UNITED STATES
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, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____ to _____
Commission file number 1-3382
CAROLINA POWER & LIGHT COMPANY
(Exact name of registrant as specified in its charter)
411 Fayetteville Street
North Carolina 56-0165465 Raleigh, North Carolina 27601
_______________________________________________________________________
(State or other (I.R.S. Employer (Address of principal (Zip Code)
jurisdiction of Identification executive offices)
incorporation or No.)
organization)
919-546-6111
(Registrant's telephone number)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which
registered
___________________ _______________________________
Common Stock (Without Par Value) New York Stock Exchange
Pacific Stock Exchange
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 28, 1997, was $5,746,914,678.
Shares of Common Stock (Without Par Value) outstanding at
February 28,1997: 151,415,722.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Company's 1997 definitive proxy statement dated
March 31, 1997, are incorporated into Part III, Items 10, 11, 12
and 13 hereof.
TABLE OF CONTENTS
Page
____
Safe Harbor for Forward-Looking Statements. . . . . . . . . . i
PART I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . 1
General . . . . . . . . . . . . . . . . . . . . . . . 1
Generating Capability . . . . . . . . . . . . . . . . 2
Interconnections with Other Systems . . . . . . . . . 5
Competition and Franchises. . . . . . . . . . . . . . 6
Construction Program . . . . . . . . . . . . . . . .10
Financing Program . . . . . . . . . . . . . . . . . .10
Retail Rate Matters . . . . . . . . . . . . . . . . .12
Wholesale Rate Matters . . . . . . . . . . . . . . .14
Environmental Matters . . . . . . . . . . . . . . . .15
Nuclear Matters . . . . . . . . . . . . . . . . . . .18
Fuel . . . . . . . . . . . . . . . . . . . . . . . .22
Other Matters . . . . . . . . . . . . . . . . . . . .24
Operating Statistics . . . . . . . . . . . . . . . .27
Item 2. Properties . . . . . . . . . . . . . . . . . . . . .28
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . .28
Item 4. Submission of Matters to a Vote of Security Holders .29
Executive Officers of the Registrant . . . . . . . . 30
PART II
Item 5. Market for the Registrant's Common Equity and Related
Shareholder Matters . . . . . . . . . . . . . . . . 32
Item 6. Selected Consolidated Financial Data . . . . . . . .33
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 34
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. . . . . . . . . . . . . . . .66-69
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
This Form 10-K and other presentations made by the Company and
its subsidiaries contain forward-looking
statements within the meaning of Section 21E of the Securities
Exchange Act of 1934, as amended. The Company is
including the following cautionary statement in this Form 10-K to
make applicable and to take advantage of the safe
harbor provisions of the Private Securities Litigation Reform Act
of 1995 for any forward-looking statements, whether
written or oral, made by or on behalf of the Company.
Forward-looking statements include statements concerning plans,
objectives, goals, strategies, future events or performance, and
underlying assumptions, and any other statements which
are not statements of historical fact. Such statements include
without limitation those that are identified by the use of
the words "anticipates," "estimates," "expects," "intends,"
"plans," "predicts" and similar expressions. Although the
Company believes that in making any such statement its
expectations are based on reasonable assumptions, any such
statement involves uncertainties and is qualified in its entirety
by reference to the following important factors that could
cause the actual results of the Company to differ materially from
those projected in such forward-looking statement:
(i) prevailing governmental policies and regulatory actions,
including those of the Federal Energy Regulatory
Commission, the North Carolina Utilities Commission, the South
Carolina Public Service Commission, and the Nuclear
Regulatory Commission, with respect to allowed rates of return,
industry and rate structure, purchased power costs and
investment recovery, operations of nuclear generating facilities,
acquisitions and disposal of assets and facilities,
operation and construction of plant facilities, decommissioning
costs, present or prospective wholesale and retail
competition, changes in tax laws and policies and changes in and
compliance with environmental and safety laws and
policies, (ii) weather conditions and other natural phenomena,
(iii) unanticipated population growth or decline, and
changes in market demand and demographic pattern, (iv) competition
for retail and wholesale customers, (v) pricing
and transportation of fossil fuel and other commodities, (vi)
unanticipated changes in interest rates or in rates of
inflation, (vii) unanticipated changes in operating expenses and
capital expenditures, (viii) capital market conditions,
(ix) competition for new energy development opportunities, and (x)
legal and administrative proceedings and
settlements.
Any forward-looking statement speaks only as of the date on
which such statement is made, and the Company
does not undertake any obligation to update any forward-looking
statement to reflect events occurring or circumstances
arising after the date on which such statement is made, or to
reflect the occurrence of unanticipated events. New factors
emerge from time to time and it is not possible for the Company to
predict all of such factors, or to assess the impact
of each such factor or the extent to which any factor, or
combination of factors, may cause results to differ materially
from those contained in any forward looking statement.
i
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 primarily engaged in the
generation, transmission, distribution and sale of electricity
in portions of North Carolina and South Carolina. The Company had
6,701 employees at December 31, 1996. 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, 1996, the Company was
furnishing electric service to approximately 1,121,000 customers.
3. SALES. During 1996, 34% of operating revenues was derived
from residential sales, 21% from commercial
sales, 25% from industrial sales, 18% from resale sales and 3%
from other sources. Of such operating revenues,
approximately 68% was derived from North Carolina retail
customers, 14% from South Carolina retail customers, 14%
from wholesale customers under contract and 4% from bulk power
sales.
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 1994 increased by 5.8%,
for 1995 increased by 0.12%, and for 1996
decreased by 3.4%, 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 1994-1996
were 56.3%, 59.2%, and 60.8%, respectively. The Company
forecasts capacity margins of 12.1% over anticipated
system peak load for 1997 and 11.4% for 1998. 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
1
unavailable as a result of scheduled outages, environmental
modifications or unplanned outages. See PART I, 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 the Company,
Power Agency, which is comprised of former North Carolina
municipal wholesale customers of the Company and Virginia
Electric and Power Company (Virginia Power), 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.
2
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 rate-making 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
3. GENERATION ADDITIONS SCHEDULE. The Company's energy and
load forecasts were revised in December 1996.
Over the next ten years, system sales growth is forecasted
to average approximately 2.6% 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, provides for the addition of 3440
megawatts of combustion turbine capacity, 1800 megawatts
of combined cycle capacity, and 500 megawatts of baseload coal
capacity over the period 1997 to 2011. Additions planned
through 1999 are discussed below.
a. In 1997, two new combustion turbine generating units,
construction of which began in 1995, are scheduled to commence
commercial operation. These units, having a total generating
capacity of approximately 240 MW, are located at the Company's
Darlington County Electric Plant near Hartsville, South Carolina
and are expected to cost an aggregate amount of approximately $61 million.
b. The Company filed an Application for a Certificate of
Public Convenience and Necessity with the North Carolina Utilities
Commission (NCUC) on September 27, 1995 seeking permission to construct
500 MW of combustion turbine capacity adjacent to the Company's Lee Steam
Electric Plant in Wayne County, North Carolina. The
units will primarily be used during periods of summer and winter
peak demands. The NCUC hearing in this matter was
held on January 9, 1996, and by order issued March 21, 1996, the
NCUC granted the Company a certificate to construct
these combustion turbine units. The original schedule called for
construction of the 500 MW of combustion turbine
capacity to begin in 1996, and commercial operation anticipated to
begin in 1998; however, the Company has delayed plans
for construction of the 500 MW of combustion turbine capacity.
Construction is now scheduled to begin in 1997, with
commercial operation to begin in 1999 and the aggregate cost
expected to approximate $120 million. In the interim,
peaking requirements will be met with power purchases.
c. The Company issued a Notice of Inquiry (NOI) on March
12, 1996 concerning short-term power
purchases for the peak winter months of 1998-1999, and the peak
summer months of 1998. The NOI was sent to a number
of electric utilities, independent power producers and power
marketers. The Company received a number of bids, which
resulted in contract purchases for the summer of 1998.
d. In June 1996, the Company issued a Request for Proposals
(RFP) for purchased power of 700 to 1000 MW of capacity to meet
the Company's future generation needs in
its service territory and to replace contract purchases
terminating in 1998-1999. The Company projected a need of
approximately 200 to 350 MW in its western service territory,
and approximately 350 to 650 MW in its eastern service territory.
The capacity was requested to be available for delivery
by June 1, 1999. Proposals were invited from all potential
suppliers who were capable of meeting the conditions of the
RFP. In January 1997 the Company decided, based on the proposals
received, to purchase approximately one-third of the
necessary peaking capacity. The other two-thirds of capacity will
be supplied by a combination of power from the
combustion turbine units to be constructed at the Wayne County
site, described in paragraph 3.b. above, and the Buncombe
County site, as described in paragraph 3.e. below.
e. Due to increased economic activity and load growth in
its western service territory, on September 4, 1996,
the Company filed with the NCUC its preliminary plans to construct
approximately 320 MW of combustion turbine
generating capacity in Buncombe County, North Carolina at the
Company's existing Asheville Steam Electric Plant, with
an in-service date of the summer of 1999. Pursuant to those
plans, on January 31, 1997, the Company filed with the NCUC
an Application for a Certificate of Public Convenience and
Necessity for one 160 MW combustion turbine at the Asheville
Plant. (This turbine, along with certain power purchases
described in paragraph 3.d. above, will satisfy the Company's
anticipated future generation needs in its western service
territory. As a result, plans to construct the additional 160 MW
of combustion turbines in Buncombe County have been indefinitely
postponed.) The Company cannot predict the outcome
of this matter.
4
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 AND POWER PURCHASE/SALE 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. In
addition to the interchange agreements, the Company has executed
individual purchase agreements and sales agreements
with more than 100 companies beyond the Virginia-Carolinas
Subregion described in paragraph 2.b. below. Purchases and
sales under these agreements may be made due to economic or
reliability considerations.
By letter dated May 24, 1996, the Company provided Duke
with written notice that effective
June 1, 1999, it will terminate Schedule G to the Interchange
Agreement between the Company and Duke. Schedule G
provides for the wheeling of electricity between the Company's
eastern area and its western area.
By letter dated December 30, 1996, Duke provided the
Company with written notice that effective
December 31, 1999, it will terminate the Standby Concurrent
Exchange Agreement (Standby Agreement) between the
Company and Duke. The Standby Agreement provides for the
simultaneous exchange of up to 70 MW of electricity during
periods of scheduled maintenance or breakdown.
On December 31, 1996 pursuant to the Federal Energy
Regulatory Commission (FERC) Order 888,
which directs that no bundled economy energy coordination
transactions occur after December 31, 1996, the Company
submitted to the FERC a compliance filing to unbundle transmission
charges from rate schedules that are applicable to the
power sales agreements between the Company and others. See PART
I, ITEM 1, "Competition and Franchises," paragraph
1.b. for further discussion of FERC Order 888.
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 arrangements among the members of electric
reliability organizations at the subregional level.
3. LONG-TERM 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 purchases under the six-year 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 $65.4
million in 1996.
5
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
purchases under the agreement is approximately $30 million, which
represents capital-related capacity costs. Other costs
associated with the agreement include demand-related production
expenses, and fuel and energy-related operation and
maintenance expenses. In 1996, purchases under this agreement,
including transmission use charges, totaled $60.9 million.
c. In 1996, the Company agreed with Cogentrix of North
Carolina, Inc. and Cogentrix Eastern Carolina
Corporation (collectively referred to as Cogentrix) to amend
electric power purchase agreements related to five plants
owned by Cogentrix. The amendments, which became effective on
September 26, 1996, permit the Company to dispatch
the output of the five plants. In return, the Company gave up its
right to purchase two of the five plants in 1997. As a result
of the amendments, the Company will save approximately $30
million per year in energy costs during the years 1997
through 2002.
4. POWER AGENCY. Pursuant to the terms of a 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 $27
million. Other costs of such purchases are primarily
demand-related production expenses, and fuel and energy-related
operation and maintenance expenses. Purchases under the agreement
with Power Agency totaled $36.7 million in 1996.
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 mandate wholesale transfer, or
6
wheeling, of power over the transmission lines of other utilities.
Since the Energy Act was passed, competition in the
wholesale electric utility industry has increased due to greater
participation by traditional electricity suppliers and by
non-traditional electricity suppliers, such as wholesale power
marketers and brokers, and by the trading of energy futures
contracts on commodities exchanges such as the New York
Merchantile Exchange and the Kansas City Board of Trade.
This increased competition could impact the Company's load
forecasts, plans for power supply, and wholesale energy
sales and related revenues. The impact could vary depending on
the extent to which additional generation is built to
compete in the wholesale market, new opportunities are created for
the Company to expand its wholesale load, or current
wholesale customers elect to purchase from other suppliers after
existing contracts expire. If the Company is not able to
recover lost revenues associated with any lost loads, there could
be an adverse impact on the Company's financial
condition.
On April 24, 1996 the FERC issued final regulations for
wholesale wheeling of electric power through
its rules on open access transmission and stranded costs and on
information systems and standards of conduct (Orders 888
and 889). The rules require all transmitting utilities to have
on file an open access transmission tariff, which should
contain provisions for the recovery of stranded costs. The rules
also contain numerous other items that could impact the
sale of electric energy at the wholesale level. These final rules
became effective on July 9, 1996. FERC also issued a
notice of proposed rulemaking (NOPR) on Capacity Reservation Open
Access Transmission Tariffs. The Company filed
comments on this new NOPR with the FERC on October 21, 1996. On
May 24, 1996, the Company filed a Request for
Clarification and Rehearing of Orders 888 and 889, as did many
other entities. The Company filed its open access
transmission tariff with the FERC on July 9, 1996. On August 7,
1996, Power Agency filed with the FERC a motion to
intervene and protest concerning the Company's tariff. Other
entities also filed protests. These protests challenged
numerous aspects of the Company's tariff and requested that an
evidentiary proceeding be held. The FERC set the matter
for hearing and set a discovery and procedural schedule. The
Company, the FERC staff and most of the parties have
agreed on a settlement-in-principle, and by order dated January
16, 1997, the administrative law judge suspended the
procedural schedule until April 17, 1997, pending a final
settlement of the case. By order issued May 15, 1996, the NCUC
established a new docket (Docket No. E-100, Sub 78) to address
FERC Orders 888 and 889. In accordance with the
NCUC's order, the Company filed its comments on July 16, 1996
regarding the implementation of the FERC's orders,
their impact on North Carolina customers and what the NCUC can do
to maximize the benefits of the wholesale market.
In response to various rehearing requests, on March 4, 1997, the
FERC issued Orders 888-A and 889-A. These Orders
make minor clarifying adjustments to FERC Orders 888 and 889, and
are intended to facilitate implementation of those
Orders. The Company cannot predict the outcome of these matters
or the impact of the new rules on its future financial
condition.
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
have changed or 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. These changes or proposals elsewhere have
taken differing forms and included disparate elements.
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 investigate 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 would not convene a
formal hearing to investigate these issues at that 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 indicated that they would monitor
other states' activities regarding retail competition and would
allow interested parties to submit information on the subject.
7
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. On April 3, 1996, the NCUC issued an
order seeking comments regarding the impact of retail competition
on system reliability, obligation to serve, and stranded
and ancillary costs. However, by order issued May 7, 1996, in
Docket No. E-100, Sub 77, which concerns retail
competition, the NCUC found that FERC Orders 888 and 889
essentially restructure the wholesale electric industry, and
therefore may provide a new focus for NCUC proceedings with
respect to competition in the electric industry. As a result,
the NCUC concluded: (i) that all parties should concentrate their
efforts on examining the impacts of the FERC orders,
(ii) that the filing of comments requested by its order issued
April 3, 1996 should be extended indefinitely, and (iii) that
this docket should be held in abeyance pending further order. The
Company cannot predict the outcome of the current
debate regarding retail wheeling; however, the implications of
retail competition on the Company's financial condition
could be of a significantly greater magnitude than those
associated with wholesale wheeling as discussed above.
On January 29, 1997, representatives of both houses of
the North Carolina General Assembly filed bills
calling for the establishment of a commission, comprised of
retail electric customers, electric companies, legislators and
other interested parties, to study the future of the electric
utility industry in North Carolina. The commission would be
expected to file a report with the 1999 North Carolina General
Assembly that would examine the numerous components
of the electric industry and the implications of making changes.
On February 6, 1997, representatives in the South
Carolina General Assembly introduced a bill calling for a
transition to full competition in the electric utility industry
beginning in 1998. The Company cannot predict the outcome of
these matters.
Several pieces of legislation that concern the issue of
retail competition were introduced in Congress
in 1996. One bill (HR 3790), if enacted, would mandate retail
wheeling in all 50 states no later than December 15, 2000.
As proposed, this bill would require states to give all customers
the right to choose their electric supplier. If this choice
was not implemented by the states, the bill proposes that the FERC
would be responsible for the implementation. The
other bills had various provisions concerning retail competition
and related topics. On January 30, 1997 a bill was
introduced that would require states to allow all customers to
choose their electric supplier by December 15, 2003. The
bill has been referred to the Public Utility Subcommittee of the
House Labor, Commerce and Industry Committee. The
Company anticipates that this issue will continue to be debated by
Congress during 1997. 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 14% of the Company's 1996
operating revenue. These long-term contracts will
allow the Company flexibility in managing its load and efficiently
planning its future resource requirements. 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. On December 2, 1996, the Company filed an application
with the NCUC (Docket No. E-2, Sub 702)
for approval of a self-generation deferral rate for General
Electric Company's nuclear fuel and aircraft engine facility in
North Carolina. In 1994, the NCUC adopted guidelines for
self-generation deferral rates. The guidelines allow utilities
to adjust rates to retain certain loads for which self-generation
is feasible as long as they can demonstrate that doing so
is in the best interest of all of their customers. The proposed
rate, which is somewhat lower than the rate General Electric
has been paying for electricity, will enable the Company to retain
General Electric as a customer. On February 28, 1997,
the Public Staff of the NCUC filed a response to the Company's
application recommending that the Company's proposed
self-generation deferral rate for General Electric be allowed. On
March 10, 1997, the NCUC approved the proposed rate.
8
d. On December 16, 1996, the Company filed an application
with the NCUC (Docket No. E-2, Sub 704)
for approval of an experimental real-time pricing schedule for a
limited number of non-residential customers. The
proposed tariff offers hourly marginal cost-based prices for
electricity consumption that exceeds the customer's baseline,
which typically represents the hourly consumption during the
previous year under existing tariffs. The proposed rate
provides opportunities for some customers to control a part of
their electricity costs and helps the Company make the best
use of its existing generation resources. The tariff would be
available to a limited number of participants with contract
demand requirements of at least 1,000 kW. A similar application
was filed with the SCPSC on February 6, 1997. On
February 18, 1997, the proposed tariff was approved by both the
NCUC and SCPSC.
e. In June 1994, the FERC granted final approval of a
Power Coordination Agreement (1994 PCA) and
an Interchange Agreement, both dated August 27, 1993, which
set forth explicitly the future relationship between
the Company and North Carolina Electric Membership Corporation
(NCEMC), and established a framework under which
they will operate (Project Nos. 432-004 and 2748-000). The 1994
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. On October 31, 1996,
the Company and NCEMC entered into a
revised power coordination agreement under which the Company will
continue to serve a majority of NCEMC's power
needs well past the year 2000. Under the terms of the revised
agreement, NCEMC will receive discounted capacity in
exchange for long-term commitments to the Company for its
supplemental power. As a result of this new agreement, the
Company will provide 225 MW of baseload power to NCEMC from 2000
to 2010, an additional block of 225 MW from
2001 to 2004, and a third block of 225 MW from 2002 to 2008. The
remainder of the NCEMC load provided by the
Company, not separately contracted for in the revised agreement,
will be billed at a fixed price through the year 2004,
rather than at the formula rates established in the 1994 PCA. The
revised agreement, which represents an amendment to
the 1994 PCA, was accepted for filing by the FERC on December 26,
1996, with an effective date of January 1, 1997.
f. 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
had become a municipal electric utility, the City would possibly
have sought to purchase bulk power from a supplier other
than the Company. The Company undertook efforts to educate the
City's residents, businesses and industries regarding
the many costs and legal issues associated with a municipalization
effort. Both the Company and the City undertook
studies to determine the feasibility of the municipalization
proposal. The results of the Company's study, which was
conducted by the consulting group Stone & Webster, found that
municipalization would increase the cost of electricity
to the City. The results of the City's study, conducted by the
consulting group Strategic Energy Limited, found that
municipalization would only benefit the City if the City were not
required to pay the Company for any of its lost revenues
or stranded costs. On September 3, 1996, the Darlington City
Council voted against the proposal that the City become
a municipal electric utility and will take no further action on
the request at this time.
g. On August 7, 1996, Power Agency notified the Company
that it intends to discontinue certain
contractual purchases of power from the Company effective
September 1, 2001. Power Agency's notice indicated that
it intends to replace these contractual obligations through
purchases of capacity and energy related services in the open
market and that the Company will be considered as a potential
supplier for those purchases. The 1981 Power
Coordination Agreement, as amended, between the parties requires
that Power Agency give appropriate notice five years
prior to reducing its purchases from the Company. The Company and
Power Agency have agreed on a process for
determining the sufficiency of the August 1996 notice. 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.
9
CONSTRUCTION PROGRAM
____________________
1. CAPITAL REQUIREMENTS. During 1996 the Company expended
approximately $555 million for capital
requirements. The Company revised its capital program in 1996 as
part of its annual business planning process.
Estimated capital requirements for the years 1997 through 1999,
which primarily reflect construction expenditures that
will be made to meet customer growth by adding generating,
transmission and distribution facilities as well as upgrading
existing facilities, are set forth below. These estimates include
Clean Air Act compliance expenditures of approximately
$56 million, and generating facility addition expenditures of
approximately $317 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 2002. See PART I, ITEM 1,
"Environmental Matters," paragraph 2 and "Generating Capability,"
paragraph 3, for further discussion of the impact of
the Clean Air Act on the Company and planned generation additions,
respectively.
Estimated Capital Requirements
______________________________
(In millions)
1997 1998 1999 TOTAL
____ ____ ____ _____
Construction Expenditures $365 $489 $401 $1,255
Nuclear Fuel Expenditures 78 104 104 286
AFUDC (12) (20) (23) (55)
____ ____ ____ _____
Net Expenditures (a) 431 573 482 1,486
Mandatory Redemptions of
Long-Term Debt 103 208 53 364
____ ____ ____ _____
TOTAL $534 $781 $535 $1,850
==== ==== ==== =====
____________
(a) Reflects reductions of approximately $7 million, $11 million
and $7 million for 1997, 1998 and 1999, 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, external
funding requirements, which do not include early redemptions of
long-term debt or redemptions of preferred stock, are
expected to approximate $161 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 1997 or 1999. The
Company may from time to time sell additional
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. 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.
10
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. ISSUANCES OF BONDS, PREFERRED STOCK AND DEBENTURES. No
bonds, preferred stock or debentures were
issued by the Company during 1996; however, see PART I, ITEM 1,
"Financing Program," paragraph 5 below for
discussion of the Company's credit facility borrowings.
4. REDEMPTIONS/RETIREMENTS OF BONDS, PREFERRED STOCK AND
DEBENTURES. Redemptions and retirements during 1996 and early
1997 included:
- 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 $22.6 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.
- The retirement on April 1, 1996, of $30 million principal
amount of First Mortgage Bonds, 5 1/8%
Series, which matured on that date.
- The redemption on April 1, 1996, of $100 million principal
amount of First Mortgage Bonds, 9%
Series due April 1, 2022, at 105.89% of the principal
amount of such bonds plus accrued interest to
the date of redemption.
- The retirement on December 2, 1996, of $25 million
principal amount of First Mortgage Bonds,
4.85% Secured Medium-Term Notes, Series C, which matured
on that date.
- The retirement on December 27, 1996, of $50 million
principal amount of First Mortgage Bonds,
7.90% Secured Medium-Term Notes, Series C, which matured
on that date.
- The retirement on January 24, 1997, of $60 million
principal amount of First Mortgage Bonds,
7.75% Secured Medium-Term Notes, Series C, which matured
on that date.
5. CREDIT FACILITIES. The Company's credit facilities
presently total $685 million. This amount includes
two new long-term revolving credit facilities totaling $350 million,
which the Company entered in 1996 to support its
commercial paper borrowings. In addition to these new facilities,
the Company has other long-term revolving credit
agreements totaling $235 million, and a $100 million short-term
revolving credit agreement. The Company is required
to pay minimal annual commitment fees to maintain certain credit
facilities. Consistent with management's intent to
maintain up to $350 million of its commercial paper on a
long-term basis, and as supported by its long-term revolving credit
facilities, the Company has included in its long-term debt $350
million of commercial paper outstanding as of December
31, 1996. See PART II, ITEM 8, Consolidated Financial Statements
and Supplementary Data, Note 3, for a more detailed
discussion of the Company's revolving credit facilities.
11
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%
=====
A petition was filed on July 19, 1996 by the Carolina
Industrial Group for Fair Utility Rates (CIGFUR) with
the NCUC requesting that the NCUC conduct an investigation of the
Company's base rates or treat its petition as a complaint
against the Company (Docket No. E-2, Sub. 699). The petition
alleged that the Company's return on equity (which was
authorized by the NCUC in the Company's last general rate
proceeding in 1988), and earnings are too high. The Company
filed a response to the petition and motion to dismiss on July 29,
1996, in which it argued that the petition was without merit.
By letter dated August 2, 1996, the Company notified the NCUC that
the Company intended to seek NCUC approval of
certain accounting adjustments that would impact the Company's
earnings. On August 6, 1996, the NCUC issued an order
allowing the Company until September 16, 1996 to submit these
adjustments, and stating that it would take no further action
in this docket until the filing was made by the Company. On
September 13, 1996, the Company (i) filed for approval to
accelerate the amortization of certain regulatory assets, and to
defer and amortize hurricane damage expenses, (ii) requested
NCUC approval to implement these adjustments, effective January 1,
1997, and (iii) renewed its motion to dismiss CIGFUR's
petition. On October 28, 1996, the Public Staff of the NCUC
filed its comments on the Company's proposal. Those
12
comments included recommendations that the NCUC issue an order
allowing the adjustments proposed by the Company,
subject to certain minor modifications. By Order dated December
6, 1996, the NCUC approved the Company's proposal
to accelerate amortization of certain regulatory assets over a
three-year period beginning January 1, 1997. The accelerated
amortization of these regulatory assets will reduce income by
approximately $43 million, after tax, in each of the next three
years. The NCUC also authorized the Company to defer operation
and maintenance expenses associated with Hurricane Fran.
See PART I, ITEM 1, "Other Matters," paragraph 8 for further
discussion of hurricane damage. On December 27, 1996, the
NCUC issued an order denying CIGFUR's petition and stating that it
tentatively found no reasonable grounds to proceed with
CIGFUR's petition as a complaint. On January 10, 1997, CIGFUR
filed a motion for reconsideration with the NCUC, to
which the Company responded on January 23, 1997. On February 6,
1997, the NCUC issued an order denying CIGFUR's
motion for reconsideration. On February 25, 1997, CIGFUR filed a
Notice of Appeal of the NCUC's decision with the North
Carolina Court of Appeals. The Company cannot predict the outcome
of this matter.
With regard to South Carolina retail jurisdiction, on
December 9, 1996, the Company filed for approval of
a similar proposal to accelerate amortization of certain
regulatory assets, including plant abandonment costs related to
the Harris Plant, over a three-year period beginning January 1, 1997,
with the SCPSC (Docket No. 96-381-E). This accelerated
amortization will reduce income by approximately $13 million,
after tax, in each of the next three years. In anticipation of
approval of the proposal in 1997, the unamortized balance of plant
abandonment costs related to the Harris Plant was adjusted
in 1996 to reflect the present value impact of the shorter
recovery period. This adjustment resulted in an increase in
income of approximately $14 million, after tax, in 1996. On March 4,
1997, the SCPSC approved the implementation of the proposed
accounting adjustments.
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 South Carolina
Consumer Advocate and Nucor Corporation intervened
in the proceeding, but the SCPSC has not yet issued an order in
this matter. The Company cannot predict the outcome of this
matter.
4. 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. On June 7, 1996, the Company filed its 1996
application proposing no change in its net fuel factor. The
hearing was held on August 14, 1996, and by order issued
September 10, 1996, the NCUC approved the Company's request for no
change in its net fuel factor.
In the South Carolina retail jurisdiction, fuel rates are
set by the SCPSC. At the fuel hearings, any past over-
or under-recovery of fuel costs is taken into account in
establishing the new rate. During the 1996 legislative session,
the South Carolina General Assembly made several modifications to SC
Code Ann. Section 58-27-865, which is the statute that governs
the recovery of fuel cost by electric utilities. The
modifications include: changing the test period from a six-month
period to a twelve-month period, which will result in the frequency of
fuel cost hearings being changed from every six months to
every twelve months; allowing utilities to recover the cost of
Clean Air Act allowances through the fuel factor; and
establishing a rebuttable presumption of prudent operation of a
utility's nuclear generating facilities if the utility achieves a
13
nuclear system capacity factor of 92.5%, exclusive of refueling
and maintenance outages. On February 19, 1997, the
Company filed a proposal with the SCPSC to reduce its fuel factor
from its current level of 1.34 cents/kWh to 1.122 cents/kWh.
In accordance with the modified fuel cost recovery
statute, the Company's South Carolina fuel proceeding was
held on March 19, 1997, and on March 25, 1997, the SCPSC approved the
Company's proposed fuel factor. The new fuel factor will be effective
for the period April 1, 1997 through March 31, 1998.
5. AVOIDED COST PROCEEDINGS.
a. The NCUC opened Docket No. E-100, Sub 79 for its
biennial proceeding to establish the avoided cost
rates for all electric utilities in North Carolina. Avoided cost
rates are intended to reflect the costs that utilities are able to
"avoid" by purchasing power from qualifying facilities. The
Company's initial filing in this docket was made on
November 4, 1996. Intervenor comments on the utilities' filings
were made on January 10, 1997. On February 4, 1997, the
NCUC received non-expert public testimony and further written
comments by the parties. On March 4, 1997, all parties filed
proposed orders with the NCUC. The Company cannot predict the
outcome of this matter.
b. The SCPSC opened Docket No. 95-1192-E to establish
avoided cost rates for all electric utilities in South
Carolina. Hearings were held on August 8, 1996, and on August 28,
1996, the SCPSC issued an order approving the
Company's proposed avoided cost rates.
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. On April 11, 1996
the FERC issued an order approving the 10.75 percent ROE and
ordered refunds of excess revenues collected since January
1, 1996. These refunds are not material to the results of
operations of the Company.
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
14
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
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.
The costs associated with compliance with pollution
control laws and regulations at the Company's existing facilities
that the Company expects to incur from 1997 through 1999
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 requirements, 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 fuel-switching and 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'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 oxide emissions. The Company
estimates that future capital costs necessary to comply with
Phase II of the Act will approximate $160 million. Increased
operation 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. The EPA has
recently proposed revisions to existing air quality standards for
ozone and particulate matters. If these standards are
eventually finalized as proposed, additional compliance costs will
be incurred. 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 operation, and
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. In most instances, this statute has
been interpreted to impose retroactive joint and several
15
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 Consent Decree has been approved by the court,
and the work it requires is in progress. 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. 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.
c. 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.
Seaboard is in bankruptcy. 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 Administrative Order of Consent (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
16
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.
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, located near Cordova, North Carolina.
The lawsuit 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. (The EPA first notified
the Company in 1992 that it is a PRP with respect to the
additional remediation of hazardous wastes at the site.) 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 some petroleum products 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 CERCLA hazardous wastes
from Company facilities were sent to the 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.
e. Various organic materials associated with the
production of manufactured gas, generally referred to as
coal tar, are regulated under various federal and state laws. 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 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 Waste Management (DWM), formerly
the Division of Solid Waste Management, to establish a uniform
framework for addressing these MGP sites. The
investigation and remediation of specific MGP sites will be
addressed pursuant to one or more Administrative Orders on
Consent between the DWM and individual PRPs. The Company
continues to investigate the identities of parties connected
to individual MGP sites , the relative relationships of the
Company and other parties to those sites, and the degree to which
the Company will undertake shared voluntary efforts with others
at individual sites.
Due to uncertainty regarding the extent of remedial
action that will be required and questions of liability,
the cost of remedial activities at certain MGP sites is not
currently determinable. The Company cannot predict the outcome
of these matters.
f. By letter dated March 7, 1996, the EPA notified the
Company that it is a PRP with respect to the disposal
of hazardous substances at the Cherokee Oil Company (Cherokee)
sites in Charlotte, North Carolina. The materials sent from
the Company's facilities to the Cherokee sites were associated
with tank cleanings at the Company's former Wilmington Oil
Terminal. The EPA has performed removal actions at the sites and
is now seeking cost recovery. Although the Company
cannot predict the outcome of this matter, it does not anticipate
costs associated with this site will be material to the results
of operations of the Company.
4. OTHER ENVIRONMENTAL MATTERS. On April 21, 1989, the North
Carolina Department of Environment, Health
and Natural Resources, Division of Water Quality (DWQ), formerly
the Division of Environmental Management, requested
that, in response to a 1979 spill of No. 2 fuel oil, the Company
install a groundwater compliance monitoring system at the
17
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 DWQ 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 solely associated with its prior years of
ownership. 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. As noted above, 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. The Company continues to carry a
liability for the estimated costs associated with certain
remedial activities at several MGP and other sites. This
liability is not material to the financial position 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
Nuclear Regulatory Commission (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 1997,
1998 and 1999 are expected to total approximately $37 million, $44
million, and $37 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, 1996, sufficient
on-site spent nuclear fuel storage capability is available for the
full-core discharge of Brunswick Unit No. 1 through 1999,
Brunswick Unit No. 2 through 1998, and Robinson Unit No. 2 through
2000 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
18
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 in June 1983 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. 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. To date, the
Company has paid $306 million (including Power Agency's
share), to the DOE. See PART I, ITEM 1, "Retail Rate Matters,"
paragraph 4. By letter dated December 17, 1996, the DOE
notified the Company and other similarly situated utilities that
the agency anticipates that it will be unable to begin acceptance
of spent nuclear fuel by January 31, 1998. On January 31, 1997,
the Company, together with 35 other utilities, filed a Joint
Petition for Review with the United States Court of Appeals
requesting the Court review the final decision of the DOE and
the DOE's failure to meet its unconditional obligation under the
Nuclear Waste Act. The petition requests the Court, among
other things, to issue a declaration stating that the petitioners
are relieved of their reciprocal obligation to pay fees into the
Nuclear Waste Fund and, instead, may deposit those funds into
escrow until the DOE commences disposing of spent nuclear
fuel. 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
19
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 funds 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 $33.1 million in 1996, $31.2
million in 1995, and $29.5 million in 1994. Accumulated
decommissioning costs, which are included in accumulated
depreciation, were $326 million at December 31, 1996 and $288.4
million at December 31, 1995. These costs 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 $145.3 million at December 31, 1996
and $110.2 million at December 31, 1995. Trust earnings, which
increase the trust balance with a corresponding increase
in accumulated decommissioning, were $4.5 million in both 1996 and
1995 and $1.5 million in 1994. 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 (the 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.
It is uncertain what impacts the final statement may ultimately have
on the Company's accounting for nuclear decommissioning and other
closure and removal costs. The Board has announced that the
effective date would be no earlier than 1998.
5. OPERATING LICENSES. Facility Operating Licenses, issued
by the NRC, for the Company's nuclear facilities
allow for a full 40 years of operation. Expiration dates for
these licenses are set forth in the following table.
20
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 became 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 (PARS) 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 2000. 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.
21
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 nuclear
units. For a more detailed discussion of nuclear liability
insurance, see PART II, ITEM 8, Consolidated Financial Statements
and Supplementary Data Note 11 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 1993 through 1997 is set
forth below:
1993 1994 1995 1996 1997
____ ____ ____ ____ ____
(estimated)
Fossil 54% 43% 44% 45% 48%
Nuclear 31 42 42 41 42
Purchased Power 13 13 13 12 9
Hydro 2 2 1 2 1
2. COAL.
a. The Company has intermediate and long-term
agreements from which it expects to receive
approximately 63% of its coal burn requirements in 1997. During
1995 and 1996, the Company obtained approximately
77% (7,531,171 tons), and 68% (7,181,257 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 1998 to 2006.
During 1996, the Company maintained from 29 to 52 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 1,286,000 tons
of coal in the spot market during 1995 and 3,340,000
tons in 1996. The Company's contract coal purchase prices during
1996 ranged from approximately $29.90 to $38.45 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
____ _____ _________________
1992 43.25 174
1993 43.10 172
1994 43.36 174
1995 44.46 179
1996 42.21 170
b. The Company and certain subsidiaries of Zeigler
Coal Holding Company (Zeigler) have renegotiated
their existing contract. Under the revised agreement, which
expires in 2006, the Company will continue to purchase
22
approximately 2.75 million tons of coal annually from Zeigler's
Marrowbone mine, and will purchase approximately 6
million tons of additional, lower cost coal from Zeigler over a
period of several years under a new contract. The coal will
be required to meet the same technical specifications for sulfur
and thermal content as the coal supplied from the
Marrowbone mine, and is expected to save the Company more than
$100 million over the life of the contract.
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 8.8
million gallons and 12.1 million gallons of No. 2 oil during 1995
and 1996, 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. Two additional
units will be added in 1997 increasing gas-fired capacity by 240
MW. Over the last five years, No. 2 oil, natural gas and
propane accounted for 1.7% of the Company's total burned fuel
cost. In 1996, No. 2 oil, natural gas and propane accounted
for 1.6% 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 uranium
contracts are expected to supply the necessary nuclear fuel
to operate Robinson Unit No. 2 through 1998, 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
DECOMMISSIONING FUND. Under Title XI of the Energy
Policy Act of 1992, Public Law 102-486, Congress established a
decontamination and decommissioning (D&D) 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. The Company has paid approximately $27 million in
D&D fees, and expects to pay a cumulative total of approximately
$85 million during the period 1992 through 2007. As
of December 31, 1996, the Company had a recorded liability of
$56.1 million representing the balance of its estimated share
of the contributions. The Company is recovering these costs as a
component of fuel cost.
On or about March 4, 1997, the Company filed a claim with
the DOE seeking a refund of part of the price
paid by the Company for enrichment services purchased from the DOE
in 1993. It is the Company's position that the
contract price it paid to DOE in 1993 for uranium purchases
included the cost of D&D, and that DOE's collection of
23
additional D&D fees pursuant to the Energy Act resulted in an
overpayment of fees by the Company totaling approximately
$1.4 million. The Company cannot predict the outcome of this matter.
Additionally, on or about March 21, 1997, the Company,
along with other entities, filed an administrative
claim with the DOE, and a Complaint against the DOE in the United
States Court of Federal Claims, Carolina Power & Light Company v.
United States, seeking the recovery of approximately $27 million
representing D&D assessments paid by the Company, and the
elimination of future D&D fund assessments. It is
the Company's position that the D&D assessments
constitute a breach of contract, a taking of vested
contract rights, a violation of property rights, illegal exaction,
and a violation of the Fifth Amendment of the United States
Constitution. In a similar case, Yankee Atomic Electric Company
v, United States (33 Fed.Cl. 580 (Cl.Ct. 1995) the United
States Court of Claims found that a portion of the D&D assessments
made against Yankee Atomic were unlawful. The
government has appealed that case to the District of Columbia
Circuit Court of Appeals. The Company cannot predict the
outcome of these matters.
6. PURCHASED POWER. The Company purchased 6,792,340 MWh in
1996, 6,974,597 MWh in 1995 and 6,710,346 MWh in 1994 or approximately
12%, 13% and 13%, respectively, of its system energy requirements
(including Power Agency) and had available 1,536 MW in 1996, 1,596 MW
in 1995 and 2,840 MW in 1994 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
24
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, LLC. On November 29, 1994, the Company
established a wholly-owned subsidiary, CaroNet,
Inc., (CaroNet), which was reorganized as CaroNet, LLC in 1996.
CaroNet owns a ten-percent interest in a regional
limited 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 and South Carolina, as
well as a small portion of Georgia. PCS, a wireless
communications technology, provides high-quality mobile
communications. BellSouth is the general partner and handles
day-to-day management of the business. In anticipation
of infrastructure construction, the Company invested $50 million
in CaroNet on April 28, 1995. Construction of the PCS
system infrastructure began during the summer of 1995 and by the
end of 1996, service was available in all major cities
in the Carolinas. The bulk of the infrastructure construction is
expected to be completed within two years. CaroNet
participates on the Partnership's executive committee. In
addition to participating in the Partnership, CaroNet is providing
fiber optic network capacity to telecommunications carriers in
North and South Carolina. On November 14, 1995, the
SCPSC issued an order granting CaroNet permission to provide
wholesale services in South Carolina. CaroNet filed an
application to provide competing local telephone service and an
application to provide intrastate long distance service in
North Carolina with the NCUC on September 19, 1996 and September
26, 1996, respectively.
6. CAROHOME, LLC. In 1995, the Company established CaroHome,
LLC (CaroHome), a limited-liability
company, to further the Company's investments in affordable
housing. These investments are designed to earn tax credits
while helping communities meet their needs for affordable housing.
The Company, primarily through CaroHome, has
committed to invest $47 million in affordable housing and
anticipates investing up to a total of $125 million in affordable
housing by the year 2000.
25
7. 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. (KBI), an energy-management
software and control systems company. Investments in KBI amounted
to $9 million in 1996, with total investment through
2001 anticipated to reach $12 million, subject to the terms and
conditions of a Stock Purchase Agreement, which includes
certain sales and profitability targets. Although KBI and its
subsidiaries will continue to operate independently,
CaroCapital has designated two directors who are currently serving
on the KBIs' board of directors.
8. HURRICANE DAMAGE. On July 12, 1996, Hurricane Bertha
struck the North Carolina coast. Restoration of the Company's system from
hurricane-related damage resulted in operation and maintenance expenses of
approximately $4 million and capital expenditures of
approximately $7 million, which did not have a material impact on
the results of operations or financial position of the
Company.
On September 5, 1996, Hurricane Fran struck significant portions
of the Company's service territory. Restoration of the
Company's system from hurricane-related damage resulted in
operation and maintenance expenses of approximately
$40 million and capital expenditures of approximately $55 million.
The capital expenditures are related to labor and
materials used in replacing destroyed poles, lines and other
equipment. The operation and maintenance expenditures are
related to repairs of damaged equipment. The Company did not seek
a general rate increase to recover the restoration costs.
Instead, on September 13, 1996, the Company proposed to the NCUC
(Docket No. E-2, Sub 699) a plan that would defer
operation and maintenance expenses associated with Hurricane Fran,
with amortization over the next three years. By Order
dated December 6, 1996, the NCUC authorized the Company to defer
operation and maintenance expenses associated with
Hurricane Fran, with amortization over a 40-month period beginning
in September 1996. See PART I, ITEM 1, "Retail
Rate Matters," paragraph 2 for further discussion of the approved
plan.
26
<TABLE>
<CAPTION>
OPERATING STATISTICS
--------------------
Years Ended December 31
-----------------------
<S> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Energy supply (millions of kWh)
Generated - coal 24,859 23,517 21,001 25,807 25,196
nuclear 20,284 19,949 18,511 13,691 11,108
hydro 882 824 884 784 881
combustion turbines 68 56 67 84 54
Purchased 7,292 7,433 7,039 7,110 7,343
----------- ----------- ----------- ----------- -----------
Total energy supply (Company share) 53,385 51,779 47,502 47,476 44,582
Power Agency share (a) 3,616 3,828 3,236 2,402 2,232
----------- ----------- ----------- ----------- -----------
Total system energy supply 57,001 55,607 50,738 49,878 46,814
=========== =========== =========== =========== ===========
Average fuel cost (per million BTU)
Fossil $ 1.75 $ 1.83 $ 1.78 $ 1.75 $ 1.83
Nuclear fuel 0.45 0.46 0.47 0.46 0.45
All fuels 1.14 1.17 1.14 1.28 1.38
Energy sales (millions of kWh)
Residential 12,611 12,074 11,147 11,398 10,490
Commercial 9,615 9,276 8,690 8,548 8,060
Industrial 14,456 14,312 14,030 13,557 13,134
Government and municipal 1,263 1,288 1,263 1,248 1,213
Power Agency contract requirements 2,523 2,338 2,589 3,505 3,304
NCEMC 3,947 5,454 4,885 4,778 4,372
Other wholesale 2,014 1,915 1,983 2,144 2,042
Other utilities 4,899 3,233 985 327 214
----------- ----------- ----------- ----------- -----------
Total energy sales 51,328 49,890 45,572 45,505 42,829
Company uses and losses 2,057 1,889 1,930 1,971 1,753
----------- ----------- ----------- ----------- -----------
Total energy requirements 53,385 51,779 47,502 47,476 44,582
=========== =========== =========== =========== ===========
Customers billed
Residential 945,703 920,495 894,616 873,377 856,130
Commercial 167,151 159,064 155,349 151,242 146,858
Industrial 5,066 4,863 4,845 4,825 4,763
Government and municipal 2,774 2,328 2,302 2,214 2,262
Resale 27 17 12 26 26
----------- ----------- ----------- ----------- -----------
Total customers billed 1,120,721 1,086,767 1,057,124 1,031,684 1,010,039
=========== =========== =========== =========== ===========
Operating revenues (in thousands)
Residential $ 992,152 $ 969,112 $ 915,986 $ 943,697 $ 871,469
Commercial 627,880 618,394 595,573 592,973 560,560
Industrial 721,588 733,448 741,662 744,016 720,413
Government and municipal 75,391 78,400 78,317 78,616 76,838
Power Agency contract requirements 96,795 100,951 115,262 134,258 140,623
NCEMC 234,653 299,171 266,733 253,859 252,744
Other wholesale 87,463 82,407 84,775 100,062 99,749
Other utilities 105,077 78,147 33,789 11,232 4,834
Miscellaneous revenue 54,716 46,523 44,492 36,670 39,591
----------- ----------- ----------- ----------- -----------
Total operating revenues $2,995,715 $ 3,006,553 $ 2,876,589 $ 2,895,383 $ 2,766,821
=========== =========== =========== =========== ===========
Peak demand of firm load (thousands of kW)
System 9,812 10,156 10,144 9,589 9,236
Company 9,264 9,500 9,642 9,107 8,745
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 1,603 1,592 1,596 1,289 890
----------- ----------- ----------- ----------- -----------
Total system capability 11,216 11,205 11,209 10,902 10,503
Less Power Agency-owned portion (a) 686 682 654 627 647
----------- ----------- ----------- ----------- -----------
Total Company capability 10,530 10,523 10,555 10,275 9,856
=========== =========== =========== =========== ===========
__________
(a) Net of the Company's purchases from Power Agency.
(b) Represents peak generating capability, based on summer peak conditions assuming all generating units are available
for operation. Amounts include capacity under contract with cogenerators, small power producers and other
utilities.
27
</TABLE>
ITEM 2. PROPERTIES
__________________
In addition to the major generating facilities listed in PART I, 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, 1996, the Company had 5,860 pole miles of
transmission lines including 292 miles of 500 kV
lines and 2,827 miles of 230 kV lines, and distribution lines of
approximately 44,312 pole miles of overhead lines and
approximately 6,791 miles of underground lines. Distribution and
transmission substations in service had a transformer
capacity of approximately 36,091 kVA in 2,248 transformers.
Distribution line transformers numbered 408,047 with an
aggregate 16,697,000 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 to its principal plants and important units,
subject to the lien of its Mortgage and Deed of Trust, with minor
exceptions, restrictions, and reservations in conveyances, as well
as minor defects of the nature ordinarily found in
properties of similar character and magnitude. The Company also
owns certain 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, 1992 through December 31, 1996, there
was added to the Company's utility plant accounts $1,998,819,677,
there was retired $568,063,316 of property and there
were transfers to other accounts and adjustments for a net
decrease of $21,547,650 resulting in net additions during the
period of $1,409,208,711 an increase of approximately 15.66%.
ITEM 3. LEGAL PROCEEDINGS
_________________________
Legal and regulatory proceedings are included in the
discussion of the Company's business in PART I, ITEM 1
and incorporated by reference herein.
28
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 1996.
29
EXECUTIVE OFFICERS OF THE REGISTRANT
____________________________________
Name Age Recent Business Experience
____ ___ __________________________
Sherwood H. Smith, Jr. 62 Chairman of the Board of Directors,
October 1996 to present; Chairman
and Chief Executive Officer,
September 1992 to October 1996;
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 58 President and Chief Executive Officer,
October 1996 to present; President and
Chief Operating Officer, September 1992
to October 1996; 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.
Glenn E. Harder 46 Executive Vice President and Chief
Financial Officer, Financial Services,
August 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 52 Executive Vice President and Chief
Nuclear Officer, Energy Supply,
December 1996 to present;
Executive Vice President - Nuclear
Generation, April 1993 to
December 1996; Executive
Vice President - Nuclear
30
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.
Roy A. Anderson 48 Senior Vice President,
Customer Services, 1996-January
1997(Resigned); Vice President,
Fossil Generation, 1995-1996;
Vice President, Brunswick
Nuclear Power Plant, 1992-1995.
James M. Davis, Jr. 60 Senior Vice President, Group
Executive - Power Operations,
June 1986 to present; Senior
Vice President - Operations
Support Group, August 1983.
Norris L. Edge 65 Senior Vice President, Group
Executive - Customer and Operating
Services, May 1990 to October 1996
(Retired); Vice President -
Rates and Energy Services, September
1989; Vice President - Rates and
Service Practices, December 1980.
Cecil L. Goodnight 54 Senior Vice President and Chief
Administrative Officer,
Administrative Services, December
1996 to present; Senior Vice President,
Human Resources and Support Services,
March 1995- December 1996; Vice President
- Human Resources (formerly Employee
Relations Department), May 1983 to
March 1995.
Richard E. Jones 59 Senior Vice President, General
Counsel and Secretary, Group
Executive - Public and Corporate
Relations, November 1990 to
April 1996 (Resigned); 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.
Mark F. Mulhern 37 Vice President and Treasurer,
February 1997 to present; Vice
President and Controller, March
1996 to February 1997; 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.
Bonnie V. Hancock 35 Vice President and Controller,
February 1997 to present; Manager,
Tax Department, September 1995 to
February 1997; Director, Corporate
Income Tax, Treasury Department,
September 1993 to September 1995.
Before joining the Company, Ms.
Hancock held various management
positions in the Tax Department
at Potomac Electric Power Company.
31
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:
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
1996 High Low Dividends Paid
First Quarter $ 38 3/8 $ 34 1/2 $.455
Second Quarter 38 34 7/8 .455
Third Quarter 38 1/4 34 1/8 .455
Fourth Quarter 37 34 1/4 .455
The December 31 closing price of the Company's Common Stock was
$34 1/2 in 1995 and $36 1/2 in 1996.
As of February 28, 1997, the Company had 76,189 holders of record of Common
Stock.
On July 13, 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 0.7 million shares in 1996, 4.2 million shares
in 1995 and 4.4 million shares in 1994.
32
<TABLE>
<CAPTION>
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
- ------- ------------------------------------
The selected consolidated financial data should be read in conjunction with the consolidated financial statements and the notes
thereto included elsewhere in this report.
Years Ended December 31
-----------------------
<S> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
(in thousands except per share data)
Operating results
Operating revenues $ 2,995,715 $ 3,006,553 $ 2,876,589 $ 2,895,383 $ 2,766,821
Net income $ 391,277 $ 372,604 $ 313,167 $ 346,496 $ 379,635
Earnings for common stock $ 381,668 $ 362,995 $ 303,558 $ 336,887 $ 379,045
Ratio of earnings to fixed charges 4.12 3.67 3.31 3.23 3.34
Per share data
Earnings per common share $ 2.66 $ 2.48 $ 2.03 $ 2.10 $ 2.36
Dividends declared per common share $ 1.835 $ 1.775 $ 1.715 $ 1.655 $ 1.595
Financial position
Total assets $ 8,369,201 $ 8,227,150 $ 8,211,163 $ 8,194,018 $ 7,706,201
Capitalization
Common stock equity $ 2,690,454 $ 2,574,743 $ 2,586,179 $ 2,632,116 $ 2,534,025
Preferred stock - redemption not required 143,801 143,801 143,801 143,801 143,801
Long-term debt, net 2,525,607 2,610,343 2,530,773 2,584,903 2,674,823
---------- ---------- ---------- ---------- ----------
Total capitalization $ 5,359,862 $ 5,328,887 $ 5,260,753 $ 5,360,820 $ 5,352,649
========== ========== ========== ========== ==========
33
</TABLE>
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):
1996 1995
Increase Increase
(Decrease) (Decrease)
Customer growth/changes
in usage patterns $ 87 $ 85
Sales to other utilities 34 46
Weather 4 75
NCEMC load loss (96) -
Price (36) (62)
Sales to Power Agency (4) (14)
____ _____
$(11) $130
===== =====
Sales to other utilities increased in both comparison periods as a
result of the Company's active pursuit of opportunities in
the wholesale market. A return of more normal weather in 1995
generated a $75 million increase in revenues as compared
to 1994 when the Company's service territory experienced unusually
mild weather. Beginning in January 1996, the
Company lost 200 megawatts of load from North Carolina Electric
Membership Corporation (NCEMC), resulting in a $96
million decrease in revenues. The price-related decrease in 1996
is primarily attributable to a decrease in the fuel cost
component of revenue. For 1995 as compared to 1994, approximately
half of the price-related 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
significantly affect net income due to a corresponding decrease in
amortization expense. For 1995 as compared to 1994, 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.
Operating Expenses
__________________
Fuel expense decreased in 1996 due to renegotiated coal contracts,
increased spot market coal purchases and the refunding
of over-recovered fuel costs. This decrease more than offset the
increase in fuel expense related to a 3.9% increase in
generation during 1996. Fuel expense increased in 1995 over 1994
primarily as a result of a 9.6% increase in generation.
Purchased power decreased in 1995 as compared to 1994 as a result
of a 1993 agreement with Power Agency. Pursuant
to this agreement, the Company's buyback percentage 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.
Operation and maintenance expenses decreased in 1996 as compared
to 1995, continuing a downward trend as a result of
the Company's ongoing cost reduction efforts. Partially offsetting
this decrease were storm-related expenses of
approximately $6 million incurred as a result of severe ice storms
experienced in early 1996 and the impact of Hurricane
Bertha striking the Company's service territory in July 1996.
34
Operation and maintenance expenses 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 expenses in that year.
Hurricane Fran struck significant portions of the Company's
service territory in September 1996. In December 1996, the
North Carolina Utilities Commission (NCUC) authorized the Company
to defer operation and maintenance expenses
associated with Hurricane Fran. See discussion of Hurricane Fran
in Other Matters.
The increase in depreciation and amortization expense in 1996
includes amortization of deferred Hurricane Fran costs of
approximately $4 million. Depreciation and amortization expense
decreased from 1994 to 1995 due to 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.
Other Income
____________
Other income, net, increased in 1996 primarily due to an
adjustment of $22.9 million to the unamortized balance of
abandonment costs related to the Harris Plant. See additional
discussion of the abandonment adjustment in the Retail Rate
Matters section of Other Matters. In 1995, other income, net,
decreased due to an increase in charitable contributions of
approximately $7 million and decreases in various income items,
none of which was individually significant.
Interest Charges
________________
Interest charges on long-term debt decreased from 1995 to 1996
primarily due to reductions of long-term debt in 1996. Also
contributing to the decrease were refinancings of long-term debt
with lower interest cost commercial paper borrowings
which are backed by the Company's long-term revolving credit
facilities. See discussion of credit facilities in Liquidity and
Capital Resources.
Other interest charges increased in 1995 primarily due to a $6
million interest accrual recorded in 1995 related to the 1995
NCUC Fuel Order.
LIQUIDITY AND CAPITAL RESOURCES
_______________________________
Cash Flow and Financing
_______________________
The net cash requirements of the Company arise primarily from
operational needs and support for investing activities,
including replacement or expansion of existing facilities and
construction to comply with pollution control laws and
regulations.
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 $4.3
billion in first mortgage bonds and an additional 29 million
shares of preferred stock at an assumed price of $100 per share
and a $6.63 annual dividend rate. The Company also has 10 million
authorized preference stock shares available for
issuance that are not subject to an earnings test.
In 1996, the Company entered into two new long-term revolving
credit facilities totaling $350 million, which support the
Company's commercial paper borrowings. In addition to these new
facilities, the Company has other long-term revolving
credit agreements totaling $235 million and a $100 million
short-term revolving credit agreement. The Company is required
to pay minimal annual commitment fees to maintain certain credit
facilities. Consistent with management's intent to
maintain up to $350 million of its commercial paper on a long-term
basis, and as supported by its long-term revolving credit
35
facilities, the Company has included in long-term debt $350
million of commercial paper outstanding as of December 31,
1996.
The proceeds from the issuance of commercial paper related to the
credit facilities mentioned above, and/or internally
generated funds, financed the redemption or retirement of
long-term debt totaling $453 million in 1996. External funding
requirements, which do not include early redemptions of long-term
debt or redemptions of preferred stock, are expected
to approximate $161 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 1997 or 1999.
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 & Poor's and A+ by Duff & Phelps. The
Company's commercial paper is currently rated P-1, A-1 and D-1
with Moody's Investors Service, Standard & Poor's and
Duff & Phelps, respectively.
The amount and timing of future sales of Company securities will
depend upon market conditions and the specific needs
of the Company. The Company may from time to time sell securities
beyond the amount needed to meet capital
requirements in order to allow for the early redemption of
outstanding issues of long-term debt, the redemption of preferred
stock, the reduction of short-term debt or for other corporate
purposes.
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 0.7
million shares in 1996, 4.2 million shares in 1995 and 4.4 million
shares in 1994.
Capital Requirements
____________________
Estimated capital requirements for the period 1997 through 1999
primarily reflect construction expenditures that will be
made to meet customer growth by adding generating, transmission
and distribution facilities as well as upgrading existing
facilities. The Company's capital requirements for those years are
reflected in the following table (in millions).
1997 1998 1999
____ ____ ____
Construction expenditures $ 365 $ 489 $ 401
Nuclear fuel expenditures 78 104 104
AFUDC (12) (20) (23)
Mandatory redemptions
of long-term debt 103 208 53
___ ___ ___
Total $ 534 $ 781 $ 535
=== === ===
This table includes Clean Air Act expenditures of approximately
$56 million and generating facility addition expenditures
of approximately $317 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 2002.
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 through 2009 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 1996, purchases under this
agreement totaled $60.9 million, including transmission
use charges. 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 $65.4 million in 1996.
36
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 $27 million. Other costs of such
purchases are primarily demand-related production expenses and
fuel and energy-related operation and maintenance
expenses. Purchases under the agreement with Power Agency totaled
$36.7 million in 1996.
OTHER MATTERS
_____________
Retail Rate Matters
____________________
A petition was filed in July 1996 by the Carolina Industrial Group
for Fair Utility Rates (CIGFUR) with the NCUC,
requesting that the NCUC conduct an investigation of the Company's
base rates or treat its petition as a complaint against
the Company. This petition alleged that the Company's return on
equity, which was authorized by the NCUC in the
Company's last general rate proceeding in 1988, and earnings are
too high. The Company filed a response to the petition
and Motion to Dismiss in July 1996, in which it argued that the
petition was without merit. As part of this docket, the
Company filed a proposal to accelerate amortization of certain
regulatory assets. In addition to proposing accelerated
amortization of the regulatory assets, the Company requested
approval to defer storm-related operation and maintenance
expenses associated with Hurricane Fran.
In December 1996, the NCUC approved the Company's proposal to
accelerate amortization of certain regulatory assets over
a three-year period beginning January 1, 1997. The accelerated
amortization of these regulatory assets will reduce income
by approximately $43 million, after tax, in each of the next three
years. The NCUC also authorized the Company to defer
operation and maintenance expenses associated with Hurricane Fran.
See discussion of Hurricane Fran below.
Additionally, the Company has filed for approval from the South
Carolina Public Service Commission (SCPSC) to
accelerate amortization of certain regulatory assets, including
plant abandonment costs related to the Harris Plant, over a
three-year period beginning January 1, 1997. This accelerated
amortization will reduce income by approximately $13
million, after tax, in each of the next three years. In
anticipation of the approval in 1997, the unamortized balance of
plant abandonment costs related to the Harris Plant was adjusted in 1996
to reflect the present value impact of the shorter
recovery period. This adjustment resulted in an increase in income
of approximately $14 million, after tax, in 1996. On
March 4, 1997, the SCPSC approved the implementation of the
proposed accounting adjustments.
In December 1996, the NCUC issued an order denying CIGFUR's
petition and stating that it tentatively finds no reasonable
grounds to proceed with CIGFUR's petition as a complaint. On
January 10, 1997, CIGFUR filed its Comments and Motion
for Reconsideration. On January 23, 1997, the Company filed its
response in opposition to CIGFUR's Comments and
Motion for Reconsideration. On February 6, 1997, the NCUC issued
an order denying CIGFUR's motion for
reconsideration. On February 25, 1997, CIGFUR filed a Notice of
Appeal of the NCUC's decision with the North Carolina
Court of Appeals. The Company cannot predict the outcome of this
matter.
Hurricane Fran
______________
Hurricane Fran struck significant portions of the Company's
service territory on September 5, 1996. Restoration of the
Company's system from hurricane-related damage resulted in
operation and maintenance expenses of approximately $40
million and capital expenditures of approximately $55 million. In
December 1996, the NCUC authorized the Company to
defer operation and maintenance expenses associated with Hurricane
Fran, with amortization over a 40-month period.
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. There are several
manufactured gas plant (MGP) sites to which the Company and
certain entities that were later merged into the Company had some
connection. In this regard, the Company, along with
37
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 Waste Management
(DWM), formerly the Division of Solid Waste Management, to
establish a uniform framework for addressing these MGP
sites. The investigation and remediation of specific MGP sites
will be addressed pursuant to one or more Administrative
Orders on Consent between the DWM and individual potentially
responsible party or parties. The Company continues to
investigate the identities of parties connected to individual MGP
sites, the relative relationships of the Company and other
parties to those sites and the degree to which the Company will
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.
The Company continues to carry a liability for the estimated costs
associated with certain remedial activities at several MGP
and other sites. This liability is not material to the financial
position of the Company. Due to uncertainty regarding the
extent of remedial action that will be required and questions of
liability, the cost of remedial activities at certain MGP sites
is not currently determinable. The Company cannot predict the
outcome of these matters.
The 1990 amendments to the Clean Air Act (Act) require substantial
reductions in sulfur dioxide and nitrogen oxide
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's (EPA) 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 oxide emissions.
The Company estimates that future capital costs necessary to
comply with Phase II of the Act will approximate $160
million. Increased operation 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. The EPA has recently proposed revisions to existing
air quality standards for Ozone and Particulate Matter. If these
standards are finalized as proposed, additional compliance
costs will be incurred. As plans for compliance with the Act's
requirements are subject to change, the amount required for
capital expenditures and for increased operation and maintenance
and fuel expenditures cannot be determined with certainty
at this time.
Nuclear
_______
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 include 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.
38
The Financial Accounting Standards Board (the 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. It is uncertain what impacts the
final statement may ultimately have on the Company's accounting
for nuclear decommissioning and other closure and
removal costs. The Board has announced that the effective date
would be no earlier than 1998.
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. In December of 1996, the
DOE notified the Company and other similarly situated utilities
that the agency anticipates that it will be unable to begin
acceptance of spent nuclear fuel by January 31, 1998. In January
of 1997, the Company, together with 35 other utilities,
filed a Joint Petition for Review with the United States Court of
Appeals requesting that the Court review the final decision
of the DOE and the DOE's failure to meet its unconditional
obligation under the Nuclear Waste Act.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 these licenses,
dry storage may be necessary.
Other Business
______________
The Company amended electric purchase power agreements related to
five plants owned by Cogentrix of North Carolina,
Inc., and Cogentrix Eastern Carolina Corporation (collectively
referred to as Cogentrix) in 1996. The amendments became
effective in late 1996 and permit the Company to dispatch the
output of these plants. In return, the Company gave up its
right to purchase two of Cogentrix's plants in 1997. As a result
of the amended agreements, the Company will save
approximately $30 million per year in energy costs during 1997
through 2002.
In 1994, the Company established CaroNet, Inc., which was
reorganized into CaroNet, LLC in 1996. CaroNet, LLC owns
a ten percent interest in BellSouth Carolinas PCS, L.P., a limited
partnership led by BellSouth Personal Communications,
Inc. (BellSouth). 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, provides high-quality mobile
communications. BellSouth is the general partner and handles
day-to-day management of the business. The Company
invested $50 million in CaroNet, LLC in anticipation of
infrastructure construction by BellSouth. Construction began in
1995 and by the end of 1996, service was available in all major
cities in the Carolinas. The bulk of infrastructure
construction is expected to be completed within two years. In
addition to participating in the limited partnership, CaroNet,
LLC is providing fiber optic network capacity to
telecommunications carriers in North Carolina and South Carolina.
In 1995, the Company established CaroHome, LLC, a
limited-liability company, to further the Company's investments in
affordable housing. These investments are designed to earn tax
credits while helping communities meet the needs for
affordable housing. The Company, principally through CaroHome,
LLC, has committed to invest $47 million in affordable
housing and anticipates investing up to a total of $125 million in
affordable housing by the year 2000.
In 1996, the Company established a wholly owned subsidiary,
CaroCapital, Inc., which purchased a minority equity interest
in Knowledge Builders, Inc. (KBI), an energy-management software
and control systems company. Investments in KBI
amounted to $9 million in 1996 with anticipation of total
investment through 2001 reaching $12 million, subject to the
terms and conditions of a Stock Purchase Agreement, which includes
certain sales and profitability targets.
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
39
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 Federal Energy
Regulatory Commission (FERC) to mandate wholesale
transfer, or wheeling, of power over the transmission lines of
other utilities. Since the Energy Act was passed, competition
in the wholesale electric utility industry has increased due to
greater participation by traditional electricity suppliers and
by non-traditional electricity suppliers, such as wholesale power
marketers and brokers, and by the trading of energy futures
contracts on commodities exchanges such as the New York Mercantile
Exchange and the Kansas City Board of Trade. This
increased competition could impact the Company's load forecasts,
plans for power supply and wholesale energy sales and
related revenues. The impact could vary depending on the extent to
which additional generation is built to compete in the
wholesale market, new opportunities are created for the Company to
expand its wholesale load or current wholesale
customers elect to purchase from other suppliers after existing
contracts expire. If the Company is not able to recover lost
revenues associated with any lost loads, there could be an adverse
impact on the Company's financial condition.
In early 1996, the FERC issued regulations for wholesale wheeling
of electric power through its rules on open access
transmission and stranded costs and on information systems and
standards of conduct (Orders 888 and 889). The rules
require all transmitting utilities to have on file an open access
transmission tariff, which should contain provisions for the
recovery of stranded costs. The rules also contain numerous other
items that could impact the sale of electric energy at the
wholesale level. The Company filed its open access transmission
tariff with the FERC in mid-1996. Shortly thereafter,
Power Agency filed with the FERC a Motion to Intervene and Protest
concerning the Company's tariff. Other entities also
filed protests. These protests challenge numerous aspects of the
Company's tariff and request that an evidentiary proceeding
be held. The FERC set the matter for hearing and set a discovery
and procedural schedule. The Company, the FERC staff
and most of the parties have agreed on a settlement-in-principle,
and by order dated January 16, 1997, the administrative
law judge suspended the procedural schedule until April 17, 1997,
pending a final settlement of the case.
The Energy Act prohibits the FERC from ordering retail wheeling
transmitting power on behalf of another producer to
an individual retail customer. Some states have changed or 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. These
changes or proposals elsewhere have taken differing forms and
included disparate elements. 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 ruled that it would not
convene a formal hearing to investigate the issue at that 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 indicated that they would monitor
other states' activities regarding generation competition and
allow interested parties to submit information on the subject.
In April 1996, the NCUC issued an order seeking comments regarding
the impact of retail competition on system reliability,
obligation to serve and stranded and ancillary costs. However, in
May 1996, the NCUC issued an order which stated that
FERC Orders 888 and 889 essentially restructure the wholesale
electric utility industry, and therefore may provide a new
focus for NCUC proceedings with respect to competition in the
electric industry. As a result, the NCUC concluded that all
parties should concentrate their efforts on examining the impacts
of the FERC orders and that the filing of comments
requested by the NCUC's April 1996 order should be extended
indefinitely. The NCUC also concluded that this docket
should be held in abeyance pending further order. The Company
cannot predict the outcome of the current debate regarding
retail wheeling; however, the implications of retail wheeling on
competition and the Company's financial condition could
be of a significantly greater magnitude than those associated with
wholesale wheeling, as discussed above.
On January 29, 1997, representatives of both houses of the North
Carolina General Assembly filed bills calling for the
establishment of a commission, comprised of representatives from
retail customers, electric companies and other interested
parties. The commission would be expected to file a report with
the 1999 North Carolina General Assembly that would
examine the numerous components of the electric industry and the
implications of making changes. On February 6, 1997,
representatives in the South Carolina General Assembly introduced
a bill calling for a transition to full competition in the
electric utility industry beginning in 1998. The Company cannot
predict the outcome of these matters.
Several pieces of legislation that concern the issue of retail
competition were introduced in Congress in 1996. One bill
mandated retail wheeling in all 50 states no later than December
15, 2000. As proposed, this bill would require states to
give all customers the right to choose their electric supplier. If
this choice were not implemented by the states, the bill
40
proposes that the FERC would be responsible for the
implementation. The other bills had various provisions concerning
retail competition and related topics. The Company anticipates
that this issue will continue to be debated by Congress
during 1997. 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 14% of the Company's 1996 operating
revenue. These long-term contracts will allow the
Company flexibility in managing its load and efficiently planning
its future resource requirements. 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.
In 1994, NCEMC issued two requests for proposals (RFPs) to provide
up to 675 MW of baseload power, which was being
purchased from the Company under the existing 1994 Power
Coordination Agreement (PCA), in blocks of up to 225 MW
(for a minimum of ten years each) beginning in 2001, 2002 and
2003. The Company responded to the RFPs and
negotiations the parties concerning power supply options continued
for several months. As a result of these negotiations,
in late 1996, the Company and NCEMC entered into a revised PCA
under which NCEMC will receive discounted capacity
in exchange for long-term commitments to the Company for its
supplemental power. As a result of this revised agreement,
the Company has extended beyond 2000 the terms of existing
capacity agreements to supply 225 MW from 2000 through
2010, an additional block of 225 MW from 2001 through 2004, and a
third block of 225 MW from 2002 through 2008. The
remainder of the NCEMC capacity provided by the Company, not
separately contracted for in the revised agreement, will
be billed at fixed rates through the year 2003, rather than at the
formula rates established in the original PCA. The FERC
has accepted the revised PCA. When NCEMC seeks future supplies,
the Company will respond and expects to remain
competitive in the pursuit and retention of wholesale load.
In August 1996, Power Agency notified the Company of its intention
to discontinue certain contractual purchases of power
from the Company effective September 1, 2001. Power Agency's
notice indicated that it intends to replace these contractual
obligations through purchases of capacity and energy and related
services in the open market, and that the Company will
be considered as a potential supplier for those purchases. Under
the 1981 Power Coordination Agreement, as amended,
between the Company and Power Agency, Power Agency can reduce its
purchases from the Company with an appropriate
five-year notice. The Company and Power Agency are currently
discussing the sufficiency of the August 1996 notice. The
Company cannot predict the outcome of this matter.
Under Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation,"
(SFAS-71), a utility defers certain costs of providing services if
the rates established by its regulators are designed to
recover those costs and the economic environment gives reasonable
assurance that those rates can be charged and collected
from customers. The continued applicability of SFAS-71 will
require further evaluation as competitive forces, deregulation
and restructuring take effect in the electric utility industry. In
the event the Company discontinued the application of SFAS-71,
amounts recorded under SFAS-71 as regulatory assets and
liabilities, would be eliminated. Additionally, the factors
discussed above could also result in an impairment of electric
utility plant assets as determined pursuant to Statement of
Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of."
41
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, 1996, 1995 and 1994 44
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1996, 1995 and 1994 45
Consolidated Balance Sheets as of December 31, 1996
and 1995 46-47
Consolidated Schedules of Capitalization as of
December 31, 1996 and 1995 48
Consolidated Statements of Retained Earnings for the
Years Ended December 31, 1996, 1995 and 1994 49
Consolidated Quarterly Financial Data (Unaudited) 49
Notes to Consolidated Financial Statements 50-61
Consolidated Financial Statement Schedules for the Years
Ended December 31, 1996, 1995 and 1994:
II- Valuation and Qualifying Accounts 52-64
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.
42
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, 1996 and 1995, and the related
consolidated statements of income, retained earnings, and cash flows for
each of the three years in the period ended December 31, 1996. 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, 1996 and 1995, and
the results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996 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, 1994, 1993 and 1992, and the related
consolidated statements of income, retained earnings and cash flows for
the years ended December 31, 1996 and 1992 (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, 1996, 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 10, 1997
43
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31
(In thousands except per share data) 1996 1995 1994
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues $ 2,995,715 $ 3,006,553 $2,876,589
- --------------------------------------------------------------------------------------------------------------------------------
Operating expenses
Fuel 515,050 529,812 510,138
Purchased Power 412,554 409,940 414,300
Other operation and maintenance 730,140 738,031 746,692
Depreciation and amortization 386,927 364,527 397,735
Taxes other than on income 140,479 144,043 138,540
Income tax expense 269,763 259,224 198,535
Harris Plant deferred costs, net 26,715 28,128 26,329
- --------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,481,628 2,473,705 2,432,269
- --------------------------------------------------------------------------------------------------------------------------------
Operating income 514,087 532,848 444,320
- --------------------------------------------------------------------------------------------------------------------------------
Other income
Allowance for equity funds used during construction 11 3,350 6,074
Income tax credit 13,847 18,541 9,425
Harris Plant carrying costs 7,299 8,297 9,754
Interest income 4,063 8,680 14,569
Other income, net (Note 6) 37,340 9,063 25,592
- --------------------------------------------------------------------------------------------------------------------------------
Total other income 62,560 47,931 65,414
- --------------------------------------------------------------------------------------------------------------------------------
Income before interest charges 576,647 580,779 509,734
- --------------------------------------------------------------------------------------------------------------------------------
Interest charges
Long-term debt 172,622 187,397 183,891
Other interest charges 19,155 25,896 16,119
Allowance for borrowed funds used during construction (6,407) (5,118) (3,443)
- ---------------------------------------------------------------------------------------------------------------------------------
Total interest charges, net 185,370 208,175 196,567
- ---------------------------------------------------------------------------------------------------------------------------------
Net income 391,277 372,604 313,167
- ---------------------------------------------------------------------------------------------------------------------------------
Preferred stock dividend requirements (9,609) (9,609) (9,609)
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings for common stock $ 381,668 $ 362,995 $ 303,558
- ---------------------------------------------------------------------------------------------------------------------------------
Average common shares outstanding (Notes 5 and 7) 143,621 146,232 149,614
- ---------------------------------------------------------------------------------------------------------------------------------
Earnings per common share $ 2.66 $ 2.48 $ 2.03
- ---------------------------------------------------------------------------------------------------------------------------------
Dividends declared per common share $ 1.835 $ 1.775 $ 1.715
- ---------------------------------------------------------------------------------------------------------------------------------
44
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS
Years ended December 31
(In thousands) 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating activities
Net income $ 391,277 $ 372,604 $ 313,167
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 446,508 446,662 473,481
Harris Plant deferred costs 19,416 19,831 16,575
Deferred income taxes 130,818 89,681 37,240
Investment tax credit (10,445) (9,344) (11,537)
Allowance for equity funds used during construction (11) (3,350) (6,074)
Deferred fuel cost (credit) (23,156) (849) 38,171
Net increase in receivables,inventories and prepaid expens (64,793) (77,849) (73,891)
Net increase(decrease)in payables and accrued expenses 8,365 (39,592) (46,771)
Miscellaneous 64,852 35,629 (4,935)
- ---------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 962,831 833,423 735,426
- ---------------------------------------------------------------------------------------------------------
Investing activities
Gross property additions (369,308) (266,400) (274,777)
Nuclear fuel additions (87,265) (77,346) (25,849)
Contributions to external decommissioning trust (30,683) (38,075) (21,625)
Contributions to retiree benefit trusts (24,700) (2,400) (18,917)
Allowance for equity funds used during construction 11 3,350 6,074
Miscellaneous (28,046) (28,515) (6,094)
- ---------------------------------------------------------------------------------------------------------
Net cash used in investing activities (539,991) (409,386) (341,188)
- ---------------------------------------------------------------------------------------------------------
Financing activities
Proceeds from issuance of long-term debt (Note 3) 350,000 180,713 318,211
Net increase (decrease) in short-term notes payable (8,858) 5,643 (7,900)
Retirement of long-term debt (467,810) (276,144) (268,380)
Purchase of Company common stock (Note 5) (28,902) (132,439) (114,717)
Dividends paid on common stock (261,204) (257,937) (255,206)
Dividends paid on preferred stock (9,614) (9,623) (9,614)
- ---------------------------------------------------------------------------------------------------------
Net cash used in financing activities (426,388) (489,787) (337,606)
- ---------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents (3,548) (65,750) 56,632
- ---------------------------------------------------------------------------------------------------------
Cash and cash equivalents at beginning of year 14,489 80,239 23,607
- ---------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $ 10,941 $ 14,489 $ 80,239
=========================================================================================================
Supplemental disclosures of cash flow information
Cash paid during the year - interest $ 194,391 $ 203,296 $ 188,754
income taxes $ 141,350 $ 177,163 $ 180,759
45
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
Assets
December 31
(In thousands) 1996 1995
- -------------------------------------------------------------------------------------
<S> <C> <C>
Electric utility plant
Electric utility plant in service $ 9,783,442 $ 9,440,442
Accumulated depreciation (3,796,645) (3,493,153)
- -------------------------------------------------------------------------------------
Electric utility plant in service, net 5,986,797 5,947,289
Held for future use 12,127 13,304
Construction work in progress 196,623 179,260
Nuclear fuel, net of amortization 204,372 188,655
- -------------------------------------------------------------------------------------
Total electric utility plant, net 6,399,919 6,328,508
- -------------------------------------------------------------------------------------
Current assets
Cash and cash equivalents 10,941 14,489
Accounts receivable 384,318 364,536
Fuel 60,369 53,654
Materials and supplies 122,809 121,227
Prepayments 65,794 59,918
Other current assets 27,808 27,834
- -------------------------------------------------------------------------------------
Total current assets 672,039 641,658
- -------------------------------------------------------------------------------------
Deferred debits and other assets (Note 6)
Income taxes recoverable through future rates 384,336 387,150
Abandonment costs 65,863 57,120
Harris Plant deferred costs 83,397 107,992
Unamortized debt expense 69,956 58,404
Miscellaneous other property and investments 489,334 475,564
Other assets and deferred debits 204,357 170,754
- -------------------------------------------------------------------------------------
Total deferred debits and other assets 1,297,243 1,256,984
- -------------------------------------------------------------------------------------
Total assets $ 8,369,201 $ 8,227,150
- -------------------------------------------------------------------------------------
See notes to consolidated financial statements.
46
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS (continued)
Capitalization and liabilities
December 31
(In thousands) 1996 1995
- --------------------------------------------------------------------------------------
<S> <C> <C>
Capitalization (see consolidated
schedules of capitalization)
Common stock equity $ 2,690,454 $ 2,574,743
Preferred stock - redemption not required 143,801 143,801
Long-term debt, net 2,525,607 2,610,343
- --------------------------------------------------------------------------------------
Total capitalization 5,359,862 5,328,887
- --------------------------------------------------------------------------------------
Current liabilities
Current portion of long-term debt 103,345 105,755
Notes payable (principally commercial paper) 64,885 73,743
Accounts payable 375,216 309,294
Interest accrued 39,436 48,441
Dividends declared 73,469 71,285
Deferred fuel credit 4,339 27,495
Other current liabilities 74,668 81,676
- --------------------------------------------------------------------------------------
Total current liabilities 735,358 717,689
- --------------------------------------------------------------------------------------
Deferred credits and other liabilities
Accumulated deferred income taxes 1,827,693 1,716,835
Accumulated deferred investment tax credits 232,262 242,707
Other liabilities and deferred credits 214,026 221,032
- --------------------------------------------------------------------------------------
Total deferred credits and other
liabilities 2,273,981 2,180,574
- --------------------------------------------------------------------------------------
Commitments and contingencies (Note 11)
Total capitalization and liabilities $ 8,369,201 $ 8,227,150
- --------------------------------------------------------------------------------------
See notes to consolidated financial statements.
47
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED SCHEDULES OF CAPITALIZATION
December 31
(Dollars in thousands except per share data) 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Common stock equity
Common stock without par value, 200,000,000 shares authorized; outstanding,
151,415,722 shares at December 31, 1996 and 152,102,922 at December 31, 1995 (Note 5) $ 1,366,100 $ 1,381,496
Unearned ESOP common stock (Note 7) (178,514) (191,341)
Capital stock issuance expense (790) (790)
Retained earnings (Note 5) 1,503,658 1,385,378
- ---------------------------------------------------------------------------------------------------------------------------------
Total common stock equity $ 2,690,454 $ 2,574,743
- ---------------------------------------------------------------------------------------------------------------------------------
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, 1996)
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, 1996)
First mortgage bonds:
5.125% due 1996 $ - $ 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
6.750% due 2002 100,000 100,000
7.750% to 8.125% due 2003 - 122,626
5.875% and 7.875% due 2004 300,000 300,000
6.875% to 9.00% due 2021 - 2023 500,000 725,000
First mortgage bonds - secured medium-term notes:
4.85% and 7.90% due 1996 - 75,000
7.75% due 1997 60,000 60,000
5.00% and 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
3.60% due 2024 122,600 122,600
- ---------------------------------------------------------------------------------------------------------------------------------
Total first mortgage bonds 1,621,130 2,073,756
- ---------------------------------------------------------------------------------------------------------------------------------
Other long-term debt:
Pollution control obligations backed by letter of credit, 3.57% to 5.05% due 2014 - 2017 442,000 442,000
Other pollution control obligations, 4.25% due 2019 55,640 55,640
Unsecured subordinated debentures, 8.55% due 2025 125,000 125,000
Commercial paper reclassified to long-term debt (Note 3) 350,000 -
Miscellaneous notes 56,858 48,157
- ---------------------------------------------------------------------------------------------------------------------------------
Total other long-term debt 1,029,498 670,797
- ---------------------------------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net (21,675) (28,455)
Current portion of long-term debt (103,346) (105,755)
- ---------------------------------------------------------------------------------------------------------------------------------
Total long-term debt, net $ 2,525,607 $ 2,610,343
- ---------------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 5,359,862 $ 5,328,887
- ---------------------------------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
48
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Years ended December 31
(In thousands) 1996 1995 1994
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Retained earnings at beginning of year $ 1,385,378 $ 1,280,960 $ 1,231,354
Net income 391,277 372,604 313,167
Preferred stock dividends at stated rates (9,609) (9,609) (9,609)
Common stock dividends at annual rate of $1.835 per share in 1996,
$1.775 in 1995 and $1.715 in 1994 (Note 5) (263,388) (258,577) (256,021)
Other adjustments - - 2,069
- -------------------------------------------------------------------------------------------------------------------------------
Retained earnings at end of year $ 1,503,658 $ 1,385,378 $ 1,280,960
- -------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
First Quarter Second Quarter Third Quarter Fourth Quarter
(In thousands except
per share data) 1996 1995 1996 1995 1996 1995 1996 1995
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $ 783,585 $ 728,238 $ 685,968 $ 681,965 $ 831,590 $ 875,500 $ 694,572 $ 720,850
Operating income $ 154,428 $ 136,259 $ 94,966 $ 93,426 $ 164,125 $ 194,440 $ 100,568 $ 108,723
Net income $ 118,346 $ 98,033 $ 62,656 $ 55,962 $ 129,159 $ 151,905 $ 81,116 $ 66,704
Common stock data:
Earnings per common share $ .81 $ .65 $ .42 $ .36 $ .88 $ 1.02 $ .55 $ .45
Dividend paid per common
share $ .455 $ .440 $ .455 $ .440 $ .455 $ .440 $ .455 $ .440
Price per share - high $ 38 3/8 $ 28 5/8 $ 38 $ 30 3/4 $ 38 1/4 $ 34 $ 37 $ 34 1/2
low $ 34 1/2 $ 26 3/8 $ 34 7/8 $ 26 3/4 $ 34 1/8 $ 29 1/2 $ 34 1/4 $ 32 3/8
See notes to consolidated financial statements.
49
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
The Company is a public service corporation primarily 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 1995 and 1994 have been reclassified to conform to the 1996
presentation, with no effect on previously reported net income or common
stock equity.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Principles of Consolidation
The consolidated financial statements include the activities of the
Company's wholly owned subsidiaries. These subsidiaries have investments
in areas such as communications technology, energy-management software
and affordable housing. Significant intercompany balances and
transactions have been eliminated.
B. Use of Estimates and Assumptions
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).
1996 1995
--------- ---------
Production plant $ 6,161.4 $ 6,014.1
Transmission plant 940.0 912.7
Distribution plant 2,178.6 2,037.6
General plant and other 503.4 476.0
--------- ---------
Electric utility plant in service $ 9,783.4 $ 9,440.4
========= =========
As prescribed in regulatory uniform systems of accounts, an allowance
for the cost of borrowed and equity funds used to finance electric
utility plant construction (AFUDC) 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 5.8% in 1996, 8.0% in 1995 and
8.4% in 1994.
50
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 3.9% in 1996 and 3.8% in 1995 and 1994.
Depreciation expense totaled $363.2 million in 1996, $344.0 million in
1995 and $335.1 million in 1994. Depreciation and amortization expense
also includes amortization of plant abandonment costs (see Note 6C) and
amortization of hurricane-related deferred costs (see Note 6D).
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 include 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 $33.1 million in 1996, $31.2 million in 1995 and $29.5 million in
1994.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were $326.0 million at December 31, 1996, and $288.4
million at December 31, 1995. 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, totaled $145.3 million at
December 31, 1996, and $110.2 million at December 31, 1995. Trust
earnings, which increase the trust balance with a corresponding increase
in accumulated decommissioning, were $4.5 million in 1996 and 1995 and
$1.5 million in 1994. 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 (the 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.
It is uncertain what impacts the
51
final statement may ultimately have on the Company's accounting for nuclear
decommissioning and other closure and removal costs. The Board has announced
that the effective date would be no earlier than 1998.
F. Other Policies
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.
Other property and investments are stated principally at cost. The
Company maintains an allowance for doubtful accounts receivable, which
totaled $3.7 million at December 31, 1996, and $2.3 million at December
31, 1995. Fuel inventory and materials and supplies inventory 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 (see Note 6B). 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.
3. SHORT-TERM NOTES AND REVOLVING CREDIT FACILITIES
At December 31, 1996, and 1995, the Company's short-term debt balances
were $64.9 million and $73.7 million, respectively. Additionally, at
December 31, 1996, the Company had $350 million of commercial paper
classified as long-term debt (see below). The weighted-average interest
rates of these borrowings were 5.41% at December 31, 1996, and 5.86% at
December 31, 1995.
In 1996, the Company entered into two new long-term revolving credit
facilities totaling $350 million, which support the Company's commercial
paper borrowings. In addition to these new facilities, the Company has
other long-term revolving credit agreements totaling $235 million and a
$100 million short-term revolving credit agreement. The Company is
required to pay minimal annual commitment fees to maintain certain
credit facilities. Consistent with management's intent to maintain up to
$350 million of its commercial paper on a long-term basis, and as
supported by its long-term revolving credit facilities, the Company has
included in long-term debt $350 million of commercial paper outstanding
as of December 31, 1996.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts of cash and cash equivalents and notes payable
approximate fair value due to the short maturities of these instruments.
The carrying amount of the Company's long-term debt was $2.67 billion at
December 31, 1996, and $2.76 billion at December 31, 1995. The
estimated fair value of this debt, which was obtained from an
independent pricing service, was $2.67 billion at December 31, 1996, and
$2.85 billion at December 31, 1995. 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 0.7 million shares in 1996, 4.2 million shares in 1995 and
4.4 million shares in 1994.
52
At December 31, 1996, 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 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, 1996, there were no significant
restrictions on the use
of retained earnings.
As of December 31, 1996, long-term debt maturities for the years 1997
through 2000 are $103 million, $208 million, $53 million and $197
million, respectively. There are no long-term debt maturities scheduled
for the year 2001.
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.
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, these bonds are classified as
long-term debt in the Consolidated Balance Sheets.
6. REGULATORY MATTERS
A. Regulatory Assets
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," (SFAS-71). Accordingly, the
Company records certain assets 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, 1996,
the balances of the Company's regulatory assets were as follows
(in millions):
Income taxes recoverable through future rates $ 384.3
Harris Plant deferred costs 83.4
Abandonment costs 65.9
Loss on reacquired debt
(included in unamortized debt expense) 63.0
Items included in other assets and deferred debits:
Deferred DOE enrichment facilities-related costs 54.7
Deferred hurricane-related costs 35.1
Emission allowance carrying costs 11.8
Deferred purchased capacity costs - Mayo Plant 1.9
-------
Total $ 700.1
=======
See Note 11C for additional discussion of SFAS-71.
B. Retail Rate Matters
A petition was filed in July 1996 by the Carolina Industrial Group for
Fair Utility Rates (CIGFUR) with the NCUC requesting that the NCUC
conduct an investigation of the Company's base rates or treat its
petition as a complaint against the Company. This petition alleged that
the Company's return on equity, which was authorized by the NCUC in the
Company's last general rate proceeding in 1988, and earnings are too
high. The Company filed a response to the petition and Motion to Dismiss
in July 1996, in which it argued that the petition was without merit. As
part of this docket, the Company
53
filed a proposal to accelerate amortization of certain regulatory assets. In
addition to proposing accelerated amortization of the regulatory assets, the
Company requested approval to defer storm-related operation and maintenance
expenses associated with Hurricane Fran. (See discussion of Hurricane Fran in
Note 6D.)
In December 1996, the NCUC approved the Company's proposal to accelerate
amortization of certain regulatory assets over a three-year period
beginning January 1, 1997. The accelerated amortization of these
regulatory assets will reduce income by approximately $43 million, after
tax, in each of the next three years. The NCUC also authorized the
Company to defer operation and maintenance expenses associated with
Hurricane Fran.
Additionally, the Company has filed for, and expects to receive,
approval from the SCPSC to accelerate amortization of certain regulatory
assets, including plant abandonment costs related to the Harris Plant,
over a three-year period beginning January 1, 1997. This accelerated
amortization will reduce income by approximately $13 million, after
tax, in each of the next three years. In anticipation of the approval in
1997, the unamortized balance of plant abandonment costs related to the
Harris Plant was adjusted in 1996 to reflect the present value impact of
the shorter recovery period. This adjustment resulted in an increase in
income of approximately $14 million, after tax, in 1996.
The North Carolina retail and South Carolina retail jurisdictional
balances at December 31, 1996, for the regulatory assets subject to
accelerated amortization, include loss on reacquired debt of $50
million, emission allowance carrying costs of $12 million, certain
income taxes recoverable through future rates of $101 million and plant
abandonment costs of $45 million.
In December 1996, the NCUC issued an order denying CIGFUR's petition and
stating that it tentatively finds no reasonable grounds to proceed with
CIGFUR's petition as a complaint. On January 10, 1997, CIGFUR filed its
Comments and Motion for Reconsideration. On January 23, 1997, the
Company filed its response in opposition to CIGFUR's Comments and Motion
for Reconsideration. The Company cannot predict the outcome of this
matter.
C. 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 wholesale jurisdictions and in
1999 for the South Carolina retail jurisdiction, assuming SCPSC approval
of accelerated amortization as discussed in Note 6B.
Amortization of plant abandonment costs is included in depreciation and
amortization expense and totaled $17.6 million in 1996, $18.3 million in
1995 and $60.5 million in 1994. The unamortized balances of plant
abandonment costs are reported at the present value of future recoveries
of these costs. The associated accretion of the present value was $26.4
million in 1996 (which includes a $22.9 million adjustment to the
unamortized balance - see Note 6B), $4.3 million in 1995 and $6.6
million in 1994, 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 11A), the unamortized balance of Harris Plant
deferred costs was $15.6 million at December 31, 1996, and $38.4 million
at December 31, 1995.
54
D. Hurricane-Related Deferred Costs
Hurricane Fran struck significant portions of the Company's service
territory on September 5, 1996. Restoration of the Company's system from
hurricane-related damage resulted in operation and maintenance expenses
of approximately $40 million and capital expenditures of approximately
$55 million. In December 1996, the NCUC authorized the Company to defer
operation and maintenance expenses associated with Hurricane Fran, with
amortization over a 40-month period. Amortization of deferred hurricane
costs is included in depreciation and amortization expense and totaled
approximately $4 million in 1996.
7. EMPLOYEE STOCK OWNERSHIP PLAN
The Company sponsors the Stock Purchase-Savings Plan (SPSP) for which
all full-time employees and certain part-time employees are eligible.
The SPSP, which has Company match and incentive goal features,
encourages systematic savings by employees and provides a method of
acquiring Company common stock and other diverse investments. The SPSP,
as amended in 1989, is an employee stock ownership plan (ESOP) that can
enter into acquisition loans 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. 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 8,114,328 ESOP suspense shares at December 31, 1996, with a
fair value of $296.2 million. ESOP shares allocated to plan participants
totaled 14,861,249 at December 31, 1996. 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 note receivable from
the SPSP Trustee is included in the determination of unearned ESOP
common stock, which reduces common stock equity. ESOP shares that have
not been committed to be released to participants' accounts are not
considered outstanding for the determination of earnings per common
share. Interest income on the note receivable and dividends on
unallocated ESOP shares are not recognized for financial statement
purposes.
8. 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):
1996 1995 1994
----------- ----------- ---------
Actual return on plan assets $ (76,347) $ (103,381) $ 4,897
Variance from expected return,
deferred 27,056 59,425 (47,219)
----------- ----------- ---------
Expected return on plan assets (49,291) (43,956) (42,322)
Service cost 19,257 16,344 19,686
Interest cost on projected benefit
obligation 39,505 35,592 35,108
Net amortization 466 (3,580) 831
----------- ----------- ---------
Net periodic pension cost $ 9,937 $ 4,400 $ 13,303
=========== =========== =========
55
Reconciliations of the funded status of the pension plan at December 31
are (in thousands):
1996 1995
--------- ---------
Actuarial present value of benefits for services
rendered to date:
Accumulated benefits based on salaries to date,
including vested benefits of $415.1 million
for 1996 and $345.1 million for 1995 $ 452,552 $ 392,768
Additional benefits based on estimated future
salary levels 106,136 130,167
--------- ---------
Projected benefit obligation 558,688 522,935
Fair market value of plan assets, invested
primarily in equity and fixed-income
securities 683,508 610,278
--------- ---------
Funded status 124,820 87,343
Unrecognized prior service costs 8,023 8,747
Unrecognized actuarial gain (155,145) (124,383)
Unrecognized transition obligation, amortized
over 18.5 years beginning January 1, 1987 899 1,005
--------- ---------
Accrued pension costs recognized in the
Consolidated Balance Sheets $ (21,403) $ (27,288)
========= =========
The assumptions used to measure the projected benefit obligation are:
1996 1995
------ ------
Weighted-average discount rate 7.75% 7.75%
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 9.25% in 1996 and 9.00% in
1995 and 1994.
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):
1996 1995 1994
--------- --------- -------
Actual return on plan assets $ (2,656) $ (2,514) $ 42
Variance from expected return,
deferred 726 1,420 (682)
--------- --------- -------
Expected return on plan assets (1,930) (1,094) (640)
Service cost 8,412 7,498 8,039
Interest cost on accumulated benefit
obligation 10,629 10,595 9,463
Net amortization 5,889 5,530 5,966
--------- --------- -------
Net periodic OPEB cost $ 23,000 $ 22,529 $ 22,828
========= ========= =======
56
Reconciliations of the funded status of the OPEB plans at December 31
are (in thousands):
1996 1995
---------- ----------
Actuarial present value of benefits
for services rendered to date:
Current retires $ 60,534 $ 59,809
Active employees eligible to retire 19,607 17,942
Active employees not eligible to retire 84,346 68,819
---------- ----------
Accumulated postretirement
benefit obligation 164,487 146,570
Fair market value of plan assets,
invested primarily in equity and
fixed-income securities 28,799 20,869
--------- ----------
Funded status (135,688) (125,701)
Unrecognized actuarial gain (11,339) (15,132)
Unrecognized transition obligation,
amortized over 20 years beginning
January 1, 1993 94,225 101,414
---------- ----------
Accrued OPEB costs recognized in the
Consolidated Balance Sheets $ (52,802) $ (39,419)
========== ==========
The assumptions used to measure the accumulated postretirement benefit
obligation are:
1996 1995
----- -----
Weighted-average discount rate 7.75% 7.75%
Initial medical cost trend rate for
pre-Medicare benefits 7.70% 8.40%
Initial medical cost trend rate for
post-Medicare benefits 7.50% 8.20%
Ultimate medical cost trend rate 5.25% 5.25%
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 9.25% in 1996 and 9.00% in 1995 and 1994.
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 1996 would increase by $2.8 million, and the
accumulated postretirement benefit obligation at December 31, 1996,
would increase by $18.6 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.
57
9. 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):
1996 1995
------------ ------------
Accelerated depreciation and property
cost differences $ 1,734,001 $ 1,613,752
Deferred costs, net 122,580 133,139
Miscellaneous other temporary
differences, net 23 (12,487)
------------ ------------
Net accumulated deferred income
tax liability $ 1,856,604 $ 1,734,404
============ ============
Total deferred income tax liabilities were $2.30 billion and $2.17
billion at December 31, 1996, and 1995, respectively. Total deferred
income tax assets were $439 million at December 31, 1996, and $434
million at December 31, 1995.
A reconciliation of the Company's effective income tax rate to the
statutory federal income tax rate is as follows:
1996 1995 1994
----- ----- -----
Effective income tax rate 39.5% 39.2% 37.6%
State income taxes, net of federal
income tax benefit (4.9) (5.0) (5.5)
Investment tax credit amortization 1.6 1.6 2.4
Other differences, net (1.2) (0.8) 0.5
----- ----- -----
Statutory federal income tax rate 35.0% 35.0% 35.0%
===== ===== =====
The provisions for income tax expense are comprised of (in thousands):
1996 1995 1994
----------- ----------- -----------
Included in Operating Expenses
Income tax expense (credit)
Current - federal $ 132,570 $ 143,440 $ 143,461
state 29,380 41,826 39,185
Deferred - federal 97,303 75,442 23,926
state 20,955 7,860 3,500
Investment tax credit (10,445) (9,344) (11,537)
----------- ----------- -----------
Subtotal 269,763 259,224 198,535
Harris Plant deferred costs
Investment tax credit (286) (297) (297)
----------- ----------- -----------
Total included in operating
expenses 269,477 258,927 198,238
----------- ----------- -----------
Included in Other Income
Income tax expense (credit)
Current - federal (22,382) (20,669) (15,732)
state (4,025) (4,251) (3,507)
Deferred - federal 10,286 5,254 8,065
state 2,274 1,125 1,749
----------- ----------- -----------
Total included in other income (13,847) (18,541) (9,425)
----------- ----------- -----------
Total income tax expense $ 255,630 $ 240,386 $ 188,813
=========== =========== ===========
58
10. 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, 1996 (dollars in
millions):
Company
Megawatt Ownership Plant Accumulated Under
Facility Capability Interest Investment Depreciation Construction
- ------------ ---------- --------- ---------- ------------ ------------
Mayo Plant 745 83.83% $ 451.3 169.1 $ 0.3
Harris Plant 860 83.83% $ 3,011.1 $ 840.3 $ 12.3
Brunswick Plant 1,521 81.67% $ 1,395.2 $ 814.2 $ 23.0
Roxboro Unit No.4 700 87.06% $ 230.4 $ 97.1 $ 1.4
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.
11. 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. Under the terms of the 1993 agreement, the Company
increased the amount of capacity and energy purchased from Power
Agency's ownership interest in the Harris Plant, and the buyback period
was extended six years through 2007. The estimated minimum annual
payments for these purchases, which reflect capital-related capacity
costs, total approximately $27 million. Other costs of such purchases
are primarily demand-related production expenses, fuel and energy-
related operation and maintenance expenses. Contractual purchases from
the Mayo and Harris plants totaled $36.7 million for 1996, $39.4 million
for 1995 and $60.4 million for 1994. 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,
1996, and 1995, the Company had deferred purchased capacity costs,
including carrying costs accrued on the deferred balances, of $69.7
million and $72.7 million, respectively. Increased purchases resulting
from the 1993 agreement with Power Agency, which were approximately $13
million for 1996, $10 million for 1995 and $21 million for 1994, 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
59
Duke, representing capital-related capacity costs. Other 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, from Rockport and Duke, respectively, totaled $60.9 million and
$65.4 million for 1996, $61.8 million and $63.8 million for 1995 and
$61.9 million and $62.9 million for 1994. The Rockport agreement expires
in late-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 $17 million in the event that losses at
insured facilities exceed premiums, reserves, reinsurance and other NML
resources, which are at present more than $857 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 $1.4 million at Brunswick Unit No. 1, $1.3 million at
Brunswick Unit No. 2, $1.5 million at the Harris Plant and $1.3 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 $6.2 million
with respect to the incremental replacement power costs coverage and
$26.4 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 $2.5 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. Applicability of SFAS-71
The continued applicability of SFAS-71 (see Note 6A) will require
further evaluation as competitive forces, deregulation and restructuring
take effect in the electric utility industry. In the event the Company
discontinued the application of SFAS-71, amounts recorded under SFAS-71
as regulatory assets and liabilities, would be eliminated. Additionally,
the factors discussed above could also result in an impairment of
electric utility plant assets as determined pursuant to Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
60
D. 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. There are several manufactured gas plant (MGP)
sites to which the Company and certain entities that were later merged
into the Company 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 Waste Management (DWM), formerly the Division of
Solid Waste Management, to establish a uniform framework for addressing
these MGP sites. The investigation and remediation of specific MGP sites
will be addressed pursuant to one or more Administrative Orders on
Consent between the DWM and individual potentially responsible party or
parties. The Company continues to investigate the identities of parties
connected to individual MGP sites, the relative relationships of the
Company and other parties to those sites and the degree to which the
Company will 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.
The Company continues to carry a liability for the estimated costs
associated with certain remedial activities at several MGP and other
sites. This liability is not material to the financial position of the
Company. Due to uncertainty regarding the extent of remedial action that
will be required and questions of liability, the cost of remedial
activities at certain MGP sites is not currently determinable. The
Company cannot predict the outcome of these matters.
(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.
(3) 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.
61
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Year Ended December 31, 1996
- -----------------------------------------------------------------------------------------------------------
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 Account Reserves Period
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Reserves deducted from
related assets on the
balance sheet:
Uncollectible accounts $ 2,323,808 $ 8,525,513 $ - $ 7,159,538 $ 3,689,783
=========== =========== ============ ========== ===========
Reserves other than those
deducted from assets on
the balance sheet:
Injuries and damages $ 1,270,881 $ 1,033,504 $ - $ 1,026,497 $ 1,277,888
=========== =========== ============ ========== ===========
Reserve for possible coal
mine investment losses $ 7,797,250 $ - $ - $ 172,242 $ 7,625,008
=========== =========== ============ ========== ===========
Reserve for employee
retirement and
compensation plans $ 91,779,866 $ 41,816,846 $ - $ 26,027,305 $ 107,569,407
=========== =========== ============ ========== ===========
Reserve for environmental
investigation and
remediation costs $ 1,906,730 $ - $ - $ 90,821 1,815,909
=========== =========== ============ ========== ===========
62
</TABLE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
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 Account Reserves Period
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Reserves deducted from
related assets on the
balance sheet:
Uncollectible accounts $ 2,520,785 $ 4,622,288 $ - $ 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 $ - $ 1,507,998 $ 1,270,881
=========== ========== ============ ========== ==========
Reserve for possible coal
mine investment losses $ 8,004,970 $ - $ - $ 207,720 $ 7,797,250
=========== ========== ============ ========== ==========
Reserve for employee
retirement and
compensation plans $ 88,015,413 $ 36,288,787 $ - $ 32,524,334 $ 91,779,866
=========== ========== ============ ========== ==========
Reserve for environmental
investigation and
remediation costs $ 1,976,716 $ - $ - $ 69,986 $ 1,906,730
=========== ========== ============ ========== ==========
63
</TABLE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
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 Account Reserves Period
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Reserves deducted from
related assets on the
balance sheet:
Uncollectible accounts $ 2,305,141 $ 5,151,386 $ - $ 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 $ - $ 862,285 $ 2,212,161
=========== =========== ============ ========== ==========
Property insurance
reserve $ 23,217,772 $ (23,217,772 $ - $ - $ -
=========== =========== ============ ========== ==========
Reserve for possible coal
mine investment losses $ 8,406,753 $ - $ - $ 401,783 $ 8,004,970
=========== =========== ============ ========== ==========
Reserve for employee
retirement and
compensation plans $ 65,626,193 $ 46,044,119 $ - $ 23,654,899 $ 88,015,413
=========== =========== ============ ========== ==========
Reserve for environmental
investigation and
remediation costs $ - $ 1,976,716 $ - $ - $ 1,976,716
=========== =========== ============ ========== ==========
64
</TABLE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
__________________________________________________________
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
___________________________________________________________
a) Information on the Company's directors is set
forth in the Company's 1997 definitive proxy statement
dated March 31, 1997, 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 1997 definitive proxy statement dated
March 31, 1997, 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 (i) Wachovia
Bank of North Carolina, N.A., Post Office Box 3099,
Winston-Salem, North Carolina 27102 which as of December 31, 1996,
owned 8,791,601 shares of Common Stock (5.8% of Class)
as Trustee of the Company's Stock Purchase-Savings Plan
and (ii) The Colonial Group, Inc., One Financial Center,
Boston, MA 02111, which as of December 31, 1996, owned 30,000
shares of the Company's Serial Preferred Stock, $7.72
Series (6% of Class).
b) Information on security ownership of the
Company's management is set forth in the Company's 1997
definitive proxy statement dated March 31, 1997, and incorporated
by reference herein.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
_______________________________________________________
Information on certain relationships and related
transactions is set forth in the Company's 1997 definitive
proxy statement dated March 31, 1997, and incorporated by
reference herein.
65
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;
66
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 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 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).
67
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. 18 Letter re: Change in Accounting Principles
Exhibit No. 23(a) Consent of Deloitte & Touche LLP
Exhibit No. 23(b) Consent of William D. Johnson
Exhibit No. 27 Financial Data Schedule
*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.
68
b) Reports on Form 8-K filed during or with respect to the
last quarter of 1996 and the portion of the first quarter
of 1997 prior to the filing of this 10-K:
Date of Report Item Reported
______________ _____________
NONE
69
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 26th day of March,
1997.
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/ William Cavanaugh III
_____________________________ Principal Executive
(William Cavanaugh III, Officer and Director
President and Chief Executive
Officer)
/s/ Glenn E. Harder
_____________________________ Principal Financial
(Glenn E. Harder Officer
Executive Vice President
and Chief Financial Officer)
/s/ Bonnie V. Hancock
_____________________________ Principal Accounting
(Bonnie V. Hancock Officer
Vice President and Controller)
/s/ Sherwood H. Smith, Jr.
_____________________________ Director March 26, 1997
(Sherwood H. Smith, Jr.,
Chairman)
/s/ Edwin B. Borden
_____________________________ Director
(Edwin B. Borden)
/s/ Felton J. Capel
_____________________________ Director
(Felton J. Capel)
/s/ Charles W. Coker
_____________________________ Director
(Charles W. Coker)
70
Signature Title Date
_________ _____ ____
/s/ Richard L. Daugherty
_____________________________ Director
(Richard L. Daugherty)
/s/ Robert L. Jones
_____________________________ Director
(Robert L. Jones)
/s/ Estell C. Lee Director
_____________________________ March 26, 1997
(Estell C. Lee)
/s/ William O. McCoy
_____________________________ Director
(William O. McCoy)
/s/ J. Tylee Wilson
_____________________________ Director
(J. Tylee Wilson)
71
<TABLE>
<CAPTION>
EXHIBIT 12
CAROLINA POWER & LIGHT COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED DIVIDENDS COMBINED
AND RATIO OF EARNINGS TO FIXED CHARGES
--------------------------------------------
Twelve Months Ended December 31,
--------------------------------------------
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Earnings, as defined:
Net income......................................$ 391,277 $ 372,604 $ 313,167 $ 346,496 $ 379,635
Fixed charges, as below......................... 204,593 226,833 213,821 237,098 253,215
Income taxes, as below.......................... 247,405 232,046 180,518 181,653 211,717
-------------- -------------- -------------- -------------- -----------
Total earnings, as defined....................$ 843,275 $ 831,483 $ 707,506 $ 765,247 $ 844,567
============== ============== ============== ============== ===========
Fixed Charges, as defined:
Interest on long-term debt......................$ 172,622 $ 187,397 $ 183,891 $ 205,182 $ 223,158
Other interest.................................. 19,155 25,896 16,119 16,419 15,717
Imputed interest factor in rentals-charged
principally to operating expenses............. 12,816 13,540 13,811 15,497 14,340
-------------- -------------- -------------- -------------- -----------
Total fixed charges, as defined...............$ 204,593 $ 226,833 $ 213,821 $ 237,098 $ 253,215
============== ============== ============== ============== ===========
Earnings Before Income Taxes......................$ 638,682 $ 604,650 $ 493,685 $ 528,149 $ 591,352
============== ============== ============== ============== ===========
Ratio of Earnings Before Income Taxes to Net Income...... 1.63 1.62 1.58 1.52 1.56
Income Taxes:
Included in operating expenses..................$ 269,477 $ 258,927 $ 198,238 $ 189,535 $ 210,266
Included in other income:
Income tax expense (credit)................... (13,847) (18,541) (9,425) 392 5,885
Harris Plant carrying costs................... - - - - 1,969
Other income, net............................. - - - - 58
Included in AFUDC - borrowed funds.............. - - - - 2,060
Included in AFUDC - deferred taxes in nuclear
fuel amortization and book depreciation....... (8,225) (8,340) (8,295) (8,274) (8,521)
-------------- -------------- -------------- -------------- -----------
Total income taxes............................$ 247,405 $ 232,046 $ 180,518 $ 181,653 $ 211,717
============== ============== ============== ============== ===========
Fixed Charges and Preferred Dividends Combined:
Preferred dividend requirements.................$ 9,609 $ 9,609 $ 9,609 $ 9,609 $ 14,798
Portion deductible for income tax purposes...... (312) (312) (312) (312) (321)
-------------- -------------- -------------- -------------- -----------
Preferred dividend requirements not deductible..$ 9,297 $ 9,297 $ 9,297 $ 9,297 $ 14,477
============== ============== ============== ============== ===========
Preferred dividend factor:
Preferred dividends not deductible times ratio
of earnings before income taxes to
net income................................ .$ 15,154 $ 15,061 $ 14,689 $ 14,131 $ 22,584
Preferred dividends deductible for
income taxes............................. . 312 312 312 312 321
Fixed charges, as above...................... 204,593 226,833 13,821 237,098 253,215
Total fixed charges and preferred dividends -------------- -------------- -------------- -------------- -----------
combined..................................$ 220,059 $ 242,206 $ 228,822 $ 251,541 $ 276,120
============== ============== ============== ============== ===========
Ratio of Earnings to Fixed Charges and Preferred
Dividends Combined............................. 3.83 3.43 3.09 3.04 3.06
Ratio of Earnings to Fixed Charges............... 4.12 3.67 3.31 3.23 3.34
</TABLE>
[CP&L Logo Appears Here]
Carolina Power & Light Company Bonnie V. Hancock
P.O. Box 1551 Vice President - Accounting
Raleigh, NC 27602 and Controller
March 19, 1997
Securities and Exchange Commission
450 5th Street, NW
Judiciary Plaza
Washington, DC 20549
Gentlemen:
Pursuant to the General Instructions to Form 10-K, please be advised
that the financial statements contained in the 1996 Form 10-K of
Carolina Power & Light Company do not reflect any changes from the
preceding year in accounting principles or practices or in the
method of applying any such principles or practices.
Sincerely yours,
/s/ Bonnie V. Hancock
Exhibit No. 23(a)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
33-33520 on Form S-8, Registration Statement No. 33-5134 on Form S-3,
Post-Effective Amendment No. 1 to Registration Statement No. 33-38349 on
Form S-3, Registration Statement No. 33-50597 on Form S-3 and Registration
Statement No. 33-57835 on Form S-3 of Carolina Power & Light Company, of our
report dated February 10, 1997, appearing in this Annual Report on Form 10-K of
Carolina Power & Light Company for the year ended December 31, 1996.
\s\ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
March 26, 1997
CONSENT OF EXPERT AND COUNSEL
Carolina Power & Light Company:
The statements of law and legal conclusions under Item 1.
Business and Item 3. Legal Proceedings in the Company's
Annual Report on Form 10-K for the year ended December 31, 1996
have been reviewed by me and are set forth therein
in reliance upon my opinion as an expert.
I hereby consent to the incorporation by reference of such
statements of law and legal conclusions in Registration
Statement No. 33-33520 on Form S-8, Registration Statement No.
33-5134 on Form S-3, Post-Effective Amendment No.
1 to Registration Statement No. 33-38349 on Form S-3, Registration
Statement No. 33-50597 on Form S-3 and Registration
Statement No. 33-57835 on Form S-3 and the related Prospectuses,
which are a part of such Registration Statements.
/s/ William D. Johnson,
Vice President and Senior Counsel
March 26, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED
FROM (INTERIM FINANCIAL STATEMENTS AS OF DECEMBER 31, 1996) AND
IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<CIK> 0000017797
<NAME> CAROLINA POWER & LIGHT COMPANY
<CAPTION>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $6,399,919
<OTHER-PROPERTY-AND-INVEST> $489,334
<TOTAL-CURRENT-ASSETS> $672,039
<TOTAL-DEFERRED-CHARGES> $603,552
<OTHER-ASSETS> $204,357
<TOTAL-ASSETS> $8,369,201
<COMMON> $1,187,586
<CAPITAL-SURPLUS-PAID-IN> ($790)
<RETAINED-EARNINGS> $1,503,658
<TOTAL-COMMON-STOCKHOLDERS-EQ> $2,690,454
$0
$143,801
<LONG-TERM-DEBT-NET> $2,525,607
<SHORT-TERM-NOTES> $0
<LONG-TERM-NOTES-PAYABLE> $0
<COMMERCIAL-PAPER-OBLIGATIONS> $0
<LONG-TERM-DEBT-CURRENT-PORT> $103,345
$0
<CAPITAL-LEASE-OBLIGATIONS> $0
<LEASES-CURRENT> $0
<OTHER-ITEMS-CAPITAL-AND-LIAB> $2,905,994
<TOT-CAPITALIZATION-AND-LIAB> $8,369,201
<GROSS-OPERATING-REVENUE> $2,995,715
<INCOME-TAX-EXPENSE> $269,763
<OTHER-OPERATING-EXPENSES> $2,211,865
<TOTAL-OPERATING-EXPENSES> $2,481,628
<OPERATING-INCOME-LOSS> $514,087
<OTHER-INCOME-NET> $62,560
<INCOME-BEFORE-INTEREST-EXPEN> $576,647
<TOTAL-INTEREST-EXPENSE> $185,370
<NET-INCOME> $391,277
$9,609
<EARNINGS-AVAILABLE-FOR-COMM> $381,668
<COMMON-STOCK-DIVIDENDS> $263,388
<TOTAL-INTEREST-ON-BONDS> $172,622
<CASH-FLOW-OPERATIONS> $962,831
<EPS-PRIMARY> $2.66
<EPS-DILUTED> $2.66
