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.
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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
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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
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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
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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.
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