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: February 10, 1997
Date of Earliest Event Reported: February 10, 1997
DUKE POWER COMPANY
(Exact name of registrant as specified in its charter)
North Carolina
(State or other jurisdiction of
incorporation)
1-4928
(Commission File
Number)
56-0205520
(I.R.S. Employer
Identification Number)
422 South Church Street
Charlotte, North Carolina 28242
(Address, including zip code, of principal executive offices)
------------------
Registrant's telephone number, including area code:
(704) 382-8127
<PAGE>
Item 7. Financial Statements and Exhibits.
(c) Exhibits.
23 Consent of Independent Auditors.
27 Financial Data Schedule for December 31, 1996.
99.1 Audited Consolidated Balance Sheets as of December 31, 1996 and
1995, and the related Consolidated Statements of Income,
Consolidated Statements of Retained Earnings, and Consolidated
Statements of Cash Flows for each of the years ended December
31, 1994, 1995 and 1996, and Notes to Consolidated Financial
Statements.
99.2 Independent Auditors' Report.
99.3 Responsibility for Financial Statements.
99.4 Management's Discussion and Analysis of Results of Operations and
Financial Condition.
99.5 Selected Financial Data.
99.6 Quarterly Financial Data.
99.7 Stock Market Information.
<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
By:
Richard J. Osborne
Senior Vice President and
Chief Financial Officer
Date: February 10, 1997
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement
Nos. 33-19274, 33-50543, 33-50715, 33-50617, 333-02571 and 333-14209 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 7, 1997, appearing in this
Form 8-K of Duke Power Company filed with the Securities and Exchange Commission
on February 10, 1997.
DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 10, 1997
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1996 1995 1994
<S> <C> <C> <C>
OPERATING REVENUES (Notes 1, 2 and 11)...................... $4,757,974 $4,676,684 $4,488,913
OPERATING EXPENSES
Fuel used in electric generation (Note 1)................. 758,498 744,226 705,019
Net interchange and purchased power (Notes 2 and 3)....... 378,724 468,293 553,355
Other operation and maintenance........................... 1,505,028 1,403,547 1,341,659
Depreciation and amortization (Note 1).................... 492,185 458,131 459,781
General taxes............................................. 261,336 253,436 249,273
Total operating expenses................................ 3,395,771 3,327,633 3,309,087
OPERATING INCOME............................................ 1,362,203 1,349,051 1,179,826
INTEREST EXPENSE AND OTHER INCOME (Note 1)
Interest expense.......................................... (283,075) (289,318) (270,217)
Allowance for funds used during construction and other
deferred returns........................................ 111,891 125,040 111,872
Other, net................................................ 14,638 (3,794) 14,414
Total interest expense and other income................. (156,546) (168,072) (143,931)
INCOME BEFORE INCOME TAXES.................................. 1,205,657 1,180,979 1,035,895
INCOME TAXES (Notes 1 and 4)................................ 475,691 466,441 397,019
NET INCOME.................................................. 729,966 714,538 638,876
Dividends on preferred and preference stock............... 44,245 48,903 49,724
EARNINGS FOR COMMON STOCK................................... $ 685,721 $ 665,635 $ 589,152
COMMON STOCK DATA (Note 6)
Average shares outstanding (thousands).................... 203,553 204,859 204,859
Earnings per share........................................ $ 3.37 $ 3.25 $ 2.88
Dividends per share....................................... $ 2.08 $ 2.00 $ 1.92
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Dollars in Thousands Year ended December 31, 1996 1995 1994
BALANCE -Beginning of year.................. $2,858,275 $2,605,920 $2,410,825
ADD - Net income............................ 729,966 714,538 638,876
Total................................ 3,588,241 3,320,458 3,049,701
DEDUCT
Dividends
Common stock............................ 423,064 409,716 393,370
Preferred and preference stock.......... 44,245 48,903 49,724
Capital stock transactions, net........... 128,358 3,564 687
Total deductions..................... 595,667 462,183 443,781
BALANCE - End of year....................... $2,992,574 $2,858,275 $2,605,920
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
1
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Dollars in Thousands Year ended December 31, 1996 1995 1994
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income................................................ $ 729,966 $ 714,538 $ 638,876
Adjustments to reconcile net income to net cash
provided by operating activities:
Non-cash items
Depreciation and amortization........................... 667,713 674,816 647,515
Deferred income taxes and investment tax credit
amortization.......................................... (27,641) 5,989 94,261
Allowance for equity funds used during
construction.......................................... (15,824) (23,082) (27,411)
Purchased capacity levelization......................... 73,473 (33,149) (268,925)
Other, net.............................................. 47,384 76,029 22,460
(Increase) Decrease in
Accounts receivable.................................. (20,289) (136,838) 47,586
Inventory............................................ 40,476 (14,549) (28,568)
Prepayments.......................................... (1,031) (7,178) (435)
Increase (Decrease) in
Accounts payable..................................... 15,153 11,694 (52,506)
Taxes accrued........................................ (19,750) 14,454 (51,641)
Interest accrued and other liabilities............... (6,966) 28,934 14,523
Total adjustments....................................... 752,698 597,120 396,859
Net cash provided by operating
activities....................................... 1,482,664 1,311,658 1,035,735
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures and other property
additions............................................... (646,465) (713,299) (772,452)
Investment in nuclear fuel................................ (84,206) (76,603) (108,711)
External funding for decommissioning...................... (56,470) (56,470) (52,524)
Pre-funded pension cost................................... - - (30,000)
Investment in affiliates.................................. (25,708) (54,945) (6,718)
Net change in investment securities....................... (25,887) 54,425 17,922
Net cash used in investing activities.............. (838,736) (846,892) (952,483)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of
First and refunding mortgage bonds...................... - 173,839 343,824
Short-term notes payable, net........................... (49,750) 48,200 86,300
Construction loans and other............................ 113,997 47,643 57,032
Payments for the redemption of
First and refunding mortgage bonds...................... (3,097) (157,365) (81,781)
Common stock............................................ (159,000) - -
Construction loans and other............................ (91,548) (9,416) (18,885)
Preferred stock......................................... - (100,516) (1,500)
Dividends paid............................................ (466,751) (458,018) (443,633)
Other..................................................... 2,917 (1,153) (20,991)
Net cash used in financing activities.............. (653,232) (456,786) (79,634)
Net increase (decrease) in cash............................. (9,304) 7,980 3,618
Cash at beginning of year................................... 45,410 37,430 33,812
CASH AT END OF YEAR......................................... $ 36,106 $ 45,410 $ 37,430
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
2
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
ASSETS
Dollars in Thousands December 31, 1996 1995
<S> <C> <C>
CURRENT ASSETS
Cash (Notes 5 and 10)..................................... $ 36,106 $ 45,410
Short-term investments (Notes 1 and 10)................... 72,712 76,300
Receivables (less allowance for losses: 1996 -
$7,134; 1995 - $6,352) (Note 1)......................... 709,992 689,703
Inventory - at average cost............................... 301,365 341,841
Prepayments and other..................................... 23,931 22,900
Total current assets.................................. 1,144,106 1,176,154
INVESTMENTS AND OTHER ASSETS
Investments in affiliates (Note 11)....................... 188,982 163,274
Other investments, at cost or less (Note 10).............. 114,669 85,194
Nuclear decommissioning trust funds (Notes 10 and 14)..... 362,627 273,466
Pre-funded pension cost (Note 12)......................... 80,000 80,000
Total investments and other assets.................... 746,278 601,934
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 3, 9, 13 and 14)
Electric plant in service (at original cost)
Production.............................................. 7,278,439 7,154,332
Transmission............................................ 1,543,688 1,532,302
Distribution............................................ 4,303,885 4,105,513
Other................................................... 1,068,342 1,030,226
Electric plant in service............................. 14,194,354 13,822,373
Less accumulated depreciation and amortization.......... 5,438,498 5,122,192
Electric plant in service, net........................ 8,755,856 8,700,181
Nuclear fuel............................................ 604,813 731,691
Less accumulated amortization........................... 363,290 453,921
Nuclear fuel, net..................................... 241,523 277,770
Construction work in progress (including nuclear fuel
in process:
1996 - $27,546; 1995 - $25,500)......................... 388,999 382,582
Total electric plant, net............................. 9,386,378 9,360,533
Other property - at cost (less accumulated
depreciation:
1996 - $31,544; 1995 - $29,956)......................... 426,039 354,713
Total property, plant and equipment, net.............. 9,812,417 9,715,246
DEFERRED DEBITS (Notes 1, 3, 4 and 13)
Purchased capacity costs.................................. 892,000 965,473
Debt expense.............................................. 169,842 180,930
Regulatory asset related to income taxes.................. 488,936 490,676
Regulatory asset related to DOE assessment fee............ 94,717 101,274
Other..................................................... 121,394 126,797
Total deferred debits................................. 1,766,889 1,865,150
TOTAL ASSETS................................................ $13,469,690 $ 13,358,484
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
3
<PAGE>
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Dollars in Thousands December 31, 1996 1995
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable.......................................... $ 327,315 $ 343,692
Notes payable (Notes 5 and 10)............................ 105,550 155,300
Taxes accrued (Note 1).................................... 973 34,884
Interest accrued.......................................... 64,589 73,675
Current maturities of long-term debt (Note 9)............. 212,309 12,071
Other (Note 13)........................................... 152,233 149,555
Total current liabilities............................. 862,969 769,177
LONG-TERM DEBT (Notes 5, 9 and 10).......................... 3,538,114 3,711,405
ACCUMULATED DEFERRED INCOME TAXES (Notes 1 and 4)........... 2,376,012 2,382,204
DEFERRED CREDITS AND OTHER LIABILITIES
Investment tax credit (Notes 1 and 4)..................... 250,117 261,347
DOE assessment fee (Note 1)............................... 94,717 101,274
Nuclear decommissioning costs externally funded (Note
14)..................................................... 362,627 273,466
Other..................................................... 412,419 390,427
Total deferred credits and other
liabilities......................................... 1,119,880 1,026,514
PREFERRED AND PREFERENCE STOCK WITH SINKING FUND
REQUIREMENTS (Notes 8 and 10)............................. 234,000 234,000
PREFERRED AND PREFERENCE STOCK WITHOUT SINKING
FUND REQUIREMENTS (Notes 7 and 10)........................ 450,000 450,000
COMMITMENTS AND CONTINGENCIES (Notes 11 and 13).............
COMMON STOCKHOLDERS' EQUITY (Note 6)
Common stock, no par, 300,000,000 shares authorized;
201,589,596 shares outstanding for 1996 and
204,859,339 shares outstanding for 1995............... 1,896,141 1,926,909
Retained earnings......................................... 2,992,574 2,858,275
Total common stockholders' equity..................... 4,888,715 4,785,184
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $13,469,690 $ 13,358,484
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
4
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. NATURE OF OPERATIONS
The Company is primarily engaged in the generation, transmission,
distribution and sale of electric energy in the central portion of North
Carolina and the western portion of South Carolina, comprising the area in both
states known as the Piedmont Carolinas. The Company is one of the nation's
largest investor-owned electric utilities.
The Company is also engaged in a variety of diversified operations, most of
which are organized in separate subsidiaries. The Company's subsidiaries and
diversified activities are in the Associated Enterprises Group (AEG). AEG
includes Church Street Capital Corp.; Crescent Resources, Inc.; Duke Energy
Group, Inc.; Duke Engineering & Services, Inc.; Duke/Fluor Daniel; Duke/Louis
Dreyfus, LLC; Duke Merchandising; DukeNet Communications, Inc.; Duke Water
Operations; and Nantahala Power and Light Company. Certain subsidiaries have
invested in both domestic and international affiliates. (See Note 11.)
The financial 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. In preparing these statements, management makes informed judgments and
estimates of the expected effects of events and transactions that are currently
being reported. However, actual results could differ from these estimates.
B. REVENUES
Electric revenues are recorded as service is rendered to customers.
"Receivables" on the Consolidated Balance Sheets include $205,656,000 and
$206,792,000 as of December 31, 1996 and 1995, respectively, for electric
service that has been rendered but not yet billed to customers by Duke Power,
and $4,294,000 as of December 31, 1996 for electric service that has been
rendered but not yet billed to customers by Nantahala Power and Light Company.
C. 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.
D. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC represents the estimated debt and equity costs of capital funds
necessary to finance the construction of new regulated facilities. AFUDC, a non-
cash item, is recognized as a cost of "Construction work in progress," with an
offsetting credit to "Interest expense and other income." 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 AFUDC rates of 9.7, 9.3 and 9.6 percent for Duke Power for 1996, 1995
and 1994, respectively, include a component for debt cost on a pre-tax basis.
Rates for all periods are compounded semiannually.
E. OTHER DEFERRED RETURNS
Other deferred returns represent the estimated financing costs associated
with funding certain regulatory assets. These regulatory assets primarily arise
from the Company's funding of purchased capacity costs above levels collected in
rates. Other deferred returns are non-cash items. They are primarily recognized
as an addition to "Purchased capacity costs" and as an offsetting credit to
"Interest expense and other income."
5
<PAGE>
F. DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT
Provisions for electric plant depreciation are recorded using the straight-
line method. The year-end composite weighted-average depreciation rates were
3.44, 3.48 and 3.46 percent for 1996, 1995 and 1994, respectively.
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 $9,472,000 during 1996 and has paid $45,022,000
cumulatively related to its ownership interest in nuclear plants. The Company
has reflected the remaining liability and regulatory asset of $94,717,000 in the
Consolidated Balance Sheet at December 31, 1996.
G. SUBSIDIARIES
The Company's consolidated financial statements reflect consolidation of all
of its majority-owned subsidiaries. Intercompany transactions have been
eliminated in consolidation.
H. INCOME TAXES
The Company and its subsidiaries file a consolidated federal income tax
return.
Deferred income taxes have been provided for temporary differences.
Temporary differences occur when events and transactions recognized for
financial reporting result in taxable or tax-deductible amounts in different
periods. Investment tax credits have been deferred and are being amortized over
the estimated useful lives of the related properties.
I. UNAMORTIZED DEBT PREMIUM, DISCOUNT AND EXPENSE
Expenses incurred in connection with the issuance of presently outstanding
long-term debt issued for regulated operations, and premiums and discounts
relating to such debt, are being amortized over the terms of the respective
issues. Also, any call premiums or unamortized expenses associated with
refinancing higher-cost debt obligations used to finance regulated assets and
operations are being amortized over the lives of the new issues of long-term
debt.
J. CONSOLIDATED STATEMENTS OF CASH FLOWS
For purposes of the Consolidated Statements of Cash Flows, the Company's
short-term 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 $491,340,000, $441,440,000 and $372,416,000 for
the years ended December 31, 1996, 1995 and 1994, respectively.
Interest paid, net of amounts capitalized, was $269,219,000, $258,698,000
and $236,696,000 for the years ended December 31, 1996, 1995 and 1994,
respectively.
K. COST-BASED REGULATION
As a regulated entity, the Company is subject to the provisions of SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation." Accordingly,
the Company records certain assets and liabilities that result from the effects
of the ratemaking process that would not be recorded under generally accepted
accounting principles for non-regulated entities. Currently, 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 cost-based prices of electricity, profits
could be reduced, and utilities might be required to reduce their asset balances
to reflect a market basis less than cost. Discontinuance of cost-based
regulation would also require affected utilities to write off their associated
regulatory assets. The regulatory assets of the Company are classified as
"Deferred debits" on the Consolidated Balance
6
<PAGE>
Sheets. Substantially all of the "Deferred debits" are 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 continues to position itself to effectively meet these
challenges by maintaining prices that are locally, regionally and nationally
competitive.
NOTE 2. RATE MATTERS
DUKE POWER COMPANY
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 Duke Power's rates for sales to wholesale customers. Sales to the other
joint owners of the Catawba Nuclear Station, which represent a substantial
majority of Duke Power's wholesale revenues, are set through contractual
agreements. (See Note 3.)
The most recent general rate increase requests in Duke Power's retail
jurisdictions were filed and approved in 1991. Duke Power also filed its most
recent general rate increase request within the FERC wholesale jurisdiction in
1991. A negotiated settlement between Duke Power and the wholesale customers was
approved by the FERC in 1992.
Fuel costs are reviewed semiannually in the wholesale jurisdiction and
annually in the South Carolina retail jurisdiction, 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 Duke Power to adjust rates for past over- or under-
recovery of fuel costs. Therefore, Duke Power reflects in revenues the
difference between actual fuel costs incurred and fuel costs recovered through
rates.
The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a
decrement rider of 0.432 cents per kilowatt-hour, or an average of approximately
8 percent, affecting South Carolina retail customers. South Carolina retail
sales represent approximately 30 percent of the Company's total retail sales.
The rate reduction was reflected on bills rendered on or after June 1, 1996.
This net decrement rider reflects an interim true-up decrement adjustment
associated with the levelization of Catawba Nuclear Station purchased capacity
costs and an interim true-up increment associated with amortization of the
demand-side management deferral account. The rate adjustment was made because,
in the South Carolina retail jurisdiction, cumulative levelized revenues
associated with the recovery of Catawba purchased capacity costs had exceeded
purchased capacity payments and accrual of deferred returns, and certain demand-
side costs had exceeded the level reflected in rates.
Certain of the Company's wholesale customers, excluding the other Catawba
joint owners, initiated proceedings in 1995 before the FERC concerning rate
matters. The Company and nine of its eleven wholesale customers entered into a
settlement in July 1996 which reduced the customers' rates by approximately 9
percent and renewed their contracts with the Company through the year 2000. Both
of the customers that did not enter into the settlement have signed agreements
to purchase energy from other suppliers beginning in 1997. The eleven wholesale
customers involved in this matter accounted for less than 2 percent of the
Company's overall electric revenues during 1996. The two customers that have
signed agreements with other suppliers accounted for less than 0.5 percent of
the Company's 1996 overall electric revenues.
NANTAHALA POWER AND LIGHT COMPANY
During 1996, Nantahala Power and Light Company (NP&L) filed an application
with and received approval from the NCUC to increase its annual retail service
revenues by $4.6 million. NP&L's wholesale rates are adjusted annually to
reflect current costs. Purchased power costs of NP&L are reviewed annually and
during general rate case proceedings by the NCUC. NP&L is allowed to adjust
rates for past over- or under-recovery of purchased power costs. Therefore,
NP&L defers the difference between actual purchased power costs incurred and
those recovered through rates.
7
<PAGE>
NOTE 3. JOINT OWNERSHIP OF GENERATING FACILITIES
The Company previously 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:
Ownership Interest
Owner in the Station
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%
Each owner has provided its own financing for its ownership interest in the
station.
The Company retains a 12.5 percent ownership interest in the Catawba Nuclear
Station. As of December 31, 1996, $497,304,000 of "Electric plant in service"
and "Nuclear fuel" represents the Company's investment in Units 1 and 2.
Accumulated depreciation and amortization of $192,057,000 associated with
Catawba has been recorded as of year-end. The Company's share of operating costs
of Catawba is included 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
purchased power agreements were effective beginning with the commercial
operation of each unit. Unit 1 and Unit 2 began commercial operation in June
1985 and August 1986, respectively. The purchased power agreements were
established for 15 years for NCMPA and PMPA and 10 years for NCEMC and Saluda
River. While the purchased power agreements with NCMPA and PMPA extend for 15
years, a significant decrease in the percentage of capacity and energy the
Company is obligated to purchase occurs in the 11th calendar year of operation
for each unit. This significant decrease occurred in 1995 for Unit 1 and 1996
for Unit 2.
The agreements also provide for supplemental power sales by the Company to
the other joint owners. Such power sales are to satisfy capacity and energy
needs of the other joint owners beyond the capacity and energy which they retain
from Catawba or potentially acquire in the form of other resources. The
agreements further provide the other joint owners the ability to secure such
supplemental requirements outside of these contractual agreements following an
appropriate notice period. NCEMC and Saluda River have given appropriate notice
that they intend to acquire their supplemental capacity requirements outside of
these agreements effective January 1, 2001 and January 1, 2002, respectively,
thus relieving the Company of the obligation to serve this portion of load. As
the joint owners retain more capacity and energy from Catawba, or a third
party, supplemental power sales are expected to decline.
The agreements with each of the other joint owners include provisions that
the Company will provide generating reserves to backstand the other joint
owners' retained capacity in the Catawba plant at the system average cost of
installed capacity. Additionally, the agreements include certain reliability
exchanges designed to manage outage-related risks by exchanging energy
entitlements between the Catawba Nuclear Station and the McGuire Nuclear
Station, impacting the Company as well as all the other joint owners.
Purchased energy cost payments are based on variable operating costs and are
a function of the generation output of Catawba. Purchased capacity payments are
based on the fixed costs of the plant and include the capital costs and fixed
operating and maintenance costs. Actual purchased capacity costs for 1996 and
projected obligations for 1997 through 2001, including the impact of the 1995
settlement agreement with NCMPA and PMPA (See Note 13), are as follows (dollars
in thousands):
PURCHASED CAPACITY PURCHASED CAPACITY TOTAL PURCHASED
YEAR CAPITAL COST FIXED O&M CAPACITY
1996 Actual $ 84,303 $ 40,499 $ 124,802
1997 Projected $ 67,030 $ 34,858 $ 101,888
1998 Projected $ 48,423 $ 26,388 $ 74,811
1999 Projected $ 35,337 $ 19,122 $ 54,459
2000 Projected $ 4,286 $ 2,470 $ 6,756
2001 Projected - - -
Effective in its November 1991 rate order, the North Carolina Utilities
Commission 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 Public Service Commission of South Carolina 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.
Levelization was reaffirmed through inclusion in rates approved in March 1992 by
the Federal Energy Regulatory Commission (FERC). The portion of purchased
capacity subject to levelization not currently recovered in rates is being
deferred, and the Company is recording a deferred return on the accumulated
balance. The Company recovers the accumulated balance, including the deferred
return, when the sum of the declining purchased capacity payments and accrual of
deferred returns for the current period drops below the levelized revenues.
Jurisdictional levelizations are
8
<PAGE>
intended to recover total costs, including deferred returns, and are subject
to adjustments, including final true-ups. The Company recovers the costs of
purchased energy and the non-levelized portion of purchased capacity on a
current basis.
The current levelized revenues approved in the Company's last general rate
proceedings are $211,423,000, $94,137,000 and $6,815,000 for North Carolina
retail, South Carolina retail and Other Wholesale (FERC), respectively.
Purchased power costs, subject to levelization, are deferred based on allocation
factors of approximately 62 percent, 26 percent and 2 percent for North Carolina
retail, South Carolina retail and Other Wholesale (FERC), respectively. The
PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider
for an interim true-up adjustment. (See Note 2.) The Company also recovers an
allocated amount of purchased power costs in the pricing of supplemental sales
made to the other joint owners on a current basis.
During 1996, in the North Carolina retail and FERC wholesale jurisdictions,
annual levelized revenues exceeded purchased capacity payments and the accrual
of deferred returns for the first time. In the South Carolina retail
jurisdiction, cumulative levelized revenues have exceeded purchased capacity
payments and accrual of deferred returns.
For the years ended December 31, 1996, 1995 and 1994, the Company recorded
purchased capacity and energy costs from the other joint owners of $151,174,000,
$388,246,000 and $604,505,000, respectively. These amounts, after adjustments
for the costs 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, 1996 and 1995, $892,000,000 and $965,473,000,
respectively, associated with the cost of capacity purchased but not reflected
in current rates have been accumulated in the Consolidated Balance Sheets as
"Purchased capacity costs."
NOTE 4. INCOME TAX EXPENSE
Accumulated deferred income taxes consist primarily of the following (dollars
in thousands):
<TABLE>
<CAPTION>
December 31, 1996 December 31, 1995
<S> <C> <C> <C> <C>
Excess tax over book depreciation at historical
tax rates................................................ $1,424,709 $1,387,925
Regulatory liability related to adjusting deferred
taxes to the current statutory tax rate.................. (108,462)* (114,538)*
Net excess tax over book depreciation................... $1,316,247 $1,273,387
Regulatory asset related to restating to a pre-tax
basis.................................................... 597,398* 605,214*
Deferred purchased capacity costs.......................... 345,089 374,112
Book versus tax basis differences.......................... 42,963 60,443
Loss on bond redemptions................................... 63,962 68,135
Other...................................................... 10,353 913
Total deferred income taxes............................. $2,376,012 $2,382,204
</TABLE>
* The net regulatory asset related to income taxes is $488,936,000 for 1996
and $490,676,000 for 1995.
Total deferred income tax liability was $2,932,260,000 as of December 31,
1996, and $2,946,711,000 as of December 31, 1995. Total deferred income tax
asset was $556,248,000 as of December 31, 1996, and $564,507,000 as of December
31, 1995.
Income tax expense for the years ended December 31, 1996, 1995 and 1994
consisted of the following (dollars in thousands):
1996 1995 1994
Current income taxes
Federal............................. $413,429 $377,237 $249,968
State............................... 89,903 83,215 52,790
Total current income taxes......... 503,332 460,452 302,758
Deferred taxes, net
Federal............................. (16,706) 13,466 83,359
State............................... 295 3,770 22,153
Total deferred taxes, net.......... (16,411) 17,236 105,512
Investment tax credit amortization... (11,230) (11,247) (11,251)
Total income tax expense........... $475,691 $466,441 $397,019
9
<PAGE>
Income taxes differ from amounts computed by applying the statutory tax rate
to pre-tax income for the years ended December 31, 1996, 1995 and 1994 as
follows (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
Income taxes on pre-tax income at the statutory federal
rate of 35%............................................... $421,980 $413,343 $362,563
Increase (reduction) in tax resulting from:
Allowance for funds used during construction (AFUDC)....... (5,538) (8,079) (9,594)
Amortization of investment tax credit deferrals............ (11,230) (11,247) (11,251)
AFUDC in book depreciation/amortization.................... 19,990 21,057 19,027
Deferred income tax flowback at rates higher than
statutory................................................ (6,389) (5,675) (5,530)
State income taxes, net of federal income tax
benefits................................................. 58,242 56,210 47,872
Other items, net........................................... (1,364) 832 (6,068)
Total income tax expense............................. $475,691 $466,441 $397,019
</TABLE>
NOTE 5. SHORT-TERM BORROWINGS AND CREDIT FACILITIES
The following credit facilities were available to the Company at December 31,
1996 and 1995:
<TABLE>
<CAPTION>
Line of Credit at Outstanding at Line of Credit at Outstanding at
Type of Facility December 31, 1996 December 31, 1996 December 31, 1995 December 31, 1995
<S> <C> <C> <C> <C>
Annually renewable lines of credit $ 64,900,000 $ 8,550,000 $ 64,900,000 $ 29,300,000
Two-year revolving facilities (a) 40,000,000 - 40,000,000 -
Four-year revolving facilities (b) 235,000,000 42,000,000 210,000,000 30,043,000
Five-year revolving facilities (c) 355,000,000 - 355,000,000 -
$ 694,900,000 $ 50,550,000 $ 669,900,000 $ 59,343,000
</TABLE>
(a) THE COMPANY HAD $40,000,000 IN POLLUTION CONTROL BONDS, INCLUDED IN
LONG-TERM DEBT, OUTSTANDING THROUGHOUT 1996 AND 1995 BACKED BY THESE FACILITIES.
(b) THE OUTSTANDING BALANCES OF $42,000,000 IN 1996 AND $30,043,000 IN 1995 ARE
INCLUDED IN LONG-TERM DEBT.
(c) THE COMPANY HAD $130,000,000 IN COMMERCIAL PAPER, INCLUDED IN LONG-TERM
DEBT, OUTSTANDING THROUGHOUT 1996 AND 1995 BACKED BY THESE FACILITIES.
Cash balances maintained at the banks on deposit were $11,336,000 as of
December 31, 1996, and $17,120,000 as of December 31, 1995. 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 $45,000 as of December 31, 1996
and 1995. 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>
Twelve Months Ended
December 31, 1996 December 31, 1995 December 31, 1994
<S> <C> <C> <C>
Amount outstanding at end of period - average rate of
6.05% as of December 31, 1996, 5.91% as of
December 31, 1995, and 6.02% as of
December 31, 1994 ....................................... $ 105,550 $ 155,300 $ 107,100
Maximum amount outstanding during the period............... $ 176,450 $ 264,300 $ 143,400
Average amount outstanding during the period............... $ 56,343 $ 88,470 $ 24,161
Weighted-average interest rate for the period - computed
on a daily basis......................................... 5.33% 6.05% 4.58%
</TABLE>
10
<PAGE>
NOTE 6. COMMON STOCK AND RETAINED EARNINGS
COMMON STOCK
As of December 31, 1996, a total of 9,004,659 shares was reserved for
issuance for stock plans.
On February 27, 1996, the Board of Directors authorized the Company to
repurchase up to $1 billion of its common stock over the next five years. As of
December 31, 1996, approximately 3.3 million shares had been repurchased for
$159 million. On January 28, 1997, the Board of Directors amended the program to
expressly limit the number of shares authorized for repurchase under the
program, from the initiation of the program through a date two years after the
consummation of the proposed merger with PanEnergy Corp, to an amount not to
exceed 15 million shares. (See Note 13.)
RETAINED EARNINGS
As of December 31, 1996, substantially all of the Company's retained
earnings were unrestricted as to the declaration or payment of dividends.
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, 1996 and 1995:
Par Value Shares
Preferred Stock $ 100 12,500,000
Preferred Stock A $ 25 10,000,000
Preference Stock $ 100 1,500,000
As of December 31, 1996 and 1995, there were no shares of preference stock
outstanding. Preferred stock without sinking fund requirements as of December
31, 1996 and 1995, was as follows (dollars in thousands):
<TABLE>
<CAPTION>
Year Shares
Rate/Series Issued Outstanding 1996 1995
<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
7.85% S..................... 1992 600,000 60,000 60,000
7.00% W..................... 1993 500,000 50,000 50,000
7.04% Y..................... 1993 600,000 60,000 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 60,000
Auction Series A............. 1990 750,000 75,000 75,000
Total.................... $450,000 $450,000
</TABLE>
11
<PAGE>
NOTE 8. PREFERRED AND PREFERENCE STOCK WITH SINKING FUND REQUIREMENTS
The following shares of stock were authorized with or without sinking fund
requirements as of December 31, 1996 and 1995:
Par Value Shares
Preferred Stock $ 100 12,500,000
Preferred Stock A $ 25 10,000,000
Preference Stock $ 100 1,500,000
As of December 31, 1996 and 1995, there were no shares of preference stock
outstanding. Preferred stock with sinking fund requirements as of December 31,
1996 and 1995, was as follows (dollars in thousands):
<TABLE>
<CAPTION>
Year Shares
Rate/Series Issued Outstanding 1996 1995
<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
7.50% 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 50,000
Total..................... $234,000 $234,000
</TABLE>
The annual sinking fund requirements through 2001 are $0 in 1997, $4,250,000
in 1998, $24,250,000 in 1999, $37,250,000 in 2000 and $37,250,000 in 2001. Some
additional redemptions are permitted at the Company's option.
The call provisions for the outstanding preferred stock specify various
redemption prices not exceeding 108 percent of par value, plus accumulated
dividends to the redemption date.
12
<PAGE>
NOTE 9. LONG-TERM DEBT
Long-term debt outstanding as of December 31, 1996 and 1995,
was as follows (dollars in thousands):
<TABLE>
<CAPTION>
Series Year Due 1996 1995 Series Year Due 1996 1995
<C> <C> <C> <C> <C> <S> <C> <C>
FIRST AND REFUNDING MORTGAGE BONDS: (CONTINUED)
6.59% 1996 - 3,000 8.27% 2025 50,000 50,000
5 3/8% 1997 72,600 72,600 8.28% 2025 2,000 2,000
5 5/8% 1997 100,000 100,000 8.30% 2025 5,000 5,000
5.17% 1998 50,000 50,000 8.95% 2027 15,584 15,681
7.5% 1999 100,000 100,000 7% 2033 150,000 150,000
6 1/4% 1999 65,000 65,000
5.76% 1999 5,000 5,000 POLLUTION CONTROL BONDS:
5.78% 1999 25,000 25,000 7.70% 2012 20,000 20,000
5.79% 1999 30,000 30,000 7.75% B 2017 10,000 10,000
8% B 1999 200,000 200,000 7.50% 2017 25,000 25,000
7% 2000 100,000 100,000 3.58% 2014 40,000 40,000
7% B 2000 100,000 100,000 5.80% 2014 77,000 77,000
5 7/8% 2001 150,000 150,000 Subtotal 3,463,184 3,466,281
6 5/8% B 2003 100,000 100,000
5 7/8% C 2003 75,000 75,000 OTHER LONG-TERM DEBT:
6.125% 2003 75,000 75,000 Capitalized leases 11,265 7,477
8% 2004 75,000 75,000 Other long-term debt 146,539 147,410
6 1/4% B 2004 100,000 100,000 Unamortized debt discount
7.37%-7.41% 2004 100,000 100,000 and premium, net (56,995) (61,674)
7% 2005 200,000 200,000 Current maturities of
6 3/8% 2008 125,000 125,000 long-term debt (174,726) (4,295)
8 3/4% 2021 150,000 150,000 Subtotal (a) 3,389,267 3,555,199
8 3/8% B 2021 150,000 150,000
8 5/8% 2022 100,000 100,000 SUBSIDIARY LONG-TERM DEBT:
7 3/8% 2023 200,000 200,000 Crescent Resources, Inc. (b) 118,058 130,694
6 7/8% B 2023 200,000 200,000 Nantahala Power and Light 68,372 33,288
7 7/8% 2024 150,000 150,000 Current maturities of
6 3/4% 2025 150,000 150,000 long-term debt (37,583) (7,776)
7 1/2% B 2025 100,000 100,000 Subtotal 148,847 156,206
8.27% 2025 21,000 21,000 Total long-term debt $3,538,114 $3,711,405
</TABLE>
(a) SUBSTANTIALLY ALL OF DUKE POWER'S ELECTRIC PLANT WAS MORTGAGED AS OF
DECEMBER 31, 1996.
(b) SUBSTANTIAL AMOUNTS OF CRESCENT RESOURCES, INC.'S REAL ESTATE DEVELOPMENT
PROJECTS, LAND AND BUILDINGS ARE PLEDGED AS COLLATERAL.
As of December 31, 1996 and 1995, the Company had $40,000,000 in pollution
control revenue bonds backed by an unused, two-year revolving credit facility of
$40,000,000. In addition, the Company had $130,000,000 in commercial paper
outstanding throughout 1996 and 1995 backed by unused five-year revolving credit
facilities. 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, 1996, Crescent Resources, Inc. had $45,428,000 in
mortgage loans which mature through 1999 and $30,630,000 in mortgage loans
maturing in 2000 or thereafter. Additionally, Crescent Resources, Inc. had
$42,000,000 outstanding at December 31, 1996, included in long-term debt on a
$75,000,000 four-year revolving credit facility. Interest rates are variable and
at December 31, 1996, ranged from 5.95 percent to 7.10 percent. As of December
31, 1996, Nantahala Power and Light Company had $68,000,000 in senior notes
maturing in 2011, 2012 and 2016. The notes carry fixed interest rates of
9.21 percent, 7.45 percent and 6.90 percent and require monthly payments of
principal beginning in 1997, 1998 and 2002, respectively.
The annual maturities of consolidated long-term debt, including capitalized
lease principal payments through 2001, are $212,309,000 in 1997; $62,759,000 in
1998; $444,840,000 in 1999; $248,271,000 in 2000; and $154,541,000 in 2001.
13
<PAGE>
NOTE 10. FINANCIAL INSTRUMENTS
The carrying amounts of "Cash," "Short-term investments," and "Notes
payable" on the Consolidated Balance Sheets approximate fair value primarily
because of the short maturities of these instruments. "Other investments"
includes notes receivable issued at fixed rates with maturities up to 30 years
for which there are no quoted market prices. The majority of estimated fair
value amounts of long-term debt and preferred stock as disclosed below were
obtained from independent parties. Judgment is required in interpreting market
data to develop the estimates of fair value. Accordingly, the estimates
determined as of December 31, 1996 and 1995, are not necessarily indicative of
the amounts the Company could have realized in current market exchanges.
External funds have been established, as required by the Nuclear Regulatory
Commission, as a mechanism to fund certain costs of nuclear decommissioning.
(See Note 14.) Currently, these nuclear decommissioning trust funds are invested
in U.S. stocks, bonds and cash equivalents. "Nuclear decommissioning trust
funds" are presented on the Consolidated Balance Sheets at amounts that
approximate fair value.
The carrying amounts and estimated fair values of long-term debt and
preferred stock are as follows (dollars in thousands):
<TABLE>
<CAPTION>
December 31, 1996 December 31, 1995
Carrying Amount Fair Value Carrying Amount Fair Value
<S> <C> <C> <C> <C>
Long-term debt.... $3,796,153 $3,773,000 $3,777,672 $3,879,000
Preferred stock... $ 684,000 $ 699,000 $ 684,000 $ 689,000
</TABLE>
The Company has authority to issue up to $1 billion aggregate principal
amount of debt securities under a shelf registration statement filed with the
Securities and Exchange Commission (SEC). Such debt securities may be issued as
First and Refunding Mortgage Bonds, Senior Notes or Subordinated Debentures.
In order to obtain variable rate financing at an attractive cost, the
Company entered into interest rate swap agreements associated with the November
1994, issuance of $200 million aggregate principal amount of its First and
Refunding Mortgage Bonds, 8% Series B due 1999 and the August 1995, issuance of
$100 million aggregate principal amount of its First and Refunding Mortgage
Bonds, 7 1/2% Series B due 2025. The interest rate swaps are reset quarterly
based upon the three-month London Interbank Offered Rate (LIBOR). As a result of
the interest rate swap contracts, interest expense on the Consolidated
Statements of Income is recognized at the weighted average rate for the year
tied to the LIBOR rate. The weighted average rates are as follows (dollars in
thousands):
<TABLE>
<CAPTION>
Weighted Average Rate
Series Year Due Face Value 1996 1995 1994
<S> <C> <C> <C> <C> <C>
8% Series B 1999 $200,000 5.64% 6.14% 5.95%
7 1/2% Series B 2025 $100,000 6.69% 7.06% -
</TABLE>
Duke Energy Group, Inc. entered into a hedge transaction in 1995 to offset
currency fluctuations between the U.S. dollar and the Chilean peso associated
with expected equity contributions to an affiliate in 1995, 1996 and 1997.
The hedge transaction has a notional amount of approximately $4.4 million at
December 31, 1996. Duke Energy Group, Inc. records any realized gains or losses
associated with the hedge as an adjustment to investments in affiliates.
14
<PAGE>
NOTE 11. INVESTMENTS IN AFFILIATES
Certain investments, where the Company's ownership in domestic and
international affiliates is 50 percent or less, are accounted for by the equity
method. These investments include ownership interests in various power
development projects; start-up personal communications services; marketing of
natural gas, electric power, and development of other energy services;
participation in various construction and support activities for fossil-fueled
generating plants; and real-estate development projects. The Company's
proportionate share of net income (loss) from these affiliates for the years
ended December 31, 1996, 1995 and 1994 was $(6,133,000), $9,237,000 and
$7,049,000, respectively. These amounts are reflected in "Operating revenues" on
the Consolidated Statements of Income.
A summary of assets and liabilities of these affiliates follows (dollars in
thousands):
<TABLE>
<CAPTION>
December 31, 1996 December 31, 1995
Company's Company's
Proportionate Proportionate
Total Share Total Share
<S> <C> <C> <C> <C>
Assets of affiliates........ $ 1,979,418 $549,442 $1,445,600 $351,376
Liabilities of affiliates... $1,041,207* $360,460 $ 615,452* $188,102
</TABLE>
*The Company's exposure to these liabilities is mitigated through the use of
project or limited recourse financing by the affiliates and capitalization
of its subsidiaries investing in the affiliates.
In addition, the Company had outstanding loans to certain affiliates of
$2,900,000 and $23,170,000 at December 31, 1996 and 1995, respectively.
In the normal course of business, some of these affiliates enter into
contractual agreements to exchange natural gas, electric power, futures, swaps
and options; and construction contracts which contain certain schedule and
performance requirements. The affiliates exercise risk management procedures to
control and minimize their exposure associated with the contracts. Certain
subsidiaries of the Company have guaranteed performance of the affiliates under
some of these contracts. Management is of the opinion that these guarantees will
not have any material adverse effect on the results of operations or the
financial position of the Company.
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. Through December 31, 1996, the benefit was based upon an age-related
formula which took into account years of creditable service and the employee's
average compensation based upon the highest compensation during a consecutive
sixty-month period. The benefit was reduced by an adjustment which is based upon
the employee's social security wages. Normal retirement age under the Plan was
age 65; however, early retirement benefits were payable as early as age 55 with
10 years of creditable service or age 51 if the employee had at least 30 years
of creditable service. The Company's policy is to fund pension costs as accrued.
Effective January 1, 1997, the Plan was amended to be a Cash Balance Plan.
Under the Cash Balance Plan, records are maintained on an individual participant
basis with monthly credits based upon the participant's creditable compensation
multiplied times a percentage that ranges from 3 percent to 7 percent depending
upon the sum of the participant's age and years of service. An additional
credit of 4 percent applies to creditable compensation in excess of the social
security wage base. Additionally, monthly interest credits will be allocated
based upon the yield of 30-year U.S. Treasury Bonds, subject to a 4 percent
minimum and a 9 percent maximum yield. Normal retirement age will remain age 65.
Employees who were participants in the Plan before January 1, 1997, remain
eligible to receive certain transitional benefits under the provisions of the
previous plan. After January 1, 1997, employees can receive early retirement
benefits as early as age 55 with at least 5 years of vesting service.
15
<PAGE>
Net periodic pension cost for the years ended December 31, 1996, 1995 and
1994, include the following components (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C> <C> <C> <C>
Service cost benefit earned during the year..... $ 49,636 $ 46,402 $ 43,098
Interest cost on projected benefit obligation... 116,088 111,110 96,521
Actual return on plan assets.................... (180,463) (253,314) (6,138)
Amount deferred for recognition................. 58,705 144,022 (86,995)
Expected return on plan assets.................. (121,758) (109,292) (93,133)
Net amortization................................ 9,070 6,161 7,657
Net periodic pension cost................... $ 53,036 $ 54,381 $ 54,143
</TABLE>
A reconciliation of the funded status of the plan to the amounts recognized
in the Consolidated Balance Sheets as of December 31, 1996 and 1995, is as
follows (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995
<S> <C> <C>
Accumulated benefit obligation:
Vested benefits........................................... $ (1,453,115) $ (1,289,459)
Nonvested benefits........................................ (4,083) (6,216)
Accumulated benefit obligation.......................... $ (1,457,198) $ (1,295,675)
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....................... $ 1,587,812 $ 1,424,148
Projected benefit obligation................................ (1,663,375) (1,596,747)
Unrecognized net experience loss............................ 220,355 286,837
Unrecognized prior service cost reduction................... (65,460) (35,039)
Remaining unrecognized transitional obligation.............. 668 801
Pre-funded pension cost................................. $ 80,000 $ 80,000
</TABLE>
Assumptions used in the Company's pension accounting include:
1996 1995 1994
Weighted-average discount rate 7.50% 7.50% 8.25%
Weighted-average salary increase 4.75% 4.75% 5.40%
Expected long-term rate of return on plan assets 9.00% 9.00% 9.00%
During 1995, the Company offered to certain employees an Enhanced Vested
Benefits program (EVB). The Company recorded an additional one-time expense for
special termination benefits associated with EVB of approximately $42,196,000,
including $21,600,000 of additional retirement plan costs.
16
<PAGE>
B. POSTRETIREMENT BENEFITS
The Company and its operating subsidiaries, with the exception of Nantahala
Power and Light Company (NP&L), which maintained its own postretirement benefit
plans through December 1995, currently provide certain health care and life
insurance benefits for retired employees. NP&L employees who retired after
January 1, 1996, are covered by Duke Power Company's postretirement benefit
plan. Through December 31, 1996, employees became eligible for these benefits if
they retired at age 55 or greater with 10 years of service or if they retired as
early as age 51 with 30 years or more of service. Effective January 1, 1997,
employees who were participants in the Retirement Plan before January 1, 1997,
become eligible for certain transitional postretirement benefits under the
provisions of the previous plan. Employees who were not participants in the plan
before January 1, 1997, become eligible as early as age 55 with at least 10
years of vesting service. All 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 $15,200,000 into these funding mechanisms in
1996 and $23,000,000 in 1995.
Net periodic postretirement benefit cost for the years ended December 31,
1996, 1995 and 1994, include the following components (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C> <C> <C> <C>
Service cost benefit earned during the year......... $ 6,388 $ 5,874 $ 5,415
Interest cost on accumulated postretirement benefit
obligation........................................ 27,276 27,201 25,321
Actual return on plan assets........................ (12,383) (14,726) (1,451)
Amount deferred for recognition..................... 2,988 7,260 (3,469)
Expected return on plan assets...................... (9,395) (7,466) (4,920)
Straight-line - 20 year amortization of transitional
obligation........................................ 13,515 13,293 13,293
Other amortization.................................. 1,566 555 366
Net periodic postretirement benefit cost.......... $39,350 $39,457 $39,475
</TABLE>
A reconciliation of the funded status of the plan to the amounts recognized
in the Consolidated Balance Sheets as of December 31, 1996 and 1995, is as
follows (dollars in thousands):
<TABLE>
<CAPTION>
1996 1995
<S> <C> <C> <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....................................... $ 127,594 $ 105,506
Actives eligible to retire................................ (39,567) (25,780)
Actives not eligible to retire............................ (118,103) (97,389)
Retirees and surviving spouses............................ (251,325) (253,688)
Accumulated postretirement benefit obligation (APBO)...... (408,995) (376,857)
Unrecognized prior service cost........................... 66,692 712
Unrecognized net experience (gain)/loss................... (3,772) 25,955
Unrecognized transitional obligation...................... 177,338 212,695
(Accrued) postretirement benefit cost................. $ (41,143) $ (31,989)
</TABLE>
17
<PAGE>
Assumptions used in the Company's postretirement benefits accounting
include:
1996 1995 1994
Weighted-average discount rate ...................... 7.50% 7.50% 8.25%
Weighted-average salary increase .................... 4.75% 4.75% 5.40%
Expected long-term rate of return on 401(h) assets .. 9.00% 9.00% 9.00%
Expected long-term rate of return on RLR assets ..... 6.50% 8.00% 6.50%
The assumed medical inflation rate was approximately 9.5 percent in
1996. 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 2001, which remains fixed thereafter.
A 1.0 percent increase in the medical and dental trend rates produces a 7.0
percent ($2,940,971) 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 7.8 percent ($31,462,000) as of December 31, 1996.
NOTE 13. COMMITMENTS AND CONTINGENCIES
A. CONSTRUCTION PROGRAM
Projected construction and nuclear fuel costs for Duke Power's electric
operations, both including allowance for funds used during construction, are
$2.6 billion and $716 million, respectively, for 1997 through 2001. These
projections are subject to periodic review and revisions. Actual construction
and nuclear fuel costs and capital expenditures 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.
Projected capital expenditures of subsidiaries and diversified activities
are $1.5 billion for 1997 through 2001. These projections are subject to
periodic review and revisions and may vary significantly as business plans
evolve to meet the opportunities presented by their markets.
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 $8.9 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 $8.7 billion,
which will be increased by $79.3 million as each additional commercial nuclear
reactor is licensed, has been provided through a mandatory industry-wide excess
secondary insurance program of risk pooling. The $8.7 billion could also be
reduced by $79.3 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 $79.3 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 $79.3 million amount is subject to
indexing for inflation and may be subject to state premium taxes. The $79.3
million includes a surcharge of 5 percent (which is also included in the above
$8.7 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 $34 million.
This amount represents 5 times the Company's annual premium to NML. 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 NML policies applicable to Catawba.
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The Company is also a member of Nuclear Electric Insurance Limited (NEIL)
and purchases insurance through NEIL's excess property, decontamination and
decommissioning liability insurance program. NEIL provides excess insurance
coverage of $2.25 billion for the Catawba Nuclear Station and $1.5 billion for
each of the Oconee and McGuire Nuclear Stations. 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 $40 million. This amount is
limited to 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 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 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. The Oconee Nuclear Station units are insured
for up to approximately $2.7 million, under like terms. Coverages continue at
100 percent for 52 weeks and 80 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 $27 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. PROPOSED MERGER WITH PANENERGY CORP
On November 25, 1996, the Company and PanEnergy Corp announced a proposed
stock-for-stock transaction creating an integrated energy company. Upon
consummation of the merger, PanEnergy will be a wholly owned subsidiary of the
Company, and the Company's name will be changed to Duke Energy Corporation. The
transaction is expected to close by December 31, 1997, subject to approval of
the shareholders of both companies and all applicable regulatory approvals. The
shareholders of each company will vote on the proposed merger at their annual
meetings, which are scheduled for April 24, 1997 for both companies.
Applications for regulatory approval were filed with the NCUC and the PSCSC on
December 19, 1996 and the FERC on February 3, 1997. Regulatory proceedings are
expected to be successfully completed by year-end 1997. In connection with the
transaction, each share of PanEnergy common stock will be converted into 1.0444
shares of common stock of the Company. The transaction will be accounted for as
a pooling of interests. Further details about the proposed acquisition are
provided in the Company's report on Form 8-K, filed with the Securities and
Exchange Commission on December 9, 1996, and in the Joint Proxy-Prospectus
provided to shareholders in connection with the Company's annual meeting. Unless
otherwise indicated, all information presented herein relates to the Company
only and does not take into account the proposed merger with PanEnergy.
D. OTHER
The Company and North Carolina Municipal Power Agency Number 1 and
Piedmont Municipal Power Agency, two of the four other joint owners of the
Catawba Nuclear Station, entered into a settlement in September 1995 which
resolved outstanding issues related to how certain calculations affecting bills
under the Catawba joint ownership contractual agreements should be performed.
The settlement was approved by the North Carolina Utilities Commission on
January 16, 1996 and The Public Service Commission of South Carolina on January
23, 1996. As part of the settlement, the Company agreed to purchase additional
megawatts (MW) of Catawba capacity during the period 1996 through 1999 and
remove certain restrictions related to sales of surplus energy by these two
joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in
1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the
costs associated with this settlement as part of the purchased capacity
levelization, consistent with prior orders of the retail regulatory commissions.
Therefore, the Company believes these matters should not have a material adverse
effect on the results of operations or the financial position of the Company.
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The Company and all four of the other joint owners of the Catawba Nuclear
Station entered into settlement agreements in 1994 which resolved all issues in
contention in arbitration proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding was 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.) In 1994, the Company settled its cumulative net obligation through 1993 of
approximately $205 million related to these settlement agreements. Billings for
1994 and later years will conform to the settlement agreements, which have been
approved by the Company's retail regulatory commissions. Because the Company
expects the costs associated with these settlements to be recovered as part of
the purchased capacity levelization, which has been approved by the Company's
retail regulatory commissions, the Company included approximately $205 million
as an increase to "Purchased capacity costs" on its Consolidated Balance Sheets
in 1994. Therefore, the Company believes 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. Where appropriate, the Company has made accruals in
accordance with Statement of Financial Accounting Standards No. 5, "Accounting
for Contingencies," in order to provide for such matters. 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 financial position of the
Company.
NOTE 14. NUCLEAR DECOMMISSIONING COSTS
Estimated site-specific nuclear decommissioning costs, including the cost of
decommissioning plant components not subject to radioactive contamination, total
approximately $1.3 billion stated in 1994 dollars based on decommissioning
studies completed in 1994. 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 responsible for decommissioning costs related to their
ownership interests in the station. Both the North Carolina Utilities Commission
and the Public Service Commission of South Carolina have granted the Company
recovery of estimated decommissioning costs through retail rates over the
expected remaining service periods of the Company's nuclear plants. Such
estimates presume each unit 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.
In accordance with a 1988 Nuclear Regulatory Commission order, during 1996,
the Company expensed approximately $56,470,000 which was contributed to the
external funds for decommissioning costs and accrued an additional $1,618,000 to
the internal reserve. Nuclear units are depreciated at a rate of 4.70 percent,
of which 1.61 percent is for decommissioning. The balance of the external funds
as of December 31, 1996, was $362,627,000. The balance of the internal reserve
as of December 31, 1996, was $207,774,000 and is reflected in accumulated
depreciation and amortization on the Consolidated Balance Sheets. Management's
opinion is that the decommissioning costs being recovered through rates, when
coupled with assumed after-tax fund earnings of 5.5 percent to 5.9 percent, are
currently sufficient to provide for the cost of decommissioning.
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INDEPENDENT AUDITORS' REPORT
Duke Power Company:
We have audited the accompanying consolidated balance sheets of Duke Power
Company and subsidiaries (the Company) as of December 31, 1996 and 1995, and the
related consolidated statements of income, retained earnings and cash flows for
each of the three years in the period ended December 31, 1996. 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,
1996 and 1995, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 1996 in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Charlotte, North Carolina
February 7, 1997
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
LLP. 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.
(Signature OF Jeffrey L. Boyer)
Jeffrey L. Boyer
Controller
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL
CONDITION
This Management's Discussion and Analysis presents the financial condition,
results of operations and certain forward-looking information about Duke Power
Company and its subsidiaries. On November 25, 1996, the Company and PanEnergy
Corp announced a proposed stock-for-stock merger. Unless otherwise indicated,
all information presented herein relates to Duke Power Company only and does not
take into account the proposed merger with PanEnergy. (For additional
information on the proposed merger, see "Current Issues-Proposed Merger with
PanEnergy Corp.")
RESULTS OF OPERATIONS
EARNINGS AND DIVIDENDS
Earnings per share increased 4 percent from $3.25 in 1995 to $3.37 in 1996.
The increase was primarily due to electric customer growth.
Earnings per share increased from $2.88 in 1994 to $3.37 in 1996, indicating
an average annual growth rate of 8 percent. Total Company earned return on
average common equity was 14.2 percent in 1996 compared to 14.3 percent in 1995
and 13.3 percent in 1994.
The Company continued its practice of annually increasing the common stock
dividend. Common dividends per share increased at an average annual rate of 4
percent from $1.92 in 1994 to $2.08 in 1996. Indicated annual dividends per
share increased to $2.12.
REVENUES AND SALES
Operating revenues increased at an average annual rate of 3 percent from
1994 to 1996, primarily because of growth in the residential and general service
customer classes and increased retail kilowatt-hour sales to weather-sensitive
customer classes. As discussed below, increased retail sales were partially
offset by decreased sales to wholesale customers. A South Carolina retail rate
reduction also decreased revenues in 1996. (For additional information on the
South Carolina rate reduction, see "Liquidity and Resources-Duke Power Company
Rate Matters.") Revenues from subsidiaries and diversified operations
contributed $162 million to the increase in revenues over the three-year period,
primarily from increased engineering service fees and developed lot and land
sales.
Wholesale revenues declined in 1996 as a result of the retention of
significantly larger portions of ownership entitlement by the other joint owners
of the Catawba Nuclear Station. This increased retention reduces the joint
owners' supplemental requirements supplied by the Company. The effect on
earnings of such wholesale revenue declines is partially offset by declines in
purchased power costs from the other joint owners which are not subject to
levelization. (For additional information on Catawba joint ownership, see Note
3, "Notes to the Consolidated Financial Statements.")
Kilowatt-hour sales from Duke Power electric operations were flat from
1995 to 1996. Sales to residential, general service, and other industrial
customers increased by 7 percent, 6 percent and 2 percent, respectively, as
a result of colder winter weather and continued economic growth in Duke Power's
service area. However, sales to textile customers decreased 5 percent, due to
a weaker demand for textile goods. Wholesale sales decreased 16 percent
primarily due to a decrease of 24 percent in supplemental sales requirements
to the other joint owners of the Catawba Nuclear Station.
OPERATING EXPENSES
From 1995 to 1996, other operation and maintenance expenses increased 7
percent. Increased activities of subsidiaries and diversified operations
contributed to this increase. Distribution maintenance expenses also increased,
primarily because of restoration costs associated with a February ice storm and
Hurricane Fran.
Other operation and maintenance expenses increased at an average annual rate
of 6 percent from 1994 to 1996. Increased activities of the subsidiaries and
diversified operations associated with engineering services contributed to this
increase.
Fuel expense increased at an average annual rate of 4 percent from 1994 to
1996. The increase was due primarily to higher system production requirements
and higher levels of fossil generation as a percentage of total generation.
These increases were partially offset by lower fossil fuel costs.
Net interchange and purchased power expenses decreased from $553 million in
1994 to $379 million in 1996, an average annual decrease of 17 percent. This
decrease was primarily the result of lower purchased power costs from the other
joint owners not subject to levelization as the other joint owners retained
significantly larger portions of their ownership entitlement, and lower
levelized costs as a result of the substantial completion of the recovery of
such costs from South Carolina customers.
From 1994 to 1996, depreciation and amortization expense increased at an
average annual rate of 3 percent, primarily due to increased depreciation
associated with additional investments. These investments were primarily
associated with distribution plant, including investment to support customer
growth, and the completion of the Lincoln Combustion Turbine Station. (For
additional information on the Lincoln Combustion Turbine Station, see "Capital
Needs-Meeting Future Power Needs.")
INTEREST EXPENSE AND OTHER INCOME
Interest expense increased at an average annual rate of 2 percent from 1994
to 1996, primarily due to long-term debt financing activities in 1994.
Allowance for funds used during construction (AFUDC) and other deferred
returns, net of associated taxes, represented 11 percent of earnings for common
stock in 1996 compared to 13 percent in 1994. AFUDC and other deferred returns
are expected to be less than 11 percent of total earnings during the next three
years.
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The deferred return, net of associated taxes, on the purchased capacity
levelization deferral related to the joint ownership of the Catawba Nuclear
Station represented 7 percent of earnings for common stock in 1996, 1995 and
1994. The cumulative deferred purchased capacity balance began to decline in
1996 and will continue to decline in 1997. (For additional information on
purchased capacity levelization, see "Capital Needs-Purchased Capacity
Levelization.")
AFUDC, net of associated taxes, represented 3 percent of earnings for common
stock in 1996 compared to 5 percent in 1995 and 6 percent in 1994. The changes
were primarily the result of the construction and subsequent commercial
operation of the Lincoln Combustion Turbine Station as 12 units were brought on-
line in 1995 and the remaining 4 units were brought on-line during the first
quarter of 1996. (For additional information on the Lincoln Combustion Turbine
Station, see "Capital Needs-Meeting Future Power Needs.")
LIQUIDITY AND RESOURCES
DUKE POWER COMPANY RATE MATTERS
Duke Power Company's most recent general rate increase requests in the
North Carolina and South Carolina retail jurisdictions were filed and approved
in 1991. Additionally, Duke Power 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 of Duke Power's regulatory jurisdictions were reduced by
adjustment riders to reflect capacity revenues received from this CP&L bulk
power sales agreement.
The Public Service Commission of South Carolina (PSCSC), on May 7, 1996,
ordered a rate reduction in the form of a decrement rider of 0.432 cents per
kilowatt-hour, or an average of approximately 8 percent, affecting South
Carolina retail customers. South Carolina retail sales represent approximately
30 percent of the Company's total retail sales. The rate reduction was
reflected on bills rendered on or after June 1, 1996. This net decrement rider
reflects an interim true-up decrement adjustment associated with the
levelization of Catawba Nuclear Station purchased capacity costs and an interim
true-up increment associated with amortization of the demand-side management
deferral account. The rate adjustment was made because, in the South Carolina
retail jurisdiction, cumulative levelized revenues associated with the recovery
of Catawba purchased capacity costs had exceeded purchased capacity payments and
accrual of deferred returns, and certain demand-side costs had exceeded the
level reflected in rates.
Certain of the Company's wholesale customers, excluding the other Catawba
joint owners, initiated proceedings in 1995 before the Federal Energy
Regulatory Commission (FERC) concerning rate matters. The Company and nine of
its eleven wholesale customers entered into a settlement in July 1996 which
reduced the customers' rates by approximately 9 percent and renewed their
contracts with the Company through the year 2000. Both of the customers that
did not enter into the settlement have signed agreements to purchase energy
from other suppliers beginning in 1997. The eleven wholesale customers involved
in this matter accounted for less than 2 percent of the Company's overall
electric revenues during 1996. The two customers that have signed agreements
with other suppliers accounted for less than 0.5 percent of the Company's 1996
overall electric revenues. (For additional information about sales to wholesale
customers, see "Current Issues-Competition.")
CATAWBA SETTLEMENTS
The Company and North Carolina Municipal Power Agency Number 1 (NCMPA) and
Piedmont Municipal Power Agency (PMPA), two of the four other joint owners of
the Catawba Nuclear Station, entered into a settlement in 1995 which resolved
outstanding issues related to how certain calculations affecting bills under the
Catawba joint ownership contractual agreements should be performed. The
settlement was approved by the North Carolina Utilities Commission (NCUC) on
January 16, 1996, and the PSCSC on January 23, 1996. As part of the settlement,
the Company agreed to purchase additional megawatts (MW) of Catawba capacity
during the period 1996 through 1999 and remove certain restrictions related to
sales of surplus energy by these two joint owners. The additional capacity
purchases are 215 MW in 1996, 165 MW in 1997, 120 MW in 1998 and 100 MW in 1999.
The Company expects to recover the costs associated with this settlement as part
of the purchased capacity levelization, consistent with prior orders of the
retail regulatory commissions. Therefore, the Company believes these matters
should not have a material adverse effect on its results of operations or its
financial position.
The Company and all four of the other joint owners of the Catawba Nuclear
Station entered into settlement agreements in 1994 which resolved all issues in
contention in arbitration proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding was 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 previously have been approved by the
Company's retail regulatory commissions. (For additional information on Catawba
joint ownership, see Note 3, "Notes to the Consolidated Financial Statements.")
In 1994, the Company settled its cumulative net obligation through 1993 of
approximately $205 million related to these settlement agreements. Billings for
1994 and later years conform to the settlement agreements, which were approved
by the Company's retail regulatory commissions.
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Because the Company expects the costs associated with these settlements to
be recovered as part of the purchased capacity levelization, which has been
approved by the Company's retail regulatory commissions, the Company included
approximately $205 million as an increase to "Purchased capacity costs" on its
Consolidated Balance Sheets in 1994. Therefore, the Company believes these
matters should not have a material adverse effect on its results of operations
or its financial position.
CASH FROM OPERATIONS
Consolidated net cash provided by operating activities in 1996 accounted
for 97 percent of total cash from operating, financing and investing activities
compared with 81 percent in 1995 and 67 percent in 1994. When 1996 stock
repurchase activities are excluded, cash generated from operating activities
exceeded the Company's capital needs. (For additional information on the stock
repurchase program, see Note 6, "Notes to the Consolidated Financial
Statements.")
FINANCING AND INVESTING ACTIVITIES
The Company's consolidated capital structure at year-end 1996, including
subsidiary long-term debt, was 54 percent common equity, 39 percent long-term
debt and 7 percent preferred stock. This structure is consistent with the
Company's target to maintain a double-A credit rating. As of December 31, 1996,
Duke Power's bonds were rated "AA" by Fitch Investors Service and Duff & Phelps,
"Aa2" by Moody's Investors Service and "AA-" by Standard & Poor's Group. As a
result of the announcement of the proposed merger with PanEnergy Corp, the
Company has been placed on credit review by the rating agencies. (For additional
information on the proposed merger, see "Current Issues-Proposed Merger with
PanEnergy Corp.")
The Company had total credit facilities of $694.9 million and $669.9 million
as of December 31, 1996 and 1995, respectively. The Company had unused credit
facilities of $474.4 million and $440.6 million as of December 31, 1996 and
1995, respectively.
During July 1996, the Company began purchasing shares of its common stock.
The Company has repurchased approximately 3.3 million shares of common stock for
$159 million as of December 31, 1996. (For additional information on the stock
repurchase program, see Note 6, "Notes to the Consolidated Financial
Statements.") In 1995, the Company issued $178 million of long-term debt, of
which $72 million was used to retire higher cost long-term debt. The Company
also retired $96 million of preferred stock and $80 million of long-term debt
in 1995. In 1994, the Company issued $407 million in debt, primarily First and
Refunding Mortgage Bonds.
The Company has authority to issue up to $1 billion aggregate principal
amount of debt securities under a shelf registration statement filed with the
Securities and Exchange Commission (SEC). Such debt securities may be issued as
First and Refunding Mortgage Bonds, Senior Notes, or Subordinated Debentures.
In order to obtain variable rate financing at an attractive cost, the
Company entered into interest rate swap agreements associated with the November
1994 issuance of $200 million aggregate principal amount of its First and
Refunding Mortgage Bonds 8% Series B due 1999 and the August 1995 issuance of
$100 million aggregate principal amount of its First and Refunding Mortgage
Bonds 7 1/2% Series B due 2025. The interest rate swaps are reset quarterly
based upon the three-month London Interbank Offered Rate (LIBOR). As a result of
the interest rate swap contracts, interest expense is recognized at the
weighted average rate for the year tied to the LIBOR rate. The weighted average
rates at December 31, 1996, 1995 and 1994 were 5.64%, 6.14% and 5.95%,
respectively, for the 8% Series B due 1999. The weighted average rates at
December 31, 1996 and 1995 were 6.69% and 7.06%, respectively, for the 7 1/2%
Series B due 2025.
Duke Energy Group, Inc. entered into a hedge transaction in 1995 to offset
currency fluctuations between the U.S. dollar and the Chilean peso associated
with expected equity contributions to an affiliate in 1995, 1996 and 1997.
The hedge transaction has a notional amount of approximately $4.4 million at
December 31, 1996. Duke Energy Group, Inc. records any realized gains or
losses associated with the hedge as an adjustment to investments in affiliates.
Duke/Louis Dreyfus (D/LD) enters into various derivative financial
instruments involving future settlement. These transactions include exchange-
traded futures and options and over-the-counter swaps and options for
commodities, primarily natural gas and electricity. D/LD's derivative financial
instruments are used for trading and marketing activities. These instruments are
accounted for at market value and the related unrealized gains and losses are
recognized in income. D/LD utilizes various risk management procedures to
monitor its exposure and minimize counterparty risk.
Duke Power's embedded cost of long-term debt, excluding debt
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of subsidiaries, was 7.95 percent for 1996 compared to 7.94 percent in
1995 and 7.98 percent in 1994. The embedded cost of preferred stock was 6.99
percent in 1996 compared to 7.06 percent in 1995 and 6.99 percent in 1994. The
increase in the embedded cost of long-term debt from 1995 to 1996 is primarily
the result of maturing lower cost debt. The decrease in the embedded cost of
preferred stock from 1995 to 1996 reflects the impact of decreased adjustable
dividend rates on a certain series of preferred stock.
FIXED CHARGES COVERAGE
Consolidated fixed charges coverage using the SEC method was 5.07 times for
1996 compared to 4.94 and 4.72 times for 1995 and 1994, respectively. The
increase is primarily a result of higher earnings. Consolidated fixed charges
coverage, excluding AFUDC and other deferred returns, was 4.69 times for 1996
compared with 4.52 for 1995 and 4.32 for 1994 and the Company goal of 3.5
times. The increase in coverage is primarily the result of higher earnings,
excluding AFUDC and other deferred returns.
CAPITAL NEEDS
PROPERTY ADDITIONS AND RETIREMENTS
Additions to property and nuclear fuel of $720 million and retirements of
$396 million resulted in an increase in gross plant of $324 million in 1996.
Since January 1, 1994, additions to property and nuclear fuel of $4 billion
and retirements of $2.5 billion have resulted in an increase in gross plant of
$1.5 billion.
CONSTRUCTION EXPENDITURES
Plant construction costs for generating facilities supporting Duke Power
electric operations, including AFUDC, decreased from $309 million in 1994 to
$164 million in 1996, primarily because of the completion of the Lincoln
Combustion Turbine Station. (For more information, see "Capital Needs-Meeting
Future Power Needs.") Construction costs for distribution plant,
including AFUDC, increased from $203 million in 1994 to $227 million in 1996.
Projected construction and nuclear fuel costs for Duke Power's electric
operations, both including AFUDC, are $2.6 billion and $716 million,
respectively, for 1997 through 2001. These construction expenditures are
primarily for distribution and production-related activities representing $1.3
billion and $864 million, respectively. These projections are subject to
periodic reviews and revisions. Actual construction and nuclear fuel costs
and capital expenditures 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.
Projected capital expenditures of subsidiaries and diversified activities
are $1.5 billion for 1997 through 2001, of which a significant portion is real
estate and power project development. These projections are subject to periodic
reviews and revisions and may vary significantly as business plans evolve to
meet the opportunities presented by their markets.
For 1997 through 2001, the Company anticipates substantially funding its
projected construction and capital expenditures through the internal generation
of funds.
PURCHASED CAPACITY LEVELIZATION
The rates established in Duke Power's electric retail jurisdictions permit
recovery of its investment in both units of the Catawba Nuclear Station and the
costs associated with contractual purchases of capacity from the other joint
owners of the Catawba Nuclear Station. 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 have been 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.
Such rate treatments require the Company to fund portions of the purchased
capacity payments until these costs, including returns, are recovered at a later
date. The Company recovers the accumulated costs and returns when the sum of the
declining purchased capacity payments and accrual of returns for the current
period drop below the levelized revenues. During 1996, in the North Carolina
retail jurisdiction and the wholesale jurisdiction regulated by the Federal
Energy Regulatory Commission (FERC), annual levelized revenues exceeded
purchased capacity payments and the accrual of deferred returns for the first
time. In the South Carolina retail jurisdiction, cumulative levelized revenues
have exceeded purchased capacity payments and accrual of deferred returns. The
PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider
for an interim true-up adjustment. (For additional information on the South
Carolina rate reduction, see "Liquidity and Resources-Duke Power Company Rate
Matters.") Jurisdictional levelizations are intended to recover total
costs, including returns, and are subject to adjustments, including final true-
ups.
25
<PAGE>
MEETING FUTURE POWER NEEDS
The Company's strategy for meeting customers' present and future energy
needs consists 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 an integrated resource planning
process. The goal is to provide adequate and reliable electricity in an
environmentally responsible, cost-effective manner. As customers elect to
procure generation from other suppliers, as two of the Company's wholesale
customers have indicated they will do beginning in 1997, the Company will
no longer be obligated to plan for the future generation needs of those
customers.
The Company has completed the construction of a combustion turbine facility
in Lincoln County, North Carolina, to provide capacity at periods of peak
demand. The station consists of 16 combustion turbines with a total generating
capacity of 1,200 megawatts. During 1995, twelve units of the Lincoln Combustion
Turbine Station began commercial operation. The last four units began commercial
operation in the first quarter of 1996.
The purchase of capacity and energy is also an integral part of meeting
future power needs. As of January 1, 1997, the Company has 329 megawatts of firm
purchased capacity from other generators of electricity under contract,
including 91 megawatts from qualifying facilities.
In 1995, the Company issued two requests for proposals (RFP) to solicit both
short-term and long-term competitive bids to provide future electric generating
capacity resources. After review of all the bids, the Company selected a short-
term bid from PECO Energy Co. of Philadelphia. The agreement gives the Company
the option to purchase up to 250 megawatts of capacity during the summer months
of 1998 through 2001. Contract arrangements between the parties were finalized
on August 1, 1996. The long-term RFP was closed and no bids were accepted.
Demand-side management programs benefit the Company and its customers by
providing cost-effective energy efficiency, providing for load control through
interruptible control features, shifting usage to off-peak periods and
increasing strategic sales of electricity. The November 1991 rate orders of the
NCUC and the PSCSC provided for recovery in rates of a designated level 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. The May 1996 rate rider in
South Carolina included an increment for demand-side management cost recovery.
(For additional information on the South Carolina rate rider, see "Liquidity and
Resources-Duke Power Company Rate Matters.") The Company ultimately expects
recovery through rates of associated deferred costs, not to exceed $75 million
including deferred returns in the North Carolina retail jurisdiction. The
annual costs deferred, including the return, were approximately $9 million
and $2 million in North Carolina and South Carolina, respectively, in 1996 and
$16 million and $11 million in North Carolina and South Carolina, respectively,
in 1995. As of December 31, 1996, the balance of deferred demand-side management
costs as presented on the Consolidated Balance Sheets in "Other deferred debits"
is $67 million and $40 million in North Carolina and South Carolina,
respectively.
CURRENT ISSUES
While the Company improved its financial performance in 1996 compared to
1995, its ability to maintain and improve its current level of earnings will
depend on several factors. As the electric industry becomes increasingly
competitive, the Company's ability to control costs will be an important factor
in maintaining a pricing structure that is both attractive to customers and
profitable to the Company. Wheeling of third-party energy to a retail customer
is not generally allowed in the Company's service territory. However, there are
discussions and events at the national level and within certain states regarding
retail competition which could result in changes in the industry. On April 24,
1996, the FERC issued its final rules on open-access transmission, providing
energy suppliers with opportunities to sell and deliver capacity and energy at
market-based prices. (For additional information on competition, see "Current
Issues-Competition.") Management cannot predict the outcome of these
matters and their impact, if any, on the Company's financial position and
results of operation. The Company is focusing on providing competitive prices to
its industrial customers, as well as to wholesale customers who have access to
alternative sources of energy. Other significant factors impacting the Company's
future earnings levels include continued economic growth in the Piedmont
Carolinas, the success of the Company's subsidiaries and diversified activities,
and the outcome of various legislative and regulatory actions.
PROPOSED MERGER WITH PANENERGY CORP. On November 25, 1996, the Company and
PanEnergy Corp announced a proposed stock-for-stock transaction creating an
integrated energy company. Upon consummation of the merger, PanEnergy will be
a wholly owned subsidiary of the Company, and the Company's name will be
changed to Duke Energy Corporation. The transaction is expected to close by
December 31, 1997, subject to approval of the shareholders of both companies
and all applicable regulatory approvals. The shareholders of each company will
vote on the proposed merger at their annual meetings, which are scheduled for
April 24, 1997 for both companies. Applications for regulatory approval were
filed with the NCUC and the PSCSC on December 19, 1996, and with the FERC on
February 3, 1997. Regulatory proceedings are expected to be successfully
completed by year-end 1997. In connection with the transaction, each share of
PanEnergy common stock will be converted into 1.0444 shares of
26
<PAGE>
common stock of the Company. The transaction will be accounted for as a pooling
of interests. Further details about the proposed acquisition are provided in
the Company's report on Form 8-K, filed with the Securities and Exchange
Commission on December 9, 1996, and in the Joint Proxy-Prospectus provided to
shareholders in connection with the Company's annual meeting. Unless otherwise
indicated, all information presented herein relates to the Company only and
does not take into account the proposed merger with PanEnergy.
RESOURCE OPTIMIZATION. The Company has been engaged in a concentrated
effort to more efficiently and effectively use its resources through better work
practices. In 1995, the Company offered to certain employees an Enhanced Vested
Benefits program (EVB) which gave targeted employees, who left the Company, an
enhanced vested retirement package and the Company's standard severance pay
based on years of service. This program resulted in the elimination of
approximately 900 positions during 1996. During 1994, the Company offered an
Enhanced Voluntary Separation program (EVS) which gave most employees the option
of leaving the Company for a lump-sum payment and the Company's standard
severance pay based on years of service. This program resulted in the departure
of approximately 1,300 employees in 1994. Implementing various efficiency
practices has resulted in streamlined work flows and provided the opportunity
for work force reduction programs such as EVB and EVS.
Full-time Employees
1996 1991
Duke Power electric operations 15,002 18,187
Subsidiaries and diversified businesses 2,724 364
Total 17,726 18,551
The increase in workforce of subsidiaries and diversified businesses is
commensurate with the growth in their business opportunities.
NUCLEAR DECOMMISSIONING COSTS. Estimated site-specific nuclear
decommissioning costs, including the cost of decommissioning plant components
not subject to radioactive contamination, total approximately $1.3 billion
stated in 1994 dollars based on decommissioning studies completed in 1994. 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 responsible
for decommissioning costs related to their ownership interests in the station.
Such estimates presume each unit will be decommissioned as soon as possible
following the end of its 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.
In accordance with a 1988 Nuclear Regulatory Commission order, during
1996, the Company expensed approximately $56 million which was contributed to
the external funds and accrued an additional $2 million to the internal
reserve. The balance of the external funds as of December 31, 1996, was
$363 million. The balance of the internal reserve as of December 31, 1996,
was $208 million and is reflected in accumulated depreciation and amortization
on the Consolidated Balance Sheets.
Both the NCUC and the PSCSC have granted the Company recovery of estimated
decommissioning costs through retail rates over the expected remaining service
periods of the Company's nuclear plants. Decommissioning costs being recovered
through rates, invested at assumed after-tax earnings rate of 5.5 percent to 5.9
percent, are sufficient to provide for the estimated cost of decommissioning.
As required under the Nuclear Waste Policy Act of 1982, the Company entered
into a contract with the U.S. Department of Energy (DOE) under which the DOE
agreed to dispose of the Company's spent nuclear fuel. The DOE has announced
that the department anticipates a delay in accepting the waste materials on the
contract date of January 31, 1998. The Company has joined with 35 other
utilities in a lawsuit attempting to force the DOE to meet its obligations as
called for in the contract. While it is uncertain what interim storage will be
provided by the DOE due to its inability to meet the contract date, the Company
has satisfactory plans in place to provide storage of spent nuclear fuel if the
DOE cannot accept it.
ENVIRONMENTAL ISSUES. The Company is subject to federal, state and local
regulations regarding air and water quality, hazardous and solid waste disposal,
and other environmental matters. The Company was an operator of manufactured gas
plants until the early 1950s. The Company has entered 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 four
federal Superfund 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
27
<PAGE>
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,
efficient plant operations and by using nuclear generation. The sulfur dioxide
provisions of the Act allow utilities to choose among various alternatives for
compliance. To meet the Phase II requirements by 2000, the Company's current
strategy includes the use of lower sulfur coal, emission allowance purchases,
low nitrogen oxide burners and emission monitoring equipment. A one-time cost
associated with bringing the Company into compliance with the Act could range
from $94 million to $260 million. Additional operating expenses of approximately
$25 million will be incurred for fuel premiums and emission allowance purchases
each year after 2000. This strategy is contingent upon developments in the
emissions allowance market, lower sulfur coal premiums, future regulatory and
legislative actions, and advances in clean air technology.
STRESS CORROSION CRACKING. Stress corrosion cracking (SCC) has occurred in
the steam generators of Units 1 and 2 at the McGuire Nuclear Station and Unit 1
at the Catawba Nuclear Station. 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 may be a problem. Although the Company has taken steps to mitigate the
effects of SCC, the inherent potential for future SCC in the McGuire and Catawba
steam generators still exists. The Company planned for the replacement of steam
generators at three units that have experienced SCC and purchased the
replacement steam generators from Babcock & Wilcox International. Replacement of
the steam generators at Catawba Unit 1 was successfully completed at a lower
cost than projected on October 4, 1996, after a 115-day outage that included
replacement work and other maintenance. Steam generator replacement in both
McGuire units is scheduled for completion during 1997. The Catawba Unit 2 steam
generators have not been scheduled for replacement. Steam generator replacement
at each McGuire unit is expected to take approximately four months and cost
approximately $170 million, excluding the cost of replacement power. Stress
corrosion problems are excluded under the Company's 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, began a legal action in
1990, alleging that Westinghouse Electric Corporation knowingly supplied to the
McGuire and Catawba stations steam generators that were defective in design,
workmanship and materials, requiring replacement well short of their stated
design life. The lawsuit was settled in 1994. While the court order does not
allow disclosure of the terms of the settlement, the Company believes the
litigation was settled on terms that provided satisfactory consideration to the
Company and will not have a material effect on the Company's results of
operations or financial position.
COMPETITION. The Energy Policy Act of 1992 (EPACT) and the FERC's subsequent
rulemaking activities are major drivers towards a more competitive market for
electric generation. EPACT reformed provisions of the Public Utility Holding
Company Act of 1935 (PUHCA) and Part II of the Federal Power Act to remove
certain barriers to competition for the supply of electricity. For example,
EPACT allows utilities to participate in the development of 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
regulation under PUHCA as an electric utility holding company. In addition,
EPACT permits the FERC to order transmission access for third parties to
transmission facilities owned by another entity so that energy suppliers can
sell to wholesale customers wherever they are located. It does not, however,
permit the FERC to issue an order requiring transmission access to retail
customers.
The FERC, responsible in large measure for implementation of the EPACT, has
moved vigorously to implement its mandate, interpreting the statute broadly in
issuing orders for third-party transmission service and issuing a number of
rules of general applicability. On April 24, 1996, the FERC issued its Order
Numbers 888 and 889, which established the final form of transmission tariff to
provide comparable service to all users of a utility's transmission system.
Open-access transmission for wholesale customers as defined by the FERC's
final rules provides energy suppliers, including the Company, with opportunities
to sell and deliver capacity and energy at market-based prices. Engaging in such
transactions may result in improved utilization of the Company's existing
assets. In addition, such access provides another supply option through which
the Company can buy capacity and energy at attractive rates, influencing its
competitive price position. However, sales to existing wholesale customers of
the Company may continue to be impacted by open access either due to competitive
pressure on the wholesale price of electricity, or the potential loss of sales
as wholesale customers seek other options to meet their capacity and energy
requirements at market-based prices. (For additional information about sales to
wholesale customers, see "Liquidity and Resources-Duke Power Company Rate
Matters," and Note 3, "Notes to Consolidated Financial Statements.")
Wholesale sales represented approximately 8.8 percent of the Company's total
kilowatt-hour sales in 1996. Supplemental sales to the other joint owners of the
Catawba Nuclear Station comprised the majority of such sales. Such supplemental
sales will continue to decline in 1997 as a result of the retention of larger
portions of ownership entitlement by the other joint owners. (For additional
information on Catawba joint ownership, see Note 3, "Notes to the Consolidated
Financial Statements.")
In early 1995, prior to issuance of the FERC's Notice of Proposed
Rulemaking, the Company and certain of its affiliates filed three applications
with the FERC, all of which were designed to enable effective participation in
the competitive environment of the changing electric utility industry. Duke
Power filed an
28
<PAGE>
application for permission to sell at market-based rates up to 2,500
megawatts of capacity and energy from its own assets. Two of the Company's
affiliates, Duke Energy Marketing Corp. (DEMC) and Duke/Louis Dreyfus L.L.C.
(D/LD), filed applications with the FERC to become power marketers. All of the
applications were supported by transmission tariffs which complied with then-
applicable FERC standards and established the rates, terms and conditions for
transmission service to third parties on the Company's transmission system. Late
in 1995, the FERC granted the applications of Duke, DEMC, and D/LD; accepted
Duke's transmission tariffs; and ordered a hearing on the rates to be charged
for service under those tariffs. On July 9, 1996, in compliance with the
standards and schedules set forth in Order Number 888, the Company filed a pro
forma open access transmission tariff complying with the requirements of the
FERC's final rules. Such a filing was required of all transmission-owning
utilities subject to the FERC's jurisdiction. The Company also filed on that
date a proposed settlement in the proceeding earlier ordered by the FERC. The
proposed settlement resolves all rate issues related to transmission services
under Duke's tariff and contains the rates agreed upon under the settlement.
The settlement and the July 9, 1996 tariff filing remain subject to final FERC
approval.
Competition for retail customers is not generally allowed in the Company's
service territory. However, there are discussions and events at the national
level and within certain states, including North and South Carolina, regarding
retail competition which could result in changes in the industry. Such changes,
should they occur, could impact all entities owning generation, including the
other joint owners of the Catawba Nuclear Station.
Currently, 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 cost-based
prices of electricity, profits could be reduced and utilities might be required
to reduce their asset balances to reflect a market basis less than cost.
Discontinuance of cost-based regulation would also require affected utilities to
write off their associated regulatory assets. The regulatory assets of the
Company are classified as "Deferred debits" on the Consolidated Balance Sheets.
Substantially all of the "Deferred debits" are 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 continues to position itself to effectively meet these challenges by
maintaining prices that are locally, regionally and nationally competitive.
COMMITMENTS AND CONTINGENCIES. The Company is 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 may involve substantial amounts. Where appropriate, the
Company has made accruals in accordance with Statement of Financial Accounting
Standards No. 5, "Accounting for Contingencies," in order to provide for such
matters. 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.
SUBSIDIARIES AND DIVERSIFIED OPERATIONS.The Company continues to
aggressively pursue both domestic and international diversified business
opportunities that are synergistic with the Company's core business to provide
additional value to the Company's shareholders. Among the Company's current
industry pursuits are ownership of electric power facilities, energy marketing,
real estate, communications, engineering consulting and various energy services.
Although these opportunities are primarily concentrated in areas that utilize
the Company's expertise, they present different and potentially greater risks
than does the Company's core business. The Company only pursues opportunities in
which the expected returns are commensurate with the risks and makes efforts to
mitigate such risks. The Company undertakes a continuous evaluation of the
various lines of business it may enter or exit, with the objective of enhancing
shareholder value and managing any associated risk.
Domestically, non-electric property of the Company's subsidiaries and
diversified activities was $404 million and $335 million at December 31, 1996
and 1995, respectively. The Company had equity investments in affiliates, which
own assets within the United States, of $82 million and $58 million at December
31, 1996 and 1995, respectively.
Internationally, the Company had equity investments in affiliates, which own
generation and transmission facilities, of $107 million and $105 million at
December 31, 1996 and 1995, respectively. Additionally, the Company, through its
non-regulated subsidiaries, had loaned $3 million and $23 million to certain of
these affiliates at December 31, 1996 and 1995, respectively.
The Company's subsidiaries and diversified activities contributed $51
million to net income in 1996 compared with $54 million in 1995 and $52 million
in 1994. From 1994 to 1996, increased developed lot and land sales, and
engineering services and construction fees generated additional income. These
increases were offset by personal communications services joint venture start-up
losses and a provision for an investment in a plant in Argentina.
29
<PAGE>
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
<S> <C> <C> <C> <C> <C>
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(thousands)
Operating revenues........................... $ 4,757,974 $ 4,676,684 $ 4,488,913 $ 4,466,233 $ 4,122,503
Operating expenses........................... 3,395,771 3,327,633 3,309,087 3,258,422 3,087,422
Operating income......................... 1,362,203 1,349,051 1,179,826 1,207,811 1,035,081
Interest expense and other income............ (156,546) (168,072) (143,931) (171,419) (223,028)
Income before income taxes................... 1,205,657 1,180,979 1,035,895 1,036,392 812,053
Income taxes................................. 475,691 466,441 397,019 409,977 303,970
Net income................................... 729,966 714,538 638,876 626,415 508,083
Dividends on preferred and preference
stock................................. 44,245 48,903 49,724 52,429 56,407
Earnings for common stock.................... $ 685,721 $ 665,635 $ 589,152 $ 573,986 $ 451,676
COMMON STOCK DATA
Shares of common stock - year-end (thousands).. 201,590 204,859 204,859 204,859 204,859
- average (thousands)... 203,553 204,859 204,859 204,859 204,819
Per share of common stock
Earnings................................. $ 3.37 $ 3.25 $ 2.88 $ 2.80 $ 2.21
Dividends................................ $ 2.08 $ 2.00 $ 1.92 $ 1.84 $ 1.76
Book value - year-end.................... $ 24.25 $ 23.36 $ 22.13 $ 21.17 $ 20.26
Market price - high-low.................. $53-43 3/8 $47 7/8-37 3/8 $ 43-32 7/8 $ 44 7/8-35 3/8 $ 37 1/2-31 3/8
- year-end.................. $ 46 1/4 $ 47 3/8 $ 38 1/8 $ 42 3/8 $ 36 1/8
BALANCE SHEET DATA (thousands)
Total assets................................. $13,469,690 $13,358,484 $12,862,228 $ 12,293,605 $11,012,795
Long-term debt............................... $ 3,538,114 $ 3,711,405 $ 3,567,122 $ 3,285,397 $ 3,288,111
Preferred stock with sinking fund requirements $ 234,000 $ 234,000 $ 279,500 $ 281,000 $ 279,519
ELECTRIC AND OTHER STATISTICS (a)
Kilowatt-hour sales (millions)
Residential.............................. 20,992 19,669 18,870 19,465 17,789
General service.......................... 19,269 18,160 17,289 16,904 15,818
Industrial............................... 29,620 29,782 29,290 28,198 27,041
Other energy and wholesale (b)........... 7,028 8,330 10,274 11,337 10,360
Total kilowatt-hour sales billed... 76,909 75,941 75,723 75,904 71,008
Unbilled kilowatt-hour sales............. (57) 796 (160) 154 34
Total kilowatt-hour sales.......... 76,852 76,737 75,563 76,058 71,042
Average revenue per billed KWH
Residential.............................. 7.24(cents) 7.33 (cents) 7.31(cents) 7.32(cents) 7.38(cents)
General service.......................... 5.83(cents) 5.93 (cents) 5.96(cents) 6.00(cents) 6.10(cents)
Industrial............................... 4.13(cents) 4.23(cents) 4.24(cents) 4.31(cents) 4.36(cents)
Sources of energy (millions of KWH)
Generated - Coal......................... 40,649 32,389 32,714 34,097 28,999
- Nuclear (c).......... 33,177 39,836 35,587 34,390 33,925
- Hydro................ 1,319 1,685 1,460 1,582 1,834
- Oil and gas (d)...... 199 255 35 43 5
Total generation... 75,344 74,165 69,796 70,112 64,763
Net interchange and purchased power.......... 3,587 1,175 1,276 1,750 1,403
Total output............................. 78,931 75,340 71,072 71,862 66,166
Purchases from other Catawba joint owners.... 2,662 6,070 9,046 8,810 9,466
Total sources of energy............ 81,593 81,410 80,118 80,672 75,632
Line loss and Company usage.................. 4,741 4,673 4,555 4,614 4,590
Total kilowatt-hour sales.......... 76,852 76,737 75,563 76,058 71,042
System average heat rate (c)................. 9,844 9,873 9,863 9,872 9,929
System load factor (c)....................... 61.7% 57.6% 57.7% 59.4% 58.9%
</TABLE>
30
<PAGE>
<TABLE>
<CAPTION>
1996 1995 1994 1993 1992
<S> <C> <C> <C> <C> <C>
ELECTRIC OPERATING RESULTS (thousands) (a)
Electric revenues (b)..................... $4,396,873 $4,422,438 $4,279,329 $4,281,876 $3,961,484
Electric expenses
Operation
Fuel used in electric generation...... 758,498 744,226 705,019 732,246 659,593
Net interchange and purchased power... 376,616 467,264 553,802 535,033 540,840
Wages, benefits and materials......... 781,527 805,665 781,842 701,994 636,729
Maintenance of plant facilities......... 470,963 415,610 429,617 375,457 403,162
Depreciation and amortization........... 475,865 446,284 450,215 488,441 491,339
General taxes........................... 251,935 243,985 239,714 231,680 215,493
Total operating expenses.............. 3,115,404 3,123,034 3,160,209 3,064,851 2,947,156
Operating income.......................... 1,281,469 1,299,404 1,119,120 1,217,025 1,014,328
Income taxes.............................. 422,964 438,825 361,653 402,960 289,633
Electric operating income................. $ 858,505 $ 860,579 $ 757,467 $ 814,065 $ 724,695
</TABLE>
(a) EXCLUDES NANTAHALA POWER AND LIGHT COMPANY OPERATIONS.
(b) INCLUDES SALES TO NANTAHALA POWER AND LIGHT COMPANY.
(c) INCLUDES 12.5% OF CATAWBA GENERATION.
(d) 1996 AND 1995 INCLUDE KWH OF THE LINCOLN COMBUSTION TURBINE
STATION PRIOR TO COMMERCIAL OPERATION.
QUARTERLY FINANCIAL DATA
<TABLE>
<CAPTION>
First Second Third Fourth
Dollars in Thousands Quarter Quarter Quarter Quarter Total
(except per-share data)
<S> <C> <C> <C> <C> <C>
1996 BY QUARTER
Operating revenues $1,162,077 $1,119,731 $1,292,426 $1,183,740 $4,757,974
Operating income. $ 357,412 $ 301,231 $ 470,706 $ 232,854 $1,362,203
Net income....... $ 191,304 $ 157,382 $ 264,987 $ 116,293 $ 729,966
Earnings per share $ 0.88 $ 0.71 $ 1.25 $ 0.53 $ 3.37
1995 BY QUARTER
Operating revenues $1,111,065 $1,052,403 $1,379,978 $1,133,238 $4,676,684
Operating income. $ 369,414 $ 263,876 $ 504,507 $ 211,254 $1,349,051
Net income....... $ 201,276 $ 137,523 $ 285,200 $ 90,539 $ 714,538
Earnings per share $ 0.92 $ 0.61 $ 1.33 $ 0.39 $ 3.25
</TABLE>
Generally, quarterly earnings fluctuate with seasonal weather conditions and
maintenance of electric generating units, especially nuclear units.
STOCK MARKET INFORMATION
The Company had 130,683 holders of record of common stock as of December 31,
1996, and 129,265 holders as of December 31, 1995. During 1996, approximately
87,105,100 shares of common stock were traded, compared with 59,641,300 during
the previous year. Also during 1996, the Company repurchased 3,269,743 shares of
its common stock, at a total cost of $159 million, through a stock repurchase
program. (For additional information on the stock repurchase program, see Note
6, "Notes to the Consolidated Financial Statements.") The Company's common stock
prices, as quoted in the New York Stock Exchange Composite Transactions, and
dividends paid were as follows:
<TABLE>
<CAPTION>
Dividends Stock Price Range Dividends Stock Price Range
Per Share High Low Per Share High Low
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1996 BY QUARTER 1995 BY QUARTER
Fourth. $0.53 $49 1/8 $43 3/8 Fourth ............. $0.51 $47 7/8 $43 1/8
Third.. 0.53 51 3/8 45 3/4 Third............... 0.51 43 3/4 40
Second. 0.51 51 1/2 45 3/4 Second............. 0.49 42 3/4 38 1/4
First.. 0.51 53 46 7/8 First................ 0.49 40 3/4 37 3/8
</TABLE>
31
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
THE CONSOLIDATED STATEMENTS OF INCOME, CONSOLIDATED STATEMENTS OF
CASH FLOWS, CONSOLIDATED BALANCE SHEETS AND CONSOLIDATED STATEMENTS
OF RETAINED EARNINGS FOR THE 12 MONTHS ENDED 12/31/96 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<CIK> 0000030371
<NAME> DUKE POWER COMPANY
<MULTIPLIER> 1000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 9386378
<OTHER-PROPERTY-AND-INVEST> 1172317
<TOTAL-CURRENT-ASSETS> 1144106
<TOTAL-DEFERRED-CHARGES> 1766889
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 13469690
<COMMON> 1896141
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 2992574
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4888715
234000
450000
<LONG-TERM-DEBT-NET> 3538114
<SHORT-TERM-NOTES> 105550
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 212309
0
<CAPITAL-LEASE-OBLIGATIONS> 9758
<LEASES-CURRENT> 1507
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4041002
<TOT-CAPITALIZATION-AND-LIAB> 13469690
<GROSS-OPERATING-REVENUE> 4757974
<INCOME-TAX-EXPENSE> 475691
<OTHER-OPERATING-EXPENSES> 3395771
<TOTAL-OPERATING-EXPENSES> 3871462
<OPERATING-INCOME-LOSS> 1362203
<OTHER-INCOME-NET> 126529
<INCOME-BEFORE-INTEREST-EXPEN> 1013041
<TOTAL-INTEREST-EXPENSE> 283075
<NET-INCOME> 729966
44245
<EARNINGS-AVAILABLE-FOR-COMM> 685721
<COMMON-STOCK-DIVIDENDS> 423064
<TOTAL-INTEREST-ON-BONDS> 244001
<CASH-FLOW-OPERATIONS> 1482664
<EPS-PRIMARY> 3.37
<EPS-DILUTED> 0
</TABLE>
