end of 1995 and the remaining
six to begin commercial operation before the end of 1996. The Lincoln facility
will provide capacity at periods of peak demand.
Demand-side management programs are a part of meeting the Company's future
power needs. These programs benefit the Company and its customers by providing
for load control through interruptible control features, shifting usage to
off-peak periods, increasing usage during off-peak periods, and by promoting
energy efficiency. In return for participation in demand-side management
programs, customers may be eligible to receive various incentives which help
to reduce their electric bills. Demand-side management programs such as
Industrial Interruptible Service and Residential Load Control can be used to
manage capacity availability problems. Energy-efficiency programs such as
high-efficiency chillers, high-efficiency heat pumps and high-efficiency air
conditioners are other examples of current demand-side management programs.
The November 1991 rate orders of the NCUC and The Public Service Commission of
South Carolina (PSCSC) provided for recovery in rates of a designated level
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of costs for demand-side management programs and allowed the deferral for
later recovery of certain demand-side management costs that exceed the
level reflected in rates, including a return on the deferred costs. As
additional demand-side costs are incurred, the Company ultimately expects
recovery of associated costs, which are currently being deferred, through
rates. The annual costs deferred, including the return, were approximately
$26 million in 1993 and $18 million in 1992.
The purchase of capacity and energy is also an integral part of meeting future
power needs. The Company currently has under contract 500 megawatts of
capacity from other generators of electricity.
Current Issues
While the Company improved its financial performance in 1993 compared to 1992,
the ability to maintain and improve its current level of earnings will depend
on several factors. Future trends in the Company's earnings will depend on the
continued economic growth in the Piedmont Carolinas, the Company's ability to
contain costs, its ability to maintain competitive prices, the outcome of
various legislative and regulatory actions and the success of the Company's
diversified activities.
Resource Optimization. The Company has been engaged in a concentrated effort
to more efficiently and effectively use its resources through better work
practices. During the first quarter of 1993, the Company offered a Limited
Period Separation Opportunity program (LPSO) which gave employees the option
of leaving the Company for a lump sum severance payment and, for qualifying
employees, enhanced retirement benefits. Implementing programs such as LPSO
and other efficiency practices has resulted in a continued workforce reduction
and in streamlined workflows. The number of full-time employees has decreased
from 19,945 at year-end 1990 to 18,274 at year-end 1993. Included in these
amounts are 496 and 789 employees of subsidiaries and affiliates for 1990 and
1993, respectively.
Income Tax Accounting Change. In January 1993, the Company implemented a
standard as required by the Financial Accounting Standards Board (FASB) that
requires a liability approach for financial accounting and reporting for
income taxes. While classification of certain items on the Consolidated
Balance Sheets has changed, principally because certain items previously
reported net of tax are now being reported on a gross basis, there is no
material effect on the Company's results of operations.
Nuclear Decommissioning Costs. Estimated site-specific nuclear decommissioning
costs, including the cost of decommissioning plant components not subject to
radioactive contamination, total approximately $955 million stated in 1990
dollars. This amount includes the Company's 12.5 percent ownership in the
Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station
are liable for providing decommissioning related to their ownership interests
in the station. Both the NCUC and the PSCSC have granted the Company recovery
of the estimated site-specific decommissioning costs through retail rates over
the expected remaining service periods of the Company's nuclear plants. Such
estimates presume that units will be decommissioned as soon as possible
following the end of their license life. Although subject to extension, the
current operating licenses for the Company's nuclear units expire as follows:
Oconee 1 and 2 - 2013, Oconee 3 - 2014; McGuire 1 - 2021, McGuire 2 - 2023;
and Catawba 1 - 2024, Catawba 2 - 2026.
The Nuclear Regulatory Commission (NRC) issued a rule-making in 1988 which
requires an external mechanism to fund the estimated cost to decommission
certain components of a nuclear unit subject to radioactive contamination. In
addition to the required external funding, the Company maintains an internal
reserve to provide for decommissioning costs of plant components not subject
to radioactive contamination. During 1993, the Company expensed approximately
$52.5 million which was contributed to the external funds and accrued an
additional $5.0 million to the internal reserve. The balance of the external
funds as of December 31, 1993, was $118.5 million. The balance of the internal
reserve as of December 31, 1993, was $200.0 million and is reflected in
Accumulated depreciation and amortization on the Consolidated Balance Sheets.
Management's opinion is that the estimated site-specific decommissioning costs
being recovered through rates, when coupled with assumed after-tax fund
earnings of 4.5 percent to 5.5 percent, are currently sufficient to provide
for the cost of decommissioning based on the Company's current decommissioning
schedule.
Environmental Update. The Company is subject to federal, state and local
regulations with regard to air and water quality, hazardous and solid waste
disposal, and other environmental matters. The Company was an operator of
manufactured gas plants prior to the early 1950s. The Company is entering into
a cooperative effort with the State of North Carolina and other owners of
certain former manufactured gas plant sites to investigate and, where
necessary, remediate these contaminated sites. The State of South Carolina has
expressed interest in entering into a similar arrangement. The Company is
considered by regulators to be a potentially responsible party and may be
subject to liability at two federal Superfund sites and two comparable state
sites. While the cost of remediation of these sites may be substantial, the
Company will share in any liability associated with remediation of
contamination at such sites with other potentially responsible parties.
Management is of the opinion that resolution of these matters will not have a
material adverse effect on the results of operations or financial position of
the Company.
The Clean Air Act Amendments of 1990. The Clean Air Act Amendments of 1990
require a two-phase reduction by electric utilities in the aggregate annual
emissions of sulfur dioxide and nitrogen oxide by the year 2000. The Company
currently meets all requirements of Phase I. The Company supports the national
objective of clean air in the most cost-effective manner and has already
reduced emissions through the use of low-sulfur coal in its fossil plants,
through efficient operations and by using nuclear generation. The sulfur
dioxide provisions of the Act allow utilities to choose among various
alternatives for compliance. The Company is currently developing a detailed
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compliance plan for Phase II requirements which must be filed with the
Environmental Protection Agency (EPA) by 1996. A preliminary strategy, which
allows for varying options, indicates that one-time costs associated with
bringing the Company into compliance with the Act could be as high as $1
billion, and that approximately $75 million in additional annual operating and
maintenance expenses will be incurred as well. These one-time costs could be
less depending on favorable developments in the emissions allowance market,
future regulatory and legislative actions, and advances in clean air
technology. All options within the preliminary strategy allow for full
compliance of Phase II requirements by the year 2000.
Stress Corrosion Cracking (SCC). Stress corrosion cracking has occurred in the
steam generators of Units 1 and 2 at the McGuire Nuclear Station and Unit 1 at
the Catawba Nuclear Station. The Company is of the opinion that the SCC is
caused by the defective design, workmanship and materials used by the
manufacturer of the steam generators. Catawba Unit 2, which has certain design
differences and came into service at a later date, has not yet shown the
degree of SCC which has occurred in McGuire Units 1 and 2 and Catawba Unit 1.
It is, however, too early in the life of Catawba Unit 2 to determine the
extent to which SCC will be a problem. Although the Company has taken steps to
mitigate the effects of SCC, the inherent potential for future SCC in the
Catawba and McGuire steam generators still exists. The Company has begun
planning for the replacement of steam generators and has set the following
schedule to begin the process: McGuire Unit 1 - 1995, Catawba Unit 1 - 1996,
McGuire Unit 2 - 1997. The Catawba Unit 2 steam generators have not been
scheduled for replacement. The order of replacement is subject to change based
on performance of the existing steam generators and on the overall performance
of the three units. The Company has signed an agreement with Babcock & Wilcox
International to purchase replacement steam generators. Steam generator
replacement at each unit is expected to take approximately four months and
cost approximately $170 million, excluding the cost of replacement power and
without consideration of reimbursement of applicable costs by the other joint
owners of Catawba Unit 1. Stress corrosion problems are excluded under the
nuclear insurance policies.
The Company in connection with its McGuire and Catawba stations and on behalf
of the other joint owners of the Catawba Station -- North Carolina Municipal
Power Agency Number 1, North Carolina Electric Membership Corporation,
Piedmont Municipal Power Agency and Saluda River Electric Cooperative, Inc. --
commenced a legal action on March 22, 1990. This action alleges that
Westinghouse Electric Corporation (Westinghouse), the supplier of the steam
generators, knew, or recklessly disregarded information in its possession,
that the steam generators supplied to McGuire and Catawba stations would be
susceptible to SCC and that Westinghouse deliberately concealed such
information from the Company. The Company is seeking a judgment against
Westinghouse for damages of approximately $600 million, including the cost of
necessary remedial measures, the cost of replacement steam generators and
payment for replacement power during the outages to accomplish the
replacement. In addition to these damages, the Company is seeking punitive or
treble damages and attorneys' fees. A trial date has been set for March 14,
1994.
Competition. The Energy Policy Act of 1992 has far-reaching implications for
the Company by moving utilities toward a more competitive environment. The Act
reformed certain provisions of the Public Utility Holding Company Act of 1935
(PUHCA) and removed certain regulatory barriers. For example, the Act allows
utilities to develop independent electric generating plants in the United
States for sales to wholesale customers, as well as to contract for utility
projects internationally, without becoming subject to registration under PUHCA
as an electric utility holding company. The Act requires transmission of power
for third parties to wholesale customers, provided the reliability of service
to the utility's local customer base is protected and the local customer base
does not subsidize the third-party service. Although the Act does not require
transmission access to retail customers, states can authorize such
transmission access to and for retail electric customers.
The electric utility industry is predominantly regulated on a basis designed
to recover the cost of providing electric power to its retail and wholesale
customers. If cost-based regulation were to be discontinued in the industry,
for any reason, including competitive pressure on the price of electricity,
utilities might be forced to reduce their assets to reflect their market basis
if such basis is less than cost. Discontinuance of cost-based regulation could
also require some utilities to write off their regulatory assets. Management
cannot predict the potential impact, if any, of these competitive forces on
the Company's future financial position and results of operations. However,
the Company is continuing to position itself to effectively meet these
challenges by maintaining prices that are regionally and nationally
competitive.
Subsidiary Activities. A major part of the future growth in the electric power
market is anticipated to be outside the traditional regulated framework and,
to a large extent, outside the United States. The Company, through its
subsidiaries, is participating in these international opportunities and
continues participating in domestic opportunities to provide additional value
to its shareholders. Internationally, the Company is seeking opportunities to
provide engineering consulting services, construction, operation and
maintenance of generation facilities, and ownership of transmission and
generation facilities. Although these opportunities are concentrated in areas
that utilize the Company's expertise, they present different and greater risks
than does the Company's core business. The Company considers only
opportunities in which the expected returns are commensurate with the risks
and makes efforts to mitigate such risks. At December 31, 1993, the Company
had equity investments of $84.5 million in international transmission and
generation facilities and $17.1 million in electric assets within the United
States, but outside its current service area. The Company is actively pursuing
additional international and domestic opportunities to capitalize on the
future potential growth of this market.
22
<PAGE>
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C>
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (thousands)
Electric revenues (a)................................. $ 4,281,876 $ 3,961,484 $ 3,816,960 $ 3,705,131 $3,692,955
Electric expenses (a)................................. 3,467,811 3,236,789 3,110,137 3,062,348 2,988,355
Electric operating income........................... 814,065 724,695 706,823 642,783 704,600
Other income.......................................... 71,269 85,007 150,905 146,740 101,826
Income before interest deductions................... 885,334 809,702 857,728 789,523 806,426
Interest deductions................................... 258,919 301,619 274,105 251,335 234,815
Net income............................................ 626,415 508,083 583,623 538,188 571,611
Dividends on preferred and preference stock......... 52,429 56,407 54,683 52,616 52,477
Earnings for common stock............................. $ 573,986 $451,676 $528,940 $ 485,572 $ 519,134
COMMON STOCK DATA (B)
Shares of common stock -- year-end (thousands)........ 204,859 204,859 204,699 202,584 202,563
-- average (thousands)......... 204,859 204,819 203,431 202,570 202,554
Per share of common stock
Earnings.............................................. $ 2.80 $ 2.21 $ 2.60 $ 2.40 $ 2.56
Dividends............................................. $ 1.84 $ 1.76 $ 1.68 $ 1.60 $ 1.52
Book value -- year-end................................ $ 21.17 $20.26 $19.86 $18.84 $ 18.05
Market price -- high-low............................. $44 7/8-35 3/8 $37 1/2-31 3/8 $35-26 3/4 $32 3/8-25 1/2 $28 1/4-21 3/8
-- year-end.................................. $42 3/8 $36 1/8 $35 $ 30 5/8 $28 1/16
BALANCE SHEET DATA (thousands)
Total assets.................................. $12,193,107 $10,950,387 $10,470,615 $10,083,507 $9,542,398
Long-term debt................................ $ 3,285,397 $ 3,288,111 $ 3,159,575 $ 3,102,746 $2,822,442
Preferred stock with sinking fund
requirements............................ $ 281,000 $ 279,519 $ 228,650 $ 239,800 $ 247,825
ELECTRIC AND OTHER STATISTICS
Kilowatt-hour sales (millions)
Residential................................. 19,465 17,789 17,918 17,221 16,895
General service............................. 16,904 15,818 15,586 15,032 14,206
Industrial.................................. 28,198 27,041 26,270 25,894 25,934
Other energy and wholesale (a)(c)........... 11,337 10,360 10,132 10,468 11,969
Total kilowatt-hour sales billed.......... 75,904 71,008 69,906 68,615 69,004
Unbilled kilowatt-hour sales................ 154 34 (19) (540) 370
Total kilowatt-hour sales................. 76,058 71,042 69,887 68,075 69,374
Residential customer data.....................
Average annual KWH use...................... 13,372 12,427 12,710 12,444 12,459
Average revenue billed per KWH.............. 7.32(cents) 7.38(cents) 7.10(cents) 7.07(cents) 7.09(cents)
Sources of energy (millions of KWH) (d)
Generated -- Coal........................... 34,097 28,999 26,455 27,262 26,175
-- Nuclear (e).............................. 48,211 48,238 49,328 44,649 47,773
-- Hydro (f)................................ 1,582 1,834 1,545 1,879 1,520
-- Oil and gas.............................. 43 5 7 53 27
Total generation............................ 83,933
79,076 77,335 73,843 75,495
Purchased power and net interchange (a)....... 1,750 1,403 587 1,531 1,158
Total output................................ 85,683 80,479 77,922 75,374 76,653
Less: Other Catawba joint owners' share....... 13,821 14,313 12,280 11,735 12,566
Plus: Purchases from other Catawba
joint owners.............................. 8,810 9,466 8,525 8,658 9,809
Total sources of energy................... 80,672 75,632 74,167 72,297 73,896
Line loss and Company usage................... 4,614 4,590 4,280 4,222 4,522
Total kilowatt-hour sales................. 76,058 71,042 69,887 68,075 69,374
System average heat rate...................... 9,921 9,974 9,996 10,007 10,013
System load factor............................ 60.2% 60.0% 59.4% 59.9% 61.8%
</TABLE>
(a) ELECTRIC REVENUES, ELECTRIC EXPENSES, KILOWATT-HOUR SALES AND NET
INTERCHANGE AND PURCHASED POWER FOR THE YEARS 1989 AND 1990 INCLUDE A
RECLASSIFICATION FOR CERTAIN POWER TRANSACTIONS PREVIOUSLY CLASSIFIED AS NET
INTERCHANGE AND PURCHASED POWER PRIOR TO A 1990 FERC ORDER.
(b) ALL COMMON STOCK DATA REFLECTS THE TWO-FOR-ONE SPLIT OF COMMON STOCK ON
SEPTEMBER 28, 1990.
(c) INCLUDES SALES TO NANTAHALA POWER AND LIGHT COMPANY.
(d) DOES NOT INCLUDE OPERATING STATISTICS OF NANTAHALA POWER AND LIGHT COMPANY.
(e) INCLUDES 100% OF CATAWBA GENERATION.
(f) 1991 INCLUDES KWH OF THE BAD CREEK HYDROELECTRIC STATION PRIOR TO COMMERCIAL
OPERATION.
23
<PAGE>
SELECTED FINANCIAL DATA
QUARTERLY FINANCIAL DATA
<TABLE>
<CAPTION>
First Second Third Fourth
Dollars in Thousands (except per-share data) Quarter Quarter Quarter Quarter Total
<S> <C> <C> <C> <C> <C>
1993 by quarter
Electric Revenues........................................ $1,007,783 $987,218 $1,289,994 $996,881 $4,281,876
Electric Operating Income................................ 188,522 169,111 283,411 173,021 814,065
Net Income............................................... 141,684 122,470 241,409 120,852 626,415
Earnings Per Share....................................... $0.63 $0.53 $1.12 $0.52 $2.80
1992 by quarter
Electric Revenues........................................ $981,330 $899,319 $1,139,525 $941,310 $3,961,484
Electric Operating Income................................ 161,726 148,888 248,081 166,000 724,695
Net Income............................................... 106,365 86,938 190,519 124,261 508,083
Earnings Per Share....................................... $0.45 $0.36 $0.85 $0.55 $2.21
</TABLE>
Generally, quarterly earnings fluctuate with seasonal weather conditions, timing
of rate changes and maintenance of electric generating units, especially nuclear
units.
24
SUBSIDIARY HIGHLIGHTS
The earnings contribution of the Company's diversified activities and
subsidiaries was $22.0 million in 1993, $25.7 million in 1992 and $23.6 million
in 1991. (a)(b) Highlights of selected subsidiaries are presented below.
(dollars in thousands)
ELECTRIC POWER SUPPLY
Nantahala Power and Light Company provides service to a five-county area in the
western North Carolina mountains by its operation of 11 hydroelectric stations
and purchases of supplemental power.
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Assets net of
liabilities................................ $ 47,679 $ 42,910 $ 39,384
Net
income...... ............................. $ 4,261 $ 3,526 $ 2,721
Number of employees
(c).......................................... 194 191 194
</TABLE>
FUNDS MANAGEMENT
Church Street Capital Corp. (CSCC) manages investment of funds for the Company
and is the parent company of several subsidiaries. CSCC has no full-time
employees.
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Short-term investments and marketable
securities............................... $ 155,871 $ 173,347 $ 120,303
Investment income (after tax)............... $ 3,548 $ 5,404 $ 6,397
</TABLE>
Highlights of CSCC's subsidiaries are presented below:
REAL ESTATE MANAGEMENT, LAND DEVELOPMENT
Crescent Resources, Inc. is engaged in forest management, real estate
development, and sales and leasing.
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Asset net of
liabilities................................ $133,034 $ 110,949 $ 88,046
Net income (a)............................... $ 16,327 $ 16,613 $ 9,661
Number of employees (c)...................... 77 73 69
</TABLE>
ENGINEERING, CONSTRUCTION, TECHNICAL SERVICES AND POWER DEVELOPMENT
Engineering, construction, technical services and power development
opportunities are pursued nationally and internationally.
Duke Engineering & Services, Inc. markets engineering, construction, quality
assurance, consulting and other engineering-related services for utility
facilities other than coal-fired plants.
Duke/Fluor Daniel, a joint venture with Fluor Daniel, Inc., provides design,
construction, operation and maintenance support primarily for coal-fired
generating plants.
Duke Energy Group, parent of Duke Energy Corp., structures, finances and
manages investments in electric generation and transmission facilities.
<TABLE>
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Assets net of
liabilities.................................. $127,708 $ 36,687 $ 13,480
Net
income....................................... $ 40 $ 33 $ 1,512
Number of employees (c)....................... 518 495 364
</TABLE>
(a) 1991 EXCLUDES THE CUMULATIVE EFFECT OF AN ACCOUNTING CHANGE OF $6,727,000,
AFTER TAX.
(b) THE EARNINGS CONTRIBUTION OF THE COMPANY'S SUBSIDIARIES AND NON-ELECTRIC
OPERATIONS INCLUDES ELIMINATION OF INTERCOMPANY PROFIT OF $509,000 AND
$1,211,000, AFTER TAX, IN 1993 AND 1992, RESPECTIVELY.
(c) FULL-TIME EMPLOYEES.
25
<PAGE>
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement
Nos. 33-59926, 33-60314, 33-19274, 33-50543, 33-50715 and 33-50617 of Duke
Power Company on Form S-3 and Registration Statement No. 2-72172 of Duke Power
Company on Form S-8 of our report dated February 11, 1994, appearing in this
Form 8-K of Duke Power Company filed with the Securities and Exchange Commission
on February 18, 1994.
Deloitte & Touche
DELOITTE & TOUCHE
Charlotte, North Carolina
February 18, 1994
<PAGE>
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 thereunto duly authorized.
DUKE POWER COMPANY
(Registrant)
By ELLEN T. RUFF
ELLEN T. RUFF
SECRETARY
Date: February 18, 1994
