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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, 1997 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
Title of each class Name of each exchange on which
so registered each class is registered
- -------------------------------- -----------------------------------
Preferred Stock 4% Cumulative New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ |X| ]
As of February 27, 1998, 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 1998 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.......... 13
Fuel Supply.............................................. 14
Environmental Matters............................................. 15
Item 2. Properties........................................................ 18
Item 3. Legal Proceedings. ............................................... 19
Item 4. Submission of Matters to a Vote of Security Holders............... 22
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters...................................... 25
Item 6. Selected Financial Data........................................... 26
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition....................... 27
Item 8. Financial Statements and Supplementary Data....................... 38
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure ................................ 65
PART III
Item 10. Directors and Executive Officers of the Registrant................ 65
Item 11. Executive Compensation............................................ 65
Item 12. Security Ownership of Certain Beneficial
Owners and Management.................................... 65
Item 13. Certain Relationships and Related Transactions.................... 65
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K...................................... 65
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 5,647,300
kilowatts. At the end of 1997, the Company had 2,450 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") recently 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 277 communities and
their contiguous rural and suburban areas. During 1997, five 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 1.7 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
1
largest city in that state. Of the 282 communities served, 254 are located in
Oklahoma and 28 in Arkansas. Approximately 91 percent of total electric
operating revenues for the year ended December 31, 1997, 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 5,287 megawatts, and occurred on July
28, 1997. The Company's load responsibility peak demand was approximately 4,982
megawatts on July 28, 1997, resulting in a capacity margin of approximately 18.4
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 1.6 percent in 1997 as compared to an increase of 1.5 percent in 1996
and a 7.0 percent decrease in 1995. In 1997, kilowatt-hour sales to the
Company's customers ("system sales") increased slightly due to continued
customer growth. Sales to other utilities ("off-system sales") decreased in
1997. Off-system sales are at much lower prices per kilowatt-hour and have less
impact on operating revenues and income than system sales. In 1996 and 1995,
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/
1997 (DEC) 1996 (Dec) 1995 (Dec)
- --------------------------------------------------------------------------------
System Sales 22,183 3.0% 21,541 3.4% 20,828 0.9%
Off-System Sales 1,202 (18.5)% 1,475 (20.4)% 1,852 (232.6)%
------ ------- ------
Total Sales 23,385 1.6% 23,016 1.5% 22,680 (7.0)%
====== ====== ======
In 1997, the Company's Sooner Generating Station (consisting of two
coal-fired units with an aggregate capability of 1,015 Mw) and the Company's
three coal-fired units at its Muskogee Generating Station (with an aggregate
capability of 1,515 Mw) were again recognized by an industry survey as being in
the top ten lowest cost producers of electricity for 1996 among the 850 electric
generating stations surveyed.
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 of federal and state
legislation.
2
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
Year Ended December 31
1997 1996 1995
---- ---- ----
ELECTRIC ENERGY:
(Millions of Kwh)
Generation (exclusive of station use)... 21,620 21,253 20,639
Purchased............................... 3,528 3,564 3,578
---------- ---------- -----------
Total generated and purchased..... 25,148 24,817 24,217
Company use, free service and losses.... (1,763) (1,801) (1,537)
---------- ---------- -----------
Electric energy sold.............. 23,385 23,016 22,680
---------- ---------- -----------
ELECTRIC ENERGY SOLD:
(Millions of Kwh)
Residential............................. 7,179 7,143 6,848
Commercial and industrial............... 11,586 11,161 10,963
Public street and highway lighting...... 68 67 66
Other sales to public authorities....... 2,202 2,096 2,087
Sales for resale........................ 2,350 2,549 2,716
---------- ---------- -----------
Total............................. 23,385 23,016 22,680
========== ========== ===========
ELECTRIC OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential......................... $ 474,419 $ 479,574 $ 471,313
Commercial and industrial........... 526,673 530,213 512,212
Public street and highway lighting.. 9,456 9,367 9,115
Other sales to public authorities... 98,818 98,209 95,660
Sales for resale.................... 57,695 60,141 63,340
Provision for rate refund........... --- (1,221) (2,437)
Miscellaneous....................... 24,630 24,054 19,084
----------- ----------- -----------
Total Electric Revenues........... $1,191,691 $1,200,337 $1,168,287
=========== =========== ===========
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential............................. 593,699 588,778 583,741
Commercial and industrial............... 85,315 84,032 82,577
Public street and highway lighting...... 249 249 249
Other sales to public authorities....... 10,897 10,688 10,340
Sales for resale........................ 40 41 43
----------- ----------- -----------
Total............................. 690,200 683,788 676,950
=========== =========== ===========
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (Kwh)................ 12,133 12,178 11,786
Average annual revenue.................. $ 801.74 $ 817.62 $ 811.10
Average price per Kwh (cents)........... 6.61 6.71 6.88
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 1997 and 1996, 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 1998 through 2000 are
estimated as follows:
(dollars in millions) 1998 1999 2000
- --------------------------------------------------------------------------------
Construction expenditures
including AFUDC .................. $ 108.0 $ 100.0 $ 100.0
Maturities of long-term debt and
sinking fund requirement.......... 25.0 12.5 110.0
- --------------------------------------------------------------------------------
Total........................... $ 133.0 $ 112.5 $ 210.0
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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 $0.9 million of the Company's construction
expenditures budgeted for 1998 are to comply with environmental laws and
regulations. The Company's construction program was developed to support an
anticipated peak demand growth of one to two percent annually and to maintain
minimum capacity reserve margins as stipulated by the Southwest Power Pool. See
"Rate Structure, Load Growth and Related Matters."
The Company intends to meet its customers' increased electricity needs
during the foreseeable future primarily by maintaining the reliability and
increasing the utilization of existing capacity. The Company's current resource
strategy includes the reactivation of existing plants and the addition of
peaking resources. The Company does not anticipate the need for another
base-load plant in the foreseeable future.
The Company's ability to sell additional securities on satisfactory
terms to meet its capital needs is dependent upon numerous factors, including
general market conditions for utility securities, which will impact the
Company's ability to meet earnings tests for the issuance of additional first
mortgage bonds and preferred stock. Based on earnings for the twelve months
ended December 31, 1997, and assuming an annual interest rate of 7.6 percent,
the Company could issue more than $1.0 billion in principal amount of additional
first mortgage bonds under the earnings test contained in the Company's Trust
Indenture (assuming adequate property additions were available). Under the
earnings test contained in the Company's Restated Certificate of Incorporation
and assuming none of the foregoing first mortgage bonds are issued, more than
$0.9 billion of additional preferred stock at an assumed annual dividend rate of
6.8 percent could be issued as of December 31, 1997. As explained below, the
Company's Trust Indenture is expected to be discharged and no longer in effect
in April 1998.
The Company 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
4
million in short-term borrowings at any one time. The maximum amount of
outstanding short-term borrowings during 1997 was $129.3 million.
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
will have been redeemed or retired with the result that no first mortgage bonds
will remain outstanding. At that time, the Company will cancel its First
Mortgage Bond Trust Indenture and cause the related first mortgage lien
currently on substantially all of its properties to be discharged and released.
The Company expects to have more flexibility in future financings under its
Senior Note Indenture than existed under the First Mortgage Bond Trust
Indenture.
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. and 320 megawatts annually from Applied
Energy Services, Inc., another qualified cogeneration facility. In 1986, a
contract was signed with Sparks Regional Medical Center to purchase energy not
needed by the hospital from its nominal seven megawatt cogeneration facility. In
1987, the Company signed a contract to purchase up to 110 megawatts of capacity
from Mid-Continent Power Company ("MCPC"). This obligation to purchase capacity
began in 1998, but the Company has no obligation to purchase energy. Energy
Corp. is seeking to obtain ownership of this cogeneration facility and, as part
of the transaction, to amend the existing power purchase agreement. See
"Regulation and Rates".
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.
5
For the year ended December 31, 1997, approximately 88 percent of the
Company's electric revenue was subject to the jurisdiction of the OCC, seven
percent to the APSC, and five 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. Under PURPA, the
Company was obligated to enter into the original contract, which was approved by
the OCC in 1987, and which required the Company to purchase peaking capacity
from the plant for 10 years beginning in 1998 -- whether the capacity was needed
or not. In December 1997, Energy Corp. agreed to purchase the stock of Oklahoma
Loan Acquisition Corporation, the company that owns the MCPC plant. As part of
the transaction, the duration of the existing cogeneration contract with the
Company would be reduced from 10 years ending December 31, 2007, to four and one
half years ending June 30, 2002. If the transaction is approved by the necessary
regulatory agencies and is consummated, the Company estimates that it will
provide aggregate savings for its Oklahoma customers of approximately $46
million as compared to the existing cogeneration contract. On March 13, 1998,
the OCC issued its order granting the relief requested by the Company.
Additional regulatory approvals of the FERC and the APSC, among others, are
needed to complete the transaction.
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.
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, 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 1997, the GEP Rider increased revenues by
approximately $18.0 million, or approximately $0.28 per share. The current GEP
Rider is estimated to positively impact revenue by $27 million, or approximately
$0.41 per share during the 12 months ending June 1998.
As previously reported, Oklahoma enacted in April 1997 the Electric
Restructuring Act of 1997 (the "Act"). If implemented as proposed, the Act will
significantly affect the Company's future operations.
6
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;
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 OCC 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 under the direction of the
Joint Electric Utility Task Force (which task force is described below).
However, 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
7
established whereby all retail consumers are permitted to choose
their retail electric energy suppliers by July 1, 2002.
3. When consumer choice is introduced, rates shall be unbundled to
provide clear price information on the components of generation,
transmission and distribution and any other ancillary charges.
Charges for public benefit programs currently authorized by
statute or the OCC, or both, shall be unbundled and appear in
line item format on electric bills for all classes of consumers.
4. An entity providing distribution services shall be relieved of
its traditional obligation to provide electric supply but shall
have a continuing obligation to provide distribution service for
all consumers in its service territory.
5. The benefits associated with implementing an independent system
planning committee composed of owners of electric distribution
systems to develop and maintain planning and reliability
criteria for distribution facilities shall be evaluated.
6. A defined period for the transition to a restructured electric
utility industry shall be established. The transition period
shall reflect a suitable time frame for full compliance with the
requirements of a restructured utility industry.
7. Electric rates for all consumer classes shall not rise above
current levels throughout the transition period. If possible,
electric rates for all consumers shall be lowered when feasible
as markets become more efficient in a restructured industry.
8. The OCC shall consider the establishment of a distribution
access fee to be assessed to all consumers in Oklahoma connected
to electric distribution systems regulated by the OCC. This fee
shall be charged to cover social costs, capital costs, operating
costs, and other appropriate costs associated with the operation
of electric distribution systems and the provision of electric
services to the retail consumer.
9. Electric utilities have traditionally had an obligation to
provide service to consumers within their established service
territories and have entered into contracts, long-term
investments and federally mandated cogeneration contracts to
meet the needs of consumers. These investments and contracts
have resulted in costs which 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
8
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 OCC is directed to
prepare a four-part study to be delivered to the Joint Electric Utility Task
Force (the "Joint Task Force"). The first part of the study, which was due
February 1, 1998, is to address independent operation issues. The second part,
which is due December 31, 1998, is to address technical issues, such as
reliability, safety, unbundling of generation, transmission and distribution
services, transition issues and market power. The third part of the study is due
December 31, 1999, and is to address financial issues, including rates, charges,
access fees, transition costs and stranded costs. The final part of the study is
due August 31, 2000 and is to cover consumer issues, such as the obligation to
serve, service territories, consumer choices, competition and consumer
safeguards.
Section 5 of the Act directs the Oklahoma Tax Commission to study and
submit a report to the Joint Task Force by December 31, 1998, 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 is precluded from issuing
any rules on such matters without the approval of the Oklahoma Legislature or
the Joint Task Force. Also, in the event a uniform tax policy that allows all
competitors to be taxed on a fair and equitable basis is not established on or
before July 1, 2002, then the effective date for implementing customer choice of
retail electric suppliers shall be extended until a uniform tax policy is
established.
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 to direct and oversee the studies of
the OCC and Oklahoma Tax Commission 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. Section 8 sets forth the effective date of the Act as
April 25, 1997.
9
A new bill was introduced in the State Senate in the 1998 legislative
session and was passed by a State Senate committee in February 1998. This bill,
if adopted, would modify the Act by (i) directing the Joint Task Force, instead
of the OCC, to conduct the required studies and (ii) accelerating the deadlines
for completion of such studies to October 1, 1999.
The Company intends to actively participate in the restructuring of the
electric utility industry in Oklahoma and to remain a competitive supplier of
electricity. However, due to the early stages of the process, the Company cannot
predict the impact that the restructuring will have on its operations in the
future. The Company continues to be generally supportive of the restructuring
efforts in Oklahoma. However, the Company believes that federal legislation
mandating retail competition in all states is appropriate to ensure that its
ability to compete for retail customers of other suppliers is commensurate with
the ability of such suppliers to compete for the Company's jurisdictional
customers in Oklahoma.
In December 1997, the APSC established four generic proceedings to
consider the implementation of a competitive retail electric market in the State
of Arkansas. Among the topics to be considered are 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 intends to participate
actively in these proceedings.
On February 25, 1994, the OCC issued an order that, among other things,
effectively lowered the Company's rates to its Oklahoma retail customers by
approximately $17 million annually and required the Company to refund
approximately $41.3 million. Of the $41.3 million refund, $39.1 million was
associated with revenues prior to January 1, 1994, while the remaining $2.2
million related to 1994. The entire $41.3 million refund related to the OCC's
disallowance of a portion of the fees paid by the Company to Enogex for prior
transportation and related gas gathering services.
In 1994, the Company underwent a significant restructuring effort and
redesign of its operations to more favorably position itself for the competitive
electric utility environment. As part of this process, OG&E implemented a
Voluntary Early Retirement Package ("VERP") and a severance package that reduced
its workforce by approximately 900 employees. The Company incurred $63.4 million
of restructuring costs in 1994. Pending an OCC order, the Company deferred the
costs associated with the VERP and severance package in the third quarter of
1994. 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. In 1997, 1996 and
1995, the labor savings substantially offset the amortization of the regulatory
asset and the annual rate reduction of $15 million.
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) and that the Company file a cost of service study with the
APSC. While the Company does not agree that any refund is appropriate, it is in
the process of evaluating and responding to the staff's position.
AUTOMATIC FUEL ADJUSTMENT CLAUSES: Variances in the actual cost of fuel
---------------------------------
used in electric generation and certain purchased power costs, as compared to
that component in cost-of-service for ratemaking, are charged to substantially
all of the Company's electric customers through automatic fuel adjustment
clauses, which are subject to periodic review by the OCC, the APSC and the FERC.
10
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
have had a significant impact on wholesale markets. These orders were
subsequently amended in orders issued in March and November 1997. These orders
have been appealed by many entities, including representatives of the states,
the electric utility industry and consumers. 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.
The Company is complying with these rules from the FERC. To implement
the requirements of Order 888, as amended, the Company has filed an Open Access
Transmission Tariff ("OATT"), the Company's original OATT, which was accepted
for filing by FERC on June 11, 1997, had an effective date of July 9, 1996. The
Company filed an updated OATT on July 30, 1997 to comply with FERC's changes to
Order 888. That filing remains pending before FERC. Among other things, the OATT
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, net of related transmission
revenues, based upon each company's share of the total system load.
On December 27, 1996, the Company submitted, in accordance with Order
889, "Standards of Conduct" governing interactions between its
transmission-function employees and its wholesale merchant-function employees.
On March 12, 1998, the FERC issued an order requiring the Company and many other
utilities to submit revised Standards of Conduct. In accordance with the FERC's
11
directive, revised Standards will be submitted in April 1998. Generally
speaking, the FERC has required only that the Company provide a more detailed
version of the Standards it has already submitted, or that the Standards reflect
changes required by amendments to Order 889 that occurred after the Company
originally submitted its Standards. Management expects minimal annual expense
increases, as a result of Orders 888 and 889.
Orders 888 and 889 are cornerstones of the FERC's efforts to encourage
competition in the wholesale electric power market. As part of its own efforts
to better its competitive position in the wholesale market, the Company on
November 3, 1997 sought from the FERC authority to sell capacity and energy at
"market-based," negotiated rates. The Company was granted market-based rate
authority on December 18, 1997, subject to certain restrictions on interactions
with its affiliates. For example, the Company is prohibited from selling power
to its affiliates under its market-based rate schedule without separate approval
from the FERC. Such restrictions on affiliate interactions, which are intended
to prevent affiliate abuse, are the norm for traditional utilities with
market-based rate authority.
Enogex's newly formed subsidiary, OGE Energy Resources, Inc. ("OERI") is
a power marketer that received market-based rate authority in 1997. OERI is an
indirect wholly-owned subsidiary of the Company's parent, OGE Energy Corp. and,
as a result, is an affiliate of the Company. Like the Company, OERI is subject
to certain restrictions on its dealings with the Company, such as the
prohibition on sales to the Company without separate approval from the FERC.
OERI is authorized to "broker" power purchases and sales for the Company, again
subject to certain restrictions. These restrictions, which are intended to
prevent affiliate abuse are the norm for power marketers with traditional
utility affiliates.
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 $32 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 proceedings 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 the redesign
and restructuring effort in 1994 and continuing actions to reduce fuel costs,
improvements in customer service and efforts to improve the
12
Company's electric transmission and distribution network to reduce outages, all
of which enhance the Company's ability to deliver electricity competitively.
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 our
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 1997,
these programs and schedules included: (i) elimination of the Low Use
Residential Service rate (because it did not effectively reach those customers
it was intended to serve); (ii) an increased level of Company funding to the
LIHEAP assistance program (the LIHEAP program helps low income residential
customers meet their winter heating needs with lower electrical heating energy
costs); (iii) the "Surprise Free Guarantee" program, which guarantees
residential customers comfort and annual energy consumption for heating, cooling
and water heating for new homes built to energy efficient standards; (iv) the
elimination of the PEAKS program (a program that helped reduce the summer
residential air conditioning peak) because continuation of this program was not
cost effective as compared to other alternatives; (v) 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 (vi) 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 afternoons to
non-peak hours.
The Company implemented a Real Time Pricing ("RTP") pilot program, for
industrial and commercial customers that can meet the requirements of the
tariff. 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 which 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 the helping of
customers in control of their costs.
The Company's 1997 marketing efforts included geothermal heat pumps,
electrotechnologies, an 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 compliant, 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.
13
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 1997, approximately 81 percent of the Company-generated energy
was produced by coal-fired units and 19 percent by natural gas-fired units. It
is estimated that the fuel mix for 1998 through 2002, based upon expected
generation for these years, will be as follows:
1998 1999 2000 2001 2002
- --------------------------------------------------------------------------------
Coal............. 80% 80% 79% 79% 79%
Natural Gas...... 20% 20% 21% 21% 21%
The decline in the percentage of coal-fired generation relative to total
generation will result from projected increases in natural gas-fired generation,
not 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:
1997 1996 1995 1994 1993
- --------------------------------------------------------------------------------
Coal........... $0.84 $0.83 $0.83 $0.78 $1.16
Natural Gas.... $3.60 $3.61 $3.19 $3.58 $3.64
Weighted Avg... $1.39 $1.45 $1.41 $1.58 $1.92
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 "Regulation and
Rates - Automatic Fuel Adjustment Clauses."
COAL-FIRED UNITS: All Company coal units, with an aggregate capability of 2,530
- ----------------
megawatts, are designed to burn low sulfur western coal. The Company purchases
coal under a mix of long- and short-term contracts. During 1997, the Company
purchased 9.6 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
14
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 1997, rail congestion on the Union Pacific Railroad caused a 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 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, resulting in a record capacity factor of
approximately 79 percent. See "Environmental Matters" for a discussion of an
environmental proposal that, if implemented as proposed, could inhibit the
Company's ability to use coal as its primary boiler fuel.
GAS-FIRED UNITS: For calendar year 1998, the Company expects to acquire less
- ----------------
than 2 percent of its gas needs from long-term gas purchase contracts. The
remainder of the Company's gas needs during 1998 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 $42.6 million during 1998, compared to
approximately $48.8 million utilized in 1997. Approximately $0.9 million of the
Company's construction expenditures budgeted for 1998 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 the Company believes it can meet the SO2 limits without
additional capital expenditures. In 1997 the Company emitted 61,475 tons of SO2.
15
With respect to the nitrogen oxide ("NOx") regulations of Title IV of
the CAA, the Company committed to meeting a 0.45 lbs/mm Btu NOx emission level
in 1997. 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 1997 was 0.38 lbs/mm Btu.
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 1997.
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 was exempted from any OTAG emission reduction requirements. If
reductions had been 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.
EPA has finalized revisions to the ambient ozone and particulate
standards. Based on historic data and EPA projections, Tulsa and Oklahoma
counties would fail to meet the proposed standard for ozone. In addition,
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.
In December 1997, the United States agreed to a global treaty for the
reduction of greenhouse gases that contribute to global warming. The U.S.
committed to a 7 percent reduction in carbon dioxide from the 1990 levels. If
the Senate ratifies the treaty, 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 estimated 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 1997 the Company obtained refunds of approximately
$0.5 million from its recycling efforts. This figure does not include the
additional savings gained through the reduction and/or avoidance of disposal
costs and the reduction in material purchases due to reuse of existing
materials. Similar savings are anticipated in future years.
The Company has made application for renewal of all of its National
Pollutant Discharge Elimination System ("NPDES") permits. The Company has
received two of the permits in final form and the others are pending regulatory
action. It is anticipated, because of regulation changes, that all of the
permits when finally issued will offer greater operational flexibility than
those in the past.
The Company has requested from the State agency responsible for the
development of Water Quality Standards removal of 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. It is anticipated that the
request for the removal of this classification will be successful.
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."
16
The Company has and will continue to evaluate the impact of its
operations on the environment. As a result, contamination on Company property
will be discovered from time to time. One site identified as having been
contaminated by historical operations was addressed during 1997. 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.
17
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 5,647 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 549
2 Gas 1973 507
3 Gas 1975 500 1,556
Muskogee 3 Gas 1956 184
4 Coal 1977 500
5 Coal 1978 500
6 Coal 1984 515 1,699
Sooner 1 Coal 1979 505
2 Coal 1980 510 1,015
Horseshoe 6 Gas 1958 178
Lake 7 Gas 1963 238
8 Gas 1969 404 820
Mustang 1 Gas 1950 58 Inactive
2 Gas 1951 57 Inactive
3 Gas 1955 122
4 Gas 1959 260
5 Gas 1971 64 446
Conoco 1 Gas 1991 26
2 Gas 1991 26 52
Arbuckle 1 Gas 1953 74 Inactive
Enid 1 Gas 1965 12
2 Gas 1965 12
3 Gas 1965 12
4 Gas 1965 12 48
Woodward 1 Gas 1963 11 11
---------
Total Active Generating Capability (all stations) 5,647
=========
18
At December 31, 1997, 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) 301 substations with a total capacity of
approximately 4.1 million kVA, 19,896 structure miles of overhead lines, 1,585
miles of underground conduit and 6,502 miles of underground conductors in
Oklahoma; and (ii) 30 substations with a total capacity of approximately 617,500
kVA, 1,642 structure miles of overhead lines, 154 miles of underground conduit
and 353 miles of underground conductors in Arkansas.
Substantially all of the Company's electric facilities are subject to a
direct first mortgage lien under the Trust Indenture securing the Company's
first mortgage bonds. The Trust Indenture and related lien are expected to be
discharged in April 1998.
During the three years ended December 31, 1997, the Company's gross
property, plant and equipment additions approximated $300 million and gross
retirements approximated $89 million. These additions were provided by
internally generated funds. The additions during this three-year period amounted
to approximately 8.2 percent of total property, plant and equipment at December
31, 1997.
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 motion
to dismiss or 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 granted
the motion to dismiss or summary judgment. 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 Party's ("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
19
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.
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 OG&E 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) tortious
interference with contract; and (vi) tortious interference with a prospective
economic advantage. Trigen seeks actual damages of at least $7 million, trebled,
together with its costs, pre-and post-judgment interest and attorney fees, in
connection with each of the first four counts. It seeks actual damages of at
least $7 million, plus punitive damages together with its costs, pre-and
post-judgment interest
20
and attorney fees, in connection with each of the remaining counts. Trigen also
seeks permanent injunctive relief against the alleged Sherman Act violations and
against the Company's alleged practice of offering cooling services to customers
in Oklahoma City in the form of RTP-priced electricity "bundled" together with
financing, construction, and/or other consulting services at guaranteed rates.
The Company filed an answer and counterclaim on November 7, 1996
asserting that Trigen made false claims, misrepresented facts, published false
statements and other defamatory conduct which damaged the Company, and asserting
violation of the Oklahoma Deceptive Trade Practices Act. The Company seeks
punitive and actual damages. While the Company cannot predict the outcome of
this proceeding, the Company believes that it will not have a material adverse
effect on its 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 have appealed. Management
believes that the lawsuit is without merit and will not have a material adverse
effect on the Company's financial position or its results of operations.
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. ss. 35-201, et seq. Plaintiffs seek money damages against the
Defendants under 62 O.S. ss. 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 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.
21
While the Company cannot predict the precise outcome of these proceedings, the
Company believes at the present time that the lawsuits are without merit and
intends to vigorously defend this case.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
- ------------------------------------------------------------
None
EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------
The following persons were Executive Officers of the Registrant as of
March 15, 1998:
Name Age Title
- -------------------- --- --------------------------------
Steven E. Moore 51 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 54 Senior Vice President - Finance
and Administration
Melvin D. Bowen, Jr. 56 Vice President - Power Delivery
Jack T. Coffman 54 Vice President - Power Supply
Michael G. Davis 48 Vice President - Marketing and
Customer Services
Irma B. Elliott 59 Vice President and
Corporate Secretary
James R. Hatfield 40 Vice President and Treasurer
Donald R. Rowlett 40 Controller Corporate Accounting
Don L. Young 57 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 21, 1998.
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
1992-1995: Vice President - Law
and Public Affairs
Al M. Strecker 1996-Present: Senior Vice President -
Energy Corp.
1994-Present: Senior Vice President -
Finance and
Administration
1992-1994: Vice President and
Treasurer
Melvin D. Bowen, Jr. 1994-Present: Vice President -
Power Delivery
1992-1994: Metro Region
Superintendent
Jack T. Coffman 1994-Present: Vice President -
Power Supply
1992-1994: Manager - Generation
Services
23
Name Business Experience
- -------------------------- -------------------------------------------
Michael G. Davis 1996-Present: Vice President - Energy
Corp.
1994-Present: Vice President -
Marketing and
Customer Services
1992-1994: Director - Marketing
Division
1992: Manager - Industrial
Services
Irma B. Elliott 1996-Present: Vice President and
Corporate Secretary -
Energy Corp.
1996-Present: Vice President and
Corporate Secretary
1992-1996: 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
(an intrastate gas
pipeline subsidiary of
UtiliCorp United Inc.)
1992-1993: Assistant Treasurer -
UtiliCorp United Inc.
(an electric and
natural gas utility
company)
Donald R. Rowlett 1996-Present: Controller Corporate
Accounting
1994-1996: Assistant Controller
1992-1994: Senior Specialist -
Tax Accounting
1992: Specialist - Tax Accounting
Don L. Young 1996-Present: Controller Corporate Audits
1992-1996: Controller
24
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
- ---------------------------------------------------------
STOCKHOLDER MATTERS.
- -------------------
Currently, all Company common stock, 40,378,745 shares, is held by
Energy Corp. Therefore, there is no public trading market for the Company's
common stock.
25
ITEM 6. SELECTED FINANCIAL DATA.
- --------------------------------
HISTORICAL DATA
As Restated - See Note 1
to Consolidated Financial Statements
---------------------------------------------------
1997 1996 1995 1994 1993
-----------------------------------------------------------------
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS EXCEPT
FOR PER SHARE DATA)
Operating revenues.................. $1,191,691 $1,200,337 $1,168,287 $1,196,898 $1,282,817
Operating expenses.................. 1,016,974 1,022,988 987,270 1,016,074 1,106,820
----------- ----------- ----------- ----------- -----------
Operating income.................... 174,717 177,349 181,017 180,824 175,997
Other income and deductions......... 2,224 (914) 2,272 321 (873)
Interest charges.................... 55,947 59,566 70,745 67,350 70,394
----------- ----------- ----------- ----------- -----------
Net income.......................... 120,944 116,869 112,544 113,795 104,730
Preferred dividend requirements..... 2,285 2,302 2,316 2,317 2,317
----------- ----------- ----------- ----------- -----------
Earnings available for common....... $ 118,709 $ 114,567 $ 110,228 $ 111,478 $ 102,413
=========== =========== =========== =========== ===========
Long-term debt...................... $ 691,924 $ 709,281 $ 723,862 $ 723,667 $ 748,660
Total assets........................ $2,350,782 $2,421,241 $2,754,871 $2,782,629 $2,731,424
Earnings per average common share... $ 2.94 $ 2.84 $ 2.73 $ 2.76 $ 2.54
CAPITALIZATION RATIOS *
Common equity....................... 53.46% 52.57% 54.78% 54.35% 53.17%
Cumulative preferred stock.......... 3.09% 3.09% 2.92% 2.95% 2.93%
INTEREST COVERAGES *
Before federal income taxes
(including AFUDC)............... 4.43X 4.09X 3.49X 3.66X 3.36X
(excluding AFUDC)............... 4.42X 4.08X 3.47X 3.64X 3.35X
After federal income taxes
(including AFUDC)............... 3.14X 2.94X 2.56X 2.66X 2.48X
(excluding AFUDC)............... 3.13X 2.93X 2.55X 2.65X 2.47X
* These amounts do not include Enogex.
26
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) 1997 1996 1995 1997 1996
- --------------------------------------------------------------------------------------------------------
Operating revenues........................... $1,191,690 $1,200,337 $1,168,287 (0.7) 2.7
Earnings available for common stock.......... $ 118,709 $ 114,567 $ 110,228 3.6 3.9
Average shares outstanding................... 40,379 40,367 40,356 --- ---
Earnings per average common share from
continuing operations....................... $ 2.94 $ 2.84 $ 2.73 3.5 4.0
Dividends paid per share..................... $ 2.68 $ 2.66 $ 2.66 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 from continuing operations for 1997 increased 3.5 percent from
$2.84 per share in 1996 to $2.94 per share in 1997. The increase was primarily
the result of the Generation Efficiency Performance Rider ("GEP Rider"), lower
interest costs and continued customer growth in the Company's service area. 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 increase was
partially offset by the $45 million annual rate reduction in March 1997. The
1996 increase is primarily the result of continued customer growth in the
Company's service area and lower interest costs.
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") recently initiated proceedings to consider the
implementation of a competitive retail market in Arkansas. These developments
are described in more detail below under "Regulation; Competition."
27
In 1996, the Company decided upon an enterprise-wide software future
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.
28
RESULTS OF OPERATIONS
REVENUES
Percent Change
From Prior Year
---------------
(THOUSANDS) 1997 1996 1995 1997 1996
- -------------------------------------------------------------------------------------------------
Sales of electricity to OG&E customers... $1,168,663 $1,173,961 $1,135,720 (0.5) 3.4
Provisions for rate refund............... --- (1,221) (2,437) * *
Sales of electricity to other utilities.. 23,027 27,597 35,004 (16.6) (21.2)
- ---------------------------------------------------------------------------------
Total operating revenues............ $1,191,690 $1,200,337 $1,168,287 (0.7) 2.7
=================================================================================================
System kilowatt-hour sales............... 22,182,992 21,540,670 20,828,415 3.0 3.4
Kilowatt-hour sales to other utilities... 1,201,933 1,475,449 1,851,839 (18.5) (20.3)
- ---------------------------------------------------------------------------------
Total kilowatt-hour sales........... 23,384,925 23,016,119 22,680,254 1.6 1.5
=================================================================================================
*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 decreased $8.6 million or 0.7 percent during 1997.
This decrease was due to the rate reduction in March 1997 and milder weather in
the first and second quarters of 1997, partially offset by continued customer
growth, the effect of the GEP Rider and warmer weather in the third quarter of
1997. During 1996, operating revenues increased $32.0 million or 2.7 percent due
to continued customer growth and a return to more normal weather resulting in
increased system sales.
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 and that related to the Company
workforce reduction in 1994. 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.
29
On June 18, 1997, the Company filed documents with the OCC relating to
the GEP Rider, pursuant to the Order. The GEP Rider 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 1997, the GEP Rider increased revenues by
approximately $18.0 million, or approximately $0.28 per share. The current GEP
Rider is estimated to positively impact revenue by $27 million, or approximately
$0.41 per share during the 12 months ending June 1998.
EXPENSES AND OTHER ITEMS
Percent Change
From Prior Year
---------------
(DOLLARS IN THOUSANDS) 1997 1996 1995 1997 1996
- -------------------------------------------------------------------------------------------------
Fuel ............................. $ 319,494 $ 323,412 $ 304,775 (1.2) 6.1
Purchased power................... 222,464 222,070 216,598 0.2 2.5
Other operation and maintenance... 245,943 253,176 249,873 (2.9) 1.3
Depreciation and Amortization..... 114,760 112,233 110,719 2.3 1.4
Taxes............................. 114,312 112,097 105,305 2.0 6.4
- ---------------------------------------------------------------------------
Total operating expenses..... $1,016,973 $1,022,988 $ 987,270 (0.6) 3.6
=================================================================================================
Total operating expenses decreased $6.0 million or 0.6 percent in 1997,
primarily due to lower fuel costs for the production of electricity and reduced
operation and maintenance expenses. These reductions were partially offset by
increases in depreciation and amortization and income taxes.
The Company's generating capability is 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 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. During 1996, fuel costs increased $18.6 million or 6.1 percent
because of increased generation of electricity resulting from continued customer
growth and favorable weather conditions in the electric service area.
Other operation and maintenance 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. Other operation and maintenance increased approximately $3.3 million or
1.3 percent in 1996 due to the new enterprise-wide software information
processing system,
30
increased pension expense and minor overhauls at coal-fired generating plants.
The 1996 increases were partially offset by a reduction in transmission and
distribution maintenance expenses.
In 1997, income taxes increased primarily due to an increase in deferred
taxes associated with depreciation. Income taxes increased in 1996 as a result
of an increase in pre-tax earnings.
Purchased power costs were $222.5 million in 1997, remaining relatively
constant compared to the $222.1 million in 1996. Purchased power costs increased
$5.5 million or 2.5 percent in 1996 primarily due to the availability of larger
quantities of economically-priced energy from other utilities. As required by
PURPA, the Company is currently purchasing power from qualified cogeneration
facilities. As discussed below, the Company recently took action to restructure
one of its cogeneration contracts. See related discussion of purchased power in
Note 8 of Notes to Consolidated Financial Statements.
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; and the OCC issued an order in
February 1994 requiring, among other things, a $41.3 million refund relating to
the fees the Company paid Enogex. See Note 9 of Notes to Consolidated Financial
Statements for a discussion of the July 1996 and February 1994 orders.
The Company has initiated numerous other 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 1997 and 1996
reflects higher levels of depreciable plant.
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. The decrease in interest
expense for 1996 was primarily attributable to the successful refinancing of
approximately $300 million of long-term debt in 1995.
31
LIQUIDITY, CAPITAL RESOURCES AND CONTINGENCIES
The primary capital requirements for 1997 and as estimated for 1998
through 2000 are as follows:
(DOLLARS IN MILLIONS) 1997 1998 1999 2000
- --------------------------------------------------------------------------------
Construction expenditures
including AFUDC.................. $100.1 $108.0 $100.0 $100.0
Maturities of long-term debt and
sinking fund requirements........ 15.0 25.0 12.5 110.0
- --------------------------------------------------------------------------------
Total.......................... $115.1 $133.0 $112.5 $210.0
================================================================================
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.
1997 CAPITAL REQUIREMENTS AND FINANCING ACTIVITIES
Capital requirements were $100.1 million in 1997. Approximately $1.0
million of the 1997 capital requirements were to comply with environmental
regulations. This compares to capital requirements of $94 million in 1996, of
which $1.3 million were to comply with environmental regulations.
During 1997, the Company's primary source of capital was internally
generated funds from operating cash flows. Operating cash flow remained strong
in 1997 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.
Short-term borrowings were used during 1997 to meet temporary cash
requirements. At December 31, 1997, the Company had no outstanding short-term
borrowings.
In July 1997, the Company issued $250 million of long-term debt with
$125 million at 6.50 percent due July 15, 2017, and $125 million at 6.65 percent
due July 15, 2027. The proceeds from the sale of this new debt were applied to
the redemption on August 21, 1997, of: $75 million principal amount of the
Company's 8.375 percent First Mortgage Bonds due January 1, 2007; $100 million
principal amount of the Company's 8.25 percent First Mortgage Bonds due August
15, 2016; and $75 million principal amount of the Company's 8.875 percent First
Mortgage Bonds due December 1, 2020; all at the stated principal amount, plus
the applicable redemption premiums and accrued interest to the redemption date.
In July 1997, the Company also refinanced its obligations with respect to $56
million of 7 percent Pollution Control Revenue Bonds due March 1, 2017, through
the issuance of a new series due
32
June 1, 2027, and bearing interest at a variable rate. The annualized interest
rate on these bonds from their date of issuance through December 31, 1997, was
approximately 4.4 percent.
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.
In January 1998, all outstanding shares of the Company's cumulative
preferred stock were redeemed. In February 1998, the Company filed a
registration statement for up to $112.5 million of senior notes. Assuming
favorable market conditions, the Company may issue all or part of these senior
notes to refinance first mortgage bonds.
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 balance of the century, the
Company will concentrate on maintaining the reliability and increasing the
utilization of existing capacity and increasing demand-side management efforts.
Approximately $0.9 million of the Company's construction expenditures budgeted
for 1998 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.
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. Under the Public
Utility Regulatory Policy Act ("PURPA"), the Company was obligated to enter into
the original contract, which was approved by the OCC in 1987, and which required
the Company to purchase 110 megawatts of peaking capacity from the plant for 10
years beginning in 1998 -- whether the capacity was needed or not. As part of
this transaction, Energy Corp. agreed to purchase the stock of Oklahoma Loan
Acquisition Corporation, the company that owns the MCPC plant, for approximately
$25 million. Completion of the transaction is subject to receipt of numerous
regulatory approvals in addition to the OCC, including the FERC and the APSC.
Assuming the transaction is approved by the necessary regulatory agencies and
the transaction is completed, the term of the existing cogeneration contract
will be reduced by four and one-half years, which should reduce the amounts to
be paid by the Company, and should provide savings for its Oklahoma customers,
of approximately $46 million as compared to the existing cogeneration contract.
Funding for the $25 million purchase price is expected to be provided by
internally generated funds and short-term borrowings.
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. Energy
Corp. has the necessary regulatory approvals to incur up to $400 million in
short-term borrowings at any one time. Energy Corp. has in place a line of
credit for up to $160 million which expires December 6, 2000.
33
THE YEAR 2000 ISSUE
Many computer systems and applications currently use two-digit date
fields to designate a year. As the year 2000 approaches, date-sensitive systems
will recognize the year 2000 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 and suppliers to process critical financial and
operational information incorrectly, if they are not Year 2000 compliant.
The Company is aggressively addressing the century date-change issues.
This is reflected by the January 1, 1997, implementation throughout the Company
of the enterprise-wide software system which is Year 2000 compliant. As a result
of the enterprise-wide software installation, the Company was able to
significantly reduce the potential risks of its older computer systems, because
many programs were replaced by the new software which is Year 2000 compliant. As
part of the Company's lease agreement for personal computers, all new personal
computers are being issued with operating systems that are Year 2000 compliant.
All existing personal computers will be upgraded with Year 2000 compliant
operating systems before the turn of the century. In addition, the Company has
formed a multifunctional team of experienced and knowledgeable Company members
from each business unit to review and test the operational systems in an effort
to further eliminate any potential problems should they exist. Year 2000
compliance may also adversely affect the operations and financial performance of
the Company indirectly by causing complications at the Company's suppliers and
customers. The Company intends to determine the status of its significant
customers and suppliers in becoming Year 2000 compliant. There can be no
assurance that the Company's operations will not be adversely affected by Year
2000 problems of its customers and suppliers. At this time, the Company is
currently unable to anticipate the magnitude of the operational or financial
impact on the Company of Year 2000 issues with its suppliers and customers.
Other than costs incurred to implement the enterprise-wide software
system and the replacement of personal computers, both of which were part of the
normal budgeting process and would have occurred regardless of the Year 2000
issues, the Company has not incurred any incremental costs associated with Year
2000. At this time, the Company currently anticipates incurring less than $2.0
million for future Year 2000 compliance expenses. Anticipated spending for any
such modifications will be expensed as incurred and is not expected to have a
material impact on the Company's consolidated financial position or results of
operations.
It is the Company's goal to minimize the impact the turn of the century
date-change will have for its shareowners, customers and employees.
CONTINGENCIES
The Company is defending various claims and legal actions, including
environmental actions, which are common to its operations. As to environmental
matters, the Company has been designated as a "potentially responsible party"
("PRP") with respect to two waste disposal sites to which the Company sent
materials. Remediation 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.
34
The Company has contracted for low-sulfur coal to comply with the sulfur
dioxide limitations of the Clean Air Act Amendments of 1990 ("CAAA"). The
Company also has completed installation and certification of all required
continuous emissions monitors at each of its generating units. Phase II sulfur
dioxide emission requirements will affect the Company beginning in the year
2000. The Company believes it can meet these sulfur dioxide limits without
additional capital expenditures. With respect to nitrogen oxide limits, the
Company is meeting the current emission standards and has exercised its option
to extend the effective date of the further reductions from 2000 to 2008. The
Company is continuing to monitor regulatory proposals including nitrogen oxide
regulations proposed by the EPA in October 1997. These regulations address
long-range ozone transport from Midwest emissions sources that allegedly
contribute to ozone problems in the Northeast. As proposed, such regulations
would not apply to the Company, but if these or similar regulations were to be
adopted and applied to the Company, the Company could be required to incur
significant capital expenditures and significantly increased operation and
maintenance costs.
The Oklahoma Department of Environmental Quality's CAAA Title V air
permitting program was approved by the EPA in March 1996. By March of 1997, the
Company had submitted comprehensive site air permit applications for all of its
major source generating stations. Air permit fees for generating stations were
approximately $0.3 million in 1997 and are estimated to be approximately $0.3
million in 1998.
REGULATION; COMPETITION
As previously reported, Oklahoma enacted in April 1997 the Electric
Restructuring Act of 1997 (the"Act"). 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 OCC 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 under the direction
of the Joint Electric Utility Task Force, composed of seven members from the
Oklahoma Senate and seven members from the Oklahoma House of Representatives.
The OCC Study is to be delivered in four parts. The first part of the Study,
which was delivered February 1, 1998, addressed operational issues. The second
part of the Study, which is due December 1, 1998, is to address technical
issues, such as reliability, safety, unbundling of generation, transmission and
distribution services, transition issues and market power. The third part of the
Study is due December 31, 1999, and is to address financial issues, including
rates, charges, access fees, transition costs and stranded costs. The final part
of the Study is due August 31, 2000, and is to cover consumer issues, such as
the obligation to serve, service territories, consumer choices, competition and
consumer safeguards.
The Act similarly directs the Oklahoma Tax Commission to study and
submit a report to the Joint Task Force by December 31, 1998, regarding 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.
35
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 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, and (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.
A new bill was introduced in the State Senate in the 1998 legislative
session and was passed by a State Senate committee in February 1998. This bill,
if adopted, would modify the Act by (i) directing the Joint Task Force, instead
of the OCC, to conduct the required studies and (ii) accelerating the deadlines
for completion of such studies to October 1, 1999.
The Company intends to actively participate in the restructuring of the
electric utility industry in Oklahoma and to remain a competitive supplier of
electricity. However, due to the early stages of the process, the Company cannot
predict the impact that the restructuring will have on its operations in the
future.
In December 1997, the APSC established four generic proceedings to
consider the implementation of a competitive retail electric market in the State
of Arkansas. Among the topics to be considered are 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 intends to participate
actively in these proceedings.
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 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
generators access to public utility transmission facilities.
In April 1996, the FERC issued two final rules, Orders 888 and 889,
which have had a significant impact on wholesale markets. Order 888, which was
preceded by a Notice of Proposed Rulemaking referred to as the "Mega-NOPR", 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 ("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. The Company is complying with these
rules from the FERC.
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
36
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
deregulate 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 $32 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) and that the Company file a cost of service study within 60
days. The Company is in the process of evaluating the application.
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.
37
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
- ----------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
See Note 1
============
Year ended December 31 (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1997 1996 1995
==============================================================================================================
OPERATING REVENUES................................................. $1,191,690 $1,200,337 $1,168,287
- --------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Fuel............................................................ 319,494 323,412 304,775
Purchased power................................................. 222,464 222,070 216,598
Other operation and maintenance................................. 245,943 253,176 249,873
Depreciation and amortization................................... 114,760 112,233 110,719
Current income taxes............................................ 60,544 73,171 72,800
Deferred income taxes, net...................................... 15,927 2,156 (2,335)
Deferred investment tax credits, net............................ (5,150) (5,150) (5,150)
Taxes other than income......................................... 42,991 41,920 39,990
- --------------------------------------------------------------------------------------------------------------
Total operating expenses..................................... 1,016,973 1,022,988 987,270
- --------------------------------------------------------------------------------------------------------------
OPERATING INCOME................................................... 174,717 177,349 181,017
- --------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
Interest income................................................. 4,531 3,187 6,556
Other........................................................... (2,307) (4,101) (4,284)
- --------------------------------------------------------------------------------------------------------------
Net other income and deductions.............................. 2,224 (914) 2,272
- --------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt...................................... 53,281 54,141 63,970
Allowance for borrowed funds used during construction........... (599) (709) (1,224)
Other........................................................... 3,265 6,134 7,999
- --------------------------------------------------------------------------------------------------------------
Total interest charges, net.................................. 55,947 59,566 70,745
- --------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS.................................. 120,994 116,869 112,544
INCOME FROM OPERATIONS OF ENOGEX DISTRIBUTED
TO OGE ENERGY CORP.(less applicable taxes of $8,050
and $3,502 respectively)......................................... --- 16,463 12,712
- --------------------------------------------------------------------------------------------------------------
NET INCOME......................................................... 120,994 133,332 125,256
PREFERRED DIVIDEND REQUIREMENTS.................................... 2,285 2,302 2,316
- --------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON STOCK................................ $ 118,709 $ 131,030 $ 122,940
==============================================================================================================
AVERAGE COMMON SHARES OUTSTANDING.................................. 40,379 40,367 40,356
EARNINGS PER AVERAGE COMMON SHARE:
Income from continuing operations................................ $ 2.94 $ 2.84 $ 2.73
Income from Enogex operations.................................... --- 0.41 0.32
- --------------------------------------------------------------------------------------------------------------
Earnings per average common share................................ $ 2.94 $ 3.25 $ 3.05
==============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
38
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
See Note 1
============
Year ended December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
==============================================================================================================
BALANCE AT BEGINNING OF PERIOD..................................... $ 328,630 $ 425,545 $ 409,960
ADD:
Income from continuing operations............................... 120,994 116,869 112,544
Income from operations of Enogex................................ --- 16,463 12,712
- --------------------------------------------------------------------------------------------------------------
Total........................................................ 449,624 558,877 535,216
DEDUCT:
Cash dividends declared on preferred stock...................... 2,285 2,302 2,316
Cash dividends declared on common stock......................... 108,393 107,377 107,355
- --------------------------------------------------------------------------------------------------------------
Total Cash Dividends......................................... 110,678 109,679 109,671
Distribution of Enogex to OGE Energy Corp....................... --- 120,568 ---
- --------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD........................................... $ 338,946 $ 328,630 $ 425,545
==============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
39
CONSOLIDATED BALANCE SHEETS
See Note 1
============
December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
==============================================================================================================
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service...................................................... $3,647,366 $3,574,241 $3,523,708
Construction work in progress................................... 18,910 26,807 24,446
- --------------------------------------------------------------------------------------------------------------
Total property, plant and equipment.......................... 3,666,276 3,601,048 3,548,154
Less accumulated depreciation............................. 1,653,771 1,560,546 1,483,899
- --------------------------------------------------------------------------------------------------------------
Net property, plant and equipment............................ 2,012,505 2,040,502 2,064,255
- --------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost............................ 28,140 21,869 21,858
- --------------------------------------------------------------------------------------------------------------
PROPERTY, EQUIPMENT AND OTHER LONG-TERM
ASSETS OF ENOGEX................................................ --- --- 295,447
- --------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents....................................... 228 200 397
Accounts receivable - customers, less reserve of $3,583,
$3,520 and $3,847, respectively.............................. 92,379 96,067 88,509
Accrued unbilled revenues....................................... 36,900 34,900 43,550
Accounts receivable - other..................................... 9,795 44,699 8,283
Fuel inventories, at LIFO cost.................................. 43,577 60,463 59,277
Materials and supplies, at average cost......................... 24,481 20,387 18,856
Prepayments and other........................................... 2,533 3,094 3,479
Accumulated deferred tax assets................................. 6,048 8,994 10,042
Current assets of Enogex........................................ --- --- 36,816
- --------------------------------------------------------------------------------------------------------------
Total current assets......................................... 215,941 268,804 269,209
- --------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Advance payments for gas........................................ 10,500 9,500 6,500
Income taxes recoverable - future rates......................... 42,549 44,368 41,934
Other........................................................... 41,147 36,198 55,668
- --------------------------------------------------------------------------------------------------------------
Total deferred charges....................................... 94,196 90,066 104,102
- --------------------------------------------------------------------------------------------------------------
TOTAL ASSETS....................................................... $2,350,782 $2,421,241 $2,754,871
==============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
40
CONSOLIDATED BALANCE SHEETS (Continued)
See Note 1
============
December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
==============================================================================================================
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statements):
Common stock and retained earnings.............................. $ 851,390 $ 841,035 $ 937,535
Cumulative preferred stock...................................... 49,266 49,379 49,939
Long-term debt.................................................. 691,924 709,281 723,862
Long-term debt of Enogex........................................ --- --- 120,000
- --------------------------------------------------------------------------------------------------------------
Total capitalization......................................... 1,592,580 1,599,695 1,831,336
- --------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Short-term debt................................................. --- 41,400 67,600
Accounts payable - affiliates................................... 14,986 --- ---
Accounts payable................................................ 47,802 63,596 55,275
Dividends payable............................................... 571 27,421 27,427
Customers' deposits............................................. 23,846 23,257 21,920
Accrued taxes................................................... 18,963 25,037 26,556
Accrued interest................................................ 15,746 16,386 15,967
Long-term debt due within one year.............................. 25,000 15,000 ---
Other........................................................... 35,386 35,739 32,953
Current liabilities of Enogex................................... --- --- 24,458
- --------------------------------------------------------------------------------------------------------------
Total current liabilities.................................... 182,300 247,836 272,156
- --------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation.......................... 57,418 57,137 63,983
Accumulated deferred income taxes............................... 439,657 429,766 427,178
Accumulated deferred investment tax credits..................... 72,878 78,028 83,178
Other........................................................... 5,949 8,779 12,120
Deferred credits and other liabilities of Enogex................ --- --- 64,920
- --------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities................. 575,902 573,710 651,379
- --------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 8 and 9)
- --------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES............................... $2,350,782 $2,421,241 $2,754,871
==============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
41
CONSOLIDATED STATEMENTS OF CAPITALIZATION
See Note 1
============
December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
=================================================================================================================
COMMON STOCK AND RETAINED EARNINGS:
Common stock, par value $2.50 per share;
authorized 100,000,000 shares; and
outstanding 40,378,745, 46,470,616,
and 46,470,616 shares, respectively............................. $ 100,947 $ 116 177 $ 116,177
Premium on capital stock........................................... 411,497 608,544 608,273
Retained earnings.................................................. 338,946 328,630 425,545
Treasury stock - zero, 6,091,871, and 6,097,357
shares, respectively............................................ --- (212,316) (212,460)
- -----------------------------------------------------------------------------------------------------------------
Total common stock and retained earnings..................... 851,390 841,035 937,535
- -----------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK:
Par value $20, authorized 675,000 shares - 4%;
418,963, 421,963, and 421,963 shares, respectively.............. 8,379 8,439 8,439
Par value $100, authorized 1,865,000 shares-
SERIES SHARES OUTSTANDING
4.20% 49,750, 49,950, and 50,000 shares, respectively....... 4,975 4,995 5,000
4.24% 74,990, 75,000, and 75,000 shares, respectively....... 7,499 7,500 7,500
4.44% 63,200, 63,500, and 65,000 shares, respectively....... 6,320 6,350 6,500
4.80% 70,925, 70,950, and 75,000 shares, respectively....... 7,093 7,095 7,500
5.34% 150,000, 150,000, and 150,000 shares, respectively.... 15,000 15,000 15,000
- -----------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock............................. 49,266 49,379 49,939
- -----------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT:
First mortgage bonds-
SERIES DATE DUE
5.125% January 1, 1997....................................... --- 15,000 15,000
6.375% January 1, 1998....................................... 25,000 25,000 25,000
7.125% January 1, 1999....................................... 12,500 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 40,000
8.375% January 1, 2007....................................... --- 75,000 75,000
8.625% November 1, 2007...................................... 35,000 35,000 35,000
8.250% August 15, 2016....................................... --- 100,000 100,000
7.000% Pollution Control Series C, March 1, 2017............. --- 56,000 56,000
6.500% Senior Notes Series D, July 15, 2017.................. 125,000 --- ---
8.875% December 1, 2020...................................... --- 75,000 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 --- ---
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 --- ---
Unamortized premium and discount, net.............................. (976) (8,619) (9,038)
- -----------------------------------------------------------------------------------------------------------------
Total long-term debt......................................... 716,924 724,281 723,862
Less long-term debt due within one year................... 25,000 15,000 ---
- -----------------------------------------------------------------------------------------------------------------
Total long-term debt (excluding long-term
debt due within one year)................................. 691,924 709,281 723,862
Enogex Inc................................................... --- --- 120,000
- -----------------------------------------------------------------------------------------------------------------
Total Capitalization.................................................. $1,592,580 $1,599,695 $1,831,336
=================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
42
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Note 1
============
Year ended December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
==============================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income....................................................... $ 120,994 $ 133,332 $ 125,256
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation................................................... 114,760 136,140 132,135
Deferred income taxes and investment tax credits, net.......... 10,777 (3,000) (9,078)
Provision for rate refund...................................... --- 1,804 3,112
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers............................ 3,688 (16,533) (6,462)
Accrued unbilled revenues.................................. (2,000) 8,650 (6,750)
Fuel, materials and supplies inventories................... 12,792 (4,200) (6,457)
Accumulated deferred tax assets............................ 3,142 692 1,318
Other current assets....................................... 35,269 (2,361) 38,051
Accounts payable........................................... (809) 13,401 5,887
Accrued taxes.............................................. (6,074) (1,176) 2,784
Accrued interest........................................... (640) 688 (4,729)
Accumulated provision for rate refund...................... --- (2,650) (320)
Other current liabilities.................................. (26,614) 7,131 (6,905)
Other operating activities..................................... 1,728 22,753 13,667
- --------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities................ 267,013 294,671 281,509
- --------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures........................................... (100,079) (161,129) (141,439)
- --------------------------------------------------------------------------------------------------------------
Net cash used in investing activities.................... (100,079) (161,129) (141,439)
- --------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt................................... (321,000) --- (331,650)
Proceeds from long-term debt................................... 306,000 --- 419,400
Short-term debt, net........................................... (41,400) (26,200) (115,150)
Redemption of preferred stock.................................. (114) (560) (34)
Retirement of treasury stock................................... 285 --- ---
Cash dividends declared on preferred stock..................... (2,285) (2,302) (2,316)
Cash dividends declared on common stock........................ (108,392) (107,377) (107,355)
- --------------------------------------------------------------------------------------------------------------
Net cash used in financing activities.................... (166,906) (136,439) (137,105)
- --------------------------------------------------------------------------------------------------------------
NET (DECREASE) INCREASE IN CASH AND CASH
EQUIVALENTS...................................................... 28 (2,897) 2,965
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD:
From continuing operations..................................... 200 397 434
From Enogex operations......................................... --- 5,023 2,021
- --------------------------------------------------------------------------------------------------------------
Total cash and cash equivalents at beginning of period... 200 5,420 2,455
- --------------------------------------------------------------------------------------------------------------
EFFECT OF REORGANIZATION - ENOGEX CASH............................. --- (2,323) ---
CASH AND CASH EQUIVALENTS AT END OF PERIOD:
From continuing operations..................................... 228 200 397
From Enogex operations......................................... --- --- 5,023
- --------------------------------------------------------------------------------------------------------------
Total cash and cash equivalents at end of period......... $ 228 $ 200 $ 5,420
==============================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)........................... $ 54,248 $ 64,482 $ 76,860
Income taxes .................................................. $ 57,150 $ 82,970 $ 77,752
- --------------------------------------------------------------------------------------------------------------
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.
43
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. The net income of Enogex prior to December 31, 1996, is
included in the consolidated statements of income as "Income from Operations of
Enogex Distributed to OGE Energy Corp." Prior year consolidated financial
statements have been restated to reflect Enogex being 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 be charged to expense are deferred as regulatory liabilities
based on expected flowback to customers in future rates. Management's expected
recovery of deferred costs and flowback of deferred credits generally results
from specific decisions by regulators granting such ratemaking treatment. At
December 31, 1997, regulatory assets and regulatory liabilities are being
reflected in rates charged to customers over periods ranging from one to 20
years.
44
The components of deferred charges - other, on the Consolidated Balance
Sheets included the following, as of December 31:
DEFERRED CHARGES - OTHER
(DOLLARS IN THOUSANDS) 1997 1996 1995
==================================================================================================
Workforce reduction (regulatory asset)......................... $ --- $ 3,759 $ 26,331
Unamortized debt expense....................................... 5,779 10,291 10,919
Unamortized loss on reacquired debt (regulatory asset)......... 28,660 10,253 11,197
Insurance claims - property damage............................. --- 6,231 ---
Miscellaneous.................................................. 6,708 5,664 7,221
- --------------------------------------------------------------------------------------------------
Total....................................................... $ 41,147 $ 36,198 $ 55,668
==================================================================================================
REGULATORY ASSETS AND LIABILITIES
(DOLLARS IN THOUSANDS) 1997 1996 1995
==================================================================================================
Regulatory Assets:
Income taxes recoverable from customers................... $ 115,989 $ 127,819 $ 139,594
Unamortized loss on reacquired debt (regulatory asset).... 28,660 10,253 11,197
Workforce reduction....................................... --- 3,759 26,331
Miscellaneous............................................. 403 435 455
- --------------------------------------------------------------------------------------------------
Total Regulatory Assets................................ 145,052 142,266 177,577
Regulatory Liabilities:
Income taxes refundable to customers...................... (73,440) (83,451) (97,660)
Gain on disposition of allowances......................... --- (329) (282)
- --------------------------------------------------------------------------------------------------
Net Regulatory Assets........................................ $ 71,612 $ 58,486 $ 79,635
==================================================================================================
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.
ACCOUNTING PRONOUNCEMENTS
In March 1997, the FASB issued SFAS No. 128, "Earnings per Share."
Adoption of SFAS No. 128 is required for both interim and annual periods ending
after December 15, 1997. This new standard was adopted effective December 31,
1997, and it did not impact the Company's earnings per share.
In March 1997, the FASB issued SFAS No. 129, "Disclosure of Information
about Capital Structure." Adoption of SFAS No. 129 is required for financial
statements for periods ending after
45
December 15, 1997. This new standard was adopted effective December 31, 1997,
and it did not change the presentation of the Company's capital structure.
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income." Adoption of SFAS No. 130 is required for both interim and annual
periods beginning after December 15, 1997. The Company will adopt this new
standard effective March 31, 1998, and management believes the adoption of this
standard will not have a material impact on its consolidated financial position
or results of operations.
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 will adopt this
new standard effective December 31, 1998. Adoption of this new standard will
change the presentation of certain disclosure information of the Company, but
will 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 will adopt this new standard effective December 31, 1998. Adoption
of this new standard will change the presentation of certain disclosure
information of the Company, but will not affect reported earnings.
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 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 1997, 1996 and
1995, 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.
46
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 5.94, 5.63 and 6.30 percent
for the years 1997, 1996 and 1995, respectively.
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
$18.5 million, $24.0 million and $27.3 million at December 31, 1997, 1996 and
1995, 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 the short-term loan rates
and is reviewed and updated periodically. The interest rates were 8.25 percent,
9.75 percent and 9.90 percent at December 31, 1997, 1996 and 1995, respectively.
The current portion of these loans totaled $4.9 million, $4.0 million
and $3.6 million at December 31, 1997, 1996 and 1995, respectively, and are
classified as accounts receivable - customers in the accompanying Consolidated
Balance Sheets. The noncurrent portion of these loans totaled $19.1 million,
$15.3 million and $13.8 million at December 31, 1997, 1996 and 1995,
respectively, and are classified as other property and investments in the
accompanying Consolidated Balance Sheets.
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.
47
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 $1.1 million
for 1997, and exceeded the stated LIFO cost by approximately $4.6 million and
$2.4 million for 1996 and 1995, respectively, 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 $12.2 million, $10.4 million and $9.2 million
at December 31, 1997, 1996 and 1995, 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.
RECLASSIFICATIONS
Certain amounts have been reclassified on the consolidated financial
statements to conform with the 1997 presentation.
RELATED PARTY TRANSACTIONS
During 1997, approximately $2.7 million of costs 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 1997, 1996 and 1995, the Company paid Enogex approximately $41.7
million, $44.3 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
48
unaffiliated sources. At December 31, 1997, a current liability of approximately
$10 million is included in accounts payable - affiliates in the accompanying
Consolidated Balance Sheets for these activities.
2. INCOME TAXES
The items comprising tax expense are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
- -------------------------------------------------------------------------------------------------------
Provision For Current Income Taxes:
Federal............................................ $ 51,214 $ 65,954 $ 61,996
State.............................................. 9,330 7,217 10,804
- --------------------------------------------------------------------------------------------------------
Total Provision For Current Income Taxes........ 60,544 73,171 72,800
- --------------------------------------------------------------------------------------------------------
Provisions (Benefit) For Deferred Income Taxes, net:
Federal
Depreciation.................................... 5,856 2,297 5,548
Repair allowance................................ 794 2,100 2,101
Removal costs................................... 774 630 700
Provision for rate refund....................... --- 928 (588)
Software implementation costs................... 4,840 --- ---
Company restructuring........................... (494) (8,250) (8,373)
Other........................................... 2,252 219 (1,613)
State.............................................. 1,905 4,232 (110)
- --------------------------------------------------------------------------------------------------------
Total Provision (Benefit) For Deferred Income Taxes, net 15,927 2,156 (2,335)
- --------------------------------------------------------------------------------------------------------
Deferred Investment Tax Credits, net................... (5,150) (5,150) (5,150)
Income Taxes Relating to Other Income and Deductions... 1,403 (515) 1,436
- --------------------------------------------------------------------------------------------------------
Total Income Tax Expense........................ $ 72,724 $ 69,662 $ 66,751
- --------------------------------------------------------------------------------------------------------
Pretax Income.......................................... $ 193,718 $ 186,531 $ 179,295
========================================================================================================
49
The following schedule reconciles the statutory federal tax rate to the
effective income tax rate:
Year ended December 31 1997 1996 1995
- --------------------------------------------------------------------------------------------------------
Statutory federal tax rate................................. 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit...... 3.8 4.0 3.9
Tax credits, net........................................... (2.7) (2.8) (2.9)
Other, net................................................. 1.4 1.1 1.2
- --------------------------------------------------------------------------------------------------------
Effective income tax rate as reported................. 37.5% 37.3% 37.2%
========================================================================================================
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.
50
The components of Accumulated Deferred Income Taxes at December 31,
1997, 1996 and 1995 are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
==============================================================================================================
Current Deferred Tax Assets:
Accrued vacation ......................................... $ 3,853 $ 3,821 $ 3,377
Provision for rate refund................................. --- --- 1,025
Uncollectible accounts.................................... 1,540 1,383 1,489
Capitalization of indirect costs.......................... 106 2,583 2,583
Provision for Worker's Compensation claims................ 549 1,207 1,568
- --------------------------------------------------------------------------------------------------------------
Accumulated deferred tax assets....................... $ 6,048 $ 8,994 $ 10,042
==============================================================================================================
Deferred Tax Liabilities:
Accelerated depreciation and other property-related
differences........................................... $423,488 $410,094 $401,043
Allowance for funds used during construction.............. 43,327 46,429 49,572
Income taxes recoverable through future rates............. 44,888 49,466 54,023
- --------------------------------------------------------------------------------------------------------------
Total................................................. 511,703 505,989 504,638
- --------------------------------------------------------------------------------------------------------------
Deferred Tax Assets:
Deferred investment tax credits........................... (23,623) (25,372) (27,120)
Income taxes refundable through future rates.............. (28,421) (32,296) (37,795)
Postemployment medical and life insurance benefits........ (3,131) (2,301) (2,347)
Company pension plan...................................... (15,503) (14,965) (10,306)
Other..................................................... (1,368) (1,289) 108
- --------------------------------------------------------------------------------------------------------------
Total................................................. (72,046) (76,223) (77,460)
- --------------------------------------------------------------------------------------------------------------
Accumulated Deferred Income Tax Liabilities.................... $439,657 $429,766 $427,178
==============================================================================================================
51
3. COMMON STOCK AND RETAINED EARNINGS
There were no new shares of common stock issued during 1997, 1996 or
1995. The $197 million decrease in 1997 in premium on capital stock, as
presented on the Consolidated Statements of Capitalization, represents the
retirement of treasury stock and repurchased preferred stock. The $0.3 million
increase in 1996, represents the gains and losses associated with the issuance
of common stock pursuant to the Restricted Stock Plan 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 and 18,872 shares of
common stock during 1996 and 1995, respectively. The Company also reacquired
10,538 shares in 1996. The shares distributed/reacquired in the reported periods
were recorded as treasury stock.
Changes in common stock were:
(THOUSANDS) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------
Shares outstanding January 1................................... 40,379 40,373 40,354
Issued/reacquired under the Restricted Stock Plan, net......... --- 6 19
- ----------------------------------------------------------------------------------------------------
Shares outstanding December 31................................. 40,379 40,379 40,373
====================================================================================================
There were 4,703,391 shares of unissued Energy Corp. common stock
reserved for the various employee and Company stock plans at December 31, 1997.
With the exception of the Restricted Stock Plan, the common stock requirements,
pursuant to those plans, are currently being satisfied with stock purchased on
the open market.
The Company's Restated Certificate of Incorporation and its Trust
Indenture, as supplemented, relating to the First Mortgage Bonds, contained
provisions which, under specific conditions, limit the amount of dividends
(other than in shares of common stock) and/or other distributions which may be
made to common shareowners.
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. 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.
52
4. CUMULATIVE PREFERRED STOCK
Preferred stock is redeemable at the option of the Company at the
following amounts per share plus accrued dividends: the 4% Cumulative Preferred
Stock at the par value of $20 per share; the Cumulative Preferred Stock, par
value $100 per share, as follows: 4.20% series-$102; 4.24% series-$102.875;
4.44% series-$102; 4.80% series-$102; and 5.34% series-$101.
In January 1998, all outstanding shares of the Company's cumulative
preferred stock were redeemed. See Note 11 of Notes to Consolidated Financial
Statements.
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
The Company's Trust Indenture, as supplemented, relating to the First
Mortgage Bonds, requires the Company to pay to the trustee annually, an amount
sufficient to redeem, for sinking fund purposes, 1 1/4 percent of the highest
amount outstanding at any time. This requirement has been satisfied by pledging
permanent additions to property to the extent of 166 2/3 percent of principal
amounts of bonds otherwise required to be redeemed. Through December 31, 1997,
gross property additions pledged totaled approximately $394 million.
Annual sinking fund requirements for each of the five years subsequent
to December 31, 1997, are as follows:
Year Amount
==========================================================
1998.......................................$ 11,614,583
1999.......................................$ 11,354,167
2000.......................................$ 11,354,167
2001.......................................$ 11,354,167
2002.......................................$ 10,520,833
==========================================================
As in prior years, the Company expects to meet these requirements by
pledging permanent additions to property.
In February 1997, the Company filed a registration statement for up to
$50 million of grantor trust preferred securities. In February 1998, the Company
filed a registration statement for up to $112.5 million of senior notes.
Assuming favorable market conditions, the Company may issue all or part of these
securities to refinance, at lower rates, one or more series of outstanding first
mortgage bonds.
Maturities of long-term debt during the next five years consist of $25
million in 1998, $12.5 million in 1999, $110 million in 2000 and $40 million in
2002.
The Company incurred costs relating to a series of amendments to its
Trust Indenture in 1991 and refinancing of long-term debt in 1997 and 1995.
Unamortized debt expense and unamortized loss on reacquired debt, and
unamortized premium and discount on long-term debt are being amortized over the
53
life of the respective debt and are classified as deferred charges -- other and
long-term debt, respectively, in the accompanying Consolidated Balance Sheets.
Substantially all electric plant was subject to lien of the Trust
Indenture at December 31, 1997.
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. Energy Corp. has an
agreement for a flexible line of credit, up to $160 million, through 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, 1997.
7. 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 the one-time costs was amortized over 26 months, commencing
January 1, 1995. The components of the severance and VERP costs and the amount
deferred are as follows:
SFAS SFAS
(DOLLARS IN THOUSANDS) No. 88 No. 106 Severance Total
==============================================================================================================
Curtailment Loss...................................... $ 1,042 $ 5,457 $ --- $ 6,499
Recognition of Transition Obligation.................. --- 17,268 --- 17,268
Special Retirement Benefits........................... 28,198 6,566 --- 34,764
Enhanced Severance.................................... --- --- 4,891 4,891
- --------------------------------------------------------------------------------------------------------------
Total VERP and Severance Costs........................ $ 29,240 $ 29,291 $ 4,891 $ 63,422
- --------------------------------------------------------------------------------------------------------------
Deferred as a Regulatory Asset at December 31, 1994............................................ $(48,903)
==============================================================================================================
The amortization of the deferred regulatory asset was $3.7 million,
$22.6 million and $22.6 million at December 31, 1997, 1996 and 1995,
respectively.
54
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. 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.
Net periodic pension cost is computed in accordance with provisions of
SFAS No. 87, "Employers' Accounting for Pensions," and is recorded in the
accompanying Statements of Income in other operation.
In determining the projected benefit obligation, the weighted average
discount rates used were 7.00, 7.75 and 7.25 percent for 1997, 1996 and 1995,
respectively. The assumed rate of increase in future salary levels was 4.50
percent in 1997, 1996 and 1995. The expected long-term rate of return on plan
assets used in determining net periodic pension cost was 9.00 percent for the
reported periods.
The plan's assets consist primarily of U. S. Government securities,
listed common stocks and corporate debt.
Net periodic pension costs for 1997, 1996 and 1995 included the
following:
(DOLLARS IN THOUSANDS) 1997 1996 1995
=================================================================================================
Service costs...................................... $ 5,798 $ 5,472 $ 4,174
Interest cost on projected benefit obligation...... 20,226 20,414 19,971
Return on plan assets ............................. (18,620) (18,314) (14,742)
Net amortization and deferral...................... (475) (1,263) (1,263)
Amortization of unrecognized prior service cost.... 2,937 2,937 2,634
- -------------------------------------------------------------------------------------------------
Net periodic pension costs......................... $ 9,866 $ 9,246 $ 10,774
=================================================================================================
55
The following table sets forth the plan's funded status at December 31,
1997, 1996 and 1995:
(DOLLARS IN THOUSANDS) 1997 1996 1995
===============================================================================================
Projected benefit obligation:
Vested benefits..................................... $(229,458) $(219,222) $(228,231)
Nonvested benefits.................................. (18,649) (16,869) (17,476)
- ------------------------------------------------------------------------------------------------
Accumulated benefit obligation...................... (248,107) (236,091) (245,707)
Effect of future compensation levels................ (40,741) (41,305) (42,790)
- ------------------------------------------------------------------------------------------------
Projected benefit obligation............................. (288,848) (277,396) (288,497)
Plan's assets at fair value.............................. 218,223 217,208 210,483
- ------------------------------------------------------------------------------------------------
Plan's assets less than projected benefit obligation..... (70,625) (60,188) (78,014)
Unrecognized prior service cost.......................... 37,164 42,954 40,616
Unrecognized net asset from application of SFAS No. 87... (4,693) (6,316) (7,580)
Unrecognized net (gain) loss............................. 1,525 (15,101) (8,638)
- ------------------------------------------------------------------------------------------------
Accrued pension liability................................ $ (36,629) $(38,651) $ (36,340)
================================================================================================
POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
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. Net postretirement benefit expense for 1997, 1996 and 1995 included
the following components:
(DOLLARS IN THOUSANDS) 1997 1996 1995
==============================================================================================
Service cost......................................... $ 1,957 $ 2,052 $ 1,721
Interest cost........................................ 6,120 6,577 6,989
Return on plan assets................................ (8,046) (3,263) (576)
Net amortization..................................... 6,431 3,723 3,197
Net amount capitalized or deferred................... (1,293) (2,157) (2,399)
--------------------------------------------------------------------------------------------
Net postretirement benefit expense.............. $ 5,169 $ 6,932 $ 8,932
============================================================================================
The discount rates used in determining the accumulated postretirement
benefit obligation were 7.00, 7.75 and 7.25 percent for December 31, 1997, 1996
and 1995, respectively. The rate of increase in future compensation levels used
in measuring the life insurance accumulated postretirement benefit obligation
was 4.50 percent for December 31, 1997, 1996 and 1995. The expected long-term
rate of return on plan assets used in determining net postretirement benefit
expense was 9.00 percent for 1997 and 1996, and was not applicable for 1995. An
8.25 percent annual rate of increase in the per capita cost
56
of covered health care benefits was assumed for 1997; the rate is assumed to
decrease gradually to 4.50 percent by the year 2007 and remain at that level
thereafter. A one-percentage-point increase in the assumed health care cost
trend rates would increase the accumulated postretirement benefit obligation as
of December 31, 1997, by approximately $10.2 million, and the aggregate of the
service and interest cost components of net postretirement health care cost for
1997 by approximately $0.9 million.
The following table sets forth the funded status of the postretirement
benefits and amounts recognized in the Company's Consolidated Balance Sheets as
of December 31, 1997, 1996 and 1995:
(DOLLARS IN THOUSANDS) 1997 1996 1995
===================================================================================================
Accumulated postretirement benefit obligation:
Retirees..................................... $(74,160) $(77,118) $(86,317)
Actives eligible to retire................... (2,745) (3,116) (2,239)
Actives not yet eligible to retire........... (10,652) (10,449) (10,369)
- ---------------------------------------------------------------------------------------------------
Total.................................... (87,557) (90,683) (98,925)
- ------------------------------------------------------------------------------- -------------------
Plan assets at fair value......................... 45,619 39,066 23,864
- ----------------------------------------------------------------------------------------------------
Funded status .................................... (41,938) (51,617) (75,061)
Unrecognized transition obligation................ 38,119 41,951 44,573
Unrecognized net actuarial gain (loss)............ (12,828) (7,293) 4,272
- ----------------------------------------------------------------------------------------------------
Accrued postretirement benefit obligation......... $(16,647) $(16,959) $(26,216)
====================================================================================================
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 1998 are estimated at $108 million.
The Company acquires natural gas for boiler fuel under 183 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,
1997, 1996 and 1995, outstanding prepayments for gas, including the amounts
classified as current assets, under these contracts were approximately $10.7
million, $9.9 million and $7.4 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, 1997, the Company held non-cancelable operating leases
covering 1,495 coal hopper railcars. Rental payments are charged to fuel expense
and recovered through the company's tariffs and automatic fuel adjustment
clauses. The leases have purchase and renewal options. Future minimum lease
payments due under the railcar leases, assuming the leases are renewed under the
renewal option are as follows:
57
(DOLLARS IN THOUSANDS)
1998..................... $5,431 2001................... $ 5,128
1999..................... 5,331 2002................... 5,026
2000..................... 5,230 2003 and beyond........ 56,097
--------
Total Minimum Lease Payments............................... $ 82,243
========
Rental payments under operating leases were approximately $5.4 million
in 1997, $5.4 million in 1996, and $6.5 million in 1995.
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 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 the third-party developer for gas storage
service. Pursuant to the contract, the third-party developer reimbursed the
Company for all outstanding cash advances and interest amounting to
approximately $46.8 million. The Company also entered into a bridge financing
agreement as guarantor for the third-party. In July 1997, the third-party
obtained permanent financing and issued a note in the amount of $49.5 million.
The proceeds from such permanent financing were applied to repay the outstanding
bridge financing. In connection therewith, Energy Corp. entered into a note
purchase agreement, pursuant to which it has agreed, upon the occurrence of a
monetary default by such third-party on its permanent financing, to purchase the
third-party's note at a price equal to the unpaid principal and interest under
the third-party note.
The Company has entered into agreements with four qualifying
cogeneration facilities having initial terms of 3 to 32 years. These contracts
were entered into pursuant to the Public Utility Regulatory Policy Act of 1978
("PURPA"). Stated generally, PURPA and the regulations thereunder promulgated by
FERC require the Company to purchase power generated in a manufacturing process
from a qualified cogeneration facility ("QF"). The rate for such power to be
paid by the Company was approved by the OCC. The rate generally consists of two
components: one is a rate for actual electricity purchased from the QF by the
Company; the other is a capacity charge which the Company must pay the QF for
having the capacity available. However, if no electrical power is made available
to the Company for a period of time (generally three months), the Company's
obligation to pay the capacity charge is suspended. The total cost of
cogeneration payments is 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 respect to one of these
facilities. If approved, the contract term will be shortened and the total
payments will be reduced by approximately $46 million. See Note 11 of Notes to
Consolidated Financial Statements for related discussion.
During 1997, 1996, and 1995, the Company made total payments to
cogenerators of approximately $212.2 million, $210.0 million, and $210.4
million, of which $176.2 million, $175.2 million, and $174.1 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: 1998 - $187 million, 1999 - $189 million,
2000 - $190 million, 2001 - $191 million and 2002 - $193 million.
58
Approximately $0.9 million of the Company's construction expenditures
budgeted for 1998 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 $42.6 million during 1998, compared to
approximately $48.8 million in 1997. 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.
The Company has contracted for low-sulfur coal to comply with the sulfur
dioxide limitations of the Clean Air Act Amendments of 1990 ("CAAA"). The
Company also has completed installation and certification of all required
continuous emissions monitors at each of its generating units. Phase II sulfur
dioxide emission requirements will affect the Company beginning in the year
2000. The Company believes it can meet these sulfur dioxide limits without
additional capital expenditures. With respect to nitrogen oxide limits, the
Company is meeting the current emission standards and has exercised its option
to extend the effective date of the further reductions from 2000 to 2008.
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.
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.
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
59
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 February 25, 1994, the OCC issued an order that, among other things,
effectively lowered the Company's rates to its Oklahoma retail customers by
approximately $14 million annually (based on a test year ended June 30, 1991)
and required the Company to refund approximately $41.3 million. The $14 million
annual reduction in rates lowered the Company's rates to its Oklahoma customers
by approximately $17 million annually. With respect to the $41.3 million refund,
the entire amount relates to the disallowance of a portion of the fees paid by
the Company to Enogex for transportation services of which $39.1 million was
associated with revenues prior to January 1, 1994, while the remaining $2.2
million related to 1994.
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) and that OG&E file a cost of service study within 60 days.
OG&E is in the process of evaluating the application.
10. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair
value of each class of financial instruments:
CASH AND CASH EQUIVALENTS AND CUSTOMER DEPOSITS
The fair value of cash and cash equivalents and customer deposits
approximate the carrying amount due to their short maturity.
LONG-TERM DEBT AND PREFERRED STOCK
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:
60
1997 1996 1995
------------------- ----------------- -----------------
Carrying Fair Carrying Fair Carrying Fair
(DOLLARS IN THOUSANDS) Amount Value Amount Value Amount Value
============================================================================================================
Cash and Cash Equivalents............... $ 228 $ 228 $ 200 $ 200 $ 397 $ 397
============================================================================================================
Customer Deposits $ 23,846 $ 23,846 $ 23,257 $ 23,257 $ 21,920 $ 21,920
============================================================================================================
Long-Term Debt and Preferred Stock:
First Mortgage Bonds.................... $581,524 $594,357 $644,881 $656,362 $644,462 $671,356
Industrial Authority Bonds.............. 135,400 135,400 79,400 79,400 79,400 79,400
Preferred Stock:
4% - 5.34% Series -- 827,828, 831,363
and 836,963 Shares, respectively..... 49,266 49,997 49,379 35,829 49,939 35,541
=============================================================================================================
11. SUBSEQUENT EVENTS
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. Under PURPA, the
Company was obligated to enter into the original contract, which was approved by
the OCC in 1987, and which required the Company to purchase peaking capacity
from the plant for 10 years beginning in 1998 -- whether the capacity was needed
or not. In January 1998, Energy Corp. agreed to purchase the stock of Oklahoma
Loan Acquisition Corporation, the company that owns the MCPC plant, for
approximately $25 million. As part of the transaction, the term of the existing
cogeneration contract with the Company will be shortened. If the transaction is
approved by the necessary regulatory agencies, the Company estimates that it
will provide savings for its Oklahoma customers of approximately $46 million.
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.
On February 11, 1998, the Company filed a registration statement for up
to $112.5 million of senior notes. Assuming favorable market conditions, the
Company may issue all or part of these securities to refinance, at lower rates,
one or more series of outstanding first mortgage bonds.
As more fully explained in Note 9, 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.
61
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, 1997, 1996 and 1995, 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, 1997, 1996 and 1995,
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 20, 1998
62
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.
63
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 PER Dec 31 Sep 30 Jun 30 Mar 31
SHARE DATA)
- ---------------------------------------------------------------------------------------------------------------
Operating revenues......................... 1997 $264,053 $417,612 $282,147 $227,878
1996 251,669 411,765 303,077 233,826
1995 241,041 436,846 275,524 214,876
- ---------------------------------------------------------------------------------------------------------------
Operating income........................... 1997 $ 20,825 $100,500 $ 43,283 $ 10,109
1996 18,002 101,098 47,356 10,893
1995 19,785 110,603 37,717 12,912
- ---------------------------------------------------------------------------------------------------------------
Income from operations of Enogex
distributed to OGE Energy Corp.......... 1997 $ --- $ --- $ --- $ ---
1996 3,900 3,740 4,322 4,501
1995 3,575 2,844 3,039 3,254
- ---------------------------------------------------------------------------------------------------------------
Net income (loss).......................... 1997 $ 9,154 $ 86,601 $ 29,124 $ (3,885)
1996 7,301 90,165 35,328 538
1995 4,890 96,969 24,258 (861)
- ---------------------------------------------------------------------------------------------------------------
Earnings (loss) available for common....... 1997 $ 8,583 $ 86,030 $ 28,553 $ (4,457)
1996 6,729 89,593 34,749 (41)
1995 4,311 96,390 23,679 (1,440)
- ---------------------------------------------------------------------------------------------------------------
Earnings (loss) per average common share... 1997 $ 0.21 $ 2.13 $ 0.71 $ (0.11)
1996 0.17 2.22 0.86 (0.00)
1995 0.11 2.39 0.59 0.04
- ---------------------------------------------------------------------------------------------------------------
64
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 27, 1998. 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 STATEMEMT 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, 1997, 1996 and 1995
o Consolidated Statements of Income for the years ended December
31, 1997, 1996 and 1995
o Consolidated Statements of Retained Earnings for the years ended
December 31, 1997, 1996 and 1995
o Consolidated Statements of Capitalization at December 31, 1997, 1996 and
1995
o Consolidated Statements of Cash Flows for the years ended December 31,
1997, 1996 and 1995
o Notes to Consolidated Financial Statements
o Report of Independent Public Accountants
o Report of Management
65
SUPPLEMENTARY DATA
------------------
o Interim Consolidated Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE
- ----------------------------------------------------- ----
Schedule II - Valuation and Qualifying Accounts 74
Report of Independent Public Accountants 75
Financial Data Schedule 86
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
February 1, 1945, from OG&E to
The First National Bank and Trust Company
of Oklahoma City, Trustee. (Filed as Exhibit 7-A to
Registration Statement No. 2-5566 and incorporated by
reference herein)
4.02 Copy of Supplemental Trust Indenture, dated
December 1, 1948, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 7.03 to Registration Statement No.
2-7744 and incorporated by reference herein)
4.03 Copy of Supplemental Trust Indenture, dated
June 1, 1949, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.03
to Registration Statement No. 2-7964 and
incorporated by reference herein)
66
4.04 Copy of Supplemental Trust Indenture, dated
May 1, 1950, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.04
to Registration Statement No. 2-8421 and
incorporated by reference herein)
4.05 Copy of Supplemental Trust Indenture, dated
March 1, 1952, being a supplemental instrument to
Exhibit 4.01 hereto.(Filed as Exhibit 4.08 to
Registration Statement No. 2-9415
and incorporated by reference herein)
4.06 Copy of Supplemental Trust Indenture, dated
June 1, 1955, being a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.07 to
Registration Statement No. 2-12274 and
incorporated by reference herein)
4.07 Copy of Supplemental Trust Indenture, dated
January 1, 1957, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.07 to
Registration Statement No. 2-14115 and
incorporated by reference herein)
4.08 Copy of Supplemental Trust Indenture, dated
June 1, 1958, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.09 to
Registration Statement No. 2-19757 and
incorporated by reference herein)
4.09 Copy of Supplemental Trust Indenture, dated
March 1, 1963, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.09 to
Registration Statement No. 2-23127 and
incorporated by reference herein)
4.10 Copy of Supplemental Trust Indenture, dated
March 1, 1965, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.10 to
Registration Statement No. 2-25808 and
incorporated by reference herein)
4.11 Copy of Supplemental Trust Indenture, dated
January 1, 1967, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.11 to
Registration Statement No. 2-27854 and
incorporated by reference herein)
67
4.12 Copy of Supplemental Trust Indenture, dated
January 1, 1968, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.12 to
Registration Statement No. 2-31010 and
incorporated by reference herein)
4.13 Copy of Supplemental Trust Indenture, dated
January 1, 1969, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.13 to
Registration Statement No. 2-35419 and
incorporated by reference herein)
4.14 Copy of Supplemental Trust Indenture, dated
January 1, 1970, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.14 to
Registration Statement No. 2-42393 and
incorporated by reference herein)
4.15 Copy of Supplemental Trust Indenture, dated
January 1, 1972, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.15 to
Registration Statement No. 2-49612 and
incorporated by reference herein)
4.16 Copy of Supplemental Trust Indenture, dated
January 1, 1974, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.16 to
Registration Statement No. 2-52417 and
incorporated by reference herein)
4.17 Copy of Supplemental Trust Indenture, dated
January 1, 1975, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.17 to
Registration Statement No. 2-55085 and
incorporated by reference herein)
4.18 Copy of Supplemental Trust Indenture, dated
January 1, 1976, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.18 to
Registration Statement No. 2-57730 and
incorporated by reference herein)
4.19 Copy of Supplemental Trust Indenture, dated
September 14, 1976, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.19 to
Registration Statement No. 2-59887
and incorporated by reference herein)
68
4.20 Copy of Supplemental Trust Indenture, dated
January 1, 1977, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.20 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
4.21 Copy of Supplemental Trust Indenture, dated
November 1, 1977, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.21 to
Registration Statement No. 2-70539 and
incorporated by reference herein)
4.22 Copy of Supplemental Trust Indenture, dated
December 1, 1977, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.22 to
Registration Statement No. 2-70539 and
incorporated by reference herein)
4.23 Copy of Supplemental Trust Indenture, dated
February 1, 1980, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.23 to
Registration Statement No. 2-70539 and
incorporated by reference herein)
4.24 Copy of Supplemental Trust Indenture, dated
April 15, 1982, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.24 to
the Company's Form 10-K Report, File No.1-1097,
for the year ended December 31, 1982, and incorporated
by reference herein)
4.25 Copy of Supplemental Trust Indenture, dated
August 15, 1986, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.25 to
the Company's Form 10-K Report, File No.1-1097,
for the year ended December 31, 1986, and incorporated
by reference herein)
4.26 Copy of Supplemental Trust Indenture, dated
March 1, 1987, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.26 to
the Company's Form 10-K Report for the year ended
December 31, 1987, File No. 1-1097, and incorporated
by reference herein)
69
4.28 Copy of Supplemental Trust Indenture, dated November 15, 1990,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.28 to the Company's Form 10-K Report
for the year ended December 31, 1990, File No. 1-1097,
and incorporated by reference herein)
4.29 Copy of Supplemental Trust Indenture, dated December 9, 1991,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.29 to the Company's Form 10-K Report
for the year ended December 31, 1991, File No. 1-1097,
and incorporated by reference herein)
4.30 Copy of Supplemental Trust Indenture, dated October 1, 1995,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.02 to the Company's Form 8-K Report
dated October 23, 1995, File No. 1-1097,
and incorporated by reference herein)
4.31 Copy of Supplemental 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)
4.32 Copy of Supplemental Trust Indenture No.1, dated October 16, 1995,
being a supplemental instrument to Exhibit 4.31 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)
4.33 Supplemental Indenture No.2, dated as of July 1, 1997,
being a supplemental instrument to Exhibit 4.31
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)
4.34 Supplemental Trust Indenture, dated as of July 1, 1997,
being a supplemental instrument to Exhibit 4.01
hereto (Filed as Exhibit 4.02 to OG&E's
Form 8-K filed on July 17, 1997, 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)
70
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 Restricted Stock Plan of Energy Corp. (Filed as Exhibit 10.09
to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996, File No. 1-12579, and incorporated
by reference herein)
10.08 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)
71
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.
(Filed as Exhibit 10.16 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996, File
No. 1-12579 and incorporated by reference herein)
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995
Executive Compensation Plans and Arrangements
---------------------------------------------
10.05 Form of Change of Control Agreement for Officers of the
Company and Energy Corp. (Filed as Exhibit 10.07
to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996, File No. 1-12579, and incorporated
by reference herein)
10.06 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 Restricted Stock Plan of the Company. (Filed as Exhibit 10.09
to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996, File No. 1-12579, and incorporated
by reference herein)
72
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. (Filed as
Exhibit 10.16 to Energy Corp.'s Form 10-K Report for
the year ended December 31, 1996, File No. 1-12579 and
incorporated by reference herein)
(B) REPORTS ON FORM 8-K
- ------------------------
Item 5. Other Events, dated November 21, 1997, reporting
that the Company had called for redemption of all its
existing preferred stock.
73
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
------------ --------- ---------- ----------- ---------- --------
1997 (THOUSANDS)
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
1995
Reserve for Uncollectible Accounts $3,521 $7,428 - $7,102 $3,847
74
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 20 1998. Our audits were made for the purpose of forming an opinion on
those statements taken as a whole. The schedule listed on Page 66, Item 14 (a)
2. is the responsibility of the Company's management and is presented for
purposes of complying with the Securities and Exchange Commission's rules and is
not part of the basic financial statements. This schedule has been subjected to
the auditing procedures applied in the audits of the basic financial statements
and, in our opinion, fairly states in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
/ s / Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 20, 1998
75
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 27th day of March, 1998.
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 27, 1998
/ s / A. M. Strecker
A. M. Strecker Principal Financial Officer; and March 27, 1998
/ s / Donald R. Rowlett
Donald R. Rowlett Principal Accounting Officer. March 27, 1998
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 27, 1998
76
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
February 1, 1945, from OG&E to
The First National Bank and Trust Company
of Oklahoma City, Trustee. (Filed as Exhibit 7-A to
Registration Statement No. 2-5566 and incorporated by
reference herein)
4.02 Copy of Supplemental Trust Indenture, dated December 1, 1948,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 7.03 to Registration Statement
No. 2-7744 and incorporated by reference herein)
4.03 Copy of Supplemental Trust Indenture, dated June 1, 1949,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 7.03 to Registration Statement
No. 2-7964 and incorporated by reference herein)
4.04 Copy of Supplemental Trust Indenture, dated
May 1, 1950, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.04
to Registration Statement No. 2-8421 and
incorporated by reference herein)
4.05 Copy of Supplemental Trust Indenture, dated March 1, 1952, a
supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.08 to Registration Statement
No. 2-9415 and incorporated by reference herein)
77
4.06 Copy of Supplemental Trust Indenture, dated
June 1, 1955, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.07
to Registration Statement No. 2-12274 and
incorporated by reference herein)
4.07 Copy of Supplemental Trust Indenture, dated
January 1, 1957, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.07
to Registration Statement No. 2-14115 and
incorporated by reference herein)
4.08 Copy of Supplemental Trust Indenture, dated
June 1, 1958, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.09
to Registration Statement No. 2-19757 and
incorporated by reference herein)
4.09 Copy of Supplemental Trust Indenture, dated
March 1, 1963, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.09
to Registration Statement No. 2-23127 and
incorporated by reference herein)
4.10 Copy of Supplemental Trust Indenture, dated
March 1, 1965, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.10
to Registration Statement No. 2-25808 and
incorporated by reference herein)
4.11 Copy of Supplemental Trust Indenture, dated
January 1, 1967, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.11
to Registration Statement No. 2-27854 and
incorporated by reference herein)
4.12 Copy of Supplemental Trust Indenture, dated
January 1, 1968, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.12
to Registration Statement No. 2-31010 and
incorporated by reference herein)
4.13 Copy of Supplemental Trust Indenture, dated
January 1, 1969, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.13
to Registration Statement No. 2-35419 and
incorporated by reference herein)
78
4.14 Copy of Supplemental Trust Indenture, dated January 1, 1970,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 2.14 to Registration Statement
No. 2-42393 and incorporated by reference herein)
4.15 Copy of Supplemental Trust Indenture, dated January 1, 1972,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 2.15 to Registration Statement
No. 2-49612 and incorporated by reference herein)
4.16 Copy of Supplemental Trust Indenture, dated January 1, 1974,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 2.16 to Registration Statement
No. 2-52417 and incorporated by reference herein)
4.17 Copy of Supplemental Trust Indenture, dated January 1, 1975,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 2.17 to Registration Statement
No. 2-55085 and incorporated by reference herein)
4.18 Copy of Supplemental Trust Indenture, dated January 1, 1976,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 2.18 to Registration Statement
No. 2-57730 and incorporated by reference herein)
4.19 Copy of Supplemental Trust Indenture, dated September 14, 1976,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 2.19 to Registration Statement
No. 2-59887 and incorporated by reference herein)
4.20 Copy of Supplemental Trust Indenture, dated January 1, 1977,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 2.20 to Registration Statement
No. 2-59887 and incorporated by reference herein)
4.21 Copy of Supplemental Trust Indenture, dated November 1, 1977,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.21 to Registration Statement
No. 2-70539 and incorporated by reference herein)
79
4.22 Copy of Supplemental Trust Indenture, dated December 1, 1977,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.22 to Registration Statement
No. 2-70539 and incorporated by reference herein)
4.23 Copy of Supplemental Trust Indenture, dated February 1, 1980,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.23 to Registration Statement
No. 2-70539 and incorporated by reference herein)
4.24 Copy of Supplemental Trust Indenture, dated April 15, 1982,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.24 to the Company's Form 10-K Report,
File No. 1-1097, for the year ended December 31, 1982,
and incorporated by reference herein)
4.25 Copy of Supplemental Trust Indenture, dated August 15, 1986,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.25 to the Company's Form 10-K Report,
File No. 1-1097, for the year ended December 31, 1986,
and incorporated by reference herein)
4.26 Copy of Supplemental Trust Indenture, dated March 1, 1987,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.26 to the Company's Form 10-K Report
for the year ended December 31, 1987, File No. 1-1097,
and incorporated by reference herein)
4.28 Copy of Supplemental Trust Indenture, dated November 15, 1990,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.28 to the Company's Form 10-K Report
for the year ended December 31, 1990, File No. 1-1097,
and incorporated by reference herein)
4.29 Copy of Supplemental Trust Indenture, dated December 9, 1991,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.29 to the Company's Form 10-K Report
for the year ended December 31, 1991, File No. 1-1097,
and incorporated by reference herein)
80
4.30 Copy of Supplemental Trust Indenture dated October 1, 1995,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.02 to the Company's Form 8-K Report
dated October 23, 1995, File No. 1-1097, and incorporated
by reference herein)
4.31 Copy of Supplemental 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)
4.32 Copy of Supplemental Trust Indenture No. 1 dated October 16, 1995,
being a supplemental instrument to Exhibit 4.31 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)
4.33 Supplemental Indenture No. 2, dated as of July 1, 1997, being
a supplemental instrument to Exhibit 4.31 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)
4.34 Supplemental Trust Indenture dated as of July 1, 1997, being a
supplemental instrument to Exhibit 4.01 hereto,
(Filed as Exhibit 4.02 to OG&E's Form 8-K filed on
July 17, 1997, (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)
81
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 Restricted Stock Plan of Energy Corp. (Filed as Exhibit 10.09
to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996, File No.1-12579, and incorporated
by reference herein)
10.08 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)
82
10.12 Energy Corp.'s Annual Incentive Compensation Plan. (Filed as
Exhibit 10.16 to Energy Corp.'s Form 10-K Report for
the year ended December 31, 1996, File No. 1-12579 and
incorporated by reference herein)
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995
83