Back to GetFilings.com
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
-----------------
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 333-86243
---------
CP&L ENERGY, INC.
-----------------
(Exact name of registrant as specified in its charter)
North Carolina 56-2155481
-------------- ----------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
411 Fayetteville Street, Raleigh, North Carolina 27601-1748
------------------------------------------------ ----------
(Address of principal executive offices) (Zip Code)
919-546-6111
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
-----------------------------------------------------------
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
N/A N/A
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 the registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K. [X]
Shares of Common Stock (Without Par Value) outstanding at
February 29, 2000: 100
DOCUMENTS INCORPORATED BY REFERENCE
None
EXPLANATORY NOTE:
Carolina Power & Light Company (CP&L) is in the process of converting to a
holding company structure, in which it would become a subsidiary of CP&L Energy,
Inc. (the Company). CP&L's shareholders approved the contemplated holding
company structure on October 20, 1999. The necessary approvals from various
regulatory authorities are expected by the end of the second quarter of 2000.
Upon conversion to a holding company structure, each share of CP&L's common
stock will automatically be exchanged for one share of common stock of the
Company.
On September 15, 1999, CP&L filed an application with the Nuclear Regulatory
Commission for consent to the indirect transfer of control of its nuclear plant
operating licenses to the Company. This application was approved on December 31,
1999.
On October 15, 1999, CP&L filed an application with the North Carolina Utilities
Commission to approve the transfer of ownership of CP&L, Interpath
Communications Inc., and North Carolina Natural Gas Corporation to the Company.
Neither CP&L nor the Company can predict the outcome of this matter.
On October 18, 1999, CP&L filed an application with the Securities and Exchange
Commission (the SEC) for approval of the Company's acquisition of voting
securities giving it control over CP&L and NCNG. Neither CP&L nor the Company
can predict the outcome of this matter.
On October 20, 1999, CP&L filed an application with the Public Service
Commission of South Carolina (SCPSC) to approve the transfer of CP&L and
Interpath Communications Inc. to the Company. The SCPSC issued an order
approving the application on March 6, 2000.
On October 25, 1999, CP&L filed an application with the Federal Energy
Regulatory Commission for approval of the proposed reorganization of CP&L
related to the establishment of the Company. This application was approved on
December 23, 1999.
------------------------------
This Form 10-K is being filed to satisfy the requirements of Section 15(d) under
the Securities Act of 1933, as amended. The Company has no business operations
and other than the Company's parent, CP&L, no shareholders. Accordingly, the
information required by the Form 10-K would not be meaningful and has been
omitted. In lieu of such information, included herewith as Attachment A is
CP&L's Form 10-K for the year ended December 31, 1999. Immediately after the
consummation of the share exchange, the Company's financial statements and other
information will be substantially similar to that of CP&L immediately prior to
the consummation of the share exchange.
For more information on the Company and the contemplated conversion of CP&L to a
holding company structure, please review the Registration Statement of the
Company (previously CP&L Holdings, Inc.) on Form S-4 (333-86243) filed with the
SEC on August 31, 1999.
2
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.
CP&L Energy, Inc.
Date: 3/28/00 (Registrant)
By: /s/ Robert B. McGehee
---------------------
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/Position Date
- --------- -------------- ----
/s/ William Cavanaugh III Principal Executive 3/28/00
- ------------------------- Officer and Director
(William Cavanaugh III, Chairman,
President and Chief Executive
Officer)
/s/ Robert B. McGehee Principal Financial Officer, 3/28/00
- --------------------- Principal Accounting Officer
(Robert B. McGehee, Executive and Director
Vice President and Chief Financial
Officer)
/s/ William D. Johnson Director 3/28/00
- ----------------------
(William D. Johnson)
3
ATTACHMENT A
CAROLINA POWER & LIGHT COMPANY'S FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1999.
4
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, 1999
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 jurisdiction of (I.R.S. Employer (Address of principal executive offices) (Zip Code)
incorporation or organization) Identification No.)
919-546-6111
------------
(Registrant's telephone number, including area code)
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 to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes X . No .
---------- ----------
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in PART III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting and non-voting common stock held by
non-affiliates at February 29, 2000 was $4,748,799,423.
Shares of Common Stock (Without Par Value) outstanding at February 29, 2000:
159,623,510.
DOCUMENTS INCORPORATED BY REFERENCE
-----------------------------------
Portions of the Company's 2000 definitive proxy statement dated March 31, 2000
are incorporated into PART III, ITEMS 10, 11, 12 and 13 hereof.
1
TABLE OF CONTENTS
Page
----
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS 3
PART I
ITEM 1. BUSINESS 4
General 4
Company 4
Significant Transactions 4
Financial Information 5
Business Activities 5
Generating Capability 5
Interconnections with Other Systems 8
Competition 9
Capital Requirements 13
Financing Requirements 13
Retail Rate Matters 15
Wholesale Rate Matters 18
Environmental Matters 18
Nuclear Matters 20
Fuel 24
Natural Gas Supply 26
Diversified Businesses 27
Other Matters 27
Employees 29
Operating Statistics - Electric 30
Operating Statistics - Natural Gas 31
ITEM 2. PROPERTIES 32
ITEM 3. LEGAL PROCEEDINGS 34
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 34
EXECUTIVE OFFICERS OF THE REGISTRANT 35
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS 37
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA 38
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 39
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 51
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 52
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 81
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 81
ITEM 11. EXECUTIVE COMPENSATION 81
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 81
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 81
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 81
2
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
- ------------------------------------------
The matters discussed throughout this Form 10-K that are not historical facts
are forward-looking and, accordingly, involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements.
Examples of forward-looking statements discussed in this Form 10-K, PART I, ITEM
1, "BUSINESS," include, but are not limited to, statements under the following
headings: 1) "General" relating to the Amended and Restated Agreement and Plan
of Exchange with Florida Progress Corporation; 2) "Business Activities"
regarding changes at the Company; 3) "Generating Capability" regarding the
forecasted system sales growth, planned generation additions schedule, and
forecasted capacity margins over anticipated system peak loads; 4)
"Interconnections with Other Systems" relating to future energy cost savings
resulting from amendments to agreements with Cogentrix, future purchases from
the Broad River Energy project and relating to estimated minimum annual payments
for long-term purchase contracts; 5) "Competition" regarding the effect on the
Company of increased competition at the wholesale level and the likelihood of
additional industry restructuring-related bills being introduced in Congress in
2000; 6) "Capital Requirements" relating to estimated capital requirements for
2000-2002; 7) "Financing Requirements" relating to expected external funding
requirements; 8) "Environmental Matters" relating to future capital expenditures
to meet nitrogen oxide emission requirements, emerging regulatory requirements
and the materiality of future costs related to environmental matters; 9)
"Nuclear Matters" relating to future capital expenditures for modifications at
the Company's nuclear units, future increase in low-level radioactive waste
disposal costs, materiality of various nuclear-related matters; and 10) "Fuel"
regarding the percentages of future coal burn requirements from intermediate and
long-term agreements, effect of amendments to the Clean Air Act on the price of
low sulfur coal, sufficiency of existing uranium contracts and regarding total
decontamination and decommissioning fund fees expected to be paid.
In addition, examples of forward-looking statements discussed in this Form 10-K,
PART II, ITEM 7, "Management's Discussion and Analysis of Financial Condition
and Results of Operations" include, but are not limited to, statements under the
following headings: 1) "Liquidity and Capital Resources" about estimated capital
requirements through the year 2002 and 2) "Other Matters" about the effects of
new environmental regulations, nuclear decommissioning costs, and the effect of
electric utility industry restructuring.
Any forward-looking statement speaks only as of the date on which such statement
is made, and the Company undertakes no obligation to update any forward-looking
statement or statements to reflect events or circumstances after the date on
which such statement is made.
Examples of factors that should be considered with respect to any
forward-looking statements made throughout this document include, but are not
limited to, the following: Governmental policies and regulatory actions
(including those of the Federal Energy Regulatory Commission, the Environmental
Protection Agency, the Nuclear Regulatory Commission, the Department of Energy,
the North Carolina Utilities Commission and the Public Service Commission of
South Carolina); general industry trends; operation of nuclear power facilities;
availability of nuclear waste storage facilities; nuclear decommissioning costs;
changes in the economy of areas served by the Company; legislative and
regulatory initiatives that impact the speed and degree of industry
restructuring; ability to obtain adequate and timely rate recovery of costs,
including potential stranded costs arising from industry restructuring;
competition from other energy suppliers; the success of the Company's
subsidiaries; weather conditions and catastrophic weather-related damage; market
demand for energy; inflation; capital market conditions; the proposed share
exchange with Florida Progress Corporation; failure of the potential benefits of
the Company's conversion to a holding company structure to materialize,
unanticipated changes in operating expenses and capital expenditures; and legal
and administrative proceedings. All such factors are difficult to predict,
contain uncertainties that may materially affect actual results, and may be
beyond the control of the Company. New factors emerge from time to time and it
is not possible for management to predict all of such factors, nor can it assess
the effect of each such factor on the Company.
3
PART I
ITEM 1. BUSINESS
- ------- --------
GENERAL
- -------
COMPANY
- -------
Carolina Power & Light Company (the Company), whose principal executive offices
are located at 411 Fayetteville Street, Raleigh, North Carolina is a full
service energy provider formed under the laws of North Carolina in 1926 and is
an exempt holding company as defined by the Public Utility Holding Company Act
of 1935. The Company is primarily engaged in the generation, transmission,
distribution and sale of electricity in portions of North and South Carolina,
and the transmission, distribution and sale of natural gas in portions of North
Carolina. The Company provides these and other services through its business
segments: electric, natural gas and other.
The electric segment generates, transmits, distributes and sells electricity to
56 of the 100 counties in North Carolina, and 14 counties in northeastern South
Carolina. The territory served is an area of 33,667 square miles, including 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 an around the city of Asheville. The
estimated total population of the territory served is approximately 4.2 million.
At December 31, 1999, the electric segment was providing electric services,
retail and wholesale, to 1.2 million customers. The electric segment is subject
to the rules and regulations of the Federal Energy Regulatory Commission (FERC),
the North Carolina Utilities Commission (NCUC) and the Public Service Commission
of South Carolina (SCPSC).
The natural gas segment transmits, distributes and sells gas to approximately
167,000 thousand customers in 110 towns and cities and four municipal gas
distribution systems. The area served includes substantial portions of
south-central and eastern North Carolina. The natural gas segment also purchases
and transports natural gas under long-term contracts with Transcontinental Gas
Pipe Line Corporation (Transco), Columbia Gas Transmission Corporation
(Columbia) and several major oil and gas producers. Natural gas operations are
subject to the rules and regulations of the NCUC.
The other segment primarily includes telecommunication services, energy
management services, propane and miscellaneous non-regulated activities. These
services are primarily provided through two of the Company's subsidiaries,
Strategic Resource Solutions Corp. (SRS) and Interpath Communications, Inc.
(Interpath). SRS specializes in facilities and energy management software,
systems and services for educational, commercial, industrial and governmental
markets nationwide. Interpath is a telecommunications company primarily engaged
in providing comprehensive network services.
The Company holds franchises to the extent necessary to operate its regulated
electric and natural gas operations in the municipalities and other areas it
serves.
SIGNIFICANT TRANSACTIONS
- ------------------------
On July 15, 1999, the Company completed the acquisition of North Carolina
Natural Gas Corporation (NCNG), now operating as a wholly owned subsidiary. Each
outstanding share of NCNG common stock was converted into the right to receive
0.8054 shares of Company common stock, resulting in the issuance of
approximately 8.3 million shares. The acquisition was accounted for as a
purchase and, accordingly, the operating results of NCNG have been included in
the Company's consolidated financial statements since the date of acquisition.
See PART II, ITEM 7, "Other Matters."
The Company, Florida Progress Corporation (FPC), a Florida corporation, and CP&L
Energy, Inc. (CP&L Energy), a North Carolina corporation and wholly owned
subsidiary of the Company formerly known as CP&L Holdings, Inc.
4
entered into an Amended and Restated Agreement and Plan of Share Exchange dated
as of August 22, 1999, amended and restated as of March 3, 2000 (the "Amended
Agreement"). The transaction is expected to be completed in the fall of 2000.
See PART II, ITEM 7, "Other Matters."
The Company is in the process of converting to a holding company structure, in
which the Company would become a subsidiary of a newly formed holding company.
The holding company structure will allow for greater organizational flexibility,
and will provide the ability to conduct financing activities at the holding
company level. See PART II, ITEM 7, "Other Matters."
FINANCIAL INFORMATION
- ---------------------
During 1999, the Company's operating revenues totaled $3.4 billion of which $3.1
billion was related to the electric segment, $98.9 million to the natural gas
segment and $119.9 million to the other segment. During 1999, 34% of electric
revenues were derived from residential sales, 22% from commercial sales, 22%
from industrial sales, 13% from wholesale sales and 9% from other sources. Of
such operating revenues, approximately 67% were derived from North Carolina
retail customers, 13% from South Carolina retail customers, 13% from North
Carolina wholesale customers, less than 0.5% from South Carolina wholesale
customers and 7% from sales to other utilities and other customers. For the
revenues related to the natural gas segment, 50% of the revenues were derived
from industrial sales while the remaining sales were evenly distributed among
residential, commercial, electric utilities and wholesale customers, all in
North Carolina. The operating revenues for the other segment primarily include
revenues of two of the Company's subsidiaries, SRS and Interpath.
For additional information see PART II, ITEM 7, "Results of Operations" and PART
II, ITEM 8, "Note 5."
BUSINESS ACTIVITIES
- -------------------
GENERATING CAPABILITY
- ---------------------
1. FACILITIES. At December 31, 1999, the Company had a total system
installed generating capability (including the North Carolina Eastern
Municipal Power Agency's (Power Agency) share) of 10,128 megawatts
(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 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. Of the total system installed
generating capability of 10,128 MW, 53% is coal, 31% is nuclear, 2% is
hydro and 14% is fired by other fuels including No. 2 oil, natural gas
and propane.
5
MAJOR INSTALLED GENERATING FACILITIES
-------------------------------------
AT DECEMBER 31, 1999
--------------------
Year Maximum
Commercial Dependable
Plant Location Unit No. Operation Primary Fuel Capacity
-------------- -------- --------- ------------ --------
Asheville 1 1964 Coal 198 MW
(Skyland, N.C.) 2 1971 Coal 194 MW
3 1999 Gas/Oil 165 MW
4 2000 Gas/Oil 165 MW
Cape Fear 5 1956 Coal 143 MW
(Moncure, N.C.) 6 1958 Coal 173 MW
Darlington County Plant 12 1997 Gas/Oil 120 MW
(Hartsville, S.C.) 13 1997 Gas/Oil 120 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 820 MW*
(Southport, N.C.) 2 1975 Nuclear 811 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.
6
2. MAINTENANCE OF PROPERTIES. The Company maintains all of its properties
in good operating condition in accordance with sound management
practices. The average life expectancy for ratemaking and accounting
purposes of the Company's generating facilities (excluding combustion
turbine units and hydro units) is approximately 40 years from the date
of commercial operation.
3. GENERATION ADDITIONS SCHEDULE The Company's energy and load forecasts
were revised in December 1999. Over the next ten years, system internal
sales growth is forecasted to average approximately 2.8% per year and
annual growth in system internal peak demand is projected to average
approximately 2.8%. The Company's generation additions schedule
provides for the addition of approximately 2,872 MW of combustion
turbine capacity and 2,406 MW of combined cycle capacity over the
period 2000 to 2009 in order to meet the needs of its growing customer
base and increase its ability to participate in the wholesale power
market. The Company may alter its long-term plans based on changes in
load forecasts, market conditions, and other factors. In addition, see
PART I, ITEM 1 "Interconnections with Other Systems" and PART I, ITEM
1, "Competition" for discussion of the Company's long-term purchase
power contracts.
On August 18, 1998 the Company filed with the NCUC an application for a
Certificate of Public Convenience and Necessity to construct an
additional 177 MW of combustion turbine capacity adjacent to the
Company's Lee Steam Electric Plant in Wayne County, North Carolina and
a second 160 MW combustion turbine unit at the Company's Asheville
Steam Electric Plant in Buncombe County, North Carolina. The Wayne
County Turbine is in addition to the 500 MW of combustion turbine
capacity for which the Company received a Certificate of Public
Convenience and Necessity on March 21, 1996. These units will primarily
be used during periods of summer and winter peak demands. By order
issued December 17, 1998, the NCUC granted the Company a Certificate to
construct both units. Construction of the combustion turbines began
during the first quarter of 1999. Commercial operation was anticipated
to begin in June 2000 for both units; however, the Asheville combustion
turbine became operational in February 2000, three months ahead of
schedule.
On March 19, 1999, the Company filed with the NCUC an application for a
Certificate of Public Convenience and Necessity to construct 1600 MW of
combustion turbine generating capacity between two sites, one in Rowan
County and a site in Richmond County. The NCUC granted the certificate
on November 11, 1999. Construction of the combustion turbine in Rowan
county began November 15, 1999 and the construction of the combustion
turbine in Richmond county began February 1, 2000.
During 1999, the Company invested approximately $47.5 million in new
generating plant facilities.
4. PEAK DEMAND. An instantaneous system peak demand record of 10,948 MW
was reached on August 11, 1999. 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 5.22%.
Total system peak demand increased for 1997 by 2.2%, for 1998 by 5.0%
and for 1999 by 4.0% as compared with the preceding year. The Company
currently projects that system peak demand will increase at an average
annual growth rate of approximately 2.8% 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, were 60.6% for 1997,
60.1% for 1998, and 58.2% for 1999. The Company forecasts capacity
margins of 10.5% over anticipated system peak load for 2000 and 10.6%
for 2001. 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
7
purchases of power. However, some of the generating units included in
arriving at these capacity margins may be unavailable as a result of
scheduled and unplanned outages.
INTERCONNECTIONS WITH OTHER SYSTEMS
- -----------------------------------
1. INTERCONNECTIONS. 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). In
addition, the Company, on occasion, will reserve daily to hourly
transmission on Duke Energy's (Duke) system under the transmission
tariff in order to accommodate the peak demand in the western control
area.
2. INTERCHANGE AND POWER PURCHASE/SALE AGREEMENTS.
-----------------------------------------------
a) The Company has interchange agreements with APCO, 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 2b below. Purchases and sales
under these agreements may be made due to economic or reliability
considerations.
In June 1999, the Company terminated Schedule G to the
Interchange Agreement between the Company and Duke. Schedule G
provided for the wheeling of electricity between the Company's
eastern area and its western area.
On December 31, 1999, the Company terminated the Standby
Concurrent Exchange Agreement (Standby Agreement) between the
Company and Duke. The Standby Agreement provided 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," for further discussion
of the FERC Order 888.
b) The Virginia-Carolinas Subregion of the Southeastern Electric
Reliability Council is principally made up of the Company, Duke,
Nantahala Power & Light Company, SCE&G, SCPSA, Virginia Power,
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) From July 1993 through June 1999, Duke provided 400 MW of firm
capacity to the Company's system. The Company terminated this
contract in 1999. Purchases under this agreement, including
transmission use charges, totaled $33.8 million in 1999.
b) The Company has 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 transmission interconnections in the
Company's western and eastern service areas
8
and purchase 250 MW of generating capacity from Indiana
Michigan's Rockport Unit No. 2 through 2009. Upgrades to the
transmission interconnections in the Company's western and
eastern service area were completed in 1992 and 1998,
respectively. The estimated minimum annual payment for power
purchases under the agreement is approximately $31 million,
representing capital-related capacity costs. In 1999, purchases
under this agreement, including transmission use charges, totaled
$59.5 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 expects to
realize energy cost savings through the expiration of the
agreement in 2002.
d) In December 1998, the Company entered into an agreement to
purchase all of the output of a combustion turbine project to be
built, owned, and operated by Broad River Energy, LLC, in
Cherokee County, South Carolina. The project is scheduled to be
in service on or before June 1, 2001 and is expected to have a
net dependable capacity of approximately 500 MW. The agreement is
for an initial period of 15 years, with an option for the Company
to extend the agreement for two additional five-year terms.
During the term of the agreement, the Company will have full
rights to the output of the project as well as control over the
scheduling of the units.
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 Harris Plant through 2007.
The estimated minimum annual payments for these purchases, which
reflect capital-related capacity costs, total approximately $26
million. Purchases under this agreement totaled $36.5 million in 1999.
COMPETITION
- -----------
1. GENERAL. In recent years, the electric utility industry has experienced
a substantial increase in competition at the wholesale level, caused by
changes in federal law and regulatory policy. Several states have also
decided to restructure aspects of retail electric service. The issue of
retail restructuring and competition is being reviewed by a number of
states and bills have been introduced in Congress that seek to
introduce such restructuring in all states.
Allowing increased competition in the generation and sale of electric
power will require resolution of many complex issues. One of the major
issues to be resolved is who will pay for stranded costs. Stranded
costs are those costs and investments made by utilities in order to
meet their statutory obligation to provide electric service, but which
could not be recovered through the market price for electricity
following industry restructuring. The amount of such stranded costs
that the Company might experience would depend on the timing of, and
the extent to which, direct competition is introduced, and the
then-existing market price of energy. If electric utilities were no
longer subject to cost-based regulation and it were not possible to
recover stranded costs, the financial position and results of
operations of the Company could be adversely affected.
2. WHOLESALE COMPETITION. Since passage of the National Energy Act of 1992
(Energy Act), competition in the wholesale electric utility industry
has significantly increased due to a greater participation by
traditional
9
electricity suppliers, wholesale power marketers and brokers, and due
to the trading of energy futures contracts on various commodities
exchanges. This increased competition could affect 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.
To assist in the development of wholesale competition, the FERC, in
1996, issued standards 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 contains provisions for the recovery of
stranded costs and numerous other provisions that could affect 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 and other entities filed protests challenging
numerous aspects of the Company's tariff and requesting that an
evidentiary proceeding be held. The FERC set the matter for hearing and
set a discovery and procedural schedule. In July 1997, the Company
filed an offer of settlement in this matter. The administrative law
judge certified the offer to the full FERC in September 1997. The offer
is pending before the FERC. The Company cannot predict the outcome of
this matter.
On December 20, 1999, the FERC issued a rule on Regional Transmission
Organizations (RTO) that sets forth four minimum characteristics and
eight functions for transmission entities, including independent system
operators and transmission companies, to become FERC-approved RTOs. The
rule states that public utilities that own, operate or control
interstate transmission facilities must file by October 15, 2000,
either a proposal to participate in an RTO or an alternative filing
describing efforts and plans to participate in an RTO. The Company
plans to participate in an RTO and anticipates complying with this
filing requirement.
3. RETAIL COMPETITION. The Energy Act prohibits the FERC from ordering
retail wheeling - transmitting power on behalf of another producer to
an individual retail customer. Several states have changed their laws
and regulations to allow full retail competition. Other states are
considering changes to allow retail competition. These changes and
proposals have taken differing forms and included disparate elements.
The Company believes changes in existing laws in both North and South
Carolina would be required to permit competition in the Company's
retail jurisdictions.
4. NORTH CAROLINA ACTIVITIES. In April 1997, the North Carolina General
Assembly approved legislation establishing a 23-member study commission
to evaluate the future of electric service in the state. During 1998,
the study commission met and held public hearings around the state. The
study commission also retained consultants to conduct analyses and
studies concerning various restructuring issues, including stranded
costs, state and local tax implications and electric rate comparisons.
In June 1998, the study commission issued an interim report to the 1998
North Carolina General Assembly, summarizing the numerous fact-finding
and educational activities and analytical projects the study commission
had initiated or completed. That report offered no judgments or
recommendations. In May 1999, the North Carolina General Assembly
approved legislation that expanded the study commission from 23 to 29
members. All 29 study commission members were appointed by August 1999.
The study commission conducted several meetings during August through
November to discuss the reports regarding deregulation issues prepared
by the Research Triangle Institute at the request of the study
commission. During those meetings, several entities, including the
Company and Duke, presented proposals for addressing the nearly $6
billion debt of North Carolina's Municipal Power Agencies. The study
commission resumed meeting in January 2000. On
10
March 8, 2000, the commission co-chairs presented draft recommendations
regarding electric industry restructuring to the full study commission
for its consideration in preparing its report to the North Carolina
General Assembly. Key recommendations in the draft include (i) electric
retail competition should begin in North Carolina no later than June
30, 2006; (ii) recovery of utilities' stranded costs should not be
extended beyond June 30, 2006; and (iii) the generation and
distribution of assets of the municipal power agencies (including Power
Agency) should be sold no later than June 30, 2002, and the funds from
those sales should be used to pay off a portion of the municipal power
agencies' debt. The draft recommendations also address issues related
to the legislative timetable, consumer protection measures,
environmental concerns, tax laws, and transmission and distribution.
Implicit in recommendation is a rate freeze through the year 2006.
Initial comments on the draft recommendations were due on March 10,
2000. The Company and other interested parties submitted comments. The
draft recommendations will serve as a starting point for preparation of
the study commission's report addressing industry restructuring in the
State of North Carolina. The recommendations and related issues will be
debated and discussed at future study commission meetings. The
commission is expected to make a final report to the North Carolina
General Assembly in the spring of 2000. The Company cannot predict the
outcome of this matter.
5. SOUTH CAROLINA ACTIVITIES. The 1999 session of the South Carolina
General Assembly adjourned in June 1999 without approving any
legislation regarding electric industry restructuring.
On October 29, 1998, the South Carolina Senate Judiciary Committee
appointed a 13-member task force to study the restructuring issue and
make a report to the Senate. The task force was subsequently expanded
to 18 members, including the Company. The task force, including its
various committees, has conducted several meetings to receive input
from various experts and interested parties and to discuss issues
related to restructuring.
The House Public Utility Subcommittee is expected to continue
considering the electric industry restructuring bills that were
introduced in 1999, and the Senate task force is expected to continue
to consider the issue of restructuring during the South Carolina
General Assembly's 2000 legislative session. The Company cannot predict
the outcome of these matters.
6. FEDERAL ACTIVITIES. During 1999, over 20 bills were introduced in
Congress regarding electric industry restructuring. A draft bill passed
the House Commerce Subcommittee on October 27, 1999. This bill will
proceed to full Commerce Committee consideration in the first quarter
of 2000 where it is expected to be changed significantly. The Company
cannot predict the outcome of this matter.
7. COMPANY ACTIVITIES. The developments described above have created
changing markets for energy. As a strategy for competing in these
changing markets, the Company is becoming a total energy provider in
the region by providing a full array of energy-related services to its
current customers and expanding its market reach. The Company took a
major step towards implementing this strategy, by entering into the
Amended Agreement with FPC.
In December 1998, the Company entered into an agreement to purchase all
of the output of a combustion turbine project to be built, owned and
operated by Broad River Energy, LLC (BRE), in Cherokee County, South
Carolina. In conjunction with this agreement, the Company agreed to
provide bridge financing to BRE under a Financing Term Sheet. This
financing will be used by BRE to (i) make payments to Duke Energy in
connection with certain electrical interconnection agreements, (ii)
purchase two generator step up transformers and (iii) acquire land for
the Broad River Energy Center Project. Under the terms of this
agreement, the Company agreed to loan BRE up to $20.5 million that will
be due on July 1, 2000. In
11
addition, in August of 1999 the Company agreed to loan Broad River
Investors, LLC up to $84.5 million that will be due on July 1, 2000 to
finance the purchase of the combustion turbines for the project.
Interest on each of the loans is calculated based on the London
Inter-Bank Offer Rate, LIBOR, plus a spread of 1%.
In August 1999, the Company signed a five-year agreement with Municipal
Electric Authority of Georgia (MEAG) pursuant to which MEAG will
receive the full output of a 160 MW combustion turbine owned and
operated by Monroe Power Company, a wholly owned subsidiary of the
Company. Headquartered in Atlanta, Georgia, MEAG represents 48
municipal electric utilities in Georgia and is part owner of four
generating facilities and the Georgia Integrated Transmission System.
In August 1999, the Company signed an off-system wholesale peaking
power sales agreement with Santee Cooper. The Company will provide up
to 150 MW of additional peaking power for a one-year term from June
2001 to May 2002, to help meet the increasing demand in Santee Cooper's
fast-growing service area.
In October 1999, the Company and the Albemarle-Pamlico Economic
Development Corporation (APEC) announced their intention to build an
850-mile natural gas transmission and distribution system to 14
currently unserved counties in eastern North Carolina. The Company will
operate both the transmission and distribution systems and APEC will
help ensure that the new facilities are built in the most advantageous
locations to promote development of the economic base in the region. In
conjunction with this proposal, the Company and APEC filed a joint
request with the NCUC for $186 million of a $200 million state bond
package established for clean water and natural gas infrastructure. If
granted, these funds will be used to pay for the portion of the project
that likely could not be recovered from future gas customers through
rates. The Company plans to invest an additional $11.5 million, thus
bringing the total cost of the project to $197.5 million. As proposed,
the project is scheduled to be developed in phases through 2003. The
NCUC has established a procedural schedule with hearings regarding the
first phase of the project to be conducted in April 2000. An order is
expected mid-2000. The Company cannot predict the outcome of this
matter.
In December 1999, the Company announced plans to build a 30-inch
natural gas pipeline in North Carolina that will extend approximately
82 miles from Williams Energy's Transcontinental interstate pipeline in
Iredell County to Richmond County. The pipeline will provide gas for
the Company's planned new power plant in Richmond County and is
scheduled to be completed during the spring of 2001. The pipeline is
expected to cost approximately $100 million and will accommodate
extension of natural gas service to future Company power plants and
normal load growth on NCNG's system. This pipeline plan replaces a plan
for a 175-mile pipeline, the Palmetto Pipeline that the Company and
Southern Natural Gas Company, a subsidiary of El Paso Energy, had been
assessing.
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 and liabilities resulting from the
effects of the ratemaking process, which would not be recorded under
generally accepted accounting principles for unregulated entities. The
Company's ability to continue to meet the criteria for application of
SFAS-71 may be affected in the future by competitive forces and
restructuring in the electric utility industry. In the event that
SFAS-71 no longer applied to a separable portion of the Company's
operations, related regulatory assets and liabilities would be
eliminated unless an appropriate regulatory recovery mechanism is
provided. Additionally, these factors could 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."
12
CAPITAL REQUIREMENTS
- --------------------
CAPITAL REQUIREMENTS. During 1999, the Company expended approximately
$862 million for capital requirements. Estimated capital requirements
for 2000 through 2002 primarily reflect construction expenditures to
add generation, transmission and distribution facilities, as well as
upgrade existing facilities. Those capital requirements are reflected
in the following table (in millions):
2000 2001 2002
------- ------- -------
Construction Expenditures $ 851 $ 876 $ 912
Nuclear Fuel Expenditures 64 94 66
AFUDC (21) (32) (38)
Mandatory Retirements of Long-Term Debt 201 5 251
------- ------- -------
TOTAL $ 1,095 $ 943 $ 1,191
======= ======== =======
The table includes expenditures of approximately $311 million expected
to be incurred at fossil-fueled electric generating facilities to
comply with the Clean Air Act.
In addition, the Company has total projected cash requirements of
approximately $565 million over the years 2000 through 2002 relating to
expenditures in other areas such as affordable housing investments and
merchant generation. These projections are periodically reviewed and
may change significantly.
FINANCING REQUIREMENTS
- ----------------------
1. FINANCING REQUIREMENTS. The proceeds from the issuance of commercial
paper and/or internally generated funds financed the retirement of
long-term debt totaling $113 million in 1999. In addition, the issuance
of $500 million extendible notes in October 1999, financed the
retirement of $100 million of extendible commercial notes and reduced
the outstanding commercial paper balance. External funding
requirements, which do not include early redemptions of long-term debt,
redemption of preferred stock or issuances in conjunction with
acquisitions, are expected to approximate $490 million, $580 million
and $640 million in 2000, 2001 and 2002, respectively. These funds will
be required for construction, mandatory retirements of long-term debt
and general corporate purposes. 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 long-term debt, the
redemption of preferred stock, the reduction of short-term debt or for
other general corporate purposes.
2. SEC FILINGS.
i) The Company has on file with the Securities and
Exchange Commission (SEC) a shelf registration
statement (File No. 333-69237) under which first
mortgage bonds, senior notes and other debt
securities are available for issuance by the Company.
As of December 31, 1999, the Company had $600 million
available under this shelf registration.
ii) 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.
13
3. ISSUANCES OF BONDS, PREFERRED STOCK AND DEBENTURES.
---------------------------------------------------
External financings during 1999 included:
i) The issuance on March 5, 1999 of $400 million
principal amount of Senior Notes, 5.95% Series due on
March 1, 2009. The net proceeds were used to reduce
the outstanding balance of commercial paper and for
other general corporate purposes.
ii) In October 1999, the Company issued $500 million of
unsecured Extendible Notes with a final maturity of
October 28, 2009, and an initial reset period from
October 28, 1999 to July 28, 2000 at an interest rate
to be reset and payable on a monthly basis at a rate
equal to the one month LIBOR plus a spread of 0.33%.
The net proceeds from this issuance were used to
reduce commercial paper borrowings and other
short-term indebtedness.
4. REDEMPTIONS/RETIREMENTS OF BONDS, PREFERRED STOCK AND DEBENTURES.
----------------------------------------------------------------
Redemptions and retirements during 1999 included:
i) The retirement on July 1, 1999 of $50 million
principal amount of First Mortgage Bonds, Medium Term
Notes, 7.15% Series B, which matured on that date.
ii) The redemption on August 9, 1999 of $25 million
principal amount of, 9.21% Debentures Series C, due
November 15, 2011 on behalf of NCNG.
iii) The redemption on August 13, 1999 of $30 million
principal amount of, 7.15% Debentures Series, due
November 15, 2015 on behalf of NCNG.
5. CREDIT FACILITIES. As of December 31, 1999, the Company's revolving
credit facilities totaled $750 million, all of which are long-term
agreements. The Company is required to pay minimal annual commitment
fees to maintain its credit facilities. Consistent with management's
intent to maintain its commercial paper, pollution control revenue
refunding bonds (pollution control bonds) and other short-term
indebtedness on a long-term basis, and as supported by its long-term
revolving credit facilities, the Company included in long-term debt
commercial paper, pollution control bonds and other short-term
indebtedness outstanding of approximately $363 million, $56 million and
$331 million, respectively, as of December 31, 1999. Commercial paper
and pollution control bonds outstanding of approximately $488 million
and $56 million, respectively, were reclassified as long-term debt as
of December 31, 1998. See PART II, ITEM 8, "Consolidated Financial
Statements and Supplementary Data," Note 6, for a more detailed
discussion of the Company's revolving credit facilities.
6. COMMERCIAL NOTES. In September 1999, the Company established a $150
million extendible commercial notes program. As of December 31, 1999,
there were no extendible commercial notes outstanding.
7. CREDIT RATINGS. The Company's access to outside capital depends on its
ability to maintain its credit ratings. The Company's credit ratings
are as follows:
14
Moody's
Duff and Phelps Investors Service Standard and Poor's
--------------- ----------------- -------------------
First Mortgage Bonds A+ A2 A
Commercial Paper D-1 P-1 A-1
Extendible Commercial Notes N/A P-1 A-1
Extendible Notes D-1 P-1 A-1
The following is a summary of the meanings of the ratings shown above
and the relative rank of the Company's rating within each agency's
classification system.
Duff and Phelps' top four bond ratings (AAA, AA, A and BBB) are
considered "investment grade." Debt that is rated "A" is considered
upper grade securities which possess adequate protection factors but
risk factors that are more variable in periods of economic stress. Duff
and Phelps may use a plus (+) or minus (-) sign to designate the
relative position of a credit within the rating category. Moody's top
four bond ratings (Aaa, Aa, A and Baa) are generally considered
"investment grade." Obligations that are rated "A" possess many
favorable investment attributes and are considered as upper medium
grade obligations. Factors giving security to principal and interest
are considered adequate but elements may be present which suggest a
susceptibility to impairment sometime in the future. A numerical
modifier ranks the security within the category with a "2" indicating
the mid-range. Standard & Poor's top four bond ratings (AAA, AA, A and
BBB) are considered "investment grade." Debt rated "A" has a strong
capacity to pay interest and repay principal although it is somewhat
more susceptible to the adverse effects of changes in economic
conditions than debt in higher rated categories. Standard & Poor's may
use a plus (+) or minus (-) sign after ratings to designate the
relative position of a credit within the rating category.
Duff and Phelps' top three commercial paper ratings (D-1, D-2 and D-3)
are generally considered "investment grade." Issuers rated "D-1" have a
very high certainty of timely payment, liquidity factors are excellent
and risk factors are minor. Moody's top three commercial paper ratings
(P-1, P-2 and P-3) are generally considered "investment grade." Issuers
rated "P-1" have a superior ability for repayment of senior short-term
debt obligations and repayment ability is often evidenced by a
conservative structure, broad margins in earnings coverage of fixed
financial charges and well established access to a range of financial
markets and assured sources of alternate liquidity. Standard & Poor's
commercial paper ratings are a current assessment of the likelihood of
timely payment of debt having an original maturity less than 365 days.
The top three Standard & Poor's commercial paper ratings (A-1, A-2 and
A-3) are considered "investment grade." Issues rated "A-1" indicate
that the degree of safety regarding timely payment is either
overwhelming or very strong. Those issues determined to possess
overwhelming safety are denoted with a plus (+) sign designation.
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. The Company is also
subject to regulation in North Carolina by the NCUC with respect to
rates and service for the transmission, distribution, and sale of
natural gas in portions of North Carolina.
2. ELECTRIC RETAIL RATES. The rates of return granted to the Company in
its most recent general rate cases are as follows:
15
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% 0.65%
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% 0.65%
Common Equity 44.72% 12.75% 5.71%
-------
Rate of Return 10.48%
=======
3. NATURAL GAS RATES. On October 27, 1995, the NCUC issued its Order
granting a general rate increase amounting to $4.2 million in annual
revenues effective November 1, 1995. The Commission's Order approved,
in all material respects, the Stipulation of Settlement reached among
NCNG, the NCUC Public Staff, which represents the using and consuming
public, the Carolina Utility Customers Association, Inc. (CUCA) and
other intervenors in the rate case. The Order provides for a rate of
return on net investment of 10.09% but, pursuant to the Stipulation of
Settlement, did not state separately the rate of return on common
equity nor the capital structure used to calculate revenue
requirements.
4. OTHER RETAIL RATE MATTERS. Pursuant to authorizations from the NCUC and
the SCPSC, the Company began to accelerate the amortization of certain
regulatory assets over a three-year period beginning January 1997 and
expiring December 1999. The accelerated amortization of these
regulatory assets resulted in additional depreciation and amortization
expenses of approximately $68 million in each year of the three-year
period.
In 1996, the NCUC also authorized the Company to defer operation and
maintenance expenses of approximately $40 million associated with
Hurricane Fran, with amortization over a 40-month period, which expired
December 1999.
In late 1998 and early 1999, the Company filed, and the respective
commissions subsequently approved, proposals in the North and South
Carolina retail jurisdictions to accelerate cost recovery of its
nuclear generating assets beginning January 1, 2000 and continuing
through 2004. The accelerated cost recovery begins immediately after
the 1999 expiration of the accelerated amortization of certain
regulatory assets, which began in January 1997. Pursuant to the orders,
the Company's depreciation expense for nuclear generating assets will
increase by a minimum of $106 million up to a maximum of $150 million
per year. Recovering the costs of the nuclear generating assets on an
accelerated basis will better position the Company for the
uncertainties associated with potential restructuring of the electric
utility industry.
In conjunction with the acquisition, the Company and NCNG signed a
joint stipulation agreement with the Public Staff of the NCUC in which
the Company agreed to cap base retail electric rates, exclusive of fuel
16
costs, with limited exceptions, through December 2004, and NCNG agreed
to cap margin rates for gas sales and transportation services, with
limited exceptions, through November 1, 2003. Management is of the
opinion that this agreement will not have a material effect on the
consolidated results of operations or financial position of the
Company.
5. 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. In the past, utilities were 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. During 1998, the
NCUC and SCPSC substantially altered their IRP rules. Both the NCUC and
SCPSC reduced the amount of information that must be included in the
Company's IRP. The NCUC also eliminated the triennial IRP and now
requires an annual filing.
6. FUEL COST RECOVERY.
------------------
a) 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 3, 1999, the Company filed its 1999 fuel cost recovery
application. The NCUC issued a final order approving the
Company's proposed billing fuel factor of 1.057 cents/kWh on
September 9, 1999. This new factor became effective on
September 15, 1999. On October 8, 1999, CUCA appealed the
Commission's decision.
b) 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. The Company's fuel hearing was held
on March 24, 1999 and by order issued April 1, 1999, the SCPSC
approved the Company's proposed continuation of the existing
fuel factor of 1.122 cents/kWh.
7. AVOIDED COST PROCEEDINGS. In 1998, the NCUC opened Docket No. E-100,
Sub 81 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 6, 1998. Intervenor comments
on the utilities' filings were filed January 15, 1999, and a hearing
for non-expert public witnesses was held on February 2, 1999. By order
issued July 16, 1999, the NCUC approved the Company's proposed avoided
cost rates.
WHOLESALE RATE MATTERS
- ----------------------
The Company is subject to regulation by the FERC with respect to rates
for transmission and sale of electric energy at wholesale, the
interconnection of facilities in interstate commerce (other than
interconnections for use in the event of certain emergency situations),
the licensing and operation of hydroelectric projects and, to the
extent the FERC determines, accounting policies and practices. The
Company and its wholesale customers last agreed to a general increase
in wholesale rates in 1988; however, wholesale rates have been
17
adjusted since that time through contractual negotiations.
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. Environmental laws and
regulations constantly evolve and the ultimate costs of compliance
cannot always be accurately estimated. The capital costs associated
with compliance with pollution control laws and regulations at the
Company's existing fossil facilities that the Company expects to incur
from 2000 through 2002 are included in the estimates under PART I, ITEM
1, "Capital Requirements."
2. CLEAN AIR LEGISLATION. The 1990 amendments to the Clean Air Act require
substantial reductions in sulfur dioxide and nitrogen oxide emissions
from fossil-fueled electric generating plants. The Clean Air Act
required the Company to meet more stringent provisions effective
January 1, 2000. The Company will meet the sulfur dioxide emissions
requirements by maintaining sufficient sulfur dioxide emission
allowances. Installation of additional equipment was necessary to
reduce nitrogen oxide emissions. Increased operation and maintenance
costs, including emission allowance expense, installation of additional
equipment and increased fuel costs are not expected to be material to
the consolidated financial position or results of operations of the
Company.
The EPA has been conducting an enforcement initiative related to a
number of coal-fired utility power plants in an effort to determine
whether modifications at those facilities were subject to New Source
Review requirements or New Source Performance Standards under the Clean
Air Act. The Company has recently been asked to provide information to
the EPA as part of this initiative and has cooperated in providing the
requested information. The EPA has initiated enforcement actions which
may have potentially significant penalties against other companies that
have been subject to this initiative. The Company cannot predict the
outcome of this matter.
On October 27, 1998, the EPA published a final rule addressing the
issue of regional transport of ozone. This rule is commonly known as
the NOx SIP call. The EPA's rule requires 22 states, including North
and South Carolina, to further reduce nitrogen oxide emissions in order
to attain a pre-set state NOx emission level by May 2003. The EPA's
rule also suggests to the states that these additional nitrogen oxide
emission reductions be obtained from the utility sector. The Company is
evaluating necessary measures to comply with the rule and estimates its
related capital expenditures through 2003 could be approximately $327
million, a portion of which is reflected in the "Capital Requirements"
discussion under PART II, ITEM 7, "Liquidity and Capital Resources."
Increased operation and maintenance costs relating to the NOx SIP call
are not expected to be material to the Company's results of operations.
The Company and the states of North and South Carolina have been
participating in litigation challenging the NOx SIP call. On March 3,
2000, a three-judge panel of the District of Columbia Circuit Court of
Appeals upheld the EPA's NOx SIP call. Further appeals are being
considered. The Company cannot predict the outcome of this matter.
The EPA published a final rule approving certain petitions under the
Clean Air Act that requires certain sources to make reductions in
nitrogen oxide emissions by 2003. The Company's fossil-fueled electric
18
generating plants in North Carolina are included in these petitions.
The Company and other states are participating in litigation
challenging the EPA's actions. 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 to require the clean up of hazardous waste sites. This statute
imposes retroactive joint and several liability. Some states, including
North and South Carolina, have similar types of legislation. 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.
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 both the electric utility and the gas
utility have some connection. In this regard, the electric utility and
the gas utility, along with others, are participating in a cooperative
effort with the North Carolina Department of Environment and Natural
Resources, Division of Waste Management (DWM), which has established a
uniform framework to address MGP sites. The investigation and
remediation of specific MGP sites will be addressed pursuant to one or
more Administrative Orders on Consent (AOC) between the DWM and the
potentially responsible party or parties. Both the electric utility and
the gas utility have signed AOCs to investigate certain sites. Both the
electric utility and the gas utility continue to identify parties
connected to individual MGP sites, and to determine their relationships
to other parties at those sites and the degree to which the Company
will undertake efforts with others at individual sites. The Company
does not expect the costs associated with these sites to be material to
the consolidated financial position or results of operations of the
Company.
The Company is periodically notified by regulators such as the North
Carolina Department of Environment and Natural Resources, the South
Carolina Department of Health and Environmental Control, and the U.S.
Environmental Protection Agency (EPA) of its involvement or potential
involvement in sites, other than MGP sites, that may require
investigation and/or remediation. Although the Company may incur costs
at these sites about which it has been notified, based upon current
status of these sites, the Company does not expect those costs to be
material to the consolidated financial position or results of
operations of the Company.
4. OTHER ENVIRONMENTAL MATTERS. The Company has filed claims with its
general liability insurance carriers to recover costs arising out of
actual or potential environmental liabilities. Some claims have been
settled, and others are still being pursued. The Company cannot predict
the outcome of these matters.
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
19
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
disposal facilities for low-level radioactive waste and storage
facilities for spent nuclear fuel. See paragraphs 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 2000, 2001 and 2002 are expected
to total approximately $41 million, $80 million and $29 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. As of December 31, 1999, sufficient
on-site spent nuclear fuel storage capability is available for the
full-core discharge of Brunswick Unit No. 1 through 2001, Brunswick
Unit No. 2 through 2000, Robinson Unit No. 2 through 2000 and Harris
through 2002 assuming normal operating and refueling schedules. The
spent fuel storage facilities at the Brunswick and Robinson Units along
with the Harris Plant spent fuel storage facilities are sufficient to
provide storage space for spent fuel generated by all of the Company's
nuclear generating units through the expiration of their current
operating licenses, provided that currently idle storage space at the
Harris Plant can be activated. On December 23, 1998, the Company
submitted a license amendment application to the NRC requesting
approval to activate and begin using the additional spent fuel storage
at the Harris Plant. The Company is maintaining full-core discharge
capability for the Brunswick Units and Robinson Unit No. 2 by
transferring spent nuclear fuel by rail to the Harris Plant. As a
contingency to the shipment by rail of spent nuclear fuel, during April
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. At the Company's request, the NRC suspended review of the
Company's license application based on the success of the Company's
shipping efforts. The NRC will resume review of the license upon
notification by the Company of its desire to continue the application
process. Subsequent to the expiration of the licenses, dry storage may
be necessary in conjunction with the decommissioning of the units.
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. The Company cannot predict the outcome of these matters.
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 begin taking spent nuclear fuel by no later
than January 31, 1998. All similarly situated utilities were required
to sign the same standard contract. In April 1995, the DOE issued a
final interpretation that it did not have an unconditional obligation
to take spent nuclear fuel by January 31, 1998. In Indiana & Michigan
Power v. DOE, the U.S. Court of Appeals vacated the DOE's final
interpretation and ruled that the DOE had an unconditional obligation
to begin taking spent nuclear fuel. The Court did not specify a remedy
because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan
Power v. DOE, a group of utilities (including the Company) petitioned
the U.S. Court of Appeals in Northern States Power (NSP) v. DOE,
seeking an order requiring the DOE to begin taking spent nuclear fuel
by January 31, 1998. The DOE took the position that their delay was
unavoidable, and the DOE was excused from performance under the terms
20
and conditions of the contract. The Court of Appeals issued an order
that precluded the DOE from treating the delay as an unavoidable delay.
However, the Court of Appeals did not order the DOE to begin taking
spent nuclear fuel, stating that the utilities had a potentially
adequate remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31,
1998, a group of utilities (including the Company) filed a motion with
the U.S. Court of Appeals to enforce the mandate in NSP v. DOE.
Specifically, the utilities asked the Court to permit the utilities to
escrow their waste fee payments, to order the DOE not to use the waste
fund to pay damages to the utilities, and to order the DOE to establish
a schedule for disposal of spent nuclear fuel. The Court denied this
motion based primarily on the grounds that a review of the matter was
premature and that some of the requested remedies fell outside of the
mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in
the Court of Claims and before the Court of Appeals. The Company is in
the process of evaluating whether it should file a similar action for
damages. In NSP v. United States, the United States Court of Claims
decided that NSP must pursue its administrative remedies instead of
filing an action in the Court of Claims. NSP has filed an interlocutory
appeal to the U.S. Court of Appeals based on NSP's position that the
Court of Claims has jurisdiction to decide the matter. A group of
utilities (including the Company) has submitted an amicus brief in
support of NSP's position.
The Company also continues to monitor legislation that has been
introduced in Congress which might provide some limited relief. The
Company cannot predict the outcome of this matter.
With certain modifications and additional approval by the NRC, the
Company's spent nuclear fuel storage facilities will be 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. The Company has initiated
the process of obtaining the additional NRC approval.
3. LOW-LEVEL RADIOACTIVE WASTE. Disposal costs for low-level radioactive
waste that result 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 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. In December 1997,
the Southeast Regional Compact Commission suspended funding for the
proposed low-level radioactive waste facility in Wake County. The
future funding for this project remains uncertain. Although the Company
does not control the future
21
availability of low-level waste disposal facilities, the cost of waste
disposal or the development process, it supports 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 consolidated financial position or results of
operations of the Company.
4. DECOMMISSIONING.
----------------
a) Pursuant to an NRC rule, licensees of nuclear facilities are
required to submit decommissioning funding plans to the NRC
for approval to provide reasonable assurance that the licensee
will have the financial ability to implement its
decommissioning plan for each facility. The rule requires
licensees to do one of the following: prepay at least an
NRC-prescribed minimum amount immediately; set up an external
sinking fund for accumulation of at least that minimum amount
over the operating life of the facility; or provide a surety
to guarantee financial performance in the event of the
licensee's financial inability to perform actual
decommissioning. On July 26, 1990, the Company submitted its
decommissioning funding plans to the NRC. In June 1991, the
Company began depositing funds into an external trust as a
vehicle to achieve such decommissioning funding.
In the Company's retail jurisdictions, provisions for nuclear
decommissioning costs are approved by the NCUC and the SCPSC
and are based on site-specific estimates that included the
costs for removal of all radioactive and other structures at
the site. In the wholesale jurisdiction, the provisions for
nuclear decommissioning costs are based on amounts agreed upon
in applicable rate agreements. Decommissioning cost
provisions, which are included in depreciation and
amortization expense, were $33.3 million, $33.3 million, and
$33.2 million in 1999, 1998, and 1997, respectively.
Accumulated decommissioning costs, which are included in
accumulated depreciation, were $568.0 million and $496.3
million at December 31, 1999 and 1998, respectively. These
costs include amounts retained internally and amounts funded
in an external decommissioning trust. The balance of the
nuclear decommissioning trust was $379.9 million and $310.7
million at December 31, 1999 and 1998, respectively. Trust
earnings increase the trust balance with a corresponding
increase in the accumulated decommissioning balance. These
balances are adjusted for net unrealized gains and losses
related to changes in the fair value of trust assets. Based on
the site-specific estimates discussed below, and using an
assumed after-tax earnings rate of 7.75% 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 1998, using 1998 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 1998 dollars, are
$279.8 million for Robinson Unit No. 2, $299.3 million for
Brunswick Unit No. 1, $298.5 million for Brunswick Unit No. 2,
and
22
$328.1 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. 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 Capability," paragraph
1.
c) The Financial Accounting Standards Board is proceeding with
its project regarding accounting practices related to
obligations associated with the retirement of long-lived
assets, and an exposure draft of a proposed accounting
standard was issued during the first quarter of 2000. It is
uncertain what effects it may ultimately have on the Company's
accounting for nuclear decommissioning and other retirement
costs.
5. OPERATING LICENSES. Facility Operating Licenses, issued by the NRC, for
the Company's nuclear units allow for a full 40 years of operation.
Expiration dates for these licenses are set forth in the following
table.
Facility Operating License
Facility Expiration Date
-------- ---------------
Robinson Unit No. 2 July 31, 2010
Brunswick Unit No. 1 September 8, 2016
Brunswick Unit No. 2 December 27, 2014
Harris Plant October 24, 2026
6. OTHER NUCLEAR MATTERS
---------------------
a) In 1991, the NRC issued a final rule on nuclear plant
maintenance that 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.
In March 1998, the Company's Maintenance Rule Program was
found acceptable by the NRC during baseline inspections.
b) Degradation of tubing internal to steam generators in
pressurized water reactor power plants 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 degradation and
plans to replace the steam generators in 2001. The steam
generators at the Robinson plant were replaced in 1984 and are
expected to perform until the plant's operating license
expires. The Company does not expect the costs associated with
replacing the steam generators at the Harris Plant to be
material to the consolidated financial position or results of
operations of the Company.
c) The Company is insured against public liability for a nuclear
incident up to $9.7 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,
23
the Company would be subject to a pro rata assessment of up to
$83.9 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. For a more detailed discussion of
nuclear liability insurance, see PART II, ITEM 8,
"Consolidated Financial Statements and Supplementary Data,"
Note 16b.
FUEL
- ----
1. SOURCES OF GENERATION. Total system generation (including Power
Agency's share) by primary energy source, along with purchased power,
for the years 1996 through 2000 is set forth below:
1996 1997 1998 1999 2000
---- ---- ---- ---- ----
(estimated)
Fossil 45% 46% 47% 48% 48%
Nuclear 41 43 42 42 41
Purchased Power 12 10 9 8 8
Hydro 2 1 1 1 1
Combustion Turbine -- -- 1 1 2
2. COAL. The Company has intermediate and long-term agreements from which
it expects to receive approximately 80% of its coal burn requirements
in 2000. These agreements have expiration dates ranging from 2000 to
2006. 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. See PART I, ITEM
1, "Environmental Matters," paragraph 2. The average cost (including
transportation costs) to the Company of coal delivered for 1999 was
$41.98 per ton.
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 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 the lack of No.
2 oil availability, twelve combustion turbine units with a total
generating capacity of 766 MW can also burn natural gas. Over the last
five years, No. 2 oil, natural gas and propane accounted for 2.89% of
the Company's total burned fuel cost. In 1999, No. 2 oil, natural gas
and propane accounted for 4.37% 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), and 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 all of the Company's nuclear generating facilities
through 2001.
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
24
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."
5. DOE ENRICHMENT FACILITIES DECONTAMINATION AND DECOMMISSIONING (D&D)
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
which have purchased enrichment services from DOE since it began sales
to non-Department of Defense customers. Each utility's share of the
contributions is based on that utility's past purchases of services as
a percentage of all purchases of services by U.S. utilities. Total
annual contributions are capped at $150 million per year with an
overall cap of $2.25 billion over 15 years both indexed to inflation.
The Company has paid approximately $40 million in D&D fees through
1999, and expects to pay a cumulative total of approximately $82
million over the 15 year period ending September 30, 2007 (excluding
Power Agency's ownership share). The Company is recovering these costs
as a component of fuel cost.
During March 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, seeking a refund of part of
the price paid by the Company for enrichment services purchased from
the DOE. It is the Company's position that the contract price it paid
to the DOE for uranium purchases included the cost of D&D, and that the
DOE's collection of additional D&D fees pursuant to the Energy Act
resulted in an overpayment of fees by the Company. In addition, the
claim requested the elimination of future D&D fund assessments. It was
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. The Company's action was stayed pending the
outcome of a similar case, Yankee Atomic Electric Company (Yankee
Atomic) v. United States (33 Fed.Cl. 580 (Cl.Ct. 1995)), in which the
United States Court of Claims found that a portion of the D&D
assessments made against Yankee Atomic were unlawful. The government
appealed that case to the District of Columbia Circuit Court of
Appeals, which subsequently overturned the favorable Court of Claims
decision. After the Circuit Court of Appeals refused to rehear the
matter, Yankee Atomic filed a petition for a certiorari to seek a
review by the United States Supreme Court, which was denied. During
February 1999, the Company amended its complaint for various reasons,
and the government subsequently filed a motion to dismiss. The total
refund demanded in the Company's amended complaint through the date of
the complaint filing (including Power Agency's ownership share) is
approximately $39 million. The Company cannot predict the outcome of
this matter.
6. PURCHASED POWER. The Company purchased 4,730,657 MWh in 1999, 5,336,867
MWh in 1998, and 5,886,722 MWh in 1997 or approximately 8%, 9%, and
10%, respectively, of its system energy requirements (including Power
Agency) and had available 1,489 MW in 1999, 1,438 MW in 1998, and 1,839
MW in 1997 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.
NATURAL GAS SUPPLY
- ------------------
During 1999, the Company purchased 7,647,462 dekatherms (dt) of natural
gas under its firm sales contracts on the pipeline/utility. It
purchased 20,023,674 dt in the spot market or from other nontraditional
sources, including long-term contracts with producers or national gas
marketers. The Company also transported 6,961,187 dt of customer-owned
gas in 1999. The outlook for natural gas supplies in the Company's
service area remains favorable and the Company has many sources of gas
available on a firm basis. Nationally, gas supplies are adequate and no
supply curtailments are anticipated.
25
The following table summarizes the supply sources which are under
contract or otherwise available to the Company as of December 31, 1999.
Maximum Contract
Daily Annual Expiration
Deliverability (a) Quantity (a) Dat