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, 1994
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. Employer (Address of principal (Zip Code)
jurisdication of Identification No.) executive offices)
incorporation or
organization)
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 (Without Par Value) New York Stock Exchange
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. [X]
The aggregate market value of the voting stock held by non-affiliates at
February 28, 1995, was $4,414,882,793.
Shares of Common Stock (Without Par Value) outstanding at
February 28, 1995: 156,377,422.
DOCUMENTS INCORPORATED BY REFERENCE:
___________________________________
Portions of the Company's 1995 definitive proxy statement dated March 31, 1995,
are incorporated into Part III, Items 10, 11, 12 and 13 hereof.
TABLE OF CONTENTS
_________________
PART I Page
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . 3
General. . . . . . . . . . . . . . . . . . . . . . . 3
Generating Capability . . . . . . . . . . . . . . . 4
Interconnections with Other Systems . . . . . . . . 6
Competition and Franchises . . . . . . . . . . . . 8
Construction Program . . . . . . . . . . . . . . . . 10
Financing Program . . . . . . . . . . . . . . . . 10
Retail Rate Matters. . . . . . . . . . . . . . . . . 12
Wholesale Rate Matters . . . . . . . . . . . . . . . 14
Environmental Matters . . . . . . . . . . . . . . . 15
Nuclear Matters . . . . . . . . . . . . . . . . . . 19
Fuel . . . . . . . . . . . . . . . . . . . . . . . 25
Other Matters . . . . . . . . . . . . . . . . . . . 27
Operating Statistics . . . . . . . . . . . . . . . . 29
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . 30
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . 31
Item 4. Submission of Matters to a Vote of Security Holders. 31
Executive Officers of the Registrant . . . . . . . . 32
PART II
Item 5. Market for the Registrant's Common Equity and Related
Shareholder Matters . . . . . . . . . . . . . . . . 34
Item 6. Selected Financial Data . . . . . . . . . . . . . . 35
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation . . . . . . . . . 36
Item 8. Financial Statements and Supplementary Data . . . . 44
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . 68
PART III
Item 10. Directors and Executive Officers of the Registrant . 68
Item 11. Executive Compensation . . . . . . . . . . . . . . . 68
Item 12. Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . 68
Item 13. Certain Relationships and Related Transactions . . . 68
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . 69
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 7,812 employees at December 31,
1994. 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 2 electric membership corporations (North Carolina Electric
Membership Corporation, which has 17 members, and French Broad
Electric Membership Corporation). At December 31, 1994, the Company
was furnishing electric service to approximately 1,057,000
customers.
3. SALES. During 1994, 31.8% of operating revenues was
derived from residential sales, 20.7% from commercial sales, 25.8%
from industrial sales, 17.4% from resale sales and 4.3% 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, 1994, average revenues per
kilowatt-hour (kWh) sold to residential, commercial and industrial
customers were 8.22 cents, 6.85 cents and 5.29 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
____ _______ ______ _______
1990 11,957 $ 995.01 8.32 cents
1991 12,472 1,040.70 8.34
1992 12,396 1,029.82 8.31
1993 13,167 1,090.16 8.28
1994 12,559 1,032.00 8.22
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 1992 increased by 3.1%,
for 1993 increased by 3.8%, and for 1994 increased by 5.8%, as
compared with the preceding year. The Company currently projects a
2.1% 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 1992-1994 were 57.4%, 59.0% and 56.0%, respectively.
The Company forecasts capacity margins of 13.6% over anticipated
system peak load for both 1995 and 1996. 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 1994. Over the next ten
years, system sales growth is forecasted to average 2.1% per year
and annual growth in system peak demand is projected to average
2.1%. The Company's generation additions schedule, which is updated
annually, reflects no additions until 1997, 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 $72
million. The generation additions schedule also includes generation
additions of up to 1,200 MW in combustion turbine generating units
to be added adjacent to the Company's Lee Steam Electric Plant in
Wayne County, North Carolina. In December 1994, the Company filed
preliminary plans with the North Carolina Utilities Commission
(NCUC) and the North Carolina Division of Environmental Management
to construct the ten new combustion turbine generating units at the
Wayne County site. The units are nominally rated at 100-200 MW each
and would represent a capital investment of approximately $300
million. The units would primarily be used during periods of summer
and winter peak demands. The schedule, which is subject to change,
calls for construction to begin in 1996, with the units beginning
commercial service between 1998 and 2000. In addition to this
proposed project, the generation addition schedule provides for the
addition of 1,400 MW in combustion turbine capacity, and 900 MW
combined cycle capacity at undesignated sites over the period 2000
to 2007, 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). On September 17,
1993, the Company and NCEMC filed a settlement agreement (Settlement
Agreement) with the FERC for approval. Another settlement agreement
regarding various environmental issues was filed with the FERC for
approval on February 16, 1994. Through a series of orders, the FERC
approved final settlement of this proceeding, and on November 4,
1994, issued the Company a forty year license to operate its Walters
Hydroelectric Plant. The license contains numerous conditions for
the ongoing operation of the plant, including recreational
enhancements, environmental monitoring and funding, and cultural
resource management. Issuance of the license for the Walters Plant
by the FERC and the Company's acceptance of the license terms
conclude this licensing proceeding.
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. 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. A settlement agreement resolving issues related
to the purchase power contract and other matters between the Company
and NCEMC was filed with the FERC for approval on September 17,
1993. See ITEM 1, "Generating Capability," paragraph 4. 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. Purchases
under this agreement, including transmission use charges, totaled
$62.9 million in 1994. On January 20, 1995, the FERC issued an
order approving a final settlement agreement in this docket, thereby
accepting the purchase power contract and making it no longer
subject to refund.
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 through 2010. 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. Purchases under this
agreement, including transmission use charges, totaled $61.9 million
in 1994.
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.
5. POWER AGENCY. The Company is obligated to purchase a
percentage of Power Agency's ownership capacity of and energy from
the Mayo Plant and the Harris Plant through 1997 and 2007,
respectively. The estimated minimum annual payments for these
purchases, which reflect capital-related capacity costs, total
approximately $27 million. Other costs of such purchases are
primarily demand-related production expenses, fuel and
energy-related operation and maintenance expenses. Purchases under
the agreement with Power Agency totaled $60.4 million in 1994.
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 wholesale
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 National Energy Policy Act (Energy Act)
changed certain underlying federal policies governing wholesale
generation and the sale of electric power. In effect, the Energy
Act partially deregulated the wholesale electric utility industry at
the generation level by allowing non-utility generators to build and
own generating plants for both cogeneration and sales to utilities.
Provisions of the Energy Act that most affected the utility industry
were the establishment of exempt wholesale generators, and the
authority given the FERC to permit wholesale transfer, or wheeling,
of power over the transmission lines of other utilities. 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. Although the Energy Act prohibits the
FERC from ordering retail wheeling--transmitting power on behalf of
another producer to an individual retail customer--some states are
considering changing their laws or regulations to allow retail
electric customers to buy power from suppliers other than the local
utility. The Company believes changes in existing laws in both
North Carolina and South Carolina would be required to permit retail
wheeling in the Company's retail jurisdictions. The South Carolina
Public Service Commission (SCPSC) has ruled that it would be a
violation of its past practice and of South Carolina's territorial
assignment statute to require utilities to engage in retail
wheeling. On February 8, 1995, the Carolina Utility Consumers
Association, Inc., a group of industrial customers doing business in
North Carolina, filed a petition with the NCUC requesting that the
NCUC hold a generic hearing to examine whether retail wheeling would
be in the public interest, how it could be implemented in North
Carolina and whether it could be implemented without changing state
law. The NCUC has issued an order inviting interested parties to
comment on the petition. The Company cannot predict the outcome of
this matter.
The possible migration of some of the Company's load due to
increased competition in the electric industry has created greater
planning uncertainty and risks for the Company. The Company has
been addressing these risks by securing 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 and 1994 the Company signed long-term agreements
with almost all of the Company's wholesale customers, representing
approximately 15% of the Company's operating revenues. In the
industrial sector, the Company is working to meet the energy needs
of its customers. In 1994, the Company reached an agreement with
its largest industrial customer that ensures the Company will serve
that customer through 2001. Other elements of the Company's
strategy for responding to the changing market for electricity
include promoting economic development, implementing new market
strategies, increasing the focus on managing and reducing costs, and
consequently, avoiding future rate increases.
c. In April 1994, the North Carolina Public Staff (Public
Staff), which represents the using and consuming public in matters
before the NCUC, filed a petition with the NCUC proposing interim
guidelines to apply to requests for self-generation deferral rates.
By order issued May 13, 1994, the NCUC established a docket (Docket
No. E-100, Sub 73) to consider the proposed self-generation deferral
rates guidelines, and dispersed energy facilities and economic
development rates. Initial comments were filed by the Company and
other interested parties on June 13, 1994, and reply comments were
filed on June 27, 1994. In response to the parties' comments, on
July 1, 1994, the Public Staff filed modifications to the proposed
self-generation deferral rate guidelines. By order issued July 21,
1994, the NCUC, with limited exceptions, approved and adopted the
modified self-generation deferral rate guidelines proposed by the
Public Staff. The guidelines allow the Company to adjust rates to
retain certain loads for which self-generation is feasible. In this
order, the NCUC also requested that additional comments regarding
economic development rates be filed by October 21, 1994, and stated
that the issue of dispersed energy facilities would be addressed on
a case by case basis. On November 28, 1994, the NCUC issued an
order adopting interim guidelines for economic development rates.
These guidelines allow the Company to adjust its rates to attract
new industrial load that would not have been served in the absence
of such rates, provided certain criteria are satisfied. The NCUC
will review the economic development rate guidelines after one year.
d. On September 17, 1993, the Company and NCEMC filed with
the FERC a Power Coordination Agreement (PCA) and an Interchange
Agreement (IA), both dated August 27, 1993. The PCA and IA, which
were both filed in connection with the Walters Hydroelectric Plant
relicensing proceeding (Project Nos. 432-004 and 2748-000), set
forth explicitly the future relationship between the Company and
NCEMC, and establish a framework under which they will operate. See
ITEM 1, "Generating Capability," paragraph 4 for further discussion
of the Walters relicensing proceeding. The FERC granted final
approval of the PCA and the IA in June 1994. 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.
The PCA allows NCEMC to assume responsibility for up to 200 MW of
its load from the Company's system between January 1, 1996 and
December 31, 2000. On and after January 1, 1996, the Company
expects to continue to supply not less than 1000 MW of electricity
to NCEMC until at least December 31, 2000. NCEMC's board of
directors has voted to award a power-supply contract for 200 MW to
another supplier beginning on January 1, 1996. If approved by the
FERC, the contract will displace 200 MW of baseload capacity that
NCEMC currently purchases from the Company. Load reductions beyond
the year 2000 are subject to specific limits and require five years'
advance notice. On November 4, 1994, NCEMC issued two requests for
proposals (RFP) to provide up to 225 MW per year (for a minimum of
ten years) of baseload power NCEMC would otherwise purchase from the
Company beginning in 2001, 2002 and 2003. On March 3, 1995, the
Company submitted a bid in response to each RFP to compete for this
load. The Company cannot predict the outcome of these matters.
e. By order issued September 30, 1994, the SCPSC established
a docket for a generic proceeding to consider the effect of electric
and natural gas demand side management programs on competition
between the two types of utilities. The order states that the
outcome of such a proceeding will not apply to the 1995 integrated
resource plans that electric utilities file with the SCPSC. The
filing of testimony and scheduling of hearings in the SCPSC
proceeding have been indefinitely postponed. The NCUC established
a docket for a similar generic proceeding (Docket No. E-100, Sub 71)
by order dated February 24, 1994. The NCUC's hearings on this
matter concluded on December 20, 1994, but the NCUC has not issued
an order in that proceeding. The Company cannot predict the outcome
of these matters.
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 1994 the Company expended
approximately $386 million for capital requirements. The Company
revised its capital program in 1994 as part of its annual business
planning process. Capital requirements, including anticipated
construction expenditures for plant modifications, for the years
1995 through 1997 are set forth below. These estimates include
Clean Air Act compliance expenditures of approximately $117 million,
and generating facility addition expenditures of approximately $287
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)
1995 1996 1997 TOTAL
____ ____ ____ _____
Construction Expenditures $358 $445 $527 $1,330
Nuclear Fuel Expenditures 99 77 71 247
AFUDC (19) (25) (34) (78)
____ ____ ____ ______
Net expenditures (a) 438 497 564 1,499
Long-Term Debt Maturities 275 105 100 480
____ ____ ____ ______
TOTAL $713 $602 $664 $1,979
==== ==== ==== ======
(a) Reflects reductions of approximately $29 million, $28 million and
$21 million for 1995, 1996 and 1997, 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. External funding requirements,
which do not include early redemptions of long-term debt or
redemptions of preferred stock, are expected to approximate $417
million in 1995 and $120 million in 1997. These funds will be
required for construction, long-term debt maturities and general
corporate purposes, including the repayment of short-term debt.
Based on the Company's most recent estimate of capital requirements,
the Company does not expect to have external funding requirements in
1996. 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.
33-57835), enabling the Company to issue an aggregate of $450
million principal amount of First Mortgage Bonds, and an additional
$250 million combined aggregate principal amount of First Mortgage
Bonds and/or unsecured debt securities of the Company.
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 1994 and early
1995 included:
- 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 issuance
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.
- The issuance on May 12, 1994, of $72.6
million principal amount of First Mortgage
Bonds, Pollution Control Series L, Wake
County Pollution Control Revenue Refunding
Bonds (Carolina Power & Light Company
Project) Series 1994A due May 1, 2024 and
$50 million principal amount of First
Mortgage Bonds, Pollution Control Series M,
Wake County Pollution Control Revenue
Refunding Bonds (Carolina Power & Light
Company Project) Series 1994B due May 1,
2024, for a total net proceeds of $122.6
million. The proceeds from the issuances
were used for the redemption on June 15,
1994 of $122.6 million First Mortgage
Bonds, Pollution Control Series G, Wake
County Pollution Control Revenue Bonds
(Carolina Power & Light Company) Series
1984A due June 15, 2014, at 100% of the
principal amount of such bonds plus accrued
interest to the date of redemption.
- The remarketing on July 1, 1994, of First
Mortgage Bonds, Pollution Control Series J,
New Hanover County Pollution Control
Revenue Bonds (Carolina Power & Light
Company Project) Series 1984 due June 15,
2014 and First Mortgage Bonds, Pollution
Control Series K, Chatham County Pollution
Control Revenue Bonds (Carolina Power &
Light Company Project) Series 1984 due June
15, 2014, at a fixed rate of 6.30% to June
15, 2014.
- The issuance on December 28, 1994, of $50
million principal amount of First Mortgage
Bonds, Secured Medium-Term Notes, 7.9%
Series C, due December 27, 1996 for net
proceeds of $49.8 million. The proceeds
from the issuance 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.
- The issuance on January 24, 1995, of $60
million principal amount of First Mortgage
Bonds, Secured Medium-Term Notes, 7.75%
Series C, due January 24, 1997 for net
proceeds of $59.7 million. The proceeds
were used to reduce the outstanding balance
of commercial paper and other short-term
debt and for other general corporate
purposes.
4. REDEMPTIONS/RETIREMENTS. Redemptions and retirements
during 1994 and early 1995 included:
- The redemption on March 24, 1994, of $17.5
million principal amount of First Mortgage
Bonds, 8 1/2% Series due October 1, 2007,
at 100.25% of the principal amount of such
bonds plus accrued interest to the date of
redemption.
- The partial redemption on March 24, 1994,
of $77.4 million principal amount of First
Mortgage Bonds, 8 1/8% Series, due November
1, 2003, at 100.61% of the principal amount
of such bonds plus accrued interest to the
date of redemption.
- The retirement on April 15, 1994, of $50
million principal amount of First Mortgage
Bonds, 5.85% Secured Medium-Term Notes,
Series B, which matured on that date.
- The redemption on June 15, 1994, of $122.6
million principal amount of First Mortgage
Bonds, Pollution Control Series G, Wake
County Pollution Control Revenue Bonds
(Carolina Power & Light Company Project)
Series 1984A due June 15, 2014, at 100% of
the principal amount of such bonds plus
accrued interest to the date of redemption.
- The retirement on January 1, 1995, of $125
million principal amount of First Mortgage
Bonds, 5.20% Series, which matured on that
date.
5. CREDIT FACILITIES. The Company's credit facilities
presently total $307.9 million, consisting of long-term agreements
totaling $207.9 million and a $100 million short-term agreement.
RETAIL RATE MATTERS
___________________
1. GENERAL. The Company is subject to regulation in North
Carolina by the NCUC and in South Carolina by the 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 cost effective manner, giving due regard to system
reliability and safety. The Company is required to file its
Integrated Resource Plan (IRP) with the NCUC and the SCPSC once
every three years. 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. The next IRP is scheduled to be filed with the NCUC on or
before April 28, 1995, and with the SCPSC on or before June 30,
1995.
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 currently has no
deferred costs related to DSM programs.
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 1995 North
Carolina fuel case hearing is scheduled to begin on August 1, 1995.
The Company cannot predict the outcome of this matter.
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 1995 South Carolina fuel case was held on March 15,
1995 (Docket No. 95-001-E). On March 21, 1995, the SCPSC approved
a fuel factor of 1.34 cents/kWh for the six month period April 1
through September 30, 1995.
6. AVOIDED COST PROCEEDINGS. The NCUC has opened Docket No.
E-100, Sub. 75 for its biennial proceeding to establish the avoided
cost rates for all electric utilities in North Carolina. Avoided
cost rates are intended to reflect the costs that utilities are able
to "avoid" by purchasing power from qualifying facilities. The
Company has proposed to lower its avoided cost rates. The hearings
in this docket concluded on March 9, 1995, but the NCUC has not
issued an order in this proceeding. The Company cannot predict the
outcome of this matter.
7. 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. The Company cannot predict the outcome of this matter.
With regard to the SCPSC proceeding, the Company filed initial
written comments on March 1, 1994, and reply comments were due on
April 15, 1994. By order dated June 22, 1994, the SCPSC approved a
stipulation entered into by the Company and the other parties to the
proceeding. In that stipulation, the parties agreed that standards
similar to those of Section 111 of the Energy Act have already been
implemented to the degree necessary, and therefore, the specific
standards of Section 111 do not need to be adopted by the SCPSC in
order to implement the purposes of PURPA.
8. MISCELLANEOUS. There are two additional dockets pending
in the NCUC. The first docket (Docket No. M-100, Sub 124) involves
the proper interpretation of North Carolina General Statute Section
62-140(c) which controls the offer or payment of consideration by a
public utility to secure the installation or adoption of the use of
the utility's services. This docket will be decided based upon the
written comments of the parties. The second docket (Docket No. E-
100, Sub 71) explores the issue of what factors the NCUC should
consider when evaluating the reasonableness of proposed DSM
programs. Hearings in the second docket have been completed, but
the NCUC has not yet issued an order in the proceeding. The Company
cannot predict the outcome of these matters.
WHOLESALE RATE MATTERS
______________________
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. At the present time,
the Company has no wholesale rate matters pending at the FERC.
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 1995 through 1997, 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 was not required to take action to comply with
the Act's Phase I requirements, which had to 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 2007 by utilizing lower sulfur coal and sulfur dioxide
emission allowances. The Company purchased emission allowances
under the Environmental Protection Agency's (EPA) emission allowance
trading program in 1993 and 1994. Each sulfur dioxide emission
allowance will allow a utility to emit one ton of sulfur dioxide.
The Company estimates that the total capital cost to comply with
Phase II of the Act will approximate $273 million during the period
1995 through 1999 and an additional $272 million during the period
2000 through 2007. 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 $18 million for the period 1995 through 1999,
$35 million for the period 2000 through 2006 and by $24 million
annually beginning in 2007. Additionally, fuel costs are expected
to increase by a total of approximately $277 million for the period
2000 through 2006, and by approximately $62 million annually
beginning in 2007. The Company expects these increased fuel costs
to be recoverable through applicable fuel adjustment statutes.
Actual plans for compliance with the Act's requirements have not
been finalized and the amount required for capital expenditures and
for increased operating, maintenance and fuel expenditures cannot be
determined with certainty at this time. The financial impact of
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, the Commonwealth of
Kentucky, which owns the site, and the federal agencies in an effort
to reach global settlement. It appears that the Steering Committee
and eleven federal agencies will perform the Initial Remediation
Phase and the Commonwealth of Kentucky will perform the Balance of
Remediation Phase pursuant to a Consent Decree with 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.
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 0.8% 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 remediation began in May 1994, and is
scheduled to be completed in early 1995. Final grading, seeding and
demobilization is scheduled to be conducted in March 1995. It is
currently estimated that cleanup will cost approximately $23.7
million. There is currently over 90% participation by the PRPs in
the site cleanup. 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 future costs
associated with this site, if any, would 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 the 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 (a group of PRPs with respect to the
Elliot's site), 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
negotiated 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. Once
the Elliot's Auto Parts PRP Committee receives final approval from
the EPA for its final report, the Company, based on its negotiations
with the Elliot's Auto Parts PRP Committee, has agreed to (i) pay
$90,000 to the Elliot's Auto Parts PRP Committee towards the $2.7
million previously expended to remediate the site; (ii) pay 3.4%
toward any future expense incurred in connection with the site; and
(iii) execute an Administrative Order on Consent with the EPA.
Although the Company cannot predict the outcome of this matter, it
does not anticipate that future costs associated with this site, if
any, would 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). The Company estimates that to date its
costs associated with completion of the Removal Work Plan total
approximately $12,000. 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 Company recently joined the Seaboard Group II (a
group of PRPs formed to conduct additional work at the Seaboard
site). Cost estimates for the additional work are not available.
Although the Company cannot predict the outcome of this matter, it
does not anticipate that costs associated with this site would 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.
On April 13, 1994, Crown Cork & Seal Company, Inc. and
Clark Equipment Co. filed a motion to add the Company as a defendant
in an ongoing lawsuit concerning the Macon-Dockery site, which was
filed in the United States District Court for the Middle District of
North Carolina in Greensboro, North Carolina (Civil Action No.
3:92CV00744) on December 4, 1992. The lawsuit seeks to recover
costs incurred in undertaking the Remedial Investigation Feasibility
Study and the Remedial Design for the Macon-Dockery site. On July
6, 1994, the United States District Court for the Middle District of
North Carolina granted the motion Crown Cork & Seal Company and
Clark Equipment Co. filed seeking to name the Company as a defendant
in the lawsuit. On September 30, 1994, the Company filed an Answer
denying any liability to Crown Cork & Seal Company and Clark
Equipment Co. Although the Company cannot predict the outcome of
this matter, it does not anticipate that costs associated with this
site would be material to the results of operations of the Company.
g. 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 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 this
regard, the Company, along with other entities alleged to be former
owners and operators of MGP sites in North Carolina, is
participating in a cooperative effort with the North Carolina
Department of Environment, Health and Natural Resources, Division of
Solid Waste Management (DSWM) to establish a uniform framework for
addressing those sites. 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 PRPs. To date, the Company has not entered into any
such orders.
The Company has recently been approached by another
North Carolina public utility concerning a possible cost-sharing
arrangement with respect to the investigation and, if necessary,
remediation of four MGP sites. The Company is currently engaged in
discussions with the other utility regarding this matter. Based on
current cost estimates provided by that utility, the Company does
not believe its portion of costs associated with the investigation
and remediation of these sites, if any, would be material to the
results of operations of the Company.
In addition, the Company and a current owner of property
that was the site of one MGP owned by Tide Water Power Company (Tide
Water Power), which merged into the Company in 1952, have entered
into an agreement to share the cost of investigation and remediation
of this site. The Company has also been approached by a North
Carolina municipality that is the current owner of another MGP site
that was formerly owned by Tide Water Power. The Company is engaged
in discussions with that municipality concerning a possible cost-
sharing arrangement with respect to the investigation and, if
necessary, the remediation of that site. Due to the uncertainty
concerning potential environmental harm and the full extent to which
remedial action will be required at the two sites formerly owned by
Tide Water Power, the total cost of investigating and remediating
these sites is not determinable at this time.
The Company is continuing its investigation regarding the
identities of parties connected to individual MGP sites, the
relative relationships of the Company and other parties to those
sites, and the degree, if any, to which the Company should undertake
shared voluntary efforts with others at individual sites. Except as
noted above, 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.
4. OTHER ENVIRONMENTAL MATTERS. 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. In November 1994, the Company was asked by DEM
to expand its assessment to determine whether the No. 2 fuel oil
spill had migrated off-site. Off-site contamination was confirmed;
however, it is not clear that the Company is responsible for such
off-site contamination. The Company will discuss this matter with
DEM. Although the Company cannot predict the outcome of this
matter, it believes that any remediation expense would not exceed
$100,000 annually.
5. ENVIRONMENTAL ACCRUAL. In 1994, the Company accrued a
liability for the estimated costs associated with investigation and
remediation activities for certain MGP sites and for sites other than MGP
sites. This accrual was not material to the results of operations of the
Company.
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.b.
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 1995,
1996 and 1997 are expected to total approximately $72 million, $58
million and $34 million, respectively (including AFUDC).
2. SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE.
The Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) provides the
framework for development by the federal government of interim
storage and permanent disposal facilities for high-level radioactive
waste materials. The Nuclear Waste 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 Nuclear Waste 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, 1994, sufficient
on-site spent nuclear fuel storage capability is available for the
full-core discharge of Brunswick Unit No. 1 through 1995, 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, dry
storage may be necessary in conjunction with the decommissioning of
the units. 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. Due to the success of the Company's
shipping efforts to date, however, the Company has requested that
the NRC suspend review of the Company's license application pending
notification by the Company of its desire to continue the
application process. The Company cannot predict the outcome of this
matter.
As required by the Nuclear Waste Act, the Company entered
into a contract with the DOE under which the DOE agreed to 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 reduced the Company's quarterly payment.
Overpayments, with interest, were refunded in the form of credits
over the period 1992 through 1994. 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. When shipments to the existing regional compact site
cease on December 31, 1995, present projections indicate that
existing on-site storage facilities at the Company's nuclear plants
are sufficient to provide approximately one year 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 a portion of
decommissioning expense into the Trust.
With regard to the Company's recovery through rates of
nuclear decommissioning costs, in the Company's retail
jurisdictions, provisions for nuclear decommissioning costs were
approved by the NCUC and the SCPSC in the Company's 1988 general
rate cases, and were based on site-specific estimates that included
the costs for removal of all radioactive and other structures at the
site. In the wholesale jurisdiction, the provisions for nuclear
decommissioning costs are based on amounts agreed upon in applicable
rate settlements. Decommissioning cost provisions, which are
included in depreciation and amortization, were $29.5 million in
1994, $34.0 million in 1993 and $27.1 million in 1992. Accumulated
decommissioning costs, which are included in accumulated
depreciation, were $252.7 million at December 31, 1994, and $221.6
million at December 31, 1993, and include amounts retained
internally and amounts funded in the Trust. The balance of the
Trust, which is included in miscellaneous other property and
investments, was $67.6 million at December 31, 1994, and $44.5
million at December 31, 1993. Trust earnings, which increase the
trust balance with a corresponding increase in accumulated
decommissioning, were $1.5 million in 1994, $1.2 million in 1993 and
$.8 million in 1992. Based on the site-specific estimates discussed
below and using an assumed after-tax earnings rate of 8.5% and an
assumed cost escalation rate of 4%, current levels of rate recovery
for nuclear decommissioning costs are adequate to provide for
decommissioning of the Company's nuclear facilities.
b. The Company's most recent site-specific estimates of
decommissioning costs were developed in 1993 using 1993 cost
factors, and are based on prompt dismantlement decommissioning,
which reflects the cost of removal of all radioactive and other
structures currently at the site, with such removal occurring
shortly after operating license expiration. See paragraph 5 below
for expiration dates of operating licenses. These estimates, in
1993 dollars, are as follows: $257.7 million for Robinson Unit No.
2; $235.4 million for Brunswick Unit No. 1; $221.4 million for
Brunswick Unit No. 2; and $284.3 million for the Harris Plant.
These estimates are subject to change based on a variety of factors,
including, but not limited to, cost escalation, changes in
technology applicable to nuclear decommissioning, and changes in
federal, state or local regulations. The cost estimates exclude the
portion attributable to 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.
c. The Financial Accounting Standards Board has added a
project to its agenda regarding the electric utility industry's
current accounting practices related to decommissioning costs. Any
changes to these practices could affect such items as: 1) when the
decommissioning obligation is recognized, 2) where balances of
accumulated decommissioning costs are recorded, 3) where income
earned on external decommissioning trust balances is recorded and 4)
the levels of annual decommissioning cost provisions. The Financial
Accounting Standards Board is in the early stages of this project,
and consequently, it is uncertain what impacts, if any, this project
may have on the Company's accounting for decommissioning costs.
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 was completed in 1994. This documentation will remain at the
plants and will be provided to the NRC upon request.
7. OTHER NUCLEAR MATTERS.
a. 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 Energy Institute (formerly 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.
b. 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. Based on those results, potential enhancements for the
Robinson Plant were evaluated and several enhancements were made to
the Robinson Plant. These changes had insignificant financial
and operational impacts. 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), which will be completed for all three
plants and submitted to the NRC in 1995.
c. 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 Brunswick Plant outage
that began in April 1992. 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. The Company commenced startup of Unit No. 1 on
February 1, 1994, and Unit No. 1 was returned to normal operation on
February 23, 1994, after successfully completing extensive startup
testing. In July 1993, the Company also determined that the
Brunswick Unit No. 2 shroud had minor crack indications which did
not compromise the safety or operation of the Unit. Shroud
modifications, similar to those performed on Unit No. 1, were
successfully completed on Unit No. 2 during the spring 1994
refueling outage, and Unit No. 2 resumed generating electricity on
June 30, 1994. Costs associated with the shroud modifications were
not 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. The petitioners failed to provide the NRC or
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. On October 19, 1994, the
Director of the NRC's Office of Nuclear Reactor Regulation issued a
decision which granted the petitioners' request for an NRC
investigation, but concluded that no substantial health and safety
issue remains that would warrant institution of further proceedings.
The NRC Commissioners declined to review the decision. Thus, the
decision became the NRC's final action on November 14, 1994. The
petitioners did not file an appeal with the United States Court of
Appeals by the February 13, 1995 deadline.
d. 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, a 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. In early February 1994,
the Company satisfied the conditions of the NRC's November 19, 1993
Confirmatory Action letter, and returned Robinson Unit No. 2 to
service on March 21, 1994 under a power ascension plan. 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. On May 9, 1994, the NRC issued a Severity Level IV
Notice of Violation (the next to the lowest severity level)
concluding that this situation involved noncompliance with certain
NRC requirements. The NRC did not propose a civil penalty in
connection with this matter. In a letter to the NRC dated June 8,
1994, the Company acknowledged that the violations had occurred,
clarified the events surrounding the occurrences, and described the
corrective actions that had been taken to address the situation.
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 proposed penalty was reduced to
$37,500 due to the Company's comprehensive performance in analyzing
the root cause of the diesel generator problem. On April 13, 1994,
the Company submitted a written response to the Notice of Violation
and Proposed Imposition of Civil Penalty that the NRC issued in
connection with the degradation of the Robinson Unit No. 2 diesel
generators, and paid the assessed $37,500 civil penalty.
On February 8, 1994 the NRC issued its Systematic
Assessment of Licensee Performance 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 had 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.
The Company received a letter, dated May 6, 1994, from
the NRC regarding an apparent violation of NRC requirements related
to inattention to licensed duties which was identified at the
Company's H. B. Robinson Plant. An enforcement conference between
the Company and the NRC was held on May 16, 1994, to discuss this
matter. On May 30, 1994, the NRC issued a Severity Level IV Notice
of Violation to the Company in connection with this matter, but did
not propose a civil penalty. In a letter to the NRC dated June 29,
1994, the Company acknowledged that the violation had occurred and
described the corrective actions that had been taken to address the
occurrence.
The NRC report regarding inspections conducted at the
Robinson Plant during the period May 22 through June 24, 1994,
identified certain activities, which occurred in January 1994 that
might have violated certain NRC requirements. The activities
related to the failure to take adequate corrective action on issues
identified by a contractor, inadequate testing of ventilation
equipment, and inadequate corrective actions on a design concern
involving an isolation valve. An enforcement conference between the
Company and the NRC was held on July 26, 1994 to determine whether
a violation had occurred and if so, to assess the significance of
the violation. By letter dated August 30, 1994, the NRC issued a
Notice of Violation and Imposition of Civil Penalty in the amount of
$75,000 involving the Company's testing of ventilation equipment at
its H.B. Robinson Plant. The Notice also indicated that activities
related to the adequacy of corrective action on issues identified by
a contractor and the adequacy of corrective actions on a design
concern involving an isolation valve constituted violations of NRC
requirements; however, no civil penalty was assessed in connection
with those violations. By letter dated September 29, 1994, the
Company responded to the Notice of Violation and paid the assessed
penalty.
In November 1994, the NRC proposed a $100,000 civil
penalty for noncompliance with NRC requirements at the Robinson
Plant. During a plant cooldown on February 26, 1994, the plant
exceeded a technical specification limit. At one point during the
process of the plant shutdown, the reactor's pressurizer was allowed
to cool down at a rate that is higher than the specified maximum
rate. After extensive analysis, the Company determined that the
structural integrity of the pressurizer had not been negatively
affected and neither had the useful life of any reactor component.
The Company has implemented additional administrative controls to
monitor the pressurizer throughout the cooldown process, and has
conducted additional training to ensure proper monitoring. The NRC
concurs with the corrective actions being taken by the Company. The
Company paid the assessed penalty on December 22, 1994.
e. The Company is insured against public liability for a
nuclear incident up to $8.9 billion per occurrence, which is the
maximum limit on public liability claims pursuant to the Price-
Anderson Act. The $8.9 billion coverage includes $200 million
primary coverage and $8.7 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 1991 through 1995 is set forth
below:
1991 1992 1993 1994 1995
____ ____ ____ ____ ____
(estimated)
Fossil 47% 56% 54% 43% 46%
Nuclear 41 27 31 42 41
Purchased Power 10 15 13 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 86% of its
coal burn requirements in 1995. During 1993 and 1994, the Company
obtained approximately 73% (7,198,000 tons), and 93% (8,120,220
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 1996 to 2006. During 1994, the
Company maintained from 40 to 92 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 which continue beyond the effective date of the
second phase of the Act. See ITEM 1, "Environmental Matters,"
paragraph 2. The Company purchased approximately 2,650,000 tons of
coal in the spot market during 1993 and 1,690,000 tons in 1994. The
Company's contract coal purchase prices during 1994 ranged from
approximately $23.19 to $40.63 per ton (F.O.B. mine adjusted to
12,000 Btu/lb.). The average cost (including transportation costs)
to the Company of coal delivered for the past five years is as
follows:
Year $/Ton Cents/Million BTU
____ _____ _________________
1990 45.88 183
1991 47.40 190
1992 43.25 174
1993 43.10 172
1994 43.36 174
3. OIL. The Company uses No. 2 oil primarily for its
combustion turbine units, which are used for emergency backup and
peaking purposes, and for boiler start-up and flame stabilization.
The Company burned approximately 9.1 million and 12.6 million
gallons of No. 2 oil during 1993 and 1994, 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
1.8% of the Company's total burned fuel cost. In 1994, No. 2 oil,
natural gas and propane accounted for 1.9% of the Company's 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. Existing 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 1995, and the
Harris Plant through 1996. The Company currently has contracts for
the ongoing procurement of raw materials and services for its
nuclear units through the years shown below:
Raw Materials And Services
___________________________________________________
Unit Uranium Conversion Enrichment Fabrication
____ _______ __________ __________ ___________
Robinson No. 2 1995 1995 2000 2000
Brunswick No. 1 1995 1995 2000 1998
Brunswick No. 2 1995 1995 2000 1998
Harris Plant 1996 1995 2000 1999
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. At December 31,
1994, the Company had recorded a liability of $67.4 million
representing its estimated share of the contributions and is
recovering this expense as a component of fuel cost.
6. PURCHASED POWER. In 1994 the Company purchased 6,710,346
MWh or approximately 13% of its energy requirements and had
available 2,840 MW of firm purchased capacity under contract at the
time of peak load. 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. On November 30, 1994, the Company
submitted the independent consultant's report to the FERC regarding
the stability of the dam at the Walters Project. The independent
consultant concluded that the Walters dam has adequate structural
stability and reserve capacity to resist both usual and unusual
loading conditions without failure and that structural remediation
is neither warranted nor recommended. While the Company does not
believe that there are any stability concerns that would be cause
for any imminent safety concerns, the FERC's review and analysis of
the consultant's report are pending. The consultant's final reports
regarding the Blewett and Tillery Hydroelectric Plants are not yet
completed. Depending on the outcome of these matters, 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 these
matters.
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.
3. STONE CONTAINER DISPUTE. On April 20, 1994, the Company
filed a Complaint with the FERC (Docket No. EL-94-62-000 and QF85-
102-005) and in the United States District Court for the Eastern
District of North Carolina in Raleigh, North Carolina (Civil Action
No. 5:94-CV-285-DI) claiming that the rate the Company pays for
power it purchases from Stone Container Corporation (Stone
Container) is invalid. The Company entered into a twenty-year
purchase power agreement with Stone Container in 1984, and in 1987
began receiving power from a cogeneration facility operated by Stone
Container in Florence, South Carolina. It is the Company's position
that when Stone Container elected to sell the facility's gross
output under a "buy all/sell all" option in 1991, the facility lost
its status as a "qualified facility" under PURPA and became a public
utility. As a result, the contract rate the Company pays for power
purchased from the facility is no longer valid, and a just and
reasonable rate should be established by the FERC under the Federal
Power Act. The Company will continue to purchase electricity from
Stone Container at the current contract rate pending the outcome of
this litigation. The Company cannot predict the outcome of this
matter.
4. TAX REFUND DISPUTE. On April 28, 1994, the Company
filed a Complaint against the U.S. Government in the United States
District Court for the Eastern District of North Carolina in
Raleigh, North Carolina (Civil Action No. 5:94-CV-313-BR3) seeking
a refund of approximately $188 million representing tax and interest
related to depreciation deductions the Internal Revenue Service
(IRS) previously disallowed for the years 1986 and 1987 on the
Company's Harris Plant. The Company maintains that under applicable
laws and regulations the Harris Plant was ready and available for
operation in 1986. The IRS has previously denied some of the
depreciation deductions on the Company's tax returns for the years
in question on the ground that in its view the plant was not placed
in service until 1987. The Company cannot predict the outcome of
this matter.
5. WOLF CREEK COAL DISPUTE. On November 4, 1994, the
Company filed a complaint against SMC Mining Company, Wolf Creek
Collieries Company and Kermit Coal Company (collectively, the
Sellers) in the United States District Court for the Eastern
District of North Carolina in Raleigh, North Carolina (Civil Action
No. 5:94-CV-846-BO(2)). The Sellers are all companies owned by
Ziegler Coal Holding Company (Ziegler). Under the terms of a 1971
contract, as amended, the Sellers are to supply the Company with
coal having certain qualities and characteristics from the Wolf
Creek mine (Wolf Creek) in Kentucky. The contract provides that the
Company has the right to refuse to accept further deliveries from
the Sellers if the coal they ship fails to meet the specification
for sulfur content for two consecutive months. During the months of
August and September 1994, the Sellers shipped to the Company Wolf
Creek coal that did not meet the sulfur specifications provided in
the contract. As a result of the Sellers' shipment of non-complying
coal, on November 4, 1994, the Company exercised its right to
suspend future shipments of coal from Wolf Creek until the Sellers
can give the Company reasonable assurance that future shipments will
meet the contract's specifications. The Complaint asks the court to
determine whether the dispute is subject to arbitration and that the
Company's suspension of future shipments from the Sellers was legal.
On November 4, 1994, the Sellers filed a Complaint against the
Company in the Circuit Court of Martin County, Kentucky (Civil
Action No. 94-CZ-00212), asking the court to restrain the Company
from refusing to accept future shipments of coal under the 1971
contract. On November 4, 1994, the court issued an ex parte
temporary restraining order (TRO) which prevents the Company, for
the time being, from refusing contract coal deliveries from Wolf
Creek. The Company removed the Kentucky state court action to the
United States District Court for the Eastern District of Kentucky.
On November 9, 1994 the Company filed in the Kentucky federal court
a response to the state court's TRO. The response sought to
dissolve the TRO, which would allow the Company to refuse coal
shipments from Wolf Creek until the dispute is settled. In its
response, the Company also moved for transfer of the case to the
United States District Court for the Eastern District of North
Carolina, which was subsequently granted. On December 1, 1994, a
federal District Court judge in Raleigh signed a consent order
establishing a three member panel to arbitrate the dispute. The
consent order provides that in the interim, Ziegler will ship only
coal that complies with the quality specifications as the Company
interprets the contract. The Company will receive a price
adjustment on the coal purchases if its view of the contract is
upheld. The arbitration, currently scheduled to begin in late March
1995 and conclude by the end of April 1995, will resolve the issues
of suspension and compliance with contractual quality standards.
The arbitration will also address other issues raised by the
Company, including two requests for adequate assurance of
performance under N.C. Gen. Stat. Section 25-2-609. The Company requested
in October 1994 that Sellers provide assurance that they were (1)
not sending the Company coal from sources (or mines) outside those
specified in the contract and (2) that it had adequate reserves to
meet its supply obligations under the contract. Whatever the
outcome of this dispute, the Company anticipates no problems in
ensuring sufficient coal supplies for its plants. The Company
cannot predict the outcome of this matter.
6. CARONET, INC. On November 29, 1994, the Company
established a wholly-owned subsidiary, CaroNet, Inc., and the
subsidiary joined a regional partnership led by BellSouth Personal
Communications, Inc. (BellSouth). On March 14, 1995 BellSouth won
its bid for a Federal Communications Commission (FCC) license for
the partnership to operate a Personal Communications Services (PCS)
system covering most of North Carolina and South Carolina, as well
as a small portion of Georgia. PCS, a wireless communications
technology, is expected to provide high-quality mobile
communications. Wireless technology could also support automated
meter reading, automated service connection and disconnection, and
control and monitoring of certain aspects of the Company's electric
transmission and distribution systems. BellSouth will transfer the
PCS license to the partnership. BellSouth will be general partner
and handle day-to-day management of the business.
<TABLE>
<CAPTION>
OPERATING STATISTICS
--------------------
Years Ended December 31
-----------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Energy supply (millions of kWh)
Generated - coal 21,001 25,807 25,196 20,240 19,954
nuclear 18,511 13,691 11,108 16,311 15,464
hydro 884 784 881 899 910
combustion turbines 67 84 54 6 34
Purchased 7,039 7,110 7,343 5,312 5,071
--------- --------- --------- --------- ---------
Total energy supply (Company share) 47,502 47,476 44,582 42,768 41,433
Power Agency share (a) 3,236 2,402 2,232 2,984 2,829
--------- --------- --------- --------- ---------
Total system energy supply 50,738 49,878 46,814 45,752 44,262
========= ========= ========= ========= =========
Average fuel cost (per million BTU)
Fossil $ 1.78 $ 1.75 $ 1.83 $ 1.90 $ 1.86
Nuclear fuel 0.47 0.46 0.45 0.48 0.47
All fuels 1.14 1.28 1.38 1.24 1.23
Energy sales (millions of kWh)
Residential 11,147 11,398 10,490 10,340 9,751
Commercial 8,690 8,548 8,060 7,907 7,538
Industrial 14,030 13,557 13,134 12,403 12,145
Government and municipal 1,263 1,248 1,213 1,181 1,138
Wholesale-standard rate schedules 1,983 2,144 2,042 1,989 1,992
Power Agency contract requirements 2,589 3,505 3,304 2,578 2,556
NCEMC 4,885 4,778 4,372 4,215 4,019
Other utilities 985 327 214 382 652
--------- --------- --------- --------- ---------
Total energy sales 45,572 45,505 42,829 40,995 39,791
Company uses, losses and unaccounted for 1,930 1,971 1,753 1,773 1,642
--------- --------- --------- --------- ---------
Total energy requirements 47,502 47,476 44,582 42,768 41,433
========= ========= ========= ========= =========
Customers billed
Residential 894,616 873,377 856,130 835,206 818,820
Commercial 155,349 151,242 146,858 143,782 140,983
Industrial 4,845 4,825 4,763 4,680 4,733
Government and municipal 2,302 2,214 2,262 2,239 2,212
Resale 12 26 26 31 28
--------- --------- --------- --------- ---------
Total customers billed 1,057,124 1,031,684 1,010,039 985,938 966,776
========= ========= ========= ========= =========
Operating revenues (in thousands)
Residential $ 915,986 $ 943,697 $ 871,469 $ 862,833 $ 811,429
Commercial 595,573 592,973 560,560 552,341 522,778
Industrial 741,662 744,016 720,413 695,221 681,773
Government and municipal 78,317 78,616 76,838 75,389 72,157
Wholesale-standard rate schedules 84,775 100,062 352,493 94,623 96,459
Power Agency contract requirements 115,262 134,258 140,623 118,498 134,360
NCEMC 266,733 253,859 237,857 235,692
Other utilities 33,789 11,232 4,834 12,304 22,433
Miscellaneous revenue 44,492 36,670 39,591 36,689 40,026
--------- --------- --------- --------- ---------
Total operating revenues $ 2,876,589 $ 2,895,383 $ 2,766,821 $ 2,685,755 $ 2,617,107
========= ========= ========= ========= =========
Peak demand of firm load (thousands of kW)
System 10,144 9,589 9,236 8,960 8,681
Company 9,642 9,107 8,745 8,471 8,134
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 3,064 3,105
Hydro plants 218 218 218 218 218
Purchased 1,596 1,289 890 892 785
--------- --------- --------- --------- ---------
Total system capability 11,209 10,902 10,503 10,505 10,439
Less Power Agency-owned portion (a) 654 627 647 638 567
--------- --------- --------- --------- ---------
Total Company capability 10,555 10,275 9,856 9,867 9,872
========= ========= ========= ========= =========
________________
(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>
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, 1994, the Company had 5,822 pole miles of
transmission lines including 292 miles of 500 kV and 2,790 miles of
230 kV lines, and distribution lines of approximately 39,907 pole
miles of overhead lines and approximately 7,557 miles of underground
lines. Distribution and transmission substations in service had a
transformer capacity of approximately 35,250 kVA in 2,270
transformers. Distribution line transformers numbered 391,474 with
an aggregate 15,744,200 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 right-
of-way easements over private property on which transmission and
distribution lines are located.
The Company believes that its generating facilities are
suitable, adequate, well-maintained and in good operating condition.
Plant Accounts (including nuclear fuel) -
_______________________________________
During the period January 1, 1990 through December 31, 1994, there
was added to the Company's utility plant accounts $1,779,168,000, there was
retired $476,328,000 of property and there were transfers to other accounts
and adjustments for a net decrease of $319,690,000 resulting in net
additions during the period of $983,149,000 or an increase of
approximately 11.23%.
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 1994.
EXECUTIVE OFFICERS OF THE REGISTRANT
____________________________________
Name Age Recent Business Experience
____ ___ __________________________
Sherwood H. Smith, Jr. 60 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 56 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, January 1990-August 1992;
President and Chief Executive Officer,
System Energy Resources, Inc., 1986-
August 1992; President and Chief
Executive Officer, Entergy Operations,
Inc., June 1990-April 1992. Member of
Board of Directors of Arkansas Power &
Light Company and Louisiana Power &
Light Company, January 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. 64 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 E. Eury 58 EXECUTIVE VICE PRESIDENT - Power Supply,
April 1989 to July 1994 (retired);
Senior Vice President - Operations
Support, June 1986; Senior Vice
President - Fossil Generation and Power
Transmission Group, August 1983.
William S. Orser 50 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, 1987-1990. Prior to 1987,
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. 58 SENIOR VICE PRESIDENT, Group Executive -
Power Operations, June 1986 to present;
Senior Vice President - Operations
Support Group, August 1983.
Norris L. Edge 63 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.
Cecil L. Goodnight 52 SENIOR VICE PRESIDENT, Human Resources
and Support Services, March 1995-
present; Vice President - Human Resources
(formerly Employee Relations Department),
May 1983 to March 1995.
Glenn E. Harder 43 SENIOR VICE PRESIDENT, Group Executive -
Financial Services, October 1994 to
present; Vice President - Financial
Strategies and Treasurer, Entergy
Corporation, September 1991 to October
1994; Vice President -Administrative
Services & Regulatory Affairs, Entergy
Operations, Inc., May 1991 to August
1991; Vice President, Accounting and
Treasurer, System Energy Resources, Inc.,
October 1986 to May 1991. Before
joining the Company, Mr. Harder held
various senior management and executive
positions with Entergy Corporation, an
electric utility holding company with
operations in Arkansas, Louisiana and
Mississippi, and related entities.
Richard E. Jones 57 SENIOR VICE PRESIDENT, GENERAL COUNSEL
AND SECRETARY, Group Executive - Legal,
Rates, Communications, Community
Relations 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 57 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,
as reported as composite transactions in The Wall Street Journal,
_______________________
and dividends paid are as follows:
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
1994 High Low Dividends Paid
____ ____ ___ ______________
First Quarter $ 29 3/4 $ 25 5/8 $ .425
Second Quarter 26 5/8 22 7/8 .425
Third Quarter 27 22 3/4 .425
Fourth Quarter 27 3/4 25 1/4 .425
The December 31 closing price of the Company's Common Stock
was $30 1/8 in 1993 and $26 5/8 in 1994.
As of February 28, 1995, the Company had 69,748 holders of
record of Common Stock.
On July 13, 1994, the Board of Directors of the Company
(Board) authorized the Executive Committee of the Board to
repurchase up to 10 million shares of the Company's Common Stock on
the open market. Under this stock repurchase program, the Company
had purchased approximately 4.4 million shares through December 31, 1994.
<TABLE>
<CAPTION>
ITEM 6. SELECTED FINANCIAL DATA
- ------- -----------------------
Years Ended December 31
-----------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
(in thousands except per share data)
<S> <C> <C> <C> <C> <C>
Operating results
Operating revenues $ 2,876,589 $ 2,895,383 $ 2,766,821 $ 2,685,755 $ 2,617,107
Income before cumulative effect of
change in accounting method $ 313,167 $ 346,496 $ 379,635 $ 376,974 $ 280,429
Cumulative effect of change in accounting
for revenues - net of tax - - - - 99,929
---------- ---------- ---------- ---------- ----------
Net income $ 313,167 $ 346,496 $ 379,635 $ 376,974 $ 380,358
========== ========== ========== ========== ==========
Earnings for common stock $ 303,558 $ 336,887 $ 379,045 $ 364,380 $ 361,687
Per share data
Earnings per common share before cumulative
effect of change in accounting method $ 2.03 $ 2.10 $ 2.36 $ 2.27 $ 1.58
Cumulative effect of change in accounting
for revenues - - - - 0.60
---------- ---------- ---------- ---------- ----------
Earnings per common share $ 2.03 $ 2.10 $ 2.36 $ 2.27 $ 2.18
========== ========== ========== ========== ==========
Dividends declared per common share $ 1.715 $ 1.655 $ 1.595 $ 1.535 $ 1.475
Financial position
Total assets $ 8,211,163 $ 8,194,018 $ 7,706,201 $ 7,510,587 $ 7,487,443
Capitalization
Common stock equity $ 2,586,179 $ 2,632,116 $ 2,534,025 $ 2,390,676 $ 2,253,680
Preferred stock - redemption not required 143,801 143,801 143,801 238,118 238,118
redemption required, net - - - 31,090 101,179
Long-term debt, net 2,530,773 2,584,903 2,674,823 2,733,693 2,614,904
---------- ---------- ---------- ---------- ----------
Total capitalization $ 5,260,753 $ 5,360,820 $ 5,352,649 $ 5,393,577 $ 5,207,881
========== ========== ========== ========== ==========
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
_______ _________________________________________________
RESULTS OF OPERATIONS
_____________________
Revenues
________
Unusually mild weather in 1994 contributed significantly to
a decrease in revenues as compared to 1993. This weather-related
decrease totaled $86 million. Additionally, in 1994 the Company
completed recovery of the portion of abandoned plant costs collected
under a special rider resulting from the 1990 North Carolina
Utilities Commission (NCUC) Order on Remand. This reduced 1994
revenues by $28 million, but did not significantly impact net income
due to a corresponding decrease in amortization expense. Partially
offsetting these decreases was an increase in revenue of $101
million due to customer growth and changes in customer usage
patterns.
The increase in revenues in 1993 is primarily the result of
an increase in energy sales of 6.2%. The effects of weather did not
significantly impact revenues from 1992 to 1993. Revenues did not
increase from 1992 to 1993 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 decreased in 1994 primarily due to a
change in the generation mix. Nuclear generation, as a percentage of
total generation, increased to 46%, from 34%, and higher-cost fossil
generation decreased to 52%, from 64%, due to greater availability
of the Company's nuclear generating facilities. In 1993, an 8%
increase in total generation, offset somewhat by a decrease in the
cost of fossil fuel and by increased use of nuclear generation,
resulted in a slight increase in fuel for generation.
Deferred fuel reflects fuel costs or recoveries that are
deferred through 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 difference between actual costs incurred and the
fuel component collected in customer billings is reflected in
operating expenses as deferred fuel. As a result, except for fuel
settlements such as those discussed below, net income is not
impacted significantly by fluctuations in fuel costs.
In 1994, the Company reached settlement agreements with
regulators in the North Carolina and South Carolina retail
jurisdictions and agreed to forgo recovery of $8 million of deferred
fuel costs. In 1993, the Company agreed to forgo recovery of $41.1
million of deferred fuel costs related to the Brunswick Plant's
extended outage in 1992 and 1993. The net effect of these agreements
resulted in a decrease of $33.1 million in deferred fuel cost from
1993 to 1994. Excluding the effect of these settlements, deferred
fuel costs increased from 1993 to 1994 due to lower fuel costs
associated with increased nuclear generation and due to the recovery
of prior fuel costs as allowed by the North Carolina fuel adjustment
statute. From 1992 to 1993, excluding the effect of the 1993
settlements, deferred fuel costs increased due to lower fuel costs.
The increase in purchased power from 1992 to 1994 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 accounted for
an increase in purchased power of $26 million in 1994 and $37
million in 1993. In addition, purchases from North Carolina Eastern
Municipal Power Agency (Power Agency) increased $8 million in 1994
and $14 million in 1993, primarily due to the increased buyback
provisions of the Company's 1993 agreement with Power Agency (see
Other Business). A substantial portion of the increase in purchased
power is capacity cost and, therefore, not recoverable through the
Company's fuel clauses.
The increase in other operating expenses from 1993 to 1994 is
due to increases in various cost categories such as benefits,
salaries and demand-side management programs. Partially offsetting
these increases was a 1994 adjustment of $23 million to reduce the
Company's nuclear insurance reserves. Other operating expenses
increased from 1992 to 1993 due to 1) the Brunswick Plant outage in
1992 and 1993, 2) the recognition of increased expense for
postretirement benefits other than pensions due to new accounting
requirements and 3) 1992 adjustments that were made to certain
accrual and asset balances as a result of more current information
at that time. Excluding the effect of the 1994 insurance reserve
adjustment, the Company's business plan for the period through 1997
does not project an increase in other operating expenses.
Maintenance expense decreased from 1992 to 1994 primarily due
to a decrease in costs associated with the Brunswick Plant's outage
in 1992 and 1993. Additionally, maintenance expense decreased in
1993 due to the capitalization of costs associated with plant
modifications as compared to the prior year.
The decrease in depreciation and amortization from 1993 to
1994 is primarily attributable to the completion of the amortization
of abandoned plant costs for Harris Unit No. 2 and of costs
associated with the 1990 NCUC Order on Remand; these decreases in
amortization totaled $25 million. In 1993, the Company began
amortizing costs associated with two significant software projects,
which contributed to a portion of the increase in depreciation and
amortization from 1992 to 1993.
The fluctuation in Harris Plant deferred costs from 1992 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 Other Business).
Other Income
____________
The fluctuation in Harris Plant carrying costs from 1992 to
1994 is primarily related to the Company's settlement with NCEMC,
which was recorded in 1993 and increased carrying costs in that year.
The Harris Plant disallowance - Power Agency line item
reflects a write-off recorded as a result of the 1993 settlement
with Power Agency (see Other Business).
Beginning in 1994, the Company is no longer recording
interest income related to the Company's qualified employee stock
ownership plan (ESOP) loan (see New Accounting Standard). Interest
income also decreased in 1994 due to the Company's 1993 settlement
with Westinghouse Electric Corporation (Westinghouse), which
increased interest income in 1993 (see Other Business). Partially
offsetting these decreases was an increase for interest income
related to certain IRS audit issues. The increase in interest income
from 1992 to 1993 is primarily due to the Westinghouse settlement.
Other income, net, decreased in 1994 primarily due to a
change in accounting for ESOPs.
Interest Charges
________________
Interest charges on long-term debt decreased from 1992 to
1994 due to long-term debt refinancings that allowed the Company to
take advantage of lower interest rates. In addition, for 1993 as
compared to 1992, interest rates on the Company's variable rate debt
were lower.
LIQUIDITY AND CAPITAL RESOURCES
_______________________________
Capital Requirements
____________________
Estimated capital requirements for the period 1995 through
1997 primarily reflect construction expenditures that will be made
to add generating facilities, 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).
1995 1996 1997
____ ____ ____
Construction expenditures $358 $445 $527
Nuclear fuel expenditures 99 77 71
AFUDC (19) (25) (34)
Mandatory redemptions of
long-term debt 275 105 100
____ ____ ____
Total $713 $602 $664
==== ==== ====
The table above includes Clean Air Act requirement
expenditures of approximately $117 million and generating facility
addition expenditures of approximately $287 million for the period
1995 through 1997. The generating facility addition expenditures
will primarily be used to construct new combustion turbine units,
which are intended for use during periods of high demand. The units
are scheduled to be placed in service in 1997 through 2000.
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
was not required to take action to comply with the Act's Phase I
requirements, which had to 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 its 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 2007 by
utilizing lower-sulfur coal and 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. The Company has 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 will approximate $273 million during the
period 1995 through 1999 and an additional $272 million during the
period 2000 through 2007. 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 $18 million for the period 1995 through 1999,
$35 million for the period 2000 through 2006 and by $24 million
annually beginning in 2007. Additionally, fuel costs are expected to
increase by a total of approximately $277 million for the period
2000 through 2006 and by approximately $62 million annually
beginning in 2007. The Company expects these increased fuel costs to
be recoverable through the Company's fuel clauses. Actual plans for
compliance with the Act's requirements have not been finalized and
the amount required for capital expenditures and for increased
operating, maintenance and fuel expenditures cannot be determined
with certainty at this time. The NCUC and the South Carolina Public
Service Commission (SCPSC) are allowing the Company to accrue
carrying charges on its investment in emission allowances.
The Company has two long-term 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. The estimated minimum annual payment
for these power purchases is approximately $30 million, which
represents capital-related capacity costs. Other costs include
demand-related production expenses, fuel and energy-related
operation and maintenance expenses. In 1994, purchases under this
agreement totaled $61.9 million, including transmission use charges.
The agreement expires in 2009. The second agreement is with Duke
Power Company for the purchase of 400 megawatts of firm capacity
through mid-1999. The estimated minimum annual payment for these
power purchases is approximately $43 million, which represents
capital-related capacity costs. Other costs include fuel and
energy-related operation and maintenance expenses. Purchases under
this agreement, including transmission use charges, totaled $62.9
million in 1994. The agreement with Duke Power Company was recently
approved by the Federal Energy Regulatory Commission (FERC).
In addition, the Company is obligated to purchase a percentage
of Power Agency's ownership capacity of and energy from the Mayo
Plant and the Harris Plant through 1997 and 2007, respectively. The
estimated minimum annual payments for these purchases, which reflect
capital-related capacity costs, total approximately $27 million.
Other costs of such purchases are primarily demand-related
production expenses, fuel and energy-related operation and
maintenance expenses. Purchases under the agreement with Power
Agency totaled $60.4 million in 1994.
Cash Flow and Financing
_______________________
Net cash used in investing activities primarily consists of
capital expenditures, which include replacement or expansion of
existing facilities and construction to comply with pollution
control laws and regulations. Capital expenditures in 1994 were
lower than in 1993 primarily due to work performed at the Brunswick
Plant in 1993.
During 1994, the Company issued $322.6 million in long-term
debt. The proceeds of these issuances were primarily used to redeem
or retire $267.4 million of long-term debt. External funding
requirements, which do not include early redemptions of long-term
debt or redemptions of preferred stock, are expected to approximate
$417 million in 1995 and $120 million in 1997. These funds will be
required for construction, mandatory redemptions of long-term debt
and general corporate purposes, including the repayment of
short-term debt. The Company does not expect to have external
funding requirements in 1996.
In 1994, the Board of Directors of the Company authorized the
Executive Committee of the Board to repurchase up to 10 million
shares of the Company's common stock on the open market. Under this
stock repurchase program, the Company has purchased approximately
4.4 million shares through December 31, 1994.
The Company has on file with the Securities and Exchange
Commission (SEC) a shelf registration statement enabling the Company
to issue an aggregate of $450 million principal amount of first
mortgage bonds, and an additional $250 million combined aggregate
principal amount of first mortgage bonds and/or unsecured debt
securities of the Company.
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.
The Company has the ability to issue an additional $3.4 billion in
first mortgage bonds and an additional 14 million shares of
preferred stock at an assumed price of $100 per share and a $8.63
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 total
$307.9 million. The Company had $68.1 million of commercial paper
outstanding at December 31, 1994, 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
_____________
Environmental
_____________
The Company is subject to federal, state and local regulations
addressing air and water quality, hazardous and solid waste
management and other environmental matters.
Various organic materials associated with the production of
manufactured gas, generally referred to as coal tar, are regulated
under various federal and state laws, and a liability may exist for
their remediation. 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, along with other entities alleged to be former
owners and operators of MGP sites in North Carolina, is
participating in a cooperative effort with the North Carolina
Department of Environment, Health and Natural Resources, Division of
Solid Waste Management (DSWM) to establish a uniform framework for
addressing those sites. 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. To date, the Company has not
entered into any such orders.
The Company has recently been approached by another North
Carolina public utility concerning a possible cost-sharing
arrangement with respect to the investigation and, if necessary, the
remediation of four MGP sites. The Company is currently engaged in
discussions with the other utility regarding this matter.
In addition, a current owner of property that was the site of
one MGP owned by Tide Water Power Company (Tide Water Power), which
merged into the Company in 1952, and the Company have entered into
an agreement to share the cost of investigation and, if necessary,
remediation of this site. The Company has also been approached by a
North Carolina municipality that is the current owner of another MGP
site that was formerly owned by Tide Water Power. The Company is engaged
in discussions with that municipality concerning a possible cost-sharing
arrangement with respect to the investigation and, if necessary, the
remediation of that site.
The Company is continuing its investigation regarding the
identities of parties connected to several additional MGP sites, the
relative relationships of the Company and other parties to those
sites and the degree, if any, to which the Company should undertake
shared voluntary efforts with others at individual sites.
The Company has been notified by regulators of its involvement
or potential involvement in several 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 sites.
In 1994, the Company accrued a liability for the estimated
costs associated with investigation and remediation activities for
certain MGP sites and for sites other than MGP sites. This accrual
was not material to the results of operations of the Company. Due to
the lack of information with respect to the operation of MGP sites
for which a liability has not been accrued and due to the
uncertainty concerning questions of liability and potential
environmental harm, the extent and cost of required remedial action,
if any, are not currently determinable. The Company cannot predict
the outcome of these matters or the extent to which other MGP sites
may become the subject of inquiry.
Nuclear
_______
In the Company's retail jurisdictions, provisions for nuclear
decommissioning costs were approved by the NCUC and the SCPSC in the
Company's 1988 general rate cases and were based on site-specific
estimates that included the costs for removal of all radioactive and
other structures at the site. In the wholesale jurisdiction, the
provisions for nuclear decommissioning costs are based on amounts
agreed upon in applicable rate settlements. Based on the
site-specific estimates discussed below, and using an assumed
after-tax earnings rate of 8.5% and an assumed cost escalation rate
of 4%, current levels of rate recovery for nuclear decommissioning
costs are adequate to provide for decommissioning of the Company's
nuclear facilities.
The Company's most recent site-specific estimates of
decommissioning costs were developed in 1993, using 1993 cost
factors, and are based on prompt dismantlement decommissioning,
which reflects the cost of removal of all radioactive and other
structures currently at the site, with such removal occurring
shortly after operating license expiration. These estimates, in 1993
dollars, are $257.7 million for Robinson Unit No. 2, $235.4 million
for Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2
and $284.3 million for the Harris Plant. The estimates are subject
to change based on a variety of factors including, but not limited
to, cost escalation, changes in technology applicable to nuclear
decommissioning, and changes in federal, state or local regulations.
The cost estimates exclude the portion attributable to Power Agency,
which holds an undivided ownership interest in certain of the
Company's generating facilities. Operating licenses for the
Company's nuclear units expire in the year 2010 for Robinson Unit
No. 2, 2016 for Brunswick Unit No. 1, 2014 for Brunswick Unit No. 2
and 2026 for the Harris Plant.
The Financial Accounting Standards Board has added a project
to its agenda regarding the electric utility industry's current
accounting practices related to decommissioning costs. Any changes
to these practices could affect such items as: 1) when the
decommissioning obligation is recognized, 2) where balances of
accumulated decommissioning costs are recorded, 3) where income
earned on external decommissioning trust balances is recorded and 4)
the levels of annual decommissioning cost provisions. The Financial
Accounting Standards Board is in the early stages of this project,
and consequently, it is uncertain what impacts, if any, this project
may have on the Company's accounting for decommissioning costs.
As required under the Nuclear Waste Policy Act of 1982, the
Company entered into a contract with the U.S. Department of Energy
(DOE) under which the DOE agreed to dispose of the Company's spent
nuclear fuel. The Company cannot predict whether the DOE will be
able to perform its contractual obligations and provide interim
storage or permanent disposal repositories for spent nuclear fuel
and/or high-level radioactive waste materials on a timely basis.
With certain modifications, the Company's spent fuel storage
facilities 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, dry
storage may be necessary.
New Accounting Standard
_______________________
In 1994, the Company implemented Statement of Position (SOP)
93-6, "Employers' Accounting for Employee Stock Ownership Plans," on
a prospective basis. This SOP required the following changes in
accounting for the Company's ESOP: 1) ESOP shares that have not been
committed to be released to participants' accounts are no longer
considered outstanding for the determination of earnings per common
share; 2) dividends on unallocated ESOP shares are no longer
recognized for financial statement purposes; 3) interest income
related to the qualified ESOP loan is no longer recognized; 4) the
difference between the acquisition and allocation prices of ESOP
shares, which was previously recorded as other income, net, is now
recorded directly to common stock; and 5) all tax benefits of ESOP
dividends are now recorded to non-operating income tax expense,
whereas in 1993, a portion of the tax benefits was recorded directly
to retained earnings. In 1992, prior to the implementation of
Statement of Financial Accounting Standards No. 109, all tax
benefits of ESOP dividends were recorded to retained earnings and
were included in the determination of earnings per common share. In
addition, pursuant to SOP 93-6, ESOP loan transactions between the
Company and the Stock Purchase Savings Plan Trustee are no longer
reflected in the Statement of Cash Flows. The implementation of SOP
93-6 resulted in an increase in earnings per common share of
approximately $.04 for 1994.
Other Business
______________
In 1993, the Company and Westinghouse reached an agreement
that settled 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. In 1993, the Company and Power Agency entered into an
agreement to restructure portions of their contracts covering power
supplies and interests in several jointly-owned generating units.
Under terms of this agreement, the Company increased 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. The agreement has been
approved by the FERC.
As part of its 1993 agreement with the Company, Power Agency
will delay the commercial operation date of a combustion turbine
electric generating project from 1995 until 1998. The project could
displace up to approximately 180 megawatts of capacity that Power
Agency currently purchases from the Company. In 1994, the FERC
approved an agreement that resolved issues between Power Agency and
the Company with respect to the turbine generating project.
In 1994, the FERC approved the Company's license application
to continue operating the Company's 105-megawatt Walters
Hydroelectric Plant for the next 40 years. In conjunction with the
Walters' relicensing proceeding, the FERC also approved a 30-year
Power Coordination Agreement (PCA) between the Company and NCEMC.
The agreement assures that the Company will continue to be NCEMC's
primary source of electricity for the next several years. The PCA
allows NCEMC to assume responsibility for up to 200 megawatts of its
load beginning in 1996. NCEMC has given notice that it will purchase
200 megawatts from another supplier beginning January 1996. From
January 1996 through 2000, the Company will continue to supply at
least 1,000 megawatts of electricity. Load reductions beyond the
year 2000 are subject to specific limits and require five years
advance notice.
In 1993, the Company and NCEMC entered into a settlement
agreement that provided for the continuation of existing wholesale
rate levels and resolved a 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.
In 1994, the Company established a wholly-owned subsidiary,
CaroNet, Inc., and the subsidiary joined a regional partnership led
by BellSouth Personal Communications, Inc. (BellSouth). In March
1995, BellSouth won its bid for a Federal Communications Commission
license for the partnership to operate a personal communications
services (PCS) system covering most of North Carolina and South
Carolina and a small portion of Georgia. PCS, a wireless
communications technology, is expected to provide high-quality
mobile communications. Wireless technology could also support
automated meter reading, automated service connection and
disconnection, and control and monitoring of certain aspects of the
Company's electric transmission and distribution systems. BellSouth
will transfer the PCS license to the partnership. BellSouth will be
general partner and handle day-to-day management of the business.
Competition
___________
In 1992, the National Energy Policy Act (Energy Act) changed
certain underlying federal policies governing wholesale generation
and the sale of electric power. In effect, the Energy Act partially
deregulated the wholesale electric utility industry at the
generation level by allowing non-utility generators to build and own
generating plants for both cogeneration and sales to utilities.
Provisions of the Energy Act that most affected the utility industry
were the establishment of exempt wholesale generators, and the
authority given the FERC to permit wholesale transfer, or wheeling,
of power over the transmission lines of other utilities. 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. Although the Energy Act prohibits the FERC from
ordering retail wheeling--transmitting power on behalf of another
producer to an individual retail customer--some states are
considering changing their laws or regulations to allow retail
electric customers to buy power from suppliers other than the local
utility. The Company believes changes in existing laws in both North
Carolina and South Carolina would be required to permit retail
wheeling in the Company's retail jurisdictions. The South Carolina
Public Service Commission (SCPSC) has ruled that it would be a
violation of its past practice and of South Carolina's territorial
assignment statute to require utilities to engage in retail
wheeling. On February 8, 1995, the Carolina Utility Consumers
Association, Inc., a group of industrial customers doing business in
North Carolina, filed a petition with the NCUC requesting that the
NCUC hold a generic hearing to examine whether retail wheeling would
be in the public interest, how it could be implemented in North
Carolina and whether it could be implemented without changing state
law. The NCUC has issued an order inviting interested parties to
comment on the petition. The Company cannot predict the outcome of
this matter.
The possible migration of some of the Company's load due to
increased competition in the electric industry has created greater
planning uncertainty and risks for the Company. The Company has been
addressing these risks by securing 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 and 1994, the Company signed long-term agreements
with almost all of the Company's wholesale customers, representing
approximately 15% of the Company's operating revenues. In the
industrial sector, the Company is working to meet the energy needs
of its customers. In 1994, the Company reached an agreement with its
largest industrial customer, which ensures the Company will serve
this customer through 2001. Other elements of the Company's strategy
to respond to the changing market for electricity include promoting
economic development, implementing new marketing strategies,
improving customer satisfaction, increasing the focus on managing
and reducing costs and, consequently, avoiding future rate
increases.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
_______ ___________________________________________
The following financial statements, supplementary data and
financial statement schedules are included herein:
Page(s)
Independent Auditors' Report 45-46
Financial Statements:
Statements of Income for the Years Ended
December 31, 1994, 1993 and 1992 47
Statements of Cash Flows for the Years
Ended December 31, 1994, 1993 and 1992 48
Balance Sheets as of December 31, 1994 and 1993 49-50
Schedules of Capitalization as of
December 31, 1994 and 1993 51
Statements of Retained Earnings for the
Years Ended December 31, 1994, 1993 and 1992 52
Quarterly Financial Data 52
Notes to Financial Statements 53-64
Financial Statement Schedules for the Years Ended
December 31, 1994, 1993 and 1992:
VIII - Reserves 65-67
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.
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, 1994 and
1993, and the related statements of income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 1994. 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, 1994 and 1993,
and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 1994 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, 1992, 1991, and 1990, and the related statements of income,
retained earnings and cash flows for the years ended December 31, 1991
and 1990 (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, 1994, 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 8 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 LLP
Raleigh, North Carolina
February 13, 1995
<TABLE>
Carolina Power & Light Company
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
<CAPTION>
Statements of Income
Years ended December 31
(in thousands except per share data) 1994 1993 1992
- --------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues $ 2,876,589 $ 2,895,383 $ 2,766,821
- ---------------------------------------------------------------------------------------------------
Operating Expenses
Operation - fuel for generation 471,967 524,366 518,941
deferred fuel cost (credit), net (Note 1F) 38,171 27,364 (49,892)
purchased power 414,300 368,092 339,325
other 539,959 498,333 427,423
Maintenance 206,733 235,449 247,966
Depreciation and amortization 397,735 413,646 398,361
Taxes other than on income 138,540 142,871 131,897
Income tax expense 198,535 189,317 207,328
Harris Plant deferred costs, net (Note 7) 26,329 27,575 3,512
- ---------------------------------------------------------------------------------------------------
Total operating expenses 2,432,269 2,427,013 2,224,861
- ---------------------------------------------------------------------------------------------------
Operating Income 444,320 468,370 541,960
- ---------------------------------------------------------------------------------------------------
Other Income (Expense)
Allowance for equity funds used during construction 6,074 8,999 7,932
Income tax credit (expense) 9,425 (392) (5,885)
Harris Plant carrying costs (Note 7) 9,754 27,143 10,774
Harris Plant disallowance - Power Agency (Note 10a) - (20,645) -
Interest income (Note 2) 14,569 36,196 24,755
Other income, net (Note 2) 25,592 42,465 35,718
- ---------------------------------------------------------------------------------------------------
Total other income 65,414 93,766 73,294
- ---------------------------------------------------------------------------------------------------
Income Before Interest Charges 509,734 562,136 615,254
- ---------------------------------------------------------------------------------------------------
Interest Charges
Long-term debt 183,891 205,182 223,158
Other interest charges 16,119 16,419 15,717
Allowance for borrowed funds used during construction (3,443) (5,961) (3,256)
- ---------------------------------------------------------------------------------------------------
Net interest charges 196,567 215,640 235,619
- ---------------------------------------------------------------------------------------------------
Net Income 313,167 346,496 379,635
Preferred Stock Dividend Requirements (9,609) (9,609) (14,798)
Tax Benefit of ESOP Dividends (Note 2) - - 14,208
- ---------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 303,558 $ 336,887 $ 379,045
- ---------------------------------------------------------------------------------------------------
Average Common Shares Outstanding (Notes 2 and 3) 149,614 160,737 160,737
- ---------------------------------------------------------------------------------------------------
Earnings per common share (Notes 2 and 3) $ 2.03 $ 2.10 $ 2.36
- ---------------------------------------------------------------------------------------------------
Dividends Declared per Common Share $ 1.715 $ 1.655 $ 1.595
- ---------------------------------------------------------------------------------------------------
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
Carolina Power & Light Company
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
<CAPTION>
Statements of Cash Flows
Years Ended December 31
(in thousands) 1994 1993 1992
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Activities
Net income $ 313,167 $ 346,496 $ 379,635
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 473,481 460,094 432,554
Harris Plant deferred costs 16,575 432 (7,262)
Harris Plant disallowance - Power Agency - 20,645 -
Deferred income taxes 37,240 71,352 100,486
Investment tax credit adjustments (11,537) (12,806) (11,083)
Allowance for equity funds used during construction (6,074) (8,999) (7,932)
Deferred fuel cost (credit) 38,171 27,364 (49,892)
Net increase in receivables, inventories and prepaid expenses (73,891) (7,803) (88,334)
Net increase (decrease) in payables and accrued expenses (46,771) (62,013) 72,036
Miscellaneous (4,935) 10,882 (43,427)
- --------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 735,426 845,644 776,781
- --------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (274,777) (341,122) (262,434)
Nuclear fuel additions (25,849) (48,001) (71,388)
Contributions to external decommissioning trust (21,625) (20,878) (14,534)
Contributions to retiree benefit trusts (18,917) (3,750) (6,667)
Loan transactions with SPSP Trustee, net (Note 2) - 21,134 29,888
Allowance for equity funds used during construction 6,074 8,999 7,932
Miscellaneous (6,094) - -
- --------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (341,188) (383,618) (317,203)
- --------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt 318,211 582,030 673,752
Net decrease in pollution control bond escrow - 2,127 9,161
Net increase (decrease) in short-term notes payable (maturity less than 90 days) (7,900) 29,200 (16,139)
Retirement of long-term debt (268,380) (790,376) (745,405)
Purchase of Company common stock (Note 3) (114,717) - -
Retirement of preferred stock - - (134,625)
Dividends paid on common stock (Notes 2 and 3) (255,206) (262,749) (253,964)
Dividends paid on preferred stock (9,614) (9,474) (19,968)
- --------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (337,606) (449,242) (487,188)
- --------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 56,632 12,784 (27,610)
Cash and Cash Equivalents at Beginning of Year 23,607 10,823 38,433
- --------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 80,239 $ 23,607 $ 10,823
====================================================================================================================
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest $ 188,754 $ 218,801 $ 232,527
income taxes $ 180,759 113,523 74,960
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
Carolina Power & Light Company
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
<CAPTION>
Balance Sheets
Assets
December 31
(in thousands) 1994 1993
- ----------------------------------------------------------------------------------
<S> <C> <C>
Electric Utility Plant
Electric utility plant in service $ 9,190,874 $ 8,789,518
Accumulated depreciation (3,196,139) (2,897,832)
- ----------------------------------------------------------------------------------
Electric utility plant in service, net 5,994,735 5,891,686
Held for future use 13,195 13,300
Construction work in progress 170,390 309,713
Nuclear fuel, net of amortization 171,164 217,488
- ----------------------------------------------------------------------------------
Total electric utility plant, net 6,349,484 6,432,187
- ----------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 80,239 23,607
Accounts receivable 302,218 321,309
Fuel 96,136 62,029
Materials and supplies 122,720 111,052
Prepayments 52,988 46,869
Other current assets 24,129 18,591
- ----------------------------------------------------------------------------------
Total current assets 678,430 583,457
- ----------------------------------------------------------------------------------
Deferred Debits and Other Assets
Income taxes recoverable through future rates 384,375 385,515
Abandonment costs 71,079 125,361
Harris Plant deferred costs 127,824 144,399
Unamortized debt expense 63,302 63,898
Miscellaneous other property and investments 360,611 264,165
Other assets and deferred debits 176,058 185,209
- ----------------------------------------------------------------------------------
Total deferred debits and other assets 1,183,249 1,168,547
- ----------------------------------------------------------------------------------
Total Assets $ 8,211,163 $ 8,184,191
- ----------------------------------------------------------------------------------
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
See Notes to Financial Statements.
<PAGE>
</TABLE>
<TABLE>
Carolina Power & Light Company
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
<CAPTION>
Balance Sheets
Capitalization and Liabilities
December 31
(in thousands) 1994 1993
- ----------------------------------------------------------------------------------
<S> <C> <C>
Capitalization (see Schedules of Capitalization)
Common stock equity $ 2,586,179 $ 2,632,116
Preferred stock - redemption not required 143,801 143,801
Long-term debt, net 2,530,773 2,584,903
- ----------------------------------------------------------------------------------
Total capitalization 5,260,753 5,360,820
- ----------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 275,050 162,630
Notes payable (principally commercial paper) 68,100 76,000
Accounts payable 285,610 293,093
Interest accrued 54,569 54,770
Dividends declared (Note 2) 70,658 74,111
Deferred fuel credit (cost) 28,344 (9,827)
Other current liabilities 71,811 88,423
- ----------------------------------------------------------------------------------
Total current liabilities 854,142 739,200
- ----------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,628,430 1,585,490
Accumulated deferred investment tax credits 252,051 263,588
Other liabilities and deferred credits 215,787 235,093
- ----------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,096,268 2,084,171
- ----------------------------------------------------------------------------------
Commitments and Contingencies (Note 10)
Total Capitalization and Liabilities $ 8,211,163 $ 8,184,191
- ----------------------------------------------------------------------------------
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
Carolina Power & Light Company
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
<CAPTION>
Schedules of Capitalization
December 31
(in thousands) 1994 1993
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Common Stock Equity
Common stock without par value, 200,000,000 shares authorized; shares outstanding,
156,382,422 at December 31, 1994 and 160,736,522 at December 31, 1993
(Notes 2 and 3) $ 1,510,956 $ 1,622,277
Unearned ESOP common stock (204,947) (220,725)
Capital stock issuance expense (790) (790)
Retained earnings (Note 3) 1,280,960 1,231,354
- ------------------------------------------------------------------------------------------------------------------
Total common stock equity $ 2,586,179 $ 2,632,116
- ------------------------------------------------------------------------------------------------------------------
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, 1994)
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, 1994)
First mortgage bonds:
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
6.875% due 1998 40,000 40,000
5.375% due 1998 100,000 100,000
5.875% to 8.125% due 2000 - 2004 672,626 600,000
8.50% due 2007 - 17,451
6.875% to 9.00% due 2020 - 2023 725,000 725,000
First mortgage bonds - Secured Medium-Term Notes, Series A, B and C:
5.85% due 1994 - 50,000
8.85% to 8.92% due 1995 73,000 73,000
4.85% to 7.90% due 1996 - 1999 190,000 140,000
First mortgage bonds - pollution control series:
D and E, 6.90% due 2009 54,455 54,455
F, 6.60% due 2010 34,700 34,700
G, 5.90% due 2014 - 122,615
J and K, 6.30% due 2014 4,375 4,375
L and M, 5.10% to 4.13% due 2024 122,600 -
- ------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 2,288,806 2,233,646
- ------------------------------------------------------------------------------------------------------------------
Other long-term debt:
Pollution control obligations backed by letter of credit, 2.91%
to 5.90% due 2014 - 2017 442,000 442,000
Other pollution control obligations, 5.55% due 2019 55,640 55,640
Miscellaneous notes 47,409 34,680
- ------------------------------------------------------------------------------------------------------------------
Total other long-term debt 545,049 532,320
- ------------------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net (28,032) (18,433)
Current portion of long-term debt (275,050) (162,630)
- ------------------------------------------------------------------------------------------------------------------
Total long-term debt, net $ 2,530,773 $ 2,584,903
- ------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 5,260,753 $ 5,360,820
- ------------------------------------------------------------------------------------------------------------------
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
Carolina Power & Light Company
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
<CAPTION>
Statements of Retained Earnings
Years ended December 31
(in thousands) 1994 1993 1992
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Retained Earnings at Beginning of Year $1,231,354 $1,153,655 $1,034,160
Net income 313,167 346,496 379,635
Preferred stock dividends at stated rates (9,609) (9,609) (14,798)
Common stock dividends at annual rate of $1.715 per share in 1994,
$1.655 in 1993 and $1.595 in 1992 (Notes 2 & 3) (256,021) (266,019) (256,375)
Tax benefit of ESOP dividends (Note 2) - 6,837 14,208
Other adjustments 2,069 (6) (3,175)
- -------------------------------------------------------------------------------------------------------------------------------
Retained Earnings at End of Year $1,280,960 1,231,354 $1,153,655
- -------------------------------------------------------------------------------------------------------------------------------
Quarterly Financial Data
(Unaudited)
First Quarter Second Quarter Third Quarter Fourth Quarter
(in thousands except
per share data) 1994 1993 1994 1993 1994 1993 1994 1993
- -------------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 744,461 $ 707,485 $ 687,310 $ 674,591 $ 805,552 $ 854,750 $ 639,266 $ 658,557
Operating income $ 123,027 $ 130,123 $ 86,430 $ 105,107 $ 155,796 $ 159,428 $ 79,067 $ 73,712
Net income $ 88,824 $ 93,998 $ 58,215 $ 69,984 $ 120,253 $ 118,642 $ 45,875 $ 63,872
Common stock data:
Earnings per common share $ .57 $ .57 $ .37 $ .42 $ .79 $ .72 $ .30 $ .38
Dividend paid per common
share $ .425 $ .410 $ .425 $ .410 $ .425 $ .410 $ .425 $ .410
Price per share - high $ 29 3/4 $ 32 7/8 $ 26 5/8 $ 34 $ 27 $ 34 1/2 $ 27 3/4 $ 33 3/8
low $ 25 5/8 $ 27 1/16 $ 22 7/8 $ 31 1/4 $ 22 3/4 $ 32 1/8 $ 25 1/4 $ 28 1/8
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
See Notes to Financial Statements.
</TABLE>
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 1993 and
1992 have been reclassified to conform to the 1994 presentation.
B. Electric Utility Plant
The cost of additions, including betterments and replacements of units of
property, is charged to electric utility plant. Maintenance and repairs of
property, and replacements and renewals of items determined to be less than
units of property, are charged to maintenance expense. The cost of units of
property replaced, renewed or retired, plus removal or disposal costs, less
salvage, is charged to accumulated depreciation. Generally, electric utility
plant other than nuclear fuel is subject to the lien of the Company's
mortgage. The balances of electric utility plant in service at December 31 are
listed below (in millions).
1994 1993
Production plant $ 5,911.2 $ 5,713.9
Transmission plant 879.6 873.4
Distribution plant 1,929.5 1,825.2
General plant and other 470.6 377.0
--------- ---------
Electric utility plant in service $ 9,190.9 $ 8,789.5
========= =========
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 1992, a deferred income tax provision was
reflected as a reduction in the borrowed funds portion. Due to the 1993
implementation of Statement of Financial Accounting Standards (SFAS) No. 109,
"Accounting for Income Taxes," AFUDC-borrowed funds is no longer recorded on a
net-of-tax basis (see Note 8). The composite AFUDC rate was 8.4% in 1994 and
8.8% in 1993, and the composite, net-of-tax AFUDC rate was 7.3% in 1992.
Pursuant to the provisions of SFAS No. 109, the deferred income tax related to
AFUDC in undepreciated plant in service as of January 1, 1993, was recorded to
a 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 3.8% in 1994 and 1993, and 3.7% in 1992. Depreciation expense
totaled $335.1 million for 1994, $325.4 million for 1993 and $306.0 million
for 1992. Depreciation and amortization expense also includes amortization of
plant abandonment costs (see Note 7).
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 1F).
D. 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. In the wholesale jurisdiction, the provisions for
nuclear decommissioning costs are based on amounts agreed upon in applicable
rate settlements. Decommissioning cost provisions, which are included in
depreciation and amortization, were $29.5 million in 1994, $34.0 million in
1993 and $27.1 million in 1992.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were $252.7 million at December 31, 1994, and $221.6 million at
December 31, 1993, and include amounts retained internally and amounts funded
in an external decommissioning trust. The balance of the external
decommissioning trust, which is included in miscellaneous other property and
investments, was $67.6 million at December 31, 1994, and $44.5 million at
December 31, 1993. Trust earnings, which increase the trust balance with a
corresponding increase in accumulated decommissioning, were $1.5 million in
1994, $1.2 million in 1993 and $.8 million in 1992. Based on the
site-specific estimates discussed below, and using an assumed after-tax
earnings rate of 8.5% and an assumed cost escalation rate of 4%, current
levels of rate recovery for nuclear decommissioning costs are adequate to
provide for decommissioning of the Company's nuclear facilities.
The Company's most recent site-specific estimates of decommissioning costs
were developed in 1993, using 1993 cost factors, and are based on prompt
dismantlement decommissioning, which reflects the cost of removal of all
radioactive and other structures currently at the site, with such removal
occurring shortly after operating license expiration. These estimates, in 1993
dollars, are $257.7 million for Robinson Unit No. 2, $235.4 million for
Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2 and $284.3
million for the Harris Plant. The estimates are subject to change based on a
variety of factors including, but not limited to, cost escalation, changes in
technology applicable to nuclear decommissioning, and changes in federal,
state or local regulations. The cost estimates exclude the portion
attributable to North Carolina Eastern Municipal Power Agency (Power Agency),
which holds an undivided ownership interest in certain of the Company's
generating facilities. Operating licenses for the Company's nuclear units
expire in the year 2010 for Robinson Unit No. 2, 2016 for Brunswick Unit No.
1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant.
The Financial Accounting Standards Board has added a project to its agenda
regarding the electric utility industry's current accounting practices related
to decommissioning costs. Any changes to these practices could affect such
items as: 1) when the decommissioning obligation is recognized, 2) where
balances of accumulated decommissioning costs are recorded, 3) where income
earned on external decommissioning trust balances is recorded and 4) the
levels of annual decommissioning cost provisions. The Financial Accounting
Standards Board is in the early stages of this project, and consequently, it
is uncertain what impacts, if any, this project may have on the Company's
accounting for decommissioning costs.
E. Regulatory Assets and Liabilities
As a regulated entity, the Company is subject to the provisions of SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation." Accordingly,
the Company records certain assets and liabilities that result from the
effects of the ratemaking process, which would not be recorded under generally
accepted accounting principles for non-regulated entities. At December 31,
1994, the balances of the Company's regulatory assets were as follows: 1)
$384.4 million for income taxes recoverable through future rates, 2) $127.8
million for Harris Plant deferred costs, 3) $71.1 million for abandonment
costs, 4) $55 million for loss on reacquired debt, which is included in
unamortized debt expense and 5) $66 million for deferred DOE enrichment
facilities-related cost, which is included in other assets and deferred
debits. At December 31, 1994, the Company had a regulatory liability of $28.3
million related to deferred fuel.
F. Other Policies
Customers' meters are read and bills are rendered on a cycle basis. Revenues
are recorded as services are rendered.
Deferred fuel reflects fuel costs or recoveries that are deferred through fuel
clauses established by the Company's regulators. These clauses allow the
Company to recover fuel costs and the fuel component of purchased power costs
through the fuel component of customer rates. Any difference between actual
costs incurred and the fuel component collected in customer billings is
reflected in operating expenses as deferred fuel. Customer rates are adjusted
periodically to incorporate the approved deferrals. In 1993, the Company
reached settlement agreements with regulators in the North Carolina and South
Carolina retail jurisdictions and agreed to forgo recovery of a total of $41.1
million of deferred fuel expenses.
Other property and investments are stated principally at cost. The Company
maintains an allowance for doubtful accounts receivable, which totaled $2.5
million at December 31, 1994, and $2.3 million at December 31, 1993. 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. Employee Stock Ownership Plan
The Company sponsors a Stock Purchase-Savings Plan (SPSP) for which all
full-time employees and certain part-time employees are eligible. The SPSP,
which has company match and incentive goal features, encourages systematic
savings by employees and provides a method of acquiring Company common stock
and other diverse investments. The SPSP, as amended in 1989, is an employee
stock ownership plan (ESOP) that can enter into acquisition loans for the
purpose of acquiring Company common stock to satisfy SPSP common share needs.
Qualification as an ESOP did not change the level of benefits received by
employees under the SPSP. Common stock acquired with the proceeds of an ESOP
loan is held by the SPSP Trustee in a suspense account and is released from
the suspense account and made available for allocation to participants as the
ESOP loan is repaid, as specified by provisions of the Internal Revenue Code.
Such allocations are used to partially meet common stock needs related to
participant contributions, Company matching and incentive contributions and/or
reinvested dividends. Dividends paid on ESOP suspense shares and on ESOP
shares allocated to participants, as well as certain Company contributions,
are used to repay ESOP acquisition loans, and such dividends are deductible
for income tax purposes.
There were 9,315,789 ESOP suspense shares at December 31, 1994, with a fair
value of $248 million. ESOP shares allocated to plan participants totaled
13,891,199 at December 31, 1994. The Company has a long-term note receivable
from the SPSP Trustee related to the purchase of common stock from the Company
in 1989. The balance of the Company's note receivable from the SPSP Trustee,
$204 million at December 31, 1994, is recorded as unearned ESOP common stock
and reduces common stock equity.
In 1994, the Company implemented Statement of Position (SOP) 93-6, "Employers'
Accounting for Employee Stock Ownership Plans," on a prospective basis. This
SOP required the following changes in accounting for the Company's ESOP: 1)
ESOP shares that have not been committed to be released to participants'
accounts are no longer considered outstanding for the determination of
earnings per common share; 2) dividends on unallocated ESOP shares are no
longer recognized for financial statement purposes; 3) interest income related
to the qualified ESOP loan is no longer recognized; 4) the difference between
the acquisition and allocation prices of ESOP shares, which was previously
recorded as other income, net, is now recorded directly to common stock; and
5) all tax benefits of ESOP dividends are now recorded to non-operating income
tax expense, whereas in 1993, a portion of the tax benefits was recorded
directly to retained earnings. In 1992, prior to the implementation of SFAS
No. 109, all tax benefits of ESOP dividends were recorded to retained earnings
and were included in the determination of earnings per common share. In
addition, pursuant to SOP 93-6, ESOP loan transactions between the Company and
the SPSP Trustee are no longer reflected in the Statement of Cash Flows. The
implementation of SOP 93-6 resulted in an increase in earnings per common
share of approximately $.04 for 1994.
3. Capitalization
In 1994, the Board of Directors of the Company authorized the Executive
Committee of the Board to repurchase up to 10 million shares of the Company's
common stock on the open market. Under this stock repurchase program, the
Company has purchased approximately 4.4 million shares through December 31,
1994.
In 1993, the Company's common stock was split and one additional share was
issued for each common share outstanding. Prior year financial information was
restated to reflect the two-for-one stock split.
At December 31, 1994, 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, 1994, there were no significant
restrictions on the use of retained earnings.
At December 31, 1994, long-term debt maturities for the years 1995 through
1999 were $275.1 million, $105 million, $40 million, $205 million and $50
million, respectively.
Person County Pollution Control Revenue Refunding Bonds - Series 1992A
totaling $56 million have interest rates that must be negotiated on a weekly
basis. At the time of interest rate renegotiation, holders of these bonds may
require the Company to repurchase their bonds. These bonds are 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 this intention is
supported by the Company's long-term revolving credit agreements.
4. Short-Term Debt and Revolving Credit Facilities
At December 31, 1994 and 1993, the Company's short-term debt balances were
$68.1 million and $76 million, respectively. The weighted-average interest
rates of these borrowings were 6.18% at December 31, 1994, and 3.65% at
December 31, 1993. At December 31, 1994, the Company's unused and readily
available revolving credit facilities totaled $307.9 million, consisting of
long-term agreements totaling $207.9 million and a $100 million short-term
agreement.
5. 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 carrying
amount of the Company's long-term debt was $2.86 billion at December 31, 1994,
and $2.80 billion at December 31, 1993. The estimated fair value of this debt,
which was obtained from an independent pricing service, was $2.70 billion at
December 31, 1994, and $2.88 billion at December 31, 1993. There are inherent
limitations in any estimation technique, and these estimates are not
necessarily indicative of the amount the Company could realize in current
transactions.
6. Postretirement Benefit Plans
The Company has a noncontributory defined benefit retirement (pension) plan
for all full-time employees and funds the pension plan in amounts that comply
with contribution limits imposed by law. Pension plan benefits reflect an
employee's compensation, years of service and age at retirement.
The components of net periodic pension cost are (in thousands):
1994 1993 1992
Actual return on plan assets $ 4,897 $(43,604) $(26,882)
Variance from expected return, deferred (47,219) 4,490 (9,743)
------- -------- -------
Expected return on plan assets (42,322) (39,114) (36,625)
Service cost 19,686 16,776 21,368
Interest cost on projected benefit obligation 35,108 31,928 31,141
Net amortization 831 (2,390) 758
------- ------- ------
Net periodic pension cost $ 13,303 $ 7,200 $ 16,642
======= ====== =======
Reconciliations of the funded status of the pension plan at December 31 are
(in thousands):
1994 1993
Actuarial present value of benefits for services
rendered to date:
Accumulated benefits based on salaries to date,
including vested benefits of $287.7 million
for 1994 and $293.6 million for 1993 $ 330,361 $ 339,301
Additional benefits based on estimated
future salary levels 103,766 112,497
-------- --------
Projected benefit obligation 434,127 451,798
Fair market value of plan assets, invested primarily
in equity and fixed-income securities 506,605 515,428
-------- --------
Funded status 72,478 63,630
Unrecognized prior service costs 9,471 12,620
Unrecognized actuarial gain (124,447) (119,352)
Unrecognized transition obligation, being
amortized over 18.5 years beginning January 1, 1987 1,110 1,216
-------- --------
Accrued pension costs
recognized in the Balance Sheets $ (41,388) $ (41,886)
======== ========
The assumptions used to measure the projected benefit obligation are:
1994 1993
Weighted-average discount rate 8.5% 7.5%
Assumed rate of increase in future compensation 4.2% 4.2%
The expected long-term rate of return on pension plan assets used in
determining the net periodic pension cost was 9% in each of the years 1994,
1993 and 1992.
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 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 and totaled $2.7 million in 1992.
The components of net periodic OPEB cost are (in thousands):
1994 1993
Actual return on plan assets $ 42 $ (497)
Variance from expected return, deferred (682) 9
------- -------
Expected return on plan assets (640) (488)
Service cost 8,039 6,797
Interest cost on accumulated benefit obligation 9,463 9,662
Net amortization 5,966 5,966
------- -------
Net periodic OPEB cost $ 22,828 $ 21,937
======= =======
Reconciliations of the funded status of the OPEB plans at December 31 are (in
thousands):
1994 1993
Actuarial present value of benefits for services
rendered to date:
Current retirees $ 55,799 $ 62,727
Active employees eligible to retire 11,933 14,800
The assumptions used to measure the accumulated
postretirement benefit obligation are:
Active employees not eligible to retire 63,164 62,225
------- -------
Accumulated postretirement benefit obligation 130,896 139,752
Fair market value of plan assets, invested
primarily in equity and fixed-income securities 12,142 7,584
------- -------
Funded status (118,754) (132,168)
Unrecognized actuarial (gain) loss (15,125) 6,288
Unrecognized transition obligation, being amortized
over 20 years beginning January 1, 1993 107,379 113,345
------- -------
Accrued OPEB costs recognized in the Balance Sheets $(26,500) $(12,535)
======= =======
The assumptions used to measure the accumulated postretirement benefit
obligation are:
1994 1993
Weighted-average discount rate 8.5% 7.5%
Initial medical cost trend rate for
pre-medicare benefits 9.6% 10.7%
Initial medical cost trend rate for
post-medicare benefits 8.7% 9.5%
Ultimate medical cost trend rate 6.0% 5.0%
Year ultimate medical cost trend rate is achieved 2005 2005
The expected long-term rate of return on plan assets used in determining the
net periodic OPEB cost was 9% in 1994 and 1993. Assuming a one percent
increase in the medical cost trend rates, the aggregate of the service and
interest cost components of the net periodic OPEB cost for 1994 would increase
by $2.5 million, and the accumulated postretirement benefit obligation at
December 31, 1994, 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 retiree health care benefits in a trust created pursuant to
Section 401(h) of the Internal Revenue Code.
7. Plant-Related Deferred Costs
The Company abandoned 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 costs was completed in
1992, and of Harris Unit No. 2 costs in 1994. 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 related to abandoned plant costs associated with the 1990 NCUC
Order on Remand was completed in 1994. Abandoned plant amortization related to
the 1988 rate orders will be completed in 1998 for the North Carolina retail
and the wholesale jurisdictions and in 2027 for the South Carolina retail
jurisdiction.
Amortization of plant abandonment costs is included in depreciation and
amortization expense and totaled $60.5 million in 1994, $100.7 million in 1993
and $92.5 million in 1992. Prior to the 1993 implementation of SFAS No. 109,
this amortization was reported net of certain deferred taxes (see Note 8). 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 $6.6 million in 1994, $13.2 million in 1993 and $18.2 million in
1992 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
10A), the unamortized balance of Harris Plant deferred costs was $60.8 million
at December 31, 1994, and $81.4 million at December 31, 1993.
8. 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.
In 1993, the Company implemented SFAS No. 109 on a prospective basis. SFAS No.
109 required the Company to establish additional deferred tax assets and
liabilities for certain temporary differences and to adjust deferred tax
accounts for changes in income tax rates. It also prohibited net-of-tax
accounting for income statement and balance sheet items. 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. Prior to the implementation of SFAS No. 109, the Company recorded
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. See Note 2 for the impact of SFAS No. 109 on the
treatment of tax benefits of ESOP dividends. Prior period financial statement
amounts were not restated for SFAS No. 109.
Net accumulated deferred income tax liabilities at December 31 are (in
thousands):
1994 1993
Accelerated depreciation and
property cost differences $ 1,504,187 $ 1,449,796
Deferred costs, net 144,751 168,311
Miscellaneous other temporary differences, net (7,173) (12,443)
---------- ----------
Net accumulated deferred income tax liability $ 1,641,765 $ 1,605,664
========== ==========
Total deferred income tax liabilities were $1.9 billion at December 31, 1994,
and 1993. Total deferred income tax assets were $297 million at December 31,
1994, and $261 million at December 31, 1993.
The provisions for income tax expense are comprised of (in thousands):
1994 1993 1992
Included in Operating Expenses
Income tax expense (credit)
Current - federal $ 143,461 $ 108,935 $ 93,319
state 39,185 29,687 37,616
Deferred - federal 23,926 50,719 81,134
state 3,500 11,588 6,342
Investment tax credit adjustments (11,537) (11,612) (11,083)
-------- -------- --------
Subtotal 198,535 189,317 207,328
-------- -------- --------
Harris Plant deferred costs
Deferred - federal - - 2,523
state - - 597
Investment tax credit adjustments (297) 218 (182)
-------- -------- --------
Subtotal (297) 218 2,938
-------- -------- --------
Total included in operating expenses 198,238 189,535 210,266
-------- -------- --------
Included in Other Income
Income tax expense (credit)
Current - federal (15,732) (6,168) (5,857)
state (3,507) (1,291) (1,268)
Deferred - federal 8,065 7,483 11,024
state 1,749 1,562 1,986
Investment tax credit adjustments - (1,194) -
-------- -------- --------
Subtotal (9,425) 392 5,885
-------- -------- --------
Harris Plant carrying costs
Deferred - federal - - 1,612
state - - 357
-------- -------- --------
Subtotal - - 1,969
-------- -------- --------
Other income, net
Deferred - federal - - 47
state - - 11
-------- -------- --------
Subtotal - - 58
-------- -------- --------
Total included in other income (9,425) 392 7,912
-------- -------- --------
Included in Interest Charges
Allowance for borrowed funds used
during construction
Deferred - federal - - 1,678
state - - 382
-------- -------- --------
Total included in interest charges - - 2,060
-------- -------- --------
Total income tax expense $ 188,813 $ 189,927 $ 220,238
======== ======== ========
A reconciliation of the Company's effective income tax rate to the statutory
federal income tax rate follows.
1994 1993 1992
Effective income tax rate 37.6% 35.4% 36.7%
State income taxes, net of federal income tax benefit (5.5) (5.1) (5.1)
Investment tax credit amortization 2.4 2.3 1.9
Other differences, net 0.5 2.4 0.5
---- ---- ----
Statutory federal income tax rate 35.0% 35.0% 34.0%
==== ==== ====
9. 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 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, 1994 (dollars in millions).
Facility Megawatt Company Plant Accumulated Under
Capability Ownership Investment Depreciation Construction
Interest
Mayo Plant 745 83.83% $ 432.3 $ 146.9 $ 1.3
Harris Plant 860 83.83% $ 2,994.3 $ 661.0 $ 7.7
Brunswick Plant 1,521 81.67% $ 1,315.0 $ 708.9 $ 59.8
Roxboro Unit No.4 700 87.06% $ 219.2 $ 86.7 $ 4.9
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.
10. 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 1993,
the Company and Power Agency entered into an agreement to restructure portions
of their contracts covering power supplies and interests in jointly-owned
units. 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 $20.6 million, or
$14.7 million, net of tax. Under the terms of the 1993 agreement, the Company
also increased the amount of capacity and energy purchased from Power Agency's
ownership interest in the Harris Plant, and the buyback period was extended
six years through 2007. The estimated minimum annual payments for these
purchases, which reflect capital-related capacity costs, total approximately
$27 million. 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 $60.4
million for 1994, $52.6 million for 1993 and $39.8 million for 1992. 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, 1994 and 1993, the
Company had deferred purchased capacity costs, including carrying costs
accrued on the deferred balances, of $70.9 million and $67.1 million,
respectively. Increased purchases resulting from the 1993 agreement with Power
Agency, which were approximately $21 million on an annual basis for 1994 and
1993, are not being deferred for future recovery.
The Company purchases 250 megawatts of generating capacity from Indiana
Michigan Power Company's Rockport Unit No. 2. 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 $61.9
million, $60.2 million and $62.9 million for 1994, 1993 and 1992,
respectively. The agreement expires on December 31, 2009.
In mid-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 $62.9 million for 1994 and $37.1 million for
1993. The agreement was recently approved by FERC.
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 $22.7 million in the event that losses at insured facilities
exceed premiums, reserves, reinsurance and other NML resources, which are at
present more than $741 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 the outage begins) in weekly amounts of $1.9 million
at Brunswick Unit No. 1, $1.9 million at Brunswick Unit No. 2, $2.4 million at
the Harris Plant and $1.7 million at Robinson Unit No. 2. The Company is
insured for the next 104 weeks for 80% 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 $10.1 million with respect to the incremental replacement power
costs coverage and $43.3 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 $2.1 billion. Pursuant to
regulations of the Nuclear Regulatory Commission, 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 responsible to the extent losses
may exceed limits of the coverage described above. Power Agency would be
responsible for its ownership share of such losses and for certain
retrospective premium assessments on jointly-owned units.
The Company is insured against public liability for a nuclear incident up to
$8.9 billion per occurrence, which is the maximum limit on public liability
claims pursuant to the Price-Anderson Act. In the event that public liability
claims from an insured nuclear incident exceed $200 million, the Company would
be subject to a pro rata assessment of up to $75.5 million, plus a 5%
surcharge, for each reactor owned for each incident. Payment of such
assessment would be made over time as necessary to limit the payment in any
one year to no more than $10 million per reactor owned. Power Agency would be
responsible for its ownership share of the assessment on jointly-owned units.
C. Claims and Uncertainties
(1) The Company is subject to federal, state and local regulations addressing
air and water quality, hazardous and solid waste management and other
environmental matters.
Various organic materials associated with the production of manufactured gas,
generally referred to as coal tar, are regulated under various federal and
state laws, and a liability may exist for their remediation. 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, along with other entities alleged to be former owners and
operators of MGP sites in North Carolina, is participating in a cooperative
effort with the North Carolina Department of Environment, Health and Natural
Resources, Division of Solid Waste Management (DSWM) to establish a uniform
framework for addressing those sites. 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. To date, the Company has not entered into any such
orders.
The Company has recently been approached by another North Carolina public
utility concerning a possible cost-sharing arrangement with respect to the
investigation and, if necessary, the remediation of four MGP sites. The
Company is currently engaged in discussions with the other utility regarding
this matter.
In addition, a current owner of property that was the site of one MGP owned by
Tide Water Power Company (Tide Water Power), which merged into the Company in
1952, and the Company have entered into an agreement to share the cost of
investigation and, if necessary, remediation of this site. The Company has
also been approached by a North Carolina municipality that is the current
owner of another MGP site that was formerly owned by Tide Water Power. The
Company is engaged in discussions with that municipality concerning a possible
cost-sharing arrangement with respect to the investigation and, if necessary,
the remediation of that site.
The Company is continuing its investigation regarding the identities of
parties connected to several additional MGP sites, the relative relationships
of the Company and other parties to those sites and the degree, if any, to
which the Company should undertake shared voluntary efforts with others at
individual sites.
The Company has been notified by regulators of its involvement or potential
involvement in several 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 sites.
In 1994, the Company accrued a liability for the estimated costs associated
with investigation and remediation activities for certain MGP sites and for
sites other than MGP sites. This accrual was not material to the results of
operations of the Company. Due to the lack of information with respect to the
operation of MGP sites for which a liability has not been accrued and due to
the uncertainty concerning questions of liability and potential environmental
harm, the extent and cost of required remedial action, if any, are not
currently determinable. The Company cannot predict the outcome of these
matters or the extent to which other MGP sites may become the subject of
inquiry.
(2) As required under the Nuclear Waste Policy Act of 1982, the Company
entered into a contract with the DOE under which the DOE agreed to dispose of
the Company's spent nuclear fuel. The Company cannot predict whether the DOE
will be able to perform its contractual obligations and provide interim
storage or permanent disposal repositories for spent nuclear fuel and/or
high-level radioactive waste materials on a timely basis.
With certain modifications, the Company's spent fuel storage facilities 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, dry storage may be necessary.
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>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE VIII - RESERVES
Year Ended December 31, 1994
- ----------------------------------------------------------------------------------------------------------------------
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 $ 2,305,141 $ 5,151,386 $ -0- $ 4,935,742 $ 2,520,785
============== ============== ============== ============== ==============
Reserves other than those
deducted from assets on
the balance sheet:
Injuries and damages $ 2,094,006 $ 980,440 $ -0- $ 862,285 $ 2,212,161
============== ============== ============== ============== ==============
Property insurance
reserve $ 23,217,772 $ (23,217,772) $ -0- $ -0- $ -0-
============== ============== ============== ============== ==============
Reserve for possible coal
mine investment losses $ 8,406,753 $ -0- $ -0- $ 401,783 $ 8,004,970
============== ============== ============== ============== ==============
Reserve for employee
retirement and compensation
plans $ 65,626,193 $ 46,044,119 $ -0- $ 23,654,899 $ 88,015,413
============== ============== ============== ============== ==============
Reserve for environmental
investigation and
remediation costs $ -0- $ 1,976,716 $ -0- $ -0- $ 1,976,716
============== ============== ============== ============== ==============
</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>
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 1995 definitive proxy statement dated March 31, 1995,
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 1995 definitive proxy statement dated March 31, 1995, 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, 1994, owned 25,027,393 shares of Common Stock (15.9% 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 1995 definitive proxy
statement dated March 31, 1995, 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 1995 definitive proxy statement dated March
31, 1995, 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-third
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 Exhibit 4(e) and
4(f), File No. 33-57835.
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 LLP.
Exhibit No. 23(b) Consent of Richard E. Jones.
____________
*Incorporated herein by reference as indicated.
+Management contract or compensation plan or arrangement 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 1994 and the portion of the first quarter of
1995 prior to the filing of this 10-K:
Date of Report Item Reported
______________ _____________
January 23, 1995 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 24th day of March, 1995.
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) Officer and Director
/s/ Charles D. Barham, Jr. Principal Financial
(Executive Vice President Officer and Director
and Chief Financial Officer)
/s/ Paul S. Bradshaw Principal Accounting
(Vice President and Controller) Officer
/s/ Edwin B. Borden Director March 24, 1995
/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/ 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> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION (EXTRACTED
FROM FINANCIAL STATEMENTS AS OF DECEMBER 31, 1994) AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000017797
<NAME> CAROLINA POWER & LIGHT COMPANY
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $6,349,484
<OTHER-PROPERTY-AND-INVEST> $360,611
<TOTAL-CURRENT-ASSETS> $678,430
<TOTAL-DEFERRED-CHARGES> $646,580
<OTHER-ASSETS> $176,058
<TOTAL-ASSETS> $8,211,163
<COMMON> $1,306,009
<CAPITAL-SURPLUS-PAID-IN> ($790)
<RETAINED-EARNINGS> $1,280,960
<TOTAL-COMMON-STOCKHOLDERS-EQ> $2,586,179
$0
$143,801
<LONG-TERM-DEBT-NET> $2,530,773
<SHORT-TERM-NOTES> $0
<LONG-TERM-NOTES-PAYABLE> $0
<COMMERCIAL-PAPER-OBLIGATIONS> $68,100
<LONG-TERM-DEBT-CURRENT-PORT> $275,050
$0
<CAPITAL-LEASE-OBLIGATIONS> $0
<LEASES-CURRENT> $0
<OTHER-ITEMS-CAPITAL-AND-LIAB> $2,607,260
<TOT-CAPITALIZATION-AND-LIAB> $8,211,163
<GROSS-OPERATING-REVENUE> $2,876,589
<INCOME-TAX-EXPENSE> $198,535
<OTHER-OPERATING-EXPENSES> $2,233,734
<TOTAL-OPERATING-EXPENSES> $2,432,269
<OPERATING-INCOME-LOSS> $444,320
<OTHER-INCOME-NET> $65,414
<INCOME-BEFORE-INTEREST-EXPEN> $509,734
<TOTAL-INTEREST-EXPENSE> $196,567
<NET-INCOME> $313,167
$9,609
<EARNINGS-AVAILABLE-FOR-COMM> $303,558
<COMMON-STOCK-DIVIDENDS> $256,021
<TOTAL-INTEREST-ON-BONDS> $183,891
<CASH-FLOW-OPERATIONS> $730,756
<EPS-PRIMARY> $2.03
<EPS-DILUTED> $2.03
<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,
-----------------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
(Thousands of Dollars)
Earnings, as defined:
Net income............................................. $ 313,167 $ 346,496 $ 379,635 $ 376,974 $ 380,358
Fixed charges, as below................................ 213,821 237,098 253,215 279,960 337,792
Income taxes, as below................................. 180,518 181,653 211,717 206,004 175,322
--------- --------- --------- --------- ---------
Total earnings, as defined........................... $ 707,506 765,247 $ 844,567 $ 862,938 $ 893,472
========= ========= ========= ========= =========
Fixed Charges, as defined:
Interest on long-term debt............................. $ 183,891 205,182 $ 223,158 $ 233,268 $ 236,473
Other interest......................................... 16,119 16,419 15,717 33,352 88,086
Imputed interest factor in rentals-charged
principally to operating expenses.................... 13,811 15,497 14,340 13,340 13,233
--------- --------- --------- --------- ---------
Total fixed charges, as defined...................... $ 213,821 237,098 $ 253,215 $ 279,960 $ 337,792
========= ========= ========= ========= =========
Earnings Before Income Taxes............................. $ 493,685 528,149 $ 591,352 $ 582,978 $ 555,680
========= ========= ========= ========= =========
Ratio of Earnings Before Income Taxes to Net Income...... 1.58 1.52 1.56 1.55 1.46
Income Taxes:
Included in operating expenses......................... $ 198,238 189,535 $ 210,266 $ 200,711 $ 156,934
Included in other income:
Income tax expense (credit).......................... (9,425) 392 5,885 9,686 (34,397)
Harris Plant carrying costs.......................... - - 1,969 1,563 (3,539)
Other income, net.................................... - - 58 25 21
Included in AFUDC - borrowed funds..................... - - 2,060 2,694 3,081
Included in AFUDC - deferred taxes in nuclear
fuel amortization and book depreciation.............. (8,295) (8,274) (8,521) (8,675) (8,869)
Included in cumulative effect of change in
accounting for revenues.............................. - - - - 62,091
--------- --------- --------- --------- ---------
Total income taxes................................... $ 180,518 181,653 $ 211,717 $ 206,004 $ 175,322
========= ========= ========= ========= =========
Fixed Charges and Preferred Dividends Combined:
Preferred dividend requirements........................ $ 9,609 9,609 $ 14,798 $ 26,265 $ 29,771
Portion deductible for income tax purposes............. (312) (312) (321) (321) (321)
--------- --------- --------- --------- ---------
Preferred dividend requirements not deductible......... $ 9,297 9,297 $ 14,477 $ 25,944 $ 29,450
========= ========= ========= ========= =========
Preferred dividend factor:
Preferred dividends not deductible times ratio of
earnings before income taxes to net income......... $ 14,689 14,131 $ 22,584 $ 40,213 $ 42,997
Preferred dividends deductible for income taxes...... 312 312 321 321 321
Fixed charges, as above.............................. 213,821 237,098 253,215 279,960 337,792
Total fixed charges and preferred dividends --------- --------- --------- --------- ---------
combined......................................... $ 228,822 251,541 $ 276,120 $ 320,494 $ 381,110
========= ========= ========= ========= =========
Ratio of Earnings to Fixed Charges and Preferred
Dividends Combined..................................... 3.09 3.04 3.06 2.69 2.34
Ratio of Earnings to Fixed Charges ...................... 3.31 3.23 3.34 3.08 2.65
</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, Registration
Statement No. 33-50597 on Form S-3, and Registration Statement
No. 33-57835 on Form S-3 of Carolina Power & Light Company, of
our report dated February 13, 1995, appearing in this Annual
Report on Form 10-K of Carolina Power & Light Company for the
year ended December 31, 1994.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
March 24, 1995
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, 1994 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, Registration Statement No. 33-50597 on
Form S-3 and Registration Statement No. 33-57835 on Form S-3 and
the related Prospectuses, which are a part of such Registration
Statements.
/s/ Richard E. Jones
Senior Vice President, General Counsel
and Secretary
March 24, 1995
