SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
( X ) ANNUAL REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1993
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______
Commission file number 1-3382
CAROLINA POWER & LIGHT COMPANY
______________________________________________________
(Exact name of registrant as specified in its charter)
411 Fayetteville Street
North Carolina 56-0165465 Raleigh, North Carolina 27601
_________________________________________________________________
(State or other (I.R.S. (Address of principal (Zip Code)
jurisdiction of Employer executive offices)
incorporation Identifi-
or organization) cation No.)
919-546-6111
_______________________
(Registrant's telephone number)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
__________________________________________________________
Title of each class Name of each exchange on which registered
___________________ _________________________________________
Common Stock New York Stock Exchange
(Without Par Value) Pacific Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
__________________________________________________________
Preferred Stock (Without Par Value, Cumulative)
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes __X__ . No ____ .
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K. ( )
The aggregate market value of the voting stock held by
non-affiliates at February 28, 1994, was $4,518,423,909.
Shares of Common Stock (Without Par Value) outstanding at
February 28, 1994: 160,736,522.
DOCUMENTS INCORPORATED BY REFERENCE:
___________________________________
Portions of the Company's 1994 definitive proxy statement dated
March 31, 1994, are incorporated into Part III, Items 10, 11, 12
and 13 hereof.
PART I
ITEM 1. BUSINESS
_________________
GENERAL
_______
1. COMPANY. Carolina Power & Light Company
(Company) is a public service corporation formed under the laws of
North Carolina in 1926, and is engaged in the generation,
transmission, distribution and sale of electricity in portions of
North Carolina and South Carolina. The Company had 8,027 employees
at December 31, 1993. The principal executive offices of the
Company are located at 411 Fayetteville Street, Raleigh, North
Carolina 27601, telephone number: 919-546-6111.
2. SERVICE.
a. The territory served, an area of approximately
30,000 square miles, includes a substantial portion of the coastal
plain in North Carolina extending to the Atlantic coast between the
Pamlico River and the South Carolina border, the lower Piedmont
section in North Carolina, an area in northeastern South Carolina,
and an area in western North Carolina in and around the City of
Asheville. The estimated total population of the territory served is
approximately 3.5 million.
b. The Company provides electricity at retail
in 219 communities, each having an estimated population of 500 or
more, and at wholesale to one joint municipal power agency, 4
municipalities and 18 electric membership corporations. At
December 31, 1993, the Company was furnishing electric service to
approximately 1,032,000 customers.
3. SALES. During 1993, 32.6% of operating revenues was
derived from residential sales, 20.5% from commercial sales, 25.7%
from industrial sales, 17.2% from resale sales and 4.0% from other
sources. Of such operating revenues, approximately 85% was derived
from North Carolina and approximately 15% from South
Carolina. For the twelve months ended December 31, 1993, average
revenues per kilowatt-hour (kWh) sold to residential, commercial
and industrial customers were 8.28 cents, 6.94 cents and 5.49
cents, respectively. Sales to residential customers for the past
five years are listed below.
Average Average
Annual Annual Revenue
Year kWh Use Bill per kWh
____ _______ _______ _______
1989 12,419 $ 987.19 7.95 cents
1990 11,957 995.01 8.32
1991 12,472 1,040.70 8.34
1992 12,396 1,029.82 8.31
1993 13,167 1,090.16 8.28
4. PEAK DEMAND.
a. A 60-minute system peak demand record
of 10,144 megawatts (MW) was reached on January 19, 1994. At the
time of this peak demand, the Company's capacity margin based on
installed capacity (less unavailable capacity) and scheduled firm
purchases and sales was approximately 0.22%.
b. Total system peak demand for 1991 increased by
3.2%, for 1992 increased by 3.1%, and for 1993 increased by 3.8%,
as compared with the preceding year. The Company currently
projects a 2.3% average annual growth in system peak demand over
the next ten years. The year-to-year change in actual peak demand
is influenced by the specific weather conditions during those
years and may not exhibit a consistent pattern. Total system load
factors, expressed as the ratio of the average load supplied to the
peak load demand, for the years 1991-1993 were 57.8%, 57.4% and
59.0%, respectively. The Company forecasts capacity margins of
15.2% and 13.4% over anticipated system peak load for 1994 and
1995. This forecast assumes normal weather conditions in each year
consistent with long-term experience, and is based upon the rated
Maximum Dependable Capacity of generating units in commercial
operation and scheduled firm purchases of power. See ITEM 1,
"Generating Capability" and "Interconnections With Other
Systems." However, some of the generating units included in
arriving at these capacity margins may be unavailable
as a result of scheduled outages, environmental modifications or
unplanned outages. See ITEM 1, "Environmental Matters" and
"Nuclear Matters." The data contained in this paragraph includes
North Carolina Eastern Municipal Power Agency's (Power Agency) load
requirements and capability from its ownership interests in
certain of the Company's generating facilities. See ITEM 1,
"Generating Capability," paragraph 1.
GENERATING CAPABILITY
_____________________
1. FACILITIES. The Company has a total system
installed generating capability of 9,613 MW, with generating
capacity provided primarily from the installed generating
facilities listed in the table below. The remainder of the
Company's generating capacity is composed of 53 coal, hydro and
combustion turbine units ranging in size from a 2.5 MW hydro unit
to a 78 MW coal-fired unit. Pursuant to certain agreements with
Power Agency, which is comprised of former North Carolina municipal
wholesale customers of the Company and Virginia Electric and Power
Company (Virginia Power), Power Agency has acquired undivided
ownership interests of 18.33% in Brunswick Unit Nos. 1 and 2,
12.94% in Roxboro Unit No. 4 and 16.17% in Harris Unit No. 1 and
Mayo Unit No. 1 (collectively, the Joint Facilities). Of the total
system installed generating capability of 9,613 MW (including Power
Agency's share), 55% is coal, 32% is nuclear, 2% is hydro and 11%
is fired by other fuels including No. 2 oil, natural gas and
propane.
MAJOR INSTALLED GENERATING FACILITIES
Year Maximum
Plant Unit Commercial Primary Dependable
Location No. Operation Fuel Capacity
________ ____ __________ _______ __________
Asheville 1 1964 Coal 198 MW
(Skyland, N.C.) 2 1971 Coal 194 MW
Cape Fear 5 1956 Coal 143 MW
(Moncure, N.C.) 6 1958 Coal 173 MW
H. F. Lee 1 1952 Coal 79 MW
(Goldsboro, N.C.) 2 1951 Coal 76 MW
3 1962 Coal 252 MW
H. B. Robinson 1 1960 Coal 174 MW
(Hartsville, S.C.) 2 1971 Nuclear 683 MW
Roxboro 1 1966 Coal 385 MW
(Roxboro, N.C.) 2 1968 Coal 670 MW
3 1973 Coal 707 MW
4 1980 Coal 700 MW*
L. V. Sutton 1 1954 Coal 97 MW
(Wilmington, N.C.) 2 1955 Coal 106 MW
3 1972 Coal 410 MW
Brunswick 1 1977 Nuclear 767 MW*
(Southport, N.C.) 2 1975 Nuclear 754 MW*
Mayo 1 1983 Coal 745 MW*
(Roxboro, N.C.)
Harris 1 1987 Nuclear 860 MW*
(New Hill, N.C.)
____________
*Facilities are jointly owned by the Company and
Power Agency, and the capacity shown includes Power Agency's share.
2. MAINTENANCE OF PROPERTIES. The Company
maintains all of its properties in good operating condition in
accordance with sound management practices. The average life
expectancy for ratemaking and accounting purposes of the Company's
generating facilities (excluding combustion turbine units and hydro
units) is approximately 40 years from the date of commercial
operation.
3. GENERATION ADDITIONS SCHEDULE. The Company's
energy and load forecasts were revised in December 1993. Over the
next ten years, system sales growth is forecasted to average 2.3%
per year and annual growth in system peak demand is projected to
average 2.3%. The Company's generation additions schedule
reflects no additions until 1996, when three new combustion
turbine generating units are currently scheduled to
commence commercial operation. These units, having a total
generating capacity of approximately 225 MW, will
be located at the Company's Darlington County Electric Plant near
Hartsville, South Carolina and are expected to cost an aggregate of
approximately $93 million. The generation additions schedule,
which is updated annually, also includes generation additions of
3,600 MW in combustion turbine generating units to be added over
the period 1997 to 2007 at undesignated sites and a 500 MW baseload
coal unit in 2008 at an undesignated site.
4. RELICENSING OF HYDROELECTRIC PLANT. In 1973,
the Company filed an application with the Federal Power Commission,
now the Federal Energy Regulatory Commission (FERC), for a new
long-term license for its 105 MW Walters Hydroelectric Plant
(Project No. 432-004). North Carolina Electric Membership
Corporation (NCEMC), doing business as Carolina Electric
Cooperatives, filed a competing application in August 1974 (Project
No. 2748-000). Since the initial license expired in 1976, the
Company has continued to operate the Walters Hydroelectric Plant
under an annual license issued by the FERC. Loss of the license
would result in significant additional costs to the Company;
however, the financial impact would be dependent on future
ratemaking treatment. The FERC issued orders staying the
relicensing proceedings until February 1990. Thereafter, the FERC
set the matter for hearing, and the North Carolina Department of
Environment, Health and Natural Resources and the Tennessee
Wildlife Resources Agency intervened in this proceeding. A two-
phase evidentiary hearing was concluded in October 1991, but the
FERC has not yet rendered its decision. On September 17, 1993,
the Company and NCEMC filed a settlement agreement (Settlement
Agreement) with the FERC. Under the terms of the Settlement
Agreement, NCEMC will withdraw its competing request for a
license for the Walters Hydroelectric Plant. The Settlement
Agreement also resolves, as between the parties, issues related to
NCEMC's objections to the Company's purchase power contract with
Duke Power Company (Duke) and NCEMC's interest in transferring
base load capacity from its ownership in Duke's Catawba Nuclear
Station (Docket Nos. ER 89-106-000, EL 91-55-000 and ER
92-199-000). See ITEM 1, "Interconnections with Other Systems,"
paragraph 3.a. for further discussion of the purchase power
contract. Also on September 17, 1993, the parties filed with the
FERC a Power Coordination Agreement (PCA) and an Interchange
Agreement (IA), both dated August 27, 1993. The PCA and IA set
forth explicitly the future relationship between the
parties and establish a framework under which they will operate.
The PCA provides NCEMC the option to gradually assume
responsibility for a portion of its load, subject to agreed upon
limits, thereby enabling the Company to further enhance its
planning for generation and transmission property. Additionally,
the Company will sell electricity and provide necessary
transmission and coordinating services to NCEMC subject to rates
that will benefit the Company and its customers. On October 7,
1993, the FERC Staff filed comments partially opposing the
settlement on technical grounds, but recommending that it be
certified to the FERC. The Company filed its response to those
comments with the FERC on October 18, 1993. On October 26, 1993,
the Administrative Law Judge (ALJ) certified the case to the FERC
for its decision. In his certification the ALJ noted that the
settlement is a good one and will greatly benefit the people of North
Carolina. On February 28, 1994, the Company and NCEMC agreed to extend
the time for obtaining FERC approval of the PCA and the IA from February
28, 1994 to April 29, 1994. Another settlement agreement regarding
various environmental issues has been signed by all the parties and was
filed with the FERC for approval on February 16, 1994. On March 8,
1994, the FERC Staff filed comments supporting this settlement
agreement. Approval of the settlement agreements and issuance of the
license by the FERC will conclude this matter. The Company cannot
predict the outcome of these matters.
INTERCONNECTIONS WITH OTHER SYSTEMS
___________________________________
1. INTERCONNECTIONS. The Company's facilities in
Asheville and vicinity are integrated into the total
system through the facilities of Duke via interconnection
agreements that permit transfer of power to and from
the Asheville area. The Company also has major interconnections
with the Tennessee Valley Authority (TVA), Appalachian Power
Company (APCO), Virginia Power, South Carolina Electric and Gas
Company (SCE&G), South Carolina Public Service Authority (SCPSA)
and Yadkin, Inc. (Yadkin). Major interconnections include
115 kV and 230 kV ties with SCE&G and SCPSA; 115 kV, 230 kV and
500 kV ties with Duke and Virginia Power; a 115 kV tie with Yadkin;
a 161 kV tie with TVA; and three 138 kV ties and one 230 kV tie
with APCO. See paragraph 3.b. below.
2. INTERCHANGE AGREEMENTS.
a. The Company has interchange agreements with
APCO, Duke, SCE&G, SCPSA, TVA, Virginia Power and Yadkin which
provide for the purchase and sale of power for hourly, daily,
weekly, monthly or longer periods. Purchases and sales under these
agreements may be made due to changes in the in-service dates of
new generating units, outages at existing units, economic
considerations or for other reasons.
b. The Virginia-Carolinas Subregion of the
Southeastern Electric Reliability Council is made up of the
Company, Duke, Nantahala Power & Light Company, SCE&G, SCPSA and
Virginia Power, plus the Southeastern Power Administration and
Yadkin. Electric service reliability is promoted by contractual
arrangements among the members of electric reliability
organizations at the area, regional and national levels,
including the Southeastern Electric Reliability Council and the
North American Electric Reliability Council.
3. PURCHASE POWER CONTRACTS.
a. In March 1987, the Company entered into a
purchase power contract with Duke, whereby Duke would provide 400
MW of firm capacity to the Company's system over the period January
1, 1992, through December 31, 1997. The contract was filed with
the FERC in December 1988 (Docket No. ER89-106). NCEMC, Power
Agency, Nucor Steel, the South Carolina Consumer Advocate and
others moved to intervene in the proceeding, objecting to various
aspects of the contract. A hearing was held in January 1990, but
the FERC has not yet rendered its decision. Pursuant to an
amendment of the contract, commencement of the purchase of power by
the Company was delayed until July 1993 and termination was
extended through June 1999. This amendment was filed with the FERC
and accepted for filing, subject to refund, pursuant to an Order
dated January 21, 1992. The docket was consolidated with Docket
No. ER89-106 and a settlement agreement resolving issues related to
the purchase power contract and other matters was filed with the
FERC for approval on September 17, 1993. See ITEM 1, "Generating
Capability," paragraph 4 for further discussion of the settlement
agreement and other agreements between the Company and NCEMC.
Pending the FERC's approval of the settlement, the Company began
purchasing 400 MW of generating capacity from Duke in July 1993.
The estimated minimum annual payment for power under the six-year
agreement is $43 million, which represents capital-related capacity
costs. Other costs associated with the agreement include fuel,
energy-related operation and maintenance expenses and transmission
use charges. The Company cannot predict the outcome of this
matter.
b. The Company has entered into an agreement,
which has been approved by the FERC, with APCO and Indiana Michigan
Power Company (Indiana Michigan), operating subsidiaries of
American Electric Power Company, to upgrade a transmission
interconnection with APCO in the Company's western service area,
establish a new interconnection in the Company's eastern service
area, and purchase 250 MW of generating capacity from Indiana
Michigan's Rockport Unit No. 2. The transmission interconnection
upgrade in the Company's western service area was completed in
1992. The purchase of generating capacity began on January 1,
1990, and will continue for a period of 20 years. The estimated
minimum annual payment for power purchased under the terms of the
agreement is approximately $30 million, which represents
capital-related capacity costs. Other costs associated with the
agreement include demand-related production expenses, fuel,
energy-related operation and maintenance expenses and transmission
use charges.
4. FAYETTEVILLE. The Company has an agreement with the City of
Fayetteville's Public Works Commission (City) to exchange capacity and energy.
The City has a 70 MW heat recovery unit and eight 27.5 MW dual fuel (gas
or oil) fired combustion turbine units. The heat recovery unit and five
of the combustion turbine units are being used by the City to satisfy
energy requirements during periods of peak demand. The agreement makes
provisions for the purchase and sale of capacity and/or energy for
economic and reliability reasons to the mutual benefit of both parties.
On March 10, 1994, the City and the Company entered into a new ten-year
agreement under which the Company will continue to be the City's
wholesale supplier of electricity. See ITEM 1, "Wholesale Rate
Matters," paragraph 3.c. for further discussion of the new agreement.
COMPETITION AND FRANCHISES
__________________________
1. COMPETITION.
a. Generally, in municipalities and other areas
where the Company provides retail electric service, no other
utility directly renders such service. In recent years, however,
customers interested in building their own generation facilities,
competition from unregulated energy suppliers and changing
government regulations have fostered the development of alternative
sources of electricity for certain of the Company's
wholesale and industrial customers. The Public Utility
Regulatory Policies Act (PURPA) has facilitated the entry
of non-utility companies into the electric generation business.
Under PURPA, non-utility companies are allowed to construct
"qualifying facilities" for the production of electricity in
connection with industrial steam supplies and, under certain
circumstances, to compel a utility to purchase the electricity
generated at prices reflecting the utility's avoided cost as set by
state regulatory bodies. Over the near term, the purchase of power
from qualifying facilities has increased the Company's total cost
of generation.
b. In 1992, the Energy Policy Act of 1992
(Energy Act) was signed into law. The Energy Act addresses a wide
range of energy issues, including several matters affecting bulk
power competition in the electric utility industry. It creates
exemptions from regulation under the Public Utility Holding Company
Act of 1935 for persons or corporations that own and/or operate in
the United States certain generating and interconnecting
transmission facilities dedicated exclusively to wholesale sales,
thereby encouraging the participation of utility affiliates,
independent power producers and other non-utility participants in
the development of wholesale power generation. In addition, the
Energy Act confers expanded authority upon the FERC to issue orders
requiring public utilities, such as the Company, to transmit power
and energy to or for wholesale purchasers and sellers, and to
require public utilities to enlarge or construct additional
transmission capacity to provide these services. The Energy Act
also requires or facilitates numerous initiatives to increase
energy efficiency at federal and other facilities. Implementation
of portions of this legislation through rulemaking is in progress
at the FERC. The Company is unable to predict the ultimate impact
the Energy Act will have on its operations. When fully
implemented, the Energy Act could impact the Company's load
forecasts and plans for power supply to the extent additional
generation is facilitated by the Energy Act, current wholesale
customers elect to purchase from other suppliers, or new
opportunities are created for the Company to expand its wholesale
load.
The possible migration of some of the Company's load has created greater
planning uncertainty and risks for the Company. The Company has been
addressing these risks by negotiating long-term contracts with its
customers, which allow the Company flexibility in managing its load and
efficiently planning its future resource requirements. In this regard,
in 1993 the Company signed a significant long-term agreement with NCEMC,
which represents 17 of the Company's wholesale customers, and
restructured its agreement with Power Agency. Also in 1993, the Company
signed power supply agreements with the City of Camden, South Carolina
and French Broad Electric Membership Corporation. In 1994, the City of
Fayetteville's Public Works Commission entered into a new contract with
the Company. In the industrial sector, the Company continues its
efforts on a number of programs designed to retain and expand existing
load and to attract new business to its service territory.
2. FRANCHISES. The Company is a regulated public
utility and holds franchises to the extent necessary to operate in
the municipalities and other areas it serves.
CONSTRUCTION PROGRAM
____________________
1. CAPITAL REQUIREMENTS. During 1993 the Company
expended approximately $613 million for capital requirements. The
Company revised its capital program in 1993 as part of its annual
business planning process. Capital requirements, including
anticipated construction expenditures for plant modifications, for
the years 1994 through 1996 are set forth below. These estimates
include Clean Air Act compliance expenditures of approximately $79
million, and generating facility addition expenditures of
approximately $248 million. See ITEM 1, "Environmental Matters,"
paragraph 2 for further discussion of the impact of the Clean Air
Act on the Company.
Estimated Capital Requirements
______________________________
(In Millions)
1994 1995 1996 TOTAL
____ ____ ____ _____
Construction Expenditures $386 $476 $540 $1,402
Nuclear Fuel Expenditures 25 79 94 198
AFUDC (18) (29) (40) (87)
____ ____ ____ ______
Net expenditures (a) 393 526 594 1,513
Long-Term Debt Maturities 50 275 55 380
____ ____ ____ ______
TOTAL $443 $801 $649 $1,893
==== ==== ==== ======
_______________
(a) Reflects reductions of approximately $25 million, $25
million and $27 million for 1994, 1995 and 1996, respectively, in
net capital requirements resulting from Power Agency's projected
payment of its ownership share of capital expenditures related to
the Joint Facilities.
FINANCING PROGRAM
_________________
1. CAPITAL REQUIREMENTS. Based on the Company's
most recent estimate of capital requirements, the Company does not
expect to have external funding requirements in 1994 or 1996 due to
the low level of long-term debt maturities in those years.
External funding requirements, which do not include early
redemptions of long-term debt or redemptions of preferred stock,
are expected to approximate $300 million in 1995. These funds will
be required for construction, long-term debt maturities and
general corporate purposes, including the repayment of short-term
debt. The Company may from time to time sell additional
securities beyond the amount needed to meet capital requirements
to allow for the early redemption of outstanding issues of
long-term debt, the redemption of preferred stock, the reduction of
short-term debt or for other corporate purposes. The amounts and
timing of the sales of securities will depend upon market
conditions and the specific needs of the Company. See ITEM 7,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations," for further analysis and discussion of the
Company's financing plans and capital resources and liquidity.
2. SEC FILINGS.
a. The Company has on file with the Securities and
Exchange Commission (SEC) a shelf registration statement (File No.
33-50597), enabling the Company to issue an aggregate of $600
million principal amount of First Mortgage Bonds, $450 million of
which remain available for issuance. Additionally, the
Company has entered into a distribution agreement with respect to
the possible future sale of an aggregate amount of $200 million
principal amount of First Mortgage Bonds, designated as Secured
Medium-Term Notes, Series C, $110 million of which remain available
for issuance.
b. The Company has on file with the SEC a shelf
registration statement (File No. 33-5134) enabling the Company to
issue up to $180 million of Serial Preferred Stock.
3. FINANCINGS. External financings during 1993 and
early 1994 included:
- The issuance on February 17, 1993, of $150
million principal amount of First Mortgage
Bonds, 6 1/8% Series due February 1, 2000,
for net proceeds of approximately $147.8
million.
- The issuance on March 3, 1993, of $150
million principal amount of First Mortgage
Bonds, 7 1/2% Series due March 1, 2023, for net
proceeds of approximately $147.4 million.
- The issuance on July 7, 1993, of $100
million principal amount of First Mortgage
Bonds, 5 3/8% Series due July 1, 1998, for net
proceeds of approximately $99.1 million.
- The issuance on August 26, 1993, of $100
million principal amount of First Mortgage
Bonds, 6 7/8% Series due August 15, 2023, for
net proceeds of approximately $98.2 million.
- During the period from September through
December 1993, the Company issued an aggregate
of $90 million principal amount of First
Mortgage Bonds, Secured Medium-Term Notes,
Series C, with interest rates ranging from
4.85% to 5.06% and maturity dates ranging
from 1996 to 1998. Net proceeds from the
issuances of these First Mortgage Bonds
aggregated $89.4 million.
- The issuance on January 19, 1994, of $150
million principal amount of First Mortgage
Bonds, 5 7/8% Series due January 15, 2004, for
net proceeds of approximately $148 million.
The proceeds from the issuances listed above were used to reduce the
outstanding balance of commercial paper and other short-term debt, to
redeem outstanding long-term debt and for other general corporate
purposes.
4. REDEMPTIONS/RETIREMENTS. Redemptions and
retirements during 1993 included:
- The redemption on March 25, 1993, of $82.549
million principal amount of First Mortgage
Bonds, 8 1/2% Series due October 1, 2007,
at 100.26% of the principal amount of such
bonds plus accrued interest to the date of
redemption.
- The redemption on April 1, 1993, of $70 million
aggregate principal amount of First Mortgage
Bonds, 7 3/4% Series due October 1, 2001, at
102.30% of the principal amount of such bonds
plus accrued interest to the date of
redemption.
- The purchase and cancellation on April 14,
1993, of $1.8 million aggregate principal
amount of The Wake County Industrial Facilities
and Pollution Control Financing Authority
Pollution Control Revenue Bonds (Carolina Power
& Light Company Project) Series 1987 due March
1, 2017, at 100.00% of the principal amount of
such bonds plus accrued interest to the date
of purchase, pursuant to provisions of the
related trust indenture.
- The redemption on April 16, 1993, of $100
million aggregate principal amount of First
Mortgage Bonds, 8 7/8% Series due March 1,
2016, at 105.77% of the principal amount of
such bonds plus accrued interest to the
date of redemption.
- The retirement on June 22, 1993, of $25 million
aggregate principal amount of First Mortgage
Bonds, 8.75% Secured Medium-Term Notes, Series
A, which matured on that date.
- The redemption on August 18, 1993, of $100
million principal amount of First Mortgage
Bonds, 8 1/2% Series due January 1, 2017,
at 104.64% of the principal amount of such
bonds plus accrued interest to the date of
redemption.
- The retirement on September 1, 1993, of $100
million principal amount of First Mortgage
Bonds, 9% Series, which matured on that date.
- The redemption on September 16, 1993, of $30
million principal amount of First Mortgage
Bonds, 4 1/2% Series due July 1, 1994, at
100% of the principal amount of such bonds plus
accrued interest to the date of redemption.
- The redemption on October 1, 1993, of $65
million principal amount of First Mortgage
Bonds, 7 3/8% Series due January 1, 2001,
at 101.91% of the principal amount of such
bonds plus accrued interest to the date of
redemption.
- The redemption on October 1, 1993, of $100
million principal amount of First Mortgage
Bonds, 7 3/4% Series due May 1, 2002, at
102.21% of the principal amount of such bonds
plus accrued interest to the date of
redemption.
- The retirement on November 15, 1993, of $100
million principal amount of First Mortgage
Bonds, 8 1/8 % Series, which matured on
that date.
5. CREDIT FACILITIES. The Company's credit facilities
presently total $208.1 million, consisting of a $115 million
Revolving Credit Agreement with nine domestic money centers and
major regional banks, a $70 million long-term Revolving Credit
Agreement with eight foreign banks and a Revolving Credit Agreement
of $23.1 million with fifteen regional banks.
RETAIL RATE MATTERS
___________________
1. GENERAL. The Company is subject to regulation
in North Carolina by the North Carolina Utilities Commission (NCUC)
and in South Carolina by the South Carolina Public Service
Commission (SCPSC) with respect to, among other things, rates for
electric energy sold at retail, retail service territory and
issuances of securities.
2. CURRENT RETAIL RATES. The rates of return granted to
the Company in its most recent general rate cases are as follows:
1988 North Carolina Utilities Commission Order
(test year ended March 31, 1987)
______________________________________________
Capital Weighted Weighted
Capital Structure Ratio Cost Rate Cost
_________________ _______ _________ ________
Long-Term Debt 48.57% 8.62% 4.19%
Preferred Stock 7.43 8.75 .65
Common Equity 44.00 12.75 5.61
_____
Rate of Return 10.45%
=====
1988 South Carolina Public Service Commission Order
(test year ended September 30, 1987)
___________________________________________________
Capital Weighted Weighted
Capital Structure Ratio Cost Rate Cost
_________________ _______ _________ ________
Long-Term Debt 47.82% 8.62% 4.12%
Preferred Stock 7.46 8.75 .65
Common Equity 44.72 12.75 5.71
_____
Rate of Return 10.48%
=====
3. INTEGRATED RESOURCE PLANNING. Integrated Resource Planning is a
process that systematically compares all reasonably available resources,
both demand-side and supply-side, in order to develop that mix of
resources that allows a utility to meet customer demand in a most cost
effective manner, giving due regard to system reliability and safety.
The Company is required to file its IRP with the NCUC and the SCPSC once
every three years. The Company filed its 1992 Integrated Resource Plan
(IRP) with the NCUC on April 24, 1992, and by order dated June 29, 1993,
the NCUC approved the Company's 1992 IRP. The Company filed its 1992
IRP with the SCPSC on April 30, 1992, and by order dated April 8, 1993,
the SCPSC found that the Company's 1992 IRP complied with the SCPSC's
integrated resource planning rules. The Company regularly reviews its
IRP in light of changing conditions and evaluates the impact these
changes have on its resource plans, including purchases and other
resource options.
4. DEMAND SIDE MANAGEMENT. The Company's Demand Side
Management (DSM) programs are an integral part of its IRP. The
Company offers a variety of conservation, load management, and
strategic sales programs to its residential, commercial and
industrial customers. The objectives of the DSM programs are to
improve system operating efficiencies, meet customer needs in a
growing service area, defer the need for future generating units
and delay the need for future rate increases. Currently, the
Company offers time-of-use rates to all its retail customers, low
interest loans to its residential customers for the installation of
additional insulation and high efficiency heat pumps in existing
homes, financial incentives and an energy conservation discount for
all-electric homes that meet enhanced thermal integrity and
appliance efficiency standards, financial incentives for Company
control of residential water heaters and air conditioners in most
of the major metropolitan areas served by the Company, incentives
for the curtailment of large industrial loads, and energy
audits for large commercial and industrial customers, as well as
many other programs. Additional programs are in various stages of
investigation and development. The Company had achieved a summer
peak load reduction capability of 1,559 MW as of December 31, 1993,
through its conservation and load management programs. The
Company also has rates available for the purchase of power from
cogeneration and small power production facilities, as well as
standby service rates for customers using their own generation equipment.
At the end of 1993, the Company had 43 cogenerators and small power producers
on-line with facilities capable of generating a total of
approximately 471 MW, of which 283 MW is used internally by
customers and 188 MW is sold to the Company.
In addition to this cogeneration and small power production,
which is associated with the Company's Conservation and Load Management
Programs, other cogeneration projects have been installed and used as
planned generation resources. This additional capacity includes
approximately 266 MW that was fully operational at the end of
1993. The Company has a Hydroelectric Generation Program designed
to provide technical assistance to entrepreneurs who are
reactivating abandoned hydroelectric generating sites in the
Company's service territory. Presently, Hydroelectric Generation
Program capability on the Company's system totals approximately
15 MW. Other proposals for generation are received and evaluated
by the Company from time to time. See ITEM 1, "Competition and
Franchises."
5. FUEL COST RECOVERY. In the North Carolina retail
jurisdiction, the NCUC establishes base fuel costs in general rate
cases and holds hearings annually to determine whether a rider
should be added to base fuel rates to reflect increases or
decreases in the cost of fuel and the fuel cost component of
purchased power as well as changes in the fuel cost component of
sales to other utilities. The NCUC considers the changes in
the Company's cost of fuel during a historic test period ending
March 31 of each year and corrects any past over-or under-recovery.
The Company's 1994 North Carolina fuel case hearing is scheduled to
begin on August 2, 1994. In the South Carolina retail
jurisdiction, fuel rates are set by the SCPSC based on projected
costs for a future six-month test period. At the semi-annual hearings,
any past over-or under-recovery of fuel costs is taken into
account in establishing the new projected rate for the subsequent
six-month billing period. The Company's spring 1994 South Carolina
fuel case hearing was scheduled to begin on March 15, 1994;
however, on February 1, 1994, the SCPSC approved a settlement
agreement that resolved all issues between all parties to the
spring fuel proceeding. Pursuant to the settlement, the Company's
current fuel factor of 1.425 cents/kWh will continue in effect for the
six month period April 1 through September 30, 1994. Issues related to
outages at Brunswick Unit No. 1 and the Robinson Nuclear Plant during
the period July 1, 1993 through June 30, 1994 will be considered in the
fall 1994 South Carolina fuel case hearing. See ITEM 1, "Nuclear
Matters," paragraph 7.d., for considerations by the NCUC and the SCPSC
regarding costs related to the Brunswick Plant outage, and for a
discussion of the settlement agreements, reached in 1993, that resolved
issues related to a period of the Brunswick Unit No. 1 outage, and
settled the annual North Carolina and semi-annual South Carolina fuel
adjustment proceedings.
On December 14, 1992, the South Carolina Supreme Court
rendered its decision in Nucor Steel's (Nucor) appeal (Opinion No.
23761) of the SCPSC's decision in the Company's fall 1990 South
Carolina fuel case. In that fuel case the SCPSC considered the
three week operator training outage experienced by the Brunswick
Nuclear Plant in the spring of 1990, and also considered a
refueling outage experienced by Brunswick Unit No. 2 during the
test period. The South Carolina Supreme Court affirmed in part and
reversed in part the SCPSC's decision. As a result of the court's
decision, approximately $422,000 must be refunded to the
Company's customers. As part of the settlement of the spring
1994 South Carolina fuel case, the Company agreed to reduce its
fuel cost under-recovery account by this amount.
Nucor's appeal of the Company's fall 1990 South Carolina
fuel case also challenged the SCPSC's decision to exclude certain
testimony offered by Nucor regarding a partial outage experienced
by the Company's Robinson Unit No. 2 during the spring and summer
of 1990. When this issue was presented to the Court of
Common Pleas of Richland County, South Carolina, the court found
that the SCPSC should have considered Nucor's testimony, and
remanded the matter to the SCPSC. The SCPSC considered the
testimony, but found it unpersuasive and reaffirmed its earlier
orders on this issue. On September 8, 1993, Nucor appealed the
SCPSC's decision to reaffirm its earlier orders to the Court of
Common Pleas of Richland County, South Carolina. The Company
cannot predict the outcome of this matter.
6. IMPACT OF ENERGY ACT. Section 111 of the Energy Act
requires all state commissions to consider whether the adoption of
certain standards would further the purposes of the PURPA. These
standards relate to the use of integrated resource planning by
electric utilities, investments in conservation and demand side
management, and energy efficiency investments in power generation
and supply. Both the NCUC and the SCPSC have opened dockets to
consider these standards. With regard to the NCUC proceeding,
direct testimony was filed by the Company on February 8, 1994. A
hearing was held on March 8, 1994, but the NCUC has not
yet issued its ruling. With regard to the SCPSC proceeding, the
Company filed initial written comments on March 1, 1994, and reply
comments are due on April 15, 1994. The SCPSC will issue its
decision based upon the written comments. The Company cannot
predict the outcome of these matters.
WHOLESALE RATE MATTERS
______________________
1. GENERAL. The Company is subject to regulation by
the FERC with respect to rates for transmission and sale of
electric energy at wholesale, the interconnection of facilities in
interstate commerce (other than interconnections for use in the
event of certain emergency situations), the licensing and operation
of hydroelectric projects and, to the extent the FERC determines,
accounting policies and practices. The Company and its wholesale
customers last agreed to a general increase in wholesale rates in
1988.
2. FERC MATTERS.
a. On April 12, 1991, NCEMC and one of its members, Brunswick
Electric Membership Corporation, filed a Complaint and Motion for a Refund
(Complaint) with the FERC, Docket No. EL91-28-000, alleging that the
Company's wholesale rates and fuel clause billings were excessive and
requesting that the Company provide its real-time load signal to NCEMC.
All of the Company's remaining wholesale customers intervened in this
proceeding. On December 6, 1991, the FERC issued an order which denied
the Company's request to dismiss this Complaint, set certain matters for
hearing and initiated an investigation on behalf of the intervenors
(Docket No. EL91-54-000) to determine if the Company's wholesale rates
are excessive. On January 10, 1992, a FERC Administrative Law Judge
ordered that NCEMC's case be severed from the FERC-initiated
investigation so that the proceedings could continue independently of
each other. With regard to the FERC-initiated investigation, on
November 12, 1992, the FERC approved the settlement agreement that was
filed by the Company and all of the intervenors. With regard to NCEMC's
case, the Company has settled with NCEMC on all issues, and on
September 15, 1993, the FERC approved the settlement agreement
between the parties. The agreement provides for the continuation
of existing wholesale rate levels and resolves the wholesale fuel
clause billing issue through June 30, 1993. The impact of the
settlement totaled approximately $8 million, net of tax, and
decreased the Company's 1993 earnings by $.05 per common share.
On January 11, 1994, the Company and the intervenor that remained a
party to the proceeding initiated by NCEMC filed a settlement agreement
with the FERC for approval. On January 31, 1994, the FERC staff filed
comments partially opposing the settlement, but recommending that it be
certified to the FERC. On February 10, 1994, the Company and the
intervenor filed comments supporting the settlement, and rebutting
the FERC staff's contrary position. The settlement was certified to the
FERC on February 17, 1994. Although the Company cannot predict the
outcome of this matter, it does not believe that amounts associated with
the settlement will be material to the results of operations of the Company.
b. In 1989, Power Agency delivered to the Company a Notice of
Intention to Arbitrate certain disputed matters related to Power Agency's
use of capacity and energy from the South Carolina Public Service Authority
(Santee Cooper), which matters Power Agency originally raised in a complaint
before the FERC in 1988 (FERC Docket No. EL88-27-000). In June 1990,
the arbitrator issued an order in favor of the Company on the most
significant issues of contention between the Company and Power Agency.
In addition, the arbitrator ordered the Company and Power Agency to meet
for at least 120 days to negotiate a power coordination agreement
relating to Power Agency's use of capacity and energy from Santee
Cooper. On October 2, 1991, Power Agency filed a complaint at the FERC
(Docket No. EL92-1-000) alleging that the Company had refused to agree
to just and reasonable terms and conditions for power coordination
agreements for Power Agency's purchase of firm capacity and energy from
Santee Cooper for the period beginning January 1, 1994, and for Power
Agency's use of a combustion turbine electric generating project it planned
at that time to place in service on June 1, 1995. In 1993, Power Agency
agreed to delay the commercial operation date of its turbine generating
project for three years, until June 1, 1998. Power Agency's delay of the
project was part of the agreement the Company and Power Agency entered into
on April 7, 1993 to restructure portions of their contracts covering power
supplies and jointly-owned interests in several of the Company's generating
units. See ITEM 1, "Wholesale Rate Matters," paragraph 2.c. for further
discussion of the April 7, 1993 agreement between the Company and Power Agency.
On September 23, 1993, Power Agency and the Company entered into an agreement
in principle that resolves all remaining issues relating to the Santee
Cooper and turbine generator transactions. The parties continue to negotiate
the details of a final settlement. Because the Santee Cooper transaction
with Power Agency commenced on January 1, 1994, the Company and Power
Agency have entered into an interim agreement covering the Santee Cooper
transaction until a final agreement can be developed. The interim agreement
between the parties was approved by the FERC on December 30, 1993.
The Company cannot predict the outcome of these matters.
c. On April 7, 1993, the Company and Power Agency
entered into an agreement to restructure portions of their
contracts covering power supplies and jointly-owned interests in
several of the Company's generating units. Under the terms of the
agreement, the Company is increasing the amount of capacity and
energy purchased from Power Agency's ownership interest in the
Harris Plant. Additionally, the buyback period has been extended
six years through 2007. Also, pursuant to the agreement, a portion
of the Harris Plant will not be recoverable through sales of
supplemental power to Power Agency. As a result, the Company
recorded a write-off in 1993 of approximately $14.7 million, net of
tax, or $.09 per common share. Pursuant to that agreement, Power
Agency also agreed to the dismissal with prejudice of the Complaint
it filed against the Company on July 14, 1988 in the Superior Court
of Wake County, North Carolina (Docket No. 88 CVS 6512)
alleging that the Company failed to disclose alleged design,
management and other problems at the Harris Plant in connection
with the sale of capacity to Power Agency. The agreement also
provides that Power Agency will delay the commercial operation date
of its combustion turbine generating project for three years, until
June 1, 1998, and will withdraw the demand of its letter dated
January 20, 1993 regarding the costs incurred at the Brunswick
Plant during the outage that began in 1992. See ITEM 1, "Wholesale
Rate Matters," paragraph 2.b. for further discussion of the
agreement. The agreement was filed with the FERC on May 19, 1993
for approval of the provisions that are subject to the FERC's
jurisdiction. The Company cannot predict the outcome of this
matter.
3. OTHER WHOLESALE MATTERS.
a. By letter dated September 23, 1991, the City of
Bennettsville, South Carolina (City) notified the Company that it
was terminating service as a wholesale customer effective September
30, 1994, and that it intended to enter into a contract to purchase
power at wholesale from Marlboro Electric Cooperative, Inc. On
December 31, 1991, the Company filed a Declaratory Judgment
Complaint in the Court of Common Pleas of Marlboro County, South
Carolina (Docket No. 91-CP-34-316) seeking a determination as to
the appropriate termination date and as to whether a cooperative
can serve the City. On February 13, 1992, the Company filed
a Motion for Summary Judgment in this proceeding. By order filed
September 21, 1992, the Court of Common Pleas of Marlboro County,
South Carolina denied the Company's Motion for Summary Judgment
regarding the Marlboro Electric Cooperative, Inc.'s authority to
serve the City and granted the Motions for Summary Judgment
of Marlboro Electric Cooperative, Inc. and the City. On October
21, 1992, the Company filed a Notice of Appeal in the South
Carolina Supreme Court. By order dated March 7, 1994, the South
Carolina Supreme Court ruled that the City of Bennettsville can
purchase power from Marlboro Electric Cooperative, Inc. beginning
in 1995. The Company plans no further appeals. In 1993, the
City's average peak load was approximately 16 MW.
b. In March 1990, the City of Camden, South Carolina (City) notified the
Company that it would terminate its purchase of wholesale power from the
Company as of March 31, 1993. The Company responded that the
appropriate termination date was May 1, 1995. A petition filed with the
FERC by the City relating to this issue was dismissed in July 1991. On
December 3, 1991, the City filed a Declaratory Judgment Complaint in the
Court of Common Pleas of Kershaw County, South Carolina (Docket No.
91-CP-28-613) seeking a determination as to the proper termination date.
In 1992, Motions for Summary Judgment were filed by both parties in this
action. On November 9, 1992, the Court granted the Company's Motion for
Summary Judgment. The City filed a Notice of Appeal to the Supreme
Court of South Carolina. In 1993, both parties filed briefs in the
Supreme Court of South Carolina. On January 10, 1994, the parties filed
with the FERC for approval a contract amendment that will extend their
contractual relationship at least through 1998. By letter dated March
9, 1994, the FERC approved the contract amendment, effective March 11,
1994. Consequently, the parties will seek a dismissal of the State
court litigation. In 1993, the City's average peak load was
approximately 30 MW.
c. On March 10, 1994, the City of Fayetteville's Public Works
Commission and the Company entered into a new power supply and coordination
agreement under which the Company will continue to provide bulk power to
the City. The agreement provides for the sale of a minimum of 140 to
160 MW of base load service and other services for a minimum of ten
years, and at the parties' option, for up to fifteen years. The
agreement also resolves all wholesale fuel clause billing issues between
the City and the Company through December 31, 1993. The agreement will
enable the Company to effectively and efficiently meet the growing needs
of the City of Fayetteville for years to come. On March 16, 1994, the
agreement was filed with the FERC for approval. The Company cannot
predict the outcome of this matter.
ENVIRONMENTAL MATTERS
_____________________
1. GENERAL. In the areas of air quality, water
quality, control of toxic substances and hazardous and
solid wastes and other environmental matters, the Company is
subject to regulation by various federal, state and
local authorities. The Company considers itself to be in
substantial compliance with those environmental regulations
currently applicable to its business and operations
and believes it has all necessary permits to conduct
such operations. Except as noted below in paragraph 2, the
Company does not currently anticipate that its potential capital
expenditures for environmental pollution control purposes will be
material. Environmental laws and regulations, however, are
constantly evolving and the character, scope and ultimate costs for
compliance with such evolving laws and regulations cannot now be
accurately estimated. Costs associated with compliance with
pollution control laws and regulations at the Company's existing
facilities, which are expected to be incurred from 1994 through
1996, are included in the estimates of capital requirements under
ITEM 1, "Construction Program."
2. CLEAN AIR LEGISLATION. The 1990 amendments to
the Clean Air Act (Act) require substantial reductions in sulfur
dioxide and nitrogen oxides emissions from fossil-fueled electric
generating plants. The Company is not required to take action to
comply with the Act's Phase I requirements, which must be met by
January 1, 1995. Phase II of the Act, which contains more
stringent provisions, will become effective January 1, 2000. To
reduce sulfur dioxide emissions, as required by Phase II, the
Company will modify equipment to allow certain of the Company's
plants to burn lower sulfur coal, and is planning for the
installation of scrubbers. Installation of additional equipment
will also be necessary to reduce nitrogen oxides emissions. The
Company anticipates that it will be able to delay the installation
and operation of scrubbers until 2005 by purchasing sulfur
dioxide emission allowances. Each sulfur dioxide emission
allowance, issued by the Environmental Protection Agency (EPA),
will allow a utility to emit one ton of sulfur dioxide. In 1993,
the Company purchased emission allowances under the EPA's emission
allowance trading program. The Company estimates that the total
capital cost to comply with the requirements of Phase II of the Act
may approximate $340 million during the period 1994 through 1999,
and an additional $460 million during the period 2000 through 2005.
These estimates, for installation or modification of equipment, are
in nominal dollars (undiscounted future amounts expected to be
expended). The required modifications and additions are expected
to increase operating and maintenance costs by a total of $20
million for the period 1994 through 1999, $48 million for the
period 2000 through 2004, and by $42 million annually, beginning in
2005. Actual plans for compliance with the Act's requirements have
not been finalized, and the amount required for capital
expenditures and for increased operating and maintenance
expenditures cannot be determined with certainty at this time.
The financial impact of the additional expenditures will be
dependent on future ratemaking treatment. The NCUC and the SCPSC
are currently allowing the Company to accrue carrying charges on
its investment in emission allowances. A plan for
compliance with Phase II of the Act must be submitted to the EPA
by January 1, 1996. The Company cannot predict the outcome of this matter.
3. SUPERFUND. The provisions of the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as
amended (CERCLA), authorize the EPA and, indirectly, the states, to
require generators and certain transporters of certain hazardous
substances released from or at a site, and the owners and operators
of such site, to clean up the site or reimburse the costs therefor.
This statute has been interpreted to impose joint and several
liability on responsible parties. There are presently several
sites with respect to which the Company has been notified by the
EPA or the State of North Carolina of its potential liability, as
described below in greater detail.
a. On December 2, 1986, the EPA notified the Company of its
potential liability pursuant to CERCLA for the investigation and cleanup
activities associated with the Maxey Flats Nuclear Disposal Site in
Fleming County, Kentucky. The EPA indicated that the site was operated
from 1963 to 1977 under the management of Nuclear Engineering Company
(now U. S. Ecology). The EPA estimated that the Company sent 304,459
cubic feet of waste to the disposal site. In response to the EPA's
notice, the Company and several other potentially responsible parties
(PRPs) formed a steering committee (the Maxey Flats Steering Committee)
to undertake a remedial investigation/feasibility study pursuant to
CERCLA. As a result of this study, the EPA has selected a remedial
action which is currently estimated to have a present value cost of
between $57 million and $78 million. Subsequent analysis of waste
volume sent to the site performed by the Maxey Flats Steering Committee
established that the Company contributed only approximately 1% of the
total waste volume. It is expected that the Company's share of
remediation costs will be based on the ratio of the Company's waste
volume to that of other participating PRPs. The Company is currently
ranked twenty-fourth on the waste-in list. On June 30, 1992, the EPA
sent the Company, along with a number of other companies, agencies and
organizations, a notice demanding reimbursement of response costs of
approximately $5.8 million that have been incurred at the site and
seeking to initiate formal negotiations regarding performance of the
remedial design and remedial action for the site. On July 20, 1992, the
Company responded that it would negotiate these matters through the
Maxey Flats Steering Committee. In December 1992, the EPA rejected the
offer the Maxey Flats Steering Committee filed regarding the performance
of the remedial design and remedial action for this site. The Maxey
Flats Steering Committee submitted amended offers to the EPA in 1993.
The EPA has engaged in settlement negotiations with the Maxey Flats Steering
Committee. Although the Company cannot predict the outcome of these
matters, it does not anticipate that costs associated with this site
will be material to the results of operations of the Company.
b. On December 2, 1986, the EPA notified the
Company that it is a PRP with respect to the disposal, treatment or
transportation for disposal or treatment of polychlorinated
biphenyls (PCBs) at the Martha C. Rose Chemicals, Inc. (Rose)
facility located in Holden, Missouri. Roughly 190,000 pounds of
PCB wastes (approximately .8% of the total waste volume) are
alleged to have been sent to the site by the Company.
By volume, the Company ranks twenty-third on the waste-in list.
Site stabilization was completed by Clean Sites, Inc., the third
party hired to negotiate a cleanup between the waste generators and
the EPA. By letter dated November 12, 1993, the EPA approved the
final remediation design for the Rose site. Final site cleanup is
expected to begin in 1994. There is currently over 90%
participation by the PRPs in the site cleanup. It is estimated
that cleanup will cost approximately $30 million. The Company has
contributed approximately $293,000 to the waste generators' group
and does not expect that it will be required to contribute
additional funds to complete remediation of this site. Although
the Company cannot predict the outcome of this matter, it does
not anticipate that the costs associated with this site will be
material to the results of operations of the Company.
c. In May 1989, the EPA notified the Company
that it is a PRP with respect to the disposal of PCB transformers
allegedly sent through Saline County Salvage to Elliot's Auto Parts
Site in Benton, Arkansas. In its responses to the EPA, the Company
stated its belief that no Company electrical equipment went to the
site. Additionally, the Company declined to enter into an
Administrative Order of Consent. In December 1992, the Elliot's
Auto Parts PRP Committee requested that the Company pay a share of
the estimated $2.65 million cost of cleaning up the site, and
threatened to initiate litigation should the Company not contribute
to the cleanup cost. The Company responded that it would be
willing to participate in cleanup activities at the site if
documentation was produced showing that the Company contributed
any hazardous substances to the site. On January 21, 1993, the
Elliot's Auto Parts PRP Committee produced documents alleging that
the Company contributed hazardous substances to the site. Although
the documentation provided does not clearly establish
that the Company disposed of transformers at the Elliot's site,
the Company is currently negotiating with the Elliot's Auto Parts
PRP Committee to avoid protracted litigation. The Elliot's Auto
Parts PRP Committee has completed remedial activities at the site
at a cost of approximately $2.7 million and will soon submit a
final report to the EPA. Although the Company cannot predict the
outcome of this matter, it does not anticipate that costs associated
with this site will be material to the results of operations of the
Company.
d. By letter dated May 21, 1991, the EPA notified
the Company that it is a PRP with respect to the disposal of
hazardous substances at the Benton Salvage site in Benton,
Arkansas. The Company has been unable to identify any records of
shipments by the Company to that site. Until any such
documentation can be produced, the Company does not intend to
participate in cleanup activities at the site. The Company cannot
predict the outcome of this matter.
e. On April 15, 1991, the North Carolina
Department of Environment, Health, and Natural Resources (DEHNR)
notified the Company that it is a PRP with respect to the disposal
of hazardous waste at the Seaboard Chemical Corporation (Seaboard)
site in Jamestown, North Carolina. DEHNR has indicated that
it is offering PRPs the opportunity to perform voluntary site
cleanup. Seaboard records indicate that there are over 1,300 PRPs
for the site and that the Company's contribution to waste disposal
is less than 1% of the total waste disposed. On May 29, 1992, the
Company entered into an Administrative Order on Consent with
DEHNR, Division of Solid Waste Management, to undertake and
perform a Work Plan for Surface Removal (Removal Work Plan). On
July 28, 1993, DEHNR determined that the Removal Work Plan had been
substantially completed. DEHNR further recommended that the
Seaboard Group (a group of PRPs with respect to the Seaboard site)
undertake additional remedial activities at the Seaboard site. The
Seaboard Group is currently considering its response to DEHNR's
recommendation. The Company estimates that to date its costs
associated with completion of the Removal Work Plan total
approximately $12,000. Although the Company cannot predict the
outcome of this matter, it does not anticipate that costs associated
with this site will be material to the results of operations of the
Company.
f. On January 9, 1992, the EPA sent notice to
the Company, along with a number of other companies and persons,
stating that the Company is a PRP with respect to the additional
remediation of hazardous wastes at the Macon-Dockery site located
near Cordova, North Carolina. The Company made arrangements in the
past for the transportation and sale of waste and residual oil to
C&M Oil Distributors, a company that operated an oil reprocessing
facility at the Macon-Dockery site for a period of several months.
However, the information available to the Company indicates that
no hazardous wastes from Company facilities were sent to the site.
Previously, in 1987, the EPA sent notice to the Company that the
EPA believed the Company was a PRP with respect to costs incurred
by the EPA for initial site cleanup of the Macon-Dockery
site. The Company was also a third-party defendant in a lawsuit
brought in federal district court to recover the cleanup costs
incurred by the EPA. That lawsuit was subsequently settled.
Unless the EPA produces evidence which establishes that hazardous
wastes from Company facilities were sent to the site, the Company
does not intend to participate in these new cleanup activities.
The Company cannot predict the outcome of this matter.
4. OTHER ENVIRONMENTAL MATTERS.
a. On April 21, 1989, the North Carolina
Division of Environmental Management (DEM) requested that the
Company install a groundwater compliance monitoring system at the
Company's Wilmington Oil Terminal located in New Hanover County,
North Carolina. The request was prompted by the discovery of
petroleum contamination beneath a neighboring oil transportation
facility. DEM requested the installation of the monitoring system
in order to determine if groundwater quality standards have been
violated at the Wilmington Oil Terminal and if any such violations
have contributed to the contamination underneath the neighboring
facility. During the second half of 1989, six groundwater
monitoring wells were installed and samples were collected and
analyzed for the presence of petroleum hydrocarbons. Samples from
one of the six wells indicated gasoline contamination and samples
from a second well indicated No. 2 fuel oil contamination. The
Company provided information on these monitoring wells to the DEM
and in February 1993, DEM granted the Company permission to install
a remediation system to collect and treat contaminated groundwater.
This system conveys the groundwater to the neighboring facility for
co-treatment of the contaminated water. Although the Company
cannot predict the outcome of this matter, it believes that any
remediation expense would not exceed $100,000 annually.
b. Various organic materials associated with
the production of manufactured gas, generally referred to as coal
tar, are regulated under various federal and state laws, and a
contingent liability may exist for their remediation. The
production of manufactured gas was commonplace from the late 1800s
until the 1950s. The Company has learned of the existence of
several manufactured gas plant (MGP) sites to which the
Company and certain entities which were later merged into the
Company may have had some connection. In 1992, the State of North
Carolina, through DEHNR's Division of Solid Waste Management
(DSWM), launched an initiative to encourage former owners and
operators of MGP sites to voluntarily assess those sites and to
undertake remedial action where necessary. In this regard, the
Company is participating in the North Carolina MGP Group (Group),
a group of entities alleged to be former owners or operators of MGP
sites, that was formed in response to DSWM's initiative. In
December 1993, the Group and DSWM entered into a Memorandum of
Understanding relative to the establishment of a uniform program
and framework for addressing MGP sites for which DSWM has contended
that members of the Group have potential responsibility.
It is anticipated that the investigation and remediation of
specific MGP sites will be addressed pursuant to one
or more Administrative Orders on Consent between DSWM and
individual potentially responsible parties. Additionally, a
current owner of one such site formerly owned by Tidewater Power
Co., which merged into the Company in 1952, made an informal claim
against the Company for the cost of investigation and possible
remediation, if necessary, of hazardous materials at this site.
The Company and the current owner have entered into an agreement to
share the cost of investigation and remediation of the site. Due
to the lack of information with respect to the operation of MGP
sites and the uncertainty concerning questions of liability and
potential environmental harm, the extent and cost of required
remedial action, if any, and the extent to which liability may
be asserted against the Company or against others are not currently
determinable. The Company cannot predict the outcome of these
matters or the extent to which other former MGP sites
may become the subject of inquiry.
NUCLEAR MATTERS
_______________
1. GENERAL. Under the Atomic Energy Act of 1954 and the Energy
Reorganization Act of 1974, as amended, operation of nuclear plants is
intensively regulated by the NRC, which has broad power to impose
nuclear safety and security requirements. In the event of
non-compliance, the NRC has the authority to impose fines, set license
conditions, or shut down a nuclear unit, or some combination of these,
depending upon its assessment of the severity of the situation, until
compliance is achieved. The electric utility industry in general has
experienced challenges in a number of areas relating to the operation of
nuclear plants, including substantially increased capital outlays for
modifications; the effects of inflation upon the cost of operations;
increased costs related to compliance with changing regulatory
requirements; renewed emphasis on achieving excellence in all phases of
operations; unscheduled outages; outage durations; and uncertainties
regarding storage facilities for spent nuclear fuel. See paragraph 7.c.
below. The Company experiences these challenges to varying degrees.
Capital expenditures for modifications at the Company's nuclear units,
excluding Power Agency's ownership interests, during 1994, 1995 and 1996
are expected to total approximately $108 million, $78 million and $55
million, respectively (including AFUDC).
2. SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE. The Nuclear Waste
Policy Act of 1982 (Act) provides the framework for development by the
federal government of interim storage and permanent disposal facilities
for high-level radioactive waste materials. The Act promotes increased
usage of interim storage of spent nuclear fuel at existing nuclear
plants. The Company will continue to maximize the usage of spent fuel
storage capability within its own facilities for as long as feasible.
Pursuant to the Act, the Company, through a joint agreement with the U.
S. Department of Energy (DOE) and the Electric Power Research Institute,
has built a demonstration facility at the Robinson Plant that allows for
the dry storage of 56 spent nuclear fuel assemblies. As of December 31,
1993, sufficient on-site spent nuclear fuel storage capability is
available for the full-core discharge of Brunswick Unit No. 1 through
1994, Brunswick Unit No. 2 through 1996, and Robinson Unit No. 2 through
1998, assuming normal operating and refueling schedules. The Harris
Plant spent fuel storage facilities, with certain modifications together
with the spent fuel storage facilities at the Brunswick and Robinson
Units, are sufficient to provide storage space for spent fuel generated
on the Company's system through the expiration of the current operating
licenses for all of the Company's nuclear generating units. Subsequent
to the expiration of the licenses, as part of decommissioning of the
units, dry storage may be necessary. The Company is maintaining
full-core discharge capability for the Brunswick Units and Robinson Unit
No. 2 by transferring spent nuclear fuel by rail to the Harris Plant.
As a contingency to the shipment by rail of spent nuclear fuel, on April
27, 1989, the Company filed an application with the NRC for the issuance
of a license to construct and operate an independent spent fuel storage
facility for the dry storage of spent nuclear fuel at the Brunswick
Plant. The Company cannot predict whether or not a license will
ultimately be issued by the NRC.
As required by the Act, the Company entered into a
contract with the DOE under which the DOE will dispose of the
Company's spent nuclear fuel. The contract includes a provision
requiring the Company to pay the DOE for disposal costs. Disposal
costs of fuel burned are based upon actual nuclear generation and
are paid on a quarterly basis. Effective January 31, 1992, the DOE
revised the method for calculating the nuclear waste disposal cost
which will reduce the Company's quarterly payment. Existing
overpayments, with interest, will be refunded in the form of
credits over the next two fiscal years. Disposal costs, excluding
waste disposal credits, are approximately $20 million annually
based on the expected level of operations and the present disposal
fee per kWh of nuclear generation, and are currently recovered
through the Company's fuel adjustment clauses. See ITEM 1, "Retail
Rate Matters," paragraph 5. Disposal fees may be reviewed annually
by the DOE and adjusted, if necessary. The Company cannot predict
at this time whether the DOE will be able to perform its contract
and provide interim storage or permanent disposal repositories
for spent fuel and/or high-level radioactive waste materials on a
timely basis.
3. LOW-LEVEL RADIOACTIVE WASTE. Disposal costs for
low-level radioactive waste that results from normal operation of
nuclear units have increased significantly in recent years and are
expected to continue to rise. Pursuant to the Low-Level
Radioactive Waste Policy Act of 1980, as amended in 1985, each
state is responsible for disposal of low-level waste generated in
that state. States that do not have existing sites may join
in regional compacts. The States of North Carolina and South
Carolina are participants in the Southeast regional compact and,
currently, dispose of waste at an existing disposal site in South
Carolina along with other members of the compact. The North
Carolina Low-Level Radioactive Waste Management Authority,
which is responsible for siting and operating a new low-level
radioactive waste disposal facility for the Southeast regional
compact, recently selected a preferred site in Wake County, North
Carolina. Although the Company does not control the future
availability of low-level waste disposal facilities, the cost of
waste disposal or the development process, it is actively
supporting the development of new facilities and is committed to a
timely and cost-effective solution to low-level waste disposal.
Should shipments to the existing regional compact site cease,
present projections indicate that existing on-site storage
facilities at the Company's nuclear plants are sufficient
to provide approximately eight months of storage capacity. The
Company cannot predict the outcome of this matter.
4. DECOMMISSIONING.
a. Pursuant to a NRC rule, licensees of nuclear
facilities are required to submit decommissioning funding plans to
the NRC for approval to provide reasonable assurance that the
licensee will have the financial ability to implement its
decommissioning plan for each facility. The rule requires
licensees to do one of the following: prepay at least a
NRC-prescribed minimum amount immediately; set up an external
sinking fund for accumulation of at least that minimum amount
over the operating life of the facility; or provide a surety to
guarantee financial performance in the event of the licensee's
financial inability to perform actual decommissioning. On July 26,
1990, the Company submitted its decommissioning funding plans to
the NRC. In this regard, the Company entered into a Master
Decommissioning Trust Agreement dated July 19, 1990 (Trust), with
Wachovia Bank of North Carolina, N.A., as Trustee, as a vehicle to
achieve such decommissioning funding. In June 1991, the Company
began depositing amounts currently collected in rates into the
Trust. At the currently approved jurisdictional funding levels,
contributions to the Trust will be approximately $19 million
on an annualized basis. Through December 31, 1993, the Company
had collected through rates an aggregate of $221.6 million for
decommissioning, which includes amounts funded internally and
externally.
b. The Company is required to increase external
funding to the NRC-prescribed minimum no later than January 1,
1996. This NRC-prescribed minimum exceeds amounts currently
collected in rates. In future rate filings, the Company will
request rate recovery based on site-specific estimates for prompt
dismantlement decommissioning. The requested rate recovery will
also include funding plans that assume external funding of, at
least, the NRC-prescribed minimum. The financial impact on the
Company will depend on future ratemaking treatment. The NCUC and
SCPSC have allowed other utilities to recover costs based on
site-specific estimates for prompt dismantlement decommissioning
and funding plans similar to those the Company intends to use.
c. The Company's most recent site-specific
estimates of decommissioning costs were developed in 1993, and are
based on prompt dismantlement decommissioning, which reflects the
cost of removal of all radioactive and other structures currently
at the site. These estimates, in 1993 dollars, are as follows:
$257.7 million for Robinson Unit No. 2; $284.3 million for the
Harris Plant; $235.4 million for Brunswick Unit No. 1; and $221.4
million for Brunswick Unit No. 2. These estimates are subject to
change based on a variety of factors, including, but not limited
to, inflation, changes in technology applicable to nuclear
decommissioning, and changes in federal, state or local
regulations. The cost estimates exclude the portion attributable
to Power Agency, which holds an undivided ownership interest in
certain of the Company's generating facilities. To the
extent of its ownership interests, Power Agency is responsible
for satisfying the NRC's financial assurance requirements for
decommissioning costs. See ITEM 1, "Generating Capabilities,"
paragraph 1.
5. OPERATING LICENSES. Facility Operating Licenses,
issued by the NRC, may be amended by the NRC to extend the
expiration dates of an operating license of a nuclear facility to
allow for up to 40 years of commercial operation. The current
expiration dates for the Company's nuclear facilities allow for the
entire 40 years of commercial operation and are set forth in the
following table.
Facility Operating License
Facility Expiration Date
________ __________________________
Robinson Unit No. 2 July 31, 2010
Brunswick Unit No. 1 September 8, 2016
Brunswick Unit No. 2 December 27, 2014
Harris Plant October 24, 2026
6. DESIGN BASIS RECONSTITUTION EFFORTS. The Company
has been in the process of reviewing the design basis documentation
for Robinson Unit No. 2 since 1988 and for the Brunswick Plant
since 1990. Significantly more design detail has been required by
the NRC for recently constructed plants than was needed when
Robinson Unit No. 2 and the Brunswick Plant were built. In order
to operate effectively in the current regulatory environment, the
Company must be able to provide documentary evidence of compliance
with regulations and design documents. The design basis
reconstitution effort involves research, compilation and
verification of documents that set forth the key design
requirements of the various safety systems. The Company's review
of the design basis documentation for Robinson Unit No. 2 was
completed in 1993, and the Brunswick Plant effort is still in
progress. The baseline effort for the two Brunswick Units is
scheduled for completion by the end of 1996, and is projected to
have a total cost of approximately $40 million. The Company
cannot predict the outcome of this matter.
7. OTHER NUCLEAR MATTERS.
a. Large diameter reactor recirculation system
piping in boiling water reactor (BWR) units, such as the Brunswick
Units, has the potential to crack as a result of intergranular
stress corrosion (IGSCC) and the NRC required an ultrasonic
inspection of such piping at BWR units. As a result of these
inspections, certain portions of the large diameter reactor
recirculation piping were replaced at both of the Brunswick Units.
Subsequently, ultrasonic testing for IGSCC was performed on
Brunswick Unit No. 1 during an outage in 1991 and identified a
feedwater nozzle weld which required further study. The NRC
authorized restart of Unit No. 1 and, based upon additional
information provided by the Company, approved full-cycle operation
of Unit No. 1. The feedwater nozzle in question is being evaluated
for possible replacement as part of modifications scheduled for
Brunswick during the next refueling outage.
b. In 1991, the NRC issued a final rule on nuclear
plant maintenance that will become effective on July 10, 1996. In
general terms, the new maintenance rule prescribes the
establishment of performance criteria for each safety system based
on the significance of that system. The rule also requires
monitoring of safety system performance against the established
acceptance criteria, and provides that remedial action be taken
when performance falls below the established criteria. The Company
has been working closely with the Nuclear Management and Resources
Council and with other utilities to develop its compliance
approach and to minimize the financial and operational impacts of
the new rule. The Company anticipates its compliance will be on
schedule and is evaluating the magnitude of the financial and operational
impacts of this new rule. The Company cannot predict the outcome of
this matter.
c. On November 23, 1988, the NRC requested in
Generic Letter 88-20 that utilities perform Individual Plant
Examinations (IPEs) to determine potential vulnerabilities to
severe accidents beyond the design basis accidents for which the
plants are designed. These are considered to be very low
probability events. The Company submitted the results of the first
phase (for internally initiated events) in August 1992 for the
Brunswick and Robinson Plants. Potential enhancements for the
Robinson Plant are currently being evaluated, and the Company
cannot predict at this time the exact magnitude of financial and
operational impacts which may result from these evaluations. For
the Brunswick Plant, no modifications were required to meet the
guidelines of the IPE. On August 20, 1993, the Company submitted
the results of the Harris Plant IPE. While some Harris Plant
procedural changes were made due to the IPE results, the IPE did
not reveal any significant financial or operational impacts or
identify any need for plant modifications. The Company cannot
predict at this time the exact magnitude of the financial and
operational impact of the second phase of the IPE (for
externally initiated events) to be completed for all three plants
during 1994-1995.
d. In April 1992, both units at the Company's
Brunswick Plant were taken out of service in order for the Company
to address anchor bolt deficiencies and related wall construction
issues in the diesel generator building. During the outage, in
addition to resolving the anchor bolt deficiencies and related
diesel generator building wall construction issues, the Company
conducted detailed inspections and engineering evaluations of the
plant's miscellaneous steel, performed necessary corrective and
preventive maintenance and made certain modifications.
An intensive on-site review of Brunswick Unit No.
2 was conducted by a NRC operational readiness assessment team from
March 29 through April 9, 1993. The team concluded that the depth
and capability of the Brunswick staff, the organizational structure
and in-place programs were adequate to support Unit No. 2
restart and operation. On April 27, 1993, the NRC issued its
determination that Unit No. 2 was ready for restart. The Company
promptly began a detailed startup process at Unit No. 2 to ensure
a safe, controlled and deliberate return to service. The Company
returned Unit No. 2 to service in May 1993. In late December 1993,
Unit No. 2 set a new continuous run record for that unit of more
than 219 days.
In July 1993, cracks were discovered in the Brunswick Unit No. 1
reactor vessel shroud during inspections made as part of refueling activities
performed during the outage. The Company conducted intensive ultrasonic
testing and physical sampling inspections of the cracks. The results of
this investigation provided data used to develop new stiffening braces
to ensure that the shroud will continue to perform its design function.
Shroud modifications were completed in late December 1993. Costs
associated with the shroud repairs were not material to the results of
operations of the Company. The Company commenced startup of Unit No. 1
on February 1, 1994 under a gradual power ascension startup plan. This
power ascension plan was completed 27 days ahead of schedule when Unit
No. 1 was returned to normal operation on February 23, 1994, after
successfully completing extensive startup testing. Additional shroud
inspections may be conducted during future refueling outages to identify
and monitor other minor cracking in the shroud. The Company cannot
predict the outcome of this matter.
In July 1993, the Company also determined that the Brunswick
Unit No. 2 shroud has minor crack indications which do not compromise the
safety or operation of the Unit. Shroud modifications, similar to those
performed on Unit No. 1, will be undertaken on Unit No. 2 during the
spring 1994 refueling outage. The Company does not expect that costs
associated with the shroud modifications will be material to the results
of operations of the Company.
On October 14, 1993, two private organizations, the
National Whistleblower Center and the Coastal Alliance for a Safe
Environment, and an individual filed a petition with the NRC under
10 C.F.R. Section 2.206 alleging that the Company was aware of the
shroud cracks as early as 1984 and engaged in criminal activities
to conceal its knowledge of the cracks. The petitioners requested
that the NRC require the Company to state whether it knew about the
cracks in 1984 and determine whether the Company has engaged in
criminal wrongdoing. To date, the petitioners have failed to
provide the Company with any evidence substantiating their claims.
Additionally, the Company conducted an internal technical review
of this matter which did not reveal any evidence that substantiates
the petitioners' claims. The results of this technical review were
submitted to the NRC in November 1993. Although the Company cannot
predict the outcome of this matter, it believes the allegations
contained in the petition are without merit.
In December 1993, the NRC issued its latest
Systematic Assessment of Licensee Performance (SALP) report for the
Brunswick Plant. The report rated Brunswick's plant operations and
plant support as "superior," and the Plant's maintenance and
engineering as "good." The NRC, in both the report and at a public
meeting, recognized significant improvements made at the plant.
On July 28, 1993, the Company, the Public Staff, the
Attorney General of the State of North Carolina, and Carolina
Industrial Group for Fair Utility Rates II entered into an
agreement that resolved as between them all issues related to the
Brunswick Plant outage on or before the date of the agreement,
avoided higher fuel charges to the Company's customers and settled
the Company's 1993 North Carolina fuel adjustment proceeding.
The Company had $31.2 million in fuel expenses for the
twelve-month period ended March 31, 1993 that had not been
recovered from North Carolina customers through the Company's
rates. As a part of the agreement, the Company agreed to forgo
recovering $25.5 million of these fuel expenses, and to recover the
remaining $5.7 million through rates over a twelve-month period
beginning in September 1993. That $5.7 million is subject to
refund at the end of three years if the Brunswick Plant does not
achieve a specified operating performance level. Additionally, the
Company agreed that if the Brunswick Plant's performance for the
three-year period ending March 31, 1996 does not achieve a
specified operating performance level, the Company could lose up to
$10 million in additional fuel expenses. By order dated September
14, 1993, the NCUC approved the agreement. The forgone fuel
expense recovery of $25.5 million reduced the Company's 1993
earnings by approximately $.10 per common share.
On September 7, 1993, the Company, the Staff of the SCPSC, Nucor Steel,
and the Consumer Advocate for the State of South Carolina, which
represents the using and consuming public in matters before the SCPSC,
entered into an agreement to settle the fall 1993 SCPSC fuel proceeding.
The settlement resolved all issues related to fuel costs incurred by the
Brunswick Plant through June 30, 1993, avoided higher fuel charges to
the Company's customers and settled the fall 1993 semi-annual South
Carolina fuel adjustment proceedings. The SCPSC approved the agreement
by order dated September 14, 1993. Pursuant to the terms of the
settlement, the Company agreed to forgo recovery of a total of $15.6
million in fuel expenses. The forgone fuel expense recovery of $15.6
million reduced the Company's 1993 earnings by approximately $.06 per
common share.
The NRC, the NCUC and the SCPSC will continue to
review the Company's activities at the Brunswick Plant. Except as
noted, the Company cannot predict the extent to which these and
other actions may impact its ability to recover costs associated
with this outage.
e. On November 17, 1993, during startup from a
scheduled refueling outage at the Company's H. B. Robinson Plant
Unit No. 2, the Company discovered problems with the fuel
supplier's fabrication of certain fuel assemblies which had been
loaded during the outage. A problem relating to the calibration of
the power level instrumentation was also identified. The Company
elected to interrupt and delay the startup process pending analysis
and correction of the problems, and notified the NRC of its
decision. The NRC issued a Confirmatory Action Letter, dated
November 19, 1993, in which it confirmed, among other things, that
the Company would conduct detailed root cause analyses of the fuel
assembly and power level instrumentation issues and would take
appropriate corrective actions. On November 20, 1993, an NRC
Augmented Inspection Team (AIT) began its investigation of the fuel
assembly and power level instrumentation issues. In investigating
the fuel assembly issue, the AIT visited both the Robinson Plant
and the fuel supplier's facilities. Results of the AIT's
investigation were initially released in a public meeting on
December 6, 1993 and the AIT's report was issued on January 5,
1994. An enforcement conference was conducted on March 14, 1994 for
the purpose of discussing apparent violations identified in the AIT's
report in the areas of management control of refueling and
restart activities. The NRC will determine whether or not to
issue violations and what, if any, resulting penalty should be
imposed upon the Company. The Company cannot predict the outcome
of this matter.
In a separate action, on March 14, 1994, the NRC issued a Notice of
Violation and Proposed Imposition of Civil Penalty in the amount of $37,500
relating to the degradation of both Robinson Unit No. 2 emergency diesel
generators and failure to correct conditions which affected operation of
one of the diesel generators in mid-November, 1993. The base civil penalty
for this type of violation is $50,000, but the propsoed penalty was reduced
to $37,500 due to the Company's comprehensive performance in analyzing the
root cause of the diesel generator problem. The Company has thirty days from
the date of the Notice to pay or protest the civil penalty, in whole or in
part. The Company intends to pay the civil penalty. The Company
cannot predict the outcome of this matter.
On February 8, 1994, the NRC issued its SALP report for
Robinson Unit No. 2 for the period June 1992 through December 1993. While
the NRC noted that overall performance of Robinson Unit No. 2 was reasonably
good, it indicated that performance declined in several areas, primarily due
to the matters discussed above. The NRC rated Robinson Unit No. 2's
performance as "good" in operations, engineering and plant support
and "acceptable" in maintenance.
In early February 1994, the Company satisfied the conditions
of the NRC's confirmatory action letter, and returned Robinson Unit No. 2 to
service on March 21, 1994 under a power ascension plan.
f. The Company is insured against public liability
for a nuclear incident up to $9.4 billion per occurrence, which is
the maximum limit on public liability claims pursuant to the
Price-Anderson Act. The $9.4 billion coverage includes $200
million primary coverage and $9.2 billion secondary financial
protection through assessments on nuclear reactor owners. In the
event that public liability claims from an insured nuclear incident
exceed $200 million, the Company would be subject to a pro rata
assessment, for each reactor it owns, of up to $75.5 million, plus
a 5% surcharge, for each incident. Payment of such assessment
would be made over time as necessary to limit the payment in any
one year to no more than $10 million per reactor owned. Power
Agency would be responsible for its ownership share of the
assessment on jointly-owned units.
FUEL
____
1. SOURCES OF GENERATION. Total system generation
(including Power Agency's share) by primary energy source, along
with purchased power, for the years 1990 through 1994 is set forth
below:
1990 1991 1992 1993 1994
_______________________________________________
(estimated)
Fossil 47% 47% 56% 54% 47%
Nuclear 41 41 27 31 40
Purchased Power 10 10 15 13 11
Hydro 2 2 2 2 2
2. COAL. The Company has intermediate and long-term
agreements from which it expects to receive approximately 88% of
its coal burn requirements in 1994. During 1992 and 1993, the
Company obtained approximately 79% (8,185,000 tons) and 73%
(7,198,000 tons), respectively, of its coal burn requirements from
intermediate and long-term agreements. Over the next ten years,
the Company expects to receive approximately 75% of its coal burn
requirements from intermediate and long-term agreements. Existing
agreements have expiration dates ranging from 1994 to 2006. During
1993, the Company maintained from 48 to 99 days' supply of
coal, based on anticipated burn rate. All of the coal that the
Company is currently purchasing under intermediate and long-term
agreements is considered to be low sulfur coal by industry
standards. Recent amendments to the Clean Air Act may result in
increases in the price of low sulfur coal prior to the effective
date of the first phase of the Act, with such impact to continue
beyond the effective date of the second phase of the Act. See ITEM
1, "Environmental Matters," paragraph 2. The Company purchased
approximately 2,250,000 tons of coal in the spot market during 1992
and 2,650,000 tons in 1993. No spot coal was purchased in 1991.
The Company's contract coal purchase prices during 1993 ranged from
approximately $23.19 to $39.38 per ton (F.O.B. mine). The average
cost to the Company of coal delivered for the past five years is as
follows:
Year $/Ton Cents/Million BTU
____ _____ _________________
1989 45.01 179
1990 45.88 183
1991 47.40 190
1992 43.25 174
1993 43.10 172
3. OIL. The Company uses No. 2 oil primarily for its
combustion turbine units, which are used for emergency backup and
peaking purposes. The Company burned approximately 8.4 million and
9.1 million gallons of No. 2 oil during 1992 and 1993,
respectively. The Company has a No. 2 oil supply contract for its
normal requirements. In the event base-load capacity is
unavailable during periods of high demand, the Company may
increase the use of its combustion turbine units, thereby
increasing No. 2 oil consumption. The Company intends to meet any
additional requirements for No. 2 oil through additional contract
purchases or purchases in the spot market. There can be no
assurance that adequate supplies of No. 2 oil will be available to
meet the Company's requirements. To reduce the Company's
vulnerability to dislocations in the oil market, seven combustion
turbine units with a total generating capacity of 364 MW have been
converted to burn either propane or No. 2 oil. In addition, twelve
combustion turbine units with a total generating capacity of 425 MW
can burn natural gas when available. Over the last five years, No.
2 oil, natural gas and propane accounted for 1.7% of the Company's
total burned fuel cost. In 1993, No. 2 oil, natural gas and
propane accounted for 1.5% of total burned fuel cost. The
availability and cost of fuel oil could be adversely affected by
energy legislation enacted by Congress, disruption of oil or gas
supplies, labor unrest and the production, pricing and embargo
policies of foreign countries.
4. NUCLEAR. The nuclear fuel cycle requires the
mining and milling of uranium ore to provide uranium oxide
concentrate (U3O8), the conversion of U3O8 to uranium hexafluoride
(UF6), the enrichment of the UF6 and the fabrication of the
enriched uranium into fuel assemblies. The Company has on hand or
has contracted for raw materials and services for its nuclear units
through the years shown below:
Raw Materials and Service
_______________________________________________
Unit Uranium Conversion Enrichment Fabrication
____ _______ __________ __________ ___________
Robinson No. 2 1996 1995 1994 1999
Brunswick No. 1 1996 1995 1994 1998
Brunswick No. 2 1996 1995 1994 1998
Harris Plant 1996 1995 1994 1998
These contracts are expected to supply the necessary nuclear fuel
to operate Robinson Unit No. 2 through 1995, Brunswick Unit No. 1
through 1995, Brunswick Unit No. 2 through 1996, and the Harris
Plant through 1996. The Company expects to meet its U3O8
requirements through the years shown above from inventory on hand
and amounts received under contract. Although the Company cannot
predict the future availability of uranium and nuclear fuel
services, the Company does not currently expect to have difficulty
obtaining U3O8 and the services necessary for its conversion,
enrichment and fabrication into nuclear fuel for years later than
those shown above. For a discussion of the Company's plans with
respect to spent fuel storage, see ITEM 1, "Nuclear Matters,"
paragraph 2.
5. DOE ENRICHMENT FACILITIES DECONTAMINATION AND
DECOMMISSIONING FUND. Under Title XI of the Energy Policy Act of
1992, Public Law 102-486, Congress established a decontamination
and decommissioning fund for the DOE's gaseous diffusion enrichment
plants. Contributions to this fund will be made by U.S. domestic
utilities who have purchased enrichment services from DOE since
it began sales to non-Department of Defense customers. Each
utility's share of the contributions will be based on that
utility's past purchases of services as a percentage of all
purchases of services by U.S. utilities, with total annual
contributions capped at $150 million per year, indexed to
inflation, and an overall cap of $2.25 billion over 15 years, also
indexed to inflation. The Company made its first payment, totaling
approximately $5.2 million, to the fund on September 30, 1993. At
December 31, 1993, the Company had recorded a liability of $77.7
million representing its estimated share of the contributions and
expects to recover these amounts as a component of fuel cost.
6. PURCHASED POWER. In 1993 the Company purchased
6,375,907 MWh or approximately 13% of its energy requirements and
had available 1,649 MW of firm purchased capacity under contract at
the time of peak load. The Company also had a 100 MW firm capacity
commitment to SCE&G during the peak due to a limited-term sale
agreement for the summers of 1993 and 1994. See ITEM 1,
"Interconnections with Other Systems," paragraph 3. The Company
may acquire purchased power capacity in the future to accommodate
a portion of its system load needs.
OTHER MATTERS
_____________
1. SAFETY INSPECTION REPORTS. On April 3, 1990, the
FERC sent a letter to the Company providing comments on its review
of the Company's Fifth (1987) Independent Consultant's Safety
Inspection Report (required every five years under FERC Regulation
18 CFR Part 12) for the Walters Hydroelectric Project and
requesting the Company to undertake certain supplemental analyses
and investigations regarding the stability of the dam under
extreme and improbable loading conditions. Similar letters were
sent by the FERC on May 30, 1990, with respect to the Company's
Blewett and Tillery Hydroelectric Plants. With the independent
consultant, the Company has begun addressing the issues raised by
the FERC and is working with the FERC to complete investigations
and analyses with respect to each of these matters. While both the
FERC and the Company do not believe that there are any stability
concerns that would be cause for any imminent safety concerns, the
outcome of the analyses and investigations is currently unknown.
Depending on the outcome of the analyses and the FERC's
interpretations, the Company could be required to undertake efforts
to enhance the stability of the dams. The cost and need for
such efforts have not been determined. The Company cannot predict
the outcome of this matter.
2. MARSHALL HYDROELECTRIC PROJECT. On November 21,
1991, the FERC notified the Company that the 5 MW Marshall
Hydroelectric Project is no longer exempt from 18 CFR Part 12,
Subparts C and D, dam safety regulations and that the plant's
regulatory jurisdiction was being transferred from the NCUC to the
FERC. This change resulted from updated dambreak flood studies
which identified the potential impact on new downstream
development, thus indicating the need to reclassify the project
from a "low" to a "high" hazard classification. In accordance with
the change in regulatory jurisdiction, the Company developed an
emergency action plan which meets FERC regulations and guidelines
and engaged its independent consultant to perform a safety
inspection. On April 6, 1992, the consultant's safety inspection
report was submitted to the FERC for approval. Depending on the
outcome of FERC's review of the safety inspection report, the
Company could be required to undertake efforts to enhance the
stability of the Marshall dam and/or powerhouse. The cost and need
for such efforts have not been determined. The Company cannot
predict the outcome of this matter.
<PAGE>
<TABLE>
<CAPTION>
OPERATING STATISTICS
--------------------
Years Ended December 31
_______________________
1993 1992 1991 1990 1989
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Energy supply (millions of kWh)
Generated - coal 25,807 25,196 20,240 19,954 24,383
nuclear 13,691 11,108 16,311 15,464 14,333
hydro 784 881 899 910 978
combustion turbines 84 54 6 34 99
Purchased 7,110 7,343 5,312 5,071 3,822
--------- --------- --------- --------- ---------
Total energy supply (Company share) 47,476 44,582 42,768 41,433 43,615
Power Agency share (a) 2,402 2,232 2,984 2,829 3,464
--------- --------- --------- --------- ---------
Total system energy supply 49,878 46,814 45,752 44,262 47,079
========= ========= ========= ========= =========
Average fuel cost (per million BTU)
Fossil $ 1.75 $ 1.83 $ 1.90 $ 1.86 $ 1.83
Nuclear fuel 0.46 0.45 0.48 0.47 0.49
All fuels 1.28 1.38 1.24 1.23 1.31
Energy sales (millions of kWh)
Residential 11,398 10,490 10,340 9,751 9,943
Commercial 8,548 8,060 7,907 7,538 7,378
Industrial 13,557 13,134 12,403 12,145 12,345
Government and municipal 1,248 1,213 1,181 1,138 1,154
Wholesale-standard rate schedules 6,922 6,414 6,204 6,011 5,814
Power Agency contract requirements 3,505 3,304 2,578 2,556 2,315
Other utilities 327 214 382 652 2,314
--------- --------- --------- --------- ---------
Total energy sales 45,505 42,829 40,995 39,791 41,263
Company uses, losses and unaccounted for 1,971 1,753 1,773 1,642 2,352
--------- --------- --------- --------- ---------
Total energy requirements 47,476 44,582 42,768 41,433 43,615
========= ========= ========= ========= =========
Customers billed
Residential 873,377 856,130 835,206 818,820 804,787
Commercial 151,242 146,858 143,782 140,983 138,841
Industrial 4,825 4,763 4,680 4,733 4,703
Government and municipal 2,214 2,262 2,239 2,212 2,137
Resale 26 26 31 28 31
--------- --------- --------- --------- ---------
Total customers billed 1,031,684 1,010,039 985,938 966,776 950,499
========= ========= ========= ========= =========
Operating revenues (in thousands)
Residential $ 943,697 $ 871,469 $ 862,833 $ 811,429 $ 790,362
Commercial 592,973 560,560 552,341 522,778 489,867
Industrial 744,016 720,413 695,221 681,773 651,375
Government and municipal 78,616 76,838 75,389 72,157 69,952
Wholesale-standard rate schedules 353,921 352,493 332,480 332,151 325,533
Power Agency contract requirements 134,258 140,623 118,498 134,360 124,580
Other utilities 11,232 4,834 12,304 22,433 64,704
Provision for reduction of revenue - - - - (2,026)
Miscellaneous revenue 36,670 39,591 36,689 40,026 41,257
--------- --------- --------- --------- ---------
Total operating revenues $ 2,895,383 $ 2,766,821 $ 2,685,755 $ 2,617,107 $ 2,555,604
========= ========= ========= ========= =========
<PAGE>
Peak demand of firm load (thousands of kW)
System 9,589 9,236 8,960 8,681 8,327
Company 9,107 8,745 8,471 8,134 7,814
Total capability at year-end (thousands of kW) (b)
Fossil plants 6,331 6,331 6,331 6,331 6,331
Nuclear plants 3,064 3,064 3,064 3,105 3,105
Hydro plants 218 218 218 218 218
Purchased 1,289 890 892 785 489
--------- --------- --------- --------- ---------
Total system capability 10,902 10,503 10,505 10,439 10,143
Less Power Agency-owned portion (a) 627 647 638 567 559
--------- --------- --------- --------- ---------
Total Company capability 10,275 9,856 9,867 9,872 9,584
========= ========= ========= ========= =========
______________________
(a) Net of the Company's purchases from Power Agency.
(b) Represents peak generating capability, based on summer peak conditions assuming all generating units are available
for operation. Amounts include capacity under contract with cogenerators, small power producers and other
utilities.
</TABLE>
<PAGE>
[TEXT]
ITEM 2. PROPERTIES
_______ __________
In addition to the major generating facilities listed in
ITEM 1, "Generating Capability," the Company also operates the
following plants:
Plant Location
_____ ________
1. Walters North Carolina
2. Marshall North Carolina
3. Tillery North Carolina
4. Blewett North Carolina
5. Darlington South Carolina
6. Weatherspoon North Carolina
7. Morehead City North Carolina
The Company's sixteen power plants represent a flexible mix of fossil,
nuclear and hydroelectric resources, with a total generating capacity
of 9,613 MW. The Company's strategic geographic location facilitates
purchases and sales of power with many other electric utilities, allowing
the Company to serve its customers more economically and reliably. Major
industries in the Company's service area include textiles, chemicals,
metals, paper, automotive components and electronic machinery and
equipment.
At December 31, 1993, the Company had 5,830 pole miles
of transmission lines including 292 miles of 500 kV and 2,789 miles
of 230 kV lines, and distribution lines of approximately 38,560
pole miles of overhead lines and approximately 7,234 miles of
underground lines. Distribution and transmission substations in
service had a transformer capacity of approximately 34,794 kVA in
2,263 transformers. Distribution line transformers numbered
383,314 with an aggregate 15,264,600 kVA capacity.
Power Agency has acquired undivided ownership interests
of 18.33% in Brunswick Unit Nos. 1 and 2, 12.94% in Roxboro Unit
No. 4 and 16.17% in Harris Unit No. 1 and Mayo Unit No. 1.
Otherwise, the Company has good and marketable title, subject to
the lien of its Mortgage and Deed of Trust, with minor exceptions,
restrictions and reservations in conveyances and defects, which
are of the nature ordinarily found in properties of similar
character and magnitude, to its principal plants and important
units, except certain rights-of-way over private property on which
are located transmission and distribution lines, title to which can
be perfected by condemnation proceedings.
Plant Accounts (including nuclear fuel) -
_______________________________________
During the period January 1, 1989 through December 31, 1993, there was
added to the Company's utility plant accounts $1,827,147,000, there was
retired $469,275,000 of property and there were transfers to other
accounts and adjustments for a net decrease of $290,311,000
resulting in net additions during the period of $1,067,561,000 or
an increase of approximately 12.6%.
ITEM 3. LEGAL PROCEEDINGS
______ _________________
Legal and regulatory proceedings are included in the
discussion of the Company's business in ITEM 1 and incorporated by
reference herein.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
_______ ___________________________________________________
No matters were submitted to a vote of security holders
in the fourth quarter of 1993.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age Recent Business Experience
____ ___ __________________________
Sherwood H. Smith, Jr. 59 Chairman and Chief Executive
Officer, September 1992 to
present; Chairman/President
and Chief Executive Officer,
May 1980 to September 1992.
Member of the Board of
Directors of the Company
since 1971.
William Cavanaugh III 55 President and Chief Operating
Officer, September 1992 to
present; Group President -
Energy Supply, Entergy
Corporation, July 1992;
Chairman, Chief Executive
Officer and Director, System
Energy Resources, Inc., April
1992; Chairman and Chief
Executive Officer, Entergy
Operations, Inc., April 1992;
Senior Vice President, System
Executive - Nuclear, Entergy
Corporation and Entergy
Services, Inc., 1987-August
1992; Executive Vice
President and Chief Nuclear
Officer, Arkansas Power &
Light Company and Louisiana
Power & Light Company,
1990-August 1992; President
and Chief Executive Officer,
System Energy Resources,
Inc., 1986-April 1992;
President and Chief Executive
Officer, Entergy Operations,
Inc., 1990-April 1992. Member
of Board of Directors of
Arkansas Power & Light
Company and Louisiana Power
& Light Company, 1990-August
1992; Member of Board of
Directors of System Fuels,
Inc., 1992-August 1992;
Member of Board of Directors
of System Energy Resources,
Inc., 1986-August 1992;
Member of Board of Directors
of Entergy Operations, Inc.,
1990-August 1992; Member of
Board of Directors of Entergy
Services, Inc., 1987-August
1992. Before joining the
Company, Mr. Cavanaugh held
various senior management and
executive positions during a
23-year career with Entergy
Corporation, an electric
utility holding company
with operations in Arkansas,
Louisiana and Mississippi. Member
of the Board of Directors of the
Company since 1993.
Charles D. Barham, Jr. 63 Executive Vice President and
Chief Financial Officer -
Finance and Administration,
November 1990 to present;
Senior Vice President -
Legal, Planning and
Regulatory Group, July 1987;
Senior Vice President and
General Counsel - Legal and
Regulatory Group, May 1982.
Member of the Board of
Directors of the Company
since 1990.
Lynn W. Eury 57 Executive Vice President -
Power Supply, April 1989 to
present; Senior Vice
President - Operations
Support, June 1986; Senior
Vice President - Fossil
Generation and Power
Transmission Group, August
1983.
William S. Orser 49 Executive Vice President -
Nuclear Generation, April
1993 to present; Executive
Vice President - Nuclear
Generation, Detroit Edison
Company, 1992-April 1993;
Senior Vice President -
Nuclear Generation, Detroit
Edison Company, 1990-1992;
Vice President - Nuclear
Operations, Detroit Edison
Company, 1988-1990. Prior to
1988, Mr. Orser held various
other positions with Detroit
Edison, and with Portland
General Electric Company,
Southern California Edison,
and the U. S. Navy.
James M. Davis, Jr. 57 Senior Vice President, Group
Executive - Fossil Generation
and Power Transmission, June
1986 to present; Senior Vice
President - Operations
Support Group, August 1983.
Norris L. Edge 62 Senior Vice President, Group
Executive - Customer and
Operating Services, May 1990
to present; Vice President -
Rates and Energy Services,
September 1989; Vice
President - Rates and Service
Practices, December 1980.
Richard E. Jones 56 Senior Vice President,
General Counsel and
Secretary, Group Executive -
Legal, Rates, Communications
and Public Affairs, January
1993 to present; Group
Executive - Legal and
Regulatory Services,
November 1990 to January
1993; Vice President,
General Counsel and
Secretary, November 1989;
Vice President and General
Counsel, July 1987; Vice
President, Senior Counsel and
Manager - Legal Department,
May 1982.
Paul S. Bradshaw 56 Vice President and
Controller, March 1980 to
present.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
SHAREHOLDER MATTERS
______ ______________________________________________________
The Company's Common Stock is listed on the New York
and Pacific Stock Exchanges. The high and low sales prices per
share, adjusted for the two-for-one Common Stock split described
below, for the periods indicated, as reported as composite
transactions in The Wall Street Journal, and dividends paid are as
follows:
1992 High Low Dividends Paid
_________________________________________________________________
First Quarter $ 26 15/16 $ 24 9/16 $.395
Second Quarter 27 1/16 24 3/4 .395
Third Quarter 26 5/8 25 .395
Fourth Quarter 28 1/16 25 7/16 .395
1993 High Low Dividends Paid
_________________________________________________________________
First Quarter $ 32 7/8 $ 27 1/16 $.410
Second Quarter 34 31 1/4 .410
Third Quarter 34 1/2 32 1/8 .410
Fourth Quarter 33 3/8 28 1/8 .410
The December 31 closing price of the Company's
Common Stock was $27 3/4 in 1992 and $30 1/8 in 1993.
As of February 28, 1994, the Company had 72,863
holders of record of Common Stock.
In December 1992, the Board of Directors of the
Company authorized a two-for-one split of the Company's Common
Stock. On February 1, 1993, one additional share was issued for
each share outstanding to shareholders of record on January 11,
1993. The number of common shares and average common share data
for all periods reflect the two-for-one stock split.
<PAGE>
<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA
- ------- -----------------------
Years Ended December 31
-----------------------
1993 1992 1991 1990 1989
---- ---- ---- ---- ----
(in thousands except per share data)
<S> <C> <C> <C> <C> <C>
Operating results
Operating revenues $ 2,895,383 $ 2,766,821 $ 2,685,755 $ 2,617,107 $ 2,555,604
Income before cumulative effect of
change in accounting method $ 346,496 $ 379,635 $ 376,974 $ 280,429 $ 376,067
Cumulative effect of change in accounting
for revenues - net of tax - - - 99,929 -
---------- ---------- ---------- ---------- ----------
Net income $ 346,496 $ 379,635 $ 376,974 $ 380,358 $ 376,067
========== ========== ========== ========== ==========
Earnings for common stock $ 336,887 $ 379,045 $ 364,380 $ 361,687 $ 344,588
Per share data (a)
Earnings per common share before cumulative
effect of change in accounting method $ 2.10 $ 2.36 $ 2.27 $ 1.58 $ 2.10
Cumulative effect of change in accounting
for revenues - - - 0.60 -
---------- ---------- ---------- ---------- ----------
Earnings per common share $ 2.10 $ 2.36 $ 2.27 $ 2.18 $ 2.10
========== ========== ========== ========== ==========
Dividends declared per common share $ 1.655 $ 1.595 $ 1.535 $ 1.475 $ 1.430
Financial position
Total assets (b) $ 8,194,018 $ 7,706,201 $ 7,510,587 $ 7,487,443 $ 7,533,529
Capitalization
Common stock equity (c) $ 2,632,116 $ 2,534,025 $ 2,390,676 $ 2,253,680 $ 2,419,899
Preferred stock - redemption not required 143,801 143,801 238,118 238,118 238,118
redemption required, net - - 31,090 101,179 111,412
Long-term debt, net 2,584,903 2,674,823 2,733,693 2,614,904 2,524,176
---------- ---------- ---------- ---------- ----------
Total capitalization $ 5,360,820 $ 5,352,649 $ 5,393,577 $ 5,207,881 $ 5,293,605
========== ========== ========== ========== ==========
________________________
(a) Per share data reflect a two-for-one split of common stock in February 1993. See ITEM 8, Notes to Financial
Statements, Note 3A.
(b) 1993 amounts reflect the implementantion of SFAS No. 109, "Accounting for Income Taxes." Prior period amounts
are not restated for SFAS No. 109. See ITEM 8, Notes to Financial Statements, Note 6.
(c) Reduced by note receivable from Stock Purchase-Savings Plan, net of ESOP adjustment (in thousands): $220,725 in 1993;
$241,573 in 1992; $265,427 in 1991; $286,254 in 1990; and $299,999 in 1989. See ITEM 8, Notes to Financial Statements,
Note 3A.
</TABLE>
<PAGE>
[TEXT]
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
_______ _________________________________________________
The Company's financial condition and results of
operations are affected by numerous factors, including the timing
and amount of rate relief, the extent of sales growth and the level
of operating costs. The following discussion and analysis should
be considered in conjunction with the relevant Sections of ITEM 1,
"Selected Financial Data" in ITEM 6, and the Company's financial
statements appearing in ITEM 8.
RESULTS OF OPERATIONS
_____________________
Revenues
________
The increase in revenues from 1991 to 1993 is
primarily the result of an increase in energy sales of 4.5%
from 1991 to 1992 and 6.2% from 1992 to 1993. During this period,
revenues did not increase proportionately with energy sales due to
a decline in the fuel factors included in rates and due to lower
demand-related charges for certain customer classes.
Operating Expenses
__________________
Fuel for generation increased slightly in 1993 as
compared to 1992. An 8% increase in generation was offset somewhat
by a decrease in the cost of fossil fuel and by increased nuclear
generation. For 1992 as compared to 1991, fuel for generation
increased primarily as a result of changes in the generation mix.
Fossil generation increased and nuclear generation decreased in
1992 primarily due to the outage at the Brunswick Plant (see
Brunswick Plant).
A portion of the change in deferred fuel from 1992 to
1993 reflects settlement agreements reached in 1993 between the
Company and regulators in the North Carolina and South Carolina
retail jurisdictions. As part of these settlements, the Company
agreed to forgo recovery of a total of $41.1 million of deferred
fuel expenses (see Brunswick Plant). Excluding the effect of these
settlements, the deferred fuel credit decreased in 1993 due to
lower fuel costs. From 1991 to 1992, the deferred fuel credit
increased as a result of higher fuel costs associated with the
increased use of fossil fuel due to lower nuclear generation.
The deferred fuel line item reflects fuel costs that
are deferred through deferred fuel clauses required by the
Company's regulators. These clauses allow the Company to
recover fuel costs and fuel-related purchased power costs through
the fuel component of customer rates. Any differences between
actual fuel costs incurred and the fuel component of customer rates
are reflected in deferred fuel. Customer rates are adjusted
periodically to incorporate the approved deferrals. As a result,
except for fuel settlements such as those discussed above, net
income is not impacted significantly by fluctuations in fuel costs.
The increase in purchased power for 1993 is primarily
attributable to an agreement under which the Company began
purchasing 400 megawatts of generating capacity from Duke Power
Company in July 1993. Purchases under this agreement totaled
approximately $37 million for 1993. In addition, purchases from
North Carolina Eastern Municipal Power Agency (Power Agency)
increased $14 million due to the increased buyback provisions of
the Company's 1993 agreement with Power Agency (see Legal Matters).
The fuel-related portion of costs associated with these agreements
is recoverable through the Company's fuel clauses and does not,
therefore, impact net income. Partially offsetting the 1993
purchases from Duke Power Company and increased purchases
from Power Agency were decreases in purchases from other
utilities. Purchased power increased in 1992 as compared to 1991
due to purchases of replacement power from other utilities and
additional purchases of power from cogenerators.
Other operating expenses increased in 1993 as compared
to 1992 due to 1) the Brunswick Plant outage, 2) the recognition of
increased expense for postretirement benefits other than pensions
due to new accounting requirements and 3) adjustments made in 1992.
Other operating expenses decreased in 1992 as compared to 1991
due to 1992 adjustments that were made to certain accrual and
asset balances as a result of more current information at that
time. These adjustments more than offset the 1992 increases in
other operating expenses that resulted from the Brunswick Plant
outage.
Maintenance expense decreased $13 million in 1993 due
to the capitalization of costs associated with plant modifications
as compared to the prior year. Maintenance expense increased from
1991 to 1992 primarily due to costs associated with the Brunswick
Plant outage.
The Company began amortizing costs associated with two
significant software projects in 1993, which contributed to a
portion of the increase in depreciation and amortization as
compared to 1992.
The fluctuation in Harris Plant deferred costs from
1991 to 1993 is primarily due to an adjustment made in 1992 in
order to better match these costs with the associated revenue
recovery. This adjustment decreased 1992 operating expenses by
$13.4 million, net of tax. Contributing to the increase in 1993
were adjustments related to the settlement between North Carolina
Electric Membership Corporation (NCEMC) and the Company (see Legal
Matters).
Other Income
____________
The increase in Harris Plant carrying costs for 1993
is primarily related to the Company's settlement with NCEMC.
The Harris Plant disallowance - Power Agency line item
reflects a write-off recorded as a result of the 1993 settlement
with Power Agency (see Legal Matters).
The increase in interest income for 1993 is primarily
due to the Company's settlement agreement with Westinghouse
Electric Corporation (see Legal Matters).
Interest Charges
________________
Interest charges on long-term debt decreased in 1993
and 1992 as compared to the prior periods due to long-term debt
refinancings that allowed the Company to take advantage of lower
interest rates and decreases in interest rates on the Company's
variable rate debt. Other interest charges also declined in 1992 as
compared to 1991 due to a decrease in interest expense related to
certain income tax liabilities.
LIQUIDITY AND CAPITAL RESOURCES
_______________________________
Capital Requirements
____________________
Estimated capital requirements for the period 1994
through 1996 are influenced by construction expenditures that will
be made primarily to upgrade existing generating facilities and to
add transmission and distribution facilities to meet customer
growth. The Company's capital requirements for those years are
reflected below (in millions).
1994 1995 1996
____ ____ ____
Construction expenditures. . . . . . $386 $476 $540
Nuclear fuel expenditures. . . . . . 25 79 94
AFUDC. . . . . . . . . . . . . . . . (18) (29) (40)
Mandatory redemptions of
long-term debt. . . . . . . . . . . 50 275 55
____ ____ ____
Total. . . . . . . . . . . . . $443 $801 $649
==== ==== ====
The table above includes Clean Air Act requirement
expenditures of approximately $79 million and generating facility
addition expenditures of approximately $248 million. A portion of
the generating facility addition expenditures will be used to
construct three new combustion turbines at the Company's Darlington
County Electric Plant. These units, which are intended for use
during periods of high demand, have a combined generating capacity
of approximately 225 megawatts and are scheduled to be placed in
service in 1996. The total cost of these combustion turbines is
expected to approximate $93 million.
The 1990 amendments to the Clean Air Act (Act) require substantial
reductions in sulfur dioxide and nitrogen oxides emissions from
fossil-fueled electric generating plants. The Company is not required
to take action to comply with the Act's Phase I requirements, which must
be met by January 1, 1995. Phase II of the Act, which contains more
stringent provisions, will become effective January 1, 2000. To reduce
sulfur dioxide emissions as required by Phase II, the Company will
modify equipment to allow certain of the Company's plants to
burn lower sulfur coal, and the Company is planning for the installation
of scrubbers. Installation of additional equipment will also be
necessary to reduce nitrogen oxides emissions. The Company anticipates
that it will be able to delay the installation and operation of
scrubbers until 2005 by purchasing sulfur dioxide emission allowances.
Each sulfur dioxide emission allowance, issued by the Environmental
Protection Agency (EPA), will allow a utility to emit one ton of sulfur
dioxide. In 1993, the Company purchased emission allowances under the
EPA's emission allowance trading program.
The Company estimates that the total capital cost to comply with Phase
II of the Act may approximate $340 million during the period 1994
through 1999 and an additional $460 million during the period 2000
through 2005. These estimates, for installation or modification of
equipment, are in nominal dollars (undiscounted future amounts expected
to be expended). The required modifications and additions are expected
to increase operating and maintenance costs by a total of $20 million
for the period 1994 through 1999, $48 million for the period 2000
through 2004 and by $42 million annually beginning in 2005. Actual
plans for compliance with the Act's requirements have not been
finalized, and the amount required for capital expenditures and for
increased operating and maintenance expenditures cannot be determined
with certainty at this time. The financial impact of the additional
expenditures will be dependent on future ratemaking treatment. The
North Carolina Utilities Commission (NCUC) and the South Carolina Public
Service Commission (SCPSC) are currently allowing the Company to accrue
carrying charges on its investment in emission allowances.
The Company has two major agreements for the purchase of
power from other utilities. The first agreement provides for the
purchase of 250 megawatts of capacity from Indiana Michigan Power
Company's Rockport Unit No. 2. Purchases under this agreement began
in January 1990 and will continue for twenty years. The estimated
minimum annual payment for these power purchases is approximately
$30 million, which represents capital-related capacity costs. In
1993, purchases under this agreement totaled $60.2 million,
including transmission use charges. The second agreement is with
Duke Power Company for the purchase of 400 megawatts of firm
capacity. These purchases began in July 1993 and will continue for
six years. The estimated minimum annual payment for these
power purchases is approximately $43 million, which represents
capital-related capacity costs. Purchases under this
agreement, including transmission use charges, totaled $37.1
million in 1993. The agreement with Duke Power Company has been
filed with the Federal Energy Regulatory Commission (FERC) for
approval. The Company cannot predict the outcome of this matter.
Cash Flow and Financing
_______________________
The Company generated cash from operations of $845.6 million
in 1993, $776.8 million in 1992 and $596.0 million in 1991. Cash
from operations in 1993 and 1992 reflects normal operating cash
flow levels, while the lower level in 1991 was due to the payment
of certain income tax liabilities in that year.
Net cash used in investing activities is generally affected
by capital expenditures, which include replacement or expansion of
existing facilities and construction to comply with pollution
control laws and regulations. In 1993, capital expenditures
increased primarily due to work performed at the Brunswick Plant.
The Company refinanced numerous issues of long-term debt in
1992 and 1993. These refinancings, combined with a decrease in
interest rates on the Company's variable rate debt, have reduced
the Company's average cost of long-term debt from 8.04% to 6.85%
during this period.
During 1993, the Company issued $624.5 million in long-term
debt. The proceeds of these issuances, along with cash from
operations, were primarily used to redeem or retire $774.5 million
of long-term debt. The Company does not expect to have external
funding requirements in 1994 or 1996 due to the low level of
mandatory long-term debt redemptions in those years. External
funding requirements, which do not include early redemptions of
long-term debt or redemptions of preferred stock, are expected to
approximate $300 million in 1995. These funds will be required for
construction, mandatory redemptions of long-term debt and general
corporate purposes, including the repayment of short-term debt.
As of December 31, 1993, the Company had on file with the
Securities and Exchange Commission (SEC) shelf registration
statements enabling the Company to issue an aggregate of $600
million principal amount of first mortgage bonds. In January 1994,
the Company issued $150 million principal amount of First Mortgage
Bonds, 5 7/8% Series, due January 15, 2004, which reduced issuances
available under these shelf registration statements. The Company
also has entered into a distribution agreement with respect to the
possible future sale of an aggregate amount of up to $200 million
principal amount of first mortgage bonds designated as secured
medium-term notes, of which $110 million remained to be issued as
of December 31, 1993. In addition, the Company can issue up to
$180 million of additional preferred stock under a shelf
registration statement on file with the SEC.
The Company's ability to issue first mortgage bonds and
preferred stock is subject to earnings and other tests as stated in
certain provisions of its mortgage, as supplemented, and charter.
At December 31, 1993, the Company had the ability to issue an
additional $3.3 billion in first mortgage bonds and an additional
21.9 million shares of preferred stock at an assumed price of $100
per share and a $7.00 annual dividend rate. The Company also has
ten million authorized preference stock shares available for
issuance that are not subject to an earnings test.
The Company's access to outside capital depends on its
ability to maintain its credit ratings. The Company's first
mortgage bonds are currently rated A2 by Moody's Investors
Service, A by Standard & Poors and A+ by Duff & Phelps.
In order to provide flexibility in the timing and amounts
of long-term financing, the Company uses short-term financing in
the form of commercial paper backed by revolving credit agreements.
These revolving credit agreements amount to $208.1 million. The
Company had $76 million of commercial paper outstanding at December
31, 1993, which Standard & Poors and Moody's Investors Service have
rated A-1 and P-1, respectively.
The amount and timing of future sales of Company securities
will depend upon market conditions and the specific needs of the
Company. The Company may from time to time sell securities beyond
the amount needed to meet capital requirements in order to allow for
the early redemption of outstanding issues of long-term debt, the
redemption of preferred stock, the reduction of short-term debt or
for other corporate purposes.
OTHER MATTERS
_____________
Brunswick Plant
_______________
In April 1992, both units at the Company's Brunswick Plant
were taken out of service in order for the Company to address
anchor bolt deficiencies and related wall construction issues in
the diesel generator building. During the outage, in addition to
resolving these issues, the Company conducted detailed inspections
and engineering evaluations of the Plant's miscellaneous steel,
performed necessary corrective and preventive maintenance and made
certain modifications.
In the spring of 1993, an intensive on-site review of
Brunswick Unit No. 2 was conducted by a Nuclear Regulatory
Commission (NRC) operational readiness assessment team, which
concluded that the depth and capability of the Brunswick staff, the
organizational structures and in-place programs were adequate to
support Unit No. 2 restart and operation. The Company returned
Unit No. 2 to service in May 1993. In late December 1993,
Unit No. 2 set a new continuous-run record for that unit of more
than 219 days.
In July 1993, cracks were discovered in the Brunswick Unit No. 1
reactor vessel shroud during inspections made as part of refueling
activities performed during the outage. The Company
conducted intensive ultrasonic testing and physical sample
inspections of the cracks. The results of this investigation
provided data used to develop new stiffening braces to ensure that
the shroud will continue to perform its design function. Shroud
modifications were completed in late December 1993. Costs
associated with the shroud repairs were not material to the results
of operations of the Company. The Company commenced startup of
Unit No. 1 on February 1, 1994 under a gradual power ascension
startup plan. This power ascension plan was completed 27 days
ahead of schedule when Unit No. 1 was returned to normal operation
on February 23, 1994, after successfully completing extensive
startup testing. Additional shroud inspections may be conducted
during future refueling outages to identify and monitor other minor
cracking in the shroud. The Company cannot predict the outcome
of this matter.
In July 1993, the Company also determined that the Brunswick Unit No. 2
shroud has minor crack indications, which do not compromise the safety
or operation of the Unit. Shroud modifications, similar to those
performed on Unit No. 1, will be undertaken on Unit No. 2 during the
spring 1994 refueling outage. The Company does not expect that costs
associated with the shroud modifications will be material to the results
of operations of the Company.
In December 1993, the NRC issued its latest Systematic
Assessment of Licensee Performance report for the Brunswick Plant.
The report rated Brunswick's plant operations and plant support as
"superior," and the Plant's maintenance and engineering as "good."
The NRC, in both the report and at a public meeting, recognized
significant improvements made at the Plant.
In 1993, two private organizations, the National Whistleblower
Center and the Coastal Alliance for a Safe Environment, and an
individual filed a petition with the NRC alleging that the Company
was aware of the shroud cracks as early as 1984 and engaged in
criminal activities to conceal its knowledge of the cracks. The
petitioners requested that the NRC require the Company to state
whether it knew about the cracks in 1984 and determine
whether the Company has engaged in criminal wrongdoing. To date,
the petitioners have failed to provide the Company with any
evidence substantiating their claims. Additionally, the Company
conducted a technical review concerning this matter, which did not
reveal any evidence that substantiates the petitioners' claims. The
results of this technical review were submitted to the NRC in
November 1993. Although the Company cannot predict the
outcome of this matter, it believes the allegations contained in
the petition are without merit.
The Company, the Public Staff of the NCUC, the Attorney
General of the State of North Carolina and Carolina Industrial
Group for Fair Utility Rates II entered into an agreement on July
28, 1993, that resolved all issues related to the Brunswick Plant
outage on or before the date of the agreement, avoided higher fuel
charges to the Company's customers and settled the Company's annual
fuel adjustment proceeding. The Company had $31.2 million in fuel
expenses for the twelve-month period ended March 31, 1993, which
had not been recovered from North Carolina customers through the
Company's rates. As part of the agreement, the Company agreed to
forgo recovering $25.5 million of these fuel expenses and to
recover the remaining $5.7 million through rates over a
twelve-month period beginning September 1993. That $5.7 million
is subject to refund at the end of three years if the Brunswick
Plant does not achieve a specified operating performance level.
Additionally, the Company agreed that if the Brunswick Plant's
performance for the three-year period ending March 31, 1996, does
not achieve a specified operating performance level, the Company
could lose up to $10 million in additional fuel expenses. The
forgone fuel expense recovery of $25.5 million reduced the
Company's 1993 earnings by approximately $.10 per common share.
In the South Carolina retail jurisdiction, the Company, the
Staff of the SCPSC, Nucor Steel and the Consumer Advocate for the
State of South Carolina, entered into an agreement in 1993 to
settle the fall SCPSC fuel proceeding. The settlement resolved all
issues related to fuel costs incurred by the Brunswick Plant
through June 30, 1993, and avoided higher fuel charges to the
Company's customers. Pursuant to the terms of the settlement, the
Company agreed to forgo recovery of a total of $15.6 million in
fuel expenses. The forgone fuel expense recovery of $15.6 million
reduced the Company's 1993 earnings by approximately $.06 per
common share.
The NRC, the NCUC and the SCPSC will continue to review the
Company's activities at the Brunswick Plant. Except as noted, the
Company cannot predict the extent to which these and other actions
may impact its ability to recover costs associated with this
outage.
Environmental Matters
_____________________
The Company is subject to federal, state and local regulations
addressing air and water quality, hazardous and solid waste
management and other environmental matters.
There are several manufactured gas plant (MGP) sites to
which the Company and certain entities that were later merged into
the Company may have had some connection. In this regard, the
Company is participating in the North Carolina MGP Group (Group),
a group of entities alleged to be former owners or operators of MGP
sites. The Group was formed in response to an initiative launched
by the North Carolina Department of Environment, Health and Natural
Resources, Division of Solid Waste Management (DSWM), to encourage
the voluntary assessment and, where necessary, the remediation of
MGP sites. The Group and DSWM have entered into a
Memorandum of Understanding relative to the establishment of a
uniform program and framework for addressing MGP sites for which
DSWM has contended that members of the Group have potential
responsibility. It is anticipated that the investigation and
remediation of specific MGP sites will be addressed pursuant to one
or more Administrative Orders on Consent between DSWM and
individual potentially responsible parties. In addition, a
current owner of property that was the site of one MGP owned by
Tidewater Power Company, which merged into the Company in 1952, and
the Company have entered into an agreement to share the cost of
investigation and remediation of this site. Due to the lack of
information with respect to the operation of MGP sites and the
uncertainty concerning questions of liability and potential
environmental harm, the extent and cost of required remedial
action, if any, and the extent to which liability may be
asserted against the Company or against others are not currently
determinable. The Company cannot predict the outcome of these matters or
the extent to which other former MGP sites may become the subject of
inquiry.
The Company has been notified by regulators of its
involvement or potential involvement in certain sites, other
than MGP sites, that may require investigation and/or remedial
action. Although the Company cannot predict the outcome of these
matters, it does not anticipate that costs associated with
these other sites will be material to the results of operations of the
Company.
Nuclear Decommissioning
_______________________
In the Company's retail jurisdictions, provisions for nuclear
decommissioning costs are approved by the NCUC and the SCPSC and
are based on site-specific estimates that included the costs for
removal of all radioactive and other structures at the site. Cost
recovery is based on an internal modified sinking fund methodology
assuming 30-year delayed dismantlement decommissioning. In the
wholesale jurisdiction, the provisions for nuclear decommissioning
costs are based on amounts agreed upon in applicable rate
settlements. Accumulated nuclear decommissioning cost provisions
included in accumulated depreciation were $221.6 million at
December 31, 1993, and $186.4 million at December 31, 1992.
Pursuant to regulations of the NRC, the Company is required
to provide financial assurance that funds will be available for
decommissioning. In this regard, the Company filed decommissioning
plans with the NRC and, in 1991, began depositing amounts currently
collected in rates in an external decommissioning trust. The
Company is required to increase external funding to the
NRC-prescribed minimum no later than January 1, 1996. This NRC-
prescribed minimum exceeds amounts currently collected in rates.
In future rate filings, the Company will request rate recovery
based on site-specific estimates for prompt dismantlement
decommissioning. The requested rate recovery will also include
funding plans that assume external funding of, at least, the
NRC-prescribed minimum. The financial impact on the Company will
depend on future ratemaking treatment. The NCUC and SCPSC have
allowed other utilities to recover costs based on site-specific
estimates for prompt dismantlement decommissioning and funding
plans similar to those the Company intends to use.
The Company's most recent site-specific estimates of
decommissioning costs were developed in 1993 and are based on
prompt dismantlement decommissioning, which reflects the cost of
removal of all radioactive and other structures currently at the site.
These estimates, in 1993 dollars, are $257.7 million for Robinson Unit
No. 2, $284.3 million for the Harris Plant, $235.4 million for
Brunswick Unit No. 1 and $221.4 million for Brunswick Unit No. 2.
These estimates are subject to change based on a variety of
factors including, but not limited to, inflation, changes in
technology applicable to nuclear decommissioning and changes in
federal, state or local regulations. The cost estimates exclude the
portion attributable to Power Agency, which holds an undivided
ownership interest in certain of the Company's generating
facilities. To the extent of its ownership interests, Power Agency
is responsible for satisfying the NRC's financial assurance
requirements for decommissioning costs.
Legal Matters
_____________
In 1993, the Company and Power Agency entered into an
agreement to restructure portions of their contracts covering power
supplies and jointly-owned interests in several of the Company's
generating units. Under terms of this agreement, the Company is
increasing the amount of capacity and energy purchased from Power
Agency's ownership interest in the Harris Plant. Also, the buyback
period was extended six years through 2007. In addition,
pursuant to the agreement, a portion of the Company's Harris
Plant cost will not be recoverable through sales of supplemental
power to Power Agency. As a result, the Company recorded a
write-off in 1993 of approximately $14.7 million, net of tax, or
$.09 per common share. As part of this agreement, Power Agency
agreed to the dismissal with prejudice of the Complaint that it
filed against the Company in July 1988, which claimed that the
Company failed to disclose alleged design, management and other
problems at the Harris Plant in connection with the sale of
ownership interest to Power Agency. Under terms of the agreement,
Power Agency also agreed to withdraw the demand made in a 1993
letter that the Company bear any costs incurred in the restoration,
repair or replacement of property at the Brunswick Plant during the
current outage. The agreement has been filed with the
FERC for approval of the provisions that are subject to the FERC's
jurisdiction. The Company cannot predict the outcome
of this matter.
In 1991, NCEMC and one of its members filed a Complaint
with the FERC alleging that the Company's wholesale rates and fuel
clause billings were too high and requesting that the Company
provide its load signal to NCEMC. The Company settled with NCEMC on
all issues, and the settlement agreement was approved by the
FERC in 1993. The agreement provides for the continuation of
existing wholesale rate levels and resolves the wholesale fuel
clause billing issue through June 30, 1993. The impact of the
settlement totaled approximately $8 million, net of tax, and
decreased the Company's 1993 earnings by $.05 per common share.
The Company and Westinghouse Electric Corporation reached
an agreement that settles all issues related to the Harris and
Robinson Plants' steam generators, as well as certain issues
related to Harris Unit Nos. 2, 3 and 4 cancellation costs. The
effect of the agreement on the Company's results of operations,
approximately $17.3 million, net of tax, increased the Company's
1993 earnings by $.11 per common share. The remaining aspects of
the agreement will not have a material impact on future results of
operations of the Company.
In 1989, Power Agency delivered to the Company a Notice of
Intention to Arbitrate certain disputed matters related to Power
Agency's use of capacity and energy from the South Carolina Public
Service Authority (Santee Cooper). In 1990, an arbitration judge
ruled in favor of the Company on the most significant issues of
contention between the Company and Power Agency. In 1991, Power
Agency filed a Complaint at the FERC alleging that the
Company had refused to agree to just and reasonable terms and
conditions for power coordination agreements for Power Agency's
purchase of firm capacity and energy from Santee Cooper
beginning January 1, 1994 and for Power Agency's use of a
combustion turbine electric generating project planned at that time
to be placed into service by Power Agency in June 1995. In 1993,
Power Agency and the Company entered into an agreement
in principle that resolves all remaining issues in this proceeding.
An interim agreement between the parties has been approved by the
FERC. The parties continue to negotiate the details of a final
settlement. The Company cannot predict the outcome of this matter.
In 1973, the Company filed an application with the FERC for a new
long-term license for its Walters Hydroelectric Plant. NCEMC filed a
competing application in 1974. Since the expiration of the initial
license in 1976, the Company has continued to operate the Walters
Hydroelectric Plant under an annual license issued by the FERC. Loss of
the license would result in significant additional costs to the Company;
however, the financial impact would be dependent on future ratemaking
treatment. In 1993, the Company and NCEMC filed a settlement agreement
with the FERC. Under terms of the agreement, NCEMC will withdraw its
competing request for a license for the Walters Hydroelectric Plant.
The agreement also resolves issues related to NCEMC's objections to the
Company's purchase power contract with Duke Power Company and NCEMC's
interest in transferring base load capacity from its ownership in Duke
Power Company's Catawba Nuclear Station. The Company cannot predict the
outcome of this matter.
In 1993, the Company and NCEMC also filed with the FERC a
30-year Power Coordination Agreement and an Interchange Agreement.
These agreements set forth explicitly the future relationship between
the parties and establish a framework under which they will operate.
The Power Coordination Agreement provides NCEMC the option to gradually
assume responsibility for a portion of its load, subject to
agreed-upon limits, thereby enabling the Company to further enhance
its planning for generation and transmission property. The Company
will sell electricity and provide necessary transmission and
coordinating services to NCEMC subject to rates that will benefit
the Company and its customers. The Company cannot predict the
outcome of this matter.
Competition
___________
In 1992, the Energy Policy Act of 1992 (Energy Act) was
signed into law. The Energy Act addresses a wide range of energy
issues, including several matters affecting bulk power competition
in the electric utility industry. It creates exemptions from
regulation under the Public Utility Holding Company Act of 1935 for
persons or corporations that own and/or operate in the United
States certain generating and interconnecting transmission
facilities dedicated exclusively to wholesale sales, thereby
encouraging the participation of utility affiliates, independent
power producers and other non-utility participants in the
development of wholesale power generation. In addition, the Energy
Act confers expanded authority upon the FERC to issue orders
requiring public utilities, such as the Company, to transmit power
and energy to or for wholesale purchasers and sellers, and to
require public utilities to enlarge or construct additional
transmission capacity to provide these services. Implementation of
portions of this legislation through rulemaking is in progress at
the FERC. The Energy Act also requires or facilitates
numerous initiatives to increase energy efficiency at federal and
other facilities. The Company is unable to predict the ultimate
impact the Energy Act will have on its operations. When fully
implemented, the Energy Act could impact the Company's load
forecasts and plans for power supply to the extent additional
generation is facilitated by the Energy Act, current wholesale
customers elect to purchase from other suppliers or new
opportunities are created for the Company to expand its wholesale
load.
The possible migration of some of the Company's load has
created greater planning uncertainty and risks for the Company. The
Company has been addressing these risks by negotiating long-term
contracts with its customers, which allow the Company flexibility
in managing its load and efficiently planning its future resource
requirements. In this regard, in 1993 the Company signed a
significant long-term agreement with NCEMC, which represents 17
wholesale customers, and restructured its agreement with Power
Agency. Also in 1993, the Company signed power supply agreements
with a wholesale municipality and a wholesale electric membership
corporation. In 1994, another wholesale customer entered into a new
contract with the Company. In the industrial sector, the Company
continues its efforts on a number of programs designed to retain
and expand existing load and to attract new business to its
service territory.
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
_______ ___________________________________________
The following financial statements, supplementary data
and financial statement schedules are included herein:
Independent Auditors' Report
Financial Statements:
Statements of Income for the Years Ended
December 31, 1993, 1992 and 1991
Statements of Cash Flows for the Years
Ended December 31, 1993, 1992 and 1991
Balance Sheets as of December 31, 1993 and 1992
Statements of Retained Earnings for the
Years Ended December 31, 1993, 1992 and 1991
Schedules of Capitalization as of
December 31, 1993 and 1992
Notes to Financial Statements
Quarterly Financial Data
Financial Statement Schedules for the Years Ended
December 31, 1993, 1992 and 1991:
V - Utility Plant
VI - Accumulated Provision for Depreciation
and Amortization of Electric Utility
Plant
VIII - Reserves
IX - Short-term Borrowings
X - Supplementary Income Statement
Information
All other schedules have been omitted as not
applicable or not required or because the information
required to be shown is included in the Financial Statements or
the accompanying Notes to Financial Statements.
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of
Carolina Power & Light Company:
We have audited the accompanying balance sheets and schedules of
capitalization of Carolina Power & Light Company as of December 31,
1993 and 1992, and the related statements of income, retained
earnings, and cash flows for each of the three years in the period
ended December 31, 1993. Our audits also included the financial
statement schedules listed in the Index at Item 8. These financial
statements and financial statement schedules are the responsibility
of the Company's management. Our responsibility is to express an
opinion on the financial statements and financial statement
schedules 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 financial statements present fairly, in all
material respects, the financial position of the Company at
December 31, 1993 and 1992, and the results of its operations and
its cash flows for each of the three years in the period ended
December 31, 1993 in conformity with generally accepted accounting
principles. Also, in our opinion, such financial statement
schedules, when considered in relation to the basic financial
statements taken as a whole, present fairly in all material
respects the information set forth therein.
We have also previously audited, in accordance with generally
accepted auditing standards, the balance sheets and schedules of
capitalization as of December 31, 1991, 1990, and 1989, and the
related statements of income, retained earnings and cash flows for
the years ended December 31, 1990 and 1989 (none of which are
presented herein); and we expressed unqualified opinions on those
financial statements. In our opinion, the information set forth in
the selected financial data for each of the five years in the
period ended December 31, 1993, appearing at Item 6, is fairly
presented in all material respects in relation to the financial
statements from which it has been derived.
As discussed in Note 6 to the financial statements, in 1993 the
Company changed its method of accounting for income taxes to
conform with Statement of Financial Accounting Standards
No. 109.
/s/ DELOITTE & TOUCHE
Raleigh, North Carolina
February 14, 1994
<PAGE>
<TABLE>
<CAPTION> Carolina Power & Light Company
- ------------------------------------------------------------------------------------------------------
Statements of Income
Years ended December 31
1993 1992 1991
<S> <C> <C> <C>
Operating Revenues................................................. $2,895,383 $2,766,821 $2,685,755
---------- ---------- ----------
Operating Expenses
Operation - fuel for generation.................................. 524,366 518,941 471,199
deferred fuel cost (credit), net (Note 9C)........... 27,364 (49,892) 3,658
purchased power...................................... 368,092 339,325 287,342
other................................................ 498,333 427,423 434,988
Maintenance...................................................... 235,449 247,966 179,822
Depreciation and amortization.................................... 413,646 398,361 392,444
Taxes other than on income....................................... 142,871 131,897 127,205
Income tax expense (Note 6)...................................... 189,317 207,328 202,047
Harris Plant deferred costs, net (Note 6)........................ 27,575 3,512 18,331
---------- ---------- ----------
Total operating expenses.................................... 2,427,013 2,224,861 2,117,036
---------- ---------- ----------
Operating Income................................................... 468,370 541,960 568,719
---------- ---------- ----------
Other Income (Expense)
Allowance for equity funds used during construction.............. 8,999 7,932 4,539
Income tax expense (Note 6)...................................... (392) (5,885) (9,686)
Harris Plant carrying costs (Note 6)............................. 27,143 10,774 8,559
Harris Plant disallowance - Power Agency (Note 9C)............... (20,645) - -
Interest income.................................................. 36,196 24,755 29,577
Other income, net................................................ 42,465 35,718 37,627
---------- ---------- ----------
Total other income.......................................... 93,766 73,294 70,616
---------- ---------- ----------
Income Before Interest Charges..................................... 562,136 615,254 639,335
---------- ---------- ----------
Interest Charges
Long-term debt................................................... 205,182 223,158 233,268
Other interest charges........................................... 16,419 15,717 33,352
Allowance for borrowed funds used during construction (Note 6)... (5,961) (3,256) (4,259)
---------- ---------- ----------
Net interest charges........................................ 215,640 235,619 262,361
---------- ---------- ----------
Net Income......................................................... 346,496 379,635 376,974
Preferred Stock Dividend Requirements.............................. (9,609) (14,798) (26,265)
Tax Benefit of ESOP Dividends (Note 6)............................. - 14,208 13,671
---------- ---------- ----------
Earnings for Common Stock ......................................... $ 336,887 $ 379,045 $ 364,380
========== ========== ==========
Average Common Shares Outstanding (Note 3A)........................ 160,737 160,737 160,737
========== ========== ==========
Earnings per Common Share (Note 3A)................................ $ 2.10 $ 2.36 $ 2.27
========== ========== ==========
Dividends Declared per Common Share (Note 3A)...................... $ 1.655 $ 1.595 $ 1.535
========== ========== ==========
_________________________________________________________________________________________________________
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Carolina Power & Light Company
Statements of Cash Flows
Years ended December 31
1993 1992 1991
(in thousands)
<S> <C> <C> <C>
Operating Activities
Net income.................................................. $ 346,496 $ 379,635 $ 376,974
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization............................. 460,094 432,554 441,240
Harris Plant deferred costs............................... 432 (7,262) 9,773
Harris Plant disallowance - Power Agency (Note 9C)........ 20,645 - -
Deferred income taxes..................................... 71,352 100,486 12,523
Investment tax credit adjustments......................... (12,806) (11,083) (34,543)
Allowance for equity funds used during construction....... (8,999) (7,932) (4,539)
Deferred fuel cost (credit)............................... 27,364 (49,892) 3,658
Uncollectible accounts expense............................ 4,864 3,723 4,136
Net increase in receivables, inventories and prepaid
expenses................................................ (12,667) (92,057) (105,715)
Net increase (decrease) in payables and accrued expenses.. (60,903) 72,036 (103,295)
Miscellaneous............................................. 9,772 (43,427) (4,261)
-------- -------- ---------
Net cash provided by operating activities............... 845,644 776,781 595,951
-------- -------- ---------
Investing Activities
Gross property additions.................................... (341,122) (262,434) (256,411)
Nuclear fuel additions...................................... (48,001) (71,388) (40,223)
Contributions to external decommissioning trust............. (20,878) (14,534) (6,889)
Contributions to retiree benefit trusts..................... (3,750) (6,667) (10,833)
Loan payments from SPSP Trustee............................. 39,330 46,695 47,291
Loans to SPSP Trustee ...................................... (18,196) (16,807) (15,419)
Allowance for equity funds used during construction......... 8,999 7,932 4,539
-------- -------- ---------
Net cash used in investing activities................... (383,618) (317,203) (277,945)
-------- -------- ---------
Financing Activities
Proceeds from issuance of long-term debt.................... 582,030 673,752 319,629
Net decrease in pollution control bond escrow............... 2,127 9,161 2,358
Net increase (decrease) in short-term notes payable
(maturity less than 90 days).............................. 29,200 (16,139) (7,071)
Retirement of long-term debt................................ (790,376) (745,405) (253,429)
Retirement of preferred stock............................... - (134,625) (75,563)
Dividends paid on common stock.............................. (262,749) (253,964) (244,320)
Dividends paid on preferred stock........................... (9,474) (19,968) (27,808)
-------- -------- ---------
Net cash used in financing activities................... (449,242) (487,188) (286,204)
-------- -------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents.......... 12,784 (27,610) 31,802
Cash and Cash Equivalents at Beginning of Year................ 10,823 38,433 6,631
-------- -------- ---------
Cash and Cash Equivalents at End of Year...................... $ 23,607 $ 10,823 $ 38,433
======== ======== =========
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest........................ $ 218,801 $ 232,527 $ 316,437
income taxes.................... $ 113,523 $ 74,960 $ 263,799
____________________________________________________________________________________________________
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Carolina Power & Light Company
Balance Sheets
Assets
December 31
1993 1992
(in thousands)
<S> <C> <C>
Electric Utility Plant
Electric utility plant in service....................... $ 8,789,518 $ 8,578,453
Accumulated depreciation................................ (2,897,832) (2,632,577)
------------ ------------
Electric utility plant in service, net............... 5,891,686 5,945,876
Held for future use..................................... 13,300 13,385
Construction work in progress........................... 309,713 251,238
Nuclear fuel, net of amortization....................... 217,488 215,079
------------ ------------
Total electric utility plant, net.................... 6,432,187 6,425,578
------------ ------------
Current Assets
Cash and cash equivalents............................... 23,607 10,823
Accounts receivable..................................... 321,309 312,493
Fuel.................................................... 62,029 105,131
Materials and supplies.................................. 111,052 103,941
Deferred fuel cost...................................... 9,827 37,191
Prepayments............................................. 46,869 49,934
Other current assets.................................... 18,591 19,185
------------ ------------
Total current assets................................. 593,284 638,698
------------ ------------
Deferred Debits and Other Assets
Income taxes recoverable through future rates (Note 6).. 385,515 -
Abandonment costs....................................... 125,361 192,045
Harris Plant deferred costs (Note 6).................... 144,399 99,201
Unamortized debt expense................................ 63,898 49,603
Miscellaneous other property and investments............ 264,165 144,723
Other assets and deferred debits........................ 185,209 156,353
------------ ------------
Total deferred debits and other assets............... 1,168,547 641,925
------------ ------------
Total Assets......................................... $ 8,194,018 $ 7,706,201
============ ============
_________________________________________________________________________________________
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION> Carolina Power & Light Company
Balance Sheets
Capitalization and Liabilities
December 31
1993 1992
(in thousands)
<S> <C> <C>
Capitalization (see Schedules of Capitalization)
Common stock equity..................................... $ 2,632,116 $ 2,534,025
Preferred stock - redemption not required............... 143,801 143,801
Long-term debt, net..................................... 2,584,903 2,674,823
------------ ------------
Total capitalization................................. 5,360,820 5,352,649
------------ ------------
Current Liabilities
Current portion of long-term debt....................... 162,630 225,000
Notes payable (principally commercial paper)............ 76,000 46,800
Accounts payable........................................ 293,093 320,431
Interest accrued........................................ 54,770 61,115
Dividends declared...................................... 74,111 70,706
Other current liabilities............................... 88,423 103,666
------------ ------------
Total current liabilities........................... 749,027 827,718
------------ ------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes (Note 6).............. 1,585,490 1,044,052
Accumulated deferred investment tax credits............. 263,588 276,394
Other liabilities and deferred credits.................. 235,093 205,388
------------ ------------
Total deferred credits and other liabilities........ 2,084,171 1,525,834
------------ ------------
Commitments and Contingencies (Note 9)
Total Capitalization and Liabilities................ $ 8,194,018 $ 7,706,201
=========== ===========
_________________________________________________________________________________________
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Carolina Power & Light Company
___________________________________________________________________________________________________________
Schedules of Capitalization
December 31
1993 1992
(in thousands)
<S> <C> <C>
Common Stock Equity
Common stock without par value, 200,000,000 shares authorized;
160,736,522 shares outstanding (Note 3A)....................................... $1,622,277 $1,622,277
Note receivable from SPSP, net of ESOP adjustment................................ (220,725) (241,573)
Capital stock issuance expense................................................... (790) (334)
Retained earnings (Note 3A)...................................................... 1,231,354 1,153,655
---------- ----------
Total common stock equity............................................... $2,632,116 $2,534,025
========== ==========
Cumulative Preferred Stock, without par value (entitled to $100 a share plus accumulated
dividends in the event of liquidation; outstanding shares are as of December 31, 1993)
Preferred stock - redemption not required:
Authorized - 300,000 shares $5.00 Preferred Stock; 20,000,000 shares Serial
Preferred Stock
$ 5.00 Preferred - 237,259 shares outstanding (redemption price $110.00)......... $ 24,376 $ 24,376
4.20 Serial Preferred - 100,000 shares outstanding (redemption price $102.00).. 10,000 10,000
5.44 Serial Preferred - 250,000 shares outstanding (redemption price $101.00).. 25,000 25,000
7.95 Serial Preferred - 350,000 shares outstanding (redemption price $101.00).. 35,000 35,000
7.72 Serial Preferred - 500,000 shares outstanding (redemption price $101.00).. 49,425 49,425
---------- ----------
Total preferred stock - redemption not required.............................. $ 143,801 $ 143,801
========== ==========
Long-Term Debt (interest rates are as of December 31, 1993)
First mortgage bonds:
9.00 % due 1993................................................................ $ - $ 100,000
8.125% due 1993................................................................ - 100,000
4.50 % due 1994................................................................ - 30,000
5.20 % due 1995................................................................ 125,000 125,000
9.14 % due 1995................................................................ 77,050 77,050
5.125% due 1996................................................................ 30,000 30,000
6.375% due 1997................................................................ 40,000 40,000
5.375% to 6.875% due 1998 - 2002............................................... 390,000 375,000
7.75 % to 8.50% due 2003 - 2007................................................ 367,451 450,000
6.875 % to 9.00% due 2021 - 2023............................................... 725,000 675,000
First mortgage bonds - Secured Medium-Term Notes, Series A, B and C:
8.75% due 1993................................................................. - 25,000
5.85% due 1994................................................................. 50,000 -
4.85% to 8.92% due 1995 - 1999................................................. 213,000 173,000
First mortgage bonds - pollution control series:
D & E, 6.90% due 2009.......................................................... 54,455 54,455
F, 6.60% due 2010.............................................................. 34,700 34,700
G, J & K, 5.90% to July 1, 1994, due 2014...................................... 126,990 126,990
---------- ----------
Total first mortgage bonds................................................... 2,233,646 2,416,195
---------- ----------
<PAGE>
Other long-term debt:
Pollution control obligations backed by letter of credit, 2.32%
to 4.40% due 2014 - 2017....................................................... 442,000 443,800
Other pollution control obligations, 3.05% due 2019.............................. 55,640 55,640
Miscellaneous notes.............................................................. 34,680 390
---------- ----------
Total other long-term debt................................................... 532,320 499,830
---------- ----------
Unamortized premium and discount, net............................................ (18,433) (16,202)
Current portion of long-term debt................................................ (162,630) (225,000)
---------- ----------
Total long-term debt, net.................................................... $2,584,903 $2,674,823
========== ==========
Total Capitalization......................................................... $5,360,820 $5,352,649
========== ==========
___________________________________________________________________________________________________________
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Carolina Power & Light Company
__________________________________________________________________________________________________________________________________
Statements of Retained Earnings
Years ended December 31
(in thousands)
1993 1992 1991
<S> <C> <C> <C>
Retained Earnings at Beginning of Year................................ $ 1,153,655 $1,034,160 $ 917,991
Net income............................................................ 346,496 379,635 376,974
Preferred stock dividends at stated rates............................. (9,609) (14,798) (26,265)
Common stock dividends at annual rate of $1.655 per share in 1993,
$1.595 in 1992 and $1.535 in 1991 (Note 3A)......................... (266,019) (256,375) (246,731)
Tax benefit of ESOP dividends (Note 6)................................ 6,837 14,208 13,671
Other adjustments..................................................... (6) (3,175) (1,480)
----------- --------- ----------
Retained Earnings at End of Year...................................... $ 1,231,354 1,153,655 $1,034,160
=========== ========= ==========
__________________________________________________________________________________________________________________________________
See Notes to Financial Statements.
<CAPTION>
Quarterly Financial Data
(Unaudited)
First Quarter Second Quarter Third Quarter Fourth Quarter
1993 1992 1993 1992 1993 1992 1993 1992
(in thousands except per share data)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues..................... $ 707,485 658,271 674,591 621,208 854,750 824,318 658,557 663,024
Operating income....................... $ 130,123 138,299 105,107 109,644 159,428 183,975 73,712 110,042
Net income............................. $ 93,998 94,240 69,984 69,142 118,642 145,404 63,872 70,849
Common stock data: (Note 3A)
Earnings per common share.............. $ .57 .57 .42 .42 .72 .90 .38 .46
Dividend paid per common share......... $ .410 .395 .410 .395 .410 .395 .410 .395
Price per share - high................. $ 32 7/8 26 15/16 34 27 1/16 34 1/2 26 5/8 33 3/8 28 1/16
low.................. $ 27 1/16 24 9/16 31 1/4 24 3/4 32 1/8 25 28 1/8 25 7/16
__________________________________________________________________________________________________________________________________
See Notes to Financial Statements.
</TABLE>
<PAGE>
[TEXT]
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. System of Accounts
The accounting records of the Company are maintained in accordance
with uniform systems of accounts prescribed by the Federal Energy
Regulatory Commission (FERC), the North Carolina Utilities
Commission (NCUC) and the South Carolina Public Service Commission
(SCPSC).
Certain amounts for 1992 and 1991 have been reclassified to conform
to the 1993 presentation.
B. Electric Utility Plant
The cost of additions, including replacements of units of property,
and betterments is charged to utility plant. Maintenance and
repairs of property, and replacements and renewals of items
determined to be less than units of property, are charged to
maintenance expense. The cost of units of property replaced,
renewed or retired, plus removal or disposal costs, less salvage,
is charged to accumulated depreciation. Electric utility plant
other than nuclear fuel is subject to the lien of the Company's
mortgage.
As prescribed in regulatory uniform systems of accounts, an
allowance for the cost of borrowed and equity funds (AFUDC) used to
finance electric utility plant construction is charged to the cost
of plant. Regulatory authorities consider AFUDC an appropriate
charge for inclusion in the Company's utility rates to customers
over the service life of the property. The equity funds portion of
AFUDC is credited to other income, the borrowed funds portion is
credited to interest charges and, in years prior to 1993, a
deferred income tax provision was reflected as a reduction in the
borrowed funds portion. The composite, net-of-tax AFUDC rate was
7.3% in 1992 and 6.3% in 1991. Due to the implementation of
Statement of Financial Accounting Standards (SFAS) No. 109,
"Accounting for Income Taxes," in 1993, AFUDC-borrowed funds is no
longer recorded on a net-of-tax basis (see Note 6). The composite
AFUDC rate in 1993, which reflects the implementation of SFAS No.
109, was 8.8%.
Pursuant to the provisions of SFAS No. 109, the deferred income
taxes related to AFUDC in undepreciated plant in service at January
1, 1993, were recorded to an accumulated deferred income tax
liability with an offsetting adjustment to a regulatory asset.
C. Depreciation and Amortization
For financial reporting purposes, depreciation of utility plant
other than nuclear fuel is computed on the straight-line method
based on the estimated remaining useful life of the property,
adjusted for estimated net salvage. Depreciation provisions,
including decommissioning costs (see Note 1D), as a percent of
average depreciable property other than nuclear fuel, were
approximately 3.7% in each of the years 1993, 1992 and 1991.
Depreciation and amortization expense also includes amortization of
plant abandonment costs (see Note 7) and intangible plant, which
primarily includes software development costs.
Amortization of nuclear fuel costs, including disposal costs
associated with obligations to the U.S. Department of Energy (DOE),
is computed primarily on the unit-of-production method and charged
to fuel for generation. Costs related to obligations to the DOE for
the decommissioning and decontamination of enrichment facilities
are also charged to fuel for generation. The disposal and the
decommissioning and decontamination costs are components of fuel
costs for the purpose of deferred fuel accounting (see Note 1E).
D. Nuclear Decommissioning
Depreciation and amortization expense includes provisions for
nuclear decommissioning costs. In the Company's retail
jurisdictions, provisions for nuclear decommissioning costs are
approved by the NCUC and the SCPSC and are based on site-specific
estimates that included the costs for removal of all radioactive
and other structures at the site. Cost recovery is based on an
internal modified sinking fund methodology assuming 30-year delayed
dismantlement decommissioning. In the wholesale jurisdiction, the
provisions for nuclear decommissioning costs are based on amounts
agreed upon in applicable rate settlements. Accumulated nuclear
decommissioning cost provisions included in accumulated
depreciation were $221.6 million at December 31, 1993, and $186.4
million at December 31, 1992.
Pursuant to regulations of the Nuclear Regulatory Commission (NRC),
the Company is required to provide financial assurance that funds
will be available for decommissioning. In this regard, the Company
filed decommissioning plans with the NRC and, in 1991, began
depositing amounts currently collected in rates in an external
decommissioning trust. The Company is required to increase
external funding to the NRC-prescribed minimum no later than
January 1, 1996. This NRC-prescribed minimum exceeds amounts
currently collected in rates. In future rate filings, the Company
will request rate recovery based on site-specific estimates
for prompt dismantlement decommissioning. The requested rate
recovery will also include funding plans that assume external
funding of, at least, the NRC-prescribed minimum. The financial
impact on the Company will depend on future ratemaking treatment.
The NCUC and SCPSC have allowed other utilities to recover
costs based on site-specific estimates for prompt dismantlement
decommissioning and funding plans similar to those the Company
intends to use.
The Company's most recent site-specific estimates of
decommissioning costs were developed in 1993 and are based on
prompt dismantlement decommissioning, which reflects the cost of
removal of all radioactive and other structures currently
at the site. These estimates, in 1993 dollars, are $257.7 million
for Robinson Unit No. 2, $284.3 million for the Harris Plant,
$235.4 million for Brunswick Unit No. 1 and $221.4 million for
Brunswick Unit No. 2.
These estimates are subject to change based on a variety of
factors, including, but not limited to, inflation, changes in technology
applicable to nuclear decommissioning, and changes in federal,
state or local regulations. The cost estimates exclude the portion
attributable to North Carolina Eastern Municipal Power Agency
(Power Agency), which holds an undivided ownership interest in
certain of the Company's generating facilities (see Note 8). To the
extent of its ownership interests, Power Agency is responsible for
satisfying the NRC's financial assurance requirements for
decommissioning costs.
E. Other Policies
Customers' meters are read and bills are rendered on a cycle basis.
Revenues are recorded as services are rendered.
Regulators of all three jurisdictions require deferred fuel
accounting in which the Company defers the difference between fuel
costs incurred and the fuel component of customer rates. Customer
rates are adjusted periodically to incorporate the approved
deferrals.
Other property and investments are stated principally at cost,
less accumulated depreciation where applicable. The Company maintains
an allowance for doubtful accounts receivable, which totaled $2.3
million at December 31, 1993, and $2.1 million at December 31,
1992. Fuel inventory and inventory of materials and supplies are
carried on a first-in, first-out or average cost basis. Long-term
debt premiums, discounts and issuance expenses are amortized over
the life of the related debt using the straight-line method. Any
expenses or call premiums associated with the reacquisition of debt
obligations are amortized over the remaining life of the original
debt using the straight-line method. For purposes of the Statements
of Cash Flows, the Company considers all highly liquid investments
with original maturities of three months or less to be cash
equivalents.
2. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts of cash, cash equivalents and notes payable
approximate fair value because of the short maturities of these
instruments. The estimated fair value of long-term debt was
obtained from an independent pricing service. Investments in
trusts, presented in the table below, primarily includes external
decommissioning trust assets and funds invested pursuant to a
voluntary employee beneficiary association. The estimated fair
values of the Company's trust investments were obtained from quoted
market prices. These estimated fair values are as follows (in
thousands).
1993 1992
Carrying Fair Carrying Fair
Amount Value Amount Value
Long-term debt....$2,799,761 $2,877,300 $2,958,588 $2,978,276
Investments in
trusts..........$ 117,022 $ 119,277 $ 91,119 $ 91,844
There are inherent limitations in any estimation technique, and the
estimates presented herein are not necessarily indicative of the
amounts the Company could realize in current transactions.
3. CAPITALIZATION
A. Common Stock Equity
In December 1992, the Board of Directors authorized a two-for-one
split of the Company's common stock. On February 1, 1993, one
additional share was issued for each share outstanding to
shareholders of record on January 11, 1993. The number
of common shares, average common shares and per common share data
for all periods reflect the two-for-one stock split.
In 1989, the Company issued common stock shares to the Trustee of
the Company's Stock Purchase-Savings Plan (SPSP) in conjunction
with a qualified employee stock ownership plan (ESOP) loan. At
December 31, 1993, the Trustee was indebted to the Company for
$216.2 million. The note receivable from the Trustee is treated
as a reduction in common stock equity.
At December 31, 1993, the Company had 14,767,052 shares of
authorized but unissued common stock reserved and available for
issuance to satisfy the requirements of the Company's stock plans.
The Company intends, however, to meet the requirements of these
stock plans with issued and outstanding shares presently held by
the Trustee of the SPSP or with open market purchases of common
stock shares, as appropriate.
The Company's mortgage, as supplemented, and charter contain
provisions limiting the use of retained earnings for the payment of
dividends under certain circumstances. At December 31, 1993, there
were no significant restrictions on the use of retained earnings.
B. Long-Term Debt
As of December 31, 1993, long-term debt maturities for the years
1994 through 1998 were $50 million, $275 million, $55 million, $40
million and $205 million, respectively.
Person County Pollution Control Revenue Refunding Bonds-Series
1992A totaling $56 million have interest rates that must be
renegotiated on a weekly basis. First Mortgage Bonds-Pollution
Control Series G, J and K, totaling $127 million have three-year
interest rate periods that expire in 1994 and 1997. At the time,
of interest rate renegotiation, holders of these bonds may require
the Company to repurchase their bonds. These obligations are
excluded in total from long-term debt maturities in the preceding
paragraph. A portion of these bonds is classified as long-term
debt in the Balance Sheets, consistent with the Company's intention
to maintain the debt as long-term and to the extent that this
intention is supported by a $70 million long-term revolving credit
agreement (see Note 4). The amount of these obligations not
covered by the long-term revolving credit agreement is included in
current portion of long-term debt in the Balance Sheets.
4. REVOLVING CREDIT FACILITIES
At December 31, 1993, the Company's unused and readily available
revolving credit facilities totaled $208.1 million, consisting of
a $115 million revolving credit agreement with nine domestic money
centers and major regional banks, a $23.1 million revolving credit
agreement with fifteen regional banks and a $70 million long-term
revolving credit agreement with eight foreign banks.
5. POSTRETIREMENT BENEFIT PLANS
The Company has a noncontributory defined benefit retirement plan
(Plan) for all full-time employees and funds the Plan in amounts
that comply with contribution limits imposed by law. Plan benefits
reflect an employee's recent compensation, years of service and age
at retirement.
<PAGE>
<TABLE>
<CAPTION>
The components of net periodic pension cost are as follows (in thousands).
1993 1992 1991
<S> <C> <C> <C>
Actual return on plan assets.......................... $ (43,604) $ (26,882) $ (74,908)
Variance from expected return, deferred............... 4,490 (9,743) 41,211
---------- ---------- ----------
Expected return on plan assets........................ (39,114) (36,625) (33,697)
Service cost.......................................... 16,776 21,368 19,951
Interest cost on projected benefit obligation......... 31,928 31,141 28,419
Net amortization...................................... (2,390) 758 488
---------- ---------- ----------
Net cost..................................... $ 7,200 $ 16,642 $ 15,161
========== ========== ==========
Reconciliations of the funded status of the Plan to the amounts recognized in the
Balance Sheets at December 31 are presented below (in thousands).
1993 1992
<S> <C> <C>
Actuarial present value of benefits for services rendered
to date:
Accumulated benefits based on salaries to date, including
vested benefits of $293.6 million for 1993 and $242.6
million for 1992............................................. $ (339,301) $ (279,439)
Additional benefits based on estimated future salary levels.... (112,497) (112,563)
---------- ----------
Projected benefit obligation.......................... (451,798) (392,002)
Fair market value of plan assests, invested primarily in
equity and fixed-income securities........................... 515,428 483,292
---------- ----------
Funded status of plan................................. 63,630 91,290
Unrecognized prior service costs............................... 12,620 9,784
Unrecognized actuarial gain.................................... (119,352) (142,082)
Unrecognized transition obligation, being amortized over 18.5
years beginning January 1, 1987.............................. 1,216 1,322
---------- ----------
Accrued pension costs recognized in the Balance $ (41,886) $ (39,686)
Sheets.............................................. ========== ==========
The rates used for projected benefit obligation measurement are as
follows.
1993 1992 1991
Weighted-average discount rate.......... 7.5% 8.25% 7.0%
Assumed rate of increase in future
compensation.......................... 4.2% 4.9% 4.9%
</TABLE>
<PAGE>
[TEXT]
The expected long-term rate of return on plan assets used in
determining the net periodic pension cost was 9% for each of the
three years.
In addition to pension benefits, the Company provides contributory
postretirement benefits, including certain health care and life
insurance benefits, for substantially all retired employees. In
January 1993, the Company implemented SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." SFAS
No. 106 requires the recognition of the costs associated with these
other postretirement benefits (OPEB) on an accrual basis.
Previously, the cost of OPEB was generally recognized as claims
were incurred and premiums were paid. These costs totaled $2.7
million in 1992 and $3.0 million in 1991.
The components of the net periodic cost of OPEB for 1993 are as
follows (in thousands).
Actual return on plan assets....................$ (497)
Variance from expected return, deferred......... 9
----------
Expected return on plan assets.................. (488)
Service cost.................................... 6,797
Interest cost on accumulated benefit obligation. 9,662
Net amortization................................ 5,966
----------
Net cost......................................$ 21,937
==========
A reconciliation of the funded status of the OPEB plans to the amount
recognized in the Balance Sheet at December 31, 1993, is presented below (in
thousands).
Actuarial present value of benfits for services rendered to date:
Current retirees................................$ (62,727)
Active employees eligible to retire............. (14,800)
Active employees not eligible to retire......... (62,225)
----------
Accumulated postretirement benefit obligation. (139,752)
Fair market value of plan assets, invested primarily
in equity and fixed-income securities......... 7,584
----------
Funded status.......................... (132,168)
Unrecognized actuarial loss..................... 6,288
Unrecognized transition obligation, being amortized
over 20 years beginning January 1, 1993....... 113,345
----------
Accrued OPEB costs recognized in the
Balance Sheet ........................$ (12,535)
==========
<PAGE>
The accumulated postretirement benefit obligation (APBO) was
determined using a 7.5% weighted-average discount rate. The
expected long-term rate of return on plan assets used in
determining the net periodic cost of OPEB (NPC) was 9%. The
medical cost trend rates used in determining the APBO were assumed
to be 10.7% and 9.5% in 1994 for pre-medicare and post-medicare
benefits, respectively. These rates were assumed to gradually
decline to 5% in 2005, and remain at that level thereafter.
Assuming a one percent increase in the medical cost trend rates,
the aggregate of the service and interest cost components of the
NPC for 1993 would increase by $1.6 million, and the APBO as of
December 31, 1993, would increase by $15.1 million. In general,
OPEB costs are paid as claims are incurred and premiums are
paid; however, the Company is partially funding future health care
benefits for retirees in a trust created pursuant to Section 401(h)
of the Internal Revenue Code of 1986.
In future rate filings, the Company will request rate recovery
based on the provisions of SFAS No. 106. The NCUC and the SCPSC
have allowed other utilities to recover costs based on these
provisions.
6. INCOME TAXES
Income taxes are allocated between operating income and other
income based on the source of the income that generated the tax.
Investment tax credits related to operating income are amortized
over the service life of the related property.
On January 1, 1993, the Company implemented SFAS No. 109, which
required the Company to establish additional deferred income tax
assets and liabilities for certain temporary differences and to
adjust deferred income tax accounts for changes in income tax
rates. It also prohibits net-of-tax accounting for income
statement and balance sheet items. Prior to the implementation of
SFAS No. 109, deferred income taxes were not recorded for certain
timing differences. At December 31, 1992, deferred income taxes
were not provided for cumulative timing differences of
approximately $311 million as a result of a rate moderation plan
and pre-1976 flow-through.
Substantially all of the adjustments required by SFAS No. 109 were
recorded to deferred income tax balance sheet accounts, with
offsetting adjustments to certain assets and liabilities. As a
result, the cumulative effect on net income was not material. The
Company's total assets and liabilities increased by approximately
$450 million as a result of the implementation of SFAS No. 109.
As a result of the implementation of SFAS No. 109, the Company no
longer records the following income statement items on a net-of-tax
basis: Harris Plant deferred costs, Harris Plant carrying costs and
allowance for borrowed funds used during construction. In
addition, a portion of the tax benefit of ESOP dividends is now
recorded to non-operating income tax expense. The remaining
portion continues to be recorded directly to retained earnings, but
is no longer included in the determination of earnings per common
share. Prior period financial statement amounts were not
restated.
<PAGE>
<TABLE>
<CAPTION>
The provisions for income tax expense are composed of the following (in thousands).
1993 1992 1991
<S> <C> <C> <C>
Included in Operating Expenses
Income tax expense (credit)
Current - federal.................................... $ 108,935 $ 93,319 $ 224,832
state...................................... 29,687 37,616 9,711
Deferred - federal.................................... 50,719 81,134 (33,446)
state...................................... 11,588 6,342 35,494
Investment tax credit adjustments..................... (11,612) (11,083) (34,544)
--------- --------- ---------
Subtotal.............................................. 189,317 207,328 202,047
--------- --------- ---------
Harris Plant deferred costs
Deferred - federal.................................... - 2,523 (851)
state...................................... - 597 (186)
Investment tax credit adjustments..................... 218 (182) (299)
--------- --------- ---------
Subtotal.............................................. 218 2,938 (1,336)
--------- --------- ---------
Total included in operating expenses......... 189,535 210,266 200,711
--------- --------- ---------
Included in Other Income
Income tax expense (credit)
Current - federal.................................... (6,168) (5,857) 28
state...................................... (1,291) (1,268) (817)
Deferred - federal.................................... 7,483 11,024 8,410
state...................................... 1,562 1,986 2,065
Investment tax credit adjustments..................... (1,194) - -
--------- --------- ---------
Subtotal.............................................. 392 5,885 9,686
--------- --------- ---------
Harris Plant carrying costs
Deferred - federal.................................... - 1,612 1,280
state...................................... - 357 283
--------- --------- ---------
Subtotal.............................................. - 1,969 1,563
--------- --------- ---------
Other income, net
Deferred - federal.................................... - 47 21
state...................................... - 11 4
--------- --------- ---------
Subtotal.............................................. - 58 25
--------- --------- ---------
Total included in other income............... 392 7,912 11,274
_________ _________ _________
Included in Interest Charges
Allowance for borrowed funds used during construction
Deferred - federal.................................... - 1,678 2,194
state...................................... - 382 500
--------- --------- ---------
Total included in interest charges........... - 2,060 2,694
--------- --------- ---------
Total income tax expense..................... $ 189,927 $ 220,238 $ 214,679
========= ========= =========
</TABLE>
[TEXT]
<PAGE>
A reconciliation of the Company's effective income tax rate to the
statutory federal income tax rate follows.
1993 1992 1991
Effective income tax rate............... 35.4% 36.7% 36.3%
State income taxes, net of federal
income tax benefit.................... (5.1) (5.1) (5.3)
Investment tax credit amortization...... 2.3 1.9 2.0
Other differences, net.................. 2.4 .5 1.0
----- ----- -----
Statutory federal income tax rate.. 35.0% 34.0% 34.0%
===== ===== =====
At December 31, 1993, deferred income tax assets and liabilities
were $260.8 million and $1.9 billion, respectively. At December
31, 1992, prior to the implementation of SFAS No. 109, deferred
income tax assets and liabilities were $253.5 million and $1.3
billion, respectively. The net accumulated deferred income tax
liability was comprised of the following at December 31 (in
thousands).
1993 1992
Accelerated depreciation and
property cost differences............... $ 1,449,796 $ 1,053,706
Deferred costs, net....................... 168,311 35,984
Miscellaneous other temporary
differences, net........................ (12,443) (14,288)
---------- ----------
Net accumulated deferred
income tax liability............... $ 1,605,664 $ 1,075,402
========== ==========
<PAGE>
<TABLE>
<CAPTION>
The provisions for net deferred income tax expense prior to the implementation of SFAS
No. 109 relate to the following (in thousands).
1992 1991
<S> <C> <C>
Accelerated depreciation and property cost differences......... $ 90,610 $ (13,902)
Deferred costs, net............................................ (4,689) (29,433)
Deferred fuel, net............................................. 19,642 (1,498)
Prefunded employee benefit costs............................... 4,094 17,460
Production material and supplies tax accounting method
differences.................................................. 1,346 15,458
Interest related to tax audit issues........................... 1,135 26,068
Miscellaneous other timing differences, net.................... (4,445) 1,615
--------- ---------
Total provision for deferred income taxes, net........ $ 107,693 $ 15,768
========= =========
</TABLE>
[TEXT]
7. DEFERRED COSTS
The Company eliminated from its construction program and abandoned
further efforts to complete Harris Unit Nos. 3 and 4 in December
1981, Harris Unit No. 2 in December 1983 and Mayo Unit No. 2 in
March 1987. The NCUC and SCPSC each allowed the Company to recover
the cost of these abandoned units over a ten-year period without a
return on the unamortized balances. The amortization of Harris
Unit Nos. 3 and 4 was completed in 1992. In 1988 rate orders and
a 1990 NCUC Order on Remand, the Company was ordered to remove from
rate base and treat as abandoned plant certain costs related to the
Harris Plant.
Amortization of plant abandonment costs is included in depreciation
and amortization expense and totaled $100.7 million in 1993, $92.5
million in 1992 and $95.9 million in 1991. The 1993 amortization of
plant abandonment costs reflects increased amortization due to the
implementation of the SFAS No. 109 provision that prohibits
net-of-tax accounting (see Note 6). The unamortized balances of
plant abandonment costs are reported at the present value of future
recoveries of these costs. The associated accretion of present
value was $13.2 million in 1993, $18.2 million in 1992 and $24.6
million in 1991 and is reported in other income, net.
In 1988, the Company began recovering certain Harris Plant deferred
costs over ten years from the date of deferral, with carrying costs
accruing on the unamortized balance. Excluding deferred purchased
capacity costs (see Note 9A), the unamortized balance of Harris
Plant deferred costs was $81.4 million at December 31, 1993, and
$64.7 million, net of tax, at December 31, 1992. Due to the
implementation of SFAS No. 109 in 1993, Harris Plant deferred
costs are no longer recorded on a net-of-tax basis (see Note 6).
Harris Plant deferred costs are reported net of amortization on the
Statements of Income.
8. JOINT OWNERSHIP OF GENERATING FACILITIES
Power Agency, which includes a majority of the Company's previous
municipal wholesale customers, holds undivided ownership interests
in certain generating facilities of the Company. The Company and
Power Agency are entitled to shares of the generating capability
and output of each unit equal to their respective ownership
interests. Each also pays its ownership share of additional
construction costs, fuel inventory purchases and operating
expenses. The Company's share of expenses for the jointly-owned
units is included in the appropriate expense category in the
Statements of Income. Power Agency's payment obligation with
respect to abandonment costs for Harris Unit Nos. 2, 3 and 4 and
Mayo Unit No. 2 is 12.94% of such costs.
The Company's share of the jointly-owned generating facilities is
listed below with related information as of December 31, 1993
(dollars in millions).
<TABLE>
<CAPTION>
Facility Megawatt Company Plant Accumulated Under
Capability Ownership Investment Depreciation Construct
Interest
<S> <C> <C> <C> <C> <C>
Mayo Plant 745 83.83% $ 428.9 $ 135.2 $ .1
Harris Plant 860 83.83% $ 2,983.6 $ 575.2 $ 6.9
Brunswick Plant 1,521 81.67% $ 1,178.7 $ 652.4 $ 138.4
Roxboro Unit No. 4 700 87.06% $ 217.4 $ 81.4 $ 2.1
In the table above, plant investment and accumulated depreciation,
which includes accumulated decommissioning, are not reduced by the
regulatory disallowances related to the Harris Plant.
9. COMMITMENTS AND CONTINGENCIES
A. Purchased Power
The Company is obligated to purchase a percentage of Power Agency's
ownership capacity and energy from the Mayo and Harris Plants. For
Mayo, the percentage purchased declines ratably over a 15-year
period that ends in 1997. In April 1993, the Company and Power
Agency entered into an agreement to restructure portions of their
contracts covering power supplies and jointly-owned interests.
Under the terms of this agreement, the Company is increasing the
amount of capacity and energy purchased from Power Agency's
ownership interest in the Harris Plant. Also, the buyback period
has been extended six years through 2007. The minimum payments for
these purchases, which reflect capital-related capacity costs, are
estimated at $40.3 million, $27.1 million, $26.8 million, $26.5
million and $26.4 million for the years 1994 through 1998,
respectively, and $249.8 million for the years 1999 through 2007.
Other costs of such purchases are primarily demand-related
production expenses, fuel and energy-related operation and
maintenance expenses. Contractual purchases from the Mayo and
Harris Plants totaled $52.6 million for 1993, $39.8 million for
1992 and $46.3 million for 1991. In 1987, the NCUC ordered the
Company to reflect the recovery of the capacity portion of these
costs on a levelized basis over the original 15-year buyback
period, thereby deferring for future recovery the difference
between such costs and amounts collected through rates. In 1988,
the SCPSC ordered similar treatment, but with a ten-year
levelization period. At December 31, 1992, the Company had deferred
purchased capacity costs, including carrying costs accrued on the
deferred balances, of $37.1 million, net of tax. Due to the
implementation of SFAS No. 109 in 1993, the deferred costs are no
longer recorded on a net-of-tax basis (see Note 6). At December
31, 1993, the balance was $67.1 million, net-of-tax. Increased
purchases from the Harris Plant that resulted from the April 1993
agreement with Power Agency are not being deferred for future
recovery.
In January 1990, the Company began purchasing generating capacity
from Indiana Michigan Power Company's Rockport Unit No. 2. The
agreement provides for the purchase of 250 megawatts of capacity,
representing approximately 19% of the total plant capacity. The
estimated minimum annual payment for power is approximately $30
million, which represents capital-related capacity costs. Other
power costs include demand-related production expenses, fuel and
energy-related operation and maintenance expenses. Purchases,
including transmission use charges, totaled $60.2 million, $62.9
million and $59.7 million for 1993, 1992 and 1991, respectively.
The agreement expires on December 31, 2009.
In July 1993, the Company began purchasing 400 megawatts of
generating capacity from Duke Power Company. The estimated minimum
annual payment for power under the six-year agreement is $43
million, which represents capital-related capacity costs. Other
power costs associated with the agreement include fuel and energy-
related operation and maintenance expenses. Purchases, including
transmission use charges, totaled $37.1 million for 1993. The
agreement has been filed with the FERC for approval. The Company
cannot predict the outcome of this matter.
B. Insurance
The Company is a member of Nuclear Mutual Limited (NML), which
provides primary insurance coverage against property damage to
members' nuclear generating facilities. The Company is insured
thereunder for $500 million for each of its nuclear generating
facilities. For the current policy period, the Company is
subject to maximum retrospective premium assessments of
approximately $26.3 million in the event that losses at insured
facilities exceed premiums, reserves, reinsurance and other NML
resources, which are at present more than $750 million.
The Company is also a member of Nuclear Electric Insurance Limited
(NEIL), which provides insurance coverage against incremental costs
of replacement power resulting from prolonged accidental outages of
members' nuclear generating units. The Company is insured
thereunder for the first 52 weeks (starting 21 weeks after
an outage begins) in weekly amounts of $2.3 million at Brunswick
Unit No. 1, $2.2 million at Brunswick Unit No. 2, $2.6 million at
the Harris Plant and $2.0 million at Robinson Unit No. 2. The
Company is insured for the next 104 weeks for 67% of the above
amounts. NEIL also provides decontamination, decommissioning and
excess property insurance for nuclear generating facilities. The
Company is insured under this coverage for $1.4 billion at each of
its nuclear generating facilities. This is in addition to the $500
million coverage provided by NML. For the current policy period,
the Company is subject to retrospective premium assessments of up
to approximately $12.3 million with respect to the incremental
replacement power costs coverage and $44.9 million with respect to
the decontamination, decommissioning and excess property coverage
in the event covered expenses at insured facilities exceed
premiums, reserves, reinsurance and other NEIL resources. These
resources are at present more than $945 million for incremental
replacement power coverage and more than $1 billion for
decontamination, decommissioning and excess property insurance
coverage. Pursuant to regulations of the NRC, the Company's
property damage insurance policies provide that all proceeds from
such insurance be applied, first, to place a plant in safe and
stable condition after an accident and, second, to decontaminate it
before any proceeds can be used for plant repair or restoration.
The Company is self-insured to the extent losses may exceed limits
of the coverage described above. Power Agency would be responsible
for its ownership share of such losses and for certain
retrospective premium assessments on jointly-owned units.
The Company is insured against public liability for a nuclear
incident up to $9.4 billion per occurrence, which is the maximum
limit on public liability claims under the Price-Anderson Act. The
$9.4 billion coverage includes $200 million primary coverage and
$9.2 billion secondary financial protection through assessments on
nuclear reactor owners. In the event that public liability claims
from an insured nuclear incident exceed $200 million, the Company
would be subject to a pro rata assessment, for each reactor it
owns, of up to $75.5 million, plus a 5% surcharge, for each
incident. Payment of such assessment would be made over time as
necessary to limit the payment in any one year to no more
than $10 million per reactor owned. Power Agency would be
responsible for its ownership share of the assessment on
jointly-owned units.
C. Claims and Uncertainties
(1) In April 1992, both units at the Company's Brunswick Plant were
taken out of service in order for the Company to address anchor
bolt deficiencies and related wall construction issues in the
diesel generator building. During the outage, in addition to
resolving these issues, the Company conducted detailed inspections
and engineering evaluations of the Plant's miscellaneous steel,
performed necessary corrective and preventive maintenance and made
certain modifications.
In the spring of 1993, an intensive on-site review of Brunswick
Unit No. 2 was conducted by an NRC operational readiness assessment
team, which concluded that the depth and capability of the
Brunswick staff, the organizational structures and in-place
programs were adequate to support Unit No. 2 restart and operation.
The Company returned Unit No. 2 to service in May 1993. In late
December 1993, Unit No. 2 set a new continuous run record of more
than 219 days.
Cracks were discovered in the Brunswick Unit No. 1 reactor vessel
shroud during inspections made as part of refueling activities
performed during the outage. The Company conducted intensive
ultrasonic testing and physical sample inspections of the cracks.
The results of this investigation provided data used to develop
new stiffening braces to ensure that the shroud will continue to
perform its design function. Shroud modifications were completed in
late December 1993. Costs associated with the shroud repairs were
not material to the results of operations of the Company. The
Company returned Unit No. 1 to service in February 1994.
Additional shroud inspections at Unit No. 1 will be conducted
during the spring 1995 refueling outage to verify the integrity of
the shroud. The Company cannot predict the outcome of this matter.
The Brunswick Unit No. 2 shroud has minor crack indications, which
do not presently compromise the safety or operation of the unit.
Shroud inspections will be undertaken on Unit No. 2 during the
spring of 1994. The Company does not expect that costs associated
with any necessary shroud repairs will be material to the results
of operations of the Company.
In December 1993, the NRC issued its latest Systematic Assessment
of Licensee Performance report for the Brunswick Plant. The report
rated Brunswick's plant operations and plant support as "superior,"
and the Plant's maintenance and engineering as "good." The NRC, in
both the report and at a public meeting, recognized significant
improvements made at the Plant.
In 1993, two private organizations, the National Whistleblower
Center and the Coastal Alliance for a Safe Environment, and an
individual filed a petition with the NRC alleging that the Company
was aware of the shroud cracks as early as 1984 and engaged in
criminal activities to conceal its knowledge of the cracks. The
petitioners requested that the NRC require the Company to state
whether it knew about the cracks in 1984 and determine whether the
Company has engaged in criminal wrongdoing. To date, the
petitioners have failed to provide the Company with any evidence
substantiating their claims. Additionally, the Company conducted a
technical review concerning this matter, which did not reveal any
evidence that substantiates the petitioners' claims. The results of
this technical review were submitted to the NRC in November 1993.
Although the Company cannot predict the outcome of this matter, it
believes the allegations contained in the petition are without
merit.
The Company, the Public Staff of the NCUC, the Attorney General of
the State of North Carolina and Carolina Industrial Group for Fair
Utility Rates II entered into an agreement on July 28, 1993, that
resolved all issues related to the Brunswick Plant outage on or
before the date of the agreement, avoided higher fuel charges to
the Company's customers and settled the Company's annual fuel
adjustment proceeding. The Company had $31.2 million in fuel
expenses for the twelve-month period ended March 31, 1993, which
had not been recovered from North Carolina customers through the
Company's rates. As part of the agreement, the Company agreed to
forgo recovering $25.5 million of these fuel expenses and to
recover the remaining $5.7 million through rates over a
twelve-month period beginning September 1993. That $5.7 million is
subject to refund at the end of three years if the Brunswick Plant
does not achieve a specified operating performance level.
Additionally, the Company agreed that if the Brunswick Plant's
performance for the three-year period ending March 31, 1996, does
not achieve a specified operating performance level, the Company
could lose up to $10 million in additional fuel expenses.
In the South Carolina retail jurisdiction, the Company, the Staff
of the SCPSC, Nucor Steel and the Consumer Advocate for the State
of South Carolina, entered into an agreement in 1993 to settle the
fall SCPSC fuel proceeding. The settlement resolved all issues
related to fuel costs incurred by the Brunswick Plant through June
30, 1993, and avoided higher fuel charges to the Company's customers.
Pursuant to the terms of the settlement, the Company agreed to
forgo recovery of a total of $15.6 million in fuel expenses.
The NRC, the NCUC and the SCPSC will continue to review the
Company's activities at the Brunswick Plant. Except as noted, the
Company cannot predict the extent to which these and other actions
may impact its ability to recover costs associated with this
outage.
(2) The Company is subject to federal, state and local regulations
addressing air and water quality, hazardous and solid waste
management and other environmental matters.
There are several manufactured gas plant (MGP) sites to which
the Company and certain entities that were later merged into the
Company may have had some connection. In this regard, the Company
is participating in the North Carolina MGP Group (Group), a group
of entities alleged to be former owners or operators of MGP sites.
The Group was formed in response to an initiative launched by the
North Carolina Department of Environment, Health and Natural
Resources, Division of Solid Waste Management (DSWM), to encourage
the voluntary assessment and, where necessary, the remediation of
MGP sites. The Group and DSWM have entered into a Memorandum of
Understanding relative to the establishment of a uniform program
and framework for addressing MGP sites for which DSWM has contended
that members of the Group have potential responsibility. It is
anticipated that the investigation and remediation of specific MGP
sites will be addressed pursuant to one or more Administrative
Orders on Consent between DSWM and individual potentially
responsible parties. In addition, a current owner of property that
was the site of one MGP owned by Tidewater Power Company, which
merged into the Company in 1952, and the Company have entered into
an agreement to share the cost of investigation and remediation of
this site. Due to the lack of information with respect to the
operation of MGP sites and the uncertainty concerning questions of
liability and potential environmental harm, the extent and cost of
required remedial action, if any, and the extent to which liability
may be asserted against the Company or against others are not
currently determinable. The Company cannot predict the outcome of
these matters.
The Company has been notified by regulators of its involvement or
potential involvement in certain sites, other than MGP sites, that
require remedial action. Although the Company cannot predict the
outcome of these matters, it does not anticipate significant costs
associated with these other sites.
(3) In 1991, North Carolina Electric Membership Corporation (NCEMC)
and one of its members filed a Complaint with the FERC alleging
that the Company's wholesale rates and fuel clause billings were
too high and requesting that the Company provide its load signal to
NCEMC. The Company settled with NCEMC on all issues, and the
settlement agreement was approved by the FERC in 1993. The
agreement provides for the continuation of existing wholesale rate
levels and resolves the wholesale fuel clause billing issue
through June 30, 1993. The impact of the settlement decreased the
Company's 1993 earnings by approximately $8 million, net of tax.
(4) In 1993, the Company and Power Agency entered into an
agreement to restructure portions of their contracts covering power
supplies and jointly-owned interests in several of the Company's
generating units. The agreement changed portions of the Harris
Plant buyback provisions (see Note 9A). Also, pursuant to the
agreement, a portion of the Company's Harris Plant cost will not be
recoverable through sales of supplemental power to Power Agency. As
a result, the Company recorded a write-off in 1993 of approximately
$14.7 million, net of tax. As part of this agreement, Power
Agency agreed to the dismissal with prejudice of the Complaint that
it filed against the Company in July 1988 which claimed that the
Company failed to disclose alleged design, management and other
problems at the Harris Plant in connection with the sale of an
ownership interest to Power Agency. Under terms of the agreement,
Power Agency also agreed to withdraw the demand made in a 1993
letter that the Company bear any costs incurred in the restoration,
repair or replacement of property at the Brunswick Plant during the
outage that was in progress. The agreement has been filed with
the FERC for approval of the provisions that are subject to the
FERC's jurisdiction. The Company cannot predict the outcome of
this matter.
In the opinion of management, liabilities, if any, arising
under other pending claims would not have a material effect on the
financial position, results of operations or cash flows of the
Company.
<PAGE>
</TABLE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE V - UTILITY PLANT
Year Ended December 31, 1993
- -------------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -------------------------------------------------------------------------------------------------------------------------------
Balance at Other Changes - Balance at
Beginning of Additions Add (Deduct) Close of
Classification Period at Cost Retirements See Note 2 Period
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Electric utility plant other than
nuclear fuel, at original cost:
In Service:
Intangible plant (Note 1) $ 177,329 $ 59,901,256 $ -0- $ -0- $ 60,078,585
Production plant 5,679,711,814 76,031,082 17,091,154 (24,735,703) 5,713,916,039
Transmission plant 848,715,952 27,828,432 3,302,052 195,594 873,437,926
Distribution plant 1,738,670,266 107,886,829 20,921,886 (392,707) 1,825,242,502
General plant 260,543,187 24,581,458 11,557,525 (600,811) 272,966,309
-------------- -------------- -------------- -------------- --------------
Electric utility plant in service 8,527,818,548 296,229,057 52,872,617 (25,533,627) 8,745,641,361
Property under capital leases 46,963,973 -0- -0- (3,209,696) 43,754,277
Electric plant acquisition adjustment 3,670,671 -0- -0- (3,548,112) 122,559
Held for future use 13,385,359 49,180 -0- (134,565) 13,299,974
Construction work in progress 251,237,690 51,865,141 -0- 6,610,324 309,713,155
-------------- -------------- -------------- -------------- --------------
Total electric utility plant
other than nuclear fuel 8,843,076,241 348,143,378 52,872,617 (25,815,676) 9,112,531,326
Nuclear fuel, at original cost 410,923,715 52,032,343 25,265,005 1,542,032 439,233,085
-------------- -------------- -------------- -------------- --------------
Total electric utility plant
including nuclear fuel $ 9,253,999,956 $ 400,175,721 $ 78,137,622 $ (24,273,644) $ 9,551,764,411
============== ============== ============== ============== ==============
NOTES
- -----
1. Column C primarily includes software development costs. In conformity with the system of accounts prescribed by
regulatory authority, intangible assets are included in utility plant, the amount thereof being set forth above, and
Schedule VII is omitted.
2. The net change in Column E represents the following:
Electric utility plant other than nuclear fuel:
Transfers to non-utility property $ (735,768)
Power Agency adjustments 439,844
Amortization of capital leases (3,209,696)
Harris Plant disallowance - Power Agency * (24,779,621)
Deferred tax adjustment (SFAS No. 109) ** 6,017,677
Adjustment to reverse fully amortized acqusition adjustments (3,548,112)
--------------
Total $ (25,815,676)
==============
Nuclear fuel:
Spent nuclear fuel $ (2,011,963)
Deferred tax adjustment (SFAS No. 109) ** 3,553,995
--------------
Total $ 1,542,032
==============
* See Item 8, Notes to Financial Statements, Note 9C.
* See Item 8, Notes to Financial Statements, Note 6.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE V - UTILITY PLANT
Year Ended December 31, 1992
- -------------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -------------------------------------------------------------------------------------------------------------------------------
Balance at Other Changes - Balance at
Beginning of Additions Add (Deduct) Close of
Classification Period at Cost Retirements See Note 2 Period
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Electric utility plant other than
nuclear fuel, at original cost:
In Service:
Intangible plant (Note 1) $ 177,329 $ -0- $ -0- $ -0- $ 177,329
Production plant 5,563,476,581 122,762,386 5,691,342 (835,811) 5,679,711,814
Transmission plant 819,338,524 34,759,962 5,913,881 531,347 848,715,952
Distribution plant 1,657,113,617 105,303,904 24,447,064 699,809 1,738,670,266
General plant 248,007,064 18,142,213 5,288,921 (317,169) 260,543,187
-------------- -------------- -------------- -------------- --------------
Electric utility plant in service 8,288,113,115 280,968,465 41,341,208 78,176 8,527,818,548
Property under capital leases 49,957,389 -0- -0- (2,993,416) 46,963,973
Electric plant acquisition adjustment 3,670,671 -0- -0- -0- 3,670,671
Held for future use 15,465,637 156,213 -0- (2,236,491) 13,385,359
Construction work in progress 242,755,881 9,000,399 -0- (518,590) 251,237,690
-------------- -------------- -------------- -------------- --------------
Total electric utility plant
other than nuclear fuel 8,599,962,693 290,125,077 41,341,208 (5,670,321) 8,843,076,241
Nuclear fuel, at original cost 399,456,396 59,213,564 50,143,749 2,397,504 410,923,715
-------------- -------------- -------------- -------------- --------------
Total electric utility plant
including nuclear fuel $ 8,999,419,089 $ 349,338,641 $ 91,484,957 $ (3,272,817) $ 9,253,999,956
============== ============== ============== ============== ==============
NOTES
- -----
1. In conformity with the system of accounts prescribed by regulatory authority, intangible assets are included in utility
plant, the amount thereof being set forth above, and Schedule VII is omitted.
2. The net change in Column E represents the following:
Electric utility plant other than nuclear fuel:
Transfers to non-utility property $ (2,667,749)
Power Agency adjustments (9,156)
Amortization of capital leases (2,993,416)
--------------
Total $ (5,670,321)
==============
Nuclear fuel:
Spent nuclear fuel $ 2,397,504
==============
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE V - UTILITY PLANT
Year Ended December 31, 1991
- -------------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- -------------------------------------------------------------------------------------------------------------------------------
Balance at Other Changes - Balance at
Beginning of Additions Add (Deduct) Close of
Classification Period at Cost Retirements See Note 2 Period
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Electric utility plant other than
nuclear fuel, at original cost:
In Service:
Intangible plant (Note 1) $ 177,329 $ -0- $ -0- $ -0- $ 177,329
Production plant 5,470,984,943 97,064,181 4,579,203 6,660 5,563,476,581
Transmission plant 813,907,687 12,594,962 4,279,239 (2,884,886) 819,338,524
Distribution plant 1,574,103,231 100,647,398 20,299,462 2,662,450 1,657,113,617
General plant 232,199,294 19,522,591 3,672,987 (41,834) 248,007,064
-------------- -------------- -------------- -------------- --------------
Electric utility plant in service 8,091,372,484 229,829,132 32,830,891 (257,610) 8,288,113,115
Property under capital leases 52,749,428 -0- -0- (2,792,039) 49,957,389
Electric plant acquisition adjustment 3,670,671 -0- -0- -0- 3,670,671
Held for future use 13,585,641 2,175,932 109,641 (186,295) 15,465,637
Construction work in progress 200,112,163 42,982,458 -0- (338,740) 242,755,881
-------------- -------------- -------------- -------------- --------------
Total electric utility plant
other than nuclear fuel 8,361,490,387 274,987,522 32,940,532 (3,574,684) 8,599,962,693
Nuclear fuel, at original cost 418,998,829 55,659,667 99,730,917 24,528,817 399,456,396
-------------- -------------- -------------- -------------- --------------
Total electric utility plant
including nuclear fuel $ 8,780,489,216 $ 330,647,189 $ 132,671,449 $ 20,954,133 $ 8,999,419,089
============== ============== ============== ============== ==============
NOTES
- -----
1. In conformity with the system of accounts prescribed by regulatory authority, intangible assets are included in utility
plant, the amount thereof being set forth above, and Schedule VII is omitted.
2. The net change in Column E represents the following:
Electric utility plant other than nuclear fuel:
Transfers to non-utility property $ (739,027)
Power Agency adjustments (43,618)
Amortization of capital leases (2,792,039)
--------------
Total $ (3,574,684)
==============
Nuclear fuel:
Spent nuclear fuel $ 24,528,817
==============
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE VI - ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF ELECTRIC UTILITY PLANT
Year Ended December 31, 1993
-------------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------------------
Additions Deductions from Reserves
--------- ------------------------
(1) (2) (1) (2)
Balance at Charged Retirements, Balance at
Beginning Charged to to Other Renewals, & Close of
Description of Period Income Accounts Replacements Other Period
-------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Accumulated provision for
depreciation of electric
utility plant other than
nuclear fuel (Note 1) $ 2,632,577,141 $ 325,456,002 $ 1,211,670 $ 57,183,470 $ 4,229,201 $ 2,897,832,142
============== ============== ============== ============== ============== ==============
Accumulated provision
for amortization of
nuclear fuel (Note 2) $ 195,844,453 $ 51,056,959 $ 2,120,891 $ 25,265,005 $ 2,011,963 $ 221,745,335
============== ============== ============== ============== ============== ==============
NOTES
- -----
1. This accumulated provision is maintained for all electric utility depreciable plant. For statement of the Company's policy
with respect to retirements of property, see Item 8, Notes to Financial Statements, Note 1B. The amount in Column C(2)
reflects Decommissioning Qualified External Trust earnings and expense. The amount in Column D(1) includes net salvage credits
for retirements. The amount in Column D(2) represents the following:
Electric utility plant other than nuclear fuel:
Harris Plant disallowance - Power Agency * $ 4,134,168
Transfers to Accumulated Provision for Depreciation of
Non-Utility Property 95,033
--------------
Total $ 4,229,201
==============
* See Item 8, Notes to Financial Statements, Note 9C.
2. Column C(2), nuclear fuel, is related to the implementation, in January 1993, of Statement of Financial Accounting Standards
No. 109, "Accounting for Income Taxes." Pursuant to the provisions of SFAS No. 109, the deferred income taxes related to
allowance for the cost of borrowed funds in the provision for amortization of nuclear fuel, were recorded to an accumulated
deferred income tax liability and the accumulated provision, above, increased accordingly. Column D(2), nuclear fuel, is
related to spent nuclear fuel.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE VI - ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF ELECTRIC UTILITY PLANT
Year Ended December 31, 1992
-------------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------------------
Additions Deductions from Reserves
--------- ------------------------
(1) (2) (1) (2)
Balance at Charged Retirements, Balance at
Beginning Charged to to Other Renewals, & Close of
Description of Period Income Accounts Replacements Other Period
-------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Accumulated provision for
depreciation of electric
utility plant other than
nuclear fuel (Note 1) $ 2,367,823,895 $ 306,175,034 $ 827,908 $ 42,203,592 $ 46,104 $ 2,632,577,141
============== ============== ============== ============== ============== ==============
Accumulated provision
for amortization of
nuclear fuel (Note 2) $ 201,281,130 $ 42,309,568 $ -0- $ 50,143,749 $ (2,397,504) $ 195,844,453
============== ============== ============== ============== ============== ==============
NOTES
- -----
1. This accumulated provision is maintained for all electric utility depreciable plant. For statement of the Company's policy
with respect to retirements of property, see Item 8, Notes to Financial Statements, Note 1B. The amount in Column C(2)
reflects Decommissioning Qualified External Trust earnings and expense. The amount in Column D(1) includes net salvage credits
for retirements. Column D(2) is related to transfers to Account 122 - Accumulated Provision for Depreciation of Non-Utility
Property.
2. Column D(2), nuclear fuel, is related to spent nuclear fuel.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE VI - ACCUMULATED PROVISION FOR DEPRECIATION AND AMORTIZATION OF ELECTRIC UTILITY PLANT
Year Ended December 31, 1991
-------------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------------------------------------------------------------------------------------------------------------------------------
Additions Deductions from Reserves
--------- ------------------------
(1) (2) (1) (2)
Balance at Charged Retirements, Balance at
Beginning Charged to to Other Renewals, & Close of
Description of Period Income Accounts Replacements Other Period
-------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Accumulated provision for
depreciation of electric
utility plant other than
nuclear fuel (Note 1) $ 2,102,651,111 $ 300,244,421 $ 129,755 $ 35,197,968 $ 3,424 $ 2,367,823,895
============== ============== ============== ============== ============== ==============
Accumulated provision
for amortization of
nuclear fuel (Note 2) $ 210,932,991 $ 65,550,239 $ -0- $ 99,730,917 $ (24,528,817) $ 201,281,130
============== ============== ============== ============== ============== ==============
NOTES
- -----
1. This accumulated provision is maintained for all electric utility depreciable plant. For statement of the Company's policy
with respect to retirements of property, see Item 8, Notes to Financial Statements, Note 1B. The amount in Column C(2)
reflects Decommissioning Qualified External Trust earnings and expense. The amount in Column D(1) includes net salvage credits
for retirements. Column D(2) is related to transfers to Account 122 - Accumulated Provision for Depreciation of Non-Utility
Property.
2. Column D(2), nuclear fuel, is related to spent nuclear fuel.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE VIII - RESERVES
Year Ended December 31, 1993
- ----------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ----------------------------------------------------------------------------------------------------------------------
Additions
---------
Balance at (1) (2) Deductions Balance at
Beginning Charged to Charged to from Close of
Description of Period Income Other Accounts Reserves Period
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Reserves deducted from
related assets on the
balance sheet:
Uncollectible accounts $ 2,067,878 $ 4,942,000 $ -0- $ 4,704,737 $ 2,305,141
============== ============== ============== ============== ==============
Reserves other than those
deducted from assets on
the balance sheet:
Injuries and damages $ 2,046,430 $ 1,596,361 $ -0- $ 1,548,785 $ 2,094,006
============== ============== ============== ============== ==============
Property insurance
reserve $ 23,217,772 $ -0- $ -0- $ -0- $ 23,217,772
============== ============== ============== ============== ==============
Reserve for possible coal
mine investment losses $ 8,467,088 $ -0- $ -0- $ 60,335 $ 8,406,753
============== ============== ============== ============== ==============
Reserve for employee
retirement and compensation
plans $ 47,515,666 $ 24,870,724 $ -0- $ 6,760,197 $ 65,626,193
============== ============== ============== ============== ==============
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE VIII - RESERVES
Year Ended December 31, 1992
- ----------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ----------------------------------------------------------------------------------------------------------------------
Additions
---------
Balance at (1) (2) Deductions Balance at
Beginning Charged to Charged to from Close of
Description of Period Income Other Accounts Reserves Period
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Reserves deducted from
related assets on the
balance sheet:
Uncollectible accounts $ 2,241,837 $ 3,722,870 $ -0- $ 3,896,829 $ 2,067,878
============== ============== ============== ============== ==============
Reserves other than those
deducted from assets on
the balance sheet:
Injuries and damages $ 1,993,670 $ 1,964,804 $ -0- $ 1,912,044 $ 2,046,430
============== ============== ============== ============== ==============
Property insurance
reserve $ 23,217,772 $ -0- $ -0- $ -0- $ 23,217,772
============== ============== ============== ============== ==============
Reserve for possible coal
mine investment losses $ 17,770,480 $ (9,000,000) $ -0- $ 303,392 $ 8,467,088
============== ============== ============== ============== ==============
Reserve for employee
retirement and compensation
plans $ 35,136,039 $ 18,163,651 $ -0- $ 5,784,024 $ 47,515,666
============== ============== ============== ============== ==============
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE VIII - RESERVES
Year Ended December 31, 1991
- ----------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ----------------------------------------------------------------------------------------------------------------------
Additions
---------
Balance at (1) (2) Deductions Balance at
Beginning Charged to Charged to from Close of
Description of Period Income Other Accounts Reserves Period
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Reserves deducted from
related assets on the
balance sheet:
Uncollectible accounts $ 2,675,035 $ 4,135,851 $ -0- $ 4,569,049 $ 2,241,837
============== ============== ============== ============== ==============
Reserves other than those
deducted from assets on
the balance sheet:
Injuries and damages $ 2,820,458 $ 2,257,040 $ -0- $ 3,083,828 $ 1,993,670
============== ============== ============== ============== ==============
Property insurance
reserve $ 13,962,378 $ -0- $ 9,255,394 $ -0- $ 23,217,772
============== ============== ============== ============== ==============
Reserve for possible coal
mine investment losses $ 17,973,493 $ -0- * * $ 17,770,480
============== ============== ============== ============== ==============
Reserve for employee
retirement and compensation
plans $ 26,305,247 $ 17,216,923 $ -0- $ 8,386,131 $ 35,136,039
============== ============== ============== ============== ==============
___________
* This information is omitted in accordance with Rule 12-09 of Regulation S-X of the Securities and Exchange
Commission, since the additions, deductions and balances are not significant.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE IX - SHORT-TERM BORROWINGS
Three Years Ended December 31, 1993
- ---------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E COLUMN F
- ---------------------------------------------------------------------------------------------------------
Maximum Average Weighted
Category of Weighted amount amount average**
aggregate Balance at average outstanding outstanding interest
short-term end of interest during the during the rate during
borrowings period rate period period** the period
- ---------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
<S> <C> <C> <C> <C> <C>
Bank loans $ - 0 - - 0 - $ - 0 - $ - 0 - - 0 -
============== ============== ============== ============== ==============
Commercial paper* $ 76,000,000 3.31% $ 147,400,000 $ 94,472,849 3.29%
============== ============== ============== ============== ==============
Year Ended December 31, 1992
<S> <C> <C> <C> <C> <C>
Bank loans $ - 0 - - 0 - $ - 0 - $ - 0 - - 0 -
============== ============== ============== ============== ==============
Commercial paper* $ 46,800,000 3.65% $ 112,200,000 $ 49,875,184 3.99%
============== ============== ============== ============== ==============
Year Ended December 31, 1991
<S> <C> <C> <C> <C> <C>
Bank loans $ - 0 - - 0 - $ - 0 - $ - 0 - - 0 -
============== ============== ============== ============== ==============
Commercial paper* $ 62,900,000 4.74% $ 197,725,000 $ 34,782,016 6.23%
============== ============== ============== ============== ==============
__________
* The commercial paper at the end of the period had due dates of up to 45 days after the end of 1993,
36 days after the end of 1992 and 60 days after the end of 1991.
Excluded from aggregate short-term borrowings are miscellaneous notes which had balances at year
end of $39,000 for 1991.
** Average computed on a daily weighted basis.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
Years ended December 31
(in thousands)
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Taxes other than on income
Ad valorem $ 57,809 $ 49,995 $ 47,309
State and city franchise 68,641 66,116 65,092
Social security and
unemployment 26,309 25,398 23,444
Miscellaneous 7,594 6,408 5,862
-------- -------- --------
Total 160,353 147,917 141,707
Less-Amount charged to plant
and sundry accounts 17,482 16,020 14,502
-------- -------- --------
Remainder-charged to
operating expenses $ 142,871 $ 131,897 $ 127,205
======== ======== ========
</TABLE>
<PAGE>
[TEXT]
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
______ _____________________________________________
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
________ __________________________________________________
a) Information on the Company's directors is set
forth in the Company's 1994 definitive proxy statement dated March
31, 1994, and incorporated by reference herein.
b) Information on the Company's executive officers
is set forth in Part I and incorporated by reference herein.
ITEM 11. EXECUTIVE COMPENSATION
_______ ______________________
Information on executive compensation is set forth in
the Company's 1994 definitive proxy statement dated March 31, 1994,
and incorporated by reference herein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT
________ _______________________________________________
a) The Company knows of no person who is a
beneficial owner of more than five (5%) percent of any
class of the Company's voting securities except for Wachovia Bank
of North Carolina, N.A., Post Office Box 3099, Winston-Salem, North
Carolina 27102 which as of December 31, 1993, owned 24,380,381
shares of Common Stock (15.2% of Class) as Trustee of the Company's
Stock Purchase-Savings Plan.
b) Information on security ownership of the Company's
management is set forth in the Company's 1994 definitive proxy
statement dated March 31, 1994, and incorporated by reference
herein.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
________ ______________________________________________
Information on certain relationships and transactions
is set forth in the Company's 1994 definitive proxy statement dated
March 31, 1994, and incorporated by reference herein.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K.
_______ ____________________________________________
a) 1. Financial Statements Filed:
See ITEM 8 - Financial Statements and
Supplementary Data.
2. Financial Statement Schedules Filed:
See ITEM 8 - Financial Statements and
Supplementary Data.
3. Exhibits Filed:
Exhibit No. *3a(1) Restated Charter of Carolina Power &
Light Company, dated May 22, 1980
(filed as Exhibit 2(a)(1), File No.
2-64193).
Exhibit No. *3a(2) Amendment, dated May 10, 1989, to
Restated Charter of the Company
(filed as Exhibit 3(b), File No.
33-33431).
Exhibit No. *3a(3) Amendment, dated May 27, 1992 to
Restated Charter of the Company
(filed as Exhibit 4(b)(2), File No.
33-55060).
Exhibit No. *3a(4) By-laws of the Company as amended
December 12, 1990 (filed as Exhibit
3(c), File No. 33-38298).
Exhibit No. *4a(1) Resolution of Board of Directors,
dated December 8, 1954, authorizing
the issuance of, and establishing the
series designation, dividend rate and
redemption prices for the Company's
Serial Preferred Stock, $4.20 Series
(filed as Exhibit 3(c), File No.
33-25560).
Exhibit No. *4a(2) Resolution of Board of Directors,
dated January 17, 1967, authorizing
the issuance of, and establishing the
series designation, dividend rate and
redemption prices for the Company's
Serial Preferred Stock, $5.44 Series
(filed as Exhibit 3(d), File No.
33-25560).
Exhibit No. *4a(3) Statement of Classification of Shares
dated January 13, 1971, relating to
the authorization of, and
establishing the series designation,
dividend rate and redemption prices
for the Company's Serial
Preferred Stock, $7.95 Series
(filed as Exhibit 3(f), File No.
33-25560).
Exhibit No. *4a(4) Statement of Classification of Shares
dated September 7, 1972, relating to
the authorization of, and
establishing the series designation,
dividend rate and redemption
prices for the Company's Serial
Preferred Stock, $7.72 Series (filed
as Exhibit 3(g), File No. 33-25560).
Exhibit No. *4b Mortgage and Deed of Trust dated as
of May 1, 1940 between the Company
and The Bank of New York (formerly,
Irving Trust Company) and Frederick
G. Herbst (W.T. Cunningham,
Successor), Trustees and the First
through Fifth Supplemental Indentures
thereto (Exhibit 2(b), File No. 2-
64189); and the Sixth through
Sixty-second Supplemental Indentures
(Exhibit 2(b)-5, File No. 2-16210;
Exhibit 2(b)-6, File No. 2-16210;
Exhibit 4(b)-8, File No. 2-19118;
Exhibit 4(b)-2, File No. 2-22439;
Exhibit 4(b)-2, File No. 2-24624;
Exhibit 2(c), File No. 2-27297;
Exhibit 2(c), File No. 2-30172;
Exhibit 2(c), File No. 2-35694;
Exhibit 2(c), File No. 2-37505;
Exhibit 2(c), File No. 2-39002;
Exhibit 2(c), File No. 2-41738;
Exhibit 2(c), File No. 2-43439;
Exhibit 2(c), File No. 2-47751;
Exhibit 2(c), File No. 2-49347;
Exhibit 2(c), File No. 2-53113;
Exhibit 2(d), File No. 2-53113;
Exhibit 2(c), File No. 2-59511;
Exhibit 2(c), File No. 2-61611;
Exhibit 2(d), File No. 2-64189;
Exhibit 2(c), File No. 2-65514;
Exhibits 2(c) and 2(d), File No.
2-66851; Exhibits 4(b)-1, 4(b)-2,
and 4(b)-3, File No. 2-81299;
Exhibits 4(c)-1 through 4(c)-8,
File No. 2-95505; Exhibits 4(b)
through 4(h), File No. 33-25560;
Exhibits 4(b) and 4(c), File No.
33-33431; Exhibits 4(b) and 4(c),
File No. 33-38298; Exhibits 4(h) and
4(i), File No. 33-42869; Exhibits
4(e)-(g), File No. 33-48607;
Exhibits 4(e) and 4(f), File No.
33-55060; Exhibits 4(e) and 4(f),
File No. 33-60014; Exhibits 4(a) and
4(b), File No. 33-38349; Exhibit
4(e), File No. 33-50597; and Item
7(c) of the Company's Current Report
on Form 8-K dated January 19, 1994).
Exhibit No. *10a(1) Purchase, Construction and Ownership
Agreement dated July 30, 1981
between Carolina Power & Light
Company and North Carolina Municipal
Power Agency Number 3 and Exhibits,
together with resolution dated
December 16, 1981 changing name to
North Carolina Eastern Municipal
Power Agency, amending letter dated
February 18, 1982, and amendment
dated February 24, 1982 (filed as
Exhibit 10(a), File No. 33-25560).
Exhibit No. *10a(2) Operating and Fuel Agreement dated
July 30, 1981 between Carolina Power
& Light Company and North Carolina
Municipal Power Agency Number 3 and
Exhibits, together with resolution
dated December 16, 1981 changing
name to North Carolina Eastern
Municipal Power Agency, amending
letters dated August 21, 1981 and
December 15, 1981, and amendment
dated February 24, 1982 (filed as
Exhibit 10(b), File No. 33-25560).
Exhibit No. *10a(3) Power Coordination Agreement dated
July 30, 1981 between Carolina
Power & Light Company and North
Carolina Municipal Power Agency
Number 3 and Exhibits, together with
resolution dated December 16, 1981
changing name to North Carolina
Eastern Municipal Power Agency and
amending letter dated January 29,
1982 (filed as Exhibit 10(c), File
No. 33-25560).
Exhibit No. *10a(4) Amendment dated December 16, 1982 to
Purchase, Construction and Ownership
Agreement dated July 30, 1981 between
Carolina Power & Light Company and
North Carolina Eastern Municipal
Power Agency (filed as Exhibit 10(d),
File No. 33-25560).
Exhibit No. *10a(5) Agreement Regarding New Resources and
Interim Capacity between Carolina
Power & Light Company and North
Carolina Eastern Municipal Power
Agency dated October 13, 1987 (filed
as Exhibit 10(e), File No. 33-25560).
Exhibit No. *10a(6) Power Coordination Agreement - 1987A
between North Carolina Eastern
Municipal Power Agency and Carolina
Power & Light Company for Contract
Power From New Resources Period
1987-1993 dated October 13, 1987
(filed as Exhibit 10(f), File No.
33-25560).
+Exhibit No. *10c(1) Directors Deferred Compensation Plan
effective January 1, 1982 as amended
(filed as Exhibit 10(g), File No.
33-25560).
+Exhibit No. *10c(2) Supplemental Executive Retirement
Plan effective January 1, 1984 (filed
as Exhibit 10(h), File No. 33-25560).
+Exhibit No. *10c(3) Retirement Plan for Outside Directors
(filed as Exhibit 10(i), File No. 33-
25560).
+Exhibit No. *10c(4) Executive Deferred Compensation Plan
effective May 1, 1982 as amended
(filed as Exhibit 10(j), File No.
33-25560).
+Exhibit No. *10c(5) Key Management Deferred Compensation
Plan (filed as Exhibit 10(k), File
No. 33-25560).
+Exhibit No. *10c(6) Resolutions of the Board of
Directors, dated March 15, 1989,
amending the Key Management Deferred
Compensation Plan (filed as Exhibit
10(a), File No. 33-48607).
+Exhibit No. *10c(7) Resolutions of the Board of Directors
dated May 8, 1991, amending the
Directors Deferred Compensation Plan
(filed as Exhibit 10(b), File No. 33-
48607).
+Exhibit No. *10c(8) Resolutions of the Board of Directors
dated May 8, 1991, amending the
Executive Deferred Compensation Plan
(filed as Exhibit 10(c), File No. 33-
48607).
Exhibit No. 12 Computation of Ratio of Earnings to
Fixed Charges and Preferred Dividends
Combined and Ratio of Earnings to
Fixed Charges.
Exhibit No. 23(a) Consent of Deloitte & Touche.
Exhibit No. 23(b) Consent of Richard E. Jones.
*Incorporated herein by reference as indicated.
+Management contract or compensation plan or arrangment required to
be filed as an exhibit to this report pursuant to Item 14(c) of Form
10-K.
b) Reports on Form 8-K filed during or with
respect to the last quarter of 1993 and the first quarter
of 1994:
Date of Report Item Reported
______________ _____________
December 1, 1993 Item 5. Other Events
January 19, 1994 Item 7. Financial Statements,
Pro Forma Financial
Information and
Exhibits
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or
15(d) 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, on the 25th day of March,
1994.
CAROLINA POWER & LIGHT COMPANY
(Registrant)
By: /s/ Paul S. Bradshaw
Vice President and Controller
Pursuant to the requirements of the Securities
Exchange Act of 1934, this report has been signed below
by the following persons on behalf of the registrant and in the
capacities and on the date indicated.
Signature Title Date
_________ _____ ____
/s/ Sherwood H. Smith, Jr. Principal Executive
(Chairman and Chief Executive Officer and Director
Officer)
/s/ Charles D. Barham, Jr. Principal Financial
(Executive Vice President and Officer and Director
Chief Financial Officer)
/s/ Paul S. Bradshaw Principal Accounting
(Vice President and Controller) Officer
/s/ Edwin B. Borden Director March 25, 1994
/s/ Felton J. Capel Director
/s/ William Cavanaugh III Director
(President and Chief Operating
Officer)
/s/ George H. V. Cecil Director
/s/ Charles W. Coker Director
/s/ Richard L. Daugherty Director
/s/ William E. Graham, Jr. Director
/s/ Gordon C. Hurlbert Director
/s/ J. R. Bryan Jackson Director
/s/ Robert L. Jones Director
/s/ Estell C. Lee Director
/s/ J. Tylee Wilson Director
<TABLE>
<CAPTION>
EXHIBIT 12
CAROLINA POWER & LIGHT COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED DIVIDENDS COMBINED
AND RATIO OF EARNINGS TO FIXED CHARGES
-----------------------------------------------------------
Twelve Months Ended December 31,
-----------------------------------------------------------
1993 1992 1991 1990 1989
--------- --------- --------- --------- ---------
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Net income............................................. $ 346,496 $ 379,635 $ 376,974 $ 380,358 $ 376,067
Fixed charges, as below................................ 237,098 253,215 279,960 337,792 266,134
Income taxes, as below................................. 181,653 211,717 206,004 175,322 158,535
--------- --------- --------- --------- ---------
Total earnings, as defined........................... $ 765,247 $ 844,567 $ 862,938 $ 893,472 $ 800,736
========= ========= ========= ========= =========
Fixed Charges, as defined:
Interest on long-term debt............................. $ 205,182 $ 223,158 $ 233,268 $ 236,473 $ 220,840
Other interest......................................... 16,419 15,717 33,352 88,086 32,579
Imputed interest factor in rentals-charged
principally to operating expenses.................... 15,497 14,340 13,340 13,233 12,715
--------- --------- --------- --------- ---------
Total fixed charges, as defined...................... $ 237,098 $ 253,215 $ 279,960 $ 337,792 $ 266,134
========= ========= ========= ========= =========
Earnings Before Income Taxes............................. $ 528,149 $ 591,352 $ 582,978 $ 555,680 $ 534,602
========= ========= ========= ========= =========
Ratio of Earnings Before Income Taxes to Net Income...... 1.52 1.56 1.55 1.46 1.42
Income Taxes:
Included in operating expenses......................... $ 189,535 $ 210,266 $ 200,711 $ 156,934 $ 160,792
Included in other income:
Income tax expense (credit).......................... 392 5,885 9,686 (34,397) 175
Harris Plant carrying costs.......................... - 1,969 1,563 (3,539) 2,175
Other income, net.................................... - 58 25 21 15
Included in AFUDC - borrowed funds..................... - 2,060 2,694 3,081 4,513
Included in AFUDC - deferred taxes in nuclear
fuel amortization and book depreciation.............. (8,274) (8,521) (8,675) (8,869) (9,135)
Included in cumulative effect of change in
accounting for revenues.............................. - - - 62,091 -
--------- --------- --------- --------- ---------
Total income taxes................................... $ 181,653 $ 211,717 $ 206,004 $ 175,322 $ 158,535
========= ========= ========= ========= =========
Fixed Charges and Preferred Dividends Combined:
Preferred dividend requirements........................ $ 9,609 $ 14,798 $ 26,265 $ 29,771 $ 31,479
Portion deductible for income tax purposes............. (312) (321) (321) (321) (321)
--------- --------- --------- --------- ---------
Preferred dividend requirements not deductible......... $ 9,297 $ 14,477 $ 25,944 $ 29,450 $ 31,158
========= ========= ========= ========= =========
Preferred dividend factor:
Preferred dividends not deductible times ratio of
earnings before income taxes to net income......... $ 14,131 $ 22,584 $ 40,213 $ 42,997 $ 44,244
Preferred dividends deductible for income taxes...... 312 321 321 321 321
Fixed charges, as above.............................. 237,098 253,215 279,960 337,792 266,134
Total fixed charges and preferred dividends --------- --------- --------- --------- ---------
combined......................................... $ 251,541 $ 276,120 $ 320,494 $ 381,110 $ 310,699
========= ========= ========= ========= =========
Ratio of Earnings to Fixed Charges and Preferred
Dividends Combined..................................... 3.04 3.06 2.69 2.34 2.58
Ratio of Earnings to Fixed Charges ...................... 3.23 3.34 3.08 2.65 3.01
</TABLE>
Exhibit No. 23(a)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement No. 33-33520 on Form S-8, Registration Statement No.
33-5134 on Form S-3, Post-Effective Amendment No. 1 to Registration
Statement No. 33-38349 on Form S-3, and Registration Statement
No. 33-50597 on Form S-3 of Carolina Power & Light Company, of our
report dated February 14, 1994, appearing in this Annual Report on
Form 10-K of Carolina Power & Light Company for the year ended
December 31, 1993.
/s/ DELOITTE & TOUCHE
Raleigh, North Carolina
March 25, 1994
EXHIBIT NO. 23(b)
CONSENT OF EXPERT AND COUNSEL
Carolina Power & Light Company:
The statements of law and legal conclusions under Item 1.
Business and Item 3. Legal Proceedings in the Company's Annual
Report on Form 10-K for the year ended December 31, 1993 have
been reviewed by me and are set forth therein in reliance upon
my opinion as an expert.
I hereby consent to the incorporation by reference of such
statements of law and legal conclusions in Registration Statement
No. 33-33520 on Form S-8, Registration Statement No. 33-5134 on
Form S-3, Post-Effective Amendment No. 1 to Registration Statement
No. 33-38349 on Form S-3, and Registration Statement No. 33-50597
and the related Prospectuses, which are a part of such Registration
Statements.
/s/ Richard E. Jones
Senior Vice President, General Counsel
and Secretary
March 25, 1994
<PAGE>
March 25, 1994
Securities and Exchange Commission
450 5th Street, NW
Judiciary Plaza
Washington, DC 20549
Gentlemen:
Pursuant to the General Instructions to Form 10-K, please be
advised that the financial statements contained in the 1993 Form
10-K of Carolina Power & Light Company reflect the implementation
of Statements of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other Than
Pensions" and No. 109, "Accounting for Income Taxes." These
financial statements do not reflect any other changes from the
preceding year in accounting principles or practices or in the
method of applying any such principles or practices.
Sincerely yours,
/s/ Paul S. Bradshaw
Vice President and Controller
