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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, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
________ _________
Commission file number 1-3382
______
CAROLINA POWER & LIGHT COMPANY
____________________________________________________
(Exact name of registrant as specified in its charter)
411 Fayetteville Street
North Carolina 56-0165465 Raleigh, North Carolina 27601
_____________________________________________________________________
(State or other (I.R.S. (Address of principal (Zip Code)
jurisdiction of Employer executive offices)
incorporation or Identification
organization) No.)
919-546-6111
____________
(Registrant's telephone number)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
__________________________________________________________
Title of each class Name of each exchange on which registered
___________________ _________________________________________
Common Stock (Without Par Value) New York Stock Exchange
Pacific Stock Exchange
Quarterly Income Capital Securities New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
__________________________________________________________
Preferred Stock (Without Par Value, Cumulative)
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes X . No .
__ __
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the voting stock held by non-affiliates at
February 29, 1996, was $5,682,940,192.
Shares of Common Stock (Without Par Value) outstanding at
February 29, 1996: 152,102,922.
DOCUMENTS INCORPORATED BY REFERENCE:
___________________________________
Portions of the Company's 1996 definitive proxy statement dated March 29,
1996, 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. . . . . . . . . . . . . . . 7
Construction Program . . . . . . . . . . . . . . . . . 11
Financing Program . . . . . . . . . . . . . . . . . . . 12
Retail Rate Matters . . . . . . . . . . . . . . . . . . 13
Wholesale Rate Matters . . . . . . . . . . . . . . . . 15
Environmental Matters . . . . . . . . . . . . . . . . . 16
Nuclear Matters . . . . . . . . . . . . . . . . . . . . 20
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . 24
Other Matters . . . . . . . . . . . . . . . . . . . . . 25
Operating Statistics . . . . . . . . . . . . . . . . . 28
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 29
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . 29
Item 4. Submission of Matters to a Vote of Security Holders . . 30
Executive Officers of the Registrant . . . . . . . . . . . . 31
PART II
Item 5. Market for the Registrant's Common Equity and Related
Shareholder Matters . . . . . . . . . . . . . . . . . . . . 33
Item 6. Selected Consolidated Financial Data . . . . . . . . . 34
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation . . . . . . . . . . . . . 35
Item 8. Consolidated Financial Statements and Supplementary Data 42
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . 65
PART III
Item 10. Directors and Executive Officers of the Registrant . . 65
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . 65
Item 12. Security Ownership of Certain Beneficial Owners and
Management . . . . . . . . . . . . . . . . . . . . . . . . . 65
Item 13. Certain Relationships and Related Transactions . . . . 65
PART IV
Item 14. Exhibits, Consolidated Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . 66
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 7,203 employees at December
31, 1995. 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 of North Carolina extending to the Atlantic coast between
the Pamlico River and the South Carolina border, the lower
Piedmont section of 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 3.75 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, 3
municipalities and 2 electric membership corporations (North
Carolina Electric Membership Corporation, which has 27 members, 17
of which are served by the Company's system, and French Broad
Electric Membership Corporation). At December 31, 1995, the
Company was furnishing electric service to approximately
1,087,000 customers.
3. SALES. During 1995, 32% of operating revenues was
derived from residential sales, 21% from commercial sales, 24%
from industrial sales, 16% from resale sales and 7% from other
sources. Of such operating revenues, approximately 67% was
derived from North Carolina retail customers, 14% from South
Carolina retail customers, 16% from wholesale customers under
contract and 3% from bulk power sales. For the twelve months
ended December 31, 1995, average revenues per kilowatt-hour (kWh)
sold to residential, commercial and industrial customers were 8.03
cents, 6.67 cents and 5.12 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
____ _______ _______ _______
1991 12,472 $1,040.70 8.34 cents
1992 12,396 1,029.82 8.31
1993 13,167 1,090.16 8.28
1994 12,559 1,032.00 8.22
1995 13,242 1,062.82 8.03
4. PEAK DEMAND.
a. A 60-minute system peak demand record of 10,156
megawatts (MW) was reached on August 14, 1995. 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 7.0%.
b. Total system peak demand for 1993 increased by 3.8%,
for 1994 increased by 5.8%, and for 1995 increased by 0.12%, as
compared with the preceding year. The Company currently projects
that system peak demand will increase at an average annual growth
rate of approximately 2.5% 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 1993-1995 were 59.0%, 56.0% and 58.9%, respectively.
The Company forecasts capacity margins of 12.5% over anticipated
system peak load for 1996 and 11.5% for 1997. 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 PART I, 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 PART I, ITEM 1, "Generating
Capability," paragraph 1.
GENERATING CAPABILITY
_____________________
1. FACILITIES. The Company has a total system installed
generating capability (including Power Agency's share) 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, 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 1995. Over the next
ten years, system sales growth is forecasted to average
approximately 2.5% per year and annual growth in system peak
demand is projected to average approximately 2.5%. The Company's
generation additions schedule, which is updated annually, reflects
no additions until 1997, when two new combustion turbine
generating units, construction of which began in 1995, are
currently scheduled to commence commercial operation. These
units, having a total generating capacity of approximately 240 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 $65 million. In December 1994, the
Company filed preliminary plans with the North Carolina Utilities
Commission (NCUC) and the North Carolina Division of Environmental
Management to install up to 1200 MW of new combustion turbine
generating units adjacent to the Company's Lee Steam Electric
Plant in Wayne County, North Carolina. The Company's current plan
is to add 500 MW of combustion turbine capacity in 1998. The
units would primarily be used during periods of summer and winter
peak demands. The Company filed an Application for a Certificate
of Public Convenience and Necessity with the NCUC on September 27,
1995 seeking permission to construct the 500 MW of capacity. The
schedule, which is subject to change, calls for construction of
the 500 MW of combustion turbine capacity to begin in 1996, with
the aggregate cost expected to approximate $135 million and
commercial operation anticipated to begin in 1998. The NCUC hearing in
this matter was held on January 9, 1996, but the NCUC has not yet
rendered its decision. In addition to the proposed Wayne County
project, the generation addition schedule provides for the
addition of 2,400 MW in combustion turbine capacity, and 1,800 MW
of combined cycle capacity at undesignated sites over the period
1999 to 2010, and a 500 MW baseload coal unit in 2010 at an
undesignated site.
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 Power Company (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. 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. On January 20, 1995, the FERC issued an order
accepting the purchase power contract. The estimated minimum
annual payment for power under the six-year agreement is $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 $63.8 million in 1995.
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 2009. The upgrade to the transmission
interconnection in the Company's western service area was completed
in 1992, and the Company recently announced plans to upgrade an
existing 138 kV transmission line between Person County, North Carolina
and Danville, Virginia, rather than establishing a new interconnection
in its eastern service area. The upgrade is currently expected to be
completed by mid-1998. 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, and energy-related
operation and maintenance expenses. Purchases under this
agreement, including transmission use charges, totaled $61.8
million in 1995.
4. POWER AGENCY. Pursuant to a 1981 Power Coordination
Agreement, as amended, entered into between the Company and 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 $26
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 $39.4 million in 1995.
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 power
supply.
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
after existing contracts expire, or new opportunities are created
for the Company to expand its wholesale load.
On March 29, 1995, the FERC issued a Notice of
Proposed Rulemaking (Proposal) that would establish guidelines for
wholesale wheeling of electric power. The Proposal would require
utilities to provide open access to their interstate power
transmission network and not give themselves preferential access
to their own services. Currently, such power transfers are
negotiated case-by-case or under long-term contracts. The FERC's
Proposal would establish a standard generic set of terms and
conditions, and would define the terms under which independent
power producers and others could gain access to a utility's
transmission grid to sell power to a wholesale customer such as a
municipality or rural electric cooperative. The Company does not
favor the Proposal, which is expected to be finalized sometime in
1996, but rather favors the continued evolution of wholesale
electric markets. The Company filed comments regarding the
Proposal with the FERC on August 7, 1995. In those comments, the
Company disagreed with the FERC's approach to regulating wholesale
wheeling, and indicated that in issuing the proposed guidelines
the FERC exceeded its authority. The Company also suggested ways
to improve the proposed guidelines, in the event that they are
enacted. On August 11, 1995, the Company filed comments
concerning the FERC's inquiry regarding the potential
environmental impact of the Proposal. In those comments, the
Company noted the FERC's failure to comply with several
requirements of the National Environmental Policy Act. On
October 4, 1995, the Company filed reply comments which addressed
a number of specific points made in the initial comments other
parties filed regarding the Proposal. The Company cannot predict
the outcome of this matter or the impact of the Proposal on its
future results of operations and financial position.
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 competition 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 competition. 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 electric competition would be in the public interest, how
it could be implemented in North Carolina and whether it could be
implemented without changing state law. On July 21, 1995, the
NCUC issued an order indicating that it will not convene a formal
hearing to investigate these issues at this time. The NCUC's
order noted that North Carolina's territorial assignment statute
appears to prohibit retail competition, and the issue involves a
number of jurisdictional uncertainties. The NCUC concluded that
for the time being, it should monitor developments in other states
and at the FERC regarding jurisdictional and other issues
affecting retail competition. Instead of convening a hearing, the
NCUC requested that interested parties suggest, by mid-September
1995, specific issues for further consideration in this docket.
On September 19, 1995, the Company filed with the NCUC a list of
specific issues it believes should be addressed prior to any form
of retail competition being allowed in the state of North
Carolina. The issues include, but are not limited to: (i)
concerns about system planning and service reliability; (ii) the
drastic changes to the laws governing utility regulation that
would need to be implemented before retail competition could be
allowed; (iii) whether retail choice promotes cost reduction
rather than cost shifting; and (iv) how stranded costs will be
determined and recovered. The NCUC also indicated that it is
considering holding informal proceedings in the future to gather
more information on competition issues. The Company cannot
predict the outcome of this matter.
The issues described above have created greater
planning uncertainty and risks for the Company. The Company has
been addressing these risks in the wholesale sector by securing
long-term contracts with all of its wholesale customers,
representing approximately 16% of the Company's 1995 operating
revenues. These long-term contracts will allow the Company
flexibility in managing its load and efficiently planning its
future resource requirements; however, NCEMC does have the
contractual right, subject to five years' advance notice, to
reduce the baseload capacity it purchases from the Company after
December 31, 2000. See PART I, ITEM 1, "Competition and
Franchises," paragraph 1.d for further discussion of the contract
between the Company and NCEMC. In the industrial sector, the
Company is continuing to work to meet the energy needs of its
customers. Other elements of the Company's strategy for
responding 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.
c. By order issued May 13, 1994, the NCUC established a
docket (Docket No. E-100, Sub 73) to consider proposed self-generation
deferral rate guidelines, and dispersed energy
facilities and economic development rates. By order issued July
21, 1994, the NCUC approved and adopted guidelines to apply to
requests for self-generation deferral rates. The guidelines allow
the Company to adjust rates to retain certain loads for which
self-generation is feasible. 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. In addition, on June 8, 1995, and July 5, 1995, the
Company filed with the NCUC and the SCPSC, respectively, an
Economic Development Rider which will permit the Company to
provide a discount on the first five years of electric service it
provides to businesses that locate to or expand within the
Company's service territory if they meet certain criteria, including
thresholds for the size of new load, the amount of investment and the
number of new jobs provided by the businesses. The Economic
Development Rider was approved by the NCUC on July 10, 1995, and by the
SCPSC on July 21, 1995.
d. In June 1994, the FERC granted final approval of a
Power Coordination Agreement (PCA) and an Interchange Agreement,
both dated August 27, 1993, which set forth explicitly the future
relationship between the Company and NCEMC, and established a
framework under which they will operate (Project Nos. 432-004 and
2748-000). 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 allowed
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. Pursuant to this authority, NCEMC's board of directors
awarded a power-supply contract for 200 MW to another supplier
beginning on January 1, 1996. The contract, which has been
accepted by the FERC, displaced 200 MW of baseload capacity that
NCEMC previously purchased from the Company; however, the Company
expects to continue to supply not less than 1000 MW of electricity
to NCEMC from January 1, 1996 until at least December 31, 2000.
Load reductions beyond the year 2000 are subject to specific
limits and require five years' advance notice. NCEMC has not
officially notified the Company that any of the baseload power to
be supplied to NCEMC by the Company beginning in 2001 will be
provided by another entity; however, on November 4, 1994, NCEMC
issued two requests for proposals (RFP) to provide up to 225 MW
(for a minimum of ten years) of baseload power NCEMC would
otherwise purchase from the Company beginning in 2001, an
additional block of up to 225 MW per year beginning in 2002, and a
third block of up to 225 MW per year beginning in 2003. On March
3, 1995, the Company submitted a bid in response to each RFP to
compete for this load. On September 13, 1995, NCEMC notified the
Company that it had decided to suspend negotiations regarding the
Company's bids at this time, but requested that the Company leave
its bids open for future consideration. Negotiations between the
Company and NCEMC have resumed. The Company cannot predict the
outcome of these matters.
e. By order issued February 24, 1994, the NCUC established
a docket (Docket No. E-100, Sub 71), 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 NCUC also opened a related docket (Docket No. M-100,
Sub 124)to determine 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. By
orders issued in October 1995, the NCUC issued a new rule, as well
as a set of guidelines, that require natural gas and electric
utility companies to obtain NCUC approval prior to offering anyone
incentives, of more than nominal value, that are intended to
influence the recipient's fuel choice. This rule sets forth the
procedures a utility must follow to gain such approval, and the
guidelines identify the substantive issues that must be addressed
by any utility seeking to offer such incentives. The NCUC also
ruled that it would not consider the impact of a utility's program
involving the provision of an incentive on competitors of the
utility.
By order issued September 30, 1994, the SCPSC established a
docket for a similar generic proceeding (Docket No. 94-618-E/G).
The filing of testimony and scheduling of hearings in the SCPSC
proceeding have been indefinitely postponed. The Company cannot
predict the outcome of this matter.
f. On March 29, 1995, a bill was introduced in the North
Carolina General Assembly (General Assembly) to facilitate the
construction of an interstate natural gas pipeline to be built
from Aiken, South Carolina to Leland, North Carolina. The bill,
as originally introduced, proposed to, among other things, exempt
from utility regulation all power generating facilities that
receive gas from the pipeline as fuel. On July 29, 1995, the
General Assembly passed a bill directing the Joint Utility Review
Committee of the General Assembly (Utility Review Committee) to
study whether or not the extension of interstate natural gas
pipelines into North Carolina can and should be encouraged by
amending the North Carolina Public Utilities Act (Public Utilities
Act) to exempt from regulation as public utilities facilities that
sell electric power and thermal energy generated with natural gas
from these pipelines. The bill also directs the Utility Review
Committee to study whether the Public Utilities Act should be
amended to encourage the construction of new interstate pipelines
in North Carolina. The bill orders the Utility Review Committee
to report its findings and any recommendations regarding these
matters before the General Assembly convenes on May 13, 1996.
The Company cannot predict the outcome of this matter.
g. On March 22, 1995, a bill was introduced in the General
Assembly that would change fundamentally the nature of public
power agencies in the state. The bill, as originally introduced,
proposed to, among other things, permit certain organizational
changes among the state's municipal power agencies and provide
additional authority for the marketing of excess capacity and
energy. A substantially amended version of this bill, which
authorizes internal reorganization of the state's municipal power
agencies, and orders the Utility Review Committee to study other
issues contained in the original legislation and report its
findings and any recommendations to the General Assembly in 1996,
was passed by the General Assembly effective July 11, 1995. On
January 11, 1996, representatives of the state's municipal power
agencies informed the Utility Review Committee that they do not
wish to pursue additional statutory changes during the 1996
session of the General Assembly. The Company cannot predict the
outcome of this matter.
h. In late 1995, one of the Company's industrial customers
in the City of Darlington, South Carolina ("City"), requested that
the City become a municipal electric utility and provide retail
electric service to the area. If it were to become a municipal
electric utility, the City would possibly seek to purchase bulk
power from a supplier other than the Company. The Company has
undertaken efforts to educate the City's residents, businesses and
industries regarding the many costs and legal issues associated
with a municipalization effort. The City plans to undertake
studies to determine the feasibility of the municipalization
proposal. The results of those studies will likely determine
whether the proposal is presented to the City's voters. The
Company cannot predict the outcome of this matter.
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 1995 the Company expended
approximately $610 million for capital requirements. The Company
revised its capital program in 1995 as part of its annual business
planning process. Capital requirements, including anticipated
construction expenditures for plant modifications, for the years
1996 through 1998 are set forth below. These estimates include
Clean Air Act compliance expenditures of approximately $55
million, and generating facility addition expenditures of
approximately $327 million. See PART I, 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)
1996 1997 1998 TOTAL
____ ____ ____ _____
Construction Expenditures $406 $489 $447 $1,342
Nuclear Fuel Expenditures 103 64 105 272
AFUDC (15) (18) (33) (66)
____ ____ ____ ______
Net expenditures (a) 494 535 519 1,548
Mandatory Redemptions of 105 100 205 410
Long-Term Debt ____ _____ ____ ______
Long-Term Debt
TOTAL $599 $635 $724 $1,958
==== ==== ==== ======
_________________
(a) Reflects reductions of approximately $12 million, $7 million and
$9 million for 1996, 1997 and 1998, respectively, in net capital
requirements resulting from Power Agency's projected payment of its
ownership share of capital expenditures related to the Joint Facilities.
FINANCING PROGRAM
_________________
1. CAPITAL REQUIREMENTS. Based on the Company's most
recent estimate of capital requirements, the Company does not
expect to have external funding requirements in 1996. External
funding requirements, which do not include early redemptions of
long-term debt or redemptions of preferred stock, are expected to
approximate $14 million in 1997 and $76 million in 1998. 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 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 PART II, 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), under which an aggregate of $450 million principal
amount of First Mortgage Bonds, and an additional $125 million
combined aggregate principal amount of First Mortgage Bonds and/or
unsecured debt securities of the Company remain available for
issuance.
b. The Company has on file with the SEC a shelf
registration statement (File No. 33-5134) enabling the Company to
issue up to $180 million of Serial Preferred Stock.
3. FINANCINGS. External financings during 1995 included:
- 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.
- On April 21, 1995, the Company issued $125 million
principal amount of Quarterly Income Capital
Securities (Series A Subordinated Deferrable
Interest Debentures) ("Capital Securities") at an
interest rate of 8.55%, for net proceeds to the
Company of approximately $121 million. The proceeds
from the issuance of the Capital Securities were
applied to the Company's ongoing maintenance and
construction program, and for other general
corporate purposes.
4. REDEMPTIONS/RETIREMENTS. Redemptions and retirements
during 1995 and early 1996 included:
- The retirement on January 1, 1995, of $125 million
principal amount of First Mortgage Bonds, 5.20%
Series, which matured on that date.
- The retirement on April 1, 1995, of $77.1 million
principal amount of First Mortgage Bonds, 9.14%
Series, which matured on that date.
- The retirement on June 8, 1995, of $25 million
principal amount of First Mortgage Bonds, 8.92%
Secured Medium-Term Notes, Series A, which matured
on that date.
- The retirement on July 20, 1995, of $25 million
principal amount of First Mortgage Bonds, 8.86%
Secured Medium-Term Notes, Series A, which matured
on that date.
- The retirement on November 1, 1995, of $23 million
principal amount of First Mortgage Bonds, 8.85%
Secured Medium-Term Notes, Series A, which matured
on that date.
- The redemption on February 27, 1996, of $125 million
principal amount of First Mortgage Bonds, 8 7/8%
Series due February 15, 2021, at 105.69% of the
principal amount of such bonds plus accrued interest
to the date of redemption.
- The redemption on March 26, 1996, of $22.626 million
principal amount of First Mortgage Bonds, 8 1/8%
Series due November 1, 2003, at 100.52% of the
principal amount of such bonds plus accrued interest
to the date of redemption.
- The redemption on March 26, 1996, of $100 million
principal amount of First Mortgage Bonds, 7 3/4%
Series due 2003, at 100.18% of the principal
amount of such bonds plus accrued interest to the
date of redemption.
5. CREDIT FACILITIES. The Company's credit facilities
presently total $685 million, consisting of long-term agreements
totaling $585 million and a $100 million short-term agreement.
The Company is required to pay minimal annual commitment fees to
maintain its credit facilities. See PART II, ITEM 8, Notes to
Consolidated Financial Statements, Note 3, for a more detailed
discussion of the Company's credit facilities.
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 and service 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, safety and the environment. Utilities are
required to file their Integrated Resource Plans (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 Company filed its 1995
IRP with the NCUC on April 28, 1995, and with the SCPSC on July 3,
1995. By order dated February 20, 1996, the NCUC approved the
Company's 1995 IRP as filed. The SCPSC established April 8, 1996
as the deadline for parties to intervene and/or submit comments
regarding the Company's 1995 IRP. The Company cannot predict the
outcome of this matter.
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. 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.
By order dated September 6, 1995, the NCUC approved the
Company's request for a reduction in the fuel expense portion of
the Company's rates, reflecting the Company's improved nuclear
performance, and refunding approximately $44 million in fuel-related
revenues, which exceeded actual costs for the test period,
and $6 million in related interest. The new fuel factor became
effective on September 15, 1995, and will remain in effect for one
year. The Company's 1996 fuel case hearing is scheduled to begin
on August 6, 1996.
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 1996 fuel case hearing was held on
March 14, 1996, but the SCPSC has not yet issued an order in this
proceeding.
The Company cannot predict the outcome of these matters.
6. AVOIDED COST PROCEEDINGS. The NCUC opened Docket No.
E-100, Sub 74 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 hearings in this docket concluded on March 9, 1995, and on
June 23, 1995, the NCUC approved, with one minor exception, the
Company's proposed lower avoided cost rates. The Company
anticipates that the revised lower rates will result in reduced
purchase power expense to the Company, as it enters into new
purchase agreements with qualifying facilities. The next NCUC
avoided cost proceeding will be held in 1997.
WHOLESALE RATE MATTERS
______________________
1. GENERAL. The Company is subject to regulation by the
FERC with respect to rates for transmission and sale of electric
energy at wholesale, the interconnection of facilities in
interstate commerce (other than interconnections for use in the
event of certain emergency situations), the licensing and
operation of hydroelectric projects and, to the extent the FERC
determines, accounting policies and practices. The Company and
its wholesale customers last agreed to a general increase in
wholesale rates in 1988; however, wholesale rates have been
adjusted since that time through contractual negotiations.
2. FERC MATTERS.
a. By letter dated May 31, 1995, the Company requested
that the FERC (Docket No. 95-1139) establish a return on equity
(ROE) in connection with the formula rates provided in the PCA
dated August 27, 1993 between the Company and NCEMC. The
requested ROE is consistent with the rate of return on common
equity approved by the NCUC in the Company's 1988 rate case. On
February 6, 1996, the Company filed an offer of settlement with
the FERC to set the ROE at 10.75 percent. The FERC staff filed
comments supporting the settlement on February 14, 1996. The
Company cannot predict the outcome of this matter.
b. On May 31, 1995, the Company filed a petition with the
FERC (Docket No. EL95-50) seeking to recover certain fuel costs
from the Company's wholesale customers. These costs are related
to the Company's $6.8 million buyout of its contractual agreement
with The Arch Coal Sales Company (Arch Coal). As a result of this
buyout, the Company will purchase less coal from Arch Coal in the
future and will pay a lower purchase price for that coal. The
Company cannot predict the outcome of this matter.
c. On July 7, 1995, Smithfield Foods, Inc., doing business
as Carolina Foods Processors, Inc. (Carolina Foods), filed a
Complaint with the FERC (Docket No. EL95-60) alleging that certain
charges imposed upon NCEMC under the PCA between the Company and
NCEMC are unreasonable. These charges are related to generation
installed by Carolina Foods, which receives electric service from
Four County EMC (a customer of NCEMC). The Company filed its
response to the Complaint on August 10, 1995. The Company cannot
predict the outcome of this matter.
d. On March 1, 1996, the Company and Power Agency entered into a
contractual agreement which provides that Power Agency will delay construction
and startup of its 183.7 MW combustion turbine generating project until
2004. (That project was scheduled to begin commercial operation in June
of 1998.) Pursuant to a 1981 Power Coordination Agreement, as amended,
between Power Agency and the Company, Power Agency is obligated to purchase
this electricity from the Company from 1995 through May 31, 1998. As a
result of the new agreement, Power Agency will purchase peaking capacity from
the Company as follows: 110 MW from June 1, 1998 through December 31, 1998,
116 MW in 1999 and 183.7 MW from 2000 through 2003. The new agreement must
be submitted to the FERC for approval. The Company cannot predict the
outcome of this matter.
ENVIRONMENTAL MATTERS
_____________________
1. GENERAL. In the areas of air quality, water quality,
control of toxic substances and hazardous and solid wastes and
other environmental matters, the Company is subject to regulation
by various federal, state and local authorities. The Company
considers itself to be in substantial compliance with those
environmental regulations currently applicable to its business and
operations and believes it has all necessary permits to conduct
such operations. 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 1996 through 1998, are included in
the estimates of capital requirements under PART I, 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 for these emissions,
which had to be met by January 1, 1995. The Act's Phase II require-
ments, which contain more stringent provisions, will become effective
January 1, 2000. The Act required that a Title IV permit application,
including certifications regarding compliance with the Phase II sulfur
dioxide and nitrogen oxides emissions requirements, be submitted to
the appropriate permitting authority for each of the Company's plants
by January 1, 1996. The Company submitted its Title IV permit
applications in late 1995. The Company plans to meet the Phase II sulfur
dioxide emissions requirements by utilizing the most economical
combination of lower sulfur coal and sulfur dioxide emission
allowances. Each sulfur dioxide emission allowance allows a
utility to emit one ton of sulfur dioxide. The has Company purchased
emission allowances under the Environmental Protection Agency's
(EPA) emission allowance trading program in order to supplement the
allowances the EPA granted to the Company. Installation of additional
equipment will be necessary to reduce nitrogen oxides emissions. The Company
estimates that future capital costs necessary to comply with Phase II of
the Act will approximate $180 million. Increased operating and maintenance
costs, including emission allowance expense, and increased fuel
costs are not expected to be material to the results of operations
of the Company. As the Company's plans for compliance with the
Act's requirements are subject to change, the amount required for
capital expenditures and for increased operating, maintenance and
fuel expenditures cannot be determined with certainty at this
time. 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, a low-level nuclear waste disposal site located 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 low-level radioactive 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. On
June 5, 1995, a De Maximus Consent Decree (Consent Decree) was
filed on behalf of the Maxey Flats Steering Committee in the
United States District Court for the Eastern District of Kentucky
(Civil Action No. 95-58). The Consent Decree provides for the
performance of the Initial Remediation Phase and the Balance of
Remediation Phase, and for the reimbursement of certain response
costs incurred by the EPA. The Department of Justice received
comments relating to the proposed Consent Decree until August 18,
1995 and is awaiting court approval of the Consent Decree.
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, on-site cleanup activities were
completed in July 1995, and the operation and maintenance (O&M)
phase began. During the O&M phase, twenty-three groundwater
monitoring wells will be sampled quarterly for a minimum 10-year
period. There is currently over 90% participation by the PRPs in
the site cleanup. The Company contributed approximately $293,000
to the waste generators' group. In late December 1995, the Rose
Chemicals Steering Committee (a group of PRPs with respect to the
Rose site) issued refunds of excess monies collected for site
remediation. The Company received a refund of $158,639.
Although the Company cannot predict the outcome of this matter, it
does not anticipate that it will be required to contribute
additional funds to complete remediation of this site.
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 on 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 has submitted a final report to
the EPA. On July 12, 1995, the Company was informed that the EPA
had approved the final report regarding the site on October 13,
1994. Now that the final report has been approved, the settlement
agreement between the Company and the Elliot's Auto Parts PRP
Committee will be implemented. In this settlement, the Company
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 (AOC) with the EPA. Although the
Company cannot predict the outcome of this matter, it does not
anticipate that future costs associated with this site,
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 Little Rock, 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. The wastes sent from the Company's
facilities to the Seaboard site consisted primarily of cleaning
and degreasing solvents, solvent contaminated oils and paint-related waste.
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 AOC 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 has joined the
Seaboard Group II (a group of PRPs formed to conduct additional
work at the Seaboard site). The Seaboard Group II, the City of
High Point, North Carolina and the DEHNR have negotiated an AOC
that requires the Seaboard Group II and the City of High Point to
conduct a joint Remedial Investigation (RI). The Company has
executed that AOC. The City of High Point operated a landfill
that bounds the Seaboard site on three sides. The City of High
Point has conducted studies of groundwater on its site and those
studies have indicated that a joint RI is appropriate. 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. Wastes disposed of at the Macon-Dockery site
include antifreeze, used oils, metals, paint, solvent
wastes, and waste acids and bases. The Company made arrangements
in the past for the transportation and sale of waste oil and
residual oil to C&M Oil Distributors, a company that operated an
oil reprocessing facility at the Macon-Dockery site. However,
the information available to the Company indicates that no hazardous wastes
from Company facilities were sent to the site. In 1987, the EPA notified the
Company that it believed the Company was a PRP for costs associated with
the EPA's cleanup action at the Macon-Dockery site. The EPA
initiated a lawsuit in federal district court against entities other than
the Company to recover its cleanup costs. Some of the defendants in that
lawsuit brought claims against the Company. In 1989, the Company signed a
Consent Decree with the EPA which obligated the Company to pay $15,000 and
settled the Company's liability, if any, for third party contribution claims.
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. Discovery in this matter is
currently underway. Although the Company cannot predict the
outcome of this matter, it does not anticipate that costs
associated with this site, if any, 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. There are 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 continues to investigate the identities
of parties connected to individual MGP sites in North Carolina,
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.
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 DEM requested that, in response
to a 1979 spill of No. 2 fuel oil, the Company install a
groundwater compliance monitoring system at the Company's
Wilmington Oil Terminal located in New Hanover County, North
Carolina. During the second half of 1989, six groundwater
monitoring wells were installed. One of the six wells indicated
gasoline contamination and samples from a second well indicated
No. 2 fuel oil contamination. In February 1993, the DEM approved
a corrective action plan (CAP) for addressing gasoline and No. 2
fuel oil contamination. In 1995, the Company confirmed the
presence of off-site gasoline contamination; however, it is not
clear that the Company is responsible for off-site gasoline
contamination. The Company is proceeding to seek approval to
modify the CAP so that on and off-site contamination will be
remediated by natural attenuation and degradation factors. The
Company sold the Wilmington Oil Terminal on March 1, 1996, but
will continue to address existing on- and off-site gasoline and
No. 2 fuel oil contamination. 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.
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 noncompliance, 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 both disposal facilities
for low-level radioactive waste and storage facilities for spent
nuclear fuel. See paragraphs 2 and 3 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 1996, 1997
and 1998 are expected to total approximately $50 million, $34
million and $41 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 use 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, 1995, sufficient on-site spent
nuclear fuel storage capability is available for the full-core
discharge of Brunswick Unit No. 1 through 1997, Brunswick Unit No.
2 through 1998, and Robinson Unit No. 2 through 1997 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, at the
Company's request, the NRC suspended 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 PART I, 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 were participants in the Southeast regional compact and
disposed of waste at a disposal site in South Carolina along with
other members of the compact. Effective July 1, 1995, South
Carolina withdrew from the Southeast regional compact and excluded
North Carolina waste generators from the existing disposal site in
South Carolina. As a result, the State of North Carolina does not
have access to a low-level radioactive waste disposal facility.
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, has submitted a license application for the site
it selected in Wake County, North Carolina to the North Carolina
Division of Radiation Protection. 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. The Company's nuclear plants in North Carolina
are currently storing low-level waste on site and are developing
additional storage capacity to accommodate future needs.
The Company's nuclear plant in South Carolina has access to the existing
disposal site in South Carolina. Although the Company cannot predict the
outcome of this matter, it does not expect the cost of providing
additional on-site storage capacity for low-level radioactive
waste to be material to the results of operations or financial
position of the Company.
4. DECOMMISSIONING.
a. Pursuant to an 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 an 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 agreements. Decommissioning cost
provisions, which are included in depreciation and amortization,
were $31.2 million in 1995, $29.5 million in 1994 and $34.0
million in 1993. Accumulated decommissioning costs, which are
included in accumulated depreciation, were $288.4 million at
December 31, 1995, and $252.7 million at December 31, 1994, 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 $110.2 million
at December 31, 1995, and $67.6 million at December 31, 1994.
Trust earnings, which increase the trust balance with a
corresponding increase in accumulated decommissioning, were $4.5
million in 1995, $1.5 million in 1994, and $1.2 million in 1993.
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 the Brunswick and Harris nuclear
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 PART I,
ITEM 1, "Generating Capabilities," paragraph 1.
c. The Financial Accounting Standards Board has reached
several tentative conclusions with respect to its project
regarding accounting practices related to closure and removal of
long-lived assets. The primary conclusions as they relate to
nuclear decommissioning are: 1) the cost of decommissioning should
be accounted for as a liability and accrued as the obligation is
incurred; 2) recognition of a liability for decommissioning
results in recognition of an increase to the cost of the plant; 3)
the decommissioning liability should be measured based on
discounted cash flows using a risk-free rate; and 4)
decommissioning trust funds should not be offset against the
decommissioning liability. An exposure draft was issued in
February 1996, and it is uncertain what impacts, if any, the final
statement may have on the Company's accounting for nuclear
decommissioning and other closure and removal costs.
5. OPERATING LICENSES. Facility Operating Licenses,
issued by the NRC, for the Company's nuclear facilities allow for
a full 40 years of commercial operation. Expiration dates for
these licenses 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. 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. Although the Company cannot predict the outcome
of this matter, it does not expect the impacts of the new rule to
be material to the Company's results of operations.
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. In June 1995, the
Company completed and submitted the results of the second phase of
the IPEs (for externally initiated events) for the Company's three
nuclear plants. The results of the IPEs indicated that some
procedural changes may be required for the Harris and Brunswick
Plants. Those results also indicated that both minor procedural
changes and minor plant modifications will be required for the
Robinson Plant. The Company has filed an implementation plan with
the NRC which calls for all IPE actions to be implemented by 1998.
Although the Company cannot predict at this time the exact
magnitude of the financial and operational impacts of the second
phase of the IPEs, it does not expect those impacts to be material
to the results of operations or financial position of the Company.
c. Degradation of tubing internal to steam generators in
pressurized water reactor power plants (PWR's) due to
intergranular stress corrosion cracking has been an on-going
industry phenomenon. The Company has determined that the steam
generators at the Harris Plant are subject to steam generator
degradation and the Company is closely monitoring the steam
generator performance. Experience and testing conducted to date
indicate that the Harris Plant steam generators will not require
replacement before 2001. The steam generators at the H.B.
Robinson plant were replaced in 1982 and are expected to perform
until the plant's operating license expires. Although the Company cannot
predict the outcome of this matter, it does not expect the cost of
replacing the steam generators at the Harris Plant to be material
to the results of operations or financial position of the Company.
d. 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. For a more detailed discussion
of nuclear liability insurance, see PART II, ITEM 8, Notes to
Consolidated Financial Statements Note 10.B.
FUEL
____
1. SOURCES OF GENERATION. Total system generation
(including Power Agency's share) by primary energy source, along
with purchased power, for the years 1992 through 1996 is set forth
below:
1992 1993 1994 1995 1996
(estimated)
____ ____ ____ ____ ___________
Fossil 56% 54% 43% 44% 47%
Nuclear 27 31 42 42 42
Purchased Power 15 13 13 13 10
Hydro 2 2 2 1 1
2. COAL. The Company has intermediate and long-term agreements from
which it expects to receive approximately 73% of its coal burn requirements in
1996. During 1994 and 1995, the Company obtained approximately 84% (8,120,220
tons), and 86% (7,531,172 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 1995, the Company maintained from 35 to
99 days' supply of coal, based on anticipated burn rate. All of the coal that
the Company is currently purchasing under intermediate and long-term agreements
is considered to be low sulfur coal by industry standards. Recent amendments to
the Clean Air Act may result in increases in the price of low sulfur coal which
continue beyond the effective date of the second phase of the Act. See PART I,
ITEM 1, "Environmental Matters," paragraph 2. The Company purchased
approximately 1,690,000 tons of coal in the spot market during 1994 and
1,306,000 tons in 1995. The Company's contract coal purchase prices during
1995 ranged from approximately $23.00 to $54.00 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
____ _____ ________________
1991 47.40 190
1992 43.25 174
1993 43.10 172
1994 43.36 174
1995 44.46 179
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 12.6 million
and 8.8 million gallons of No. 2 oil during 1994 and 1995, 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 1.6 % of the
Company's total burned fuel cost. In 1995, No. 2 oil, natural gas and propane
accounted for 1.2 % 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 1997, Brunswick Unit No. 1 through 1998, Brunswick Unit
No. 2 through 1998, and the Harris Plant through 1999. The Company
expects to meet its future U3O8 requirements 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 a discussion of the Company's plans with respect to spent fuel storage,
see PART I, ITEM 1, "Nuclear Matters," paragraph 2.
5. DOE ENRICHMENT FACILITIES DECONTAMINATION AND DECOMMISSION 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 are being 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, 1995, the Company had a recorded liability of $61.8 million
representing its estimated share of the contributions. The Company is
recovering a corresponding regulatory asset as a component of fuel cost.
6. PURCHASED POWER. In 1995 the Company purchased 6,974,597 MWh or
approximately 13% of its system energy requirements (including Power Agency) and
had available 1,596 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, Subpart 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 hazard to a high hazard classification. In
accordance with the change in regulatory jurisdiction, the Company developed an
emergency action plan which meets FERC 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. In March 1995
the Company received comments on the report from the FERC. As a result of
these comments, and a meeting with FERC officials, the Company was requested to
perform further analyses and submit its findings to the FERC. The Company
subsequently submitted the first phase of the requested analyses to the FERC by
letter dated September 15, 1995. Depending on the outcome of the FERC's review,
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 dispute. The District Court action has been stayed
pending a decision by the FERC. Both parties have submitted briefs in the FERC
matter and are awaiting the FERC's decision. 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. On December 19, 1995, the jury returned a
verdict in favor of the U. S. Government. The Company has filed an appeal
of the jury's verdict. The Company cannot predict the outcome of this matter.
5. CARONET, INC. On November 29, 1994, the Company established a
wholly-owned subsidiary, CaroNet, Inc., (CaroNet) and the subsidiary joined a
regional partnership, BellSouth Carolinas PCS, L. P. (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. BellSouth is the general partner and
handles day-to-day management of the business. In anticipation of infra-
structure construction, the Company invested $50 million in CaroNet on
April 28, 1995. The Partnership began construction of the PCS system infra-
structure during the summer of 1995, and service start-up is anticipated by
mid-1996. CaroNet owns a ten percent limited partnership
interest in the Partnership and participates on the Partnership's executive
committee. On May 15, 1995 and May 22, 1995, CaroNet filed applications with
the NCUC and the SCPSC, respectively, for a Certificate of Public Convenience
and Necessity, seeking permission to provide wholesale intrastate
telecommunications services in North Carolina and South Carolina. By order
dated November 3, 1995, the NCUC stated that it will no longer regulate the
provision of wholesale intrastate telecommunications services. As a result of
this order, the application CaroNet filed with the NCUC was withdrawn. The
hearing regarding the application filed with the SCPSC was held on November 1,
1995, and on November 14, 1995, the SCPSC issued an order granting CaroNet
permission to provide wholesale services in South Carolina.
6. CAROCAPITAL, INC. On January 22, 1996, the Company established a
wholly-owned subsidiary, CaroCapital, Inc., (CaroCapital), which purchased a
minority equity interest in Knowledge Builders, Inc. (Knowledge Builders), an
energy-management software and control systems company. The Company invested
$5 million in CaroCapital on January 25, 1996, and anticipates that its total
investment through 2001 could reach $12 million, subject to the terms and
conditions of a Stock Purchase Agreement, which includes certain sales and
profitability targets. Although Knowledge Builders and its subsidiaries
will continue to operate independently, CaroCapital has designated two
directors who are currently serving on the Knowledge Builders' board of
directors.
OPERATING STATISTICS
---------------------
Years Ended December 31
--- -------------------
1995 1994 1993 1992 1991
----- ----- ----- ----- -----
Energy supply (millions of kWh)
Generated - coal 23,517 21,001 25,807 25,196 20,240
nuclear 19,949 18,511 13,691 11,108 16,311
hydro 824 884 784 881 899
combustion turbines 56 67 84 54 6
Purchased 7,433 7,039 7,110 7,343 5,312
----------- ----------- ----------- ----------- -----------
Total energy supply (Company share) 51,779 47,502 47,476 44,582 42,768
Power Agency share (a) 3,828 3,236 2,402 2,232 2,984
----------- ----------- ----------- ----------- -----------
Total system energy supply 55,607 50,738 49,878 46,814 45,752
=========== =========== =========== =========== ===========
Average fuel cost (per million BTU)
Fossil $ 1.83 $ 1.78 $ 1.75 $ 1.83 $ 1.90
Nuclear fuel 0.46 0.47 0.46 0.45 0.48
All fuels 1.17 1.14 1.28 1.38 1.24
Energy sales (millions of kWh)
Residential 12,074 11,147 11,398 10,490 10,340
Commercial 9,276 8,690 8,548 8,060 7,907
Industrial 14,312 14,030 13,557 13,134 12,403
Government and municipal 1,288 1,263 1,248 1,213 1,181
Power Agency contract requirements 2,338 2,589 3,505 3,304 2,578
NCEMC 5,454 4,885 4,778 4,372 4,215
Other wholesale 1,915 1,983 2,144 2,042 1,989
Other utilities 3,233 985 327 214 382
----------- ----------- ----------- ----------- -----------
Total energy sales 49,890 45,572 45,505 42,829 40,995
Company uses and losses 1,889 1,930 1,971 1,753 1,773
----------- ----------- ----------- ----------- -----------
Total energy requirements 51,779 47,502 47,476 44,582 42,768
=========== =========== =========== =========== ===========
Customers billed
Residential 920,495 894,616 873,377 856,130 835,206
Commercial 159,064 155,349 151,242 146,858 143,782
Industrial 4,863 4,845 4,825 4,763 4,680
Government and municipal 2,328 2,302 2,214 2,262 2,239
Resale 17 12 26 26 31
----------- ----------- ----------- ----------- -----------
Total customers billed 1,086,767 1,057,124 1,031,684 1,010,039 985,938
=========== =========== =========== =========== ===========
Operating revenues (in thousands)
Residential $ 969,112 $ 915,986 $ 943,697 $ 871,469 $ 862,833
Commercial 618,394 595,573 592,973 560,560 552,341
Industrial 733,448 741,662 744,016 720,413 695,221
Government and municipal 78,400 78,317 78,616 76,838 75,389
Power Agency contract requirements 100,951 115,262 134,258 140,623 118,498
NCEMC 299,171 266,733 253,859 252,744 237,857
Other wholesale 82,407 84,775 100,062 99,749 94,623
Other utilities 78,147 33,789 11,232 4,834 12,304
Miscellaneous revenue 46,523 44,492 36,670 39,591 36,689
----------- ----------- ----------- ----------- -----------
Total operating revenues $ 3,006,553 $ 2,876,589 $ 2,895,383 $ 2,766,821 $ 2,685,755
=========== =========== =========== =========== ===========
Peak demand of firm load (thousands of kW)
System 10,156 10,144 9,589 9,236 8,960
Company 9,500 9,642 9,107 8,745 8,471
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 3,064
Hydro plants 218 218 218 218 218
Purchased 1,592 1,596 1,289 890 892
----------- ----------- ----------- ----------- -----------
Total system capability 11,205 11,209 10,902 10,503 10,505
Less Power Agency-owned portion (a) 682 654 627 647 638
----------- ----------- ----------- ----------- -----------
Total Company capability 10,523 10,555 10,275 9,856 9,867
=========== =========== =========== =========== ===========
(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
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 (including
Power Agency's share) 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, 1995, the Company had 5,853 pole miles of transmission
lines including 292 miles of 500 kV and 2,821 miles of 230 kV lines, and
distribution lines of approximately 40,087 pole miles of overhead lines and
approximately 8,302 miles of underground lines. Distribution and transmission
substations in service had a transformer capacity of approximately 36,036 kVA in
2,263 transformers. Distribution line transformers numbered 399,972 with an
aggregate 16,247,000 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,
1991 through December 31, 1995, there was added to the Company's utility plant
accounts $1,810,966,031, there was retired $554,503,996 of property and there
were transfers to other accounts and adjustments for a net decrease of
$4,927,241 resulting in net additions during the period of $1,251,564,794 or an
increase of approximately 14.25%.
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 1995.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age Recent Business Experience
____ ___ __________________________
Sherwood H. Smith, Jr. 61 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 57 PRESIDENT AND CHIEF OPERATING OFFICER, September
1992 to present; Group President - Energy
Supply, Entergy Corporation, July 1992; Chairman
and Chief Executive Officer, 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., 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. 65 EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL
OFFICER - Finance and Administration, November
1990 to August 1995 (retired); 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 (retired May 1995).
Glenn E. Harder 44 EXECUTIVE VICE PRESIDENT AND CHEIF FINANCIAL
OFFICER, Financial Services, August 1, 1995 to
present; Senior Vice President, Group Executive
-Financial Services, October 1994 to August
1995; 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.
William S. Orser 51 EXECUTIVE VICE PRESIDENT - Nuclear Generation,
April 1993 to present; Executive Vice President
- Nuclear Generation, Detroit Edison Company,
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. 65 SENIOR VICE PRESIDENT, Group Executive - Power
Operations, June 1986 to present; Senior Vice
President - Operations Support Group, August
1983.
Norris L. Edge 64 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 53 SENIOR VICE PRESIDENT, Human Resources and
Support Services, March 1995-present; Vice
President - Human Resources (formerly Employee
Relations Department), May 1983 to March 1995.
Richard E. Jones 58 SENIOR VICE PRESIDENT, GENERAL COUNSEL AND
SECRETARY, Group Executive - Public and
Corporate Relations, November 1990 to present;
Vice President, General Counsel and Secretary,
November 1989 to November 1990; Vice President
and General Counsel, July 1987 to November
1989; Vice President, Senior Counsel and Manager
- Legal Department, May 1982.
Paul S. Bradshaw 58 VICE PRESIDENT AND CONTROLLER, March 1980 to
September 1, 1995 (retired)
Mark F. Mulhern 36 VICE PRESIDENT AND CONTROLLER, March 1996; Vice
President of Finance and Treasurer, HYDRA-CO
Enterprises, Inc., a subsidiary of Niagara
Mohawk Power Corporation, 1994-1996; Director of
Finance and Accounting, HYDRA-CO Enterprises,
Inc., 1992-1994; Controller, HYDRA-CO
Enterprises, Inc., 1991-1992. Prior to 1991,
Mr. Mulhern held various positions with the
accounting firm of Price Waterhouse & Co.
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:
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
1995 High Low Dividends Paid
____ ____ ___ ______________
First Quarter $28 5/8 $26 3/8 $ .440
Second Quarter 30 3/4 26 3/4 .440
Third Quarter 34 29 1/2 .440
Fourth Quarter 34 1/2 32 3/8 .440
The December 31 closing price of the Company's Common Stock was $26 5/8 in
1994 and $ 34 1/2 in 1995.
As of February 29, 1996, the Company had 65,581 holders of record of
Common Stock.
On July 13, 1994, the Board of Directors of the Company (Board) authorized
the repurchase of up to 10 million shares of the Company's Common Stock on the
open market. Under this stock repurchase program, the Company purchased
approximately 4.2 million shares in 1995 and 4.4 million shares in 1994.
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
- ------- ------------------------------------
Years Ended December 31
-----------------------
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
(in thousands except per share data)
Operating results
Operating revenues $ 3,006,553 $ 2,876,589 $ 2,895,383 $ 2,766,821 $ 2,685,755
Net income $ 372,604 $ 313,167 $ 346,496 $ 379,635 $ 376,974
Earnings for common stock $ 362,995 $ 303,558 $ 336,887 $ 379,045 $ 364,380
Ratio of earnings to fixed charges 3.67 3.31 3.23 3.34 3.08
Per share data
Earnings per common share before cumulative $ 2.48 $ 2.03 $ 2.10 $ 2.36 $ 2.27
Dividends declared per common share $ 1.775 $ 1.715 $ 1.655 $ 1.595 $ 1.535
Financial position
Total assets $ 8,227,150 $ 8,211,163 $ 8,194,018 $ 7,706,201 $ 7,510,587
Capitalization
Common stock equity $ 2,574,743 $ 2,586,179 $ 2,632,116 $ 2,534,025 $ 2,390,676
Preferred stock - redemption not required 143,801 143,801 143,801 143,801 238,118
redemption required, net - - - - 31,090
Long-term debt, net 2,610,343 2,530,773 2,584,903 2,674,823 2,733,693
---------- ---------- ---------- ---------- ----------
Total capitalization $ 5,328,887 $ 5,260,753 $ 5,360,820 $ 5,352,649 $ 5,393,577
========== ========== ========== ========== ==========
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
_______ __________________________________________________
RESULTS OF OPERATIONS
_____________________
Revenues
________
Revenue fluctuations as compared to the prior year are due to the
following factors (in millions).
1995 1994
Increase Increase
(Decrease) (Decrease)
________ ________
Customer growth/changes
in usage patterns $ 96 $ 101
Weather 64 (86)
Sales to other utilities 46 30
Price (62) (45)
Sales to North Carolina
Eastern Municipal
Power Agency (14) (19)
_____ ______
$130 $ (19)
===== ======
The return of more normal weather in 1995 generated a $64 million increase
in revenues as compared to 1994 when the Company's service territory
experienced unusually mild weather. In 1994, this unusually mild weather
resulted in a revenue decrease of $86 million compared to the prior year.
For 1995 as compared to 1994, approximately half of the price decrease was due
to a decrease in the fuel cost component of customer rates and approximately
half was due to the expiration in July 1994 of a North Carolina rate rider under
which the Company was allowed to recover certain abandoned plant costs. The
reduction in revenue due to the expiration of the rate rider did not significan-
tly affect net income due to a corresponding decrease in amortization expense.
The price decrease from 1993 to 1994 was due primarily to the expiration of
the rate rider. For both comparison periods, sales to North Carolina Eastern
Municipal Power Agency (Power Agency) decreased due to the increased
availability of generating units owned jointly by the Company and Power Agency.
The increased availability of all generating units allowed the Company to
increase sales to other utilities during the 1993 to 1995 period. In addition,
sales to other utilities increased in 1995 as a result of the Company
aggressively seeking bulk power sales. For 1995, approximately $5 million
of the increase in sales to other utilities related to capacity and certain
energy costs and, therefore, resulted in an increase in net income.
Operating expenses
__________________
Fuel expense increased in 1995 primarily as a result of higher total
generation. Generation increased approximately 9.6% due to higher sales. Fuel
expense decreased in 1994 primarily due to 1993 settlement agreements between
the Company and its regulators, which required the Company to forgo recovery of
certain deferred fuel costs.
As a result of a 1993 agreement with Power Agency, the Company's purchase
of capacity and energy from Power Agency's ownership interest in the Harris
Plant decreased from 50% in 1994 to 33% in 1995. This change in buyback
percentage reduced purchased power in 1995 by $20 million as compared to 1994.
Partially offsetting this decrease in 1995 were increases in purchases from
other utilities and cogenerators. For 1994 as compared to 1993, purchased power
increased primarily due to an agreement under which the Company began
purchasing 400 megawatts of generating capacity from Duke Power Company in
mid-1993.
Operation and maintenance expense decreased in 1995 primarily due to lower
nuclear outage-related expenses. Partially offsetting this decrease was an
increase of $13 million in severance-related costs and a 1994 insurance reserve
adjustment of $23 million, which reduced expense in that year. The increase in
operation and maintenance expense 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 the 1994 insurance reserve
adjustment.
Depreciation and amortization expense decreased from 1993 to 1995. This
decrease reflects the completion in July 1994 of the amortization of certain
abandoned plant costs associated with a North Carolina rate rider and the
completion of the amortization of abandoned plant costs for Harris Unit No. 2
in October 1994. The decreases related to these items totaled $42 million for
1995 as compared to 1994 and $25 million for 1994 compared to 1993.
Other income
____________
The high level of Harris Plant carrying costs in 1993 reflects the
Company's settlement with North Carolina Electric Membership Corporation
(NCEMC) 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.
In 1993, interest income included interest income associated with the
Company's 1993 settlement with Westinghouse Electric Corporation (Westinghouse)
and interest income related to the Company's qualified employee stock ownership
plan (ESOP) loan. In 1994, the recognition of interest income related to the
Company's qualified ESOP loan was discontinued as required by Statement of
Position 93-6, "Employers' Accounting for Employee Stock Ownership Plans."
In 1995, other income, net, decreased due to an increase in charitable
contributions of approximately $7 million and decreases in various other items,
none of which was individually significant. Other income decreased in 1994
primarily due to the change in accounting for ESOPs.
Interest charges
________________
The 1995 increase in other interest charges is primarily due to a $6
million interest accrual related to the 1995 North Carolina Utilities
Commission (NCUC) Fuel Order. Because of the improved performance of the
Company's nuclear facilities during the test year ended March 31, 1995, the
fuel component of customer rates exceeded actual fuel costs. As a result,
the Company is refunding this over-recovery of fuel costs with interest
over the twelve-month period beginning September 15, 1995. Interest charges
on long-term debt decreased in 1994 as compared to 1993 due to long-term debt
refinancings that allowed the Company to take advantage of lower interest
rates.
1993 settlements
________________
In 1993, the Company reached several agreements that affected the
Company's 1993 results of operations. 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 increased the Company's
earnings by $17.3 million, net of tax, or $.11 per common share. 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. As part of the agreement, the Company recorded a write-off
of approximately $14.7 million, net of tax, or $.09 per common share. In
addition, the Company and NCEMC entered into a settlement agreement that pro-
vided for the continuation of existing wholesale rate levels and resolved a
wholesale fuel clause billing issue through June 30, 1993. The impact of this
settlement totaled approximately $8 million, net of tax, and decreased the
Company's earnings by $.05 per common share.
LIQUIDITY AND CAPITAL RESOURCES
_______________________________
Capital requirements
____________________
Estimated capital requirements for the period 1996 through 1998 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).
1996 1997 1998
____ ____ ____
Construction expenditures $406 $489 $447
Nuclear fuel expenditures 103 64 105
AFUDC (15) (18) (33)
Mandatory redemptions
of long-term debt 105 100 205
____ ____ ____
Total $599 $635 $724
==== ==== ====
The table above includes Clean Air Act expenditures of approximately $55
million and generating facility addition expenditures of approximately $327
million. 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 2001.
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 power purchases under this agreement 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 1995, purchases under this agreement
totaled $61.8 million, including transmission use charges. The agreement
expires in December 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 power purchases under this agreement 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
$63.8 million in 1995.
In addition, pursuant to the terms of the 1981 Power Coordination
Agreement, as amended, between the Company and 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 $26 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 $39.4 million in 1995.
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.
In 1994, the Board of Directors of the Company authorized the repurchase
of up to 10 million shares of the Company's common stock on the open market.
Under this stock repurchase program, the Company purchased approximately 4.2
million shares in 1995 and 4.4 million shares in 1994.
The Company has on file with the Securities and Exchange Commission (SEC)
a shelf registration statement under which an aggregate of $450 million
principal amount of first mortgage bonds and an additional $125 million combined
aggregate principal amount of first mortgage bonds and/or unsecured debt
securities of the Company remain available for issuance. The Company can also
issue up to $180 million of additional preferred stock under a shelf
registration statement on file with the SEC.
The Company's ability to issue first mortgage bonds and preferred stock is
subject to earnings and other tests as stated in certain provisions of its
mortgage, as supplemented, and charter. The Company has the ability to issue an
additional $3.7 billion in first mortgage bonds and an additional 23 million
shares of preferred stock at an assumed price of $100 per share and a $7.51
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 credit facilities total $685 million,
consisting of $585 million in long-term agreements and a $100 million short-term
agreement. The Company is required to pay minimal annual commitment fees to
maintain its credit facilities. The Company had $73.7 million of commercial
paper outstanding at December 31, 1995, which Moody's Investors Service,
Standard & Poors and Duff & Phelps have rated P-1, A-1 and D-1, respectively.
During 1995, the Company issued $185 million in long-term debt. The
proceeds of these issuances, along with internally generated funds, were
primarily used to redeem or retire $276.1 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 $14 million in
1997 and $76 million in 1998. 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.
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 continues to investigate the identities of parties connected to MGP
sites in North Carolina, 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 expect costs associated with these sites to be material to
the results of operations of the Company.
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.
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 for these emissions, 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. The Company plans to meet
the Phase II sulfur dioxide emissions requirements by the most economical
combination of fuel-switching and utilization of sulfur dioxide emission
allowances. Each sulfur dioxide emission allowance allows a utility to emit one
ton of sulfur dioxide. The Company has purchased emission allowances under the
Environmental Protection Agency (EPA)'s emission allowance trading program in
order to supplement the allowances the EPA has granted to the Company.
Installation of additional equipment will be necessary to reduce nitrogen
oxides emissions.
The Company estimates that future capital costs necessary to comply with
Phase II of the Act will approximate $180 million. Increased operating and
maintenance costs, including emission allowance expense, and increased fuel
costs are not expected to be material to the results of operations of the
Company. As plans for compliance with the Act's requirements are subject to
change, the amount required for capital expenditures and for increased
operating, maintenance and fuel expenditures cannot be determined with certainty
at this time.
Nuclear
_______
In the Company's retail jurisdictions, provisions for nuclear
decommissioning costs were approved by the NCUC and the South Carolina Public
Service Commission (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 agreements. 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 the Brunswick and Harris
nuclear 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 reached several tentative
conclusions with respect to its project regarding accounting practices related
to closure and removal of long-lived assets. The primary conclusions as they
relate to nuclear decommissioning are: 1) the cost of decommissioning should be
accounted for as a liability and accrued as the obligation is incurred; 2)
recognition of a liability for decommissioning results in recognition of an
increase to the cost of the plant; 3) the decommissioning liability should be
measured based on discounted cash flows using a risk-free rate; and 4)
decommissioning trust funds should not be offset against the decommissioning
liability. An exposure draft was issued in February 1996, and it is uncertain
what impacts, if any, the final statement may have on the Company's accounting
for nuclear decommissioning and other closure and removal 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.
Other Business
______________
In 1994, the Company established a wholly-owned subsidiary, CaroNet, Inc.,
which owns a ten percent interest in BellSouth Carolinas PCS, L. P. a limited
partnership led by BellSouth Personal Communications, Inc. (BellSouth) and
participates in the partnership's executive committee. In 1995, BellSouth won
its bid for a Federal Communications Commission license for the limited
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. BellSouth is the general partner and
handles day-to-day management of the business. The Company has invested $50
million in CaroNet, Inc. in anticipation of infrastructure construction by
BellSouth. Construction began in 1995 and service start-up is expected by
mid-1996. In addition to participating in the limited partnership, CaroNet, Inc.
will be providing intrastate and interstate telecommunications services in North
Carolina and South Carolina.
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
after existing contracts expire or new opportunities are created for the Company
to expand its wholesale load.
In 1995, the FERC proposed a rule designed to bring greater competition to
the wholesale electric markets. The major provisions of the proposed rule are:
1) electric utilities under FERC jurisdiction that own or control transmission
systems would be required to file with the FERC a tariff that would allow buyers
and sellers of bulk power equal and open access to their transmission systems;
2) utilities with transmission systems would be required to provide all new
wholesale buyers and sellers of electricity the same equal and open access to
the utilities' transmission systems; and 3) these utilities would be permitted
to recover certain stranded investments incurred as a result of the
restructuring order. The Company does not favor the proposed rule, which is
expected to be finalized sometime in 1996, but rather favors the continued
evolution of wholesale electric markets. The Company cannot predict the impact
of this proposed rule on its future results of operations and financial
position.
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, or
instituting experimental programs, 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 competition in the Company's retail jurisdictions. In 1995, the
Carolina Utility Consumers Association, Inc., a group of industrial customers
conducting business in North Carolina, filed a petition with the NCUC requesting
that the NCUC hold a generic hearing to investigate retail electric competition.
The NCUC has ruled that it would not convene a formal hearing to investigate the
issue at this time. The NCUC's order noted that North Carolina's territorial
assignment statute appears to prohibit retail competition, and the issue
involves a number of jurisdictional uncertainties. Both the NCUC and the SCPSC
have indicated that they will monitor other states' activities regarding
generation competition and allow interested parties to submit information on the
subject. The Company cannot predict the outcome of these matters.
The issues described above have created greater planning uncertainty and
risks for the Company. The Company has been addressing these risks in the
wholesale sector by securing long-term contracts with all of its wholesale
customers, representing approximately 16% of the Company's 1995 operating
revenue. These long-term contracts will allow the Company flexibility in
managing its load and efficiently planning its future resource requirements;
however, NCEMC does have the contractual right, subject to five years' advance
notice, to reduce the baseload capacity it purchases from the Company after
December 31, 2000. In the industrial sector, the Company is continuing to work
to meet the energy needs of its customers. 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. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
____________________________________________________________________
The following consolidated financial statements, supplementary data and
consolidated financial statement schedules are included herein:
Page(s)
Independent Auditors' Report 43
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 1995, 1994 and 1993 44
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1995, 1994 and 1993 45
Consolidated Balance Sheets as of December 31, 1995 and 1994 46-47
Consolidated Schedules of Capitalization as of
December 31, 1995 and 1994 48
Consolidated Statements of Retained Earnings for the
Years Ended December 31, 1995, 1994 and 1993 49
Consolidated Quarterly Financial Data 49
Notes to Consolidated Financial Statements 50-61
Consolidated Financial Statement Schedules for the Years Ended
December 31, 1995, 1994 and 1993:
II - Reserves 62-64
All other schedules have been omitted as not applicable or not required
or because the information required to be shown is included in the Consolidated
Financial Statements or the accompanying Notes to Consolidated Financial
Statements.
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of
Carolina Power & Light Company
We have audited the accompanying consolidated balance sheets and schedules
of capitalization of Carolina Power & Light Company and subsidiaries as of
December 31, 1995 and 1994, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three years in
the period ended December 31, 1995. 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 consolidated financial statements present fairly, in
all material respects, the financial position of Carolina Power & Light
Company and subsidiaries at December 31, 1995 and 1994, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1995 in conformity with generally accepted
accounting principles. Also, in our opinion, such financial statement
schedules, when considered in relation to the basic consolidated 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 consolidated balance sheets and schedules of
capitalization as of December 31, 1993, 1992 and 1991, and the related
consolidated statements of income, retained earnings and cash flows for
the years ended December 31, 1992 and 1991 (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, 1995, appearing at
Item 6, is fairly presented in all material respects in relation to the
consolidated financial statements from which it has been derived.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
February 12, 1996
Consolidated statements of income
Years ended December 31
(in thousands except per share data) 1995 1994 1993
- ------------------------------------------------------------------------------------------------------
Operating revenues $ 3,006,553 $ 2,876,589 $ 2,895,383
- ------------------------------------------------------------------------------------------------------
Operating expenses
Operation - fuel 529,812 510,138 551,730
purchased power 409,940 414,300 368,092
other 541,446 539,959 498,333
Maintenance 196,585 206,733 235,449
Depreciation and amortization 364,527 397,735 413,646
Taxes other than on income 144,043 138,540 142,871
Income tax expense 259,224 198,535 189,317
Harris Plant deferred costs, net 28,128 26,329 27,575
- ------------------------------------------------------------------------------------------------------
Total operating expenses 2,473,705 2,432,269 2,427,013
- ------------------------------------------------------------------------------------------------------
Operating income 532,848 444,320 468,370
- ------------------------------------------------------------------------------------------------------
Other income (expense)
Allowance for equity funds used during construction 3,350 6,074 8,999
Income tax credit (expense) 18,541 9,425 (392)
Harris Plant carrying costs 8,297 9,754 27,143
Harris Plant disallowance - Power Agency (Note 10A) - - (20,645)
Interest income 8,680 14,569 36,196
Other income, net 9,063 25,592 42,465
- ------------------------------------------------------------------------------------------------------
Total other income 47,931 65,414 93,766
- ------------------------------------------------------------------------------------------------------
Income before interest charges 580,779 509,734 562,136
- ------------------------------------------------------------------------------------------------------
Interest charges
Long-term debt 187,397 183,891 205,182
Other interest charges 25,896 16,119 16,419
Allowance for borrowed funds used during construction (5,118) (3,443) (5,961)
- ------------------------------------------------------------------------------------------------------
Net interest charges 208,175 196,567 215,640
- ------------------------------------------------------------------------------------------------------
Net income 372,604 313,167 346,496
- ------------------------------------------------------------------------------------------------------
Preferred stock dividend requirements (9,609) (9,609) (9,609)
- ------------------------------------------------------------------------------------------------------
Earnings for common stock $ 362,995 $ 303,558 $ 336,887
- ------------------------------------------------------------------------------------------------------
Average common shares outstanding (Notes 5 and 6) 146,232 149,614 160,737
- ------------------------------------------------------------------------------------------------------
Earnings per common share (Notes 5 and 6) $ 2.48 $ 2.03 $ 2.10
- ------------------------------------------------------------------------------------------------------
Dividends declared per common share $ 1.775 $ 1.715 $ 1.655
- ------------------------------------------------------------------------------------------------------
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
See notes to consolidated financial statements.
Carolina Power & Light Company
Consolidated statements of cash flows
Years ended December 31
(in thousands) 1995 1994 1993
- --------------------------------------------------------------------------------------------------
Operating activities
Net income $ 372,604 $ 313,167 $ 346,496
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and amortization 446,662 473,481 460,094
Harris Plant deferred costs 19,831 16,575 432
Harris Plant disallowance - Power Agency - - 20,645
Deferred income taxes 89,681 37,240 71,352
Investment tax credit (9,344) (11,537) (12,806)
Allowance for equity funds used during construction (3,350) (6,074) (8,999)
Deferred fuel cost (credit) (849) 38,171 27,364
Net increase in receivables, inventories and prepaid expenses (77,849) (73,891) (7,803)
Net decrease in payables and accrued expenses (39,592) (46,771) (62,013)
Miscellaneous 35,629 (4,935) 10,882
- --------------------------------------------------------------------------------------------------
Net cash provided by operating activities 833,423 735,426 845,644
- --------------------------------------------------------------------------------------------------
Investing activities
Gross property additions (266,400) (274,777) (341,122)
Nuclear fuel additions (77,346) (25,849) (48,001)
Contributions to external decommissioning trust (38,075) (21,625) (20,878)
Contributions to retiree benefit trusts (2,400) (18,917) (3,750)
Loan transactions with SPSP trustee, net - - 21,134
Allowance for equity funds used during construction 3,350 6,074 8,999
Miscellaneous (28,515) (6,094) -
- --------------------------------------------------------------------------------------------------
Net cash used in investing activities (409,386) (341,188) (383,618)
- --------------------------------------------------------------------------------------------------
Financing activities
Proceeds from issuance of long-term debt 180,713 318,211 582,030
Withdrawal from pollution control bond escrow - - 2,127
Net increase (decrease) in short-term notes payable
(maturity less than 90 days) 5,643 (7,900) 29,200
Retirement of long-term debt (276,144) (268,380) (790,376)
Purchase of Company common stock (Note 5) (132,439) (114,717) -
Dividends paid on common stock (257,937) (255,206) (262,749)
Dividends paid on preferred stock (9,623) (9,614) (9,474)
- --------------------------------------------------------------------------------------------------
Net cash used in financing activities (489,787) (337,606) (449,242)
- --------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents (65,750) 56,632 12,784
- --------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 80,239 23,607 10,823
- --------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 14,489 $ 80,239 $ 23,607
==================================================================================================
Supplemental disclosures of cash flow information
Cash paid during the year - interest $ 203,296 $ 188,754 $ 218,801
income taxes $ 177,163 180,759 113,523
- --------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
Carolina Power & Light Company
Consolidated balance sheets
Assets
December 31
(in thousands) 1995 1994
- ----------------------------------------------------------------------------------
Electric utility plant
Electric utility plant in service $ 9,440,442 $ 9,190,874
Accumulated depreciation (3,493,153) (3,196,139)
- ----------------------------------------------------------------------------------
Electric utility plant in service, net 5,947,289 5,994,735
Held for future use 13,304 13,195
Construction work in progress 179,260 170,390
Nuclear fuel, net of amortization 188,655 171,164
- ----------------------------------------------------------------------------------
Total electric utility plant, net 6,328,508 6,349,484
- ----------------------------------------------------------------------------------
Current assets
Cash and cash equivalents 14,489 80,239
Accounts receivable 364,536 302,218
Fuel 53,654 96,136
Materials and supplies 121,227 122,720
Prepayments 59,918 52,988
Other current assets 27,834 24,129
- ----------------------------------------------------------------------------------
Total current assets 641,658 678,430
- ----------------------------------------------------------------------------------
Deferred debits and other assets
Income taxes recoverable through future rates 387,150 384,375
Abandonment costs 57,120 71,079
Harris Plant deferred costs 107,992 127,824
Unamortized debt expense 58,404 63,302
Miscellaneous other property and investments 475,564 360,611
Other assets and deferred debits 170,754 176,058
- ----------------------------------------------------------------------------------
Total deferred debits and other assets 1,256,984 1,183,249
- ----------------------------------------------------------------------------------
Total assets $ 8,227,150 $ 8,211,163
- ----------------------------------------------------------------------------------
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
See notes to consolidated financial statements.
Carolina Power & Light Company
Consolidated balance sheets
Capitalization and liabilities
December 31
(in thousands) 1995 1994
- ----------------------------------------------------------------------------------
Capitalization (see schedules of capitalization)
Common stock equity $ 2,574,743 $ 2,586,179
Preferred stock - redemption not required 143,801 143,801
Long-term debt, net 2,610,343 2,530,773
- ----------------------------------------------------------------------------------
Total capitalization 5,328,887 5,260,753
- ----------------------------------------------------------------------------------
Current liabilities
Current portion of long-term debt 105,755 275,050
Notes payable (principally commercial paper) 73,743 68,100
Accounts payable 309,294 285,610
Interest accrued 48,441 54,569
Dividends declared 71,285 70,658
Deferred fuel credit 27,495 28,344
Other current liabilities 81,676 71,811
- ----------------------------------------------------------------------------------
Total current liabilities 717,689 854,142
- ----------------------------------------------------------------------------------
Deferred credits and other liabilities
Accumulated deferred income taxes 1,716,835 1,628,430
Accumulated deferred investment tax credits 242,707 252,051
Other liabilities and deferred credits 221,032 215,787
- ----------------------------------------------------------------------------------
Total deferred credits and other liabilities 2,180,574 2,096,268
- ----------------------------------------------------------------------------------
Commitments and contingencies (Note 10)
Total capitalization and liabilities $ 8,227,150 $ 8,211,163
- ----------------------------------------------------------------------------------
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
See notes to consolidated financial statements.
Carolina Power & Light Company
Consolidated schedules of capitalization
December 31
(in thousands) 1995 1994
- ------------------------------------------------------------------------------------------------------------------
Common stock equity
Common stock without par value, 200,000,000 shares authorized; shares outstanding,
152,102,922 at December 31, 1995 and 156,382,422 at December 31, 1994 (Note 5) $ 1,381,496 $ 1,510,956
Unearned ESOP common stock (191,341) (204,947)
Capital stock issuance expense (790) (790)
Retained earnings (Note 5) 1,385,378 1,280,960
- ------------------------------------------------------------------------------------------------------------------
Total common stock equity $ 2,574,743 $ 2,586,179
- ------------------------------------------------------------------------------------------------------------------
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, 1995)
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, 1995)
First mortgage bonds:
5.20% and 9.14% due 1995 $ - $ 202,050
5.125% due 1996 30,000 30,000
6.375% due 1997 40,000 40,000
5.375% and 6.875% due 1998 140,000 140,000
6.125% due 2000 150,000 150,000
5.875% to 8.125% due 2002 - 2004 522,626 522,626
6.875% to 9.00% due 2021 - 2023 725,000 725,000
First mortgage bonds - secured medium-term notes, series A, B and C:
8.85% to 8.92% due 1995 - 73,000
4.85% and 7.90% due 1996 75,000 75,000
7.75% due 1997 60,000 -
5.00% to 5.06% due 1998 65,000 65,000
7.15% due 1999 50,000 50,000
First mortgage bonds - pollution control series:
6.30% to 6.90% due 2009 - 2014 93,530 93,530
4.25% and 3.95% due 2024 122,600 122,600
- ------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 2,073,756 2,288,806
- ------------------------------------------------------------------------------------------------------------------
Other long-term debt:
Pollution control obligations backed by letter of credit, 3.84% to 6.15% due 2014 - 2017 442,000 442,000
Other pollution control obligations, 5.20% due 2019 55,640 55,640
Unsecured subordinated debentures, 8.55% due 2025 125,000 -
Miscellaneous notes 48,157 47,409
- ------------------------------------------------------------------------------------------------------------------
Total other long-term debt 670,797 545,049
- ------------------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net (28,455) (28,032)
Current portion of long-term debt (105,755) (275,050)
- ------------------------------------------------------------------------------------------------------------------
Total long-term debt, net $ 2,610,343 $ 2,530,773
- ------------------------------------------------------------------------------------------------------------------
Total capitalization $ 5,328,887 $ 5,260,753
- ------------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
Carolina Power & Light Company
Consolidated statements of retained earnings
Years ended December 31
(in thousands) 1995 1994 1993
- -------------------------------------------------------------------------------------------------------------------------------
Retained earnings at beginning of year $ 1,280,960 $ 1,231,354 $ 1,153,655
Net income 372,604 313,167 346,496
Preferred stock dividends at stated rates (9,609) (9,609) (9,609)
Common stock dividends at annual rate of $1.775 per share in 1995,
$1.715 in 1994 and $1.655 in 1993 (Note 5) (258,577) (256,021) (266,019)
Tax benefit of ESOP dividends - - 6,837
Other adjustments - 2,069 (6)
- -------------------------------------------------------------------------------------------------------------------------------
Retained earnings at end of year $ 1,385,378 $ 1,280,960 $ 1,231,354
- -------------------------------------------------------------------------------------------------------------------------------
Consolidated quarterly financial data
(Unaudited)
First Quarter Second Quarter Third Quarter Fourth Quarter
(in thousands except
per share data) 1995 1994 1995 1994 1995 1994 1995 1994
- -------------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 728,238 $ 744,461 $ 681,965 $ 687,310 $ 875,500 $ 805,552 $ 720,850 $ 639,266
Operating income $ 136,259 $ 123,027 $ 93,426 $ 86,430 $ 194,440 $ 155,796 $ 108,723 $ 79,067
Net income $ 98,033 $ 88,824 $ 55,962 $ 58,215 $ 151,905 $ 120,253 $ 66,704 $ 45,875
Common stock data:
Earnings per common share $ .65 $ .57 $ .36 $ .37 $ 1.02 $ .79 $ .45 $ .30
Dividend paid per common
share $ .440 $ .425 $ .440 $ .425 $ .440 $ .425 $ .440 $ .425
Price per share - high $ 28 5/8 $ 29 3/4 $ 30 3/4 $ 26 5/8 $ 34 $ 27 $ 34 1/2 $ 27 3/4
low $ 26 3/8 $ 25 5/8 $ 26 3/4 $ 22 7/8 $ 29 1/2 $ 22 3/4 $ 32 3/8 $ 25 1/4
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
See notes to consolidated financial statements.
Carolina Power & Light Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
___________________________________________
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. GENERAL
The Company is a public service corporation engaged in the generation,
transmission, distribution and sale of electricity in portions of North
Carolina and South Carolina.
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 1994
and 1993 have been reclassified to conform to the 1995 presentation.
B. USE OF ESTIMATES
In preparing financial statements that conform with generally accepted
accounting principles, management must make estimates and assumptions that
affect the reported amounts of assets and liabilities, disclosure of
contingent assets and liabilities at the date of the financial statements and
amounts of revenues and expenses reflected during the reporting period. Actual
results could differ from those estimates.
C. 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).
1995 1994
____ ____
Production plant $ 6,014.1 $ 5,911.2
Transmission plant 912.7 879.6
Distribution plant 2,037.6 1,929.5
General plant and other 476.0 470.6
-------- --------
Electric utility plant in service $ 9,440.4 $ 9,190.9
======== ========
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 and the borrowed funds portion is
credited to interest charges. The composite AFUDC rate was 8.0% in 1995, 8.4%
in 1994 and 8.8% in 1993.
D. 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 1E), as a
percent of average depreciable property other than nuclear fuel, were
approximately 3.8% in 1995, 1994 and 1993. Depreciation expense totaled $344.0
million in 1995, $335.1 million in 1994 and $325.4 million in 1993.
Depreciation and amortization expense also includes amortization of plant
abandonment costs (see Note 8).
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 expense. Costs related to
obligations to the DOE for the decommissioning and decontamination of
enrichment facilities are also charged to fuel expense.
E. 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 agreements. Decommissioning cost provisions, which are included in
depreciation and amortization, were $31.2 million in 1995, $29.5 million in
1994 and $34.0 million in 1993.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were $288.4 million at December 31, 1995 and $252.7 million at
December 31, 1994. These costs 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 $110.2 million at December 31, 1995 and $67.6 million at
December 31, 1994. Trust earnings, which increase the trust balance with a
corresponding increase in accumulated decommissioning, were $4.5 million in
1995, $1.5 million in 1994 and $1.2 million in 1993. 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 the Brunswick and Harris
nuclear 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 reached several tentative
conclusions with respect to its project regarding accounting practices related
to closure and removal of long-lived assets. The primary conclusions as they
relate to nuclear decommissioning are: 1) the cost of decommissioning should
be accounted for as a liability and accrued as the obligation is incurred;
2) recognition of a liability for decommissioning results in recognition of an
increase to the cost of the plant; 3) the decommissioning liability should be
measured based on discounted cash flows using a risk-free rate; and
4) decommissioning trust funds should not be offset against the
decommissioning liability. An exposure draft was issued in February 1996, and
it is uncertain what impacts, if any, the final statement may have on the
Company's accounting for nuclear decommissioning and other closure and removal
costs.
F. REGULATORY ASSETS AND LIABILITIES
As a regulated entity, the Company is subject to the provisions of Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation. "Accordingly, the Company records certain assets
and liabilities resulting from the effects of the ratemaking process, which
would not be recorded under generally accepted accounting principles for
non-regulated entities. At December 31, 1995, the balances of the Company's
regulatory assets were as follows: 1) $387.2 million for income taxes
recoverable through future rates; 2) $108.0 million for Harris Plant deferred
costs; 3) $57.1 million for abandonment costs; 4) $50.4 million for loss on
reacquired debt, which is included in unamortized debt expense; 5) $60.5
million for deferred DOE enrichment facilities-related cost, which is included
in other assets and deferred debits; and 6) $11.8 million of other regulatory
assets included in other assets and deferred debits. At December 31, 1995, the
Company had a regulatory liability of $27.5 million related to deferred fuel.
G. OTHER POLICIES
The Company's financial statements reflect consolidation of its majority-owned
subsidiaries. Significant intercompany balances and transactions have been
eliminated.
Customers' meters are read and bills are rendered on a cycle basis. Revenues
are accrued for services rendered but unbilled at the end of each accounting
period.
Fuel expense includes 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. 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 $2.3
million at December 31, 1995 and $2.5 million at December 31, 1994. 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 Consolidated
Statements of Cash Flows, the Company considers all highly-liquid investments
with original maturities of three months or less to be cash equivalents.
2. 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):
1995 1994 1993
____ ____ ____
Actual return on plan assets $(103,381) $ 4,897 $(43,604)
Variance from expected return, deferred 59,425 (47,219) 4,490
-------- ------- -------
Expected return on plan assets (43,956) (42,322) (39,114)
Service cost 16,344 19,686 16,776
Interest cost on projected benefit obligation 35,592 35,108 31,928
Net amortization (3,580) 831 (2,390)
-------- ------- -------
Net periodic pension cost $ 4,400 $ 13,303 $ 7,200
======== ======= =======
Reconciliations of the funded status of the pension plan at December 31 are
(in thousands):
1995 1994
____ ____
Actuarial present value of benefits for services rendered to date
Accumulated benefits based on salaries to date,
including vested benefits of $345.1 million
for 1995 and $287.7 million for 1994 $ 392,768 $ 330,361
Additional benefits based on
estimated future salary levels 130,167 103,766
-------- --------
Projected benefit obligation 522,935 434,127
Fair market value of plan assets, invested primarily
in equity and fixed-income securities 610,278 506,605
-------- --------
Funded status 87,343 72,478
Unrecognized prior service costs 8,747 9,471
Unrecognized actuarial gain (124,383) (124,447)
Unrecognized transition obligation, amortized over
18.5 years beginning January 1, 1987 1,005 1,110
-------- --------
Accrued pension costs recognized in the
Consolidated Balance Sheets $ (27,288) $ (41,388)
======== ========
The assumptions used to measure the projected benefit obligation are:
1995 1994
____ ____
Weighted-average discount rate 7.75% 8.50%
Assumed rate of increase in future compensation 4.20% 4.20%
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 1995,
1994 and 1993. In addition to pension benefits, the Company provides
contributory postretirement benefits (OPEB), including certain health care and
life insurance benefits, for substantially all retired employees.
The components of net periodic OPEB cost are (in thousands):
1995 1994 1993
____ ____ ____
Actual return on plan assets $(2,514) $ 42 $ (497)
Variance from expected return, deferred 1,420 (682) 9
------ ------ ------
Expected return on plan assets (1,094) (640) (488)
Service cost 7,498 8,039 6,797
Interest cost on accumulated benefit obligation 10,595 9,463 9,662
Net amortization 5,530 5,966 5,966
------ ------ ------
Net periodic OPEB cost $22,529 $22,828 $21,937
====== ====== ======
Reconciliations of the funded status of the OPEB plans at December 31 are
(in thousands):
1995 1994
____ ____
Actuarial present value of benefits for
services rendered to date
Current retirees $ 59,809 $ 55,799
Active employees eligible to retire 17,942 11,933
Active employees not eligible to retire 68,819 63,164
------- --------
Accumulated postretirement benefit obligation 146,570 130,896
Fair market value of plan assets, invested
primarily in equity and fixed-income securities 20,869 12,142
------- --------
Funded status (125,701) (118,754)
Unrecognized actuarial gain (15,132) (15,125)
Unrecognized transition obligation, amortized
over 20 years beginning January 1, 1993 101,414 107,379
------- --------
Accrued OPEB costs recognized in the
Consolidated Balance Sheets $ (39,419) $ (26,500)
======= ========
The assumptions used to measure the accumulated postretirement benefit
obligation are:
1995 1994
Weighted-average discount rate 7.75% 8.50%
Initial medical cost trend rate for pre-medicare benefits 8.40% 9.60%
Initial medical cost trend rate for post-medicare benefits 8.20% 8.70%
Ultimate medical cost trend rate 5.25% 6.00%
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 1995, 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 1995 would increase
by $2.5 million, and the accumulated postretirement benefit obligation at
December 31, 1995, would increase by $16.5 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.
3. SHORT-TERM DEBT AND REVOLVING CREDIT FACILITIES
At December 31, 1995 and 1994, the Company's short-term debt balances were
$73.7 million and $68.1 million, respectively. The weighted-average interest
rates of these borrowings were 5.86% at December 31, 1995, and 6.18% at
December 31, 1994. The Company's commercial paper borrowings are supported by
revolving credit facilities. At December 31, 1995, the Company's unused and
readily available revolving credit facilities totaled $335 million, consisting
of long-term agreements totaling $235 million and a $100 million short-term
agreement. The Company is required to pay minimal annual commitment fees to
maintain its credit facilities.
4. 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 $2.76 billion at December 31, 1995,
and $2.86 billion at December 31, 1994. The estimated fair value of this debt,
which was obtained from an independent pricing service, was $2.85 billion at
December 31, 1995, and $2.70 billion at December 31, 1994. 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.
5. CAPITALIZATION
In 1994, the Board of Directors of the Company authorized the repurchase of up
to 10 million shares of the Company's common stock on the open market. Under
this stock repurchase program, the Company purchased approximately 4.2 million
shares in 1995 and 4.4 million shares in 1994.
At December 31, 1995, 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 Stock Purchase-Savings Plan (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, 1995, there were no significant
restrictions on the use of retained earnings.
At December 31, 1995, long-term debt maturities for the years 1996 through
2000 were $105.8 million, $100 million, $205 million, $50 million and $197.3
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 Consolidated Balance
Sheets. This classification is 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.
6. EMPLOYEE STOCK OWNERSHIP PLAN
The Company sponsors an 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 to acquire 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. The common stock 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. Such dividends are deductible for income tax purposes.
There were 8,697,316 ESOP suspense shares at December 31, 1995, with a fair
value of $300.1 million. ESOP shares allocated to plan participants totaled
14,507,665 at December 31, 1995. 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,
$194.9 million at December 31, 1995, 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 had not been committed to be released to participants'
accounts were no longer considered outstanding for the determination of
earnings per common share; 2) dividends on unallocated ESOP shares were no
longer recognized for financial statement purposes; 3) interest income related
to the qualified ESOP loan was no longer recognized; 4) the difference between
the acquisition and allocation prices of ESOP shares, which was previously
recorded as other income, net, is recorded directly to common stock; and 5)
all tax benefits of ESOP dividends are recorded to non-operating income tax
expense, whereas in 1993, a portion of the tax benefits was recorded directly
to retained earnings. In addition, pursuant to SOP 93-6, ESOP loan
transactions between the Company and the SPSP Trustee were no longer reflected
in the Consolidated Statements of Cash Flows. The implementation of SOP 93-6
resulted in an increase in earnings per common share of approximately $.04 for
1994.
7. INCOME TAXES
Deferred income taxes are provided for temporary differences between book and
tax bases of assets and liabilities. 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.
Net accumulated deferred income tax liabilities at December 31 are
(in thousands):
1995 1994
Accelerated depreciation and property cost differences $1,613,752 $1,504,187
Deferred costs, net 133,139 144,751
Miscellaneous other temporary differences, net (12,487) (7,173)
--------- ---------
Net accumulated deferred income tax liability $1,734,404 $1,641,765
========= =========
Total deferred income tax liabilities were $2.17 billion and $1.94 billion at
December 31, 1995, and 1994, respectively. Total deferred income tax assets
were $434 million at December 31, 1995, and $297 million at December 31, 1994.
A reconciliation of the Company's effective income tax rate to the statutory
federal income tax rate follows.
1995 1994 1993
Effective income tax rate 39.2% 37.6% 35.4%
State income taxes, net of federal income tax benefit (5.0) (5.5) (5.1)
Investment tax credit amortization 1.6 2.4 2.3
Other differences, net (0.8) 0.5 2.4
---- ---- ----
Statutory federal income tax rate 35.0% 35.0% 35.0%
==== ==== ====
The provisions for income tax expense are comprised of (in thousands):
1995 1994 1993
Included in Operating Expenses
Income tax expense (credit)
Current - federal $143,440 $143,461 $108,935
state 41,826 39,185 29,687
Deferred - federal 75,442 23,926 50,719
state 7,860 3,500 11,588
Investment tax credit (9,344) (11,537) (11,612)
------- ------- -------
Subtotal 259,224 198,535 189,317
------- ------- -------
Harris Plant deferred costs
Investment tax credit (297) (297) 218
------- ------- -------
Total included in operating expenses 258,927 198,238 189,535
------- ------- -------
Included in Other Income
Income tax expense (credit)
Current - federal (20,669) (15,732) (6,168)
state (4,251) (3,507) (1,291)
Deferred - federal 5,254 8,065 7,483
state 1,125 1,749 1,562
Investment tax credit -- -- (1,194)
------- ------- -------
Total included in other income (18,541) (9,425) 392
------- ------- -------
Total income tax expense $240,386 $188,813 $189,927
======= ======= =======
8. PLANT-RELATED DEFERRED COSTS
The Company abandoned efforts to complete 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 No. 2
costs was completed in 1994. In the 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 $18.3 million in 1995, $60.5 million in 1994
and $100.7 million in 1993. 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 $4.3 million in 1995, $6.6
million in 1994 and $13.2 million in 1993 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 $38.4 million
at December 31, 1995, and $60.8 million at December 31, 1994.
9. JOINT OWNERSHIP OF GENERATING FACILITIES
Power Agency 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 Consolidated Statements
of Income.
The Company's share of the jointly-owned generating facilities is listed below
with related information as of December 31, 1995 (dollars in millions).
Company
Megawatt Ownership Plant Accumulated Under
Facility Capability Interest Investment Depreciation Construction
________ __________ ________ __________ ____________ ____________
Mayo Plant 745 83.83% $ 432.9 $ 159.0 $ 7.2
Harris Plant 860 83.83% $ 3,006.6 $ 750.6 $ 8.6
Brunswick Plant 1,521 81.67% $ 1,361.3 $ 758.7 $ 35.8
Roxboro Unit No.4 700 87.06% $ 223.2 $ 91.9 $ 3.1
In the table above, plant investment and accumulated depreciation, which
includes accumulated nuclear decommissioning, are not reduced by the
regulatory disallowances related to the Harris Plant.
10. COMMITMENTS AND CONTINGENCIES
A. PURCHASED POWER
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between the Company and Power Agency, 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 $26 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 $39.4 million
for 1995, $60.4 million for 1994 and $52.6 million for 1993. 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, 1995 and 1994, the
Company had deferred purchased capacity costs, including carrying costs
accrued on the deferred balances, of $72.7 million and $70.9 million,
respectively. Increased purchases resulting from the 1993 agreement with Power
Agency, which were approximately $10 million for 1995 and $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 (Rockport) and 400 megawatts of
generating capacity from Duke Power Company (Duke). The estimated minimum
annual payment for power under these contracts is approximately $30 million
for Rockport and $43 million for Duke, representing capital-related capacity
costs. Other power costs include demand-related production expenses, fuel and
energy-related operation and maintenance expenses for Rockport and fuel and
energy-related operation and maintenance expenses for Duke. Purchases,
including transmission use charges, for Rockport and Duke, respectively,
totaled $61.8 million and $63.8 million for 1995, $61.9 million and $62.9
million for 1994 and $60.2 million and $37.1 million for 1993. The Rockport
agreement expires in December 2009 and the Duke agreement expires in mid-1999.
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 $20 million in the event that losses at insured facilities
exceed premiums, reserves, reinsurance and other NML resources, which are at
present more than $763 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 $1.5
million at Brunswick Unit No. 1, $1.4 million at Brunswick Unit No. 2, $1.7
million at the Harris Plant and $1.4 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 per incident. 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 $7.6
million with respect to the incremental replacement power costs coverage and
$42.9 million with respect to the decontamination, decommissioning and
excess property coverage in the event covered expenses at insured facilities
exceed premiums, reserves, reinsurance and other NEIL resources. These
resources are at present more than $2.2 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 nuclear 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 nuclear
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 continues to investigate the identities of parties
connected to MGP sites in North Carolina, 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 expect costs associated with these sites to be material to the
results of operations of the Company.
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.
CAROLINA POWER & LIGHT COMPANY
SCHEDULE II - RESERVES
Year Ended December 31, 1995
- ----------------------------------------------------------------------------------------------------------------------
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
- ----------------------------------------------------------------------------------------------------------------------
Reserves deducted from
related assets on the
balance sheet:
Uncollectible accounts $ 2,520,785 $ 4,622,288 $ -0- $ 4,819,265 $ 2,323,808
============== ============== ============== ============== ==============
Reserves other than those
deducted from assets on
the balance sheet:
Injuries and damages $ 2,212,161 $ 566,718 $ -0- $ 1,507,998 $ 1,270,881
============== ============== ============== ============== ==============
Reserve for possible coal
mine investment losses $ 8,004,970 $ -0- $ -0- $ 207,720 $ 7,797,250
============== ============== ============== ============== ==============
Reserve for employee
retirement and compensation
plans $ 88,015,413 $ 36,288,787 $ -0- $ 32,524,334 $ 91,779,866
============== ============== ============== ============== ==============
Reserve for environmental
investigation and
remediation costs $ 1,976,716 $ -0- $ -0- $ 69,986 $ 1,906,730
============== ============== ============== ============== ==============
CAROLINA POWER & LIGHT COMPANY
SCHEDULE II - 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
- ----------------------------------------------------------------------------------------------------------------------
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
============== ============== ============== ============== ==============
CAROLINA POWER & LIGHT COMPANY
SCHEDULE II - RESERVES
Year Ended December 31, 1993
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COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
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Additions
---------
Balance at (1) (2) Deductions Balance at
Beginning Charged to Charged to from Close of
Description of Period Income Other Accounts Reserves Period
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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
============== ============== ============== ============== ==============
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 1996 definitive proxy statement dated March 29, 1996, 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
1996 definitive proxy statement dated March 29, 1996, 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, 1995, owned 9,511,913 shares of
Common Stock (6.2% of Class) as Trustee of the Company's Stock Purchase-Savings
Plan.
b) Information on security ownership of the Company's management is
set forth in the Company's 1996 definitive proxy statement dated March 29,
1996, 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 1996 definitive proxy statement dated March 29, 1996, and
incorporated by reference herein.
PART IV
ITEM 14. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K.
___________________________________________________________________
a) 1. Consolidated Financial Statements Filed:
See ITEM 8 - Consolidated Financial Statements and Supplementary Data.
2. Consolidated Financial Statement Schedules Filed:
See ITEM 8 - Consolidated Financial Statements and Supplementary Data.
3. Exhibits Filed:
Exhibit No. *3a(1) Restated Charter of the Company, as amended May 10,
1995 (filed as Exhibit No. 3(i) to quarterly report
on Form 10-Q for the quarterly period ended June 30,
1995, File No. 1-3382).
Exhibit No. *3a(2) By-laws of the Company, as amended May 10, 1995
(filed as Exhibit No. 3(ii) to quarterly report on
Form 10-Q for the quarterly period ended June 30,
1995, File No. 1-3382).
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. *4c(1) Indenture, dated as of March 1, 1995, between the
Company and Bankers Trust Company, as Trustee, with
respect to Unsecured Subordinated Debt Securities
(filed as Exhibit No. 4(c) to Current Report on
Form 8-K dated April 13, 1995, File No. 1-3382).
Exhibit No. *4c(2) Resolutions adopted by the Executive Committee of
the Board of Directors at a meeting held on April
13, 1995, establishing the terms of the 8.55%
Quarterly Income Capital Securities (Series A
Subordinated Deferrable Interest Debentures) (filed
as Exhibit 4(b) to Current Report on Form 8-K dated
April 13, 1995, File No. 1-3382).
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. *10b(1) Directors Deferred Compensation Plan effective
January 1, 1982 as amended (filed as Exhibit 10(g),
File No. 33-25560).
+Exhibit No. *10b(2) Supplemental Executive Retirement Plan effective
January 1, 1984 (filed as Exhibit 10(h), File No.
33-25560).
+Exhibit No. *10b(3) Retirement Plan for Outside Directors (filed as
Exhibit 10) (i), File No. 33-25560).
+Exhibit No. *10b(4) Executive Deferred Compensation Plan effective May
1, 1982 as amended (filed as Exhibit 10(j),
File No. 33-25560).
+Exhibit No. *10b(5) Key Management Deferred Compensation Plan (filed as
Exhibit 10(k), File No. 33-25560).
+Exhibit No. *10b(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. *10b(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. *10b(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.
Exhibit No. 27 Financial Data Schedule
Exhibit No. 18 Letter re: Change in Accounting Principles
*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 1995 and the portion of the first quarter of 1996
prior to the filing of this 10-K:
Date of Report Item Reported
______________ _____________
NONE
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized, on the 25th day
of March, 1996.
CAROLINA POWER & LIGHT COMPANY
(Registrant)
By /s/ Glenn E. Harder
Executive Vice President
and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
Signature Title Date
_________ _____ ____
/s/ Sherwood H. Smith, Jr. Principal Executive
(Chairman and Chief Executive Officer and Director
Officer)
/s/ Glenn E. Harder Principal Financial
(Executive Vice President and Officer
Chief Financial Officer)
/s/ Leslie M. Baker, Jr. Director
/s/ Edwin B. Borden Director March 25, 1996
/s/ Felton J. Capel Director
/s/ William Cavanaugh III Director
(President and Chief Operating
Officer)
/s/ George H. V. Cecil Director
/s/ Charles W. Coker Director
/s/ Richard L. Daugherty Director
/s/ J. R. Bryan Jackson Director
/s/ Robert L. Jones Director
/s/ Estell C. Lee Director
/s/ J. Tylee Wilson Director