<PAGE>
================================================================================
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 (FEE REQUIRED)
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the fiscal year ended December 31, 1999 Commission File Number 1-1097
Oklahoma Gas and Electric Company meets the conditions set forth in
general instruction I (1) (a) and (b) of Form 10-K and is therefore filing this
form with the reduced disclosure format permitted by general instruction I (2).
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma 73-0382390
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
As of February 29, 2000, the number of outstanding shares of the
Registrant's common stock, par value $2.50 per share, was 40,378,745 all of
which were held by OGE Energy Corp. There were no other shares of capital stock
of the Registrant outstanding at such date.
Documents incorporated by reference: None
================================================================================
<PAGE>
<TABLE>
<CAPTION>
TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
<S> <C>
Item 1. Business......................................................... 1
The Company...................................................... 1
Introduction............................................ 1
General................................................. 1
Finance and Construction................................ 4
Regulation and Rates.................................... 5
Rate Structure, Load Growth and Related Matters......... 12
Fuel Supply............................................. 13
Environmental Matters............................................ 14
Item 2. Properties....................................................... 17
Item 3. Legal Proceedings................................................ 18
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters..................................... 25
Item 6. Selected Financial Data.......................................... 26
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 27
Item 8. Financial Statements and Supplementary Data...................... 40
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure ............................... 66
PART III
Item 10. Directors and Executive Officers of the Registrant............... 66
Item 11. Executive Compensation........................................... 66
Item 12. Security Ownership of Certain Beneficial
Owners and Management................................... 66
Item 13. Certain Relationships and Related Transactions................... 66
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K..................................... 66
</TABLE>
i
<PAGE>
PART I
ITEM 1. BUSINESS.
- ----------------
THE COMPANY
INTRODUCTION
Oklahoma Gas and Electric Company (the "Company") is a regulated public
utility engaged in the generation, transmission and distribution of electricity
to retail and wholesale customers. The Company is a wholly-owned subsidiary of
OGE Energy Corp. ("Energy Corp.") which is a public utility holding company
incorporated in the State of Oklahoma and located in Oklahoma City, Oklahoma.
The Company's executive offices are located at 321 N. Harvey, P.O. Box 321,
Oklahoma City, Oklahoma 73101-0321: telephone (405) 553-3000.
The Company was incorporated in 1902 under the laws of the Oklahoma
Territory and is the largest electric utility in the State of Oklahoma. The
Company sold its retail gas business in 1928 and now owns and operates an
interconnected electric production, transmission and distribution system which
includes eight active generating stations with a total capability of 5,512,599
kilowatts. At the end of 1999, the Company had 2,046 members.
The regulated utility business has been and will continue to be affected
by competitive changes to the utility industry. Significant changes already have
occurred in the wholesale electric markets at the Federal level. In both
Oklahoma and Arkansas, legislation has been passed to provide for the
restructuring of the electric industry with the goal to provide retail customers
with the ability to choose their generation suppliers by July 1, 2002 and
January 1, 2002, respectively. The Oklahoma Legislature is considering
implementation legislation which is expected to be enacted in May, 2000. This
legislation, if implemented as proposed, would significantly impact the Company.
See "Electric Operations - Regulation and Rates - Recent Regulatory Matters" for
further discussion of these developments.
GENERAL
The Company furnishes retail electric service in 280 communities and
their contiguous rural and suburban areas. During 1999, six other communities
and two rural electric cooperatives in Oklahoma and western Arkansas purchased
electricity from the Company for resale. The service area, with an estimated
population of 1.8 million, covers approximately 30,000 square miles in Oklahoma
and western Arkansas; including Oklahoma City, the largest city in Oklahoma, and
Ft. Smith, Arkansas, the second largest city in that state. Of the 286
communities served, 257 are located in Oklahoma and 29 in
Arkansas. Approximately 90 percent of total electric operating revenues for the
year ended December 31, 1999, were derived from sales in Oklahoma and the
remainder from sales in Arkansas.
The Company's system control area peak demand as reported by the system
dispatcher for the year was approximately 5,748 megawatts, and occurred on
August 11, 1999. The Company's load responsibility peak demand was approximately
5,569 megawatts on August 11, 1999, resulting in a capacity margin of
approximately 10.0 percent. As reflected in the table below and in the operating
statistics on page 3, total kilowatt-hour sales decreased 2.2 percent in 1999 as
compared to an increase of
<PAGE>
4.2 percent in 1998 and a 1.6 percent increase in 1997. In 1999, kilowatt-hour
sales to the Company's customers ("system sales") and sales to other utilities
and power marketers ("off-system sales") decreased 0.7 percent and 48.6 percent,
because of the record heat of 1998. In 1997, total kilowatt-hour sales increased
due to continued customer growth.
Variations in kilowatt-hour sales for the three years are reflected in
the following table:
<TABLE>
<CAPTION>
SALES (Millions of Kwh)
INC/ Inc/ Inc/
1999 (DEC) 1998 (Dec) 1997 (Dec)
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
System Sales 23,468 (0.7%) 23,642 6.6% 22,183 3.0%
Off-system Sales 374 (48.6%) 728 (39.5%) 1,202 (18.5%)
------- ------- -------
Total Sales 23,842 (2.2%) 24,370 4.2% 23,385 1.6%
======= ======= =======
</TABLE>
In 1999, the Company's Sooner Generating Station (consisting of two
coal-fired units with an aggregate capability of 1,012 Mw) and the Company's
three coal-fired units at its Muskogee Generating Station (with an aggregate
capability of 1,481 Mw) were recognized by an industry survey as being among the
top seven percent of more than 400 major coal-fired plants across the United
States.
The Company is subject to competition in various degrees from
government-owned electric systems, municipally-owned electric systems, rural
electric cooperatives and, in certain respects, from other private utilities,
power marketers and cogenerators. See Item 3 "Legal Proceedings" for a further
discussion of this matter. Oklahoma law forbids the granting of an exclusive
franchise to a utility for providing electricity.
Besides competition from other suppliers or marketers of electricity,
the Company competes with suppliers of other forms of energy. The degree of
competition between suppliers may vary depending on relative costs and supplies
of other forms of energy. See "Regulation and Rates - Recent Regulatory Matters"
for a discussion of the potential impact on competition from federal and state
legislation.
2
<PAGE>
<TABLE>
<CAPTION>
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
YEAR ENDED DECEMBER 31
1999 1998 1997
------------- ------------- -------------
<S> <C> <C> <C>
ELECTRIC ENERGY:
(Millions of Kwh)
Generation (exclusive of station use)................... 21,788 22,565 21,620
Purchased............................................... 3,795 3,984 3,528
------------- ------------- -------------
Total generated and purchased..................... 25,583 26,549 25,148
Company use, free service and losses.................... (1,741) (2,179) (1,763)
------------- ------------- -------------
Electric energy sold.............................. 23,842 24,370 23,385
------------- ------------- -------------
ELECTRIC ENERGY SOLD:
(Millions of Kwh)
Residential............................................. 7,509 7,959 7,179
Commercial and industrial............................... 11,985 11,912 11,586
Public street and highway lighting...................... 69 68 68
Other sales to public authorities....................... 2,354 2,352 2,202
System sales for resale................................. 1,551 1,351 1,148
------------- ------------- -------------
Total system sales................................. 23,468 23,642 22,183
Off-system sales........................................ 374 728 1,202
------------- ------------- -------------
Total sales....................................... 23,842 24,370 23,385
============= ============= =============
ELECTRIC OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential........................................... $ 515,299 $ 537,486 $ 474,419
Commercial and industrial............................. 557,884 554,589 526,673
Public street and highway lighting.................... 9,736 9,618 9,456
Other sales to public authorities..................... 108,159 110,522 98,818
System sales for resale............................... 42,918 38,763 34,667
------------- ------------- -------------
Total system sales................................ 1,233,996 1,250,978 1,144,033
Off-system sales...................................... 27,894 37,435 23,028
------------- ------------- -------------
Total Electric Revenues........................... 1,261,890 1,288,413 1,167,061
Miscellaneous......................................... 24,954 23,665 24,629
------------- ------------- -------------
Total Operating Revenues.......................... $ 1,286,844 $ 1,312,078 $ 1,191,690
============= ============= =============
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential............................................. 599,702 598,378 593,699
Commercial and industrial............................... 86,837 86,251 85,315
Public street and highway lighting...................... 249 249 249
Other sales to public authorities....................... 11,151 11,183 10,897
Sales for resale........................................ 56 39 40
------------- ------------- -------------
Total............................................. 697,995 696,100 690,200
============= ============= =============
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (Kwh)................................ 12,546 13,342 12,133
Average annual revenue.................................. $ 860.98 $ 900.94 $ 801.74
Average price per Kwh (cents)........................... 6.86 6.75 6.61
</TABLE>
3
<PAGE>
FINANCE AND CONSTRUCTION
The Company generally meets its cash needs through internally generated
funds, short-term borrowings and permanent financing. Cash flows from operations
have enabled the Company to internally generate the required funds to satisfy
construction expenditures.
Management expects that internally generated funds will be adequate over
the next three years to meet the Company's anticipated construction
expenditures. The primary capital requirements for 2000 through 2002 are
estimated as follows:
<TABLE>
<CAPTION>
(DOLLARS IN MILLIONS) 2000 2001 2002
================================================================================
<S> <C> <C> <C>
Construction expenditures
Including AFUDC................... $ 109.0 $ 100.0 $ 100.0
Maturities of long-term debt........ 110.0 --- ---
- --------------------------------------------------------------------------------
Total........................... $ 219.0 $ 100.0 $ 100.0
================================================================================
</TABLE>
The three-year estimate includes expenditures for construction of new
facilities to meet anticipated demand for service, to replace or expand existing
facilities and to some extent, for satisfying maturing debt. Approximately $1.0
million of the Company's construction expenditures budgeted for 2000 are to
comply with environmental laws and regulations. The Company's construction
program was developed to support an anticipated peak demand growth of one to two
percent annually and to maintain minimum capacity reserve margins as stipulated
by the Southwest Power Pool. See "Rate Structure, Load Growth and Related
Matters."
The Company intends to meet its customers' increased electricity needs
during the foreseeable future primarily by maintaining the reliability and
increasing the utilization of existing capacity. The Company's current resource
strategy includes the reactivation of existing plants and the addition of
peaking resources. The Company does not anticipate the need for another
base-load plant in the foreseeable future.
The Company will continue to use short-term borrowings from Energy Corp.
to meet its temporary cash requirements. The Company has the necessary
regulatory approvals to incur up to $400 million in short-term borrowings at any
one time. At December 31, 1999, Energy Corp. had in place a line of credit for
up to $200 million, of which $100 million was to expire on January 15, 2000, and
the remaining $100 million was to expire on January 15, 2004. In January 2000,
Energy Corp.'s line of credit was increased to $300 million; with $200 million
to expire on January 15, 2001 and $100 million to expire on January 15, 2004.
The Company had $55.5 million in short-term debt outstanding at December 31,
1999, which is classified as accounts payable-affiliates on the accompanying
balance sheet. The Company did not have any short-term debt outstanding at
December 31, 1998 or 1997.
In October 1995, the Company changed its primary method of long-term
debt financing from issuing first mortgage bonds under its First Mortgage Bond
Trust Indenture to issuing Senior Notes under a new Indenture (the "Senior Note
Indenture"). Each series of Senior Notes issued under the Senior Note Indenture
was secured in essence by a series of first mortgage bonds (the "Back-up First
Mortgage Bonds"), subject to the condition that, upon retirement or redemption
of all first mortgage bonds issued prior to October 1995 (the "Prior First
Mortgage Bonds"), each series of Back-up First Mortgage Bonds would
automatically be canceled. In April 1998, all of the Prior First Mortgage Bonds
were redeemed or retired with the result that no first mortgage bonds remain
outstanding. The Company has cancelled its
4
<PAGE>
First Mortgage Bond Trust Indenture and caused the related first mortgage lien
on substantially all of its properties to be discharged and released. The
Company expects to have more flexibility in future financings under its Senior
Note Indenture than existed under the First Mortgage Bond Trust Indenture.
The Company's financial results continue to depend to a large extent
upon the tariffs it charges customers and the actions of the regulatory bodies
that set those tariffs, the amount of energy used by its customers, the cost and
availability of external financing and the cost of conforming to government
regulations.
REGULATION AND RATES
The Company's retail electric tariffs in Oklahoma are regulated by the
Oklahoma Corporation Commission ("OCC"), and in Arkansas by the Arkansas Public
Service Commission ("APSC"). The issuance of certain securities by the Company
is also regulated by the OCC and the APSC. The Company's wholesale electric
tariffs, short-term borrowing authorization and accounting practices are subject
to the jurisdiction of the Federal Energy Regulatory Commission ("FERC"). The
Secretary of the Department of Energy has jurisdiction over some of the
Company's facilities and operations.
The order of the OCC authorizing the Company to reorganize into a
subsidiary of Energy Corp. contains certain provisions which, among other
things, ensure the OCC access to the books and records of Energy Corp. and its
affiliates relating to transactions with the Company; require the Company to
employ accounting and other procedures and controls to protect against
subsidization of non-utility activities by the Company's customers; and prohibit
the Company from pledging its assets or income for affiliate transactions.
For the year ended December 31, 1999, approximately 87 percent of the
Company's electric revenue was subject to the jurisdiction of the OCC, eight
percent to the APSC, and five percent to the FERC.
RECENT REGULATORY MATTERS
In February 1997, the OCC issued an order (the "1997 Order") that, among
other things, effectively lowered the Company's rates to its Oklahoma retail
customers by $50 million annually (based on a test year ended December 31,
1995). Of the $50 million rate reduction, approximately $45 million became
effective on March 5, 1997, and the remaining $5 million became effective March
1, 1998. The 1997 Order also directed the Company to commence competitively bid
gas transportation service to its gas-fired plants no later than April 30, 2000.
The order also set annual compensation for the transportation services provided
by Enogex to the Company at $41.3 million annually until March 1, 2000, at which
time the rate would drop to $28.5 million (reflecting the completion of the
recovery from ratepayers of the amortization premium paid by the Company when it
acquired Enogex in 1986) and remain at that level until competitively-bid gas
transportation begins. Final firm bids were submitted by Enogex and other
pipelines on April 15, 1999. In July 1999, the Company filed an application with
the OCC requesting approval of a performance-based rate plan for its Oklahoma
retail customers from April 2000 until the introduction of customer choice for
electric power in July 2002. As part of this application, the Company stated
that Enogex had submitted the only viable bid ($33.4 million per year) for gas
transportation to its six gas-fired power plants that were the subject of the
competitive bid. As part of its application to the OCC, the Company offered to
discount Enogex's bid from $33.4 million annually to $25.2 million annually. The
Company has executed a new gas transportation contract with Enogex under which
Enogex would continue serving the needs of the Company's power plants at a
5
<PAGE>
price to be paid by the Company of $33.4 million annually and, if the Company's
proposal had been approved by the OCC, the Company would have recovered a
portion of such amount ($25.2 million) from its ratepayers. The OCC Staff (the
"Staff"), the Office of the Oklahoma Attorney General and a coalition of
industrial customers filed testimony questioning various parts of the Company's
performance-based rate plan, including the result of the competitive bid
process, and suggested, among other things, that the bidding process be repeated
or that gas transportation service to five of the Company's gas-fired plants be
awarded to parties other than Enogex. The Staff also filed testimony stating in
substance that the Company's electric rates as a whole were appropriate and did
not warrant a rate review. The Company negotiated with these parties in an
effort to settle all issues (including the competitive bid process) associated
with its application for a performance-based rate plan. When these negotiations
failed, the Company withdrew its application, which withdrawal was approved by
the OCC in December 1999. Based on filed testimony, the Company believes that
Enogex properly won the competitive bid and, unless the Company's decision to
award its gas transportation service to Enogex is abrogated by order of the OCC
(which order is upheld on appeal), that it intends to fulfill its obligations
under its new gas transportation contract with Enogex at a price of $33.4
million annually. Whether the Company will be able to recover the entire amount
from its ratepayers had not been determined as explained below.
The 1997 Order also contained the Generation Efficiency Performance
Rider ("GEP Rider"), which is designed so that when the Company's average annual
cost of fuel per kwh is less than 96.261 percent of the average non-nuclear fuel
cost per kwh of certain other investor-owned utilities in the region, the
Company is allowed to collect, through the GEP Rider, one-third of the amount by
which the Company's average annual cost of fuel comes in below 96.261 percent of
the average of the other specified utilities. If the Company's fuel cost exceeds
103.739 percent of the stated average, the Company will not be allowed to
recover one-third of the fuel costs above that average from Oklahoma customers.
As explained below, the GEP Rider is currently under review by OCC.
The fuel cost information used to calculate the GEP Rider is based on
fuel cost data submitted by each of the utilities in their Form No. 1 Annual
Report filed with the FERC. The GEP Rider is revised effective July 1 of each
year to reflect any changes in the relative annual cost of fuel reported for the
preceding calendar year. For 1999, the GEP Rider contributed approximately $20.8
million to revenues, which was approximately $9.5 million, or approximately
$0.14 per share lower than 1998. The current GEP Rider is estimated to
positively impact revenue by $13.1 million or approximately $0.19 per share
during the 12 months ending June 2000.
On January 12, 2000, the Staff filed three applications to address
various aspects of the Company's electric rates. Two of the applications were
expected, while the third pertains to recoveries under the Company's fuel
adjustment clause. The first application relates to the completion of the
recovery of the amortization premium paid by the Company when it acquired Enogex
in 1986 and the resulting removal of this $12.8 million from the amounts
currently being paid annually by the Company to Enogex and being recovered by
the Company from its ratepayers. The Company has consented to this action. The
second application relates to a review of the GEP Rider, which, as part of the
OCC's 1997 Order, was scheduled for review in March 2000. The Company collected
approximately $20.8 million pursuant to the GEP Rider during 1999. A hearing on
the GEP Rider is scheduled in May 2000 and the Company intends to support the
retention of the GEP Rider with only minor modifications. The final application
relates to a review of 1999 fuel cost recoveries. The Company assumes that this
application also will be used to address the competitive bid process of its gas
transportation service. The Company cannot predict the precise outcome of these
proceedings at this time, but does not expect that they will have a material
effect on its operations.
6
<PAGE>
As previously reported, on February 13, 1998, the APSC Staff filed a
motion for a show cause order to review the Company's electric rates in the
State of Arkansas. The Staff recommended a $3.1 million annual rate reduction
(based on a test year ended December 31, 1996). The Staff and the Company
reached a settlement for a $2.3 million annual rate reduction, which was
approved by the APSC in August 1999.
STATE RESTRUCTURING INITIATIVES
OKLAHOMA: As previously reported, Oklahoma enacted in April 1997 the
Electric Restructuring Act of 1997 (the "Act"). In June 1998, various amendments
to the Act were enacted. If implemented as proposed, the Act will significantly
affect the Company's future operations. The following summary of the Act does
not purport to be complete and is subject to the specific provisions of the Act,
which is codified at Sections 190.2 et. seq. of Title 17 of the Oklahoma
Statutes.
The Act consists of eight sections, with Section 1 designating the name
of the Act. Section 2 describes the purposes of the Act, which is generally to
restructure the electric industry to provide for more competition and, in
particular, to provide for the orderly restructuring of the electric utility
industry in the State of Oklahoma in order to allow direct access by retail
consumers to the competitive market for the generation of electricity while
maintaining the safety and reliability of the electric system in the state.
The primary goals of a restructured electric utility industry, as set
forth in Section 2 of the Act, are as follows:
1. To reduce the cost of electricity for as many consumers as
possible, helping industry to be more competitive, to create
more jobs in Oklahoma and help lower the cost of government by
reducing the amount and type of regulation now paid for by
taxpayers;
2. To encourage the development of a competitive electricity
industry through the unbundling of prices and services and
separation of generation services from transmission and
distribution services;
3. To enable retail electric energy suppliers to engage in fair and
equitable competition through open, equal and comparable access
to transmission and distribution systems and to avoid wasteful
duplication of facilities;
4. To ensure that direct access by retail consumers to the
competitive market for generation be implemented in Oklahoma by
July 1, 2002; and
5. To ensure that proper standards of safety, reliability and
service are maintained in a restructured electric service
industry.
Section 3 of the Act sets forth various definitions and exempts in large
part several electric cooperatives and municipalities from the Act unless they
choose to be governed by it.
Sections 4, 5 and 6 of the Act are designed to implement the goals of
the Act and provide for various studies and task forces to assess the issues and
consequences associated with the proposed restructuring of the electric utility
industry. In Section 4, the Joint Electric Utility Task Force (the "Joint Task
Force"), which is described below, is directed to undertake a study of all
relevant issues relating to
7
<PAGE>
restructuring the electric utility industry in Oklahoma including, but not
limited to, the issues set forth in Section 4, and to develop a proposed
electric utility framework for Oklahoma. The OCC is prohibited from promulgating
orders relating to the restructuring without prior authorization of the Oklahoma
Legislature. Also, in developing a framework for a restructured electric utility
industry, the OCC is to adhere to fourteen principles set forth in Section 4,
including the following:
1. Appropriate rules shall be promulgated, ensuring that reliable
and safe electric service is maintained.
2. Consumers shall be allowed to choose among retail electric
energy suppliers to help ensure competitive and innovative
markets. A process should be established whereby all retail
consumers are permitted to choose their retail electric energy
suppliers by July 1, 2002.
3. When consumer choice is introduced, rates shall be unbundled to
provide clear price information on the components of generation,
transmission and distribution and any other ancillary charges.
Charges for public benefit programs currently authorized by
statute or the OCC, or both, shall be unbundled and appear in
line item format on electric bills for all classes of consumers.
4. An entity providing distribution services shall be relieved of
its traditional obligation to provide electric supply but shall
have a continuing obligation to provide distribution service for
all consumers in its service territory.
5. The benefits associated with implementing an independent system
planning committee composed of owners of electric distribution
systems to develop and maintain planning and reliability
criteria for distribution facilities shall be evaluated.
6. A defined period for the transition to a restructured electric
utility industry shall be established. The transition period
shall reflect a suitable time frame for full compliance with the
requirements of a restructured utility industry.
7. Electric rates for all consumer classes shall not rise above
current levels throughout the transition period. If possible,
electric rates for all consumers shall be lowered when feasible
as markets become more efficient in a restructured industry.
8. The OCC shall consider the establishment of a distribution
access fee to be assessed to all consumers in Oklahoma connected
to electric distribution systems regulated by the OCC. This fee
shall be charged to cover social costs, capital costs, operating
costs, and other appropriate costs associated with the operation
of electric distribution systems and the provision of electric
services to the retail consumer.
9. Electric utilities have traditionally had an obligation to
provide service to consumers within their established service
territories and have entered into contracts, long-term
investments and federally mandated cogeneration contracts to
meet the needs of consumers. These investments and contracts
have resulted in costs that may not be recoverable in a
competitive restructured market and
8
<PAGE>
thus may be "stranded." Procedures shall be established for
identifying and quantifying stranded investments and for
allocating costs; and mechanisms shall be proposed for recovery
of an appropriate amount of prudently incurred, unmitigable and
verifiable stranded costs and investments. As part of this
process, each entity shall be required to propose a recovery
plan which establishes its unmitigable and verifiable stranded
costs and investments and a limited recovery period designed to
recover such costs expeditiously, provided that the recovery
period and the amount of qualified transition costs shall yield
a transition charge which shall not cause the total price for
electric power, including transmission and distribution
services, for any consumer to exceed the cost per kilowatt-hour
paid on the effective date of this Act during the transition
period. The transition charge shall be applied to all consumers
including direct access consumers, and shall not disadvantage
one class of consumer or supplier over another, nor impede
competition and shall be allocated over a period of not less
than three (3) years nor more than seven (7) years.
10. It is the intent that all transition costs shall be recovered by
virtue of the savings generated by the increased efficiency in
markets brought about by restructuring of the electric utility
industry. All classes of consumers shall share in the transition
costs.
Subject to the principles set forth in Section 4, the Joint Task Force
is directed to prepare a four-part study. As a result of the 1998 amendments,
the time frame for the delivery of the remaining parts of the Study was
accelerated to October 1, 1999. This study addressed: (i) technical issues
(including reliability, safety, unbundling of generation, transmission and
distribution services, transition issues and market power); (ii) financial
issues (including rates, charges, access fees, transition costs and stranded
costs); (iii) consumer issues (such as the obligation to serve, service
territories, consumer choices, competition and consumer safeguards); and (iv)
tax issues (including sales and use taxes, ad valorem taxes and franchise fees).
Section 5 of the Act directs the Joint Task Force to study and submit a
report on the impact of the restructuring of the electric utility industry on
state tax revenues and all other facets of the current utility tax structure on
the state and all political subdivisions of the state. The Oklahoma Tax
Commission and the OCC are precluded from issuing any rules on such matters
without the approval of the Oklahoma Legislature. Also, the Act requires the
establishment, on or before July 1, 2002, of a uniform tax policy that allows
all competitors to be taxed on a fair and equitable basis.
Section 6 creates the Joint Task Force, which shall consist of seven
members from the Oklahoma Senate and seven members from the Oklahoma House of
Representatives. The Joint Task Force is directed to undertake the studies set
forth in Sections 4 and 5 of the Act. The Joint Task Force is permitted to make
final recommendations to the Governor and Oklahoma Legislature. The Joint Task
Force is also empowered to retain consultants to study the creation of an
Independent System Operator, which would coordinate the physical supply of
electricity throughout Oklahoma and maintain reliability, security and stability
of the bulk power system. In addition, such study shall assess the benefits of
establishing a power exchange that would operate as a power pool allowing power
producers to compete on common ground in Oklahoma. In fulfilling its tasks, the
Joint Task Force can appoint advisory councils made up of electric utilities,
regulators, residential customers and other constituencies.
Section 7 provides generally that, with respect to electric distribution
providers, no customer switching will be allowed from the effective date of the
Act until July 1, 2002, except by mutual
9
<PAGE>
consent. It also provides that any municipality that fails to become subject to
the Act will be prohibited from selling power outside its municipal limits,
except from lines owned on the effective date of the Act. Furthermore, this
section provides generally that out-of-state suppliers of electricity and their
affiliates who make retail sales of electricity in Oklahoma, through the use of
transmission and distribution facilities of in-state suppliers, must provide
equal access to their transmission and distribution facilities outside of
Oklahoma. Section 8 sets forth the effective date of the Act as April 25, 1997.
Another provision of the Act enacted in 1998 requires a uniform tax
policy be established by July 1, 2002. The Act was modified during the 1999
session of the Oklahoma Legislature to clarify certain ambiguities by defining
key terms in the Act.
With the completion of the studies described above in October 1999, the
Oklahoma legislature is expected to implement additional legislation, which will
address many specific issues associated with deregulation. Several bills have
already been introduced. While the Company cannot predict the terms of the new
legislation, the Company intends to participate actively in the legislative
process.
The OCC has adopted rules that are designed to make the gas utility
business in Oklahoma more competitive. These rules do not impact the electric
industry. Yet, if implemented, the rules are expected to offer increased
opportunities to Enogex's pipeline and related businesses.
ARKANSAS: In December 1997, the APSC established four generic
proceedings to consider the implementation of a competitive retail electric
market in the State of Arkansas. During 1998, the APSC held hearings to consider
competitive retail generation, market structure, market power, taxation,
recovery and mitigation of stranded costs, service and reliability, low income
assistance, independent system operators and transition issues. The Company
participated actively in those proceedings, and in October 1998 the APSC issued
its report to the Arkansas Legislature recommending competitive retail electric
generation to begin no later than January 1, 2002. Several bills calling for
electric industry restructuring were introduced after the Arkansas General
Assembly began its 1999 session.
In April 1999, Arkansas became the 18th state to pass a law calling for
restructuring of the electric utility industry at the retail level. The new law
targets customer choice of electricity providers by January 1, 2002. The new law
also provides that utilities owning or controlling transmission assets must
transfer control of such transmission assets to an independent system operator,
independent transmission company or regional transmission group, if any such
organization has been approved by the FERC. Other provisions of the new law
permit municipal electric systems to opt in or out, permit recovery of stranded
costs and transition costs and require unbundled rates by July 1, 2000 for
generation, transmission, distribution and customer service. The APSC has
established a timetable to establish rules implementing the Arkansas
restructuring statutes. The new law will significantly affect OG&E's future
Arkansas operations. OG&E's electric service area includes parts of western
Arkansas, including Ft. Smith, the second-largest metropolitan market in the
state.
AUTOMATIC FUEL ADJUSTMENT CLAUSES
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are charged to substantially all of the Company's electric
customers through automatic fuel adjustment clauses, which are subject to
periodic review by the OCC, the APSC and the FERC.
10
<PAGE>
NATIONAL ENERGY LEGISLATION
Federal law imposes numerous responsibilities and requirements on the
Company. The Public Utility Regulatory Policies Act of 1978 requires electric
utilities, such as the Company, to purchase electric power from, and sell
electric power to, qualified cogeneration facilities and small power production
facilities ("QFs"). Generally stated, electric utilities must purchase electric
energy and production capacity made available by QFs at a rate reflecting the
cost that the purchasing utility can avoid as a result of obtaining energy and
production capacity from these sources; rather than generating an equivalent
amount of energy itself or purchasing the energy or capacity from other
suppliers. The Company has entered into agreements with four such cogenerators.
Electric utilities also must furnish electric energy to QFs on a
non-discriminatory basis at a rate that is just and reasonable and in the public
interest and must provide certain types of service which may be requested by QFs
to supplement or back up those facilities' own generation.
The Energy Policy Act of 1992 ("Energy Act") has resulted in some
significant changes in the operations of the electric utility industry and the
federal policies governing the generation, transmission and sale of electric
power. The Energy Act, among other things, authorized the FERC to order
transmitting utilities to provide transmission services to any electric utility,
Federal power marketing agency, or any other person generating electric energy
for sale or resale, at transmission rates set by the FERC. The Energy Act also
is designed to promote competition in the development of wholesale power
generation in the electric industry. It exempts a new class of independent power
producers from regulation under the Public Utility Holding Company Act of 1935.
Within four years of the enactment of the Energy Act, FERC issued Order
888 and Order 889 to facilitate third-party utilization of the transmission grid
as the vehicle for developing a more competitive wholesale bulk power market.
Order 888 requires all transmission owners to (i) offer comparable open-access
transmission service for wholesale transactions under a tariff of general
applicability on file at FERC and (ii) take transmission service for their own
wholesale sales under their open-access tariff. Order 889 requires electric
utilities to functionally separate their transmission and reliability functions
from their wholesale power marketing functions. In this connection, Order 889
required electric utilities to develop and maintain an Open Access Same-Time
Information System ("OASIS") to ensure that transmission customers have access
to transmission information, through electronic means, that will enable them to
obtain open-access transmission service on a basis comparable to a transmitting
utility's own use of its system.
The Company is a member of the Southwest Power Pool ("SPP"), the
regional reliability organization for Oklahoma, Arkansas, Kansas, Louisiana,
Missouri and part of Texas. The Company participated with the SPP in the
development of regional transmission tariffs and executed an agency agreement
with the SPP to facilitate interstate transmission operations within this
region. The SPP has asked for FERC recognition as an Independent System Operator
("ISO") consistent with FERC's ISO guidelines in its Order 888.
Another impact of complying with FERC's Order 888 is a requirement for
utilities to offer a transmission tariff that includes network transmission
service ("NTS") to transmission customers. NTS allows transmission service
customers to fully integrate load and resources on an instantaneous basis, in a
manner similar to how the Company has historically integrated its load and
resources. Under NTS, the Company and participating customers share the total
annual transmission cost for their combined joint-use systems, net of related
transmission revenues, based upon each company's share of the total system load.
Management expects minimal annual expenses as a result of Orders 888 and 889.
11
<PAGE>
In December 1999, FERC issued Order 2000 to advance the formation of
Regional Transmission Organizations ("RTO"). The rule requires that each public
utility that owns, operates or controls facilities for the transmission of
electric energy in interstate commerce file by October 15, 2000, a proposal with
respect to forming and participating in an RTO. The FERC also codified minimum
characteristics and functions that a transmission entity must satisfy in order
to be considered an RTO. The FERC's goal is to promote efficiency in wholesale
electricity markets and to ensure that electricity consumers pay the lowest
price possible for reliable service. The FERC expects that the RTOs will be
operational by December 15, 2001.
REGULATORY ASSETS AND LIABILITIES
As discussed previously, Oklahoma and Arkansas enacted legislation that
will restructure the electric utility industry in those states, assuming that
all the conditions in the legislation are met. This legislation would deregulate
the Company's electric generation assets and the continued use of Statement of
Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of
Certain Types of Regulation", with respect to the related regulatory assets may
no longer be appropriate. This may result in either full recovery of
generation-related regulatory assets (net of related regulatory liabilities) or
a non-cash, pre-tax write-off as an extraordinary charge of up to $30 million,
depending on the transition mechanisms developed by the legislature for the
recovery of all or a portion of these net regulatory assets.
The enacted Oklahoma and Arkansas legislation does not affect the
Company's electric transmission and distribution assets and the Company believes
that the continued use of SFAS No. 71 with respect to the related regulatory
assets is appropriate. However, if utility regulators in Oklahoma and Arkansas
were to adopt regulatory methodologies in the future that are not based on
cost-of-service, the continued use of SFAS No. 71 with respect to the regulatory
assets related to the electric transmission and distribution assets may no
longer be appropriate.
Based on a current evaluation of the various factors and conditions that
are expected to impact future cost recovery, management believes that its
regulatory assets, including those related to generation, are probable of future
recovery.
SUMMARY
The Energy Act, the actions of the FERC, the restructuring proposal in
Oklahoma, the Arkansas legislation and other factors are expected to
significantly increase competition in the electric industry. The Company has
taken steps in the past and intends to take appropriate steps in the future to
remain a competitive supplier of electricity. Past actions include a redesign
and restructuring effort in 1994 and continuing actions to reduce fuel costs,
improvements in customer service, installation of the SAP Enterprise Software
and efforts to improve the Company's electric transmission and distribution
network to reduce outages, all of which enhance the Company's ability to deliver
electricity competitively. While the Company is supportive of competition, it
believes that all electric suppliers must be required to compete on a fair and
equitable basis and the Company is advocating this position vigorously.
RATE STRUCTURE, LOAD GROWTH
AND RELATED MATTERS
Two of the Company's primary goals are: (i) to increase electric
revenues by attracting and expanding job-producing businesses and industries;
and (ii) to encourage the efficient electrical energy
12
<PAGE>
use by all of the Company's customers. In order to meet these goals, the Company
has reduced and restructured its rates to its customers. At the same time, the
Company had implemented numerous energy efficiency programs and tariff
schedules. In 1999, these programs and schedules included: (i) the "Surprise
Free Guarantee" program, which guarantees residential customers comfort and
annual energy consumption for heating, cooling and water heating for new homes
built to energy efficient standards; (ii) a load curtailment rate for industrial
and commercial customers who can demonstrate a load curtailment of at least 500
kilowatts; and (iii) the time-of-use rate schedules for various commercial,
industrial and residential customers designed to shift energy usage from peak
demand periods during the hot summer afternoon to non-peak hours.
The Company made it's pilot Real Time Pricing ("RTP") program permanent
in 1999. The program was first implemented in 1996 for qualifying industrial and
commercial customers. This tariff gives customers additional options on total
kilowatt-hour growth and the control of growth of peak demand. RTP is a tariff
option, which prices electricity so that the current price varies hourly with
short notice to reflect current expected costs. The RTP technique will allow a
measure of competitive pricing, a broadening of customer choice, the balancing
of electricity usage and capacity in the short-and long-term, and provide
customers assistance in controlling their costs.
The Company's 1999 marketing efforts included geothermal heat pumps,
electrotechnologies, electric food service promotion and a heat pump promotion
in the residential, commercial and industrial markets. The Company works closely
with individual customers to provide the best information on how current
technologies can be combined with the Company's marketing programs to maximize
the customer's benefit.
Electric and magnetic fields ("EMFs") surround all electric tools and
appliances, internal home wiring and external power lines such as those owned by
the Company. During the last several years considerable attention has focused on
possible health effects from EMFs. While some studies indicate a possible weak
correlation, other similar studies indicate no correlation between EMFs and
health effects. As part of the Energy Act Congress established the National EMF
Research and Public Information Dissemination ("RAPID") Program to address the
question of whether EMF posed a risk to human health. In the National Institute
of Environmental Health Sciences ("NIEHS") report of June 1999 with regard to
the findings of RAPID, it is concluded that it is their belief that the
probability of EMF exposure truly being a health hazard is currently small. The
nation's electric utilities, including the Company, have participated with the
Electric Power Research Institute ("EPRI") in the sponsorship of more than $75
million in research to determine the possible health effects of EMFs. In
addition, during the past decade the Company has cooperatively funded Edison
Electric Institute ("EEI") research to study the possible health effects of
EMFs. Through its participation with the EPRI and EEI, the Company will continue
its support of the research with regard to the possible health effects of EMFs.
The Company is dedicated to delivering electric service in a safe, reliable,
environmentally acceptable and economical manner.
FUEL SUPPLY
During 1999, approximately 71 percent of the Company-generated energy
was produced by coal-fired units and 29 percent by natural gas-fired units. A
slight decline in the percentage of coal generation in future years is expected
to result from increases in natural gas-fired generation required to meet
growing energy needs while coal generation will remain fairly constant. Over the
last 5 years, the average cost of fuel used, by type, per million Btu was as
follows:
13
<PAGE>
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Coal............................ $0.85 $0.85 $0.84 $0.83 $0.83
Natural Gas..................... $3.14 $2.83 $3.60 $3.61 $3.19
Weighted Avg.................... $1.54 $1.48 $1.39 $1.45 $1.41
</TABLE>
A portion of the fuel cost is included in base rates and differs for
each jurisdiction. The portion of these costs that is not included in base rates
is recovered through automatic fuel adjustment clauses. See "Electric Operations
- - Regulation and Rates - Automatic Fuel Adjustment Clauses."
COAL-FIRED UNITS: All the Company coal units, with an aggregate
-----------------
capability of 2,493 megawatts, are designed to burn low sulfur western coal. The
Company purchases coal under a mix of long- and short-term contracts. During
1999, the Company purchased 11.5 million tons of coal from the following Wyoming
suppliers: Caballo Rojo Complex, Kennecott Energy Company, Thunder Basin Coal
Company, Powder River Coal Company, and Triton Coal Company. The combination of
all coals has a weighted average sulfur content of 0.3 percent and can be burned
in these units under existing federal, state and local environmental standards
(maximum of 1.2 pounds of sulfur dioxide per million Btu) without the addition
of sulfur dioxide removal systems. Based upon the average sulfur content, the
Company units have an approximate emission rate of 0.63 pounds of sulfur dioxide
per million Btu. In anticipation of the more strict provisions of Phase II of
The Clean Air Act, starting in the year 2000, the Company has contracts in place
that will allow for a supply of very low sulfur coal from suppliers in the
Powder River Basin to meet the new sulfur dioxide standards.
The Company has continued its efforts to maximize the utilization of its
coal units by optimizing the boiler operations at both the Sooner and Muskogee
generating plants. See "Environmental Matters" for a discussion of an
environmental proposal that, if implemented as proposed, could inhibit the
Company's ability to use coal as its primary boiler fuel.
GAS-FIRED UNITS: For calendar year 2000, the Company expects to acquire
----------------
less than 1 percent of its gas needs from long-term gas purchase contracts. The
remainder of the Company's gas needs during 2000 will be supplied by contracts
with at-market pricing. These volumes of gas will be acquired through day-to-day
purchases on the spot market, as well as monthly purchase agreements.
In 1993, the Company began utilizing a natural gas storage facility
which helps lower fuel costs by allowing the Company to optimize economic
dispatch between fuel types and take advantage of seasonal variations in natural
gas prices. By diverting gas into storage during low demand periods, the Company
is able to use as much coal as possible to generate electricity and utilize the
stored gas to meet the additional demand for electricity.
ENVIRONMENTAL MATTERS
The Company's management believes all of its operations are in
substantial compliance with present federal, state and local environmental
standards. It is estimated that the Company's total expenditures for capital,
operating, maintenance and other costs to preserve and enhance environmental
quality will be approximately $44.4 million during 2000, compared to
approximately $43.0 million utilized in 1999. Approximately $1.0 million of the
Company's construction expenditures budgeted for 2000 are to comply with
environmental laws and regulations. The Company continues to evaluate its
14
<PAGE>
environmental management systems to ensure compliance with existing and proposed
environmental legislation and regulations and to better position itself in a
competitive market.
As required by Title IV of the Clean Air Act Amendments of 1990
("CAAA"), the Company has completed installation and certification of all
required continuous emissions monitors ("CEMs") at its generating stations. The
Company submits emissions data quarterly to the Environmental Protection Agency
("EPA") as required by the CAAA. Phase II sulfur dioxide ("SO2") emission
requirements will affect the Company beginning in the year 2000. Based on
current information, the Company believes it can meet the SO2 limits without
additional capital expenditures. In 1999, the Company emitted 54,845 tons of
SO2.
With respect to the nitrogen oxide ("NOx") regulations of Title IV of
the CAAA, OG&E committed to meeting a 0.45 lbs/mmbtu NOx emission level in 1997
on all coal-fired boilers. As a result, the Company was eligible to exercise its
option to extend the effective date of the lower emission requirements from the
year 2000 until 2008. The Company's average NOx emissions from its coal-fired
boilers for 1999 was 0.37 lbs/mmbtu.
The Company has submitted all of its required Title V permit
applications. As a result of the Title V Program, the Company paid approximately
$0.4 million in fees in 1999.
Other potential air regulations have emerged that could impact the
Company. By December 15, 2000, the EPA is expected to decide whether or not to
regulate mercury emissions from coal-fired utility boilers. If the decision is
made to regulate them, limits on the amount of mercury emitted are expected to
be proposed by December 2003 with company compliance required by 2008.
In 1997, EPA finalized revisions to the ambient ozone and particulate
standards. However, the standards were challenged in court and the ozone
standard was subsequently remanded back to EPA for further consideration. EPA
has appealed the decision to the US Supreme Court. If the proposed standard is
upheld, then it is likely that Tulsa and Oklahoma Counties will fail to meet the
new standard for ozone. In addition, EPA projects that Muskogee, Kay, Tulsa and
Comanche Counties in Oklahoma would fail to meet the standard for particulate
matter. If reductions are required in Muskogee, Kay and Oklahoma Counties,
significant capital expenditures could be required by the Company.
EPA has issued regulations concerning regional haze. This regulation is
intended to protect visibility in national parks and wilderness areas throughout
the United States. In Oklahoma, the Wichita Mountains would be the only area
covered under the regulation. Emissions of sulfates and nitrate aerosols (both
emitted from coal-fired boilers) can lead to the degradation of visibility. It
is possible that controls on sources hundreds of miles away from the affected
area may be required. EPA and the states will perform studies of the areas to
determine what if any controls are needed in Oklahoma. Both Sooner and Muskogee
Generating Stations could face significant capital expenditures if reductions
are required.
In December 1997, the United States was a signatory to the Kyoto
Protocol for the reduction of greenhouse gases that contribute to global
warming. The U.S. committed to a 7 percent reduction from the 1990 levels. If
the Senate ratifies the Kyoto Protocol, this reduction could have a significant
impact on the Company's use of coal as a boiler fuel. Based on current load and
fuel budget projections, a 7 percent reduction of greenhouse gases would require
the Company to substantially increase gas burning in the year 2008 and to
significantly reduce its use of coal as a boiler fuel. Since there are numerous
issues which will affect how this reduction would be implemented, if at all, the
cost to the Company to comply with this reduction cannot be established at this
time, but is expected to be substantial.
15
<PAGE>
The Company has and will continue to seek new pollution prevention
opportunities and to evaluate the effectiveness of its waste reduction, reuse
and recycling efforts. In 1999, the Company obtained refunds of approximately
$355,225 from its recycling efforts. This figure does not include the additional
savings gained through the reduction and/or avoidance of disposal costs and the
reduction in material purchases due to reuse of existing materials. Similar
savings are anticipated in future years.
The Company has received renewal of all of its Oklahoma Pollution
Discharge Elimination System ("OPDES") permits for all facilities except one,
which is pending regulatory action. All of the renewed permits issued to date
offer greater operational flexibility than those in the past. In addition, the
Company has made application for a new OPDES permit to cover Gas Turbine
generating units currently being constructed at one of our existing power
plants. No problems are foreseen in the ultimate regulatory approval of this
permit.
The Company requested that the State agency responsible for the
development of Water Quality Standards remove the agriculture beneficial use
classification from one of its cooling water reservoirs. Without removal of
this classification, the Company facility could be subjected to costly treatment
and/or facility reconfiguration requirements. The State has approved the request
and EPA, in their review of Oklahoma's Water Quality Standards, has not
disapproved this issue.
The Company remains a party to two separate actions brought by the EPA
concerning cleanup of disposal sites for hazardous and toxic waste. See "Item 3.
Legal Proceedings."
The Company has and will continue to evaluate the impact of its
operations on the environment. As a result, contamination on Company property
may be discovered from time to time. One site has been identified as having
been contaminated by historical operations. Remedial options based on the future
use of this site are being pursued with appropriate regulatory agencies. The
cost of these actions has not had and is not anticipated to have a material
adverse impact on the Company's financial position or results of operations.
16
<PAGE>
ITEM 2. PROPERTIES.
- ------------------
The Company owns and operates an interconnected electric production,
transmission and distribution system, located in Oklahoma and western Arkansas,
which includes eight active generating stations with an aggregate active
capability of 5,513 megawatts. The following table sets forth information with
respect to present electric generating facilities, all of which are located in
Oklahoma:
<TABLE>
<CAPTION>
Unit Station
Year Capability Capability
Station & Unit Fuel Installed (Megawatts) (Megawatts)
- -------------- ---- --------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Seminole 1 Gas 1971 517.0
2 Gas 1973 505.0
3 Gas 1975 496.0 1,518
Muskogee 3 Gas 1956 171.0
4 Coal 1977 515.0
5 Coal 1978 478.0
6 Coal 1984 488.0 1,652
Sooner 1 Coal 1979 500.0
2 Coal 1980 512.0 1,012
Horseshoe 6 Gas 1958 171.0
Lake 7 Gas 1963 234.0
8 Gas 1969 390.0 795
Mustang 1 Gas 1950 58.0 Inactive
2 Gas 1951 57.0 Inactive
3 Gas 1955 118.0
4 Gas 1959 239.0
5 Gas 1971 63.0 420
Conoco 1 Gas 1991 32.0
2 Gas 1991 31.0 63
Arbuckle 1 Gas 1953 74.0 Inactive
Enid 1 Gas 1965 11.0
2 Gas 1965 8.0
3 Gas 1965 12.0
4 Gas 1965 12.0 43
Woodward 1 Gas 1963 10.0 10
-----------
Total Active Generating Capability (all stations) 5,513
===========
</TABLE>
17
<PAGE>
At December 31, 1999, the Company's transmission system included: (i) 65
substations with a total capacity of approximately 15.5 million kVA and
approximately 3,997 structure miles of lines in Oklahoma; and (ii) six
substations with a total capacity of approximately 1.9 million kVA and
approximately 241 structure miles of lines in Arkansas. The Company's
distribution system included: (i) 301 substations with a total capacity of
approximately 4.2 million kVA, 20,205 structure miles of overhead lines, 1,700
miles of underground conduit and 6,924 miles of underground conductors in
Oklahoma; and (ii) 30 substations with a total capacity of approximately 737,500
kVA, 1,684 structure miles of overhead lines, 186 miles of underground conduit
and 397 miles of underground conductors in Arkansas.
Substantially all of the Company's electric facilities were previously
subject to a direct first mortgage lien under the Trust Indenture securing the
Company's first mortgage bonds. The Trust Indenture and related lien were
discharged in April 1998.
During the three years ended December 31, 1999, the Company's gross
property, plant and equipment additions approximated $282.7 million and gross
retirements approximated $110.4 million. These additions were provided by
internally generated funds from operating cash flows, permanent financing and
short-term borrowings. The additions during this three-year period amounted to
approximately 7.5 percent of total property, plant and equipment at
December 31, 1999.
ITEM 3. LEGAL PROCEEDINGS.
- -------------------------
1. On July 8, 1994, an employee of the Company filed a lawsuit in state
court against the Company in connection with the Company's VERP. The case was
removed to the U.S. District Court in Tulsa, Oklahoma. On August 23, 1994, the
trial court granted the Company's Motion to Dismiss Plaintiff's Complaint in its
entirety.
On September 12, 1994, Plaintiff, along with two other Plaintiffs, filed
an Amended Complaint alleging substantially the same allegations, which were in
the original complaint. The action was filed as a class action, but no motion to
certify a class was ever filed. Plaintiffs want credit, for retirement purposes,
for years they worked prior to a pre-ERISA (1974) break in service. They allege
violations of ERISA, the Veterans Reemployment Act, Title VII, and the Age
Discrimination in Employment Act. State law claims, including one for
intentional infliction of emotional distress, are also alleged.
On October 10, 1994, Defendants filed a Motion to Dismiss Counts II, IV,
V, VI and VII of Plaintiffs' Amended Complaint. With regard to Counts I and III,
Defendants filed a Motion for Summary Judgment on January 18, 1996. On September
8, 1997, the United States Magistrate Judge recommended the Defendant's motions
to dismiss and for summary judgment should be granted and that the case be
dismissed in its entirety and judgment entered for the Company. The United
States District Judge accepted the recommendation of the Magistrate and entered
judgment for the Company. Plaintiffs filed an appeal with the Tenth Circuit
Court of Appeals. In August 1999, the Tenth Circuit affirmed in all respects the
District Courts' decision dismissing Plaintiff's case and entering judgment for
the Company. Since the Plaintiffs have failed to file a timely writ of
certiorari to the U.S. Supreme Court, the Company considers this case closed.
2. On January 11, 1993, the Company received a Section 107 (a) Notice
Letter from the EPA, Region VI, as authorized by the CERCLA, 42 USC Section 9607
(a), concerning the Double Eagle Refinery Superfund Site located at 1900 NE
First Street in Oklahoma City, Oklahoma. The EPA has named the Company and 45
others as PRPs. Each PRP could be held jointly and severally liable for
remediation of this site.
18
<PAGE>
On February 15, 1996, the Company elected to participate in the de
minimis settlement of EPA's Administrative Order on Consent. This would limit
the Company's financial obligation and also would eliminate its involvement in
the design and implementation of the site remedy. A third party is currently
contesting the Company's participation as a de minimis party. Regardless of the
outcome of this issue, the Company believes that its ultimate liability for this
site will not be material primarily due to the limited volume of waste sent by
the Company to the site.
3. As previously reported, on September 18, 1996, Trigen-Oklahoma City
Energy Corporation ("Trigen") sued the Company in the United States District
Court, Western District of Oklahoma, Case No. CIV-96-1595-M. Trigen alleged six
causes of action: (i) monopolization in violation of Section 2 of the Sherman
Act; (ii) attempt to monopolize in violation of Section 2 of the Sherman Act;
(iii) acts in restraint of trade in violation of Oklahoma law, 79 O.S. 1991,
1; (iv) discriminatory sales in violation of 79 O.S. 1991, 4; (v) tortious
interference with contract; and (vi) tortious interference with a prospective
economic advantage. On December 21, 1998, the jury awarded Trigen in excess of
$30 million in actual and punitive damages. On February 19, 1999, the trial
court entered judgment in favor of Trigen as follows: (i) $6.8 million for
various antitrust violations, (ii) $4 million for tortious interference with an
existing contract, (iii) $7 million for tortious interference with a prospective
economic advantage and (iv) $10 million in punitive damages. The trial judge, in
a companion order, acknowledged that the portions of the judgment could be
duplicative, that the antitrust amounts could be tripled and that parties should
address these issues in their post-trial motions. On March 5, 1999, the Company
filed its post trial motions requesting judgment in its favor as a matter of
law, a new trial and a reduction in amount of any judgment to eliminate
duplication of damages. On January 25, 2000, a trial judge rejected the
Company's post-trial motions to reverse the jury verdict or to grant the Company
a new trial. The judge did, however, reduce the original $30 million judgment
against the Company to $20 million. On February 4, 2000, the Company filed a
notice of appeal. In addition, Trigen has filed a motion seeking attorneys' fees
and costs in an amount over $3 million. Trigen will not be entitled to
attorneys' fees or costs unless it prevails on appeal. While the outcome of the
appeal is uncertain, legal counsel and management believe that it is not
probable that Trigen will ultimately succeed in preserving the verdicts or
judgment. Accordingly, the Company has not accrued any loss associated with the
damages awarded. The Company believes that the ultimate resolution of this case
will not have a material adverse effect on the Company's financial position or
results of operations.
4. The City of Enid, Oklahoma ("Enid") through its City Council,
notified the Company of its intent to purchase the Company's electric
distribution facilities for Enid and to terminate the Company's franchise to
provide electricity within Enid as of June 26, 1998. On August 22, 1997, the
City Council of Enid adopted Ordinance No. 97-30, which in essence granted the
Company a new 25-year franchise subject to approval of the electorate of Enid on
November 18, 1997. In October 1997, eighteen residents of Enid filed a lawsuit
against Enid, the Company and others in the District Court of Garfield County,
State of Oklahoma, Case No. CJ-97-829-01. Plaintiffs seek a declaration holding
that (i) the Mayor of Enid and the City Council breached their fiduciary duty to
the public and violated Article 10, Section 17 of the Oklahoma Constitution by
allegedly "gifting" to the Company the option to acquire the Company's electric
system when the City Council approved the new franchise by Ordinance No. 97-30;
(ii) the subsequent approval of the new franchise by the electorate of the City
of Enid at the November 18, 1997, franchise election cannot cure the alleged
breach of fiduciary duty or the alleged constitutional violation; (iii)
violations of the Oklahoma Open Meetings Act occurred and that such violations
render the resolution approving Ordinance No. 97-30 invalid; (iv) the Company's
support of the Enid Citizens' Against the Government Takeover was improper; (v)
the Company has violated the favored nations clause of the existing franchise;
and (vi) the City of Enid and the Company have violated the competitive bidding
requirements found at 11 O.S. 35-201, ET. SEQ. Plaintiffs seek money damages
against the Defendants under 62 O.S. 372 and 373. Plaintiffs allege that the
action of the City Council in approving the proposed franchise allowed the
option to purchase the
19
<PAGE>
Company's property to be transferred to the Company for inadequate
consideration. Plaintiffs demand judgment for treble the value of the property
allegedly wrongfully transferred to the Company. On October 28, 1997, another
resident filed a similar lawsuit against the Company, Enid and the Garfield
County Election Board in the District Court of Garfield County, State of
Oklahoma, Case No. CJ-97-852-01. However, Case No. CJ-97-852-01 was dismissed
without prejudice in December 1997. On December 8, 1997, OG&E filed a Motion to
Dismiss Case No. CJ-97-829-01 for failure to state claims upon which relief may
be granted. This motion is currently pending. While the Company cannot predict
the precise outcome of this proceeding, the Company believes at the present time
that this lawsuit is without merit and intends to vigorously defend this case.
5. United States of America ex rel., Jack J. Grynberg v. Enogex Inc.,
Enogex Services Corporation (now, Resources) and Oklahoma Gas and Electric
Company. (United States District Court for the Western District of Oklahoma,
Case No. CIV-97-1010-L.) United States of America ex rel., Jack J. Grynberg v.
Transok Inc. et al. (United States District Court for the Eastern District of
Louisiana, Case No. 97-2089; United States District Court for the Western
District of Oklahoma, Case No. 97-1009M.) On June 15, 1999, the Company was
served with Plaintiff's Complaint. Plaintiff's action is a qui tam action under
the False Claims Act. Jack J. Grynberg, as individual Relator on behalf of the
United States Government, Plaintiff, alleges: (i) each of the named Defendants
have improperly and intentionally mismeasured gas (both volume and BTU content)
purchased from federal and Indian lands which have resulted in the
under-reporting and underpayment of gas royalties owed to the Federal
Government; (ii) certain provisions generally found in gas purchase contracts
are improper; (iii) transactions by affiliated companies are not arms-length;
(iv) excess processing cost deduction; and (v) failure to account for production
separated out as a result of gas processing. Grynberg seeks the following
damages: (a) additional royalties which he claims should have been paid to the
Federal Government, some percentage of which Grynberg, as Relator, may be
entitled to recover; (b) treble damages; (c) civil penalties; (d) an order
requiring Defendants to measure the way Grynberg contends is the better way to
do so; (e) interest, costs and attorneys' fees. Plaintiff has filed over
70 other cases naming over 300 other defendants in various Federal Courts across
the country containing nearly identical allegations.
In qui tam actions, the United States Government can intervene and take
over such actions from the Relator. The Department of Justice, on behalf of the
United States Government, has decided not to intervene in this action or any of
the other Grynberg qui tam actions.
On November 16, 1999, the Multidistrict Litigation Panel ("MDL Panel")
entered its order transferring and consolidating for pretrial purposes
approximately 76 other similar actions filed in nine other Federal Courts. The
consolidated cases are now before the United States District Court for the
District of Wyoming.
On November 17, 1999, the Company filed a motion to dismiss, seeking:
(i) a stay of discovery until after the dispositive motions are resolved; and
(ii) dismissal of the complaint on various basis under the Federal Rules of
Civil Procedure. A number of other defendants adopted the Company's pleadings or
filed similar motions. On December 22, 1999, the Company joined a number of
other Defendants in filing Defendants' Statement of Points and Authorities
regarding discovery issues. Grynberg's responses to all motions to dismiss were
filed on January 14, 2000, and the Company's reply and those of other defendants
were filed on February 14, 2000. A hearing on the motions to dismiss was held on
March 17, 2000.
20
<PAGE>
On December 15, 1999, the Court held a Pretrial conference for all
MDL-consolidated cases. A number of issues were discussed at such Pretrial
conference and the above-listed schedule was established. All discovery is
stayed until further order of the Court.
While the Company cannot predict the precise outcome of this proceeding,
the Company believes at the present time that this lawsuit is without merit and
intends to vigorously defend this case.
6. On September 28, 1999, the Company was served with an Amended Class
Action Petition filed in United States District Court, State of Kansas by
Quingue Operating Company, on behalf of itself and others, alleging
approximately 200 defendants, including the Company, Enogex and two
subsidiaries of Enogex, including Transok, have improperly and intentionally
mismeasured gas (both volume and Btu content) purchased from all lands in the
United States except from federal and Indian lands. Plaintiffs claim (i)
underpayment by the Company and all other Defendants of gas royalties claimed to
be owed to the Plaintiffs and the punitive class; (ii) breach of contract; (iii)
negligence or intentional misrepresentation; (iv) civil conspiracy; (v) fraud;
and (vi) breach of fiduciary duty. Plaintiffs seek the following damages: (i)
actual damages in excess of $75,000; (ii) punitive damages; (iii) certification
of the class; and (iv) injunction to prevent mismeasurement in the future.
On October 5, 1999, the Company filed its notice with the MDL Panel
advising the MDL Panel that this case involved the same measurement issues and
was a potential tag-along to the Grynberg matter discussed in Item No. 5 above.
Plaintiffs opposed the MDL Panel transfer. The MDL Panel has scheduled a hearing
on the transfer issue for March 30, 2000.
On October 28, 1999, the Company and a number of the Defendants filed a
Joint Request for Extension or Enlargement of Time to Answer or Otherwise
Respond to the First Amended Class Action filed. On December 1, 1999, the Court
granted the Company, and all other Defendants who requested relief, until thirty
(30) days after the Court rules on Plaintiffs' Motion to Remand for the Company
to answer or otherwise plead in this case. There has been no ruling to date on
the Plaintiffs' Motion to Remand.
While the Company cannot predict the precise outcome of this proceeding,
the Company believes at the present time that this lawsuit is without merit and
intends to vigorously defend this case.
21
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------
The following persons were Executive Officers of the Registrant as of
March 15, 2000:
<TABLE>
<CAPTION>
Name Age Title
- -------------------- --- --------------------------------------
<S> <C> <C>
Steven E. Moore 53 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 56 Executive Vice President and
Chief Operating Officer
James R. Hatfield 42 Senior Vice President,
Chief Financial Officer and
Treasurer
Jack T. Coffman 56 Senior Vice President - Power
Supply - OG&E
Melvin D. Bowen, Jr. 58 Vice President - Power Delivery - OG&E
Michael G. Davis 50 Vice President - Marketing and
Customer Care
Irma B. Elliott 61 Vice President and
Corporate Secretary
Steven R. Gerdes 43 Vice President - Shared
Services
David J. Kurtz 38 Vice President - Business
Development
Donald R. Rowlett 42 Vice President and Controller
Don L. Young 59 Controller Corporate Audits
</TABLE>
No family relationship exists between any of the Executive Officers of
the Registrant. Messrs. Moore, Strecker, Hatfield, Davis, Gerdes, Kurtz,
Rowlett, Young and Ms. Elliott are also officers of Energy Corp. Each Officer
is to hold office until the Board of Directors meeting following the next Annual
Meeting of Shareowners, currently scheduled for May 18, 2000.
22
<PAGE>
The business experience of each of the Executive Officers of the
Registrant for the past five years is as follows:
<TABLE>
<CAPTION>
Name Business Experience
- -------------------- ------------------------------------------------
<S> <C> <C>
Steven E. Moore 1996-Present: Chairman of the Board,
President and Chief
Executive Officer
1995-1996: President and Chief
Operating Officer
1995: Senior Vice President - Law
and Public Affairs
Al M. Strecker 1998-Present: Executive Vice President and
Chief Operating Officer
1996-1998: Senior Vice President
1995-1998: Senior Vice President -
Finance and
Administration
James R. Hatfield 1999-Present: Senior Vice President,
Chief Financial Officer
and Treasurer
1997-1999: Vice President and Treasurer
1995-1997: Treasurer
Jack T. Coffman 1999-Present: Senior Vice President -
Power Supply
1995-1999: Vice President -
Power Supply
Melvin D. Bowen, Jr. 1995-Present: Vice President -
Power Delivery
Michael G. Davis 1998-Present: Vice President - Marketing
and Customer Care
1995-1998: Vice President -
Marketing and Customer
Services
</TABLE>
23
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
Irma B. Elliott 1996-Present: Vice President and
Corporate Secretary
1995-1996: Corporate Secretary
Steven R. Gerdes 1998-Present: Vice President - Shared
Services
1997-1998: Director - Shared Services
1997: Manager - Enterprise Support
1995-1997: Manager - Purchasing and
Material Management
David J. Kurtz 1999-Present: Vice President - Business
Development
1997-1999: Vice President - Business
Development -
Enogex Inc.
1995-1997: Director - Gas Supply -
Enogex Inc.
Donald R. Rowlett 1999-1996: Vice President and Controller
1996-1999: Controller Corporate
Accounting
1995-1996: Assistant Controller
Don L. Young 1996-Present: Controller Corporate
Audits
1995-1996: Controller
</TABLE>
24
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
- ---------------------------------------------------------
STOCKHOLDER MATTERS.
- -------------------
Currently, all Company common stock, 40,378,745 shares, is held by
Energy Corp. Therefore, there is no public trading market for the Company's
common stock.
25
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA.
- -------------------------------
<TABLE>
<CAPTION>
HISTORICAL DATA
(1)
-----------
1999 1998 1997 1996 1995
---------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS EXCEPT
FOR PER SHARE DATA)
Operating revenues................. $1,286,844 $1,312,078 $1,191,690 $1,200,337 $1,168,287
Operating expenses................. 1,017,280 996,281 945,652 952,811 921,955
----------- ----------- ----------- ----------- -----------
Operating income................... 269,564 315,797 246,038 247,526 246,332
Other income and deductions........ 381 (5) 3,627 (1,429) 3,708
Interest charges................... 45,939 48,871 55,947 59,566 70,745
----------- ----------- ----------- ----------- -----------
Earnings before income taxes....... 224,006 266,921 193,718 186,531 179,295
Provision for income taxes......... 84,965 106,583 72,724 69,662 66,751
----------- ----------- ----------- ----------- -----------
Net income......................... 139,041 160,338 120,944 116,869 112,544
Preferred dividend
requirements..................... --- 733 2,285 2,302 2,316
----------- ----------- ----------- ----------- -----------
Earnings available for
common........................... $ 139,041 $ 159,605 $ 118,709 $ 114,567 $ 110,228
=========== =========== =========== =========== ===========
Long-term debt..................... $ 593,045 $ 702,912 $ 691,924 $ 709,281 $ 723,862
Total assets....................... $2,320,660 $2,320,097 $2,350,782 $2,421,241 $2,754,871
Earnings per average common
share............................ $ 3.44 $ 3.95 $ 2.94 $ 2.84 $ 2.73
CAPITALIZATION RATIOS
Common equity...................... 59.99% 54.84% 53.46% 52.57% 54.78%
Cumulative preferred stock......... --- --- 3.09% 3.09% 2.92%
Long-term debt..................... 40.01% 45.16% 43.45% 44.34% 42.30%
INTEREST COVERAGES
Before federal income taxes
(including AFUDC)................ 5.80X 6.34X 4.43X 4.09X 3.49X
(excluding AFUDC)................ 5.79X 6.32X 4.42X 4.08X 3.47X
After federal income taxes
(including AFUDC)................ 3.98X 4.21X 3.14X 2.94X 2.56X
(excluding AFUDC)................ 3.96X 4.19X 3.13X 2.93X 2.55X
</TABLE>
(1) REORGANIZATION
OGE Energy Corp. ("Energy Corp.") became the parent company of the
Company and its former subsidiary, Enogex, Inc. ("Enogex") on December 31, 1996.
On that date, all outstanding Company common stock was exchanged on a
share-for-share basis for common stock of Energy Corp. and the Company
distributed its ownership of Enogex to Energy Corp. Although Enogex continues to
operate as a subsidiary of Energy Corp., for purposes of this historical data,
Enogex has been accounted for as discontinued operations.
26
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- --------------------------------------------------------------------------------
OF OPERATIONS.
- -------------
MANAGEMENT'S DISCUSSION AND ANALYSIS.
OVERVIEW
<TABLE>
<CAPTION>
Percent Change
From Prior Year
---------------
(THOUSANDS EXCEPT PER SHARE AMOUNTS) 1999 1998 1997 1999 1998
==================================================================================================
<S> <C> <C> <C> <C> <C>
Operating revenues...................... $1,286,844 $1,312,078 $1,191,690 (1.9) 10.1
Earnings available for common stock..... $ 139,041 $ 159,605 $ 118,709 (12.9) 34.5
Average shares outstanding.............. 40,379 40,379 40,379 --- ---
Earnings per average common share....... $ 3.44 $ 3.95 $ 2.94 (12.9) 34.4
Dividends paid per share................ $ 2.56 $ 3.90 $ 2.68 (34.4) 45.5
==================================================================================================
</TABLE>
Earnings for 1999 decreased 12.9 percent from $3.95 per share in 1998 to
$3.44 per share in 1999. The decrease was primarily the result of lower revenues
due to cooler weather, lower recoveries under the Generation Efficiency
Performance Rider ("GEP Rider"), lower margin sales to other utilities and power
marketers ("off-system sales"), and was partially offset by continued customer
growth and lower interest charges. The GEP Rider allows the Company to retain
part of the fuel savings achieved through cost efficiencies and is discussed in
more detail below. The 1998 increase is primarily the result of higher revenues
due to warmer weather, the GEP Rider, higher margin off-system sales, customer
growth and lower operation and maintenance expenses.
The regulated utility business has been and will continue to be affected
by competitive changes to the utility industry. Significant changes already have
occurred in the wholesale electric markets at the Federal level. In Oklahoma,
legislation was passed in 1997 to provide for the orderly restructuring of the
electric industry with the goal to provide retail customers with the ability to
choose their generation suppliers by July 1, 2002. In April 1999, Arkansas
became the 18th state to pass a law calling for restructuring of the electric
utility industry. The new law targets customer choice of electricity providers
by January 1, 2002. The new Arkansas law is described in more detail below under
"Competition; Regulation." If implemented as proposed, the new law will
significantly affect the Company's future Arkansas operations. The Company's
electric service area includes parts of western Arkansas, including Fort Smith,
the second-largest metropolitan market in the state.
The following discussion and analysis presents factors which had a
material effect on the Company's operations and financial position during the
last three years and should be read in conjunction with the Financial Statements
and Notes thereto. Trends and contingencies of a material nature are discussed
to the extent known and considered relevant. Except for the historical
statements contained herein, the matters discussed in the following discussion
and analysis, are forward-looking statements that are subject to certain risks,
uncertainties and assumptions. Such forward-looking statements are intended to
be identified in this document by the words "anticipate", "estimate",
"objective", "possible", "potential" and similar expressions. Actual results may
vary materially. Factors that could cause actual results to differ materially
include, but are not limited to: general economic conditions, including their
impact on capital expenditures; business conditions in the energy industry;
competitive factors; unusual
27
<PAGE>
weather; regulatory decisions and the other risk factors listed in the reports
filed by the Company with the Securities and Exchange Commission.
RESULTS OF OPERATIONS
REVENUES
<TABLE>
<CAPTION>
Percent Change
From Prior Year
---------------
(THOUSANDS) 1999 1998 1997 1999 1998
===================================================================================================
<S> <C> <C> <C> <C> <C>
Sales of electricity to Company
customers.............................. $ 1,258,950 $ 1,274,643 $ 1,168,663 (1.2) 9.1
Off-system sales......................... 27,894 37,435 23,027 (25.5) 62.6
- ----------------------------------------------------------------------------------
Total operating revenues............... $ 1,286,844 $ 1,312,078 $ 1,191,690 (1.9) 10.1
===================================================================================================
System megawatt-hour sales............... 23,468,130 23,642,599 22,182,992 (0.7) 6.6
Off-system megawatt-hour sales........... 374,027 727,601 1,201,933 (48.6) (39.5)
- ----------------------------------------------------------------------------------
Total megawatt-hour sales.............. 23,842,157 24,370,200 23,384,925 (2.2) 4.2
===================================================================================================
</TABLE>
Revenues from sales of electricity are somewhat seasonal, with a large
portion of the Company's annual electric revenues occurring during the summer
months when the electricity needs of its customers increase. Actions of the
regulatory commissions that set the Company's electric rates will continue to
affect the Company's financial results. The commissions also have the authority
to examine the appropriateness of the Company's recovery from its customers of
fuel costs, which include the transportation fees that the Company pays Enogex
for transporting natural gas to the Company's generating units. See "Regulation;
Competition" and Note 9 of Notes to Financial Statements for a discussion of the
impact of the OCC's February 11, 1997, rate order on these transportation fees.
Operating revenues decreased $25.2 million or 1.9 percent during 1999.
In 1999, kilowatt-hour sales to Company customers ("system sales") and
off-system sales decreased from 1998 levels that were the result of the record
heat of 1998. Lower recoveries under the GEP Rider also contributed to lower
revenues. The GEP Rider, which was implemented in 1997, allows the Company to
retain part of the fuel savings achieved through cost efficiencies and is
discussed in more detail below. Kilowatt-hour sales by the Company to other
utilities decreased 48.6 percent in 1999. During 1998, operating revenues
increased primarily due to higher system sales from warmer weather, the GEP
Rider, higher margin off-system sales and customer growth.
In February 1997, the OCC issued an order (the "1997 Order") that, among
other things, effectively lowered the Company's rates to its Oklahoma retail
customers by $50 million annually (based on a test year ended December 31,
1995). Of the $50 million rate reduction, approximately $45 million became
effective on March 5, 1997, and the remaining $5 million became effective March
1, 1998. The 1997 Order also directed the Company to commence competitively bid
gas transportation service to its gas-fired plants no later than April 30, 2000.
The order also set annual compensation for the transportation services provided
by Enogex to the Company at $41.3 million annually until March 1, 2000, at which
time the rate would drop to $28.5 million (reflecting the completion of the
recovery from ratepayers of the amortization premium paid by the Company when it
acquired Enogex in 1986) and remain at that level until competitively-bid gas
transportation begins. Final firm bids were
28
<PAGE>
submitted by Enogex and other pipelines on April 15, 1999. In July 1999, the
Company filed an application with the OCC requesting approval of a
performance-based rate plan for its Oklahoma retail customers from April 2000
until the introduction of customer choice for electric power in July 2002. As
part of this application, the Company stated that Enogex had submitted the only
viable bid ($33.4 million per year) for gas transportation to its six gas-fired
power plants that were the subject of the competitive bid. As part of its
application to the OCC, the Company offered to discount Enogex's bid from $33.4
million annually to $25.2 million annually. The Company has executed a new gas
transportation contract with Enogex under which Enogex would continue serving
the needs of the Company's power plants at a price to be paid by the Company of
$33.4 million annually and, if the Company's proposal had been approved by the
OCC, the Company would have recovered a portion of such amount ($25.2 million)
from its ratepayers. The OCC Staff, the Office of the Oklahoma Attorney General
and a coalition of industrial customers filed testimony questioning various
parts of the Company's performance-based rate plan, including the result of the
competitive bid process, and suggested, among other things, that the bidding
process be repeated or that gas transportation service to five of the Company's
gas-fired plants be awarded to parties other than Enogex. The OCC Staff also
filed testimony stating in substance that the Company's electric rates as a
whole were appropriate and did not warrant a rate review. The Company negotiated
with these parties in an effort to settle all issues (including the competitive
bid process) associated with its application for a performance-based rate plan.
When these negotiations failed, the Company withdrew its application, which
withdrawal was approved by the OCC in December 1999. Based on filed testimony,
the Company believes that Enogex properly won the competitive bid and, unless
the Company's decision to award its gas transportation service to Enogex is
abrogated by order of the OCC (which order is upheld on appeal), that it intends
to fulfill its obligations under its new gas transportation contract with Enogex
at a price of $33.4 million annually.
The 1997 Order also established the GEP Rider, which is designed so that
when the Company's average annual cost of fuel per kwh is less than 96.261
percent of the average non-nuclear fuel cost per kwh of certain other
investor-owned utilities in the region, the Company is allowed to collect,
through the GEP Rider, one-third of the amount by which the Company's average
annual cost of fuel is less than 96.261 percent of the average of the other
specified utilities. If the Company's fuel cost exceeds 103.739 percent of the
stated average, the Company will not be allowed to recover one-third of the fuel
costs above that amount from Oklahoma customers. As explained below, the GEP
Rider is currently under review by the OCC.
The fuel cost information used to calculate the GEP Rider is based on
fuel cost data submitted by each of the utilities in their Form No. 1 Annual
Report filed with the FERC. The GEP Rider is revised effective July 1 of each
year to reflect any changes in the relative annual cost of fuel reported for the
preceding calendar year. For 1999, the GEP Rider contributed approximately $20.8
million to revenues, which was approximately $9.5 million, or approximately
$0.14 per share lower than 1998. The current GEP Rider is estimated to
positively impact revenue by $13.1 million or approximately $0.19 per share
during the 12 months ending June 2000.
On January 12, 2000, the Staff filed three applications to address
various aspects of the Company's electric rates. Two of the applications were
expected, while the third pertains to recoveries under the Company's fuel
adjustment clause. The first application relates to the completion of the
recovery of the amortization premium paid by the Company when it acquired Enogex
in 1986 and the resulting removal of this $12.8 million from the amounts
currently being paid annually by the Company to Enogex and being recovered by
the Company from its ratepayers. The Company has consented to this action. The
second application relates to a review of the GEP Rider, which, as part of the
OCC's 1997 Order, was scheduled for review in March 2000. The Company collected
approximately $20.8 million pursuant to the GEP Rider during 1999. A hearing on
the GEP Rider is scheduled in May 2000 and the
29
<PAGE>
Company intends to support the retention of the GEP Rider with only minor
modifications. The final application relates to a review of 1999 fuel cost
recoveries. The Company assumes that this application also will be used to
address the competitive bid process of its gas transportation service. The
Company cannot predict the precise outcome of these proceedings at this time,
but does not expect that they will have a material effect on its operations.
EXPENSES AND OTHER ITEMS
<TABLE>
<CAPTION>
Percent Change
From Prior Year
---------------
(DOLLARS IN THOUSANDS) 1999 1998 1997 1999 1998
==================================================================================================
<S> <C> <C> <C> <C> <C>
Fuel .................................... $ 350,814 $ 356,781 $ 319,494 (1.7) 11.7
Purchased power.......................... 249,203 240,542 222,464 3.6 8.1
Other operation and maintenance.......... 253,312 239,614 245,943 5.7 (2.6)
Depreciation and amortization............ 119,059 116,214 114,760 2.4 1.3
Taxes other than income.................. 44,892 43,130 42,991 4.1 0.3
- ----------------------------------------------------------------------------------
Total operating expenses............... $1,017,280 $ 996,281 $ 945,652 2.1 5.4
==================================================================================================
</TABLE>
Total operating expenses increased $21.0 million or 2.1 percent in 1999,
primarily due to increases in other operation and maintenance.
The Company's generating capability is fairly evenly divided between
coal and natural gas and provides for flexibility to use either fuel to the best
economic advantage for the Company and its customers. In 1999, fuel costs
decreased $5.9 million or 1.7 percent primarily due to a 3.4 percent decrease in
total energy generated which offset a 1.9 percent increase in the average cost
of fuel burned for generation of electricity. During 1998, fuel costs increased
due to a modest increase in total generation and a slight increase in the
average cost of fuel burned.
The Company's purchased power costs increased $8.7 million or 3.6
percent in 1999 due in large part to emergency purchases in the aftermath of
tornadoes, on May 3, 1999 and June 1, 1999, which inflicted heavy damage to the
Company power supply, transmission and delivery systems. In 1999, the cost of
purchased energy per kwh increased 8.7 percent. During 1998, purchased power
costs increased $18.1 million or 8.1 percent primarily due to a 13 percent
increase in the quantities purchased. During 1998, the Company also began
purchasing power from Mid-Continent Power Company ("MCPC"). Payments to MCPC in
1998 were approximately $8 million. MCPC is a qualified cogeneration facility
from which the Company is required to purchase peaking capacity through 2007. As
required by the Public Utility Regulatory Policy Act ("PURPA"), the Company is
currently purchasing power from qualified cogeneration facilities.
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are passed through to the Company's electric customers through
automatic fuel adjustment clauses. The automatic fuel adjustment clauses are
subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC
and the FERC have authority to review the appropriateness of gas transportation
charges or other fees the Company pays Enogex, which the Company seeks to
recover through the fuel adjustment clause or other tariffs. Also, as explained
below, the OCC Staff recently filed an application to review various issues
under the Company's fuel adjustment clause in Oklahoma.
30
<PAGE>
The Company has initiated numerous ongoing programs that have helped
reduce the cost of generating electricity over the last several years. These
programs include: (i) utilizing a natural gas storage facility; (ii) spot market
purchases of coal; (iii) renegotiated contracts for coal, gas, railcar
maintenance and coal transportation; and (iv) a heat-rate awareness program to
produce kilowatt-hours with less fuel. Reducing fuel costs helps the Company
remain competitive, which in turn helps the Company's electric customers remain
competitive in a global economy.
Other operation and maintenance increased $13.7 million or 5.7 percent
in 1999 primarily because of higher bad debt expense and expenses associated
with the record number of tornadoes and severe thunderstorms that inflicted
heavy damage to the Company's power supply and transmission and delivery
systems. In 1998, other operation and maintenance expenses decreased $6.3
million or 2.6 percent primarily because of decreases in post retirement medical
costs, bad debt expense, completion in February 1997 of the amortization of the
$48.9 million regulatory asset established in connection with the Company's 1994
workforce reduction and general corporate expenses.
The increases in depreciation and amortization for 1999 and 1998
reflects higher levels of depreciable plant.
In 1999 and 1998, the increase in taxes other than income is primarily
attributable to higher ad valorem taxes.
The decrease in interest expense for 1999 was primarily due to lower
general corporate interest charges. The decrease in interest expense for 1998
was attributable to the Company retiring $25 million of 6.375 percent First
Mortgage Bonds in January 1998 and the successful refinancing of $100 million of
long-term debt in 1998.
In 1999, the provision for income taxes decreased $21.6 million or 20.3
percent due to lower pre-tax income from 1998 to 1999. In 1998, the provision
for income taxes increased $34.4 million or 30.1 percent primarily due to
significantly higher pre-tax income and normally occurring temporary
differences.
LIQUIDITY, CAPITAL RESOURCES AND CONTINGENCIES
The primary capital requirements for 1999 and as estimated for 2000
through 2002 are as follows:
<TABLE>
<CAPTION>
(DOLLARS IN MILLIONS) 1999 2000 2001 2002
================================================================================
<S> <C> <C> <C> <C>
Construction expenditures
including AFUDC........................ $101.3 $109.0 $100.0 $100.0
Maturities of long-term debt............. --- 110.0 --- ---
- --------------------------------------------------------------------------------
Total................................ $101.3 $219.0 $100.0 $100.0
================================================================================
</TABLE>
The Company's primary needs for capital are related to construction of
new facilities to meet anticipated demand for utility service, to replace or
expand existing facilities in its electric utility businesses, and to some
extent, for satisfying maturing debt. The Company generally meets its cash
31
<PAGE>
needs through a combination of internally generated funds, short-term borrowings
and permanent financing.
1999 CAPITAL REQUIREMENTS AND FINANCING ACTIVITIES
Capital requirements were $101.3 million in 1999. Approximately $1.7
million of the 1999 capital requirements were to comply with environmental
regulations. This compares to capital requirements of $96.7 million in 1998, of
which $0.3 million were to comply with environmental regulations.
During 1999, the Company's primary source of capital was internally
generated funds from operating cash flows. Operating cash flow remained strong
in 1999 as internally generated funds provided financing for all of the
Company's capital expenditures. Variations in accounts receivable and accounts
payable are not generally significant indicators of the Company's liquidity, as
such variations are primarily attributable to fluctuations in weather in the
Company's service territory, which has a direct effect on sales of electricity.
The Company previously borrowed on a short-term basis, as necessary, by
the issuance of commercial paper and by obtaining short-term bank loans. In
April 1997, these functions were transferred to Energy Corp. The Company now
uses short-term borrowings from Energy Corp. to meet its temporary cash
requirements. The Company had $55.5 million in short-term debt outstanding at
December 31, 1999.
On January 2, 1998, the Company retired $25 million principal amount of
6.375 percent First Mortgage Bonds due January 1, 1998.
FUTURE CAPITAL REQUIREMENTS
The Company's construction program for the next several years does not
include additional base-load generating units. Rather, to meet the increased
electricity needs of its customers during the foreseeable future, the Company
will concentrate on maintaining the reliability and increasing the utilization
of existing capacity and increasing demand-side management efforts.
Approximately $1.0 million of the Company's construction expenditures budgeted
for 2000 are to comply with environmental laws and regulations.
Future financing requirements may be dependent, to varying degrees, upon
numerous factors outside the Company's control such as general economic
conditions, abnormal weather, load growth, inflation, changes in environmental
laws or regulations, rate increases or decreases allowed by regulatory agencies,
new legislation and market entry of competing electric power generators.
FUTURE SOURCES OF FINANCING
Management expects that internally generated funds will be adequate over
the next three years to meet anticipated construction expenditures. Short-term
borrowings will continue to be used to meet temporary cash requirements. The
Company has the necessary regulatory approvals to incur up to $400 million in
short-term borrowings at any one time. At December 31, 1999, Energy Corp. had in
place a line of credit for up to $200 million, with $100 million to expire on
January 15, 2000 and the remaining $100 million to expire on January 15, 2004.
In January 2000, Energy Corp.'s line of credit was increased to $300 million;
with $200 million to expire on January 15, 2001 and $100 million to expire on
January 15, 2004.
32
<PAGE>
THE YEAR 2000 ISSUE (A NON-EVENT)
There was a great deal of publicity about the Year 2000 ("Y2K") and the
possible problems that information technology systems may have suffered as a
result. As the Year 2000 approached, it was feared that date-sensitive systems
might recognize the Year 2000 as 1900, or not at all, potentially causing
systems, including those of the Company, its customers, suppliers, business
partners and neighboring utilities to process critical financial and operational
information incorrectly, if they were not Year 2000 ready. A failure to identify
and correct any such processing problems prior to January 1, 2000 could have
resulted in material operational and financial risks if the affected systems
either ceased to function or produced erroneous data. However, the Company was
aggressive and did its work well in addressing the risks associated with the Y2K
issue. The Company's goal was to minimize the impact of Y2K and our goal was
accomplished. Y2K was a non-event.
COSTS OF YEAR 2000 ISSUES
With the Company's mainframe conversion in 1994, the SAP Enterprise
Software installations for the financial and customer systems in 1997 and 1999,
respectively, and the Energy Management System replacement in 1999, a number of
Y2K issues were addressed as part of the Company's normal course upgrades to the
information technology systems. These upgrades were already contemplated and
provided additional benefits or efficiencies beyond the Year 2000 aspect. Since
1995, the Company has spent approximately $45 million on the mainframe
conversion, the initial financial enterprise software systems, the customer care
enterprise software installations and the SCADA/EMS replacement.
RISKS OF YEAR 2000 ISSUES
The Company experienced only one minor problem which occurred on New
Year's Day when a computer system in the Company's Outage Management System
showed an error that was corrected within an hour with a vendor-provided patch.
Although the Company has not experienced any major Y2K problems to date, the
Company believes some risks still exist as it may take a full year to identify
and address all the potential problems in the Company's business systems
resulting from Y2K upgrades, corrections and patches.
CONTINGENCIES
The Company is defending various claims and legal actions, including
environmental actions, which are common to its operations. For a further
discussion of these actions, including a lawsuit involving Trigen-Oklahoma City
Energy Corporation, see Note 8 of Notes to Financial Statements. As to
environmental matters, the Company has been designated as a "potentially
responsible party" ("PRP") with respect to two waste disposal sites to which the
Company sent materials. Remediation and required monitoring of one of these
sites has been completed. While it is not possible to determine the precise
outcome of these matters, in the opinion of management, the Company's ultimate
liability for these sites will not be material.
Beginning in 2000, the Company will be limited in the amount of sulfur
dioxide it will be allowed to emit into the atmosphere. In order to comply with
this limit the Company has contracted for lower sulfur coal. The Company
believes this will allow it to meet this limit without additional capital
expenditures. With respect to nitrogen oxides, the Company continues to meet the
current emission standard. However, regulations on regional haze, the
possibility of having a new ozone ambient standard that Oklahoma will not be
able to meet, and Oklahoma's potential for not being able to meet the new
33
<PAGE>
particulate standards, could require further reductions in sulfur dioxide and
nitrogen oxides. If this occurs, significant capital expenditures and increased
operating and maintenance costs would result.
In 1997, the United States was a signatory to the Kyoto Protocol on
global warming. If ratified by the U.S. Senate, this Protocol could have a
tremendous impact on the Company's operations, by requiring the Company to
significantly reduce the use of coal as a fuel source, since the Protocol would
require a seven percent reduction in greenhouse gas emissions below the 1990
level.
The Oklahoma Department of Environmental Quality's CAAA Title V
permitting program was approved by the EPA in March 1996. By March of 1997, the
Company had submitted all required permit applications and by December 31, 2000
the Company expects to have new Title V permits for all of its major source
generating stations. Air permit fees for generating stations were approximately
$0.4 million in 1999 and are estimated to be about the same in 2000.
By December 15, 2000, the EPA is expected to decide whether or not to
regulate mercury emissions from coal-fired utility boilers. If the decision is
made to regulate, limits on the amount of mercury emitted are expected to be
proposed by December 2003 with the Company's compliance required by 2008. This
could result in significant capital and operating expenditures.
COMPETITION; REGULATION
As previously reported, Oklahoma enacted in April 1997 the Electric
Restructuring Act of 1997 (the "Act"). Various amendments to the Act were
enacted in 1998. If implemented as proposed, the Act will significantly affect
the Company's future operations.
The purpose of the Act, as set forth therein, is generally to
restructure the electric utility industry to provide for more competition and,
in particular, to provide for the orderly restructuring of the electric utility
industry in Oklahoma in order to allow customers to choose their electricity
suppliers while maintaining the safety and reliability of the electric system in
the state.
The Act directed the Joint Electric Utility Task Force, composed of
seven members from the Oklahoma Senate and seven members from the Oklahoma House
of Representatives, to undertake a study of all relevant issues relating to
restructuring the electric utility industry in Oklahoma and to develop a
proposed electric utility framework for Oklahoma. The study was to be delivered
in several parts. As a result of the 1998 amendments, the time frame for the
delivery of the remaining parts of the study was accelerated to October 1, 1999.
This study addressed: (i) technical issues (including reliability, safety,
unbundling of generation, transmission and distribution services, transition
issues and market power); (ii) financial issues (including rates, charges,
access fees, transition costs and stranded costs); (iii) consumer issues (such
as the obligation to serve, service territories, consumer choices, competition
and consumer safeguards); and (iv) tax issues (including sales and use taxes, ad
valorem taxes and franchise fees).
Neither the Oklahoma Tax Commission nor the OCC is authorized to issue
any rules on such matters without the approval of the Oklahoma Legislature.
Other provisions of the Act (i) authorize the Joint Electric Utility Task Force
to retain consultants to study, among other things, the creation of an
independent system operator, (ii) prohibit customer switching prior to July 1,
2002, except by mutual consent, (iii) prohibit municipalities that do not become
subject to the Act, from selling power outside their municipal limits, except
from lines owned on April 25, 1997, (iv) require a uniform tax policy be
established by July 1, 2002 and (v) require out-of-state suppliers of
electricity and their affiliates who make retail sales of electricity in
Oklahoma through the use of transmission and distribution facilities of in-state
suppliers to provide equal access to their transmission and distribution
facilities outside of
34
<PAGE>
Oklahoma. The Act was modified during the 1999 session of the Oklahoma
Legislature to clarify certain ambiguities by defining key terms in the act.
With the completion of the studies described above in October 1999, the
Oklahoma legislature is expected to implement additional legislation, which will
address many specific issues associated with deregulation. Several bills have
already been introduced. While the Company cannot predict the terms of the new
legislation, the Company intends to participate actively in the legislative
process.
In April 1999, Arkansas became the 18th state to pass a law calling for
restructuring of the electric utility industry at the retail level. The new law
targets customer choice of electricity providers by January 1, 2002. The new law
also provides that utilities owning or controlling transmission assets must
transfer control of such transmission assets to an independent system operator,
independent transmission company or regional transmission group, if any such
organization has been approved by the FERC. Other provisions of the new law
permit municipal electric systems to opt in or out, permit recovery of stranded
costs and transition costs and require unbundled rates by July 1, 2000 for
generation, transmission, distribution and customer service. As required by the
new law, the APSC is in the process of adopting regulations that will implement
the new law. The new law and related regulations will significantly affect the
Company's future Arkansas operations. The Company's electric service area
includes parts of western Arkansas, including Fort Smith, the second-largest
metropolitan market in the state.
The OCC also has adopted rules that are designed to make the gas utility
business in Oklahoma more competitive. These rules do not impact the electric
industry. Yet, if implemented, the rules are expected to offer increased
opportunities to Enogex's pipeline and related businesses.
These efforts to increase competition in the electric industry at the
state level in Oklahoma and Arkansas have been paralleled and even surpassed by
efforts at the federal level to increase competition in the wholesale markets
for electricity. In October 1992, the National Energy Policy Act of 1992
("Energy Act") was enacted. Among many other provisions, the Energy Act is
designed to promote competition in the development of wholesale power generation
in the electric utility industry. It exempts a new class of independent power
producers ("IPPs") from regulation under the Public Utility Holding Company Act
of 1935 and allows the FERC to order wholesale "wheeling" by public utilities to
provide utility and non-utility generators access to public utility transmission
facilities.
Within four years of the enactment of the Energy Act, FERC issued Order
888 and Order 889 to facilitate third-party utilization of the transmission grid
as the vehicle for developing a more competitive wholesale bulk power market.
Order 888 requires all transmission owners to (i) offer comparable open-access
transmission service for wholesale transactions under a tariff of general
applicability on file at FERC and (ii) take transmission service for their own
wholesale sales under their open-access tariff. Order 889 requires electric
utilities to functionally separate their transmission and reliability functions
from their wholesale power marketing functions. In this connection, Order 889
required electric utilities to develop and maintain an Open Access Same-Time
Information System ("OASIS") to ensure that transmission customers have access
to transmission information, through electronic means, that will enable them to
obtain open-access transmission service on a basis comparable to a transmitting
utility's own use of its system.
The Energy Act, Orders 888 and 889, and other FERC policies and
initiatives have had a tremendous impact on the development of a competitive
wholesale power market. Utilities, including the Company, have increased their
own in-house wholesale marketing efforts and the number of entities with whom
they trade. Moreover, power marketers are an increasingly important presence in
the industry.
35
<PAGE>
These entities typically arbitrage wholesale price differentials by buying power
produced by others in one market and selling it in another. IPPs also are
becoming a more significant sector of the electric utility industry. In both
Oklahoma and Arkansas, significant additions of new power plants have been
announced, almost all of it from IPPs.
Notwithstanding these developments in the wholesale power market, FERC
recognized that impediments remained to the achievement of fully competitive
wholesale markets including: (i) engineering and economic inefficiencies
inherent in the current operation and expansion of the transmission grid and
(ii) continuing opportunities for transmission owners to discriminate in the
operation of their transmission facilities in favor of their own or affiliated
power marketing activities. Whereas FERC in the past only encouraged utilities
to join and place their transmission systems under the operational control of
independent system operators ("ISOs"), FERC, issued Order 2000 on December 20,
1999, its final rule on regional transmission organizations ("RTOs"). Order 2000
sets out a timetable for every jurisdictional utility (including the Company) to
either join in an RTO filing, or, alternatively, to submit a filing by October
15, 2000 describing its efforts to join in an RTO, the reasons for not
participating in an RTO proposal and any obstacles to participation, and its
plans for further work toward participation. Public utilities that have already
transferred control of their facilities to a FERC-approved RTO must file with
FERC by January 15, 2001, a statement explaining, among other things, how such
RTO has the minimum characteristics and performs the minimum functions
identified by FERC in the final rule. These minimum characteristics and
functions are intended to have the effect of turning the nation's transmission
facilities into independently operated "common carriers" that offer comparable
service to all would-be-users. Although adopting a voluntary approach towards
RTO formation, FERC stressed that Order 2000 does not preclude it from requiring
RTO participation.
The Company is a member of the Southwest Power Pool ("SPP"), the
regional reliability organization for Oklahoma, Arkansas, Kansas, Louisiana,
Missouri and part of Texas. The Company participated with the SPP in the
development of regional transmission tariffs and executed an Agency Agreement
with the SPP to facilitate interstate transmission operations within this
region. The Company presently intends to meet its obligations to transfer
operational control of its transmission system to an RTO under Order 2000 and
under the new Arkansas deregulation law through the SPP. The SPP has asked for
FERC recognition as an ISO consistent with FERC's ISO guidelines in its Order
888 and related provisions in Order 2000. The transfer of operational control of
the Company's transmission system to a FERC-approved RTO is not expected to
impact significantly the Company's financial results. Yet, it is expected to
increase the markets in which the Company can sell power at wholesale and, at
the same time, to increase competition in such wholesale markets. As a low-cost
producer of electricity with two of the most efficient power plants in the
country, the Company expects to remain a competitive supplier of electricity.
As discussed previously, legislation was enacted in Oklahoma and
Arkansas that will restructure the electric utility industry in those states,
assuming that all the conditions in the legislation are met. This legislation
would deregulate the Company's electric generation assets and the continued use
of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for
the Effects of Certain Types of Regulation" with respect to the related
regulatory assets may no longer be appropriate. This may result in either full
recovery of generation-related regulatory assets (net of related regulatory
liabilities) or a non-cash, pre-tax write-off as an extraordinary charge of up
to $30 million, depending on the transition mechanisms developed by the
legislature for the recovery of all or a portion of these net regulatory assets.
The enacted Oklahoma and Arkansas legislation does not affect the
Company's electric transmission and distribution assets and the Company believes
that the continued use of SFAS No. 71
36
<PAGE>
with respect to the related regulatory assets is appropriate. However, if
utility regulators in Oklahoma and Arkansas were to adopt regulatory
methodologies in the future that are not based on cost-of-service, the continued
use of SFAS No. 71 with respect to the regulatory assets related to the electric
transmission and distribution assets may no longer be appropriate. Based on a
current evaluation of the various factors and conditions that are expected to
impact future cost recovery, management believes that its regulatory assets,
including those related to generation, are probable of future recovery.
As stated previously, the OCC in its 1997 Order, directed the Company to
commence competitively bid gas transportation service to its gas-fired plants no
later than April 30, 2000. The order also set annual compensation for the
transportation services provided by Enogex to the Company at $41.3 million
annually until March 1, 2000, at which time the rate would drop to $28.5 million
(reflecting the completion of the recovery from ratepayers of the amortization
premium paid by the Company when it acquired Enogex in 1986) and remain at that
level until competitively-bid gas transportation begins. Final firms bids were
submitted by Enogex and other pipelines on April 15, 1999. In July 1999, the
Company filed an application with the OCC requesting approval of a
performance-based rate plan for its Oklahoma retail customers from April 2000
until the introduction of customer choice for electric power in July 2002. As
part of this application, the Company stated that Enogex had submitted the only
viable bid ($33.4 million per year) for gas transportation to its six gas-fired
power plants that were the subject of the competitive bid. As part of its
application to the OCC, the Company offered to discount Enogex's bid from $33.4
million annually to $25.2 million annually. The Company has executed a new gas
transportation contract with Enogex under which Enogex would continue serving
the needs of the Company's power plants at a price to be paid by the Company of
$33.4 million annually and, if the Company's proposal had been approved by the
OCC, the Company would have recovered a portion of such amount ($25.2 million)
from its ratepayers. The OCC Staff, the office of the Oklahoma Attorney General
and a coalition of industrial customers filed testimony questioning various
parts of the Company's performance-based rate plan, including the result of the
competitive bid process, and suggested, among other things, that the bidding
process be repeated or that gas transportation service to five of the Company's
gas-fired plants be awarded to parties other than Enogex. The OCC Staff also
filed testimony stating in substance that the Company's electric rates as a
whole were appropriate and did not warrant a rate review. The Company negotiated
with these parties in an effort to settle all issues (including the competitive
bid process) associated with its application for a performance-based rate
plan. When these negotiations failed, the Company withdrew its application,
which withdrawal was approved by the OCC in December 1999. Based on filed
testimony, the Company believes that Enogex properly won the competitive bid
and, unless the Company's decision to award its gas transportation service to
Enogex is abrogated by order of the OCC (which order is upheld on appeal), that
it intends to fulfill its obligations under its new gas transportation contract
with Enogex at a price of $33.4 million annually. Whether the Company will be
able to recover the entire amount from its ratepayers has not been determined as
explained below.
On January 12, 2000, the Staff filed three applications to address
various aspects of the Company's electric rates. Two of the applications were
expected, while the third pertains to recoveries under the Company's fuel
adjustment clause. The first application relates to the completion of the
recovery of the amortization premium paid by the Company when it acquired Enogex
in 1986 and the resulting removal of this $12.8 million from the amounts
currently being paid annually by the Company to Enogex and being recovered by
the Company from its ratepayers. The Company has consented to this action. The
second application relates to a review of the GEP Rider, which, as part of the
OCC's 1997 Order, was scheduled for review in March 2000. The Company collected
approximately $20.8 million pursuant to the GEP Rider during 1999. A hearing on
the GEP Rider is scheduled in May 2000 and the Company intends to support the
retention of the GEP Rider with only minor modifications. The final application
relates to a review of 1999 fuel cost recoveries. The Company assumes that this
application
37
<PAGE>
also will be used to address the competitive bid process of its gas
transportation service. The Company cannot predict the precise outcome of these
proceedings at this time, but does not expect that they will have a material
effect on its operations.
On February 13, 1998, the APSC Staff filed a motion for a show cause
order to review the Company's electric rates in the State of Arkansas. The Staff
recommended a $3.1 million annual rate reduction (based on a test year ended
December 31, 1996). The Staff and the Company reached a settlement for a $2.3
million annual rate reduction, which was approved by the APSC in August 1999.
Besides the existing contingencies described above, and those described
in Note 8 of Notes to Financial Statements, the Company's ability to fund its
future operational needs and to finance its construction program is dependent
upon numerous other factors beyond its control, such as general economic
conditions, abnormal weather, load growth, inflation, new environmental laws or
regulations, and the cost and availability of external financing.
In June 1998, the Financial Accounting Standards Board ("FASB") issued
statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and for Hedging Activities", with an effective date for
periods beginning after June 15, 1999. In July 1999, the FASB issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133." As a result of SFAS No. 137,
adoption of SFAS No. 133 is now required for financial statements for periods
beginning after June 15, 2000. SFAS No. 133 sweeps in a broad population of
transactions and changes the previous accounting definition of a derivative
instrument. Under SFAS No. 133, every derivative instrument is recorded on the
balance sheet as either an asset or liability measured at its fair value. SFAS
No. 133 requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. The
Company will prospectively adopt this new standard effective January 1, 2001,
and management believes the adoption of this new standard will not have a
material impact on its financial position or results of operation.
MARKET RISK
RISK MANAGEMENT
The risk management process established by the Company is designed to
measure both quantitative and qualitative risks in its businesses. A senior risk
management committee has been established to review these risks on a regular
basis. The Company is exposed to market risk relating to changes in interest
rates.
INTEREST RATE RISK
The Company's exposure to changes in interest rates relates primarily
to long-term debt obligations and commercial paper. The Company manages its
interest rate exposure by limiting its variable-rate debt to a certain
percentage of total capitalization and by monitoring the effects of market
changes in interest rates. The Company may utilize interest rate derivatives to
alter interest rate exposure in an attempt to reduce interest rate expense
related to existing debt issues. Interest rate derivatives are used solely to
modify interest rate exposure and not to modify the overall leverage of the debt
portfolio. The fair value of long-term debt is estimated based on quoted market
prices and management's estimate of current rates available for similar issues.
The following table itemizes the Company's long-term debt maturities and the
weighted-average interest rates by maturity date.
38
<PAGE>
<TABLE>
<CAPTION>
=============================================================================================================
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1999
Year-end
(DOLLARS IN MILLIONS) 2000 2001 2002 2003 2004 Thereafter Total Fair Value
- -------------------------------------------------------------------------------------------------------------
Fixed rate debt
Principal amount...... $110.0 $ --- $ --- $ --- $ --- $460.0 $ 570.0 $ 557.6
Weighted-average
interest rate....... 6.25% --- --- --- --- 7.02% 6.87% ---
Variable-rate debt
Principal amount...... --- --- --- --- --- $135.4 $ 135.4 $ 135.4
Weighted-average
interest rate....... --- --- --- --- --- 3.42% 3.42% ---
=============================================================================================================
</TABLE>
39
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
- ---------------------------------------------------
BALANCE SHEETS
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents.................................... $ 1,779 $ 312 $ 228
Accounts receivable - customers, less reserve of $3,405,
$2,441 and $3,583, respectively............................ 96,212 91,434 92,379
Accrued unbilled revenues.................................... 40,200 22,500 36,900
Accounts receivable - other.................................. 8,074 7,723 9,795
Fuel inventories, at LIFO cost............................... 75,465 47,081 43,577
Materials and supplies, at average cost...................... 30,311 25,894 24,481
Prepayments and other........................................ 3,100 28,641 2,533
Accumulated deferred tax assets.............................. 7,681 6,889 6,048
- --------------------------------------------------------------- ----------- ----------- -----------
Total current assets....................................... 262,822 230,474 215,941
- --------------------------------------------------------------- ----------- ----------- -----------
OTHER PROPERTY AND INVESTMENTS, at cost........................ 12,731 17,454 28,140
- --------------------------------------------------------------- ----------- ----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service................................................... 3,747,690 3,674,732 3,647,366
Construction work in progress................................ 15,575 28,439 18,910
- --------------------------------------------------------------- ----------- ----------- -----------
Total property, plant and equipment........................ 3,763,265 3,703,171 3,666,276
Less accumulated depreciation............................ 1,810,898 1,727,472 1,653,771
- --------------------------------------------------------------- ----------- ----------- -----------
Net property, plant and equipment............................ 1,952,367 1,975,699 2,012,505
- --------------------------------------------------------------- ----------- ----------- -----------
DEFERRED CHARGES:
Advance payments for gas..................................... 11,800 15,000 10,500
Income taxes recoverable through future rates................ 39,692 40,731 42,549
Other........................................................ 41,248 40,739 41,147
- --------------------------------------------------------------- ----------- ----------- -----------
Total deferred charges..................................... 92,740 96,470 94,196
- --------------------------------------------------------------- ----------- ----------- -----------
TOTAL ASSETS................................................... $2,320,660 $2,320,097 $2,350,782
=============================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
40
<PAGE>
BALANCE SHEETS (Continued)
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - affiliates................................ $ 75,674 $ 67,045 $ 14,986
Accounts payable............................................. 36,231 45,536 47,802
Dividends payable............................................ --- --- 571
Customers' deposits.......................................... 22,137 23,984 23,846
Accrued taxes................................................ 19,545 18,932 18,963
Accrued interest............................................. 14,573 15,931 15,746
Long-term debt due within one year........................... 110,000 --- 25,000
Other........................................................ 20,893 23,742 35,386
- --------------------------------------------------------------- ----------- ----------- -----------
Total current liabilities.................................. 299,053 195,170 182,300
- --------------------------------------------------------------- ----------- ----------- -----------
LONG-TERM DEBT................................................. 593,045 702,912 691,924
- --------------------------------------------------------------- ----------- ----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation....................... 14,886 18,162 57,418
Accumulated deferred income taxes............................ 450,028 462,886 439,657
Accumulated deferred investment tax credits.................. 62,578 67,728 72,878
Other........................................................ 11,933 19,668 5,949
- --------------------------------------------------------------- ----------- ----------- -----------
Total deferred credits and other liabilities............... 539,425 568,444 575,902
- --------------------------------------------------------------- ----------- ----------- -----------
STOCKHOLDERS' EQUITY:
Common stockholders' equity.................................. 512,446 512,446 512,444
Retained earnings............................................ 376,691 341,125 338,946
Cumulative preferred stock................................... --- --- 49,266
- --------------------------------------------------------------- ----------- ----------- -----------
Total stockholder's equity................................. 889,137 853,571 900,656
- --------------------------------------------------------------- ----------- ----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..................... $2,320,660 $2,320,097 $2,350,782
=============================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
41
<PAGE>
STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
==================================================================================================================
<S> <C> <C> <C>
COMMON STOCK AND RETAINED EARNINGS:
Common stock, par value $2.50 per share;
authorized 100,000,000 shares; and
outstanding 40,378,745, 40,378,745,
and 40,378,745 shares, respectively.............................. $ 100,947 $ 100,947 $ 100,947
Premium on capital stock........................................... 411,499 411,499 411,497
Retained earnings.................................................. 376,691 341,125 338,946
- --------------------------------------------------------------------- ----------- ----------- -----------
Total common stock and retained earnings....................... 889,137 853,571 851,390
- --------------------------------------------------------------------- ----------- ----------- -----------
CUMULATIVE PREFERRED STOCK:
Par value $20, authorized 675,000 shares - 4%;
zero, zero, and 418,963 shares, respectively..................... --- --- 8,379
Par value $100, authorized 1,865,000 shares-
SERIES SHARES OUTSTANDING
4.20% zero, zero, and 49,750 shares, respectively............ --- --- 4,975
4.24% zero, zero, and 74,990 shares, respectively............ --- --- 7,499
4.44% zero, zero, and 63,200 shares, respectively............ --- --- 6,320
4.80% zero, zero, and 70,925 shares, respectively............ --- --- 7,093
5.34% zero, zero, and 150,000 shares, respectively........... --- --- 15,000
- --------------------------------------------------------------------- ----------- ----------- -----------
Total cumulative preferred stock............................... --- --- 49,266
- --------------------------------------------------------------------- ----------- ----------- -----------
LONG-TERM DEBT:
SERIES DATE DUE
6.375% January 1, 1998........................................ --- --- 25,000
7.125% January 1, 1999........................................ --- --- 12,500
6.250% Senior Notes Series B, October 15, 2000................ 110,000 110,000 110,000
7.125% January 1, 2002........................................ --- --- 40,000
8.625% November 1, 2007....................................... --- --- 35,000
6.500% Senior Notes Series D, July 15, 2017................... 125,000 125,000 125,000
7.300% Senior Notes Series A, October 15, 2025................ 110,000 110,000 110,000
6.650% Senior Notes Series C, July 15, 2027................... 125,000 125,000 125,000
6.500% Senior Notes Series E, April 15, 2028.................. 100,000 100,000 ---
Other bonds-
Var. % Garfield Industrial Authority, January 1, 2025......... 47,000 47,000 47,000
Var. % Muskogee Industrial Authority, January 1, 2025......... 32,400 32,400 32,400
Var. % Muskogee Industrial Authority, June 1, 2027............ 56,000 56,000 56,000
Unamortized premium and discount, net.............................. (2,355) (2,488) (976)
- --------------------------------------------------------------------- ----------- ----------- -----------
Total long-term debt........................................... 703,045 702,912 716,924
Less long-term debt due within one year...................... 110,000 --- 25,000
- --------------------------------------------------------------------- ----------- ----------- -----------
Total long-term debt (excluding long-term
debt due within one year).................................... 593,045 702,912 691,924
- --------------------------------------------------------------------- ----------- ----------- -----------
Total Capitalization................................................. $1,482,182 $1,556,483 $1,592,580
===================================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
42
<PAGE>
STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1999 1998 1997
================================================================================================================
<S> <C> <C> <C>
OPERATING REVENUES................................................. $1,286,844 $1,312,078 $1,191,690
- ------------------------------------------------------------------- ----------- ----------- -----------
OPERATING EXPENSES:
Fuel............................................................. 350,814 356,781 319,494
Purchased power.................................................. 249,203 240,542 222,464
Other operation and maintenance.................................. 253,312 239,614 245,943
Depreciation and amortization.................................... 119,059 116,214 114,760
Taxes other than income.......................................... 44,892 43,130 42,991
- ------------------------------------------------------------------- ----------- ----------- -----------
Total operating expenses....................................... 1,017,280 996,281 945,652
- ------------------------------------------------------------------- ----------- ----------- -----------
OPERATING INCOME................................................... 269,564 315,797 246,038
- ------------------------------------------------------------------- ----------- ----------- -----------
OTHER INCOME (EXPENSES):
Interest charges................................................. (45,939) (48,871) (55,947)
Other, net....................................................... 381 (5) 3,627
- ------------------------------------------------------------------- ----------- ----------- -----------
Total other income (expenses).................................. (45,558) (48,876) (52,320)
- ------------------------------------------------------------------- ----------- ----------- -----------
EARNINGS BEFORE INCOME TAXES....................................... 224,006 266,921 193,718
PROVISION FOR INCOME TAXES......................................... 84,965 106,583 72,724
- ------------------------------------------------------------------- ----------- ----------- -----------
NET INCOME......................................................... 139,041 160,338 120,994
PREFERRED DIVIDEND REQUIREMENTS.................................... --- 733 2,285
- ------------------------------------------------------------------- ----------- ----------- -----------
EARNINGS AVAILABLE FOR COMMON ..................................... $ 139,041 $ 159,605 $ 118,709
=================================================================== =========== =========== ===========
AVERAGE COMMON SHARES OUTSTANDING (thousands)...................... 40,379 40,379 40,379
EARNINGS PER AVERAGE COMMON SHARE.................................. 3.44 3.95 2.94
AVERAGE COMMON SHARES OUTSTANDING ASSUMING DILUTION (thousands).... 40,379 40,379 40,379
EARNINGS PER AVERAGE COMMON SHARE ASSUMING DILUTION................ $ 3.44 $ 3.95 $ 2.94
=================================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
43
<PAGE>
STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
BALANCE AT BEGINNING OF PERIOD................................. $ 341,125 $ 338,946 $ 328,630
ADD - net income............................................... 139,041 160,338 120,994
Total........................................................ 480,166 499,284 449,624
DEDUCT:
Cash dividends declared on preferred stock................... --- 733 2,285
Cash dividends declared on common stock...................... 103,475 157,426 108,393
- --------------------------------------------------------------- ----------- ----------- -----------
Total...................................................... 103,475 158,159 110,678
BALANCE AT END OF PERIOD....................................... $ 376,691 $ 341,125 $ 338,946
=============================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
44
<PAGE>
STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income................................................... $ 139,041 $ 160,338 $ 120,994
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation and amortization.............................. 119,059 116,214 114,760
Deferred income taxes and investment tax credits, net...... (16,945) 19,047 10,777
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers.......................... (4,778) 945 3,688
Accrued unbilled revenues................................ (17,700) 14,400 (2,000)
Fuel, materials and supplies inventories................. (32,801) (4,917) 12,792
Accumulated deferred tax assets.......................... (792) (841) 3,142
Other current assets..................................... 25,190 (11,120) 35,269
Accounts payable......................................... (56,137) 49,793 (809)
Accrued taxes............................................ 613 (31) (6,074)
Accrued interest......................................... (1,358) 185 (640)
Other current liabilities................................ (4,696) 2,823 (26,614)
Other operating activities................................... 2,047 (30,149) 2,014
- --------------------------------------------------------------- ----------- ----------- -----------
Net cash provided from operating activities............ 150,743 316,687 267,299
- --------------------------------------------------------------- ----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures......................................... (101,263) (96,678) (100,079)
- --------------------------------------------------------------- ----------- ----------- -----------
Net cash used in investing activities.................. (101,263) (96,678) (100,079)
- --------------------------------------------------------------- ----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt................................. --- (112,500) (321,000)
Proceeds from long-term debt................................. --- 100,000 306,000
Short-term debt, net......................................... 55,462 --- (41,400)
Redemption of preferred stock................................ --- (49,266) (114)
Cash dividends declared on preferred stock................... --- (733) (2,285)
Cash dividends declared on common stock...................... (103,475) (157,426) (108,393)
- --------------------------------------------------------------- ----------- ----------- -----------
Net cash used in financing activities.................. (48,013) (219,925) (167,192)
- ------------------------------------------------------------------------------ ----------- -----------
NET INCREASE IN CASH AND CASH EQUIVALENTS...................... 1,467 84 28
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............... 312 228 200
CASH AND CASH EQUIVALENTS AT END OF PERIOD..................... $ 1,779 $ 312 $ 228
=============================================================== =========== =========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)....................... $ 46,257 $ 47,814 $ 54,248
Income taxes............................................... $ 51,557 $ 76,625 $ 57,150
- --------------------------------------------------------------- ----------- ----------- -----------
DISCLOSURE OF ACCOUNTING POLICY:
For purposes of these statements, the Company considers all highly liquid debt instruments purchased with
a maturity of three months or less to be cash equivalents. These investments are carried at cost which
approximates market.
============================================================================================================
</TABLE>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
45
<PAGE>
NOTES TO FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ACCOUNTING RECORDS
The accounting records of the Company are maintained in accordance with
the Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission ("FERC") and adopted by the Oklahoma Corporation Commission ("OCC")
and the Arkansas Public Service Commission ("APSC"). Additionally, the Company,
as a regulated utility, is subject to the accounting principles prescribed by
the Financial Accounting Standards Board ("FASB") Statement of Financial
Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain
Types of Regulation." SFAS No. 71 provides that certain costs that would
otherwise be charged to expense can be deferred as regulatory assets, based on
expected recovery from customers in future rates. Likewise, certain credits
that would otherwise reduce expense are deferred as regulatory liabilities based
on expected flowback to customers in future rates. Managements expected recovery
of deferred costs and flowback of deferred credits generally results from
specific decisions by regulators granting such ratemaking treatment. At
December 31, 1999, regulatory assets and regulatory liabilities are being
amortized and reflected in rates charged to customers over periods up to 20
years.
The components of deferred charges - other, on the Balance Sheets
included the following, as of December 31:
DEFERRED CHARGES - OTHER
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
Regulated Deferred Charges:
Unamortized debt expense..................................... $ 5,196 $ 5,611 $ 5,779
Unamortized loss on reacquired debt.......................... 27,281 29,072 28,660
Miscellaneous................................................ 1,317 2,217 403
- --------------------------------------------------------------- ----------- ----------- ----------
Total regulated deferred charges........................... 33,794 36,900 34,842
- --------------------------------------------------------------- ----------- ----------- -----------
Non-Regulated Deferred Charges:
Miscellaneous................................................ 7,454 3,839 6,305
- --------------------------------------------------------------- ----------- ----------- -----------
Total non-regulated deferred charges....................... 7,454 3,839 6,305
- --------------------------------------------------------------- ----------- ----------- -----------
Total Deferred Charges......................................... $ 41,248 $ 40,739 $ 41,147
============================================================================================================
</TABLE>
46
<PAGE>
<TABLE>
<CAPTION>
REGULATORY ASSETS AND LIABILITIES
(DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
Regulatory Assets:
Income taxes recoverable from customers...................... $ 93,888 $ 104,160 $ 115,989
Unamortized loss on reacquired debt.......................... 27,281 29,072 28,660
Miscellaneous................................................ 1,317 2,217 403
- --------------------------------------------------------------- ----------- ----------- -----------
Total Regulatory Assets.................................... 122,486 135,449 145,052
Regulatory Liabilities:
Income taxes refundable to customers......................... (54,196) (63,429) (73,440)
- --------------------------------------------------------------- ----------- ----------- -----------
Net Regulatory Assets.......................................... $ 68,290 $ 72,020 $ 71,612
============================================================================================================
</TABLE>
Management continuously monitors the future recoverability of regulatory
assets. When, in management's judgment, future recovery becomes impaired, the
amount of the regulatory asset is reduced or written-off, as appropriate.
If the Company were required to discontinue the application of SFAS
No.71 for some or all of its operations, it could result in writing off the
related regulatory assets; the financial effects of which could be significant.
ACCOUNTING PRONOUNCEMENTS
In March 1998, the American Institute of Certified Public accountants
("AICPA") issued Statement of Position ("SOP") 98-1, "Accounting for the Costs
of Computer Software Developed or Obtained for Internal Use." Adoption of SOP
98-1 is required for fiscal years beginning after December 15, 1998. The Company
adopted this new standard effective January 1, 1999. Adoption of this new
standard did not have a material impact on financial position or results of
operations.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and for Hedging Activities", with an effective date for periods
beginning after June 15, 1999. In July 1999, the FASB issued SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133". As a result of SFAS No. 137, adoption
of SFAS No. 133 is now required for financial statements for periods beginning
after June 15, 2000. SFAS No. 133 sweeps in a broad population of transactions
and changes the previous accounting definition of a derivative instrument. Under
SFAS No. 133, every derivative instrument is recorded in the balance sheet as
either an asset or liability measured at its fair value. SFAS No. 133 requires
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. The Company will
prospectively adopt this new standard effective January 1, 2001, and management
believes the adoption of this new standard will not have a material impact on
its financial position or results of operations.
In December 1998, the FASB Emerging Issues Task Force reached consensus
on Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities ("EITF Issue 98-10"). EITF Issue 98-10 is effective for
fiscal years beginning after December 15, 1998. EITF Issue 98-10 requires energy
trading contracts to be recorded at fair value on the balance sheet, with
changes in
47
<PAGE>
fair value included in earnings. The Company adopted this new Issue effective
January 1, 1999. Adoption of this Issue did not have a material impact on the
financial position or results of operations.
USE OF ESTIMATES
In preparing the financial statements, management is required to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
PROPERTY, PLANT AND EQUIPMENT
All property, plant and equipment is recorded at cost. Electric utility
plant is recorded at its original cost. Newly constructed plant is added to
plant balances at costs which include contracted services, direct labor,
materials, overhead and allowance for funds used during construction.
Replacement of major units of property are capitalized as plant. The replaced
plant is removed from plant balances and the cost of such property together with
the cost of removal less salvage is charged to accumulated depreciation. Repair
and replacement of minor items of property are included in the Statements of
Income as maintenance expense.
DEPRECIATION
The provision for depreciation, which was approximately 3.2 percent of
the average depreciable utility plant, for each of the years 1999, 1998 and
1997, is provided on a straight-line method over the estimated service life of
the property. Depreciation is provided at the unit level for production plant
and at the account or sub-account level for all other plant, and is based on the
average life group procedure.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction ("AFUDC") is calculated
according to FERC pronouncements for the imputed cost of equity and borrowed
funds. AFUDC, a non-cash item, is reflected as a credit on the Statements of
Income and a charge to construction work in progress.
AFUDC rates, compounded semi-annually, were 5.36, 5.75 and 5.94 percent
for the years 1999, 1998 and 1997, respectively.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value of the financial instruments on the Balance Sheets
not otherwise discussed in these notes approximate fair value.
CASH AND CASH EQUIVALENTS
For purposes of these statements, the Company considers all highly
liquid debt instruments purchased with a maturity of three months or less to be
cash equivalents. These investments are carried at cost, which approximates
market.
The Company's cash management program utilizes controlled disbursement
banking arrangements. Outstanding checks in excess of cash balances totaled
zero, $17.8 million and $18.5 million at December 31, 1999, 1998 and 1997,
respectively, and are classified as accounts payable in the
48
<PAGE>
accompanying Balance Sheets. Sufficient funds were available to fund these
outstanding checks when they were presented for payment.
HEAT PUMP LOANS
The Company has a heat pump loan program, whereby, qualifying customers
may obtain a loan from the Company to purchase a heat pump. Customer loans are
available from a minimum of $1,500 to a maximum of $13,000 with a term of 6
months to 84 months. The finance rate is based upon short-term loan rates and is
reviewed and updated periodically. The interest rates were 8.99 percent, 8.25
percent and 8.25 percent at December 31, 1999, 1998 and 1997, respectively.
The current portion of these loans totaled $0.6 million, $1.0 million
and $4.9 million at December 31, 1999, 1998 and 1997, respectively, and are
classified as accounts receivable - customers in the accompanying Balance
Sheets. The noncurrent portion of these loans totaled $2.3 million, $4.0 million
and $19.1 million at December 31, 1999, 1998 and 1997, respectively, and are
classified as other property and investments in the accompanying Balance Sheets.
The Company sold approximately $12.7 million and $25.0 million of its heat pump
loans in 1999 and 1998, respectively.
REVENUE RECOGNITION
The Company's customers are billed monthly on a cycle basis. The Company
accrues estimated revenues for services provided but not yet billed, as the cost
of providing service is recognized as incurred.
AUTOMATIC FUEL ADJUSTMENT CLAUSES
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are charged to substantially all of the Company's electric
customers through automatic fuel adjustment clauses, which are subject to
periodic review by the OCC, the APSC and the FERC.
FUEL INVENTORIES
Fuel inventories for the generation of electricity consist of coal,
natural gas and oil. These inventories are accounted for under the last-in,
first-out ("LIFO") cost method. The estimated replacement cost of fuel
inventories was lower than the stated LIFO cost by approximately $0.9 million,
$4.4 million, and $1.1 million for 1999, 1998 and 1997, respectively, based on
the average cost of fuel purchased late in the respective years.
ACCRUED VACATION
The Company accrues vacation pay by establishing a liability for
vacation earned during the current year, but is not payable until the following
year. The accrued vacation totaled $11.4 million, $12.5 million and $12.2
million at December 31, 1999, 1998 and 1997, respectively, and is classified as
other current liabilities in the accompanying Balance Sheets.
ENVIRONMENTAL COSTS
Accruals for environmental costs are recognized when it is probable that
a liability has been incurred and the amount of the liability can be reasonably
estimated. When a single estimate of the
49
<PAGE>
liability cannot be determined, the low end of the estimated range is recorded.
Costs are charged to expense or deferred as a regulatory asset based on expected
recovery from customers in future rates, if they relate to the remediation of
conditions caused by past operations or if they are not expected to mitigate or
prevent contamination from future operations. Where environmental expenditures
relate to facilities currently in use, such as pollution control equipment, the
costs may be capitalized and depreciated over the future service periods.
Estimated remediation costs are recorded at undiscounted amounts, independent of
any insurance or rate recovery, based on prior experience, assessments and
current technology. Accrued obligations are regularly adjusted as environmental
assessments and estimates are revised, and remediation efforts proceed. For
sites where the Company has been designated as one of several potentially
responsible parties, the amount accrued represents the Company's estimated share
of the cost.
RELATED PARTY TRANSACTIONS
Energy Corp. allocated operating costs to the Company of approximately
$81.9 million, $42.4 million and $2.7 million during 1999, 1998 and 1997,
respectively. Energy Corp. distributes operating costs to its affiliates based
on several factors. Operating costs directly related to specific affiliates are
assigned to those affiliates. Where more than one affiliate benefits from
certain expenditures, the costs are shared between those affiliates receiving
the benefits. Operating costs incurred for the benefit of all affiliates are
allocated among the affiliates, based primarily upon head-count, occupancy,
usage or the "Distragas" method. The Distragas method is a three-factor formula
that uses an equal weighting of payroll, operating income and assets. The
Company believes this method provides a reasonable basis for allocating common
expenses.
In 1999, 1998 and 1997, the Company paid Enogex approximately $41.5
million, $41.6 million and $41.7 million, respectively, for transporting gas to
the Company's gas-fired generating stations. In 1997, the Company began
purchasing a significant portion of its natural gas generation fuel supply
through a subsidiary of Enogex. These purchases are priced based on a market
basket of posted prices within the region and are priced similar to purchases,
which had previously been made directly from unaffiliated sources. A current
liability of approximately $6.6 million and $13.9 million at December 31, 1999
and 1998, respectively, is included in accounts payable - affiliates in the
accompanying Balance Sheets for these activities.
RECLASSIFICATIONS
Certain amounts have been reclassified on the financial statements to
conform with the 1999 presentation.
50
<PAGE>
2. INCOME TAXES
The items comprising tax expense are as follows:
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
================================================================================================================
<S> <C> <C> <C>
Provision For Current Income Taxes:
Federal.......................................................... $ 86,749 $ 73,964 $ 51,214
State............................................................ 15,016 12,563 9,330
- ------------------------------------------------------------------- ----------- ----------- -----------
Total Provision For Current Income Taxes..................... 101,765 86,527 60,544
- ------------------------------------------------------------------- ----------- ----------- -----------
Provisions (Benefit) For Deferred Income Taxes, net:
Federal
Depreciation................................................... (9,028) (1,418) 5,856
Repair allowance............................................... 1,978 1,200 794
Removal costs.................................................. 3,461 (220) 774
Salvage........................................................ (3,131) --- ---
Software implementation costs.................................. --- --- 4,840
Casualty losses................................................ 5,167 --- ---
Company restructuring.......................................... 100 22 (494)
Pension expense................................................ (2,486) 13,733 ---
Bond Redemption-unamortized costs.............................. 249 8,458 ---
Other.......................................................... (6,297) (171) 2,252
State............................................................ (1,809) 2,593 1,905
- ------------------------------------------------------------------- ----------- ----------- -----------
Total Provision (Benefit) For Deferred Income Taxes, net.... (11,796) 24,197 15,927
- ------------------------------------------------------------------- ----------- ----------- -----------
Deferred Investment Tax Credits, net............................... (5,150) (5,150) (5,150)
Income Taxes Relating to Other Income and Deductions............... 146 1,009 1,403
- ------------------------------------------------------------------- ----------- ----------- -----------
Total Income Tax Expense..................................... $ 84,965 $ 106,583 $ 72,724
- ------------------------------------------------------------------- ----------- ----------- -----------
Pretax Income...................................................... $ 224,006 $ 266,921 $ 193,718
=================================================================== =========== =========== ===========
The following schedule reconciles the statutory federal tax rate to the
effective income tax rate:
Year ended December 31 1999 1998 1997
================================================================================================================
<S> <C> <C> <C>
Statutory federal tax rate......................................... 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit.............. 3.8 3.7 3.8
Tax credits, net................................................... (2.3) (1.9) (2.7)
Other, net......................................................... 1.4 3.1 1.4
- ------------------------------------------------------------------- ----------- ----------- -----------
Effective income tax rate as reported............................ 37.9% 39.9% 37.5%
=================================================================== =========== =========== ===========
</TABLE>
51
<PAGE>
The Company is a member of an affiliated group that files consolidated
income tax returns. Income taxes are allocated to each company in the
affiliated group based on its separate taxable income or loss.
Investment tax credits on electric utility property have been deferred
and are being amortized to income over the life of the related property.
The Company follows the provisions of SFAS No. 109, "Accounting for
Income Taxes", which uses an asset and liability approach to accounting for
income taxes. Under SFAS No. 109, deferred tax assets or liabilities are
computed based on the difference between the financial statement and income tax
bases of assets and liabilities ("temporary differences") using the enacted
marginal tax rate. Deferred income tax expenses or benefits are based on the
changes in the asset or liability from period to period.
The deferred tax provisions, set forth above, are recognized as costs in
the ratemaking process by the commissions having jurisdiction over the rates
charged by the Company.
52
<PAGE>
<TABLE>
<CAPTION>
The components of Accumulated Deferred Income Taxes at December 31,
1999, 1998 and 1997 are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
Current Deferred Tax Assets:
Accrued vacation............................................. $ 5,005 $ 4,656 $ 3,853
Uncollectible accounts....................................... 1,428 945 1,540
Capitalization of indirect costs............................. 249 172 106
RAR interest................................................. 774 774 ---
Provision for Worker's Compensation claims................... 225 342 549
- --------------------------------------------------------------- ----------- ----------- -----------
Accumulated deferred tax assets.......................... $ 7,681 $ 6,889 $ 6,048
============================================================================================================
Deferred Tax Liabilities:
Accelerated depreciation and other property-related
differences................................................ $ 415,213 $ 423,527 $ 423,488
Allowance for funds used during construction................. 37,152 38,575 43,327
Income taxes recoverable through future rates................ 36,335 40,310 44,888
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... 488,700 502,412 511,703
- --------------------------------------------------------------- ----------- ----------- -----------
Deferred Tax Assets:
Deferred investment tax credits.............................. (20,130) (21,875) (23,623)
Income taxes refundable through future rates................. (20,974) (24,547) (28,421)
Postemployment medical and life insurance benefits........... (290) (1,811) (3,131)
Company pension plan......................................... (5,892) (1,447) (15,503)
Bond redemption-unamortized costs............................ 9,640 9,353 ---
Other........................................................ (1,026) 801 (1,368)
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... (38,672) (39,526) (72,046)
- --------------------------------------------------------------- ----------- ----------- -----------
Accumulated Deferred Income Tax Liabilities.................... $ 450,028 $ 462,886 $ 439,657
============================================================================================================
</TABLE>
3. COMMON STOCK AND RETAINED EARNINGS
There were no new shares of common stock issued during 1999, 1998 or
1997. The slight increase in 1998 in premium on capital stock, as presented on
the Statements of Capitalization, represents the gains associated with the
repurchased preferred stock.
4. CUMULATIVE PREFERRED STOCK
On January 15, 1998, all outstanding shares of the Company's 4%
Cumulative Preferred Stock were redeemed at the par value of $20 per share plus
accrued dividends. On January 20, 1998, all outstanding shares of the Company's
Cumulative Preferred Stock, par value $100 per share, were
53
<PAGE>
redeemed at the following amounts per share plus accrued dividends: 4.20%
series-$102; 4.24% series-$102.875; 4.44% series-$102; 4.80% series-$102; and
5.34% series-$101.
The Company's Restated Certificate of Incorporation permits the issuance
of new series of preferred stock with dividends payable other than quarterly.
5. LONG-TERM DEBT
On January 2, 1998, the Company retired $25 million principal amount of
6.375 percent First Mortgage Bonds due January 1, 1998.
On April 15, 1998, the Company issued $100.0 million in Senior Notes at
6.50 percent due April 15, 2028. The proceeds from the sale of this new debt
were applied to the redemption on April 21, 1998 of $12.5 million principal
amount of the Company's 7.125 percent First Mortgage Bonds due January 1, 1999,
$40.0 million principal amount of the Company's 7.125 percent First Mortgage
Bonds due January 1, 2002 and $35.0 million principal amount of the Company's
8.625 percent First Mortgage Bonds due November 1, 2007 and for general
corporate purposes.
The $112.5 million principal amount of the Company's First Mortgage
bonds redeemed or retired in 1998 were the last First Mortgage Bonds issued
under the First Mortgage Bond Trust Indenture dated February 1, 1945, as
supplemented and amended. Therefore, no electric plant of the Company is now
subject to the lien and sinking fund requirements of the Trust Indenture and the
lien and sinking fund requirements have been discharged.
Maturities of long-term debt during the next five years consist of $110
million in 2000.
The Company has previously incurred costs related to debt refinancings.
Unamortized debt expense and unamortized loss on reacquired debt, and
unamortized premium and discount on long-term debt are being amortized over the
life of the respective debt and are classified as deferred charges -- other and
long-term debt, respectively, in the accompanying Balance Sheets.
6. SHORT-TERM DEBT
The Company previously borrowed on a short-term basis, as necessary, by
the issuance of commercial paper and by obtaining short-term bank loans. In
April 1997, these functions were transferred to Energy Corp. At December 31,
1999, Energy Corp. had an agreement for a line of credit, up to $200 million,
$100 million was to expire January 15, 2000, and the remaining $100 million was
to expire on January 15, 2004. In January 2000, Energy Corp. increased its line
of credit to $300 million ($200 million to expire on January 15, 2001 and $100
million to expire on January 15, 2004). The Company had $55.5 million short-term
debt outstanding at December 31, 1999, which is classified as accounts
payable-affiliates on the accompanying balance sheet. The Company did not have
any short-term debt outstanding at December 31, 1998 or 1997.
7. PENSION AND POSTEMPLOYMENT BENEFIT PLANS
All eligible employees of the Company are covered by a non-contributory
defined benefit pension plan. Under the plan, retirement benefits are primarily
a function of both the years of service and the highest average monthly
compensation for 60 consecutive months out of the last 120 months of service.
54
<PAGE>
It is the Company's policy to fund the plan on a current basis to comply
with the minimum required contributions under existing tax regulations. The
Company made contributions of $2.9 million during 1999 to increase the Plan's
funded status. Such contributions are intended to provide not only for benefits
attributed to service to date, but also for those expected to be earned in the
future.
The plan's assets consist primarily of U. S. Government securities,
listed common stocks and corporate debt.
In addition to providing pension benefits, the Company provides certain
medical and life insurance benefits for retired members ("postretirement
benefits"). Employees retiring from the Company on or after attaining age 55 who
have met certain length of service requirements are entitled to these benefits.
The benefits are subject to deductibles, co-payment provisions and other
limitations. The Company charges to expense the SFAS No. 106 costs and includes
an annual amount as a component of cost-of-service in future ratemaking
proceedings.
A reconciliation of funded status of the plans and the amounts included
in the company's balance sheets:
Projected benefit obligations are as follows:
<TABLE>
<CAPTION>
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Beginning obligations........... $(303,925) $(311,017) $(277,396) $ (81,495) $ (87,557) $ (90,683)
Service cost.................... (6,018) (6,082) (5,798) (2,007) (1,600) (1,957)
Interest cost................... (19,095) (19,488) (20,226) (5,419) (5,286) (6,120)
Participant contributions....... --- --- --- (1,142) (1,051) (875)
Plan changes.................... --- (2,888) --- --- --- ---
Actuarial gains (losses)........ 44,347 (6,759) (31,501) 6,692 6,283 3,159
Benefits paid................... 17,309 19,934 23,904 8,962 7,716 6,128
Expenses........................ 708 206 --- --- --- ---
Transfer to affiliate........... --- 22,169 --- --- --- 2,791
- --------------------------------------------------------------------------------------------------------------------
Ending obligations.............. $(266,674) $(303,925) $(311,017) $ (74,409) $ (81,495) $ (87,557)
====================================================================================================================
</TABLE>
55
<PAGE>
<TABLE>
<CAPTION>
Fair value of plans' assets:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Beginning fair value............ $ 265,649 $ 234,971 $ 217,208 $ 50,588 $ 45,619 $ 39,066
Actual return on plans' assets.. 19,582 27,560 32,547 3,139 4,968 8,047
Employer contributions.......... 2,857 40,006 9,120 6,307 5,474 5,271
Participants' contributions..... --- --- --- 980 915 874
Benefits paid................... (17,309) (19,934) (23,904) (7,287) (6,388) (6,128)
Expenses........................ (708) (206) --- --- --- ---
Transfer to affiliate........... --- (16,748) --- --- --- (1,511)
- --------------------------------------------------------------------------------------------------------------------
Ending fair value............... $ 270,071 $ 265,649 $ 234,971 $ 53,727 $ 50,588 $ 45,619
====================================================================================================================
Funded status of plans:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Funded status of the plans...... $ 3,397 $ (38,276) $ (76,046) $ (20,682) $ (30,907) $ (41,938)
Unrecognized net gain (loss).... (40,225) (104) 1,702 (22,321) (17,360) (12,829)
Unrecognized prior service
benefit....................... 34,242 37,147 40,017 --- --- ---
Unrecognized transition
obligation.................... (2,347) (3,520) (5,053) 33,037 35,578 38,119
- --------------------------------------------------------------------------------------------------------------------
Net balance sheet asset
(liability)................... $ (4,933) $ (4,753) $ (39,380) $ (9,966) $ (12,689) $ (16,648)
====================================================================================================================
</TABLE>
56
<PAGE>
<TABLE>
<CAPTION>
Net Periodic Benefit Cost:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost.................... $ 6,018 $ 6,082 $ 5,798 $ 2,007 $ 1,600 $ 1,957
Interest cost................... 19,095 19,488 20,226 5,419 5,286 6,120
Return on plan assets........... (23,809) (19,173) (18,620) (3,844) (4,309) (3,445)
Amortization of transition
obligation.................... (1,173) (1,173) (1,263) 2,541 2,541 2,622
Amortization of net gain
(loss)........................ --- --- 788 (1,196) (2,129) (792)
Net amount capitalized or
deferred...................... (880) --- --- (1,086) (613) (1,293)
Amortization of unrecognized
prior service cost............ 2,906 2,905 2,937 --- --- ---
- --------------------------------------------------------------------------------------------------------------------
Net periodic benefit costs...... $ 2,157 $ 8,129 $ 9,866 $ 3,841 $ 2,376 $ 5,169
====================================================================================================================
Rate Assumptions:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Discount rate..................... 8.00% 6.75% 7.00% 8.00% 6.75% 7.00%
Rate of return on plans' assets... 9.00% 9.00% 9.00% 9.00% 9.00% 9.00%
Compensation increases............ 4.50% 4.50% 4.50% 4.50% 4.50% 4.50%
Assumed health care cost trend:
Initial trend................... N/A N/A N/A 7.00% 7.50% 8.25%
Ultimate trend rate............. N/A N/A N/A 4.50% 4.50% 4.50%
Ultimate trend year............. N/A N/A N/A 2007 2007 2007
====================================================================================================================
N/A - not applicable
</TABLE>
Assumed health care cost trend rates have a significant effect on the
amounts reported for the postretirement medical benefit plans.
The effects of a one-percentage point increase on the aggregate of the
service and interest components of the net periodic postretirement health care
benefits would be approximately $0.8 million, $0.8 million and $0.9 million at
December 31, 1999, 1998 and 1997, respectively. The effects of a one-percentage
point decrease on the aggregate of the service and interest components of the
net periodic postretirement health care benefits would be decreases of
approximately $0.7 million, $0.6 million and 0.9 million at December 31, 1999,
1998 and 1997, respectively.
57
<PAGE>
The effects of a one-percentage point increase on the aggregate of
accumulated postretirement benefit obligation for health care benefits would be
approximately $6.1 million, $7.2 million and $10.2 million at December 31, 1999,
1998 and 1997, respectively. The effects of a one-percentage point decrease on
the aggregate of accumulated postretirement benefit obligation for health care
benefits would be decreases of approximately $5.2 million, $6.1 million and $8.5
million at December 31, 1999, 1998 and 1997, respectively.
8. COMMITMENTS AND CONTINGENCIES
The Company has entered into purchase commitments in connection with its
construction program and the purchase of necessary fuel supplies of coal and
natural gas for its generating units. The Company's construction expenditures
for 2000 are estimated at $100.0 million.
The Company acquires some of its natural gas for boiler fuel under four
well-head contracts, some of which contain provisions allowing the owners to
require prepayments for gas if certain minimum quantities are not taken. At
December 31, 1999, 1998 and 1997, outstanding prepayments for gas, including the
amounts classified as current assets, under these contracts were approximately
$14.9 million, $15.2 million and $10.7 million respectively.
At December 31, 1999, the Company held non-cancelable operating leases
covering 1,495 coal hopper railcars. Rental payments are charged to fuel expense
and recovered through the Company's tariffs and automatic fuel adjustment
clauses. The leases have purchase and renewal options. Future minimum lease
payments due under the railcar leases, assuming the leases are renewed under the
renewal option are as follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
(DOLLARS IN THOUSANDS)
2000.................... $ 4,990 2003.................... $ 4,708
2001.................... 4,896 2004.................... 4,615
2002.................... 4,802 2005 and beyond......... 44,562
---------
Total Minimum Lease Payments................................ $68,573
=========
</TABLE>
Rental payments under operating leases were approximately $4.9 million
in 1999, $5.3 million in 1998, and $5.4 million in 1997.
The Company is required to maintain the railcars it has under lease to
transport coal from Wyoming and has entered into agreements with Pregressive
Rail Services and WATCO, both of which are non-affiliated companies, to furnish
this maintenance.
The Company had entered into an agreement with Central Oklahoma Oil and
Gas Corp. ("COOG"), an unrelated third-party to develop a natural gas storage
facility. Operation of the gas storage facility proved beneficial by allowing
the Company to lower fuel costs by base loading coal generation, a less costly
fuel supply. During 1996, the Company completed negotiations and contracted with
COOG for gas storage service. Pursuant to the contract, COOG reimbursed the
Company for all outstanding cash advances and interest amounting to
approximately $46.8 million. The Company also entered into a bridge financing
agreement as guarantor for COOG. In July 1997, COOG obtained permanent financing
and issued a note in the amount of $49.5 million. The proceeds from the
permanent financing were applied to repay the outstanding bridge financing. In
connection with the permanent financing, Energy Corp. entered into a note
purchase agreement, where it has agreed, upon the occurrence of a monetary
58
<PAGE>
default by COOG on its permanent financing, to purchase COOG's note at a price
equal to the unpaid principal and interest under the COOG note.
The Company has entered into agreements with four qualifying
cogeneration facilities having initial terms of 3 to 32 years. These contracts
were entered into pursuant to the Public Utility Regulatory Policy Act of 1978
("PURPA"). Stated generally, PURPA and the regulations thereunder promulgated by
FERC require the Company to purchase power generated in a manufacturing process
from a qualified cogeneration facility ("QF"). The rate for such power to be
paid by the Company was approved by the OCC. The rate generally consists of two
components: one is a rate for actual electricity purchased from the QF by the
Company; the other is a capacity charge which the Company must pay the QF for
having the capacity available. However, if no electrical power is made available
to the Company for a period of time (generally three months), the Company's
obligation to pay the capacity charge is suspended. The total cost of
cogeneration payments is recoverable in rates from customers.
During 1999, 1998, and 1997, the Company made total payments to
cogenerators of approximately $229.3 million, $226.5 million, and $212.2
million, of which $188.8 million, $185.5 million, and $176.2 million,
respectively, represented capacity payments. All payments for purchased power,
including cogeneration, are included in the Statements of Income as purchased
power. The future minimum capacity payments under the contracts for the next
five years are approximately: 2000 - $190 million, 2001 - $191 million, 2002 -
$192 million, 2003 - $163 million and 2004 - $151 million.
Approximately $1.0 million of the Company's construction expenditures
budgeted for 2000 are to comply with environmental laws and regulations.
The Company's management believes all of its operations are in
substantial compliance with present federal, state and local environmental
standards. It is estimated that the Company's total expenditures for capital,
operating, maintenance and other costs to preserve and enhance environmental
quality will be approximately $44.4 million during 2000, compared to
approximately $43.0 million in 1999. The Company continues to evaluate its
environmental management systems to ensure compliance with existing and proposed
environmental legislation and regulations and to better position itself in a
competitive market.
Beginning in 2000, the Company will be limited in the amount of sulfur
dioxide it will be allowed to emit into the atmosphere. In order to meet this
limit the Company has contracted for lower sulfur coal. The Company believes
this will allow it to meet this limit without additional capital expenditures.
With respect to nitrogen oxides, the Company continues to meet the current
emission standard. However, pending regulations on regional haze, and Oklahoma's
potential for not being able to meet the new ozone and particulate standards,
could require further reductions in sulfur dioxide and nitrogen oxides. If this
happens, significant capital expenditures and increased operating and
maintenance costs would occur.
In 1997, the United States was a signatory to the Kyoto Protocol on
global warming. If ratified by the U.S. Senate, this Protocol could have a
tremendous impact on the Company's operations, by requiring the Company to
significantly reduce the use of coal as a fuel source, since the Protocol would
require a seven percent reduction in greenhouse gas emissions below the 1990
level.
The Company is a party to two separate actions brought by the EPA
concerning cleanup of disposal sites. The Company was not the owner or operator
of those sites, rather the Company, along with many others, shipped materials to
the owners or operators of the sites who disposed of the materials. Remediation
and required monitoring at one of these sites has been completed and a consent
59
<PAGE>
decree from the EPA is being obtained for this site. The Company's total waste
disposed at the remaining site is minimal and on February 15, 1996, the Company
elected to participate in the de minimis settlement offered by EPA. One of the
other potentially responsible parties is currently contesting the Company's
participation as a de minimis party. Regardless of the outcome of this issue,
the Company believes its ultimate liability for this site is minimal.
In August 1999, the Company announced the reactivation of two of its
generators that have been idle for several years. These two generators together
produce approximately 115 megawatts of additional peak-load. The total cost of
this reactivation project is expected to be approximately $9 million. By June 1,
2000, the Company plans to begin using these generators, increasing its electric
generating capacity by approximately two percent.
Trigen-Oklahoma City Energy Corp. ("Trigen") sued the Company in the
United States District Court, Western District of Oklahoma, alleging numerous
causes of action, including monopolization of cooling services in violation of
the Sherman Act. On December 21, 1998, the jury awarded Trigen in excess of $30
million in actual and punitive damages. On February 19, 1999, the trial court
entered judgment in favor of Trigen as follows: (i) $6.8 million for various
antitrust violations, (ii) $4 million for tortious interference with an existing
contract, (iii) $7 million for tortious interference with a prospective economic
advantage and (iv) $10 million in punitive damages. The trial judge, in a
companion order, acknowledged that portions of the judgment could be
duplicative, that the antitrust amounts could be tripled and that parties should
address these issues in their post-trial motions. On January 25, 2000, a trial
judge rejected the Company's post-trial motions to reverse the jury verdict or
to grant the Company a new trial. The judge did, however, reduce the original
$30 million judgment against the Company to $20 million. On February 4, 2000,
the Company filed a notice of appeal. In addition, Trigen has filed a motion
seeking attorneys' fees and costs in an amount over $3 million. While the
outcome of an appeal is uncertain, legal counsel and management believe it is
not probable that Trigen will ultimately succeed in preserving the verdicts.
Accordingly, the Company has not accrued any loss associated with the damages
awarded. The Company believes that the ultimate resolution of this case will not
have a material adverse effect on the Company's financial position or results of
operations.
In the normal course of business, other lawsuits, claims, environmental
actions and other governmental proceedings arise against the Company.
Management, after consultation with legal counsel, does not anticipate that
liabilities arising out of other currently pending or threatened lawsuits and
claims will have a material adverse effect on the Company's financial position
or results of operations.
9. RATE MATTERS AND REGULATION
The OCC in its 1997 Order, directed the Company to commence
competitively bid gas transportation service to its gas-fired plants no later
than April 30, 2000. The order also set annual compensation for the
transportation services provided by Enogex to the Company at $41.3 million
annually until March 1, 2000, at which time the rate would drop to $28.5 million
(reflecting the completion of the recovery from ratepayers of the amortization
premium paid by the Company when it acquired Enogex in 1986) and remain at that
level until competitively-bid gas transportation begins. Final firms bids were
submitted by Enogex and other pipelines on April 15, 1999. In July 1999, the
Company filed an application with the OCC requesting approval of a
performance-based rate plan for its Oklahoma retail customers from April 2000
until the introduction of customer choice for electric power in July 2002. As
part of this application, the Company stated that Enogex had submitted the only
viable bid ($33.4 million per year) for gas transportation to its six gas-fired
power plants that were the subject of the competitive bid. As part of its
application to the OCC, the Company offered to discount Enogex's
60
<PAGE>
bid from $33.4 million annually to $25.2 million annually. The Company has
executed a new gas transportation contract with Enogex under which Enogex would
continue serving the needs of the Company's power plants at a price to be paid
by the Company of $33.4 million annually and, if the Company's proposal had been
approved by the OCC, the Company would have recovered a portion of such amount
($25.2 million) from its ratepayers. The OCC Staff, the Office of the Oklahoma
Attorney General and a coalition of industrial customers filed testimony
questioning various parts of the Company's performance-based rate plan,
including the result of the competitive bid process, and suggested, among other
things, that the bidding process be repeated or that gas transportation service
to five of the Company's gas-fired plants be awarded to parties other than
Enogex. The OCC Staff also filed testimony stating in substance that the
Company's electric rates as a whole were appropriate and did not warrant a rate
review. The Company negotiated with these parties in an effort to settle all
issues (including the competitive bid process) associated with its application
for a performance-based rate plan. When these negotiations failed, the Company
withdrew its application, which withdrawal was approved by the OCC in December
1999. Based on filed testimony, the Company believes that Enogex properly won
the competitive bid and, unless the Company's decision to award its gas
transportation service to Enogex is abrogated by order of the OCC (which order
is upheld on appeal), that it intends to fulfill its obligations under its new
gas transportation contract with Enogex at a price of $33.4 million annually.
Whether the Company will be able to recover the entire amount from its
ratepayers has not been determined as explained below.
On January 12, 2000, the Staff filed three applications to address
various aspects of the Company's electric rates. Two of the applications were
expected, while the third pertains to recoveries under the Company's fuel
adjustment clause. The first application relates to the completion of the
recovery of the amortization premium paid by the Company when it acquired Enogex
in 1986 and the resulting removal of this $12.8 million from the amounts
currently being paid annually by the Company to Enogex and being recovered by
the Company from its ratepayers. The Company has consented to this action. The
second application relates to a review of the GEP Rider, which, as part of the
OCC's 1997 Order, was scheduled for review in March 2000. The Company collected
approximately $20.8 million pursuant to the GEP Rider during 1999. A hearing on
the GEP Rider is scheduled in May 2000 and the Company intends to support the
retention of the GEP Rider with only minor modifications. The final application
relates to a review of 1999 fuel cost recoveries. The Company assumes that this
application also will be used to address the competitive bid process of its gas
transportation service. The Company cannot predict the precise outcome of these
proceedings at this time, but does not expect that they will have a material
effect on its operations.
On February 13, 1998, the APSC Staff filed a motion for a show cause
order to review the Company's electric rates in the State of Arkansas. The Staff
recommended a $3.1 million annual rate reduction (based on a test year ended
December 31, 1996). The Staff and the Company reached a settlement for a $2.3
million annual rate reduction and the APSC issued an order approving the
settlement on August 6, 1999.
10. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of Long-Term Debt and Preferred Stocks is estimated based
on quoted market prices and management's estimate of current rates available for
similar issues.
61
<PAGE>
Indicated below are the carrying amounts and estimated fair values of
the Company's financial instruments as of December 31:
<TABLE>
<CAPTION>
1999 1998 1997
------------------- ------------------- ------------------
CARRYING FAIR Carrying Fair Carrying Fair
(DOLLARS IN THOUSANDS) AMOUNT VALUE Amount Value Amount Value
======================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
Long-Term Debt and Preferred Stock:
Senior Notes........................ $457,645 $422,181 $567,512 $593,313 $556,524 $594,357
Industrial Authority Bonds.......... 135,400 135,400 135,400 135,400 135,400 135,400
Preferred Stock:
4% - 5.34% Series - zero, zero
and 827,828 shares,
respectively...................... --- --- --- --- 49,266 49,997
======================================================================================================================
</TABLE>
62
<PAGE>
Report of Independent Public Accountants
- ----------------------------------------
TO THE SHAREOWNER OF
OKLAHOMA GAS AND ELECTRIC COMPANY:
We have audited the accompanying balance sheets and statements of
capitalization of Oklahoma Gas and Electric Company (an Oklahoma corporation) as
of December 31, 1999, 1998 and 1997, and the related statements of income,
retained earnings and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Oklahoma Gas and
Electric Company as of December 31, 1999, 1998 and 1997, and the results of its
operations and its cash flows for the years then ended in conformity with
accounting principles generally accepted in the United States.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 20, 2000
63
<PAGE>
Report of Management
- --------------------
TO OUR SHAREOWNER:
The management of the Company is responsible for the preparation,
integrity and objectivity of the financial statements of the Company and other
information included in this report. The financial statements have been prepared
in conformity with accounting principles generally accepted in the United
States. As appropriate, the statements include amounts based on informed
estimates and judgments of management.
The management of the Company has established and maintains a system of
internal control designed to provide reasonable assurance, on a cost-effective
basis, that assets are safeguarded, transactions are executed in accordance with
management's authorization and financial records are reliable for preparing
financial statements. Management believes that the system of control provides
reasonable assurance that errors or irregularities that could be material to the
financial statements are prevented or would be detected within a timely period.
Key elements of this system include the effective communication of established
written policies and procedures, selection and training of qualified personnel
and organizational arrangements that provide an appropriate division of
responsibility. This system of control is augmented by an ongoing internal audit
program designed to evaluate its adequacy and effectiveness. Management
considers the recommendations of the internal auditors and independent certified
public accountants concerning the Company's system of internal control and takes
timely and appropriate actions to alleviate their concerns. Management believes
that, as of December 31, 1999, the Company's system of internal control was
adequate to accomplish the objectives discussed herein.
The Board of Directors of the Company addresses its oversight
responsibility for the financial statements through its Audit Committee, which
is composed of directors who are not employees of the Company. The Audit
Committee meets regularly with the Company's management, internal auditors and
independent certified public accountants to review matters relating to financial
reporting, auditing and internal control. To ensure auditor independence, both
the internal auditors and independent certified public accountants have full and
free access to the Audit Committee.
The independent certified public accounting firm of Arthur Andersen LLP
is engaged to audit, in accordance with auditing standards generally accepted in
the United States, the financial statements of the Company and its subsidiaries
and to issue their report thereon.
/s/ Steven E. Moore /s/ Al M. Strecker
---------------------------------------- -------------------------------
Steven E. Moore, Chairman of the Board, Al M. Strecker, Executive Vice
President and Chief Executive Officer President and Chief Operating
Officer
/s/ James R. Hatfield /s/ Donald R. Rowlett
---------------------------------------- -------------------------------
James R. Hatfield, Sr. Vice President, Donald R. Rowlett, Vice
Chief Financial Officer and Treasurer President and Controller
64
<PAGE>
Supplementary Data
- ------------------
Interim Financial Information (Unaudited)
In the opinion of the Company, the following quarterly information
includes all adjustments, consisting of normal recurring adjustments, necessary
for a fair statement of the results of operations for such periods:
<TABLE>
<CAPTION>
Quarter ended (DOLLARS IN THOUSANDS EXCEPT Dec 31 Sep 30 Jun 30 Mar 31
PER SHARE DATA)
=============================================================================================================
<S> <C> <C> <C> <C> <C>
Operating revenues............................. 1999 $ 257,616 $ 464,982 $ 314,102 $ 250,144
1998 265,207 474,209 336,017 236,645
1997 264,052 417,612 282,148 227,878
=============================================================================================================
Operating income............................... 1999 $ 18,300 $ 163,268 $ 60,697 $ 27,299
1998 29,336 193,695 85,886 6,880
1997 25,236 153,972 60,512 6,318
=============================================================================================================
Net income (loss).............................. 1999 $ 7,370 $ 87,753 $ 33,729 $ 10,189
1998 10,607 105,931 45,879 (2,079)
1997 9,155 86,601 29,123 (3,885)
=============================================================================================================
Earnings (loss) available for common stock..... 1999 $ 7,370 $ 87,753 $ 33,729 $ 10,189
1998 10,607 105,931 45,879 (2,812)
1997 8,584 86,030 28,551 (4,456)
=============================================================================================================
Earnings (loss) per average common share....... 1999 $ 0.18 $ 2.17 $ 0.84 $ 0.25
1998 0.26 2.62 1.14 (0.07)
1997 0.21 2.13 0.71 (0.11)
=============================================================================================================
</TABLE>
65
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
- --------------------------------------------------------------------
AND FINANCIAL DISCLOSURE.
-------------------------
Not Applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION.
- --------------------------------
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
- -------------------------------------------------
OWNERS AND MANAGEMENT.
----------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
- --------------------------------------------------------
Items 10, 11, 12 and 13 are omitted pursuant to General Instruction I of
Form 10-K, since the conditions set forth in General Instructions I (1)(a) and
(b) with respect to wholly owned subsidiaries have been met.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
- ----------------------------------------------------
REPORTS ON FORM 8-K.
--------------------
(A) 1. FINANCIAL STATEMENTS
- ---------------------------
The following financial statements and supplementary data are included
in Part II, Item 8 of this Report:
o Balance Sheets at December 31, 1999, 1998 and 1997
o Statements of Income for the years ended December 31, 1999, 1998 and
1997
o Statements of Retained Earnings for the years ended December 31, 1999,
1998 and 1997
o Statements of Capitalization at December 31, 1999, 1998 and 1997
o Statements of Cash Flows for the years ended December 31, 1999, 1998 and
1997
o Notes to Financial Statements
o Report of Independent Public Accountants
o Report of Management
66
<PAGE>
SUPPLEMENTARY DATA
------------------
o Interim Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE
- ----------------------------------------------------- ----
Schedule II - Valuation and Qualifying Accounts 71
Report of Independent Public Accountants 72
Financial Data Schedule 79
All other schedules have been omitted since the required information is
not applicable or is not material, or because the information required is
included in the respective financial statements or notes thereto.
3. EXHIBITS
- -----------
EXHIBIT NO. DESCRIPTION
- ----------- -----------
3.01 Copy of Restated Certificate of Incorporation.
(Filed as Exhibit 4.01 to the Company's
Registration Statement No. 33-59805,
and incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 4.02 to Post-Effective
Amendment No. Three to Registration Statement No.
2-94973 and incorporated by reference herein)
4.01 Copy of Trust Indenture, dated
October 1, 1995, from OG&E to
Boatmen's First National Bank of Oklahoma, Trustee.
(Filed as Exhibit 4.29 to Registration Statement No. 33-61821
and incorporated by reference herein)
4.02 Copy of Supplemental Trust Indenture No. 1, dated
October 16, 1995, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to
the Company's Form 8-K Report dated October 23, 1995
(File No. 1-1097) and incorporated by reference herein)
4.03 Supplemental Indenture No.2, dated as of July 1, 1997,
being a supplemental instrument to Exhibit 4.01
hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K
filed on July 17, 1997 (File No. 1-1097) and
incorporated by reference herein)
67
<PAGE>
4.04 Supplemental Indenture No. 3, dated as of April 1, 1998,
being a supplemental instrument to Exhibit 4.01
hereto. (Filed as Exhibit 4.01 to OG&E's Form
8-K filed on April 16, 1998 (File No. 1-1097)
and incorporated by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between
the Company and Atlantic Richfield Company. (Filed as
Exhibit 5.19 to Registration Statement No. 2-59887
and incorporated by reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between the Company
and Atlantic Richfield Company, together with
related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply
Agreement dated March 1, 1973, between the Company and
Atlantic Richfield Company. (Filed as Exhibit 5.28 to
Registration Statement No. 2-62208 and incorporated
by reference herein)
10.04 Amendment dated June 27, 1990, between the Company and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between the Company and Atlantic
Richfield Company. (Filed as Exhibit 10.04 to the
Company's Form 10-K Report for the year ended
December 31, 1994 (File No. 1-1097) and incorporated
by reference herein) [Confidential Treatment has been
requested for certain portions of this exhibit.]
10.05 Form of Change of Control Agreement for Officers of the Company
and Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.'s
Form 10-K Report for the year ended December 31, 1996
(File No. 1-12579) and incorporated by reference herein)
10.06 Energy Corp. Directors' Deferred Compensation Plan
(Filed as Exhibit 10.06 to Energy Corp.'s
Form 10-K Report for the year ended December 31, 1999,
(File No. 1-12579) and incorporated by reference herein)
10.07 Energy Corp.'s Stock Incentive Plan. (Filed as Exhibit 10.07
to Energy Corp.'s Form 10-K Report for the year
ended December 31, 1998 (File No. 1-12579) and
incorporated by reference herein)
68
<PAGE>
10.08 Company's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996 (File
No. 1-12579) and incorporated by reference herein)
10.09 Company's Supplemental Executive Retirement Plan.
(Filed as Exhibit 10.15 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996, File
No. 1-12579 and incorporated by reference herein)
10.10 Energy Corp.'s Annual Incentive Compensation Plan.
(Filed as Exhibit 10.12 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1998 (File
No. 1-12579) and incorporated by reference herein)
10.11 Energy Corp.'s Deferred Compensation Plan. (Filed as Exhibit 4
to Energy Corp.'s Form S-8 Registration Statement
No. 333-92423 and incorporated by reference herein)
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995
Executive Compensation Plans and Arrangements
---------------------------------------------
10.05 Form of Change of Control Agreement for Officers of the Company and
Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.'s
Form 10-K Report for the year ended December 31, 1996
(File No. 1-12579) and incorporated by reference herein)
10.06 Energy Corp. Directors' Deferred Compensation Plan
(Filed as Exhibit 10.06 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1999 (File No. 1-12579) and
incorporated by reference herein)
10.07 Energy Corp.'s Stock Incentive Plan. (Filed as Exhibit 10.07
to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1998 (File No. 1-12579) and
incorporated by reference herein)
10.08 Company's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1996 (File No. 1-12579)
and incorporated by reference herein)
69
<PAGE>
10.09 Company's Supplemental Executive Retirement Plan.
(Filed as Exhibit 10.15 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1996 (File No. 1-12579)
and incorporated by reference herein)
10.10 Energy Corp.'s Annual Incentive Compensation Plan.
(Filed as Exhibit 10.12 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1998 (File No. 1-12579)
and incorporated by reference herein)
10.11 Energy Corp.'s Deferred Compensation Plan. (Filed as Exhibit 4
to Energy Corp.'s Form S-8 Registration Statement
No. 333-92423 and incorporated by reference herein)
(B) REPORTS ON FORM 8-K
- ------------------------
Item 5. Other Events, dated July 8, 1999.
Item 5. Other Events, dated July 16, 1999.
Item 5. Other Events, dated December 8, 1999.
70
<PAGE>
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
BALANCE CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS YEAR
- ----------- --------- --------------------------- ---------- --------
<S> <C> <C> <C> <C>
1999 (THOUSANDS)
Reserve for Uncollectible Accounts $ 2,441 $ 8,596 - $ 7,632 $ 3,405
1998
Reserve for Uncollectible Accounts $ 3,583 $11,507 - $12,649 $ 2,441
1997
Reserve for Uncollectible Accounts $ 3,520 $ 7,297 - $ 7,234 $ 3,583
</TABLE>
71
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Oklahoma Gas and Electric Company:
We have audited in accordance with auditing standards generally accepted
in the United States, the financial statements of Oklahoma Gas and Electric
Company included in this Form 10-K, and have issued our report thereon dated
January 20, 2000. Our audits were made for the purpose of forming an opinion on
those statements taken as a whole. The schedule listed on Page 67, Item 14 (a)
2. is the responsibility of the Company's management and is presented for
purposes of complying with the Securities and Exchange Commission's rules and is
not part of the basic financial statements. This schedule has been subjected to
the auditing procedures applied in the audits of the basic financial statements
and, in our opinion, fairly states in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
/ s / Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 20, 2000
72
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, the Registrant has duly caused this Report to be signed on its behalf
by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and
State of Oklahoma on the 24th day of March, 2000.
OKLAHOMA GAS AND ELECTRIC COMPANY
(REGISTRANT)
/s/ Steven E. Moore
By Steven E. Moore
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this Report has been signed below by the following persons in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
- ----------------------------- ----------------------- --------------
<S> <C> <C>
/ s / Steven E. Moore
Steven E. Moore Principal Executive
Officer and Director; March 24, 2000
/ s / James R. Hatfield
James R. Hatfield Principal Financial
Officer; and March 24, 2000
/ s / Donald R. Rowlett
Donald R. Rowlett Principal Accounting
Officer. March 24, 2000
Herbert H. Champlin Director;
Luke R. Corbett Director;
William E. Durrett Director;
Martha W. Griffin Director;
Hugh L. Hembree, III Director;
Robert Kelley Director;
Bill Swisher Director; and
Ronald H. White, M.D. Director.
/ s / Steven E. Moore
By Steven E. Moore (attorney-in-fact) March 24, 2000
</TABLE>
73
<PAGE>
EXHIBIT INDEX
-------------
EXHIBIT NO. DESCRIPTION
- ----------- -----------
3.01 Copy of Restated Certificate of Incorporation.
(Filed as Exhibit 4.01 to the Company's
Registration Statement No. 33-59805,
and incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 4.02 to Post-Effective
Amendment No. Three to Registration Statement No.
2-94973 and incorporated by reference herein)
4.01 Copy of Trust Indenture dated
October 1, 1995, from OG&E to
Boatmen's First National Bank of Oklahoma, Trustee.
(Filed as Exhibit 4.29 to Registration Statement No. 33-61821
and incorporated by reference herein)
4.02 Copy of Supplemental Trust Indenture No. 1 dated
October 16, 1995, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to
the Company's Form 8-K Report dated October 23, 1995
(File No. 1-1097) and incorporated by reference herein)
4.03 Supplemental Indenture No. 2, dated as of July 1, 1997,
being a supplemental instrument to Exhibit 4.01
hereto (Filed as Exhibit 4.01 to OG&E's Form 8-K
Report filed on July 17, 1997 (File No. 1-1097) and
incorporated by reference herein)
4.04 Supplemental Indenture No. 3, dated as of April 1, 1998,
being a supplemental instrument to Exhibit 4.01
hereto. (Filed as Exhibit 4.01 to OG&E's Form
8-K Report filed on April 16, 1998 (File No. 1-1097)
and incorporated by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between
the Company and Atlantic Richfield Company. (Filed as
Exhibit 5.19 to Registration Statement No. 2-59887
and incorporated by reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between the Company
and Atlantic Richfield Company, together with
related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
74
<PAGE>
10.03 Second Amendment dated March 1, 1978, to Coal Supply
Agreement dated March 1, 1973, between the Company and
Atlantic Richfield Company. (Filed as Exhibit 5.28
to Registration Statement No. 2-62208 and incorporated
by reference herein)
10.04 Amendment dated June 27, 1990, between the Company and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between the Company and Atlantic
Richfield Company. (Filed as Exhibit 10.04 to the
Company's Form 10-K Report for the year ended
December 31, 1994 (File No. 1-1097) and incorporated
by reference herein) [Confidential Treatment has been
requested for certain portions of this exhibit.]
10.05 Form of Change of Control Agreement for Officers of the Company
and Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.'s
Form 10-K Report for the year ended December 31, 1996
(File No. 1-12579) and incorporated by reference herein)
10.06 Energy Corp. Directors' Deferred Compensation Plan
(Filed as Exhibit 10.06 to Energy Corp.'s
Form 10-K Report for the year ended December 31, 1999
(File No. 1-12579) and incorporated by reference herein)
10.07 Energy Corp.'s Stock Incentive Plan. (Filed as Exhibit 10.07
to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1998 (File No. 1-12579) and incorporated
by reference herein)
10.08 Company's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996 (File
No. 1-12579) and incorporated by reference herein)
10.09 Company's Supplemental Executive Retirement Plan.
(Filed as Exhibit 10.15 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996 (File
No. 1-12579) and incorporated by reference herein)
10.10 Energy Corp.'s Annual Incentive Compensation Plan.
(Filed as Exhibit 10.12 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1998 (File
No. 1-12579) and incorporated by reference herein)
10.11 Energy Corp.'s Deferred Compensation Plan. (Filed as Exhibit 4
to the Company's Form S-8 Registration Statement
No. 333-92423 and incorporated by reference herein)
23.01 Consent of Arthur Andersen LLP.
75
<PAGE>
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995
76
EXHIBIT 23.01
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated January 20, 2000 included in the Oklahoma Gas
and Electric Company Form 10-K for the year ended December 31, 1999, into the
previously filed Form S-3 Registration Statement No. 333-46169, Form S-3
Registration Statement No. 333-21059 and Form S-4 Registration Statement No.
33-61699.
/ s / Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
March 24, 2000
77
EXHIBIT 24.01
POWER OF ATTORNEY
WHEREAS, OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation
(herein referred to as the "Company"), is about to file with the Securities and
Exchange Commission, under the provisions of the Securities Exchange Act of
1934, as amended, its annual report on Form 10-K for the year ended December 31,
1999; and
WHEREAS, each of the undersigned holds the office or offices in the
Company herein-below set opposite his or her name, respectively;
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints
STEVEN E. MOORE, JAMES R. HATFIELD and DONALD R. ROWLETT, and each of them
individually, his or her attorney with full power to act for him or her and in
his or her name, place and stead, to sign his name in the capacity or capacities
set forth below to said Form 10-K and to any and all amendments thereto, and
hereby ratifies and confirms all that said attorney may or shall lawfully do or
cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this
19th day of January 2000.
Steven E. Moore, Chairman, Principal
Executive Officer and Director / s / Steven E. Moore
-----------------------------
Herbert H. Champlin, Director / s / Herbert H. Champlin
-----------------------------
Luke R. Corbett, Director / s / Luke R. Corbett
-----------------------------
William E. Durrett, Director / s / William E. Durrett
-----------------------------
Martha W. Griffin, Director / s / Martha W. Griffin
-----------------------------
Hugh L. Hembree, III, Director / s / Hugh L. Hembree, III
-----------------------------
Robert Kelley, Director / s / Robert Kelley
-----------------------------
Bill Swisher, Director / s / Bill Swisher
-----------------------------
Ronald H. White, M.D., Director / s / Ronald H. White, M.D.
-----------------------------
James R. Hatfield, Principal Financial Officer / s / James R. Hatfield
-----------------------------
Donald R. Rowlett, Principal Accounting Officer / s / Donald R. Rowlett
-----------------------------
STATE OF OKLAHOMA )
) SS
COUNTY OF OKLAHOMA )
On the date indicated above, before me, Debbie Peters, Notary Public in
and for said County and State, personally appeared the above named directors and
officers of OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation, and
known to me to be the persons whose names are subscribed to the foregoing
instrument, and they, severally, acknowledged to me that they executed the same
as their own free act and deed.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official
seal on the 19th day of January, 2000.
/s/ Debbie Peters
Debbie Peters
Notary Public in and for the County
of Oklahoma, State of Oklahoma
My Commission
Expires: May 3, 2003
78
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Oklahoma Gas and Electric Company Statements of Income, Balance Sheets, and
Statements of Cash Flow as reported on Form 10-K as of December 31, 1999 and is
qualified in its entirety by reference to such Form 10-K.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,952,367
<OTHER-PROPERTY-AND-INVEST> 12,731
<TOTAL-CURRENT-ASSETS> 262,822
<TOTAL-DEFERRED-CHARGES> 92,740
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,320,660
<COMMON> 100,947
<CAPITAL-SURPLUS-PAID-IN> 411,499
<RETAINED-EARNINGS> 376,691
<TOTAL-COMMON-STOCKHOLDERS-EQ> 889,137
0
0
<LONG-TERM-DEBT-NET> 593,045
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 110,000
0
<CAPITAL-LEASE-OBLIGATIONS> 131
<LEASES-CURRENT> 2,119
<OTHER-ITEMS-CAPITAL-AND-LIAB> 726,228
<TOT-CAPITALIZATION-AND-LIAB> 2,320,660
<GROSS-OPERATING-REVENUE> 1,286,844
<INCOME-TAX-EXPENSE> 84,965
<OTHER-OPERATING-EXPENSES> 1,017,280
<TOTAL-OPERATING-EXPENSES> 1,102,245
<OPERATING-INCOME-LOSS> 184,599
<OTHER-INCOME-NET> 381
<INCOME-BEFORE-INTEREST-EXPEN> 184,980
<TOTAL-INTEREST-EXPENSE> 45,939
<NET-INCOME> 139,041
0
<EARNINGS-AVAILABLE-FOR-COMM> 139,041
<COMMON-STOCK-DIVIDENDS> 103,475
<TOTAL-INTEREST-ON-BONDS> 44,813
<CASH-FLOW-OPERATIONS> 150,743
<EPS-BASIC> 3.44
<EPS-DILUTED> 3.44
</TABLE>
EXHIBIT 99.01
OKLAHOMA GAS AND ELECTRIC COMPANY CAUTIONARY FACTORS
The Private Securities Litigation Reform Act of 1995 provides a "safe
harbor" for forward-looking statements to encourage such disclosures without the
threat of litigation providing those statements are identified as
forward-looking and are accompanied by meaningful, cautionary statements
identifying important factors that could cause the actual results to differ
materially from those projected in the statement. Forward-looking statements
have been and will be made in written documents and oral presentations of
Oklahoma Gas and Electric Company (the "Company"). Such statements are based on
management's beliefs as well as assumptions made by and information currently
available to management. When used in the Company's documents or oral
presentations, the words "anticipate", "estimate", "expect", "objective" and
similar expressions are intended to identify forward-looking statements. In
addition to any assumptions and other factors referred to specifically in
connection with such forward-looking statements, factors that could cause the
Company's actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following:
o Increased competition in the utility industry, including effects of:
decreasing margins as a result of competitive pressures; industry
restructuring initiatives; transmission system operation and/or
administration initiatives; recovery of investments made under
traditional regulation; nature of competitors entering the industry;
retail wheeling; a new pricing structure; and former customers entering
the generation market;
o Changing market conditions and a variety of other factors associated
with physical energy and financial trading activities including, but not
limited to, price, basis, credit, liquidity, volatility, capacity,
transmission, currency, interest rate and warranty risks;
o Risks associated with price risk management strategies intended to
mitigate exposure to adverse movement in the prices of electricity and
natural gas on both a global and regional basis;
o Economic conditions including inflation rates and monetary fluctuations;
o Customer business conditions including demand for their products or
services and supply of labor and materials used in creating their
products and services;
o Financial or regulatory accounting principles or policies imposed by the
Financial Accounting Standards Board, the Securities and Exchange
Commission, the Federal Energy Regulatory Commission, state public
utility commissions, state entities which regulate natural gas
transmission, gathering and processing and similar entities with
regulatory oversight;
o Availability or cost of capital such as changes in: interest rates,
market perceptions of the utility and energy-related industries, the
Company or security ratings;
o Factors affecting utility operations such as unusual weather conditions;
catastrophic weather-related damage; unscheduled generation outages,
unusual maintenance or repairs; unanticipated changes to fossil fuel, or
gas supply costs or availability due to higher demand, shortages,
transportation problems or other developments; environmental incidents;
or electric transmission or gas pipeline system constraints;
80
<PAGE>
o Employee workforce factors including changes in key executives,
collective bargaining agreements with union employees, or work
stoppages;
o Rate-setting policies or procedures of regulatory entities, including
environmental externalities;
o Social attitudes regarding the utility, natural gas and power
industries;
o Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims and matters, including but not
limited to those described in Note 8 of the Notes to Financial
Statements of the Company's Annual Report on Form 10-K for the year
ended December 31, 1999, under the caption Commitments and
Contingencies;
o Technological developments, changing markets and other factors that
result in competitive disadvantages and create the potential for
impairment of existing assets;
o Other business or investment considerations that may be disclosed from
time to time in the Company's Securities and Exchange Commission filings
or in other publicly disseminated written documents.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
81
