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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, 1998 Commission File Number 1-1097
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. [ ]
As of February 26, 1999, 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.
The Proxy statement for the 1999 annual meeting of shareowners of OGE
Energy Corp., the parent of the Registrant is incorporated by reference into
Part III of this Report.
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TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
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......... 11
Fuel Supply............................................. 12
Environmental Matters............................................ 14
Item 2. Properties....................................................... 17
Item 3. Legal Proceedings................................................ 18
Item 4. Submission of Matters to a Vote of Security Holders.............. 21
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters..................................... 26
Item 6. Selected Financial Data.......................................... 27
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 28
Item 8. Financial Statements and Supplementary Data...................... 40
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure ............................... 68
PART III
Item 10. Directors and Executive Officers of the Registrant............... 68
Item 11. Executive Compensation........................................... 68
Item 12. Security Ownership of Certain Beneficial
Owners and Management................................... 68
Item 13. Certain Relationships and Related Transactions................... 68
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K..................................... 68
i
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 and its former subsidiary, Enogex Inc. and Enogex Inc.'s
subsidiaries (collectively, "Enogex") became subsidiaries of Energy Corp. on
December 31, 1996 pursuant to a mandatory share exchange whereby each share of
outstanding common stock of the Company was exchanged on a share-for-share basis
for common stock of Energy Corp. Immediately following this exchange, the
Company transferred its shares of Enogex stock to Energy Corp. and Enogex became
a direct subsidiary of Energy Corp. Energy Corp. now serves as the parent
company to the Company, Enogex, Origen Inc. and any other companies that may be
formed within the organization in the future. The new holding company structure
is intended to provide greater flexibility to take advantage of opportunities in
an increasingly competitive business environment and to clearly separate the
electric utility business from the non-utility businesses for regulatory,
capital structure and other purposes.
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 5,561,180
kilowatts.
At the end of 1998, the Company had 2,068 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
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. This
legislation, if implemented as proposed, would significantly impact the Company.
The Arkansas Public Service Commission ("APSC") has initiated proceedings to
consider the implementation of a competitive retail market in Arkansas. 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 1998, 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 91 percent of total electric operating revenues for the
year ended December 31, 1998, 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 5,529 megawatts, and occurred on
August 27, 1998. The Company's load responsibility peak demand was approximately
5,247 megawatts on July 30, 1998, resulting in a capacity margin of
approximately 14.4 percent. The Company is a member, along with neighboring
utilities and other electric suppliers, in the Southwest Power Pool ("SPP"),
which requires that the Company maintain a capacity reserve margin of 13
percent. As reflected in the table below and in the operating statistics on page
3, total kilowatt-hour sales increased 4.2 percent in 1998 as compared to an
increase of 1.6 percent in 1997 and a 1.5 percent decrease in 1996. In 1998,
kilowatt-hour sales to the Company's customers ("system sales") increased 6.6
percent due to warmer weather and continued customer growth. Sales to other
utilities and power marketers ("off-system sales") decreased in 1998; however,
various factors (including the summer heat, unit availability and storms) drove
prices of the off-system electricity to record levels, increasing operating
revenues and at margins significantly higher than had been experienced in the
past. There can be no assurance that such margins on future off-system sales
will occur again. In 1997 and 1996, 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:
SALES (Millions of Kwh)
INC/ Inc/ Inc/
1998 (DEC) 1997 (Dec) 1996 (Dec)
- --------------------------------------------------------------------------------
System Sales 23,642 6.6% 22,183 3.0% 21,541 3.4%
Off-system Sales 728 (39.5%) 1,202 (18.5%) 1,475 (20.4%)
------- ------- -------
Total Sales 24,370 4.2% 23,385 1.6% 23,016 1.5%
======= ======= =======
In 1998, the Company's Sooner Generating Station (consisting of two
coal-fired units with an aggregate capability of 1,031 Mw) and the Company's
three coal-fired units at its Muskogee Generating Station (with an aggregate
capability of 1,491 Mw) were again recognized by an industry survey as being in
the top 20 lowest cost producers of electricity for the third consecutive year.
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
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
YEAR ENDED DECEMBER 31
1998 1997 1996
------------- ------------- -------------
ELECTRIC ENERGY:
(Millions of Kwh)
Generation (exclusive of station use)................... 22,565 21,620 21,253
Purchased............................................... 3,984 3,528 3,564
------------- ------------- -------------
Total generated and purchased..................... 26,549 25,148 24,817
Company use, free service and losses.................... (2,179) (1,763) (1,801)
------------- ------------- -------------
Electric energy sold.............................. 24,370 23,385 23,016
------------- ------------- -------------
ELECTRIC ENERGY SOLD:
(Millions of Kwh)
Residential............................................. 7,959 7,179 7,143
Commercial and industrial............................... 11,912 11,586 11,161
Public street and highway lighting...................... 68 68 67
Other sales to public authorities....................... 2,352 2,202 2,096
Sales for resale........................................ 2,079 2,350 2,549
------------- ------------- -------------
Total............................................. 24,370 23,385 23,016
============= ============= =============
ELECTRIC OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential......................................... $ 537,486 $ 474,419 $ 479,574
Commercial and industrial........................... 554,589 526,673 530,213
Public street and highway lighting.................. 9,618 9,456 9,367
Other sales to public authorities................... 110,522 98,818 98,209
Sales for resale.................................... 76,198 57,695 60,141
Provision for rate refund........................... --- --- (1,221)
Miscellaneous....................................... 23,665 24,630 24,054
------------- ------------- -------------
Total Electric Revenues........................... $ 1,312,078 $ 1,191,691 $ 1,200,337
============= ============= =============
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential............................................. 598,378 593,699 588,778
Commercial and industrial............................... 86,251 85,315 84,032
Public street and highway lighting...................... 249 249 249
Other sales to public authorities....................... 11,183 10,897 10,688
Sales for resale........................................ 39 40 41
------------- ------------- -------------
Total............................................. 696,100 690,200 683,788
============= ============= =============
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (Kwh)................................ 13,342 12,133 12,178
Average annual revenue.................................. $ 900.94 $ 801.74 $ 817.62
Average price per Kwh (cents)........................... 6.75 6.61 6.71
3
FINANCE AND CONSTRUCTION
The Company generally meets its cash needs through internally generated
funds, short-term borrowings and permanent financing. Cash flows from operations
remained strong in 1998 and 1997, which enabled the Company to internally
generate the required funds to satisfy construction expenditures during these
years.
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 1999 through 2001 are
estimated as follows:
(DOLLARS IN MILLIONS) 1999 2000 2001
================================================================================
Construction expenditures
Including AFUDC................... $ 101.7 $ 100.0 $ 100.0
Maturities of long-term debt........ --- 110.0 ---
- --------------------------------------------------------------------------------
Total........................... $ 101.7 $ 210.0 $ 100.0
================================================================================
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 and sinking fund
obligations. Approximately $0.5 million of the Company's construction
expenditures budgeted for 1999 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.
Energy Corp. will continue to use short-term borrowings to meet the
temporary cash requirements of the Company. The Company has the necessary
regulatory approvals to incur up to $400 million in short-term borrowings at any
one time. The Company had no short-term debt outstanding at December 31, 1998.
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 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 financing under its Senior Note Indenture than existed
under the First Mortgage Bond Trust Indenture.
4
In accordance with the requirements of the Public Utility Regulatory
Policies Act of 1978 ("PURPA") (see "Regulation and Rates - National Energy
Legislation"), the Company is obligated to purchase 110 megawatts of capacity
annually from Smith Cogeneration, Inc., 320 megawatts annually from Applied
Energy Services, Inc., another qualified cogeneration facility and up to 110
megawatts of capacity from Mid-Continent Power Company ("MCPC"). The Company
also has agreed to purchase energy not needed by the Sparks Regional Medical
Center from its nominal seven megawatt cogeneration facility.
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 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.
As part of the corporate reorganization whereby the Company became a
subsidiary of Energy Corp., the Company obtained the approval of the OCC. The
order of the OCC authorizing the Company to reorganize into a holding company
structure 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, 1998, approximately 87 percent of the
Company's electric revenue was subject to the jurisdiction of the OCC, seven
percent to the APSC, and six percent to the FERC.
RECENT REGULATORY MATTERS: In January 1998, the Company filed an
---------------------------
application with the OCC seeking approval to revise an existing cogeneration
contract with MCPC, a cogeneration plant near Pryor, Oklahoma. As part of this
transaction, Energy Corp. agreed to purchase the stock of Oklahoma Loan
Acquisition Corporation ("OLAC"), the company that owned the MCPC plant, for
approximately $25 million. The Company obtained the required regulatory
approvals from the OCC, APSC and FERC. If the transaction had been completed,
the term of the existing cogeneration contract would have been reduced by four
and one-half years, which would have reduced the amounts to be paid by the
Company, and would have provided savings for its Oklahoma customers, of
approximately $46 million as compared to the existing cogeneration contract.
Following an arbitrator's decision that the owner of the stock of OLAC could not
sell the stock of OLAC to Energy Corp. until it had offered such stock to a
third party on the same terms as it was offered to Energy Corp., the third party
purchased the stock of OLAC and assumed ownership of the cogeneration plant in
October 1998. The effect of this transaction is that the Company's original
contract with the cogeneration plant remains in place.
5
On February 11, 1997, the OCC issued an 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 order
also directed the Company to transition to competitive bidding of its gas
transportation requirements currently met by Enogex no later than April 30,
2000, and set annual compensation for the transportation services provided by
Enogex to the Company at $41.3 million until competitively-bid gas
transportation begins. Other pipelines seeking to compete with Enogex for the
Company's business will likely have to pay a fee to Enogex for transporting gas
on Enogex's system or incur capital expenditures to develop the necessary
infrastructure to connect with the Company's gas-fired generating stations.
Nevertheless, a potential outcome of the competitive bidding process is that the
revenues of Enogex derived from transporting gas for OG&E may be significantly
less after April 30, 2000.
The Order also contained a 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.
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 1998, the GEP Rider increased revenues (compared to
1997) by approximately $10.0 million, or approximately $0.15 per share. The
current GEP Rider is estimated to positively impact revenue by $33 million or
approximately $0.52 per share during the 12 months ending June 1999.
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:
l. 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;
6
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 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
7
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 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 is to address: (i) technical issues
(including reliability, safety, unbundling of generation, transmission and
distribution services, transition issues and
8
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 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 and 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 Oklahoma.
A new bill was introduced in the State Senate in January 1999 and if
enacted would clarify ambiguities by defining key terms in the Act.
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. While it is
9
not expected that the General Assembly will enact legislation in regular
session, a special session of the General Assembly may be called to continue the
debate.
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
is recommending a $3.1 million annual rate reduction (based on a test year ended
December 31, 1996). The Company has filed its cost of service study and has
requested a $1.7 million annual rate increase. A decision on this rate case is
expected in the next few months.
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.
NATIONAL ENERGY LEGISLATION: Federal law imposes numerous
--------------------------------
responsibilities and requirements on the Company. The PURPA 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.
See "Finance and Construction." 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 ("EPAct") 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 EPAct, 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 EPAct 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.
In April 1996, FERC issued two final rules, Orders 888 and 889, which
are having a significant impact on wholesale markets. These orders were
subsequently amended in orders issued in March and November 1997. Order 888 set
forth rules on non-discriminatory open access transmission service to promote
wholesale competition. Order 888, which was effective on July 9, 1996, requires
utilities and other transmission users to abide by comparable terms, conditions
and pricing in transmitting power. Order 889, which had its effective date
extended to January 3, 1997, requires public utilities to implement Standards of
Conduct and an Open Access Same Time Information System ("OASIS," formerly known
as "Real-Time Information Networks"). These rules require transmission personnel
to provide the same information about the transmission system to all
transmission customers using the OASIS. In 1997, the FERC issued clarifying
final orders in response to rehearing requests by numerous market participants
regarding Orders No. 888 and 889. During 1998, the Company submitted filings to
the FERC to comply with these Orders, and those filings have been accepted. As
the Company continues to prepare for restructuring at the retail level, it is
expected that additional filings will be made in order to maintain continuing
compliance with the FERC's wholesale restructuring orders.
10
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.
As discussed previously, Oklahoma enacted legislation that will
restructure the electric utility industry in Oklahoma by July 2002, 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 (net of related regulatory liabilities) or a non-cash, pre-tax write-off
as an extraordinary charge of up to $31 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 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.
The EPAct, the actions of the FERC, the restructuring proposal in
Oklahoma, the Arkansas legislative debate 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 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 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 has
implemented numerous energy efficiency programs and tariff schedules. In 1998,
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
11
standards; (ii) a load curtailment rate for industrial and commercial customers
who can demonstrate a load curtailment of at least 500 kilowatts (the minimum
load of the curtailment rate was raised in the February 11, 1997, OCC order);
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 continued a Real Time Pricing ("RTP") pilot program, first
implemented in 1997, 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. Real Time Pricing is a tariff option that
prices electricity so that 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 1998 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.
Other recent efforts to improve the Company's services included the
implementation of a new customer service telephone system capable of handling
approximately ten times more calls simultaneously than the prior system and
implementation of a Company-wide enterprise software system that, besides being
Year 2000 ready, enables the Company to obtain extensive business information on
nearly a real-time basis. Also, the Company is in the process of implementing a
new outage management system that should improve the Company's ability to
restore service, and a new mapping system that, when completed, will provide the
Company up to date information on its transmission and distribution assets.
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. 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, the Edison Electric Institute ("EEI") is
helping fund $65 million for EMF studies over a five-year period, that began in
1994. One-half of this amount is expected to be funded by the federal
government, and two-thirds of the non-federal funding is expected to be provided
by the electric utility industry. 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 1998, approximately 68 percent of the Company generated energy
was produced by coal-fired units and 32 percent by natural gas-fired units. It
is estimated that the fuel mix for 1999 through 2003, based upon expected
generation for these years, will be as follows:
12
1999 2000 2001 2002 2003
- --------------------------------------------------------------------------------
Coal............................ 70% 76% 76% 74% 74%
Natural Gas..................... 30% 24% 24% 26% 26%
The increase from 70 percent to 76 percent in the percentage of
coal-fired generation relative to total generation is expected to result from
improvements in coal delivery performance. The slight decline from 76 percent to
74 percent in 2002 and 2003 is expected to result from increases in natural
gas-fired generation in those years, not from a reduction in Kwh of coal-fired
generation.
The average cost of fuel used, by type, per million Btu for each of the
5 years was as follows:
1998 1997 1996 1995 1994
- --------------------------------------------------------------------------------
Coal............................ $0.85 $0.84 $0.83 $0.83 $0.78
Natural Gas..................... $2.83 $3.60 $3.61 $3.19 $3.58
Weighted Avg.................... $1.48 $1.39 $1.45 $1.41 $1.58
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 Company coal units, with an aggregate capability
----------------
of 2,522 megawatts, are designed to burn low sulfur western coal. OG&E purchases
coal under a mix of long- and short-term contracts. During 1998, the Company
purchased 9.9 million tons of coal from the following Wyoming suppliers: Amax
Coal West, Inc., Caballo Rojo, Inc., Kennecott Energy Company, Thunder Basin
Coal Company and Powder River 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.
During 1998, rail congestion continued on the Union Pacific Railroad
causing coal shortage among many of the utilities in the Southwest Power Pool
and the state of Texas. As a result, the Company depleted its coal stockpiles
and was forced to take some coal conservation measures in November and December.
Since that time, rail service has improved. During 1998, 1997, and 1996, the
Company used larger unit trains with a maximum of 135 cars instead of a maximum
of 112 cars in unit train service to the Muskogee Generating Station. Increasing
the unit train size allows for an increase of delivered tons by approximately 21
percent. The combination of high volume, aluminum design and increased train
size to the Muskogee Generating Station reduces the number of trips from Wyoming
by approximately 29 percent. The Company 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.
13
GAS-FIRED UNITS: For calendar year 1999, 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 1999 will be supplied by contracts
with at-market pricing or through day-to-day purchases on the spot market.
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 $40.8 million during 1999, compared to
approximately $44.2 million utilized in 1998. Approximately $0.5 million of the
Company's construction expenditures budgeted for 1999 are to comply with
environmental laws and regulations. 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.
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, OG&E believes it can meet the SO2 limits without additional
capital expenditures. In 1998, the Company emitted 54,801 tons of SO2.
With respect to the nitrogen oxide ("NOx") regulations of Title IV of
the CAAA, the Company 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
for 1998 was 0.36 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
$0.3 million in fees in 1998.
Other potential air regulations have emerged that could impact the
Company. The Ozone Transport Assessment Group ("OTAG") studied long range
transport of ozone and its precursors across a thirty-seven state area. The
study was completed in 1997 but as a result of the efforts of the Company and
others, Oklahoma and 14 other states were exempted from any OTAG emission
reduction requirements. However, in the fall of 1998, EPA proposed a further
study of ozone transport from these 15 states to determine if emissions
reductions in these states are warranted. If reductions had been
14
required in Oklahoma, the Company could have been forced to reduce its NOx
emissions even further from the limits imposed by Title IV of the Act.
In 1997, EPA finalized revisions to the ambient ozone and particulate
standards. Based on current ozone data, Tulsa and Oklahoma counties will likely
fail to meet the proposed 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.
By mid 1999, EPA is expected to issue 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. 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.
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 1998, the Company obtained refunds of approximately
$155,000 from its recycling efforts. This figure does not include the additional
savings gained through the reduction and/or a 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 made application for renewal of all of its National
Pollutant Discharge Elimination system permits. The Company has received all of
the permits in final form except one, which is pending regulatory action. All of
the permits issued to date offer greater operational flexibility than those in
the past.
The Company has 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 facility could be subjected to standards that will require
costly treatment and/or facility reconfiguration. The request for the removal of
this classification has been approved at the state level and is awaiting
approval by EPA.
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 identified as having been
contaminated by historical operations was addressed during
15
1998. 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
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 5,561 megawatts. The following table sets forth information with
respect to present electric generating facilities, all of which are located in
Oklahoma:
Unit Station
Year Capability Capability
Station & Unit Fuel Installed (Megawatts) (Megawatts)
- -------------- ---- --------- ----------- -----------
Seminole 1 Gas 1971 515.0
2 Gas 1973 507.0
3 Gas 1975 500.0 1,522
Muskogee 3 Gas 1956 165.0
4 Coal 1977 492.5
5 Coal 1978 492.5
6 Coal 1984 506.0 1,656
Sooner 1 Coal 1979 514.0
2 Coal 1980 517.0 1,031
Horseshoe 6 Gas 1958 172.0
Lake 7 Gas 1963 237.0
8 Gas 1969 396.0 805
Mustang 1 Gas 1950 58.0 Inactive
2 Gas 1951 57.0 Inactive
3 Gas 1955 120.0
4 Gas 1959 260.0
5 Gas 1971 63.0 443
Conoco 1 Gas 1991 25.5
2 Gas 1991 29.5 55
Arbuckle 1 Gas 1953 74.0 Inactive
Enid 1 Gas 1965 9.8
2 Gas 1965 9.6
3 Gas 1965 11.0
4 Gas 1965 9.6 40
Woodward 1 Gas 1963 9.0 9
-----------
Total Active Generating Capability (all stations) 5,561
===========
17
At December 31, 1998, the Company's transmission system included: (i)
65 substations with a total capacity of approximately 15.5 million kVA and
approximately 4,003 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) 300 substations with a total capacity of
approximately 4.1 million kVA, 19,998 structure miles of overhead lines, 1,623
miles of underground conduit and 6,623 miles of underground conductors in
Oklahoma; and (ii) 30 substations with a total capacity of approximately 617,500
kVA, 1,658 structure miles of overhead lines, 165 miles of underground conduit
and 369 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, 1998, the Company's gross
property, plant and equipment additions approximated $276 million and gross
retirements approximated $116 million. These additions were provided by
internally generated funds. The additions during this three-year period amounted
to approximately 7.5 percent of total property, plant and equipment at December
31, 1998.
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 judgement for the Company. Plaintiffs have filed an appeal, which is
pending with the Tenth Circuit Court of Appeals.
While the Company cannot predict the precise outcome of the proceeding,
the Company continues to believe that the lawsuit is without merit and will not
have a material adverse effect on its results of operations or financial
condition.
2. The Company is also involved,along with numerous other Potentially
Responsible Parties ("PRP"), in an EPA administrative action involving the
facility in Holden, Missouri, of Martha C. Rose Chemicals, Inc. ("Rose").
Beginning in early 1983 through 1986, Rose was engaged in the business of
brokering of polychlorinated biphenyls ("PCBs") and PCB items, processing of PCB
capacitors and
18
transformers for disposal, and decontamination of mineral oil dielectric fluids
containing PCBs. During this time period, various generators of PCBs
("Generators"), including the Company, shipped materials containing PCBs to the
facility. Contrary to its contractual obligation with the Company and other
Generators, it appears that Rose failed to manage, handle and dispose of the
PCBs and the PCB items in accordance with the applicable law. Rose has been
issued citations by both the EPA and the Occupational Safety and Health
Administration. Several Generators, including OG&E, formed a Steering Committee
to investigate and clean up the Rose facility.
The Company's share of the total hazardous wastes at the Rose facility
was less than six percent. The remediation of this site was completed in 1995 by
the Steering Committee and is currently in the final stages of closure with the
EPA, which includes operation and maintenance activities as required in the
Administrative Order on Consent with the EPA. Due to additional funds resulting
from payments by third party companies who were not a part of the Steering
Committee, and also reduced remedy implementation costs, the Company received a
refund in December 1995 under the allocation formula. The Company has reached a
settlement agreement with its insurance carrier, AEGIS Insurance Company, with
respect to costs incurred at this site. The Company considers this insurance
matter to be closed.
Management believes that the Company's ultimate liability for any
additional cleanup costs of this site will not have a material adverse effect on
the Company's financial position or its results of operations. Management's
opinion is based on the following: (i) the present status of the site; (ii) the
cleanup costs already paid by certain parties; (iii) the financial viability of
the other PRPs; (iv) the portion of the total waste disposed at this site
attributable to the Company; and (v) the Company's settlement agreement with its
insurer. Management also believes that costs incurred in connection with this
site, which are not recovered from insurance carriers or other parties, may be
allowable costs for future ratemaking purposes. Absent an unforeseen
contingency, the Company believes this matter is now closed.
3. 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.
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.
4. 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, ss. 1; (iv) discriminatory sales in violation of 79 O.S. 1991, ss. 4;
(v) tortuous interference with contract; and (vi) tortuous 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 judgement in favor of Trigen as
19
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 judgement could be duplicative, that the antitrust amounts could
be tripled and that parties should address these issues in their post-trial
motions. The Company has filed its post trial motions requesting judgement in
its favor or a new trial. If a successful result is not obtained at the trial
level, the Company will appeal. 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 consolidated financial position or results of operations.
5. As previously reported, the State of Oklahoma, ex rel., Teresa
Harvey (Carroll); Margaret B. Fent and Jerry R. Fent v. Oklahoma Gas and
Electric Company, et al., District Court, Oklahoma County, Case No.
CJ-97-1242-63. On February 24, 1997, the taxpayers instituted litigation against
the Company and Co-Defendants Oklahoma Corporation Commission, Oklahoma Tax
Commission and individual commissioners seeking judgment in the amount of
$970,184.14 and treble penalties of $2,910,552.42, plus interest and costs, for
overcharges refunded by the Company to its ratepayers in compliance with an
Order of the OCC which Plaintiffs allege was illegal. Plaintiffs allege the
refunds should have been paid into the state Unclaimed Property Fund. In June
1997, the Company's Motion for Summary Judgment was granted. Plaintiffs
appealed. On April 10, 1998, the Court of Civil Appeals affirmed the order of
the trial court granting OG&E Summary Judgment. On April 29, 1998, Plaintiffs
petitioned the Court of Civil Appeals for rehearing. Plaintiffs' Petition for
Rehearing was overruled. Plaintiffs timely filed a Petition for Certiorari with
the Oklahoma Supreme Court. The Oklahoma Supreme Court denied Certiorari.
Plaintiffs did not file their Petition for Certiorari with the United States
Supreme Court in time required. Case closed.
6. As reported, 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 (a) 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;
(b) 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; (c) violations
of the Oklahoma Open Meetings Act occurred and that such violations render the
resolution approving Ordinance No. 97-30 invalid; (d) the Company's support of
the Enid Citizens' Against the Government Takeover was improper; (e) the Company
has violated the favored nations clause of the existing franchise; and (f) 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 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
20
prejudice in December 1997. On December 8, 1997, the Company filed a Motion to
Dismiss Case No. CJ-97-829-01 for failures 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
- ------------------------------------------------------------
None
21
EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------
The following persons were Executive Officers of the Registrant as of
March 15, 1999:
Name Age Title
- -------------------- --- --------------------------------------
Steven E. Moore 52 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 55 Executive Vice President and
Chief Operating Officer
Melvin D. Bowen, Jr. 57 Vice President - Power Delivery
Jack T. Coffman 55 Vice President - Power Supply
Michael G. Davis 49 Vice President - Marketing and
Customer Care
Irma B. Elliott 60 Vice President and
Corporate Secretary
James R. Hatfield 41 Vice President and Treasurer
Steven R. Gerdes 42 Vice President, Shared
Services
Donald R. Rowlett 41 Controller Corporate Accounting
Don L. Young 58 Controller Corporate Audits
No family relationship exists between any of the Executive Officers of
the Registrant. Each Officer is to hold office until the Board of Directors
meeting following the next Annual Meeting of Shareowners, currently scheduled
for May 27, 1999.
22
The business experience of each of the Executive Officers of the
Registrant for the past five years is as follows:
Name Business Experience
- -------------------- ------------------------------------------------
Steven E. Moore 1996-Present: Chairman of the Board,
President and Chief
Executive Officer -
Energy Corp.
1996-Present: Chairman of the Board,
President and Chief
Executive Officer
1995-1996: President and Chief
Operating Officer
1994-1995: Senior Vice President - Law
and Public Affairs
Al M. Strecker 1998-Present: Executive Vice President and
Chief Operating Officer -
Energy Corp.
1998-Present: Executive Vice President and
Chief Operating Officer
1996-1998: Senior Vice President -
Energy Corp.
1994-1998: Senior Vice President -
Finance and
Administration
1994: Vice President and
Treasurer
Melvin D. Bowen, Jr. 1994-Present: Vice President -
Power Delivery
1994: Metro Region
Superintendent
Jack T. Coffman 1994-Present: Vice President -
Power Supply
1994: Manager - Generation
Services
23
Name Business Experience
- -------------------- ------------------------------------------------
Michael G. Davis 1996-Present: Vice President - Energy
Corp.
1994-Present: Vice President -
Marketing and
Customer Care
1994: Director - Marketing
Division
Irma B. Elliott 1996-Present: Vice President and
Corporate Secretary -
Energy Corp.
1996-Present: Vice President and
Corporate Secretary
1994-1996: Corporate Secretary
James R. Hatfield 1997-Present: Vice President and
Treasurer - Energy
Corp.
1997-Present: Vice President and
Treasurer
1994-1997: Treasurer
1994: Vice President - Investor
Relations & Corporate
Secretary - Aquila Gas
Pipeline Corporation
Steven R. Gerdes 1998-Present: Vice President, Shared
Services - Energy Corp.
1998-Present: Vice President, Shared
Services
1997-1998: Director, Shared Services
1997: Manager, Enterprise Support
1994-1997: Manager, Purchasing &
Material Management
1994: Manager, Purchasing
24
Name Business Experience
- -------------------- ------------------------------------------------
Donald R. Rowlett 1998-Present: Controller Corporate
Accounting - Energy Corp.
1996-Present: Controller Corporate
Accounting
1994-1996: Assistant Controller
1994: Senior Specialist -
Tax Accounting
Don L. Young 1998-Present: Controller Corporate Audits
- Energy Corp.
1996-Present: Controller Corporate Audits
1994-1996: Controller
25
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.
26
ITEM 6. SELECTED FINANCIAL DATA.
- --------------------------------
HISTORICAL DATA
As Restated - See Note 1
to Consolidated Financial Statements
---------------------------------------------
1998 1997 1996 1995 1994
---------------------------------------------------------------------------
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS EXCEPT
FOR PER SHARE DATA)
Operating revenues................. $1,312,078 $1,191,690 $1,200,337 $1,168,287 $1,196,898
Operating expenses................. 1,101,855 1,016,973 1,022,988 987,270 1,016,074
----------- ----------- ----------- ----------- -----------
Operating income................... 210,223 174,717 177,349 181,017 180,824
Other income and deductions........ (1,014) 2,224 (914) 2,272 321
Interest charges................... 48,871 55,947 59,566 70,745 67,350
----------- ----------- ----------- ----------- -----------
Net income......................... 160,338 120,944 116,869 112,544 113,795
Preferred dividend
requirements..................... 733 2,285 2,302 2,316 2,317
Earnings available for
common........................... $ 159,605 $ 118,709 $ 114,567 $ 110,228 $ 111,478
=========== =========== =========== =========== ===========
Long-term debt..................... $ 702,912 $ 691,924 $ 709,281 $ 723,862 $ 723,667
Total assets....................... $2,320,097 $2,350,782 $2,421,241 $2,754,871 $2,782,629
Earnings per average common
share............................ $ 3.95 $ 2.94 $ 2.84 $ 2.73 $ 2.76
CAPITALIZATION RATIOS*
Common equity...................... 54.84% 53.46% 52.57% 54.78% 54.35%
Cumulative preferred stock......... --- 3.09% 3.09% 2.92% 2.95%
Long-term debt..................... 45.16% 43.45% 44.34% 42.30% 42.70%
INTEREST COVERAGES*
Before federal income taxes
(including AFUDC)................ 6.34X 4.43X 4.09X 3.49X 3.66X
(excluding AFUDC)................ 6.32X 4.42X 4.08X 3.47X 3.64X
After federal income taxes
(including AFUDC)................ 4.21X 3.14X 2.94X 2.56X 2.66X
(excluding AFUDC)................ 4.19X 3.13X 2.93X 2.55X 2.65X
* These amounts do not include Enogex.
27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- --------------------------------------------------------------------------------
OF OPERATIONS.
- -------------
MANAGEMENT'S DISCUSSION AND ANALYSIS.
OVERVIEW
Percent Change
From Prior Year
---------------
(THOUSANDS EXCEPT PER SHARE AMOUNTS) 1998 1997 1996 1998 1997
==================================================================================================
Operating revenues...................... $1,312,078 $1,191,690 $1,200,337 10.1 (0.7)
Earnings available for common stock..... $ 159,605 $ 118,709 $ 114,567 34.5 3.6
Average shares outstanding.............. 40,379 40,379 40,367 --- ---
Earnings per average common share....... $ 3.95 $ 2.94 $ 2.84 34.4 3.5
Dividends paid per share................ $ 3.90 $ 2.68 $ 2.66 45.5 0.8
==================================================================================================
Oklahoma Gas and Electric Company (the "Company") is an operating
public utility engaged in the generation, transmission, distribution, and sale
of electric energy. OGE Energy Corp. ("Energy Corp.") became the parent company
of the Company and its former subsidiary, Enogex Inc. ("Enogex") on December 31,
1996 in a corporate reorganization whereby all common stock of the Company was
exchanged on a share-for-share basis for common stock of Energy Corp. Under this
corporate structure, the new holding company serves as the parent company to the
Company, Enogex and any other companies that may be formed within the
organization in the future. Also, effective December 31, 1996, the Company
distributed its ownership of Enogex to Energy Corp. Although Enogex continues to
operate as a subsidiary of Energy Corp., for purposes of these consolidated
financial statements, Enogex has been accounted for as discontinued operations
and prior year consolidated financial statements have been restated to reflect
that accounting. This holding company structure is intended to provide greater
flexibility to take advantage of opportunities in an increasingly competitive
business environment and to clearly separate the Company's electric utility
business from Energy Corp.'s non-utility businesses.
Earnings for 1998 increased 34.4 percent from $2.94 per share in 1997
to $3.95 per share in 1998. The increase was primarily the result of higher
revenues due to warmer weather, the Generation Efficiency Performance Rider
("GEP Rider"), higher margin sales to other utilities and power marketers
("off-system sales"), customer growth and lower operation and maintenance
expenses. 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
1997 increase is primarily the result of the GEP Rider, lower interest costs and
customer growth in the Company's service area.
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. The
Arkansas Public Service Commission ("APSC") has initiated proceedings to
consider the implementation of a competitive retail market in Arkansas. These
developments are described in more detail below under "Regulation; Competition."
28
In 1996, the Company decided upon an enterprise-wide software system
which is Year 2000 ready for its businesses. Enterprise software is a corporate
software system designed to handle most of the Company's information processing
needs and to improve work processes throughout the Company. The enterprise
software system was successfully implemented throughout the Company on January
1, 1997 and is expected to significantly enhance the Company's abilities in the
more competitive years ahead.
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 Consolidated
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 weather; regulatory decisions and
the other risk factors listed in the reports filed by the Company with the
Securities and Exchange Commission.
29
RESULTS OF OPERATIONS
REVENUES
Percent Change
From Prior Year
---------------
(THOUSANDS) 1998 1997 1996 1998 1997
===================================================================================================
Sales of electricity to Company
customers.............................. $1,274,643 $1,168,663 $1,173,961 9.1 (0.5)
Provisions for rate refund............... --- --- (1,221) --- *
Sales of electricity to other utilities.. 37,435 23,027 27,597 62.6 (16.6)
- ----------------------------------------------------------------------------------
Total operating revenues............... $1,312,078 $1,191,690 $1,200,337 10.1 (0.7)
===================================================================================================
System kilowatt-hour sales............... 23,642,599 22,182,992 21,540,670 6.6 3.0
Kilowatt-hour sales to other utilities... 727,601 1,201,933 1,475,449 (39.5) (18.5)
- ----------------------------------------------------------------------------------
Total kilowatt-hour sales.............. 24,370,200 23,384,925 23,016,119 4.2 1.6
===================================================================================================
*Not meaningful
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 Consolidated Financial Statements for a
discussion of the impact of the OCC's February 11, 1997, rate order on these
transportation fees.
Operating revenues increased $120.4 million or 10.1 percent during
1998. This increase was due to an increase in kilowatt-hour sales to Company
customers ("system sales") from warmer weather, the GEP Rider, higher margin
sales to other utilities and power marketers ("off-system sales") and customer
growth. Kilowatt-hour sales by the Company to other utilities decreased 39.5
percent in 1998, however, the summer heat drove prices of this off-system
electricity to record levels, increasing operating revenues approximately $14.4
million in 1998 and at margins significantly higher than had been experienced in
the past. There can be no assurance that such margins on future off-system sales
will occur again. During 1997, operating revenues decreased $8.6 million or 0.7
percent due to the rate reduction in March 1997 and milder weather in the first
and second quarters of 1997. This decrease in revenues was partially offset by
continued customer growth, the effect of the GEP Rider and warmer weather in the
third quarter of 1997.
On February 11, 1997, the OCC issued an order (the "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. This $50 million rate reduction is in addition to the $15 million rate
reduction that was effective January 1, 1995. The Order also directed the
Company to transition to competitive bidding of its gas
30
transportation requirements, currently met by Enogex, no later than April 30,
2000, and set annual compensation for the transportation services provided by
Enogex to the Company at $41.3 million until competitively-bid gas
transportation begins.
The 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.
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 1998, the GEP Rider increased revenues (compared to
1997) by approximately $10.0 million, or approximately $0.15 per share. The
current GEP Rider is estimated to positively impact revenue by $33 million or
approximately $0.52 per share during the 12 months ending June 1999.
EXPENSES AND OTHER ITEMS
Percent Change
From Prior Year
---------------
(DOLLARS IN THOUSANDS) 1998 1997 1996 1998 1997
==================================================================================================
Fuel .................................... $ 356,781 $ 319,494 $ 323,412 11.7 (1.2)
Purchased power.......................... 240,542 222,464 222,070 8.1 0.2
Other operation and maintenance.......... 239,614 245,943 253,176 (2.6) (2.9)
Depreciation and amortization............ 116,214 114,760 112,233 1.3 2.3
Taxes.................................... 148,704 114,312 112,097 30.1 2.0
- ----------------------------------------------------------------------------------
Total operating expenses............... $1,101,855 $1,016,973 $1,022,988 8.3 (0.6)
==================================================================================================
Total operating expenses increased $84.9 million or 8.3 percent in
1998, primarily due to increases in quantities of fuel burned for the production
of electricity and increased taxes.
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 1998, fuel costs
increased due to a modest increase in total generation and a slight increase in
the average cost of fuel burned for generation of electricity. During 1997,
despite a slight increase in kwh sales, fuel costs decreased $3.9 million or 1.2
percent primarily due to an increase in the percentage of coal-fired generation
relative to total generation.
Other operation and maintenance decreased $6.3 million or 2.6 percent
in 1998 primarily because of decreases in post retirement medical costs, bad
debt expense, completion in February 1997 of the
31
amortization of the $48.9 million regulatory asset established in connection
with the Company's 1994 workforce reduction and general corporate expenses. In
1997, other operation and maintenance expenses decreased $7.2 million or 2.9
percent in 1997, primarily due to the completion of the VERP amortization in
February 1997 and costs associated with the development of the enterprise-wide
software in 1996.
In 1998, taxes increased $34.4 million or 30.1 percent primarily due to
significantly higher pre-tax income and normally occurring temporary
differences. In 1997, taxes increased primarily due to an increase in deferred
taxes associated with depreciation.
Purchased power costs increased $18.1 million or 8.1 percent in 1998,
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. In 1997, purchased power costs were $222.5
million, remaining relatively constant compared to the $222.1 million in 1996.
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. In addition to the
February 11, 1997, OCC Order, the APSC issued an order in July 1996 requiring,
among other things, a $4.5 million refund. See Note 9 of Notes to Consolidated
Financial Statements for a discussion of the July 1996 order.
The Company has initiated numerous ongoing programs that have helped
reduce the cost of generating electricity over the last several years. These
programs include: 1) utilizing a natural gas storage facility; 2) spot market
purchases of coal; 3) renegotiated contracts for coal, gas, railcar maintenance
and coal transportation; and 4) 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.
The increases in depreciation and amortization for 1998 and 1997
reflects higher levels of depreciable plant.
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.
The decrease in interest expense for 1997 was attributable to the Company
retiring $15 million of 5.125 percent First Mortgage Bonds in January 1997, the
successful refinancing of $306 million of long-term debt in 1997, and a lower
average daily balance in short-term debt.
LIQUIDITY, CAPITAL RESOURCES AND CONTINGENCIES
The primary capital requirements for 1998 and as estimated for 1999
through 2001 are as follows:
32
(DOLLARS IN MILLIONS) 1998 1999 2000 2001
================================================================================
Construction expenditures
including AFUDC........................ $ 96.7 $101.7 $100.0 $100.0
Maturities of long-term debt............. 25.0 --- 110.0 ---
- --------------------------------------------------------------------------------
Total................................ $121.7 $101.7 $210.0 $100.0
================================================================================
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 and sinking fund obligations. The Company
generally meets its cash needs through a combination of internally generated
funds, short-term borrowings and permanent financing.
1998 CAPITAL REQUIREMENTS AND FINANCING ACTIVITIES
Capital requirements were $96.7 million in 1998. Approximately $300,000
of the 1998 capital requirements were to comply with environmental regulations.
This compares to capital requirements of $100.1 million in 1997, of which $1.0
million were to comply with environmental regulations.
During 1998, the Company's primary source of capital was internally
generated funds from operating cash flows. Operating cash flow remained strong
in 1998 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 had no
short-term debt outstanding at December 31, 1998.
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.
In February 1997, the Company filed a registration statement for up to
$50 million of grantor trust preferred securities. Assuming favorable market
conditions, the Company may issue all or part of the $50 million of grantor
trust preferred stock.
33
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 $0.5 million of the Company's construction expenditures budgeted
for 1999 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.
As previously reported, in January 1998, the Company filed an
application with the OCC seeking approval to revise an existing cogeneration
contract with Mid-Continent Power Company ("MCPC"), a cogeneration plant near
Pryor, Oklahoma. As part of this transaction, Energy Corp. agreed to purchase
the stock of Oklahoma Loan Acquisition Corporation ("OLAC"), the company that
owned the MCPC plant, for approximately $25 million. The Company obtained the
required regulatory approvals from the OCC, APSC and FERC. If the transaction
was completed, the term of the existing cogeneration contract would have been
reduced by four and one-half years, which would have reduced the amounts to be
paid by the Company, and would have provided savings for its Oklahoma customers,
of approximately $46 million as compared to the existing cogeneration contract.
Following an arbitrator's decision that the owner of the stock of OLAC could not
sell the stock of OLAC to Energy Corp. until it had offered such stock to a
third party on the same terms as it was offered to Energy Corp., the third party
purchased the stock of OLAC and assumed ownership of the cogeneration plant in
October 1998. The effect of this transaction is that the Company's original
contract with the cogeneration plant remains in place.
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, 1998,
Energy Corp. had in place a line of credit for up to $160 million, which was to
expire December 6, 2000. In January 1999, Energy Corp.
increased its line of credit to $200 million.
THE YEAR 2000 ISSUE
There has been a great deal of publicity about the Year 2000 (Y2K) and
the possible problems that information technology systems may suffer as a
result. The Y2K problem originated with the early development of computerized
business applications. To save then-expensive storage space, reduce the
complexity of calculations and yield better system performance, programmers and
developers used a two-digit date scheme to represent the year (i.e., "72" for
"1972"). This two-digit date scheme was used well into the 1980s and 1990s in
traditional computer hardware such as mainframe systems, desktop personal
computers and network servers, in customized software systems, off-the-shelf
applications and operating systems, as well as in embedded systems ("chips") in
everything from elevators to industrial plants to consumer products. As the Year
2000 approaches, date-sensitive systems may recognize the Year 2000
34
as 1900, or not at all. This inability to recognize or properly treat the Year
2000 may cause systems, including those of the Company, its customers,
suppliers, business partners and neighboring utilities to process critical
financial and operational information incorrectly, if they are not Year 2000
ready. A failure to identify and correct any such processing problems prior to
January 1, 2000 could result in material operational and financial risks if the
affected systems either cease to function or produce erroneous data. Such risks
are described in more detail below, but could include an inability to operate
the Company's generating plants, disruptions in the operation of its
transmission and distribution system and an inability to access interconnections
with the systems of neighboring utilities.
After the Company's mainframe conversion in 1994, some 300 programs
were identified as having date sensitive code. All of these programs have since
been corrected or will be replaced by Y2K ready packaged applications.
The Company continues to address the Y2K issues in an aggressive
manner. This is reflected by the January 1, 1997 implementation throughout the
Company of SAP Enterprise Software, which is Y2K ready, for the financial
systems. The SAP installation significantly reduced the potential risks in our
older computer systems. The Company is making significant progress towards the
implementation of the enterprise-wide software system for customer systems. In
addition to significantly reducing the potential risks of its current customer
systems, the Company is set to streamline work processes in customer service and
power delivery by integrating separate systems into a single system using the
enterprise-wide software system. This new single system will also provide for a
more flexible automated billing system and enhancements in handling customer
service orders, energy outage incidents and customer services.
In October of 1997, the Company formed a multi-functional Y2K Project
Team of experienced and knowledgeable members from each business unit to review
and test its operational systems in an effort to further eliminate any potential
problems, should they exist. The team provides regular monthly reports on its
progress to the Y2K Executive Steering Committee and senior management as well
as helping prepare presentations to the Board of Directors.
The Company's Year 2000 effort generally follows a three-phase process:
Phase I - Inventory and Assess Y2K Issues
Phase II - Determine Y2K Readiness of Vendors, Suppliers & Customers
Phase III - Correct, Test, Implement Solutions and Contingency
Planning
STATE OF READINESS
The Company has substantially completed the internal inventory and
assessment (Phase 1) of the Year 2000 plan. Follow-up vendor surveys are being
sent to vendors that have not responded to our original requests for information
(Phase II). Remediation efforts are ongoing and even though contingency planning
is a normal part of our business, plans have been prepared to include specific
activities with regard to Y2K issues (Phase III).
In addition, as a part of the Company's three-year lease agreement for
personal computers, all new personal computers are being issued with operating
systems and application software that is Y2K ready. All existing personal
computers will be upgraded with Y2K ready operating systems before the turn of
the century. For embedded and plant operational systems, the Company has
generally completed the evaluative process and is commencing corrective plans.
In particular, the Company's Energy Management System ("EMS") that monitors
transmission interconnections and automatically signals
35
generation output changes, has been contracted for replacement in 1999.
Equipment has been ordered and software is currently being configured.
The Company is also participating in an "Electric System Readiness
Assessment" program, which provides monthly reports to the Southwest Power Pool
("SPP") and the North American Electric Reliability Council ("NERC"). The
responses from all participating companies are being compiled for an
industry-wide status report to the Department of Energy ("DOE"). Also, in
February 1999, the Company submitted contingency plans to the NERC and the SPP
which will be used along with those of other participating companies to
formulate a regional contingency plan.
COSTS OF YEAR 2000 ISSUES
As described above, with the mainframe conversion, the enterprise
software installations and the EMS replacement, 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. In addition to
the $1 million spent to date for Y2K issues, since 1995 the Company has spent in
excess of $29 million on the mainframe conversion, the enterprise software
installations and the EMS replacement. The Company expects to spend slightly
less than $5 million in 1999. These costs represent estimates, however, and
there can be no assurance that actual costs associated with the Company's Y2K
issues will not be higher.
RISKS OF YEAR 2000 ISSUES
As described above, the Company has made significant progress in the
implementation of its Year 2000 plan. Based upon the information currently known
regarding its internal operations and assuming successful and timely completion
of its remediation plan, the Company does not anticipate significant business
disruptions from its internal systems due to the Y2K issue. However, the Company
may possibly experience limited interruptions to some aspects of its activities,
whether information technology, operational, administrative or otherwise, and
the Company is considering such potential occurrences in planning for its most
reasonably likely worst case scenarios.
Additionally, risk exists regarding the non-readiness of third parties
with key business or operational importance to the Company. Year 2000 problems
affecting key customers, interconnected utilities, fuel suppliers and
transporters, telecommunications providers or financial institutions could
result in lost power or gas sales, reductions in power production or
transmission or internal functional and administrative difficulties on the part
of the Company. Although the Company is not presently aware of any such
situations, occurrences of this type, if severe, could have material adverse
impacts upon the business, operating results or financial condition of the
Company. There can be no assurance that the Company will be able to identify and
correct all aspects of the Year 2000 problem that affect it in sufficient time,
that it will develop adequate contingency plans or that the costs of achieving
Y2K readiness will not be material.
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 Consolidated 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
36
materials. Remediation of one of these sites has been completed. 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 the
Environmental Protection Agency ("EPA"), which is being contested by one party.
This limits the Company's financial obligation in addition to removing any
participation in the site remedy. 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 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 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 January 1, 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
$0.3 million in 1998 and are estimated to be approximately $0.4 million in 1999.
REGULATION; COMPETITION
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 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 the State of 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 directs 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 remaining parts of the
Study due October 1, 1999 include: 1) technical issues (including reliability,
safety, unbundling of generation, transmission and distribution services,
transition issues and market power); 2) financial issues (including rates,
charges, access fees, transition costs and stranded costs); 3) consumer issues
(such as the obligation to serve, service territories, consumer choices,
competition and consumer safeguards); and 4) tax issues (including sales and use
taxes, ad valorem taxes and franchise fees).
37
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 Oklahoma.
A new bill was introduced in the State Senate in January 1999 and if
enacted would clarify certain ambiguities by defining key terms in the Act.
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 on these
issues to the Arkansas General Assembly.
On February 11, 1997, the OCC issued an Order, among other things,
directing the Company to transition to competitive bidding for its gas
transportation requirements, currently met by Enogex, no later than April 30,
2000. This Order also set annual compensation for the transportation services
provided by Enogex to the Company at $41.3 million until competitively-bid gas
transportation begins. In 1998, approximately $41.6 million or 8.2 percent of
Enogex's revenues were attributable to transporting gas for the Company. Other
pipelines seeking to compete with Enogex for the Company's business will likely
have to pay a fee to Enogex for transporting gas on Enogex's system or incur
capital expenditures to develop the necessary infrastructure to connect with the
Company's gas-fired generating stations. Nevertheless, a potential outcome of
the competitive bidding process is that the revenues of Enogex derived from
transporting gas for OG&E may be significantly less after April 30, 2000.
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.
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 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.
In April 1996, the FERC issued two final rules, Orders 888 and 889,
which are having a significant impact on wholesale markets. Order 888 sets forth
rules on non-discriminatory open access transmission service to promote
wholesale competition. Order 888, which was effective on July 9, 1996, requires
utilities and other transmission users to abide by comparable terms, conditions
and pricing in transmitting power. Order 889, which had its effective date
extended to January 3, 1997, requires public utilities to implement Standards of
Conduct and an Open Access Same Time Information System
38
("OASIS", formerly known as "Real-Time Information Networks"). These rules
require transmission personnel to provide the same information about the
transmission system to all transmission customers using the OASIS. In 1997, the
FERC issued clarifying final orders in response to rehearing requests by
numerous market participants regarding Orders No. 888 and 889. During 1998, the
Company submitted filings to the FERC to comply with these Orders, and those
filings have been accepted. As the Company continues to prepare for
restructuring at the retail level, it is expected that additional filings will
be made in order to maintain continuing compliance with the FERC's wholesale
restructuring orders.
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.
As discussed previously, Oklahoma enacted legislation that will
restructure the electric utility industry in Oklahoma by July 2002, 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 $31 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 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.
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
is recommending a $3.1 million annual rate reduction (based on a test year ended
December 31, 1996). The Company filed its cost of service study and has
requested a $1.7 million annual rate increase. A decision on this rate case is
expected in the next few months.
Besides the existing contingencies described above, and those described
in Note 8 of Notes to Consolidated 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.
39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
- ----------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
Year ended December 31 (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1998 1997 1996
================================================================================================================
OPERATING REVENUES................................................. $1,312,078 $1,191,690 $1,200,337
- ----------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Fuel............................................................. 356,781 319,494 323,412
Purchased power.................................................. 240,542 222,464 222,070
Other operation and maintenance.................................. 239,614 245,943 253,176
Depreciation and amortization.................................... 116,214 114,760 112,233
Current income taxes............................................. 86,527 60,544 73,171
Deferred income taxes, net....................................... 24,197 15,927 2,156
Deferred investment tax credits, net............................. (5,150) (5,150) (5,150)
Taxes other than income.......................................... 43,130 42,991 41,920
- ----------------------------------------------------------------------------------------------------------------
Total operating expenses....................................... 1,101,855 1,016,973 1,022,988
- ----------------------------------------------------------------------------------------------------------------
OPERATING INCOME................................................... 210,223 174,717 177,349
- ----------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
Interest income.................................................. 2,315 4,531 3,187
Other............................................................ (3,329) (2,307) (4,101)
- ----------------------------------------------------------------------------------------------------------------
Net other income and deductions................................ (1,014) 2,224 (914)
- ----------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt....................................... 44,515 53,281 54,141
Allowance for borrowed funds used during construction............ (1,071) (599) (709)
Other............................................................ 5,427 3,265 6,134
- ----------------------------------------------------------------------------------------------------------------
Total interest charges, net.................................... 48,871 55,947 59,566
- ----------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS.................................. 160,338 120,994 116,869
INCOME FROM OPERATIONS OF ENOGEX DISTRIBUTED
TO OGE ENERGY CORP. (less applicable taxes of $8,050)............ --- --- 16,463
- ----------------------------------------------------------------------------------------------------------------
NET INCOME......................................................... 160,338 120,994 133,332
PREFERRED DIVIDEND REQUIREMENTS.................................... 733 2,285 2,302
- ----------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON STOCK................................ $ 159,605 $ 118,709 $ 131,030
================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING.................................. 40,379 40,379 40,367
EARNINGS PER AVERAGE COMMON SHARE:
Income from continuing operations................................ $ 3.95 $ 2.94 $ 2.84
Income from Enogex operations.................................... --- --- 0.41
- ----------------------------------------------------------------------------------------------------------------
Earnings per average common share.............................. $ 3.95 $ 2.94 $ 3.25
================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
40
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year ended December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
BALANCE AT BEGINNING OF PERIOD................................. $ 338,946 $ 328,630 $ 425,545
ADD:
Income from continuing operations............................ 160,338 120,994 116,869
Income from operations of Enogex............................. --- --- 16,463
- ------------------------------------------------------------------------------------------------------------
Total...................................................... 499,284 449,624 558,877
DEDUCT:
Cash dividends declared on preferred stock................... 733 2,285 2,302
Cash dividends declared on common stock...................... 157,426 108,393 107,377
- ------------------------------------------------------------------------------------------------------------
Total Cash Dividends....................................... 158,159 110,678 109,679
Distribution of Enogex to OGE Energy Corp.................... --- --- 120,568
- ------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD....................................... $ 341,125 $ 338,946 $ 328,630
============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
41
CONSOLIDATED BALANCE SHEETS
December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service................................................... $3,674,732 $3,647,366 $3,574,241
Construction work in progress................................ 28,439 18,910 26,807
- ------------------------------------------------------------------------------------------------------------
Total property, plant and equipment........................ 3,703,171 3,666,276 3,601,048
Less accumulated depreciation............................ 1,727,472 1,653,771 1,560,546
- ------------------------------------------------------------------------------------------------------------
Net property, plant and equipment............................ 1,975,699 2,012,505 2,040,502
- ------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost........................ 17,454 28,140 21,869
- ------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents.................................... 312 228 200
Accounts receivable - customers, less reserve of $2,441,
$3,583 and $3,520, respectively............................ 91,434 92,379 96,067
Accrued unbilled revenues.................................... 22,500 36,900 34,900
Accounts receivable - other.................................. 7,723 9,795 44,699
Fuel inventories, at LIFO cost............................... 47,081 43,577 60,463
Materials and supplies, at average cost...................... 25,894 24,481 20,387
Prepayments and other........................................ 28,641 2,533 3,094
Accumulated deferred tax assets.............................. 6,889 6,048 8,994
- ------------------------------------------------------------------------------------------------------------
Total current assets....................................... 230,474 215,941 268,804
- ------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Advance payments for gas..................................... 15,000 10,500 9,500
Income taxes recoverable - future rates...................... 40,731 42,549 44,368
Other........................................................ 40,739 41,147 36,198
- ------------------------------------------------------------------------------------------------------------
Total deferred charges..................................... 96,470 94,196 90,066
- ------------------------------------------------------------------------------------------------------------
TOTAL ASSETS................................................... $2,320,097 $2,350,782 $2,421,241
============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
42
CONSOLIDATED BALANCE SHEETS (Continued)
December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statements):
Common stock and retained earnings........................... $ 853,571 $ 851,390 $ 841,035
Cumulative preferred stock................................... --- 49,266 49,379
Long-term debt............................................... 702,912 691,924 709,281
- ------------------------------------------------------------------------------------------------------------
Total capitalization....................................... 1,556,483 1,592,580 1,599,695
- ------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Short-term debt.............................................. --- --- 41,400
Accounts payable - affiliates................................ 67,045 14,986 ---
Accounts payable............................................. 45,536 47,802 63,596
Dividends payable............................................ --- 571 27,421
Customers' deposits.......................................... 23,984 23,846 23,257
Accrued taxes................................................ 18,932 18,963 25,037
Accrued interest............................................. 15,931 15,746 16,386
Long-term debt due within one year........................... --- 25,000 15,000
Other........................................................ 38,642 35,386 35,739
- ------------------------------------------------------------------------------------------------------------
Total current liabilities.................................. 210,070 182,300 247,836
- ------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation....................... 18,162 57,418 57,137
Accumulated deferred income taxes............................ 462,886 439,657 429,766
Accumulated deferred investment tax credits.................. 67,728 72,878 78,028
Other........................................................ 4,768 5,949 8,779
- ------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities............... 553,544 575,902 573,710
- ------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 8 and 9)
- ------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES........................... $2,320,097 $2,350,782 $2,421,241
============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
43
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
==================================================================================================================
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 46,470,616 shares, respectively.............................. $ 100,947 $ 100,947 $ 116,177
Premium on capital stock........................................... 411,499 411,497 608,544
Retained earnings.................................................. 341,125 338,946 328,630
Treasury stock - zero, zero and 6,091,871 shares, respectively..... --- --- (212,316)
- ------------------------------------------------------------------------------------------------------------------
Total common stock and retained earnings....................... 853,571 851,390 841,035
- ------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK:
Par value $20, authorized 675,000 shares - 4%;
zero, 418,963, and 421,963 shares, respectively.................. --- 8,379 8,439
Par value $100, authorized 1,865,000 shares-
SERIES SHARES OUTSTANDING
4.20% zero, 49,750, and 49,950 shares, respectively.......... --- 4,975 4,995
4.24% zero, 74,990, and 75,000 shares, respectively.......... --- 7,499 7,500
4.44% zero, 63,200, and 63,500 shares, respectively.......... --- 6,320 6,350
4.80% zero, 70,925, and 70,950 shares, respectively.......... --- 7,093 7,095
5.34% zero, 150,000, and 150,000 shares, respectively........ --- 15,000 15,000
- ------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock............................... --- 49,266 49,379
- ------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT:
First mortgage bonds-
SERIES DATE DUE
5.125% January 1, 1997........................................ --- --- 15,000
6.375% January 1, 1998........................................ --- 25,000 25,000
7.125% January 1, 1999........................................ --- 12,500 12,500
6.250% Senior Notes Series B, October 15, 2000................ 110,000 110,000 110,000
7.125% January 1, 2002........................................ --- 40,000 40,000
8.375% January 1, 2007........................................ --- --- 75,000
8.625% November 1, 2007....................................... --- 35,000 35,000
8.250% August 15, 2016........................................ --- --- 100,000
7.000% Pollution Control Series C, March 1, 2017.............. --- --- 56,000
6.500% Senior Notes Series D, July 15, 2017................... 125,000 125,000 ---
8.875% December 1, 2020....................................... --- --- 75,000
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 ---
6.500% Senior Notes Series E, April 15, 2028.................. 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 ---
Unamortized premium and discount, net.............................. (2,488) (976) (8,619)
- ------------------------------------------------------------------------------------------------------------------
Total long-term debt........................................... 702,912 716,924 724,281
Less long-term debt due within one year...................... --- 25,000 15,000
- ------------------------------------------------------------------------------------------------------------------
Total long-term debt (excluding long-term
debt due within one year).................................... 702,912 691,924 709,281
- ------------------------------------------------------------------------------------------------------------------
Total Capitalization................................................. $1,556,483 $1,592,580 $1,599,695
==================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
44
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income................................................... $ 160,338 $ 120,994 $ 133,332
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation and amortization.............................. 116,214 114,760 136,140
Deferred income taxes and investment tax credits, net...... 19,047 10,777 (3,000)
Provision for rate refund.................................. --- --- 1,804
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers........................ 945 3,688 (16,533)
Accrued unbilled revenues.............................. 14,400 (2,000) 8,650
Fuel, materials and supplies inventories............... (4,917) 12,792 (4,200)
Accumulated deferred tax assets........................ (841) 3,142 692
Other current assets................................... (11,120) 35,269 (2,361)
Accounts payable....................................... 49,793 (809) 13,401
Accrued taxes.......................................... (31) (6,074) (1,176)
Accrued interest....................................... 185 (640) 688
Accumulated provision for rate refund.................. --- --- (2,650)
Other current liabilities.............................. 2,823 (26,614) 7,131
Other operating activities................................. (30,149) 1,728 22,753
- ------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities.............. 316,687 267,013 294,671
- ------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures....................................... (96,678) (100,079) (161,129)
- ------------------------------------------------------------------------------------------------------------
Net cash used in investing activities.................. (96,678) (100,079) (161,129)
- ------------------------------------------------------------------------------------------------------------
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....................................... --- (41,400) (26,200)
Redemption of preferred stock.............................. (49,266) (114) (560)
Retirement of treasury stock............................... --- 285 ---
Cash dividends declared on preferred stock................. (733) (2,285) (2,302)
Cash dividends declared on common stock.................... (157,426) (108,392) (107,377)
- ------------------------------------------------------------------------------------------------------------
Net cash used in financing activities.................. (219,925) (166,906) (136,439)
- ------------------------------------------------------------------------------------------------------------
NET (DECREASE) INCREASE IN CASH AND CASH
EQUIVALENTS.................................................. 84 28 (2,897)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD:
From continuing operations................................... 228 200 397
From Enogex operations....................................... --- --- 5,023
- ------------------------------------------------------------------------------------------------------------
Total cash and cash equivalents at beginning of period. 228 200 5,420
- ------------------------------------------------------------------------------------------------------------
EFFECT OF REORGANIZATION - ENOGEX CASH......................... --- --- (2,323)
CASH AND CASH EQUIVALENTS AT END OF PERIOD:
From continuing operations................................... 312 228 200
From Enogex operations....................................... --- --- ---
- ------------------------------------------------------------------------------------------------------------
Total cash and cash equivalents at end of period....... $ 312 $ 228 $ 200
============================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)....................... $ 47,814 $ 54,248 $ 64,482
Income taxes .............................................. $ 76,625 $ 57,150 $ 82,970
- ------------------------------------------------------------------------------------------------------------
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.
============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
REORGANIZATION
OGE Energy Corp. ("Energy Corp.") became the parent company of Oklahoma
Gas and Electric Company (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
these consolidated financial statements, Enogex has been accounted for as
discontinued operations.
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,
1998, regulatory assets and regulatory liabilities are being reflected in rates
charged to customers over periods ranging from one to 20 years.
46
The components of deferred charges - other, on the Consolidated Balance
Sheets included the following, as of December 31:
DEFERRED CHARGES - OTHER
(DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
Regulated Deferred Charges:
Workforce reduction.......................................... $ --- $ --- $ 3,759
Unamortized debt expense..................................... 5,611 5,779 10,291
Unamortized loss on reacquired debt.......................... 29,072 28,660 10,253
Miscellaneous................................................ 2,217 403 435
- ------------------------------------------------------------------------------------------------------------
Total regulated deferred charges........................... 36,900 34,842 24,738
- ------------------------------------------------------------------------------------------------------------
Non-Regulated Deferred Charges:
Insurance claims - property damage........................... --- --- 6,231
Miscellaneous................................................ 3,839 6,305 5,229
- ------------------------------------------------------------------------------------------------------------
Total non-regulated deferred charges....................... 3,839 6,305 11,460
- ------------------------------------------------------------------------------------------------------------
Total Deferred Charges......................................... $ 40,739 $ 41,147 $ 36,198
============================================================================================================
REGULATORY ASSETS AND LIABILITIES
(DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
Regulatory Assets:
Income taxes recoverable from customers...................... $ 104,160 $ 115,989 $ 127,819
Unamortized loss on reacquired debt.......................... 29,072 28,660 10,253
Workforce reduction.......................................... --- --- 3,759
Miscellaneous................................................ 2,217 403 435
- ------------------------------------------------------------------------------------------------------------
Total Regulatory Assets.................................... 135,449 145,052 142,266
Regulatory Liabilities:
Income taxes refundable to customers......................... (63,429) (73,440) (83,451)
Gain on disposition of allowances............................ --- --- (329)
- ------------------------------------------------------------------------------------------------------------
Net Regulatory Assets.......................................... $ 72,020 $ 71,612 $ 58,486
============================================================================================================
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 would result in writing off the
related regulatory assets; the financial effects of which could be significant.
47
ACCOUNTING PRONOUNCEMENTS
In June 1997, the FASB issued SFAS No. 131, "Disclosures About Segments
of an Enterprise and Related Information". Adoption of SFAS No. 131 is required
for fiscal years beginning after December 15, 1997. The Company adopted this new
standard effective December 31, 1998. Adoption of this new standard changed the
presentation of certain disclosure information of the Company, but did not
affect reported earnings.
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits". Adoption of SFAS No. 132 is
required for financial statements for periods beginning after December 15, 1997.
The Company adopted this new standard effective December 31, 1998. Adoption of
this new standard changed the presentation of certain disclosure information of
the Company, but did not affect reported earnings.
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
will adopt this new standard effective January 1, 1999, and management believes
the adoption of this new standard will not have a material impact on its
consolidated financial position or results of operations.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and for Hedging Activities". Adoption of SFAS No. 133 is required
for financial statements for periods beginning after June 15, 1999. The Company
will adopt this new standard effective January 1, 2000, and management believes
the adoption of this new standard will not have a material impact on its
consolidated 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 fair value included in earnings. The effect of initial application of
EITF Issue 98-10 will be reported as a cumulative effect of a change in
accounting principle. The Company will adopt this new Issue effective January 1,
1999, and management believes the adoption of the new Issue will not have a
material impact on its consolidated financial position or results of operations.
USE OF ESTIMATES
In preparing the consolidated 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
48
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 Consolidated
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 1998, 1997 and
1996, 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 Consolidated
Statements of Income and a charge to construction work in progress.
AFUDC rates, compounded semi-annually, were 5.75, 5.94 and 5.63 percent
for the years 1998, 1997 and 1996, respectively.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value of the financial instruments on the Consolidated
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
$17.8 million, $18.5 million and $24.0 million at December 31, 1998, 1997 and
1996, respectively, and are classified as accounts payable in the accompanying
Consolidated 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 72 months. The finance rate is based upon short-term loan rates and is
reviewed and updated periodically. The interest rates were 8.25 percent, 8.25
percent and 9.75 percent at December 31, 1998, 1997 and 1996, respectively.
The current portion of these loans totaled $1.0 million, $4.9 million
and $4.0 million at December 31, 1998, 1997 and 1996, respectively, and are
classified as accounts receivable - customers in the accompanying Consolidated
Balance Sheets. The noncurrent portion of these loans totaled $4.0
49
million, $19.1 million and $15.3 million at December 31, 1998, 1997 and 1996,
respectively, and are classified as other property and investments in the
accompanying Consolidated Balance Sheets. In 1998, the Company sold
approximately $25.0 million of its heat pump loans.
UNBILLED REVENUE
The Company accrues estimated revenues for services provided but not
yet billed. 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, oil
and natural gas. 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 $4.4 million
for 1998 and $1.1 million for 1997, and exceeded the stated LIFO cost by
approximately $4.6 million for 1996, based on the average cost of fuel purchased
late in the respective years. Natural gas products inventories are held for sale
and accounted for based on the weighted average cost of production.
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 $12.5 million, $12.2 million and $10.4
million at December 31, 1998, 1997 and 1996, respectively, and is classified as
other current liabilities in the accompanying Consolidated 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 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.
50
RELATED PARTY TRANSACTIONS
During 1998 and 1997, approximately $42.4 million and $2.7 million,
respectively, were allocated to the Company from Energy Corp., using the
"Distragas" method. The Distragas method is a three-factor formula that uses an
equal weighting of payroll, operating income and assets. This method has been
used for utility regulation and the Company believes it to be a reasonable
method for allocating common expenses.
In 1998, 1997 and 1996, the Company paid Enogex approximately $41.6
million, $41.7 million and $44.3 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 those, which
had previously been made directly from unaffiliated sources. At December 31,
1998, a current liability of approximately $13.9 million is included in accounts
payable - affiliates in the accompanying Consolidated Balance Sheets for these
activities.
51
2. INCOME TAXES
The items comprising tax expense are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
================================================================================================================
Provision For Current Income Taxes:
Federal.......................................................... $ 73,964 $ 51,214 $ 65,954
State............................................................ 12,563 9,330 7,217
- ----------------------------------------------------------------------------------------------------------------
Total Provision For Current Income Taxes..................... 86,527 60,544 73,171
- ----------------------------------------------------------------------------------------------------------------
Provisions (Benefit) For Deferred Income Taxes, net:
Federal
Depreciation................................................... (1,418) 5,856 2,297
Repair allowance............................................... 1,200 794 2,100
Removal costs.................................................. (220) 774 630
Provision for rate refund...................................... --- --- 928
Software implementation costs.................................. --- 4,840 ---
Company restructuring.......................................... 22 (494) (8,250)
Pension expense................................................ 13,733 --- ---
Bond Redemption-unamortized costs.............................. 8,458 --- ---
Other.......................................................... (171) 2,252 219
State............................................................ 2,593 1,905 4,232
- ----------------------------------------------------------------------------------------------------------------
Total Provision (Benefit) For Deferred Income Taxes, net.... 24,197 15,927 2,156
- ----------------------------------------------------------------------------------------------------------------
Deferred Investment Tax Credits, net............................... (5,150) (5,150) (5,150)
Income Taxes Relating to Other Income and Deductions............... 1,009 1,403 (515)
- ----------------------------------------------------------------------------------------------------------------
Total Income Tax Expense..................................... $ 106,584 $ 72,724 $ 69,662
- ----------------------------------------------------------------------------------------------------------------
Pretax Income...................................................... $266,922 $ 193,718 $ 186,531
================================================================================================================
52
The following schedule reconciles the statutory federal tax rate to the
effective income tax rate:
Year ended December 31 1998 1997 1996
================================================================================================================
Statutory federal tax rate......................................... 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit.............. 3.7 3.8 4.0
Tax credits, net................................................... (1.9) (2.7) (2.8)
Other, net......................................................... 3.1 1.4 1.1
- ----------------------------------------------------------------------------------------------------------------
Effective income tax rate as reported............................ 39.9% 37.5% 37.3%
================================================================================================================
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.
53
The components of Accumulated Deferred Income Taxes at December 31,
1998, 1997 and 1996 are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
Current Deferred Tax Assets:
Accrued vacation............................................. $ 4,656 $ 3,853 $ 3,821
Uncollectible accounts....................................... 945 1,540 1,383
Capitalization of indirect costs............................. 172 106 2,583
RAR interest................................................. 774 --- ---
Provision for Worker's Compensation claims................... 342 549 1,207
- ------------------------------------------------------------------------------------------------------------
Accumulated deferred tax assets.......................... $ 6,889 $ 6,048 $ 8,994
============================================================================================================
Deferred Tax Liabilities:
Accelerated depreciation and other property-related
differences................................................ $ 423,527 $ 423,488 $ 410,094
Allowance for funds used during construction................. 38,575 43,327 46,429
Income taxes recoverable through future rates................ 40,310 44,888 49,466
- ------------------------------------------------------------------------------------------------------------
Total.................................................... 502,412 511,703 505,989
- ------------------------------------------------------------------------------------------------------------
Deferred Tax Assets:
Deferred investment tax credits.............................. (21,875) (23,623) (25,372)
Income taxes refundable through future rates................. (24,547) (28,421) (32,296)
Postemployment medical and life insurance benefits........... (1,800) (3,131) (2,301)
Company pension plan......................................... (1,447) (15,503) (14,965)
Bond redemption-unamortized costs............................ 9,353 --- ---
Other........................................................ 801 (1,368) (1,289)
- ------------------------------------------------------------------------------------------------------------
Total.................................................... (39,526) (72,046) (76,223)
- ------------------------------------------------------------------------------------------------------------
Accumulated Deferred Income Tax Liabilities.................... $ 462,886 $ 439,657 $ 429,766
============================================================================================================
3. COMMON STOCK AND RETAINED EARNINGS
There were no new shares of common stock issued during 1998, 1997 or
1996. The slight increase in 1998 in premium on capital stock, as presented on
the Consolidated Statements of Capitalization, represents the gains associated
with the repurchased preferred stock. The $197 million decrease in 1997,
represents the retirement of treasury stock and repurchased preferred stock.
RESTRICTED STOCK PLAN
The Company has a Restricted Stock Plan whereby certain employees may
periodically receive shares of the Energy Corp.'s common stock at the discretion
of the Board of Directors. The Company distributed 16,024 shares of common stock
during 1996. The Company also reacquired 10,538 shares in 1996. The shares
distributed/reacquired in the reported periods were recorded as treasury stock.
54
Changes in common stock were:
(THOUSANDS) 1998 1997 1996
============================================================================================================
Shares outstanding January 1................................... 40,379 40,379 40,373
Issued/reacquired under the Restricted Stock Plan, net......... --- --- 6
- ------------------------------------------------------------------------------------------------------------
Shares outstanding December 31................................. 40,379 40,379 40,379
============================================================================================================
There were 10,110,846 shares of unissued Energy Corp. common stock
reserved for the various employee and Company stock plans at December 31, 1998.
With the exception of the Stock Incentive Plan, the common stock requirements,
pursuant to those plans, are currently being satisfied with stock purchased on
the open market.
SHAREOWNERS RIGHTS PLAN
In December 1990, the Company adopted a Shareowners Rights Plan
designed to protect shareowners' interests in the event that the Company was
ever confronted with an unfair or inadequate acquisition proposal. In connection
with the corporate restructuring, Energy Corp. adopted a substantially identical
Shareowners Rights Plan in August 1995. Pursuant to the plan, Energy Corp.
declared a dividend distribution of one "right" for each share of Energy Corp.
common stock. As a result of the June 1998 two-for-one stock split of Energy
Corp. common stock, each share is now entitled to one-half of a right. Each
right entitles the holder to purchase from Energy Corp. one one-hundredth of a
share of new preferred stock of Energy Corp. under certain circumstances. The
rights may be exercised if a person or group announces its intention to acquire,
or does acquire, 20 percent or more of Energy Corp.'s common stock. Under
certain circumstances, the holders of the rights will be entitled to purchase
either shares of common stock of Energy Corp. or common stock of the acquirer at
a reduced percentage of market value. The rights are scheduled to expire on
December 11, 2000.
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 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
55
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.
In February 1997, the Company filed a registration statement for up to
$50 million of grantor trust preferred securities.
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 Consolidated 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,
1998, Energy Corp. had an agreement for a line of credit, up to $160 million,
which was to expire December 6, 2000. The line of credit is maintained on a
variable fee basis on the unused balance. The Company had no short-term debt
outstanding at December 31, 1998. In January 1999, Energy Corp. increased its
line of credit from $160 million to $200 million.
7. PENSION AND POSTEMPLOYMENT BENEFIT PLANS
During 1994, the Company restructured its operations, reducing its
workforce by approximately 24 percent. This was accomplished through a Voluntary
Early Retirement Package ("VERP") and an enhanced severance package. The VERP
included enhanced pension benefits as well as postemployment medical and life
insurance benefits.
As a result of the postemployment benefits provided in connection with
this workforce reduction, the Company incurred severance costs and certain
one-time costs computed in accordance with SFAS No. 88, "Employers' Accounting
for Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits" and SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." In response to an application
filed by the Company, the OCC directed the Company to defer the one-time costs,
which had not been offset by labor savings through December 31, 1994. The
remaining balance of approximately $48.9 million was amortized over 26 months,
commencing January 1, 1995.
The amortization of the deferred regulatory asset was zero, $3.7 million
and $22.6 million at December 31, 1998, 1997 and 1996, respectively.
56
PENSION PLAN
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.
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 $40.0 million during 1998 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.
Reconciliation of funded status of the plans and the amounts included
in the company's consolidated balance sheets:
Projected benefit obligations are as follows:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Beginning obligations........... $(311,017) $(277,396) $(295,573) $ (87,557) $ (90,683) $(102,789)
Service cost.................... (6,082) (5,798) (6,493) (1,600) (1,957) (2,317)
Interest cost................... (19,488) (20,226) (20,909) (5,286) (6,120) (6,824)
Participant contributions....... --- --- --- (1,051) (875) (1,157)
Plan changes.................... (2,888) --- (5,308) --- --- ---
Actuarial gains (losses)........ (6,759) (31,501) 20,588 6,283 3,159 11,174
Benefits paid................... 19,934 23,904 22,722 7,716 6,128 7,641
Expenses........................ 206 --- --- --- --- ---
Transfer to affiliate........... 22,169 --- 7,577 --- 2,791 3,589
- --------------------------------------------------------------------------------------------------------------------
Ending obligations.............. $(303,925) $(311,017) $(277,396) $ (81,495) $ (87,557) $ (90,683)
====================================================================================================================
57
Fair value of plans' assets:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Beginning fair value............ $ 234,971 $ 217,208 $ 214,986 $ 45,619 $ 39,066 $ 23,864
Actual return on plans' assets.. 27,560 32,547 22,896 4,968 8,047 2,128
Employer contributions.......... 40,006 9,120 7,752 5,474 5,271 19,459
Participants' contributions..... --- --- --- 915 874 1,135
Benefits paid................... (19,934) (23,904) (22,722) (6,388) (6,128) (7,520)
Expenses........................ (206) --- --- --- --- ---
Transfer to affiliate........... (16,748) --- (5,704) --- (1,511) ---
- --------------------------------------------------------------------------------------------------------------------
Ending fair value............... $ 265,649 $ 234,971 $ 217,208 $ 50,588 $ 45,619 $ 39,066
====================================================================================================================
Funded status of plans:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Funded status of the plans...... $ (38,276) $ (76,046) $ (60,188) $ (30,907) $ (41,938) $ (51,617)
Unrecognized net gain (loss).... (104) 1,702 (15,101) (17,360) (12,829) (7,309)
Unrecognized prior service
benefit (cost)................ 37,147 40,017 42,954 --- --- ---
Unrecognized transition
obligation.................... (3,520) (5,053) (6,316) 35,578 38,119 41,951
- --------------------------------------------------------------------------------------------------------------------
Net balance sheet asset
(liability)................... $ (4,753) $ (39,380) $ (38,651) $ (12,689) $ (16,648) $ (16,975)
====================================================================================================================
58
Net Periodic Benefit Cost:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Service cost.................... $ 6,082 $ 5,798 $ 6,493 $ 1,600 $ 1,957 $ 2,317
Interest cost................... 19,488 20,226 20,909 5,286 6,120 6,824
Return on plan assets........... (19,173) (18,620) (18,742) (4,309) (3,445) (2,167)
Amortization of transition
obligation.................... (1,173) (1,263) (1,263) 2,541 2,622 2,749
Amortization of net gain
(loss)........................ --- 788 --- (2,129) (792) (2)
Net amount capitalized or
deferred...................... --- --- --- (613) (1,293) (2,157)
Amortization of unrecognized
prior service cost............ 2,905 2,937 2,939 --- --- ---
- --------------------------------------------------------------------------------------------------------------------
Net periodic benefit costs...... $ 8,129 $ 9,866 $ 10,336 $ 2,376 $ 5,169 $ 7,564
====================================================================================================================
Rate Assumptions:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Discount rate..................... 6.75% 7.00% 7.75% 6.75% 7.00% 7.75%
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 7.50% 8.25% 9.00%
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 2006
====================================================================================================================
N/A - not applicable
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, $0.9 million and $1.0 million at
December 31, 1998, 1997 and 1996, respectively. The effects of a one-percentage
point decrease on the aggregate of the service and interest components of the
net periodic
59
postretirement health care benefits would be decreases of approximately $0.6
million, $0.9 million and 0.9 million at December 31, 1998, 1997 and 1996,
respectively.
The effects of a one-percentage point increase on the aggregate of
accumulated postretirement benefit obligation for health care benefits would be
approximately $7.2 million, $10.2 million and $8.7 million at December 31, 1998,
1997 and 1996, 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 $6.1 million, $8.5 million and $8.1
million at December 31, 1998, 1997 and 1996, 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 1999 are estimated at $101.7 million.
The Company acquires natural gas for boiler fuel under 67 individual
contracts, some of which contain provisions allowing the owners to require
prepayments for gas if certain minimum quantities are not taken. At December 31,
1998, 1997 and 1996, outstanding prepayments for gas, including the amounts
classified as current assets, under these contracts were approximately $15.2
million, $10.7 million and $9.9 million respectively. The Company may be
required to make additional prepayments in subsequent years. The Company expects
to recover these prepayments as fuel costs if unable to take the gas prior to
the expiration of the contracts.
At December 31, 1998, the Company held non-cancelable operating leases
covering 1,495 coal hopper railcars. Rental payments are charged to fuel expense
an 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:
(DOLLARS IN THOUSANDS)
1999.................... $ 5,130 2002.................... $ 4,841
2000.................... 5,034 2003.................... 4,745
2001.................... 4,938 2004 and beyond......... 49,412
---------
Total Minimum Lease Payments................................ $74,100
=========
Rental payments under operating leases were approximately $5.3 million
in 1998, $5.4 million in 1997, and $5.4 million in 1996.
The Company is required to maintain the railcars it has under lease to
transport coal from Wyoming and has entered into an agreement with Railcar
Maintenance Company, a non-affiliated company, 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
60
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 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.
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 currently recoverable in rates from Oklahoma customers.
In January 1998, the Company filed an application with the OCC seeking
approval to revise an existing cogeneration contract with Mid-Continent Power
Company ("MCPC"), a cogeneration plant near Pryor, Oklahoma. As part of this
transaction, Energy Corp. agreed to purchase the stock of Oklahoma Loan
Acquisition Corporation ("OLAC"), the company that owns the MCPC plant, for
approximately $25 million. The Company obtained the required regulatory
approvals from the OCC, APSC and FERC. If the transaction was completed, the
term of the existing cogeneration contract would have been reduced by four and
one-half years, which would have reduced the amounts to be paid by the Company,
and would have provided savings for its Oklahoma customers, of approximately $46
million as compared to the existing cogeneration contract. Following an
arbitrator's decision that the owner of the stock of OLAC could not sell the
stock of OLAC to Energy Corp. until it had offered such stock to a third party
on the same terms as it was offered to Energy Corp., the third party purchased
the stock of OLAC and assumed ownership of the cogeneration plant in October
1998. The effect of this transaction is that the Company's original contract
with the cogeneration plant remains in place.
During 1998, 1997, and 1996, the Company made total payments to
cogenerators of approximately $226.5 million, $212.2 million, and $210.0
million, of which $185.5 million, $176.2 million, and $175.2 million,
respectively, represented capacity payments. All payments for purchased power,
including cogeneration, are included in the Consolidated Statements of Income as
Purchased power. The future minimum capacity payments under the contracts for
the next five years are approximately: 1999 - $189 million, 2000 - $190 million,
2001 - $191 million, 2002 - $192 million and 2003 - $163 million.
Approximately $0.5 million of the Company's construction expenditures
budgeted for 1999 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 $40.8 million during 1999, compared to
approximately $44.2 million in 1998. The Company continues to evaluate its
environmental management systems to ensure compliance
61
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 agreed to the Kyoto Treaty on global warming.
This treaty requires a 7 percent reduction in greenhouse gas emissions below the
1990 level. If ratified by the U.S. Senate, this could have a tremendous impact
on the Company's operations, potentially eliminating the use of coal as a fuel.
The Company is a party to two separate actions brought by the EPA
concerning cleanup of disposal sites for hazardous waste. 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 failed to dispose
of the materials in an appropriate manner. Remediation at one of these sites has
been completed. 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 other party 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.
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 judgement 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 judgement could be
duplicative, that the antitrust amounts could be tripled and that parties should
address these issues in their post-trial motions. 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 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 consolidated 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 consolidated
financial position or results of operations.
62
9. RATE MATTERS AND REGULATION
On February 11, 1997, the OCC issued an 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). The OCC order
also directed the Company to transition to competitive bidding of its gas
transportation requirements, currently met by Enogex, no later than April 30,
2000. The order also set annual compensation for the transportation services
provided by Enogex at $41.3 million until competitively-bid gas transportation
begins.
As discussed in Note 7 of Notes to Consolidated Financial Statements,
during the third quarter of 1994, the Company incurred $63.4 million of costs
related to the VERP and enhanced severance package. Pending an OCC order, the
Company deferred these costs; however, between August 1 and December 31, 1994,
the amount deferred was reduced by approximately $14.5 million. In response to
an application filed by the Company on August 9, 1994, the OCC issued an order
on October 26, 1994, that permitted the Company to amortize the December 31,
1994, regulatory asset of $48.9 million over 26 months and reduced the Company's
electric rates during such period by approximately $15 million annually,
effective January 1995. The labor savings from the VERP and severance package
substantially offset the amortization of the regulatory asset and annual rate
reduction of $15 million.
On June 18, 1996, the APSC staff and the Company filed a Joint
Stipulation recommending settlement of certain issues resulting from the APSC
review of the amounts that the Company pays Enogex and recovers through its fuel
clause for transporting natural gas to the Company's gas-fired generating
stations. On July 11, 1996, the APSC issued an order that, among other things,
required the Company to refund approximately $4.5 million in 1996 to its
Arkansas retail electric customers. The $4.5 million refund related to the
disallowance of a portion of the fees paid by the Company to Enogex for such
transportation services and was recorded as a provision for a potential refund
prior to August 1996.
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
is recommending a $3.1 million annual rate reduction (based on a test year ended
December 31, 1996). The Company filed its cost of service study and has
requested a $1.7 million annual rate increase. A decision on this rate case is
expected in the next few months.
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.
Indicated below are the carrying amounts and estimated fair values of
the Company's financial instruments as of December 31:
63
1998 1997 1996
------------------- ------------------- ------------------
CARRYING FAIR Carrying Fair Carrying Fair
(DOLLARS IN THOUSANDS) AMOUNT VALUE Amount Value Amount Value
======================================================================================================================
Long-Term Debt and Preferred Stock:
Senior Notes........................ $567,512 $593,313 $581,524 $594,357 $644,881 $656,362
Industrial Authority Bonds.......... 135,400 135,400 135,400 135,400 79,400 79,400
Preferred Stock:
4% - 5.34% Series - zero,
827,828 and 831,363 shares,
respectively...................... --- --- 49,266 49,997 49,379 35,829
======================================================================================================================
64
Report of Independent Public Accountants
- ----------------------------------------
TO THE SHAREOWNER OF
OKLAHOMA GAS AND ELECTRIC COMPANY:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of Oklahoma Gas and Electric Company (an Oklahoma
corporation) and its subsidiaries as of December 31, 1998, 1997 and 1996, and
the related consolidated 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 generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Oklahoma Gas and
Electric Company and its subsidiaries as of December 31, 1998, 1997 and 1996,
and the results of its operations and its cash flows for the years then ended in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 21, 1999
65
Report of Management
- --------------------
TO OUR SHAREOWNER:
The management of Oklahoma Gas and Electric Company has prepared, and
is responsible for the integrity and objectivity of the financial and operating
information contained in this Annual Report. The consolidated financial
statements have been prepared in accordance with generally accepted accounting
principles and include certain amounts that are based on the best estimates and
judgments of management.
To meet its responsibility for the reliability of the consolidated
financial statements and related financial data, the Company's management has
established and maintains an internal control structure. This structure provides
management with reasonable assurance in a cost-effective manner that, among
other things, assets are properly safeguarded and transactions are executed and
recorded in accordance with its authorizations so as to permit preparation of
financial statements in accordance with generally accepted accounting
principles. The Company's internal auditors assess the effectiveness of this
internal control structure and recommend possible improvements thereto on an
ongoing basis.
The Company maintains high standards in selecting, training and
developing its members. This, combined with the Company policies and procedures,
provides reasonable assurance that operations are conducted in conformity with
applicable laws and with its commitment to the highest standards of business
conduct.
/s/ Steven E. Moore /s/ James R. Hatfield
Steven E. Moore James R. Hatfield
Chairman of the Board, President Vice President and Treasurer
and Chief Executive Officer
66
Supplementary Data
- ------------------
Interim Consolidated 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:
Quarter ended (DOLLARS IN THOUSANDS EXCEPT Dec 31 Sep 30 Jun 30 Mar 31
PER SHARE DATA)
=============================================================================================================
Operating revenues............................. 1998 $ 265,207 $ 474,209 $ 336,017 $ 236,645
1997 264,053 417,612 282,147 227,878
1996 251,669 411,765 303,077 233,826
=============================================================================================================
Operating income............................... 1998 $ 23,849 $ 118,266 $ 58,321 $ 9,787
1997 20,825 100,500 43,283 10,109
1996 18,002 101,098 47,356 10,893
=============================================================================================================
Income from operations of Enogex
distributed to OGE Energy Corp............... 1998 $ --- $ --- $ --- $ ---
1997 --- --- --- ---
1996 3,900 3,740 4,322 4,501
=============================================================================================================
Net income (loss).............................. 1998 $ 10,607 $ 105,931 $ 45,879 $ (2,079)
1997 9,154 86,601 29,124 (3,885)
1996 7,301 90,165 35,328 538
=============================================================================================================
Earnings (loss) available for common........... 1998 $ 10,607 $ 105,931 $ 45,879 $ (2,812)
1997 8,583 86,030 28,553 (4,457)
1996 6,729 89,593 34,749 (41)
=============================================================================================================
Earnings (loss) per average common share....... 1998 $ 0.26 $ 2.62 $ 1.14 $ (0.07)
1997 0.21 2.13 0.71 (0.11)
1996 0.17 2.22 0.86 0.00
=============================================================================================================
67
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 G
of Form 10-K, since the Company's parent, OGE Energy Corp., filed copies of a
definitive proxy statement with the Securities and Exchange Commission on or
about March 29, 1999. Such proxy statement is incorporated herein by reference.
In accordance with Instruction G of Form 10-K, the information required by Item
10 relating to Executive Officers has been included in Part I, Item 4, of this
Form 10-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
- ----------------------------------------------------
REPORTS ON FORM 8-K.
-------------------
(A) 1. FINANCIAL STATEMENTS
- ---------------------------
The following consolidated financial statements and supplementary data
are included in Part II, Item 8 of this Report:
o Consolidated Balance Sheets at December 31, 1998, 1997 and 1996
o Consolidated Statements of Income for the years ended December 31,1998,
1997 and 1996
o Consolidated Statements of Retained Earnings for the years ended
December 31, 1998, 1997 and 1996
o Consolidated Statements of Capitalization at December 31, 1998, 1997
and 1996
o Consolidated Statements of Cash Flows for the years ended December 31,
1998, 1997 and 1996
o Notes to Consolidated Financial Statements
o Report of Independent Public Accountants
o Report of Management
68
SUPPLEMENTARY DATA
------------------
o Interim Consolidated Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE
- ----------------------------------------------------- ----
Schedule II - Valuation and Qualifying Accounts 73
Report of Independent Public Accountants 74
Financial Data Schedule 81
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)
69
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 Amended and Restated Stock Equivalent and Deferred
Compensation Plan for Directors, as amended. (Filed as Exhibit
10.08 to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996, File No. 1-12579, and incorporated by
reference herein)
10.07 Energy Corp.'s Stock Incentive Plan.
70
10.08 Agreement and Plan of Reorganization, dated May 14, 1986,
between the Company and Mustang Fuel Corporation. (Attached as
Appendix A to Registration Statement No. 33-7472 and
incorporated by reference herein)
10.09 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)
10.10 Energy Corp.'s Restoration of Retirement Savings Plan. (Filed
as Exhibit 10.13 to Energy Corp.'s Form 10-K Report for the
year ended December 31, 1996, File No. 1-12579 and
incorporated by reference herein)
10.11 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)
10.12 Energy Corp.'s Annual Incentive Compensation Plan.
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 Amended and Restated Stock Equivalent and
Deferred Compensation Plan for Directors, as amended.
(Filed as Exhibit 10.08 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1996, File No. 1-12579, and
incorporated by reference herein)
10.07 Energy Corp.'s Stock Incentive Plan.
71
10.09 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)
10.10 Energy Corp.'s Restoration of Retirement Savings Plan. (Filed
as Exhibit 10.13 to Energy Corp.'s Form 10-K Report for the
year ended December 31, 1996, File No. 1-12579 and
incorporated by reference herein)
10.11 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, 1993, File No. 1-12579 and incorporated by
reference herein)
10.12 Energy Corp.'s Annual Incentive Compensation Plan.
(B) REPORTS ON FORM 8-K
- ------------------------
Item 5. Other Events, dated April 16, 1998.
Item 7. Exhibits, dated April 16, 1998.
Item 5. Other Events, dated December 28, 1998.
Item 7. Exhibits, dated December 28, 1998.
72
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
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
- ----------- --------- --------------------------- ---------- --------
1998 (THOUSANDS)
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
1996
Reserve for Uncollectible Accounts $ 3,847 $ 6,571 - $ 6,898 $ 3,520
73
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Oklahoma Gas and Electric Company:
We have audited in accordance with generally accepted auditing
standards, the consolidated financial statements of Oklahoma Gas and Electric
Company included in this Form 10-K, and have issued our report thereon dated
January 21, 1999. Our audits were made for the purpose of forming an opinion on
those statements taken as a whole. The schedule listed on Page 69, 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 21, 1999
74
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 26th day of March, 1999.
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.
Signature Title Date
- ----------------------------- ----------------------- --------------
/ s / Steven E. Moore
Steven E. Moore Principal Executive
Officer and Director; March 26, 1999
/ s / James R. Hatfield
James R. Hatfield Principal Financial
Officer. March 26, 1999
/ s / Donald R. Rowlett
Donald R. Rowlett Principal Accounting
Officer. March 26, 1999
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 26, 1999
75
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
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 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)
76
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 Amended and Restated Stock Equivalent and Deferred
Compensation Plan for Directors, as amended. (Filed as Exhibit
10.08 to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996, File No. 1-12579, and incorporated by
reference herein)
10.07 Energy Corp.'s Stock Incentive Plan.
10.08 Agreement and Plan of Reorganization, dated May 14, 1986,
between the Company and Mustang Fuel Corporation. (Attached as
Appendix A to Registration Statement No. 33-7472 and
incorporated by reference herein)
10.09 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)
10.10 Energy Corp.'s Restoration of Retirement Savings Plan. (Filed
as Exhibit 10.13 to Energy Corp.'s Form 10-K Report for the
year ended December 31, 1996, File No. 1-12579 and
incorporated by reference herein)
10.11 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)
10.12 Energy Corp.'s Annual Incentive Compensation Plan.
77
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
78