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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 1-12579
OGE ENERGY CORP.
(Exact name of registrant as specified in its charter)
Oklahoma 73-1481638
(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:
Title of each class Name of each exchange on which
so registered each class is registered
------------------- ------------------------------
Common Stock New York Stock Exchange and Pacific Stock Exchange
Rights to Purchase-
Series A Preferred Stock New York Stock Exchange and Pacific 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, Common Shares outstanding were 40,385,917.
Based upon the closing price on the New York Stock Exchange on February 27,
1998, the aggregate market value of the voting stock held by nonaffiliates of
the Company was: Common Stock $2,172,426,750.
The proxy statement for the 1998 annual meeting of shareowners is
incorporated by reference into Part III of this Report.
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<TABLE>
<CAPTION>
TABLE OF CONTENTS
ITEM PAGE
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<S> <C>
PART I
Item 1. Business.......................................................... 1
The Company....................................................... 1
Electric Operations............................................... 2
General.................................................. 2
Regulation and Rates..................................... 5
Rate Structure, Load Growth and Related Matters.......... 12
Fuel Supply.............................................. 13
Enogex............................................................ 15
Origen............................................................ 18
Finance and Construction.......................................... 19
Environmental Matters............................................. 21
Employees......................................................... 22
Item 2. Properties........................................................ 23
Item 3. Legal Proceedings................................................. 24
Item 4. Submission of Matters to a Vote of Security Holders............... 27
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters...................................... 32
Item 6. Selected Financial Data........................................... 33
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................ 34
Item 8. Financial Statements and Supplementary Data....................... 47
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure................................. 75
PART III
Item 10. Directors and Executive Officers of the Registrant................ 75
Item 11. Executive Compensation............................................ 75
Item 12. Security Ownership of Certain Beneficial
Owners and Management.................................... 75
Item 13. Certain Relationships and Related Transactions.................... 75
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K...................................... 75
</TABLE>
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PART I
ITEM 1. BUSINESS.
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THE COMPANY
OGE Energy Corp. (the "Company") is a public utility holding company
which was incorporated in August 1995 in the State of Oklahoma. The Company
became the parent company of Oklahoma Gas and Electric Company ("OG&E") and its
former subsidiary, Enogex Inc. on December 31, 1996 pursuant to a mandatory
share exchange whereby each share of outstanding common stock of OG&E was
exchanged on a share-for-share basis for common stock of the Company.
Immediately following this exchange, OG&E transferred its shares of Enogex stock
to the Company and Enogex Inc. became a direct subsidiary of the Company.
The Company now serves as the parent company to OG&E, Enogex Inc.,
Origen Inc. (a newly formed company), and any other companies that may be formed
within the organization in the future. The 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 its non-utility businesses. At December
31, 1997, the Company was not engaged in any business independent of that
conducted through its subsidiaries OG&E, Enogex Inc. and Enogex Inc.'s
subsidiaries ("Enogex"), and Origen Inc. and Origen Inc.'s subsidiaries
("Origen").
The Company's principal subsidiary is OG&E and, accordingly, the
Company's financial results and condition are substantially dependent at this
time on the financial results and conditions of OG&E. OG&E is a regulated public
utility engaged in the generation, transmission and distribution of electricity
to retail and wholesale customers. OG&E was incorporated in 1902 under the laws
of the Oklahoma Territory and is the largest electric utility in the State of
Oklahoma. OG&E 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.
Enogex owns and operates approximately 3,500 miles of natural gas
transmission and gathering pipelines, has interests in five gas processing
plants, markets electricity, natural gas and natural gas products and invests in
the drilling for and production of crude oil and natural gas.
OG&E's 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 OG&E. 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.
The Company's executive offices are located at 321 North Harvey, P. O.
Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
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ELECTRIC OPERATIONS
GENERAL
OG&E 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 OG&E 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 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.
OG&E'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. OG&E's load responsibility peak demand was approximately 4,982
megawatts on July 28, 1997, resulting in a capacity margin of approximately 18.4
percent. OG&E is a member, along with neighboring utilities and other electric
suppliers, in the Southwest Power Pool ("SPP"), which requires that OG&E
maintain a capacity reserve margin of 13 percent. As reflected in the table
below and in the operating statistics on page 4, 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 increase in 1995. In 1997, kilowatt-hour sales to OG&E
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:
<TABLE>
<CAPTION>
SALES (Millions of Kwh)
Inc/ Inc/ Inc/
1997 (Dec) 1996 (Dec) 1995 (Dec)
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<S> <C> <C> <C> <C> <C> <C>
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%
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Total Sales 23,385 1.6% 23,016 1.5% 22,680 7.0%
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</TABLE>
In 1997, OG&E's Sooner Generating Station (consisting of two coal-fired
units with an aggregate capability of 1,015 Mw) and OG&E'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.
OG&E 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. Oklahoma law forbids the granting of an exclusive
franchise to a utility for providing electricity.
Besides competition from other suppliers or marketers of electricity,
OG&E competes with suppliers of other forms of energy. The degree of competition
between suppliers may vary depending on
2
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relative costs and supplies of other forms of energy. See "Electric Operations -
Regulation and Rates - Recent Regulatory Matters" for a discussion of potential
impact of competition of federal and state legislation.
3
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<TABLE>
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OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
YEAR ENDED DECEMBER 31
1997 1996 1995
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<S> <C> <C> <C>
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
</TABLE>
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REGULATION AND RATES
OG&E'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 OG&E is also regulated by the OCC and the
APSC. OG&E'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 OG&E's facilities and operations.
As part of the corporate reorganization whereby the Company became the
holding company parent of OG&E, OG&E obtained the approval of the OCC. The order
of the OCC authorizing OG&E to reorganize into a holding company structure
contains certain provisions which, among other things, ensure the OCC access to
the books and records of the Company and its affiliates relating to transactions
with OG&E; require the Company and its subsidiaries to employ accounting and
other procedures and controls to protect against subsidization of non-utility
activities by OG&E's customers; and prohibit the Company from pledging OG&E
assets or income for affiliate transactions.
For the year ended December 31, 1997, approximately 88 percent of
OG&E'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, OG&E 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 Public Utility Regulatory Policies Act of 1978 ("PURPA"), OG&E was
obligated to enter into the original contract, which was approved by the OCC in
1987, and which required OG&E to purchase peaking capacity from the plant for 10
years beginning in 1998 -- whether the capacity was needed or not. In December
1997, the Company 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 OG&E 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, OG&E 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 OG&E. 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 OG&E'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 February 11, 1997 order
also directed OG&E 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 OG&E at $41.3 million until competitively-bid gas transportation begins. In
1997, approximately $41.7 million or 12.9 percent of Enogex's revenues were
attributable to transporting gas for OG&E. Other pipelines seeking to compete
with Enogex for OG&E'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 OG&E's gas-fired generating stations.
See Note 10 of Notes to Consolidated Financial Statements.
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The Order also contained a Generation Efficiency Performance Rider
("GEP Rider"), which is designed so that when OG&E'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, OG&E is allowed to collect, through
the GEP Rider, one-third of the amount by which OG&E's average annual cost of
fuel comes in below 96.261 percent of the average of the other specified
utilities. If OG&E'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 OG&E's future operations.
The following summary of the Act does not purport to be complete and is
subject to the specific provisions of the Act, which is codified at Sections
190.2 et. seq. of Title 17 of the Oklahoma Statutes. The Act consists of eight
sections, with Section 1 designating the name of the Act. Section 2 describes
the purposes of the Act, which is generally to restructure the electric industry
to provide for more competition and, in particular, to provide for the orderly
restructuring of the electric utility industry in the State of Oklahoma in order
to allow direct access by retail consumers to the competitive market for the
generation of electricity while maintaining the safety and reliability of the
electric system in the state.
The primary goals of a restructured electric utility industry, as set
forth in Section 2 of the Act, are as follows:
l. To reduce the cost of electricity for as many consumers as
possible, helping industry to be more competitive, to create
more jobs in Oklahoma and help lower the cost of government by
reducing the amount and type of regulation now paid for by
taxpayers;
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.
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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 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
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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 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, was 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.
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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.
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.
OG&E 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, OG&E cannot
predict the impact that the restructuring will have on its operations in the
future. OG&E continues to be generally supportive of the restructuring efforts
in Oklahoma. However, the Company and OG&E believe that federal legislation
mandating retail competition in all states is appropriate to ensure that OG&E's
ability to compete for retail customers of other suppliers is commensurate with
the ability of such suppliers to compete for OG&E'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 OG&E's rates to its Oklahoma retail customers by
approximately $17 million annually and required OG&E 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 OG&E to Enogex for prior transportation and related
gas gathering services.
In 1994, OG&E 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
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restructuring costs in 1994. Pending an OCC order, OG&E 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 OG&E on
August 9, 1994, the OCC issued an order on October 26, 1994, that permitted OG&E
to amortize the December 31, 1994, regulatory asset of $48.9 million over 26
months and reduced OG&E'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 OG&E'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 with the APSC.
While OG&E 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.
NATIONAL ENERGY LEGISLATION: Federal law imposes numerous
--------------------------------
responsibilities and requirements on OG&E. The Public Utility Regulatory
Policies Act of 1978 requires electric utilities, such as OG&E, 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. OG&E 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 where
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
10
<PAGE>
("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.
OG&E is complying with these rules from the FERC. To implement the
requirements of Order 888, as amended, OG&E has filed an Open Access
Transmission Tariff ("OATT"), OG&E's original OATT, which was accepted for
filing by FERC on June 11, 1997, had an effective date of July 9, 1996. OG&E
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 OG&E has historically
integrated its load and resources. Under NTS, OG&E 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, OG&E 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 OG&E and many other utilities to submit revised
Standards of Conduct. In accordance with the FERC's directive, revised Standards
will be submitted in April 1998. Generally speaking, the FERC has required only
that OG&E 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 OG&E 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, OG&E on November 3,
1997 sought from the FERC authority to sell capacity and energy at
"market-based," negotiated rates. OG&E was granted market-based rate authority
on December 18, 1997, subject to certain restrictions on interactions with its
affiliates. For example, OG&E 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 OG&E's parent, OGE Energy Corp. and, as a
result, is an affiliate of OG&E. Like OG&E, OERI is subject to certain
restrictions on its dealings with OG&E, such as the prohibition on sales to OG&E
without separate approval from the FERC. OERI is authorized to "broker" power
purchases and sales for OG&E, 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 OG&E'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.
11
<PAGE>
The enacted Oklahoma legislation does not affect OG&E'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, continuing actions to reduce fuel costs,
improvements in customer service and efforts to improve OG&E's electric
transmission and distribution network to reduce outages, all of which enhance
OG&E's ability to deliver electricity competitively. While the Company is
supportive of competition, it believes that all electric suppliers must be
required to compete on a fair and equitable basis and the Company intends to
advocate this position vigorously.
RATE STRUCTURE, LOAD GROWTH
AND RELATED MATTERS
Two of OG&E'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 OG&E's customers. In
order to meet these goals, OG&E has reduced and restructured its rates to its
customers. At the same time, OG&E 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 OG&E 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 afternoon to non-peak hours.
OG&E 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
12
<PAGE>
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.
OG&E's 1997 marketing efforts included geothermal heat pumps,
electrotechnologies, electric food service promotion and a heat pump promotion
in the residential, commercial and industrial markets. OG&E works closely with
individual customers to provide the best information on how current technologies
can be combined with OG&E's marketing programs to maximize the customer's
benefit.
Other recent efforts to improve OG&E'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 OG&E and the Company's other subsidiaries to obtain
extensive business information on nearly a real-time basis. Also, OG&E is in the
process of implementing a new outage management system that should improve
OG&E's ability to restore service, and a new mapping system that, when
completed, will provide OG&E up-to-date information on its transmission and
distribution assets.
Electric and magnetic fields ("EMFs") surround all electric tools and
appliances, internal home wiring and external power lines such as those owned by
OG&E. 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 OG&E, 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, OG&E will continue its support of the research with regard to the possible
health effects of EMFs. OG&E is dedicated to delivering electric service in a
safe, reliable, environmentally acceptable and economical manner.
FUEL SUPPLY
During 1997, approximately 81 percent of the OG&E-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:
<TABLE>
<CAPTION>
1998 1999 2000 2001 2002
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Coal............................ 80% 80% 79% 79% 79%
Natural Gas..................... 20% 20% 21% 21% 21%
</TABLE>
The slight decline from 80 percent to 79 percent in the percentage of
coal-fired generation relative to total generation is expected to result from
increases in natural gas-fired generation, not from a reduction in Kwh of
coal-fired generation.
13
<PAGE>
The average cost of fuel used, by type, per million Btu for each of the
5 years was as follows:
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
</TABLE>
A portion of the fuel cost is included in base rates and differs for
each jurisdiction. The portion of these costs that is not included in base rates
is recovered through automatic fuel adjustment clauses. See "Electric Operations
- - Regulation and Rates - Automatic Fuel Adjustment Clauses."
COAL-FIRED UNITS: All OG&E coal units, with an aggregate capability of
----------------
2,530 megawatts, are designed to burn low sulfur western coal. OG&E purchases
coal under a mix of long- and short-term contracts. During 1997, OG&E 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, OG&E units have an
approximate emission rate of 0.63 pounds of sulfur dioxide per million Btu. In
anticipation of the more strict provisions of Phase II of The Clean Air Act
starting in the year 2000, OG&E 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, OG&E 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, OG&E 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. OG&E 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 OG&E's
ability to use coal as its primary boiler fuel.
GAS-FIRED UNITS: For calendar year 1998, OG&E expects to acquire less
----------------
than 2 percent of its gas needs from long-term gas purchase contracts. The
remainder of OG&E'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, OG&E began utilizing a natural gas storage facility which
helps lower fuel costs by allowing OG&E 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, OG&E is able to use as
much coal as possible to generate electricity and utilize the stored gas to meet
the additional demand for electricity.
14
<PAGE>
ENOGEX
The Company's wholly-owned non-utility subsidiary, Enogex Inc., is the
38th largest pipeline in the nation in terms of miles of pipeline. At January 1,
1998, Enogex Inc. had three wholly-owned subsidiaries, Enogex Products
Corporation ("Products"), OGE Resources Inc., formerly known as Enogex Services
Corporation ("Resources") and Enogex Exploration Corporation ("Exploration").
The operations of Enogex and its subsidiaries are organized into four business
units focused in the areas of natural gas gathering and transportation ("Gas
Transportation"), gas processing ("Gas Processing"), marketing of natural gas,
liquids and electricity ("Marketing") and development and production of oil and
natural gas ("Development and Production").
The operations of the Gas Transportation unit are conducted exclusively
by Enogex Inc. The Gas Processing unit consists of Products, which owns
interests in and operates natural gas processing plants and some gas gathering
lines. The Gas Marketing unit consists of Resources, which through subsidiaries
is engaged in the marketing of natural gas, natural gas liquids and electricity.
The Development and Production unit consists of Exploration, which is engaged in
investing in the development and production of oil and natural gas and the
purchase of oil and gas reserves. Enogex Inc. disposed of its 80 percent
interest in Centoma Gas Systems, Inc., effective April 1, 1997, for an amount
approximate to its net book value through the sale of its stock to the minority
interest owner.
For the year ended December 31, 1997, and before elimination of
intercompany items between OG&E and Enogex, Enogex's consolidated revenues and
net income were approximately $322.0 million and $16.2 million, respectively.
Recent Actions. As stated previously, Enogex is the exclusive
---------------
transporter of natural gas to OG&E's electric power generating stations. The OCC
in its order on February 11, 1997 directed OG&E to transition to competitive
bidding of its gas transportation no later than April 30, 2000. The order also
set annual compensation for the transportation services provided by Enogex to
OG&E at $41.3 million until competitively-bid gas transportation begins. As a
result of the foregoing, Enogex expects that revenues generated from its
transportation services for OG&E (which in 1996 and 1997 represented 19 percent
and 12.9 percent, respectively, of Enogex's consolidated revenues) will remain
at $41.3 million per year through 1999 and may decline after 1999 since Enogex
may no longer be the exclusive provider of transportation services to OG&E after
1999.
As a result, the Company's plan has been and is for Enogex to diversify
its revenue and income sources by increasing revenues from transmission services
provided to third parties, by increasing the net income of Enogex subsidiaries'
natural gas processing and development and production operations, and by
actively evaluating potential acquisitions of complementary businesses or
assets.
In May 1997, Products acquired an 80 percent interest in the NuStar
Joint Venture from Nuevo Liquids Inc. for $26 million, subject to certain
post-closing adjustments. The joint venture assets include a 66.67 percent
interest in the Benedum gas processing plant with an inlet capacity of 110
million cubic feet per day; a 100 percent interest in a second bypass plant with
a capacity of 30 million cubic feet per day; 52 miles of natural gas liquid
pipeline and over 200 miles of related gas gathering facilities located in
Upton, Crockett, Reagan and neighboring counties in the Permian Basin in West
Texas.
15
<PAGE>
In January 1998, Enogex, through a newly-formed subsidiary, Enogex
Arkansas Pipeline Corp. ("EAPC") agreed to acquire interests in two natural gas
pipelines, NOARK Pipeline System, L.P. ("NOARK") and Ozark Pipeline ("Ozark"),
for approximately $30 million and $55 million, respectively. The NOARK line is a
302 mile intra-state pipeline system that extends from near Fort Chaffee,
Arkansas to near Paragould, Arkansas. Current throughput capacity on the NOARK
line is approximately 130 million cubic feet per day. The Ozark line is a 437
mile interstate pipeline system that begins near McAlester, Oklahoma and
terminates near Searcy, Arkansas. Current throughput capacity on the Ozark line
is approximately 170 million cubic feet per day. The transactions are subject to
certain regulatory approvals, including that of the FERC.
Following regulatory approvals, EAPC will contribute Ozark to the NOARK
partnership and the two pipelines will be integrated into a single, interstate
transmission system at an estimated additional cost of $15 million and with an
estimated throughput of 330 million cubic feet per day. After the integration,
which is to be funded by EAPC, EAPC will own a 75 percent interest in the NOARK
partnership and Southwestern Energy Pipeline Co. will retain its 25 percent
interest in the partnership.
Gas Transportation. Enogex's primary business is natural gas
--------------------
transportation and it consists primarily of gathering and transporting natural
gas in Oklahoma for OG&E and on an interruptible basis, for other customers.
Enogex's system consists of approximately 3,500 miles of pipeline, which extends
from the Arkoma Basin in eastern Oklahoma to the Anadarko Basin in western
Oklahoma. Since 1960, Enogex has had a gas transmission contract with OG&E under
which Enogex transports OG&E's natural gas supply on a fee basis. Under the gas
transmission contract, OG&E agrees to tender to Enogex and Enogex agrees to
transport, on a firm, load-following basis, all of OG&E's natural gas
requirements for boiler fuel for its seven gas-fired electric generating
stations. In 1997, Enogex transported 151 Bcf of natural gas; of which
approximately 40 Bcf, or about 26 percent, was delivered to OG&E's electric
generating stations and storage facility, which resulted in approximately 63
percent of Enogex Inc.'s transportation revenues of $66.5 million for 1997.
Enogex's pipeline system also gathers and transports natural gas
destined for interstate markets through interconnections in Oklahoma with other
pipeline companies. Among others, these interconnections include Panhandle
Eastern Pipeline, Williams Natural Gas Pipeline, Natural Gas Pipeline Company of
America, Northern Natural Gas Company, NorAm Gas Transmission Company and Ozark
Gas Transmission Company.
The rates charged by Enogex for transporting natural gas on behalf of
an interstate natural gas pipeline company or a local distribution company
served by an interstate natural gas pipeline company are subject to the
jurisdiction of FERC under Section 311 of the Natural Gas Policy Act. The
statute entitles Enogex to charge a "fair and equitable" rate that is subject to
review and approval by the FERC at least once every three years. This rate
review may involve an administrative-type trial and an administrative appellate
review. In addition, Enogex has agreed to open its system to all interstate
shippers that are interested in moving natural gas through the Enogex system.
Enogex is required to conduct this transportation on a non-discriminatory basis,
although this transportation is subordinate to that performed for OG&E. This
decision does not increase appreciably the federal regulatory burden on Enogex,
but does give Enogex the opportunity to utilize any unused capacity on an
interruptible basis and thus increase its transportation revenues.
The fees charged by Enogex for transporting natural gas for OG&E and
other intrastate shippers are not subject to FERC regulation. With respect to
state regulation, the fees charged by Enogex for any intrastate transportation
service have not been subject to direct state regulation by the OCC. Even though
16
<PAGE>
the intrastate pipeline business of Enogex is not directly regulated, the OCC,
the APSC and the FERC have the authority to examine the appropriateness of any
transportation charge or other fees paid by OG&E to Enogex, which OG&E seeks to
recover from ratepayers. As stated above, OCC issued an order on February 11,
1997 directing OG&E to transition to competitive bidding of its gas
transportation no later than April 30, 2000 and set an annual compensation for
the transportation services provided by Enogex to OG&E at $41.3 million until
competitively-bid gas transportation begins.
Gas Processing. Products has been active since 1968 in the processing
---------------
of natural gas and marketing of natural gas liquids. The NuStar Joint Venture,
in which Products recently acquired an 80 percent interest, has been engaged in
the processing of natural gas since 1951. Products' and NuStar's natural gas
processing plant operations consist of the extraction and sale of natural gas
liquids. The products extracted from the gas stream include marketable ethane,
propane, butane and natural gasoline mix. The residue gas remaining after the
liquid products have been extracted consists primarily of ethane and methane. In
addition to the 66.67 percent interest in the Benedum gas processing plant owned
by NuStar Joint Venture, Products also owns the second largest natural gas
processing plant in Oklahoma, which is located near Calumet, Oklahoma and has
the capacity to process 250 million cubic feet of natural gas per day. Prior to
1997, Products shared ownership equally of the Calumet plant with a third party
and, in 1997, Products purchased all of the third party's interest in the plant.
Products also owns interests in three other natural gas processing plants in
Oklahoma, which have, in the aggregate, the capacity to process approximately 46
million cubic feet of natural gas per day.
Most of the commercial grade propane processed at Products' Oklahoma
facilities is sold on the local market. The other natural gas liquids, commonly
referred to as Group 140 are delivered to Conway, Kansas (which is one of the
nation's largest wholesale markets for gas liquids), where they are sold on the
spot market. Ethane, which is produced at all of Products' plants except
Calumet, is sold under a contract with Equistar Chemicals. This contract expired
in February 1998, but is renewable on an annual basis. Natural gas liquids are
marketed by Resources. Natural gas liquids from the NuStar Joint Venture are
sold to the Rexene Chemicals plant in Midland, Texas pursuant to a contract
expiring in February 1999.
In processing and marketing natural gas liquids, the Enogex companies
compete against virtually all other gas processors selling natural gas liquids.
The Enogex companies believe they will be able to continue to compete favorably
against such companies. With respect to factors affecting the natural gas
liquids industry generally, as the price of natural gas liquids fall without a
corresponding decrease in the price of natural gas, it may become uneconomical
to extract certain natural gas liquids. As to factors affecting the Enogex
companies specifically, the volume of natural gas processed at their plants is
dependent upon the volume of natural gas transported through the pipeline system
located "behind the plants." If the volume of natural gas transported by such
pipeline increases "behind the plants," then the volume of liquids extracted by
Products should normally increase.
Marketing. Enogex's natural gas marketing is conducted through
---------
Resources and its subsidiaries. Resources serves both producers and consumers of
natural gas by buying natural gas at the wellhead or at gathering points both on
and off the Enogex pipeline system and reselling to interstate pipelines,
end-users or downstream purchasers both within and outside Oklahoma. Resources
has placed primary emphasis on the purchase and sale of volumes of gas moving on
the Enogex pipeline system in order to enhance utilization of pipeline capacity.
During 1997, Resources sold approximately 223 billion BTUs of natural gas per
day, of which about 81 percent moved on the Enogex pipeline system.
17
<PAGE>
Resources purchases and sells gas under long-term contracts, as well as
in the "spot" market. In response to changes currently taking place in the gas
industry, Resources has been de-emphasizing its short-term markets, and an
increasing proportion of its revenues are earned pursuant to long-term sales
contracts. However, short-term or "spot" sales of natural gas will continue to
play a critical role in overall strategy because they provide an important
source of market intelligence, while serving a portfolio balancing function.
Price risk on extended term gas purchase or sales contracts entered into by
Resources is hedged on the NYMEX futures exchange as a matter of corporate
policy. Commencing in 1995, Resources began serving Products by purchasing and
marketing the natural gas liquids produced by Products. In addition, Resources
also markets natural gas developed by Exploration when volumes are sufficiently
concentrated to justify Resources marketing these volumes directly instead of
through the property operator. Other services to be provided include energy
forward price evaluations, centralized corporate risk management, and gas and
electric marketing to large end-users.
Enogex Inc. is committed to continue the activities of Resources in
order to increase the amount of natural gas transported through the pipeline and
the amount of natural gas processed by Products.
In its marketing and transportation services for third parties, Enogex
Inc. and Resources encounter competition from other natural gas transporters and
marketers and from other available alternative energy sources. The effect of
competition from alternative energy sources is dependent upon the availability
and cost of competing supply sources. Resources competes with all major
suppliers of natural gas and natural gas liquids in the geographic markets they
serve. For natural gas, those geographic markets are primarily the areas served
by pipelines with which Enogex is interconnected. Although the price of the gas
is an important factor to a buyer of natural gas from Resources, the primary
factor is the total cost (including transportation fees) that the buyer must
pay. Natural gas transported for Resources by Enogex Inc. is billed at the same
rate Enogex Inc. charges for comparable third-party transportation.
The activities of Resources and its subsidiaries were recently expanded
in early 1998 to include the marketing of electricity. As stated previously,
OERI (a subsidiary of Resources) is a power marketer that received market-based
rate authority in 1997 from the FERC. See "Electric Operations - Regulation and
Rates".
Development and Production. Exploration was formed in 1988 primarily to
--------------------------
engage in the development and production of oil and natural gas. Exploration has
focused its drilling activity in the Antrim Devonian shale trend in the state of
Michigan and also has interests in Oklahoma, Utah, Texas, Indiana, Mississippi
and Louisiana. As of December 31, 1997, Exploration had interest in 510 active
wells. Exploration's estimated proved reserves were 89,408 Mmcfe. The
standardized measure of discounted future net cash flow with related Section 29
tax credits of Exploration's proved reserves was $60.1 million at December 31,
1997.
ORIGEN
The Company's newest wholly-owned non-regulated subsidiary, Origen is
currently involved in the development of energy related products and services.
At December 31, 1997, Origen's primary business unit was Geothermal Design and
Engineering, Inc. ("GD&E"). GD&E is engaged in the design and engineering of
geothermal heating and cooling systems.
18
<PAGE>
GD&E was incorporated in April 1997 and immediately began developing
the geothermal market for HVAC/R. GD&E is a licensed consulting engineering firm
that specializes in design and project management of comprehensive geothermal
HVAC/R systems, loop field design and building controls automation. GD&E is
licensed in four states and has submitted applications to nine others. GD&E is a
nationally recognized geothermal design and engineering company with thousands
of tons of geothermal systems installed. Systems designed by GD&E carry a
system's performance guarantee. The performance guarantee states that GD&E will
warrant the system to perform within 5 percent of the design criteria in terms
of comfort, operating efficiencies (energy and demand) and maintenance
reliability. No other design-build company or engineering firm will offer this
guarantee to an owner. Developing the market has been the main goal for GD&E
during the first year. GD&E is working closely with several government agencies
and national associations such as the Dept. of Energy, Oklahoma State
University, International Ground Source Heat Pump Association, EPRI, Geothermal
Heat Pump Consortium and several others to promote the development of this
market. GD&E is also combining efforts with several utilities from across the
country to establish the geothermal market. GD&E was named a Certified Energy
Savings Performance Contractor for all civilian federal facilities. This award
came from the Department of Energy and was only given to a select few
outstanding candidates. The award enables GD&E to contract directly with federal
facilities for new or retrofitted HVAC/R systems.
Origen did not contribute to earnings in 1997, however, the first year
results were better than anticipated. The Company anticipates that Origen will
contribute to earnings in 1998.
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:
<TABLE>
<CAPTION>
(dollars in millions) 1998 1999 2000
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric utility construction
expenditures including AFUDC............ $108.0 $100.0 $100.0
Non-utility construction expenditures
and pending acquisitions................ 192.0 10.0 10.0
Maturities of long-term debt and
sinking fund requirement................ 25.0 12.5 167.0
- --------------------------------------------------------------------------------
Total................................. $325.0 $122.5 $277.0
================================================================================
</TABLE>
19
<PAGE>
The three-year estimate includes expenditures for construction of new
facilities to meet anticipated demand for service, to replace or expand existing
facilities in both its electric and non-utility businesses to fund pending
acquisitions (including any related capital expenditures), and to some extent,
for satisfying maturing debt and sinking fund obligations. Approximately $.9
million of the Company's construction expenditures budgeted for 1998 are to
comply with environmental laws and regulations. OG&E'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 "Electric Operations - Rate Structure, Load Growth and
Related Matters."
OG&E intends to meet its customers' increased electricity needs during
the foreseeable future primarily by maintaining the reliability and increasing
the utilization of existing capacity. OG&E's current resource strategy includes
the reactivation of existing plants and the addition of peaking resources. OG&E
does not anticipate the need for another base-load plant in the foreseeable
future.
The ability of the Company and its subsidiaries 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 OG&E'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, OG&E could issue more than $1.0 billion in principal amount of
additional first mortgage bonds under the earnings test contained in OG&E's
Trust Indenture (assuming adequate property additions were available). Under the
earnings test contained in OG&E's Restated Certificate of Incorporation and
assuming none of the foregoing first mortgage bonds are issued, more than $.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, OG&E'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
temporary cash requirements. OG&E has the necessary regulatory approvals to
incur up to $400 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, OG&E 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, OG&E 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. OG&E 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 PURPA (see "Electric
Operations - Regulation and Rates - National Energy Legislation"), OG&E 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
20
<PAGE>
facility. In 1987, OG&E signed a contract to purchase up to 110 megawatts of
capacity from MCPC. This obligation to purchase capacity began in 1998, but OG&E
has no obligation to purchase energy. The Company 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 OG&E charges customers and the actions of the regulatory bodies
that set those tariffs, the amount of energy used by OG&E's customers, the cost
and availability of external financing and the cost of conforming to government
regulations.
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 $43.0 million during 1998, compared to
approximately $49.1 million utilized in 1997. Approximately $.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"), OG&E has completed installation and certification of all required
continuous emissions monitors ("CEMs") at its generating stations. OG&E submits
emissions data quarterly to the Environmental Protection Agency ("EPA") as
required by the CAAA. Phase II sulfur dioxide ("SO2") emission requirements will
affect OG&E beginning in the year 2000. Based on current information, OG&E
believes it can meet the SO2 limits without additional capital expenditures. In
1997 OG&E emitted 61,475 tons of SO2.
With respect to the nitrogen oxide ("NOx") regulations of Title IV of
the CAAA, OG&E committed to meeting a 0.45 lbs/mm Btu NOx emission level in
1997. As a result, OG&E was eligible to exercise its option to extend the
effective date of the lower emission requirements from the year 2000 until 2008.
OG&E's average NOx emissions for 1997 was 0.38 lbs/mm Btu.
OG&E has submitted all of its required Title V permit applications. As
a result of the Title V Program, OG&E paid approximately $.3 million in fees in
1997.
Other potential air regulations have emerged that could impact OG&E.
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 OG&E and others, Oklahoma
was exempted from any OTAG emission reduction requirements. If reductions had
been required in Oklahoma, OG&E 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
21
<PAGE>
standard for particulate matter. If reductions are required in Muskogee, Kay and
Oklahoma counties, significant capital expenditures could be required by OG&E.
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 from the 1990 levels. If the Senate ratifies
the treaty, this reduction could have a significant impact on OG&E'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 OG&E to substantially increase gas
burning in the year 2008 and to significantly reduce its use of coal as a boiler
fuel. Since there are numerous issues which will affect how this reduction would
be implemented, if at all, the cost to the Company to comply with this reduction
cannot be established at this time, but is expected to be substantial.
The Company has and will continue to seek new pollution prevention
opportunities and to evaluate the effectiveness of its waste reduction, reuse
and recycling efforts. In 1997, the Company obtained refunds of approximately
$.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.
OG&E has made application for renewal of all of its National Pollutant
Discharge Elimination system permits. OG&E 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.
OG&E 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.
OG&E remains a party to two separate actions brought by the EPA
concerning cleanup of disposal sites for hazardous and toxic waste. See "Item 3.
Legal Proceedings".
The Company has and will continue to evaluate the impact of its
operations on the environment. As a result, contamination on Company property
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.
EMPLOYEES
The Company and its subsidiaries had 2,809 employees at December 31,
1997.
22
<PAGE>
ITEM 2. PROPERTIES.
- ------------------
OG&E 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:
<TABLE>
<CAPTION>
Unit Station
Year Capability Capability
Station & Unit Fuel Installed (Megawatts) (Megawatts)
- -------------- ---- --------- ----------- -----------
<S> <C> <C> <C> <C> <C>
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
===========
</TABLE>
23
<PAGE>
At December 31, 1997, OG&E'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. OG&E'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 OG&E's electric facilities are subject to a direct
first mortgage lien under the Trust Indenture securing OG&E's first mortgage
bonds. The Trust Indenture and related lien are expected to be discharged in
April 1998.
Enogex owns: (i) approximately 3,500 miles of natural gas pipeline
extending from the Arkoma Basin in eastern Oklahoma to the Anadarko Basin in
western Oklahoma; (ii) a natural gas processing plant near Calumet, Oklahoma,
which has the capacity to process 250 Mmcf of natural gas per day; (iii) three
other natural gas processing plants in Oklahoma, which have, in the aggregate,
the capacity to process approximately 46 Mmcf of natural gas per day; and (iv)
an 80 percent interest in the NuStar Joint Venture, whose assets include a 66.67
percent interest in the Benedum gas processing plant with an inlet capacity of
110 million cubic feet per day; a 100 percent interest in a second bypass plant
with a capacity of 30 million cubic feet per day; 52 miles of natural gas liquid
pipeline and over 200 miles of related gas gathering facilities located in
Upton, Crockett, Reagan and neighboring counties in the Permian Basin in West
Texas.
During the three years ended December 31, 1997, the Company's gross
property, plant and equipment additions approximated $463 million and gross
retirements approximated $118 million. These additions were provided by
internally generated funds. The additions during this three-year period amounted
to approximately 11.1 percent of total property, plant and equipment at December
31, 1997.
ITEM 3. LEGAL PROCEEDINGS.
- -------------------------
1. On July 8, 1994, an employee of OG&E filed a lawsuit in state court
against OG&E in connection with OG&E's VERP. The case was removed to the U.S.
District Court in Tulsa, Oklahoma. On August 23, 1994, the trial court granted
OG&E'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 OG&E. The United
States District Judge accepted the
24
<PAGE>
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 consolidated results of operations or
financial condition.
2. OG&E 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 transformers for disposal, and decontamination of mineral oil
dielectric fluids containing PCBs. During this time period, various generators
of PCBs ("Generators"), including OG&E, shipped materials containing PCBs to the
facility. Contrary to its contractual obligation with OG&E 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. OG&E 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 OG&E's ultimate liability for any additional
cleanup costs of this site will not have a material adverse effect on OG&E'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
OG&E; 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, OG&E 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 OG&E and 45 others as PRPs.
Each PRP could be held jointly and severally liable for remediation of this
site.
On February 15, 1996, OG&E elected to participate in the de minimis
settlement of EPA's Administrative Order on Consent. This would limit OG&E's
financial obligation and also would eliminate its involvement in the design and
implementation of the site remedy. A third party is currently contesting OG&E's
participation as a de minimis party. Regardless of the outcome of this issue,
OG&E
25
<PAGE>
believes that its ultimate liability for this site will not be material
primarily due to the limited volume of waste sent by OG&E 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 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 OG&E'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.
OG&E 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 OG&E, and asserting violation of the
Oklahoma Deceptive Trade Practices Act. OG&E seeks punitive and actual damages.
While OG&E cannot predict the outcome of this proceeding, OG&E believes that it
will not have a material adverse effect on OG&E's consolidated financial
position or results of operations.
5. As previously reported, the State of Oklahoma, ex rel., Teresa
Harvey (Carroll); Margaret B. Fent and Jerry R. Fent v. Oklahoma Gas and
Electric Company, et al., District Court, Oklahoma County, Case No.
CJ-97-1242-63. On February 24, 1997, the taxpayers instituted litigation against
OG&E 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 OG&E 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, OG&E'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 consolidated financial position or its results of operations.
6. As reported, the City of Enid, Oklahoma ("Enid") through its City
Council, notified OG&E of its intent to purchase OG&E's electric distribution
facilities for Enid and to terminate OG&E'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 OG&E 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, OG&E 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
OG&E the option to acquire OG&E'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) OG&E's support of the Enid Citizens' Against the
Government Takeover was improper; (e) OG&E has violated the favored nations
clause of the existing franchise; and (f) the City of Enid and OG&E have
violated the
26
<PAGE>
competitive bidding requirements found at 11 O.S.35-201, ET SEQ. Plaintiffs
seek money damages against the Defendants under 62 O.S. 372 and 373. Plaintiffs
allege that the action of the City Council in approving the proposed franchise
allowed the option to purchase OG&E's property to be transferred to OG&E for
inadequate consideration. Plaintiffs demand judgment for treble the value of the
property allegedly wrongfully transferred to OG&E. On October 28, 1997, another
resident filed a similar lawsuit against OG&E, Enid and the Garfield County
Election Board in the District Court of Garfield County, State of Oklahoma, Case
No. CJ-97-852-01. However, Case No. CJ-97-852-01 was dismissed without prejudice
in December 1997. On December 8, 1997, OG&E filed a Motion to Dismiss Case No.
CJ-97-829-01 for failure to state claims upon which relief may be granted. This
motion is currently pending. While the Company cannot predict the precise
outcome of this proceeding, the Company believes at the present time that this
lawsuit is without merit and intends to vigorously defend this case.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
- ------------------------------------------------------------
None
27
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------
The following persons were Executive Officers of the Registrant as of
March 15, 1998:
<TABLE>
<CAPTION>
Name Age Title
- --------------------- --- --------------------------------------
<S> <C> <C>
Steven E. Moore 51 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 54 Senior Vice President
Michael G. Davis 48 Vice President
James R. Hatfield 40 Vice President and Treasurer
Irma B. Elliott 59 Vice President and
Corporate Secretary
Melvin D. Bowen, Jr. 56 Vice President - Power Delivery - OG&E
Jack T. Coffman 54 Vice President - Power Supply - OG&E
Donald R. Rowlett 40 Controller Corporate Accounting - OG&E
Don L. Young 57 Controller Corporate Audits - OG&E
</TABLE>
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.
Messrs. Moore, Strecker, Davis, Hatfield and Ms. Elliott were named to
the position shown above following the corporate reorganization effective
December 31, 1996, pursuant to which the Registrant became the holding company
parent of OG&E. Such persons are also officers of OG&E.
28
<PAGE>
The business experience of each of the Executive Officers of the
Registrant for the past five years is as follows:
<TABLE>
<CAPTION>
Name Business Experience
- -------------------- ---------------------------------------------------
<S> <C> <C>
Steven E. Moore 1996-Present: Chairman of the Board,
President and Chief
Executive Officer
1996-Present: Chairman of the Board,
President and Chief
Executive Officer - OG&E
1995-1996: President and Chief
Operating Officer - OG&E
1992-1995: Vice President - Law
and Public Affairs - OG&E
Al M. Strecker 1996-Present: Senior Vice President
1994-Present: Senior Vice President -
Finance and
Administration - OG&E
1992-1994: Vice President and
Treasurer - OG&E
Michael G. Davis 1996-Present: Vice President
1994-Present: Vice President -
Marketing and Customer
Services - OG&E
1992-1994: Director - Marketing
Division - OG&E
1992: Manager - Industrial
Services - OG&E
</TABLE>
29
<PAGE>
<TABLE>
<CAPTION>
Name Business Experience
- -------------------- ---------------------------------------------------
<S> <C> <C>
James R. Hatfield 1997-Present: Vice President and Treasurer
1997-Present: Vice President and
Treasurer - OG&E
1994-1997: Treasurer - OG&E
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)
Irma B. Elliott 1996-Present: Vice President and
Corporate Secretary
1996-Present: Vice President and
Corporate Secretary -
OG&E
1992-1996: Corporate Secretary - OG&E
Melvin D. Bowen, Jr. 1994-Present: Vice President -
Power Delivery - OG&E
1992-1994: Metro Region
Superintendent - OG&E
Jack T. Coffman 1994-Present: Vice President -
Power Supply - OG&E
1992-1994: Manager - Generation
Services - OG&E
</TABLE>
30
<PAGE>
<TABLE>
<CAPTION>
Name Business Experience
- -------------------- ---------------------------------------------------
<S> <C> <C>
Donald R. Rowlett 1996-Present: Controller Corporate
Accounting - OG&E
1994-1996: Assistant Controller - OG&E
1992-1994: Senior Specialist -
Tax Accounting - OG&E
1992: Specialist - Tax Accounting -
OG&E
Don L. Young 1996-Present: Controller Corporate
Audits - OG&E
1992-1996: Controller - OG&E
</TABLE>
31
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
- ---------------------------------------------------------
STOCKHOLDER MATTERS.
- -------------------
The Company's Common Stock is listed for trading on the New York and
Pacific Stock Exchanges under the ticker symbol "OGE." Quotes may be obtained in
daily newspapers where the common stock is listed as "OGE Engy" in the New York
Stock Exchange listing table. The following table gives information with respect
to price ranges, as reported in THE WALL STREET JOURNAL as New York Stock
-----------------------
Exchange Composite Transactions, and dividends paid for the periods shown.
<TABLE>
<CAPTION>
1997 1996
--------------------------------------------------------------
DIVIDEND Dividend
PAID HIGH LOW Paid High Low
--------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
First Quarter $0.66 1/2 $43 $40 1/2 $0.66 1/2 $43 5/8 $38 7/8
Second Quarter 0.66 1/2 45 7/8 40 5/8 0.66 1/2 40 1/8 36 7/8
Third Quarter 0.66 1/2 47 1/4 44 0.66 1/2 41 7/8 38 1/8
Fourth Quarter 0.66 1/2 54 3/4 46 5/16 0.66 1/2 41 7/8 38 1/8
</TABLE>
The number of record holders of Common Stock at December 31, 1997, was
41,893. The book value of the Company's Common Stock at December 31, 1997, was
$24.39.
32
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA.
- -------------------------------
<TABLE>
<CAPTION>
HISTORICAL DATA
1997 1996 1995 1994 1993
-----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS EXCEPT
FOR PER SHARE DATA)
Operating revenues.............. $1,472,307 $1,387,435 $1,302,037 $1,355,168 $1,447,252
Operating expenses.............. 1,278,309 1,186,216 1,099,890 1,154,702 1,252,009
----------- ----------- ----------- ----------- -----------
Operating income................ 193,998 201,219 202,147 200,466 195,153
Other income and deductions..... 5,047 97 800 (2,167) (1,301)
Interest charges................ 66,495 67,984 77,691 74,514 79,575
----------- ----------- ----------- ----------- -----------
Net income...................... 132,550 133,332 125,256 123,785 114,277
Preferred dividend
requirements................... 2,285 2,302 2,316 2,317 2,317
Earnings available for
common......................... $ 130,265 $ 131,030 $ 122,940 $ 121,468 $ 111,960
=========== =========== =========== =========== ===========
Long-term debt.................. $ 841,924 $ 829,281 $ 843,862 $ 730,567 $ 838,660
Total assets.................... $2,765,865 $2,762,355 $2,754,871 $2,782,629 $2,731,424
Earnings per average common
share.......................... $ 3.23 $ 3.25 $ 3.05 $ 3.01 $ 2.78
CAPITALIZATION RATIOS
Common equity................... 52.50% 52.26% 51.19% 54.13% 50.51%
Cumulative preferred stock...... 2.63% 2.68% 2.73% 2.94% 2.78%
Long-term debt.................. 44.87% 45.06% 46.08% 42.93% 46.71%
INTEREST COVERAGES
Before federal income taxes
(including AFUDC).............. 4.11X 4.07X 3.48X 3.59X 3.32X
(excluding AFUDC).............. 4.10X 4.06X 3.46X 3.58X 3.32X
After federal income taxes
(including AFUDC).............. 2.98X 2.94X 2.59X 2.64X 2.43X
(excluding AFUDC).............. 2.97X 2.93X 2.57X 2.62X 2.42X
</TABLE>
33
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
- -------------------------------------------------------------------
AND RESULTS OF OPERATIONS.
- --------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS.
OVERVIEW
<TABLE>
<CAPTION>
Percent Change
From Prior Year
---------------
(THOUSANDS EXCEPT PER SHARE AMOUNTS) 1997 1996 1995 1997 1996
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues............................ $1,472,307 $1,387,435 $1,302,037 6.1 6.6
Earnings available for common stock........... $ 130,265 $ 131,030 $ 122,940 (0.6) 6.6
Average shares outstanding.................... 40,373 40,367 40,356 --- ---
Earnings per average common share............. $ 3.23 $ 3.25 $ 3.05 (0.6) 6.6
Dividends paid per share...................... $ 2.66 $ 2.66 $ 2.66 --- ---
==========================================================================================================
</TABLE>
The following discussion and analysis presents factors which had a
material effect on the operations and financial position of OGE Energy Corp.
(the "Company") and its subsidiaries: Oklahoma Gas and Electric Company
("OG&E"), Enogex Inc. and its subsidiaries ("Enogex") and Origen Inc. and its
subsidiaries ("Origen") 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.
The Company became the parent company of OG&E and OG&E's former
subsidiary, Enogex, on December 31, 1996, in a corporate reorganization whereby
all common stock of OG&E was exchanged on a share-for-share basis for common
stock of the Company. Prior to December 31, 1996, the Company had no operations
and the financial results discussed herein for 1995 and 1996 essentially
represent the consolidated statements of OG&E; and comparisons to prior year
results represent comparisons to the consolidated results of OG&E. Under this
corporate structure, the Company serves as the parent holding company to OG&E,
Enogex, Origen and any other companies that may be formed within the
organization in the future. This holding company structure is intended to
provide greater flexibility, allowing the Company to take advantage of
opportunities in an increasingly competitive business environment and to clearly
separate the Company's electric utility business from its non-utility
businesses. Because OG&E is the Company's principal subsidiary, the Company's
financial results and condition are substantially dependent at this time on the
financial results and condition of OG&E.
Earnings for 1997 decreased 0.6 percent from $3.25 per share in 1996 to
$3.23 per share in 1997. The decrease is primarily the result of the $45 million
annual reduction in OG&E's electric rates that became effective in March 1997,
slightly lower earnings by Enogex and a loss by Origen, the Company's new
non-regulated subsidiary, during its first year of operation. The decrease in
earnings was partially offset by the Generation Efficiency Performance Rider
("GEP Rider"), continued customer growth in the OG&E service area and lower
interest costs. The GEP Rider allows OG&E to retain part of the fuel savings
achieved through cost efficiencies and is discussed in more detail below. The
1996 increase from $3.05 per share to $3.25 per share resulted primarily from
customer growth in the OG&E service area, lower interest costs and increased
earnings by Enogex.
34
<PAGE>
The dividend payout ratio (expressed as a percentage of earnings
available for common) remained at 82 percent in 1997. The Company's long-term
goal is to achieve a dividend payout ratio of 75 percent based on long-term
earnings expectations.
The Company's 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 June 30, 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."
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.
In May 1997, Enogex acquired an 80 percent interest in the NuStar Joint
Venture for approximately $26 million. The assets of the joint venture include a
two-thirds interest in a gas processing plant, a 100 percent interest in a gas
bypass plant, approximately 50 miles of natural gas liquid pipeline and
approximately 200 miles of related gas gathering facilities in West Texas.
In January 1998, the Company, through various subsidiaries, agreed to
acquire interests in two natural gas pipelines, NOARK Pipeline Systems, L.P.,
and Ozark Pipeline. In January 1998, the Company also agreed to acquire an
existing cogeneration facility in Pryor, Oklahoma. These transactions, which are
described in detail below under "Future Capital Requirements", are contingent on
various regulatory approvals and, assuming such approvals are obtained, are
expected to enhance the Company's results in the years ahead.
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.
35
<PAGE>
RESULTS OF OPERATIONS
REVENUES
<TABLE>
<CAPTION>
Percent Change
From Prior Year
----------------
(THOUSANDS) 1997 1996 1995 1997 1996
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Sales of electricity to OG&E customers........ $ 1,168,663 $ 1,172,740 $ 1,133,283 (0.3) 3.5
Sales of electricity to other utilities....... 23,027 27,597 35,004 (16.6) (21.2)
Enogex........................................ 280,272 187,098 133,750 49.8 39.9
Origen........................................ 345 --- --- --- ---
- --------------------------------------------------------------------------------------------
Total operating revenues.................... $ 1,472,307 $ 1,387,435 $ 1,302,037 6.1 6.6
===============================================================================================================
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
===============================================================================================================
</TABLE>
In 1997, approximately 81 percent of the Company's revenues consisted
of regulated sales of electricity as a public utility, while the remaining 19
percent was provided by the non-utility operations of Enogex and Origen.
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. Enogex's primary
operations consist of transporting natural gas through its intra-state pipeline
to various customers (including OG&E), buying and selling natural gas to third
parties ("gas marketing"), selling natural gas liquids extracted by its natural
gas processing plants and investing in natural gas exploration and production
activities. Origen's primary operations consist of geothermal systems design and
engineering and the development of new products. Actions of the regulatory
commissions that set OG&E's electric rates will continue to affect the Company's
financial results. The commissions also have the authority to examine the
appropriateness of OG&E's recovery from its customers of fuel costs, which
include the transportation fees that OG&E pays Enogex for transporting natural
gas to OG&E's generating units. See "Regulation; Competition" and Note 10 of
Notes to Consolidated Financial Statements for a discussion of the impact of the
Oklahoma Corporation Commission ("OCC") February 11, 1997, rate order on these
transportation fees.
Operating revenues increased $84.9 million or 6.1 percent during 1997,
primarily due to a significant increase in revenue from Enogex. In 1997, Enogex
revenues increased $93.2 million or 49.8 percent, primarily as a result of
significant increases in the volume of natural gas sold through its gas
marketing activities ($82.4 million), and of natural gas liquids processed and
sold ($7.2 million), mainly due to the acquisition of NuStar Joint Venture in
May 1997, with a modest increase in prices for natural gas.
The increased revenues from Enogex were partially offset by decreased
revenues at OG&E. Decreased revenues at OG&E were primarily attributable 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.
36
<PAGE>
On February 11, 1997, the OCC issued an order (the "Order") that, among
other things, effectively lowered OG&E'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 OG&E's workforce reduction in
1994. The Order also directed OG&E 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 OG&E at $41.3 million until competitively-bid gas transportation
begins.
On June 18, 1997, OG&E filed documents with the OCC relating to the GEP
Rider, pursuant to the Order. The GEP Rider is designed so that when OG&E'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, OG&E is allowed to collect, through the GEP Rider, one-third of the
amount by which OG&E's average annual cost of fuel is less than 96.261 percent
of the average of the other specified utilities. If OG&E's fuel cost exceeds
103.739 percent of the stated average, OG&E 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 Federal Energy Regulatory Commission ("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.
During 1996, operating revenues increased $85.4 million or 6.6 percent,
primarily due to continued growth in kilowatt-hour sales to OG&E customers
("system sales") ($14.0 million) and a significant increase in revenue from
Enogex businesses. In 1996, Enogex revenues increased 39.9 percent. This
increase was primarily attributable to increased gas marketing sales ($26.1
million), increased petroleum product sales ($13.9 million), increased oil and
gas development and production activities ($6.9 million) and increased third
party gas transportation services ($6.5 million).
EXPENSES AND OTHER ITEMS
<TABLE>
<CAPTION>
Percent Change
From Prior Year
(DOLLARS IN THOUSANDS) 1997 1996 1995 1997 1996
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Fuel ......................................... $ 277,806 $ 279,083 $ 260,443 (0.5) 7.2
Purchased power............................... 222,464 222,070 216,598 0.2 2.5
Gas purchased for resale (Enogex)............. 201,461 117,343 87,293 71.7 34.4
Other operation and maintenance............... 311,337 307,154 290,824 1.4 5.6
Depreciation and Amortization................. 142,632 136,140 132,135 4.8 3.0
Taxes......................................... 122,609 124,426 112,597 (1.5) 10.5
- -----------------------------------------------------------------------------------------
Total operating expenses.................... $1,278,309 $1,186,216 $1,099,890 7.8 7.8
===========================================================================================================
</TABLE>
37
<PAGE>
Total operating expenses increased $92.1 million or 7.8 percent in
1997, primarily due to increases at Enogex in quantities and prices of gas
purchased for resale and other operation and maintenance costs.
Enogex's gas purchased for resale pursuant to its gas marketing
operations increased $84.1 million or 71.7 percent for 1997 compared to an
increase of $30.0 million or 34.4 percent for 1996. The 1997 increase was due to
a significant increase in sales volumes (29,236 Bbtu or 53.7 percent) and a
modest increase in purchase prices of approximately 15 percent, while the 1996
increase resulted from increased sales volumes and significantly higher purchase
prices.
OG&E'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 OG&E and its customers. In 1997, despite a slight increase in kwh
sales, fuel costs decreased $1.3 million or 0.5 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 7.2 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 expenses increased $4.2 million in 1997
primarily because of increased costs associated with expansion activities at
Enogex and Origen ($5.3 million). These increases were partially offset by the
higher costs associated with the development of the enterprise-wide software in
1996 and the completion in February 1997 of the amortization of the $48.9
million regulatory asset established in connection with OG&E's 1994 workforce
reduction. Other operation and maintenance increased $16.3 million in 1996
primarily due to the new enterprise-wide software information processing system
($6.9 million), increased pension expense ($1.7 million), and increased pipeline
operating and maintenance associated with increased gas gathering and sales by
Enogex ($3.7 million).
In 1997, taxes had a net decrease of $1.8 million or 1.5 percent
primarily due to slightly lower pre-tax income and normally occurring temporary
differences. Income taxes increased in 1996 primarily due to a decrease in tax
credits earned and higher 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
the Public Utility Regulatory Policy Act ("PURPA"), OG&E is currently purchasing
power from qualified cogeneration facilities. As discussed below, OG&E recently
took action to restructure one of its cogeneration contracts. See related
discussion of purchased power in Note 9 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 OG&E'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 OG&E pays Enogex, which OG&E 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 OG&E paid
Enogex. See Note 10 of Notes to Consolidated Financial Statements for a
discussion of the July 1996 and February 1994 orders.
38
<PAGE>
OG&E 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 OG&E remain
competitive, which in turn helps OG&E's electric customers remain competitive in
a global economy.
The increases in depreciation and amortization for 1997 and 1996
reflect higher levels of depreciable plant.
The decrease in interest expense for 1997 was attributable to OG&E
retiring $15 million of 5.125 percent First Mortgage Bonds in January 1997, the
successful refinancing of $336 million of short-term and long-term debt by OG&E
and Enogex 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 $396 million of short-term and long-term
debt in 1995.
LIQUIDITY AND CAPITAL RESOURCES
The primary capital requirements for 1997 and as estimated for 1998
through 2000 are as follows:
<TABLE>
<CAPTION>
(DOLLARS IN MILLIONS) 1997 1998 1999 2000
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Electric utility construction
expenditures including AFUDC........ $100.1 $108.0 $100.0 $100.0
Non-utility construction expenditures
and pending acquisitions............ 63.5 192.0 10.0 10.0
Maturities of long-term debt and
sinking fund requirements........... 15.0 25.0 12.5 167.0
- --------------------------------------------------------------------------------
Total........................... $178.6 $325.0 $122.5 $277.0
================================================================================
</TABLE>
The Company's primary needs for capital are related to construction of
new facilities to meet anticipated demand for utility service, to replace or
expand existing facilities in both its electric and non-utility businesses, to
expand its non-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 $163.6 million in 1997. Approximately $1.1
million of the 1997 capital requirements were to comply with environmental
regulations. This compares to capital requirements of $150 million in 1996, of
which $1.3 million was to comply with environmental regulations.
39
<PAGE>
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 and medium-term notes issued by Enogex
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 OG&E'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 outstanding short-term
borrowings of $1.0 million.
In March 1997, the Company made a $17 million capital contribution to
Enogex reflecting the Company's commitment to maintaining Enogex's strong credit
rating and financial health. In April 1997, the Company made a $5 million
initial capital contribution to Origen.
In July 1997, OG&E 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 OG&E's 8.375
percent First Mortgage Bonds due January 1, 2007; $100 million principal amount
of OG&E's 8.25 percent First Mortgage Bonds due August 15, 2016; and $75 million
principal amount of OG&E'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, OG&E 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 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.
Effective March 31, 1997, Enogex disposed of its 80 percent interest in
Centoma Gas Systems, Inc. for $3.2 million, which approximated the net book
value of Enogex's share of Centoma's assets at December 31, 1996. Enogex
purchased its interest in Centoma in 1994 for approximately $6.5 million. In
addition, during the third quarter of 1997, Enogex recognized a $2.5 million
pre-tax gain on the sale of underutilized assets.
As discussed previously, in May 1997, Enogex acquired an 80 percent
interest in the NuStar Joint Venture for approximately $26 million. Enogex
financed this acquisition with borrowings from the Company and in July 1997,
issued $30 million of medium-term notes at 6.79 percent, due July 23, 2004, to
repay the amounts borrowed from the Company.
In February 1997, OG&E filed a registration statement for up to $50
million of grantor trust preferred securities. Assuming favorable market
conditions, OG&E may issue all or part of the $50 million of grantor trust
preferred stock.
In January 1998, all outstanding shares of OG&E's cumulative preferred
stock were redeemed. In February 1998, OG&E filed a registration statement for
up to $112.5 million of senior notes. Assuming favorable market conditions, OG&E
may issue all or part of these senior notes to refinance first mortgage bonds.
40
<PAGE>
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 OG&E's electric utility customers during the balance of the
century, OG&E will concentrate on maintaining the reliability, increasing the
utilization of existing capacity and increasing demand-side management efforts.
Approximately $.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 such as general economic conditions, abnormal weather,
load growth, acquisitions of other businesses, 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, Enogex, through a newly-formed subsidiary, Enogex
Arkansas Pipeline Corp. ("EAPC") agreed to acquire interests in two natural gas
pipelines, NOARK Pipeline System, L.P. ("NOARK") and Ozark Pipeline ("Ozark"),
for approximately $30 million and $55 million, respectively. The NOARK line is a
302 mile intra-state pipeline system that extends from near Fort Chafee,
Arkansas to near Paragould, Arkansas. Current throughput capacity on the NOARK
line is approximately 130 million cubic feet per day. The Ozark line is a 437
mile interstate pipeline system that begins near McAlester, Oklahoma and
terminates near Searcy, Arkansas. Current throughput capacity on the Ozark line
is approximately 170 million cubic feet per day. The transactions are subject to
certain regulatory approvals, including that of the FERC.
Following regulatory approvals, EAPC will contribute Ozark to the NOARK
partnership and the two pipelines will be integrated into a single, interstate
transmission system at an estimated additional cost of $15 million. After the
integration, which is to be funded by EAPC, EAPC will own a 75 percent interest
in the NOARK partnership and Southwestern Energy Pipeline Co. will retain its 25
percent interest in the partnership. If the necessary regulatory approvals are
obtained, Enogex expects to fund these acquisitions through the issuance of
medium-term notes.
In January 1998, OG&E 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 PURPA,
OG&E was obligated to enter into the original contract, which was approved by
the OCC in 1987, and which required OG&E 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, the Company 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 OG&E, 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.
41
<PAGE>
FUTURE SOURCES OF FINANCING
Management expects that internally generated funds will be adequate
over the next three years to meet anticipated construction expenditures, while
maturities of long-term debt will require permanent financing, the amount and
type dependent on market conditions at the time. Short-term borrowings will
continue to be used to meet temporary cash requirements. The Company has the
necessary regulatory approvals to incur up to $400 million in short-term
borrowings at any one time. The Company has in place a line of credit for up to
$160 million which expires December 6, 2000.
The Company continues to evaluate opportunities to enhance shareowner
returns and achieve long-term financial objectives through acquisitions of
non-utility businesses. Permanent financing could be required for such
acquisitions.
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.
42
<PAGE>
CONTINGENCIES
The Company through its subsidiaries is defending various claims and
legal actions, including environmental actions, which are common to its
operations. As to environmental matters, OG&E has been designated as a
"potentially responsible party" ("PRP") with respect to two waste disposal sites
to which OG&E sent materials. Remediation of one of these sites has been
completed. OG&E'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, OG&E's ultimate liability for these sites will not be material.
The Company has contracted for low-sulfur coal to comply with the
sulfur dioxide limitations of the Clean Air Act Amendments of 1990 ("CAAA").
OG&E 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 OG&E beginning in the year 2000. OG&E
believes it can meet these sulfur dioxide limits without additional capital
expenditures. With respect to nitrogen oxide limits, OG&E is meeting the current
emission standards and has exercised its option to extend the effective date of
the further reductions from 2000 to 2008. OG&E 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 OG&E, but if these or similar
regulations were to be adopted and applied to OG&E, OG&E 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, OG&E
had submitted comprehensive site air permit applications for all of its major
source generating stations. Air permit fees for generating stations were
approximately $.3 million in 1997 and are estimated to be approximately $.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 OG&E'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
43
<PAGE>
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.
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 OG&E 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 OG&E at $41.3 million until competitively-bid gas transportation begins. In
1997, approximately $41.7 million or 12.9 percent of Enogex's revenues were
attributable to transporting gas for OG&E. Other pipelines seeking to compete
with Enogex for OG&E'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 OG&E's gas-fired generating stations.
Nevertheless, a potential outcome of the competitive bidding process is that the
revenues of Enogex derived from transporting gas for OG&E may be significantly
less after April 30, 2000.
The OCC recently adopted rules that are designed to make the gas
utility business in Oklahoma more competitive. These rules do not impact the
electric industry. Yet, if implemented, the rules are expected to offer
increased opportunities to Enogex's pipeline and related businesses.
In October 1992, the National Energy Policy Act of 1992 ("Energy Act")
was enacted. Among many other provisions, the Energy Act is designed to promote
competition in the development of
44
<PAGE>
wholesale power generation in the electric utility industry. It exempts a new
class of independent power producers from regulation under the Public Utility
Holding Company Act of 1935 and allows the FERC to order wholesale "wheeling" by
public utilities to provide utility and non-utility generators access to public
utility transmission facilities.
In April 1996, the FERC issued two final rules, Orders 888 and 889,
which may have 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. OG&E is complying with these new 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
manner similar to how OG&E has historically integrated its load and resources.
Under NTS, OG&E and participating customers share the total annual transmission
cost for their combined joint-use systems, net of related transmission revenues,
based upon each company's share of the total system load. Management expects
minimal annual expenses as a result of Orders 888 and 889.
As discussed previously, Oklahoma enacted legislation that will
restructure the electric utility industry in Oklahoma by July 2002, assuming
that all the conditions in the legislation are met. This legislation would
deregulate OG&E'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 OG&E'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 OG&E'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.
45
<PAGE>
Besides the existing contingencies described above, and those described
in Note 9 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.
46
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
- ----------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1997 1996 1995
==============================================================================================================
<S> <C> <C> <C>
OPERATING REVENUES................................................. $1,472,307 $1,387,435 $1,302,037
- --------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Fuel............................................................ 277,806 279,083 260,443
Purchased power................................................. 222,464 222,070 216,598
Gas purchased for resale........................................ 201,461 117,343 87,293
Other operation and maintenance................................. 311,337 307,154 290,824
Depreciation.................................................... 142,632 136,140 132,135
Current income taxes............................................ 57,347 81,227 77,895
Deferred income taxes, net...................................... 22,255 2,150 (3,928)
Deferred investment tax credits, net............................ (5,150) (5,150) (5,150)
Taxes other than income......................................... 48,157 46,199 43,780
- --------------------------------------------------------------------------------------------------------------
Total operating expenses..................................... 1,278,309 1,186,216 1,099,890
- --------------------------------------------------------------------------------------------------------------
OPERATING INCOME................................................... 193,998 201,219 202,147
- --------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
Interest income................................................. 3,873 2,198 4,380
Other........................................................... 1,174 (2,101) (3,580)
- --------------------------------------------------------------------------------------------------------------
Net other income and deductions.............................. 5,047 97 800
- --------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt...................................... 62,572 62,412 67,549
Allowance for borrowed funds used during construction........... (599) (709) (1,224)
Other........................................................... 4,522 6,281 11,366
- --------------------------------------------------------------------------------------------------------------
Total interest charges, net.................................. 66,495 67,984 77,691
- --------------------------------------------------------------------------------------------------------------
NET INCOME......................................................... 132,550 133,332 125,256
PREFERRED DIVIDEND REQUIREMENTS.................................... 2,285 2,302 2,316
- --------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON STOCK................................ $ 130,265 $ 131,030 $ 122,940
==============================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (thousands)...................... 40,373 40,367 40,356
EARNINGS PER AVERAGE COMMON SHARE.................................. $ 3.23 $ 3.25 $ 3.05
==============================================================================================================
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
47
<PAGE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
==============================================================================================================
<S> <C> <C> <C>
BALANCE AT BEGINNING OF PERIOD..................................... $ 449,198 $ 425,545 $ 409,960
ADD - net income................................................... 132,550 133,332 125,256
Total........................................................ 581,748 558,877 535,216
DEDUCT:
Cash dividends declared on preferred stock...................... 2,285 2,302 2,316
Cash dividends declared on common stock......................... 107,400 107,377 107,355
- --------------------------------------------------------------------------------------------------------------
Total........................................................ 109,685 109,679 109,671
- --------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD........................................... $ 472,063 $ 449,198 $ 425,545
==============================================================================================================
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
48
<PAGE>
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
==============================================================================================================
<S> <C> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service...................................................... $4,125,858 $4,005,532 $3,898,829
Construction work in progress................................... 25,799 27,968 29,705
- --------------------------------------------------------------------------------------------------------------
Total property, plant and equipment.......................... 4,151,657 4,033,500 3,928,534
Less accumulated depreciation............................. 1,797,806 1,687,423 1,585,274
- --------------------------------------------------------------------------------------------------------------
Net property, plant and equipment............................... 2,353,851 2,346,077 2,343,260
- --------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost............................ 37,898 24,802 23,775
- --------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents....................................... 4,257 2,523 5,420
Accounts receivable - customers, less reserve of $4,507,
$4,626 and $4,205, respectively.............................. 117,842 128,974 112,441
Accrued unbilled revenues....................................... 36,900 34,900 43,550
Accounts receivable - other..................................... 11,470 11,748 9,152
Fuel inventories, at LIFO cost.................................. 49,369 62,725 60,356
Materials and supplies, at average cost......................... 28,430 24,827 22,996
Prepayments and other........................................... 4,489 4,300 4,535
Accumulated deferred tax assets................................. 6,925 10,067 10,759
- --------------------------------------------------------------------------------------------------------------
Total current assets......................................... 259,682 280,064 269,209
- --------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Advance payments for gas........................................ 10,500 9,500 6,500
Income taxes recoverable through future rates................... 42,549 44,368 41,934
Other........................................................... 61,385 57,544 70,193
- --------------------------------------------------------------------------------------------------------------
Total deferred charges....................................... 114,434 111,412 118,627
- --------------------------------------------------------------------------------------------------------------
TOTAL ASSETS....................................................... $2,765,865 $2,762,355 $2,754,871
==============================================================================================================
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
49
<PAGE>
CONSOLIDATED BALANCE SHEETS (Continued)
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
==============================================================================================================
<S> <C> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statements):
Common stock and retained earnings.............................. $ 984,960 $ 961,603 $ 937,535
Cumulative preferred stock...................................... 49,266 49,379 49,939
Long-term debt.................................................. 841,924 829,281 843,862
- --------------------------------------------------------------------------------------------------------------
Total capitalization......................................... 1,876,150 1,840,263 1,831,336
- --------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Short-term debt................................................. 1,000 41,400 67,600
Accounts payable................................................ 77,733 86,856 72,089
Dividends payable............................................... 27,428 27,421 27,427
Customers' deposits............................................. 23,847 23,257 21,920
Accrued taxes................................................... 21,677 26,761 27,937
Accrued interest................................................ 20,041 19,832 19,144
Long-term debt due within one year.............................. 25,000 15,000 ---
Accumulated provision for rate refund........................... --- --- 2,650
Other........................................................... 38,518 39,188 33,388
- --------------------------------------------------------------------------------------------------------------
Total current liabilities.................................... 235,244 279,715 272,155
- --------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation.......................... 62,023 61,335 67,350
Accumulated deferred income taxes............................... 503,952 488,016 485,078
Accumulated deferred investment tax credits..................... 72,878 78,028 83,178
Other........................................................... 15,618 14,998 15,774
- --------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities................. 654,471 642,377 651,380
- --------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 9, 10 and 12)
- --------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES............................... $2,765,865 $2,762,355 $2,754,871
==============================================================================================================
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
50
<PAGE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
===============================================================================================================
<S> <C> <C> <C>
COMMON STOCK AND RETAINED EARNINGS:
Common stock, par value $0.01, $0.01 and $2.50 per share,
respectively, authorized 125,000,000, 125,000,000, and
100,000,000 shares, respectively; and outstanding 40,385,917,
46,470,616, and 46,470,616 shares, respectively................. $ 404 $ 465 $ 116,177
Premium on capital stock........................................... 512,493 724,256 608,273
Retained earnings.................................................. 472,063 449,198 425,545
Treasury stock, zero, 6,091,871, and 6,097,357 shares,
respectively.................................................... --- (212,316) (212,460)
- -----------------------------------------------------------------------------------------------------------------
Total common stock and retained earnings..................... 984,960 961,603 937,535
- -----------------------------------------------------------------------------------------------------------------
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)
Enogex Inc. notes (Note 5)......................................... 150,000 120,000 120,000
- -----------------------------------------------------------------------------------------------------------------
Total long-term debt......................................... 866,924 844,281 843,862
Less long-term debt due within one year................... 25,000 15,000 ---
- -----------------------------------------------------------------------------------------------------------------
Total long-term debt (excluding long-term
debt due within one year)................................. 841,924 829,281 843,862
- -------------------------------------------------------------------------- --------------------------------------
Total Capitalization.................................................. $1,876,150 $1,840,263 $1,831,336
=================================================================================================================
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
51
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
==============================================================================================================
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income....................................................... $ 132,550 $ 133,332 $ 125,256
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation................................................... 142,632 136,140 132,135
Deferred income taxes and investment tax credits, net.......... 17,105 (3,000) (9,078)
Gain on sale of assets......................................... (2,511) --- ---
Provision for rate refund...................................... --- 1,804 3,112
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers............................ 11,132 (16,533) (6,462)
Accrued unbilled revenues.................................. (2,000) 8,650 (6,750)
Fuel, materials and supplies inventories................... 9,753 (4,200) (6,457)
Accumulated deferred tax assets............................ 3,142 692 1,318
Other current assets....................................... 89 (2,361) 38,051
Accounts payable........................................... (9,123) 13,401 5,887
Accrued taxes.............................................. (5,084) (1,176) 2,784
Accrued interest........................................... 209 688 (4,729)
Accumulated provision for rate refund...................... --- (2,650) (320)
Other current liabilities.................................. (73) 7,131 (6,905)
Other operating activities..................................... (2,503) 22,753 13,667
- --------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities................ 295,318 294,671 281,509
- --------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures........................................... (163,571) (161,129) (141,439)
Other investing activities..................................... 4,900 --- ---
- --------------------------------------------------------------------------------------------------------------
Net cash used in investing activities...................... (158,671) (161,129) (141,439)
- --------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt................................... (321,000) --- (331,650)
Proceeds from long-term debt................................... 336,000 --- 419,400
Short-term debt, net........................................... (40,400) (26,200) (115,150)
Redemption of preferred stock.................................. (113) (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........................ (107,400) (107,377) (107,355)
- --------------------------------------------------------------------------------------------------------------
Net cash used in financing activities...................... (134,913) (136,439) (137,105)
- --------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS...................................................... 1,734 (2,897) 2,965
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD........................................................... 2,523 5,420 2,455
CASH AND CASH EQUIVALENTS AT END OF PERIOD......................... $ 4,257 $ 2,523 $ 5,420
==============================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Cash Paid During the Period for:
Interest (net of amount capitalized)....................... $ 64,081 $ 64,882 $ 76,860
Income taxes .............................................. $ 64,705 $ 82,970 $ 77,752
- --------------------------------------------------------------------------------------------------------------
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
52
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
REORGANIZATION AND PRINCIPALS OF CONSOLIDATION
OGE Energy Corp. (the "Company") became the parent company of Oklahoma
Gas and Electric Company ("OG&E") and OG&E's former subsidiary, Enogex Inc.
("Enogex") on December 31, 1996. On that date, all outstanding OG&E common stock
was exchanged on a share-for-share basis for common stock of OGE Energy Corp.
and the common stock of Enogex was distributed to the Company. In 1997, the
Company also became the parent company of Origen Inc. and its subsidiaries
("Origen"), the newly formed non-regulated businesses. The financial information
presented through December 31, 1996, represents the consolidated results of
OG&E. All significant intercompany transactions have been eliminated in
consolidation.
ACCOUNTING RECORDS
The accounting records of OG&E 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, OG&E, 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, the regulatory assets and regulatory liabilities are being reflected
in rates charged to customers over periods ranging from one to 20 years.
The components of deferred charges - other, and regulatory assets and
liabilities on the Consolidated Balance Sheets included the following, as of
December 31:
DEFERRED CHARGES - OTHER
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996 1995
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Workforce reduction (regulatory asset)................... $ --- $ 3,759 $ 26,331
Unamortized debt expense................................. 6,776 10,291 10,919
Enogex gas sales contracts............................... 13,925 14,949 11,294
Unamortized loss on reacquired debt (regulatory asset)... 28,660 10,253 11,197
Insurance claims - property damage....................... --- 6,231 ---
Miscellaneous............................................ 12,024 12,061 10,452
- ----------------------------------------------------------------------------------------------
Total........................................... $ 61,385 $ 57,544 $ 70,193
- ----------------------------------------------------------------------------------------------
</TABLE>
53
<PAGE>
<TABLE>
<CAPTION>
REGULATORY ASSETS AND LIABILITIES
(DOLLARS IN THOUSANDS) 1997 1996 1995
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Regulatory Assets:
Income taxes recoverable from customers................ $115,989 $127,819 $139,594
Unamortized loss on reacquired debt.................... 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
- ----------------------------------------------------------------------------------------------
</TABLE>
Management continuously monitors the future recoverability of
regulatory assets. When, in management's judgment, future recovery becomes
impaired, the amount of the regulatory asset is reduced or written-off, as
appropriate.
If the Company were required to discontinue the application of SFAS No.
71 for some or all of its operations, it 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 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.
54
<PAGE>
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 other operation and 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.
Enogex's gas pipeline, gathering systems, compressors and gas
processing plants are depreciated on a straight-line method over periods ranging
from 10 to 48 years.
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.
55
<PAGE>
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
OG&E has a heat pump loan program, whereby, qualifying customers may
obtain a loan from OG&E to purchase a heat pump. Customer loans are available
from a minimum of $1,500 to a maximum of $13,000 with a term of 6 months to 72
months. The finance rate is based upon short-term loan rates and is reviewed and
updated periodically. The interest rates were 8.25 percent, 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
OG&E 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 OG&E's electric customers
through automatic fuel adjustment clauses, which are subject to periodic review
by the OCC, the APSC and the FERC.
FUEL INVENTORIES
Fuel inventories for the generation of electricity consist of coal, oil
and natural gas. These inventories are accounted for under the last-in,
first-out ("LIFO") cost method. The estimated replacement cost of fuel
inventories was lower than the stated LIFO cost by approximately $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 $13.2 million, $11.4 million and $10.1
million at December 31, 1997, 1996 and 1995, respectively, and is classified as
other current liabilities in the accompanying Consolidated Balance Sheets.
56
<PAGE>
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 OG&E has been designated as one of several potentially responsible
parties, the amount accrued represents OG&E's estimated share of the cost.
RECLASSIFICATIONS
Certain amounts have been reclassified on the consolidated financial
statements to conform with the 1997 presentation.
57
<PAGE>
2. INCOME TAXES
The items comprising tax expense are as follows:
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Provision For Current Income Taxes:
Federal....................................................... $ 47,676 $ 72,633 $ 65,173
State......................................................... 9,671 8,594 12,722
- -----------------------------------------------------------------------------------------------------
Total Provision For Current Income Taxes.................... 57,347 81,227 77,895
- -----------------------------------------------------------------------------------------------------
Provisions (Benefit) For Deferred Income Taxes, net:
Federal
Depreciation................................................ 11,344 2,671 6,084
Repair allowance............................................ 794 2,100 2,101
Removal costs............................................... 774 630 700
Provision for rate refund................................... --- 928 (588)
Software implementation costs............................... 4,840 (1,727) ---
Company restructuring....................................... (494) (8,250) (8,373)
Other....................................................... 2,093 1,433 (2,678)
State......................................................... 2,904 4,365 (1,174)
- -----------------------------------------------------------------------------------------------------
Total Provision (Benefit) For Deferred Income Taxes, net... 22,255 2,150 (3,928)
- -----------------------------------------------------------------------------------------------------
Deferred Investment Tax Credits, net............................ (5,150) (5,150) (5,150)
Income Taxes Relating to Other Income and Deductions............ 2,114 (515) 1,436
- -----------------------------------------------------------------------------------------------------
Total Income Tax Expense.................................... $ 76,566 $ 77,712 $ 70,253
- -----------------------------------------------------------------------------------------------------
Pretax Income................................................... $209,116 $211,044 $195,509
=====================================================================================================
</TABLE>
The following schedule reconciles the statutory federal tax rate to the
effective income tax rate:
<TABLE>
<CAPTION>
Year ended December 31 1997 1996 1995
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Statutory federal tax rate...................................... 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit........... 3.9 4.0 3.8
Tax credits, net................................................ (4.0) (4.1) (4.8)
Other, net...................................................... 1.7 1.9 1.9
- -----------------------------------------------------------------------------------------------------
Effective income tax rate as reported......................... 36.6% 36.8% 35.9%
=====================================================================================================
</TABLE>
The Company files consolidated income tax returns. Income taxes are
allocated to each company based on its separate taxable income or loss.
58
<PAGE>
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 OG&E. The components of Accumulated Deferred Income Taxes at December
31, 1997, 1996 and 1995 are as follows:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996 1995
=====================================================================================================
<S> <C> <C> <C>
Current Deferred Tax Assets:
Accrued vacation ............................................. $ 4,221 $ 4,171 $ 3,666
Provision for rate refund..................................... --- --- 1,025
Uncollectible accounts........................................ 1,898 1,748 1,782
Capitalization of indirect costs.............................. 106 2,583 2,583
Provision for Worker's Compensation claims.................... 595 1,207 1,568
Other......................................................... 105 358 135
- -----------------------------------------------------------------------------------------------------
Accumulated deferred tax assets............................. $ 6,925 $ 10,067 $ 10,759
=====================================================================================================
Deferred Tax Liabilities:
Accelerated depreciation and other property-related
differences................................................... $489,739 $469,949 $460,332
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....................................................... 577,954 565,844 563,927
- -----------------------------------------------------------------------------------------------------
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............ (4,174) (2,301) (2,347)
Company pension plan.......................................... (16,242) (16,465) (11,612)
Other......................................................... (1,542) (1,394) 25
- -----------------------------------------------------------------------------------------------------
Total....................................................... (74,002) (77,828) (78,849)
- -----------------------------------------------------------------------------------------------------
Accumulated Deferred Income Tax Liabilities..................... $503,952 $488,016 $485,078
=====================================================================================================
</TABLE>
59
<PAGE>
3. COMMON STOCK AND RETAINED EARNINGS
There were 14,448 new shares of common stock issued pursuant to the
Restricted Stock Plan in 1997 and there were no new shares of common stock
issued during 1996 or 1995. The $211.8 million decrease in 1997 in premium on
capital stock, as presented on the Consolidated Statements of Capitalization,
represents the gains and losses associated with the issuance of common stock
pursuant to the Restricted Stock Plan, repurchased preferred stock, and the
retirement of treasury stock. The $.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 Company's common stock at the discretion of
the Board of Directors. The Company distributed 14,448, 16,024 and 18,872 shares
of common stock during 1997, 1996 and 1995, respectively. The Company also
reacquired 7,276 and 10,538 shares in 1997 and 1996, respectively. The shares
distributed in 1996 and 1995 and the shares reacquired in 1997 and 1996 were
recorded as treasury stock.
Changes in common stock were:
<TABLE>
<CAPTION>
(THOUSANDS) 1997 1996 1995
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Shares outstanding January 1.................................... 40,379 40,373 40,354
Issued/reacquired under the Restricted Stock Plan, net.......... 7 6 19
- -------------------------------------------------------------------------------------------------
Shares outstanding December 31.................................. 40,386 40,379 40,373
=================================================================================================
</TABLE>
There were 4,703,391 shares of unissued 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.
OG&E's Restated Certificate of Incorporation and its Trust Indenture,
as supplemented, relating to the First Mortgage Bonds, contain 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 the Company, as
common shareowner.
SHAREOWNERS RIGHTS PLAN
In December 1990, OG&E adopted a Shareowners Rights Plan designed to
protect shareowners' interests in the event that OG&E was ever confronted with
an unfair or inadequate acquisition proposal. In connection with the corporate
restructuring, the Company adopted a substantially identical Shareowners Rights
Plan in August 1995. Pursuant to the plan, the Company declared a dividend
distribution of one "right" for each share of Company common stock. Each right
entitles the holder to purchase from the Company one one-hundredth of a share of
new preferred stock of the Company 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 the Company's common stock. Under certain
circumstances, the holders of the rights will be entitled to purchase either
shares of common stock of the
60
<PAGE>
Company or common stock of the acquirer at a reduced percentage of market value.
The rights are scheduled to expire on December 11, 2000.
4. CUMULATIVE PREFERRED STOCK OF SUBSIDIARY
Preferred stock of OG&E is redeemable at the option of OG&E 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 OG&E's cumulative preferred
stock were redeemed. See Note 12 of Notes to Consolidated Financial Statements.
OG&E's Restated Certificate of Incorporation permits the issuance of
new series of preferred stock with dividends payable other than quarterly.
5. LONG-TERM DEBT
OG&E's Trust Indenture, as supplemented, relating to the First Mortgage
Bonds, requires OG&E 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:
<TABLE>
<CAPTION>
Year Amount
================================================================
<S> <C>
1998............................................ $ 11,614,583
1999............................................ $ 11,354,167
2000............................................ $ 11,354,167
2001............................................ $ 11,354,167
2002............................................ $ 10,520,833
================================================================
</TABLE>
As in prior years, OG&E expects to meet these requirements by pledging
permanent additions to property.
In February 1997, OG&E filed a registration statement for up to $50
million of grantor trust preferred securities. In February 1998, OG&E filed a
registration statement for up to $112.5 million of senior notes. Assuming
favorable market conditions, OG&E may issue all or part of these securities to
refinance, at lower rates, one or more series of outstanding first mortgage
bonds.
As of December 31, 1997, Enogex long-term debt consisted of $150
million of medium-term notes at a composite rate of 6.87%. The following table
itemizes the Enogex long-term debt at December 31, 1997, 1996 and 1995:
61
<PAGE>
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Series Due August 7, 2000 -- 6.76% - 6.77%..... $ 27,000 $ 27,000 $ 27,000
Series Due August 31, 2000 -- 6.68%............ 20,000 20,000 20,000
Series Due September 1, 2000 -- 6.70%.......... 10,000 10,000 10,000
Series Due August 7, 2002 -- 7.02% - 7.05%..... 63,000 63,000 63,000
Series Due July 23, 2004 -- 6.79%.............. 30,000 --- ---
- --------------------------------------------------------------------------------
Total........................................ $150,000 $120,000 $120,000
================================================================================
</TABLE>
Maturities of long-term debt during the next five years consist of $25
million in 1998, $12.5 million in 1999, $167 million in 2000, and $103 million
in 2002.
OG&E incurred costs relating to a series of amendments to its Trust
Indenture in 1991 and refinancing of long-term debt in 1997 and 1995.
Additionally, Enogex incurred costs relating to the issuance 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 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 borrows on a short-term basis, as necessary, by the
issuance of commercial paper and by obtaining short-term bank loans. The maximum
and average amounts of short-term borrowings during 1997 were $129.3 million and
$52.3 million, respectively, at a weighted average interest rate of 5.94%. The
weighted average interest rates for 1996 and 1995 were 5.63% and 6.39%,
respectively. The Company 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. Short-term debt in the amount of $1.0
million was 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
62
<PAGE>
January 1, 1995. The components of the severance and VERP costs and the amount
deferred are as follows:
<TABLE>
<CAPTION>
SFAS SFAS
(DOLLARS IN THOUSANDS) No. 88 No. 106 Severance Total
======================================================================================================
<S> <C> <C> <C> <C>
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)
======================================================================================================
</TABLE>
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.
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 Consolidated 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.
63
<PAGE>
Net periodic pension costs for 1997, 1996 and 1995 included the
following:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996 1995
===============================================================================================
<S> <C> <C> <C>
Service costs.......................................... $ 6,529 $ 6,493 $ 4,714
Interest cost on projected benefit obligation.......... 20,803 20,909 20,392
Return on plan assets ................................. (19,142) (18,742) (15,036)
Net amortization and deferral.......................... (475) (1,263) (1,263)
Amortization of unrecognized prior service cost........ 2,939 2,939 2,634
- -----------------------------------------------------------------------------------------------
Net periodic pension costs............................. $ 10,654 $ 10,336 $ 11,441
===============================================================================================
</TABLE>
The following table sets forth the plan's funded status at December 31,
1997, 1996 and 1995:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996 1995
===============================================================================================
<S> <C> <C> <C>
Projected benefit obligation:
Vested benefits...................................... $(246,799) $(223,116) $(232,457)
Nonvested benefits................................... (22,846) (17,599) (18,263)
- -----------------------------------------------------------------------------------------------
Accumulated benefit obligation....................... (269,645) (240,715) (250,720)
Effect of future compensation levels................. (51,197) (44,258) (44,853)
- -----------------------------------------------------------------------------------------------
Projected benefit obligation........................... (320,842) (284,973) (295,573)
Plan's assets at fair value............................ 242,254 222,912 214,986
- -----------------------------------------------------------------------------------------------
Plan's assets less than projected benefit obligation... (78,588) (62,061) (80,587)
Unrecognized prior service cost........................ 40,047 42,986 40,616
Unrecognized net asset from application of SFAS No.87.. (5,053) (6,316) (7,580)
Unrecognized net loss (gain)........................... 2,295 (15,254) 9,489
- -----------------------------------------------------------------------------------------------
Accrued pension liability.............................. $ (41,299) $ (40,645) $ (38,062)
===============================================================================================
</TABLE>
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.
OG&E 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:
64
<PAGE>
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996 1995
=========================================================================================
<S> <C> <C> <C>
Service cost..................................... $ 2,144 $ 2,317 $ 1,932
Interest cost.................................... 6,365 6,824 7,242
Return on plan assets............................ (8,046) (3,263) (576)
Net amortization................................. 6,492 3,844 3,325
Net amount capitalized or deferred............... (1,293) (2,157) (2,399)
- -----------------------------------------------------------------------------------------
Net postretirement benefit expense............. $ 5,662 $ 7,565 $ 9,524
=========================================================================================
</TABLE>
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 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 $11.4 million, and the aggregate of the service and
interest cost components of net postretirement health care cost for 1997 by
approximately $1.0 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:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996 1995
=========================================================================================
<S> <C> <C> <C>
Accumulated postretirement benefit obligation:
Retirees....................................... $(76,075) $(78,856) $(88,500)
Actives eligible to retire..................... (4,720) (3,863) (2,420)
Actives not yet eligible to retire............. (13,404) (11,553) (11,869)
- -----------------------------------------------------------------------------------------
Total........................................ (94,199) (94,272) (102,789)
Plan assets at fair value........................ 45,619 39,066 23,864
- -----------------------------------------------------------------------------------------
Funded status ................................... (48,580) (55,206) (78,925)
Unrecognized transition obligation............... 41,236 43,985 46,734
Unrecognized net actuarial (gain) loss .......... (12,374) (7,937) 4,331
- -----------------------------------------------------------------------------------------
Accrued postretirement benefit obligation........ $(19,718) $(19,158) $(27,860)
=========================================================================================
</TABLE>
8. REPORT OF BUSINESS SEGMENTS
The Company's electric utility operations are conducted through OG&E,
an operating public utility engaged in the generation, transmission,
distribution, and sale of electric energy. The non-utility operations are
conducted through Enogex, (which is engaged in the gathering and transmission of
natural gas, and through its subsidiaries, is engaged in the processing of
natural gas and the marketing of natural
65
<PAGE>
gas liquids, in the buying and selling of natural gas to third parties, and in
the exploration for and production of oil and natural gas) and Origen (which is
engaged in geothermal systems design and engineering and the development of new
products).
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996 1995
=====================================================================================
<S> <C> <C> <C>
Operating Information:
Operating Revenues
Electric utility...................... $1,191,691 $1,200,337 $1,168,287
Non-utility........................... 322,305 231,427 178,082
Intersegment revenues (A)............. (41,689) (44,329) (44,332)
- -------------------------------------------------------------------------------------
Total............................... $1,472,307 $1,387,435 $1,302,037
=====================================================================================
Pre-tax Operating Income
Electric utility...................... $ 246,038 $ 247,527 $ 246,333
Non-utility........................... 22,412 31,919 24,631
- -------------------------------------------------------------------------------------
Total............................... $ 268,450 $ 279,446 $ 270,964
=====================================================================================
Net Income
Electric utility...................... $ 120,994 $ 116,869 $ 112,545
Non-utility........................... 11,556 16,463 12,711
- -------------------------------------------------------------------------------------
Total............................... $ 132,550 $ 133,332 $ 125,256
=====================================================================================
Investment Information:
Identifiable Assets as of December 31
Electric utility...................... $2,350,782 $2,388,012 $2,422,609
Non-utility........................... 415,083 374,343 332,262
- -------------------------------------------------------------------------------------
Total............................... $2,765,865 $2,762,355 $2,754,871
=====================================================================================
Other Information:
Depreciation
Electric utility...................... $ 114,760 $ 112,232 $ 110,719
Non-utility........................... 27,872 23,908 21,416
- -------------------------------------------------------------------------------------
Total............................... $ 142,632 $ 136,140 $ 132,135
=====================================================================================
Construction Expenditures
Electric utility...................... $ 100,079 $ 94,019 $ 110,276
Non-utility........................... 63,492 56,155 43,242
- -------------------------------------------------------------------------------------
Total............................... $ 163,571 $ 150,174 $ 153,518
=====================================================================================
</TABLE>
(A) Intersegment revenues are recorded at prices comparable to those of
unaffiliated customers and are affected by regulatory considerations.
66
<PAGE>
9. COMMITMENTS AND CONTINGENCIES
OG&E has entered into purchase commitments in connection with OG&E's
construction program and the purchase of necessary fuel supplies of coal and
natural gas for OG&E's generating units. The Company's construction expenditures
for 1998 are estimated at $177 million.
OG&E 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. OG&E may be required to
make additional prepayments in subsequent years. OG&E 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, OG&E held non-cancelable operating leases
covering 1,495 coal hopper railcars. Rental payments are charged to fuel expense
and recovered through OG&E's tariffs and automatic fuel adjustment clauses. The
leases have purchase and renewal options. Future minimum lease payments due
under the railcar leases, assuming the leases are renewed under the renewal
option are as follows:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
(DOLLARS IN THOUSANDS)
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
==============
</TABLE>
Rental payments under operating leases were approximately $5.4 million
in 1997, $5.4 million in 1996, and $6.5 million in 1995.
OG&E 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.
OG&E 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 OG&E to lower fuel costs by base loading coal
generation, a less costly fuel supply. During 1996, OG&E completed negotiations
and contracted with the third-party developer for gas storage service. Pursuant
to the contract, the third-party developer reimbursed OG&E for all outstanding
cash advances and interest amounting to approximately $46.8 million. OG&E 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, the Company
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.
OG&E 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
67
<PAGE>
Act of 1978 ("PURPA"). Stated generally, PURPA and the regulations thereunder
promulgated by FERC require OG&E to purchase power generated in a manufacturing
process from a qualified cogeneration facility ("QF"). The rate for such power
to be paid by OG&E was approved by the OCC. The rate generally consists of two
components: one is a rate for actual electricity purchased from the QF by OG&E;
the other is a capacity charge which OG&E must pay the QF for having the
capacity available. However, if no electrical power is made available to OG&E
for a period of time (generally three months), OG&E's obligation to pay the
capacity charge is suspended. The total cost of cogeneration payments is
recoverable in rates from customers. In January 1998, OG&E 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 12 of Notes to Consolidated Financial Statements for related
discussion.
During 1997, 1996 and 1995, OG&E 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.
Approximately $.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 $43.0 million during 1998, compared to
approximately $49.1 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.
OG&E has contracted for low-sulfur coal to comply with the sulfur
dioxide limitations of the Clean Air Act Amendments of 1990 ("CAAA"). OG&E also
has completed installation and certification of all required continuous
emissions monitors at each of its generating units. Phase II sulphur dioxide
emission requirements will affect OG&E beginning in the year 2000. OG&E believes
it can meet these sulphur dioxide limits without additional expenditures. With
respect to nitrogen oxide limits, OG&E is meeting the current emission standards
and has exercised its option to extend the effective date of the further
reductions from 2000 to 2008.
OG&E is a party to two separate actions brought by the EPA concerning
cleanup of disposal sites for hazardous waste. OG&E was not the owner or
operator of those sites, rather OG&E, 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.
OG&E's total waste disposed at the remaining site is minimal and on February 15,
1996, OG&E elected to participate in the de minimis settlement offered by EPA.
One of the other potentially responsible parties is currently contesting OG&E's
participation as a de minimis party. Regardless of the outcome of this issue,
OG&E believes its ultimate liability for this site is minimal.
68
<PAGE>
In the normal course of business, other lawsuits, claims, environmental
actions and other governmental proceedings arise against the Company and its
subsidiaries. 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.
10. RATE MATTERS AND REGULATION
On February 11, 1997, the OCC issued an order that, among other things,
effectively lowered OG&E'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 OG&E 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, OG&E
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 OG&E 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 OG&E'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 OG&E's rates to its Oklahoma retail customers by
approximately $14 million annually (based on a test year ended June 30, 1991)
and required OG&E to refund approximately $41.3 million. The $14 million annual
reduction in rates lowered OG&E'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
OG&E 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 OG&E filed a Joint Stipulation
recommending settlement of certain issues resulting from the APSC review of the
amounts that OG&E pays Enogex and recovers through its fuel clause or other
tariffs for transporting natural gas to OG&E's gas-fired generating stations. On
July 11, 1996, the APSC issued an order that, among other things, required OG&E
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 OG&E 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 OG&E'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.
69
<PAGE>
11. 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 Stock is estimated based
on quoted market prices and management's estimate of current rates available for
similar issues. The fair value of the Enogex Notes is based on management's
estimate of current rates available for similar issues with the same remaining
maturities.
Indicated below are the carrying amounts and estimated fair values of
the Company's financial instruments as of December 31:
<TABLE>
<CAPTION>
1997 1996 1995
------------------- ------------------- ---------------------
CARRYING FAIR Carrying Fair Carrying Fair
(DOLLARS IN THOUSANDS) AMOUNT VALUE Amount Value Amount Value
==================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
Cash and Cash Equivalents............. $ 4,257 $ 4,257 $ 2,523 $ 2,523 $ 5,420 $ 5,420
==================================================================================================================
Customer Deposits..................... $ 23,847 $ 23,847 $ 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
Enogex Inc. Notes..................... 150,000 152,915 120,000 120,379 120,000 124,853
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
==================================================================================================================
</TABLE>
12. SUBSEQUENT EVENTS
In January 1998, Enogex, through a newly-formed subsidiary, Enogex
Arkansas Pipeline Corp. agreed to acquire interests in two natural gas
pipelines, NOARK Pipeline System, L.P. and Ozark Pipeline, for approximately $30
million and $55 million, respectively. The transactions are subject to certain
regulatory approvals, including that of the Federal Energy Regulatory
Commission.
In January 1998, OG&E 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, OG&E
was obligated to enter into the original contract, which was approved
70
<PAGE>
by the OCC in 1987, and which required OG&E to purchase peaking capacity from
the plant for 10 years beginning in 1998 -- whether the capacity was needed or
not. In January 1998, the Company 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 OG&E will be shortened. If the transaction is approved by the
necessary regulatory agencies, OG&E estimates that it will provide savings for
its Oklahoma customers of approximately $46 million.
On January 15, 1998, all outstanding shares of OG&E'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 OG&E'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 January 21, 1998, the Company adopted a Stock Incentive Plan.
Options, stock appreciation rights, performance units and restricted stock may
be granted to officers, directors and other key employees under such plan. The
Company has authorized the issuance of up to 2,000,000 shares under the plan.
The plan is subject to shareholder approval at the 1998 annual meeting.
On February 11, 1998, OG&E filed a registration statement for up to
$112.5 million of senior notes. Assuming favorable market conditions, OG&E 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 10, on February 13, 1998, the APSC
Staff filed a motion for a show cause order to review OG&E's electric rates in
the State of Arkansas. The staff is recommending a $3.1 million annual rate
reduction.
71
<PAGE>
Report of Independent Public Accountants
- ----------------------------------------
TO THE SHAREOWNERS OF
OGE ENERGY CORP.:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of OGE Energy Corp. (an Oklahoma corporation),
formerly Oklahoma Gas & Electric Company, 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 OGE Energy Corp. and
its subsidiaries as of December 31, 1997, 1996 and 1995, and the results of
their operations and their 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
72
<PAGE>
Report of Management
- --------------------
TO OUR SHAREOWNERS:
The management of OGE Energy Corp. and its subsidiaries 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 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.
73
<PAGE>
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:
<TABLE>
<CAPTION>
Quarter ended (DOLLARS IN THOUSANDS EXCEPT Dec 31 Sep 30 Jun 30 Mar 31
PER SHARE DATA)
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues............................. 1997 $ 373,277 $ 474,587 $ 333,228 $ 291,215
1996 311,515 449,224 348,644 278,052
1995 283,898 467,510 304,113 246,516
- -----------------------------------------------------------------------------------------------------------------
Operating income............................... 1997 $ 26,680 $ 103,268 $ 48,049 $ 16,001
1996 23,227 107,152 53,623 17,217
1995 24,948 115,991 42,800 18,408
- -----------------------------------------------------------------------------------------------------------------
Net income (loss).............................. 1997 $ 12,205 $ 89,520 $ 31,085 $ (260)
1996 7,301 90,165 35,328 538
1995 4,890 96,969 24,258 (861)
- -----------------------------------------------------------------------------------------------------------------
Earnings (loss) available for common........... 1997 $ 11,634 $ 88,949 $ 30,513 $ (831)
1996 6,729 89,593 34,749 (41)
1995 4,311 96,390 23,679 (1,440)
- -----------------------------------------------------------------------------------------------------------------
Earnings (loss) per average common share....... 1997 $ 0.29 $ 2.20 $ 0.76 $ (0.02)
1996 0.17 2.22 0.86 0.00
1995 0.11 2.39 0.59 (0.04)
- -----------------------------------------------------------------------------------------------------------------
</TABLE>
74
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
- --------------------------------------------------------------------
AND FINANCIAL DISCLOSURE.
-------------------------
Not Applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION.
- --------------------------------
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
- -------------------------------------------------
OWNERS AND MANAGEMENT.
----------------------
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
- --------------------------------------------------------
Items 10, 11, 12 and 13 are omitted pursuant to General Instruction G
of Form 10-K, since the Company 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 STATEMENT SCHEDULES AND
- ----------------------------------------------------
REPORTS ON FORM 8-K.
--------------------
(A) 1. FINANCIAL STATEMENTS
- ---------------------------
The following consolidated financial statements and supplementary data
are included in Part II, Item 8 of this Report:
o Consolidated Balance Sheets at December 31, 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
75
<PAGE>
SUPPLEMENTARY DATA
------------------
o Interim Consolidated Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE
- ----------------------------------------------------- ----
Schedule II - Valuation and Qualifying Accounts 84
Report of Independent Public Accountants 85
Financial Data Schedule 97
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
- -----------
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<S> <C>
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit
3.01 to OGE Energy's Form 10-K for the year ended
December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 3.02 to OGE Energy's Form 10-K for
the year ended December 31, 1996 (File No. 1-12579) 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)
</TABLE>
76
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
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)
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)
</TABLE>
77
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
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)
</TABLE>
78
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
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 OG&E'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 OG&E'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 OG&E's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
</TABLE>
79
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
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 OG&E'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
OG&E'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
OG&E'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
OG&E'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
OG&E and Atlantic Richfield Company. (Filed as
Exhibit 5.19 to Registration Statement No. 2-59887
and incorporated by reference herein)
</TABLE>
80
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between OG&E
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 OG&E 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 OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between OG&E and Atlantic
Richfield Company. (Filed as Exhibit 10.04 to
OG&E'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 OG&E. (Filed as Exhibit 10.07 to
OGE Energy's Form 10-K 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 OGE
Energy's Form 10-K for the year ended
December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.07 Amended and Restated Restricted Stock Plan of the Company.
(Filed as Exhibit 10.09 to OGE Energy's Form 10-K
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 OG&E and Mustang Fuel Corporation.
(Attached as Appendix A to Registration Statement
No. 33-7472 and incorporated by reference herein)
10.09 OG&E's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
</TABLE>
81
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
10.10 Company's Restoration of Retirement Savings Plan, as amended.
(Filed as Exhibit 10.13 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.11 OG&E's Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.12 Company's Annual Incentive Compensation Plan. (Filed as
Exhibit 10.16 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
21.01 Subsidiaries of the Registrant.
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.
99.02 Description of Common Stock. (Filed as Exhibit 99.02
to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579)
and incorporated by reference herein)
</TABLE>
82
<PAGE>
<TABLE>
<CAPTION>
Executive Compensation Plans and Arrangements
---------------------------------------------
<S> <C>
10.05 Form of Change of Control Agreement for Officers of the
Company and OG&E. (Filed as Exhibit 10.07 to
OGE Energy's Form 10-K 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 OGE
Energy's Form 10-K for the year ended
December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.07 Amended and Restated Restricted Stock Plan of the Company.
(Filed as Exhibit 10.09 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.09 OG&E's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.10 Company's Restoration of Retirement Savings Plan, as amended.
(Filed as Exhibit 10.13 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.11 OG&E's Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.12 Company's Annual Incentive Compensation Plan. (Filed as
Exhibit 10.16 to OGE Energy's Form 10-K
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 January 6, 1998 reported the Company's
agreement to purchase the stock of Oklahoma Loan Acquisition Corporation, the
company that owns the Mid-Continent Power Company, a cogeneration plant near
Pryor, Oklahoma. OG&E also filed an application with the OCC seeking approval to
revise an existing cogeneration contract with Mid-Continent Power Company.
</TABLE>
83
<PAGE>
OGE ENERGY CORP.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
BALANCE CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS YEAR
- ----------- --------- ------------------------- ---------- --------
<S> <C> <C> <C> <C>
1997 (THOUSANDS)
Reserve for Uncollectible Accounts $4,626 $7,334 - $7,453 $4,507
1996
Reserve for Uncollectible Accounts $4,205 $7,720 - $7,299 $4,626
1995
Reserve for Uncollectible Accounts $3,719 $7,673 - $7,187 $4,205
</TABLE>
84
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To OGE Energy Corp.:
We have audited in accordance with generally accepted auditing
standards, the consolidated financial statements of OGE Energy Corp. (an
Oklahoma Corporation), formerly Oklahoma Gas & Electric Company, and its
subsidiaries 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 76,
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
85
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, the Registrant has duly caused this Report to be signed on its behalf
by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and
State of Oklahoma on the 27th day of March, 1998.
OGE ENERGY CORP.
(REGISTRANT)
/s/ Steven E. Moore
By Steven E. Moore
Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this Report has been signed below by the following persons in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
- --------------------------- ----------------------- --------------
<S> <C> <C>
/ s / Steven E. Moore
Steven E. Moore Principal Executive
Officer and Director; March 27, 1998
/ s / A. M. Strecker
A. M. Strecker Principal Financial and
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
</TABLE>
86
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<S> <C>
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit
3.01 to OGE Energy's Form 10-K for the year ended
December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 3.02 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) 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)
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)
</TABLE>
87
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
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)
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)
</TABLE>
88
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
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)
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)
</TABLE>
89
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
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 OG&E'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 OG&E'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 OG&E'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 OG&E'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
OG&E'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
OG&E's Form 8-K Report dated October 23, 1995,
File No. 1-1097, and incorporated by reference herein)
</TABLE>
90
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
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
OG&E'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
OG&E 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 OG&E
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 OG&E and
Atlantic Richfield Company.
(Filed as Exhibit 5.28 to Registration Statement
No. 2-62208 and incorporated by reference herein)
</TABLE>
91
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
10.04 Amendment dated June 27, 1990, between OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between OG&E and Atlantic
Richfield Company. (Filed as Exhibit 10.04 to
OG&E'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 OG&E. (Filed as Exhibit 10.07 to
OGE Energy's Form 10-K 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 OGE
Energy's Form 10-K for the year ended
December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.07 Amended and Restated Restricted Stock Plan of the Company.
(Filed as Exhibit 10.09 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.09 OG&E's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.10 Company's Restoration of Retirement Savings Plan, as amended.
(Filed as Exhibit 10.13 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.11 OG&E's Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.12 Company's Annual Incentive Compensation Plan. (Filed as
Exhibit 10.16 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
21.01 Subsidiaries of the Registrant.
</TABLE>
92
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
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
99.02 Description of Common Stock. (Filed as Exhibit 99.02
to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579)
and incorporated by reference herein)
</TABLE>
93
<PAGE>
EXHIBIT 21.01
OGE Energy Corp.
Subsidiaries of the Registrant
Jurisdiction of Percentage of
Name of Subsidiary Incorporation Ownership
- ------------------ --------------- -------------
Oklahoma Gas and Electric Company Oklahoma 100.0
Enogex Inc. Oklahoma 100.0
Origen, Inc. Oklahoma 100.0
The above listed subsidiaries have been consolidated in the Registrant's
financial statements.
94
<PAGE>
EXHIBIT 23.01
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated January 20, 1998 included in the OGE Energy
Corp. Form 10-K for the year ended December 31, 1997, into the previously filed
Post-Effective Amendment No. 1-B to Registration Statement No. 33-61699 and
Post-Effective Amendment No. 2-A to Registration Statement No. 33-61699.
/ s / Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
March 27, 1998
95
<PAGE>
EXHIBIT 24.01
POWER OF ATTORNEY
WHEREAS, OGE ENERGY CORP., an Oklahoma corporation (herein referred to
as the "Company"), is about to file with the Securities and Exchange Commission,
under the provisions of the Securities Exchange Act of 1934, as amended, its
annual report on Form 10-K for the year ended December 31, 1997; and
WHEREAS, each of the undersigned holds the office or offices in the
Company herein-below set opposite his or her name, respectively;
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints
STEVEN E. MOORE and A. M. STRECKER and each of them individually, his or her
attorney with full power to act for him or her and in his or her name, place and
stead, to sign his name in the capacity or capacities set forth below to said
Form 10-K and to any and all amendments thereto, and hereby ratifies and
confirms all that said attorney may or shall lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this
21st day of January 1998.
Steven E. Moore, Chairman, Principal
Executive Officer and Director / s / Steven E. Moore
-------------------------------------
Herbert H. Champlin, Director / s / Herbert H. Champlin
-------------------------------------
Luke R. Corbett, Director / s / Luke R. Corbett
------------------------------------
William E. Durrett, Director / s / William E. Durrett
------------------------------------
Martha W. Griffin, Director / s / Martha W. Griffin
------------------------------------
Hugh L. Hembree, III, Director / s / Hugh L. Hembree, III
-----------------------------------
Robert Kelley, Director / s / Robert Kelley
-----------------------------------
Bill Swisher, Director / s / Bill Swisher
-----------------------------------
Ronald H. White, M.D., Director / s / Ronald H. White, M.D.
-----------------------------------
A. M. Strecker, Principal Financial / s / A. M. Strecker
and Accounting Officer -----------------------------------
STATE OF OKLAHOMA )
) SS
COUNTY OF OKLAHOMA )
On the date indicated above, before me, Lisa Thompson, Notary Public in
and for said County and State, personally appeared the above named directors and
officers of OGE ENERGY CORP., an Oklahoma corporation, and known to me to be the
persons whose names are subscribed to the foregoing instrument, and they
severally acknowledged to me that they executed the same as their own free act
and deed.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official
seal on the 21st day of January, 1998.
/s/ Lisa L. Thompson
Lisa L. Thompson
Notary Public in and for the County
of Oklahoma, State of Oklahoma
My Commission Expires:
January 16, 2000
96
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
OGE Energy Corp. Consolidated Statements of Income, Balance Sheets, and
Statements of Cash Flow as reported on Form 10-K as of December 31, 1997 and is
qualified in its entirety by reference to such Form 10-K.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,353,851
<OTHER-PROPERTY-AND-INVEST> 37,898
<TOTAL-CURRENT-ASSETS> 259,682
<TOTAL-DEFERRED-CHARGES> 114,434
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,765,865
<COMMON> 404
<CAPITAL-SURPLUS-PAID-IN> 512,493
<RETAINED-EARNINGS> 472,063
<TOTAL-COMMON-STOCKHOLDERS-EQ> 984,960
0
49,266
<LONG-TERM-DEBT-NET> 841,924
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 1,000
<LONG-TERM-DEBT-CURRENT-PORT> 25,000
0
<CAPITAL-LEASE-OBLIGATIONS> 4,731
<LEASES-CURRENT> 2,748
<OTHER-ITEMS-CAPITAL-AND-LIAB> 856,236
<TOT-CAPITALIZATION-AND-LIAB> 2,765,865
<GROSS-OPERATING-REVENUE> 1,472,307
<INCOME-TAX-EXPENSE> 74,452
<OTHER-OPERATING-EXPENSES> 1,203,857
<TOTAL-OPERATING-EXPENSES> 1,278,309
<OPERATING-INCOME-LOSS> 193,998
<OTHER-INCOME-NET> 5,047
<INCOME-BEFORE-INTEREST-EXPEN> 199,045
<TOTAL-INTEREST-EXPENSE> 66,495
<NET-INCOME> 132,550
2,285
<EARNINGS-AVAILABLE-FOR-COMM> 130,265
<COMMON-STOCK-DIVIDENDS> 107,400
<TOTAL-INTEREST-ON-BONDS> 62,572
<CASH-FLOW-OPERATIONS> 295,318
<EPS-PRIMARY> 3.23
<EPS-DILUTED> 3.23
</TABLE>
<PAGE>
EXHIBIT 99.01
OGE ENERGY CORP. CAUTIONARY FACTORS
The Private Securities Litigation Reform Act of 1995 provides a "safe
harbor" for forward-looking statements to encourage such disclosures without the
threat of litigation providing those statements are identified as
forward-looking and are accompanied by meaningful, cautionary statements
identifying important factors that could cause the actual results to differ
materially from those projected in the statement. Forward-looking statements
have been and will be made in written documents and oral presentations of OGE
Energy Corp. (the "Company"). Such statements are based on management's beliefs
as well as assumptions made by and information currently available to
management. When used in the Company's documents or oral presentations, the
words "anticipate", "estimate", "expect", "objective" and similar expressions
are intended to identify forward-looking statements. In addition to any
assumptions and other factors referred to specifically in connection with such
forward-looking statements, factors that could cause the Company's actual
results to differ materially from those contemplated in any forward-looking
statements include, among others, the following:
o Increased competition in the utility industry, including effects of:
decreasing margins as a result of competitive pressures; industry
restructuring initiatives; transmission system operation and/or
administration initiatives; recovery of investments made under
traditional regulation; nature of competitors entering the industry;
retail wheeling; a new pricing structure; and former customers entering
the generation market;
o Changing market conditions and a variety of other factors associated
with physical energy and financial trading activities including, but
not limited to, price, basis, credit, liquidity, volatility, capacity,
transmission, currency, interest rate and warranty risks;
o Risks associated with price risk management strategies intended to
mitigate exposure to adverse movement in the prices of electricity and
natural gas on both a global and regional basis;
o Economic conditions including inflation rates and monetary
fluctuations;
o Customer business conditions including demand for their products or
services and supply of labor and materials used in creating their
products and services;
o Financial or regulatory accounting principles or policies imposed by
the Financial Accounting Standards Board, the Securities and Exchange
Commission, the Federal Energy Regulatory Commission, state public
utility commissions, state entities which regulate natural gas
transmission, gathering and processing and similar entities with
regulatory oversight.
o Availability or cost of capital such as changes in: interest rates,
market perceptions of the utility and energy-related industries, the
Company or any of its subsidiaries or security ratings;
o Factors affecting utility operations such as unusual weather
conditions; catastrophic weather-related damage; unscheduled generation
outages, unusual maintenance or repairs; unanticipated changes to
fossil fuel, or gas supply costs or availability due to higher demand,
shortages, transportation problems or other developments; environmental
incidents; or electric transmission or gas pipeline system constraints;
98
<PAGE>
o Employee workforce factors including changes in key executives,
collective bargaining agreements with union employees, or work
stoppages;
o Rate-setting policies or procedures of regulatory entities, including
environmental externalities;
o Social attitudes regarding the utility, natural gas and power
industries;
o Identification of suitable investment opportunities to enhance
shareowner returns and achieve long-term financial objectives through
business acquisitions;
o Some future investments made by the Company could take the form of
minority interests which would limit the Company's ability to control
the development or operation of an investment;
o Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims and matters, including but not
limited to those described in Note 9 of the Notes to the Consolidated
Financial Statements of the Company's Annual Report on Form 10-K for
the year ended December 31, 1997, under the caption Commitments and
Contingencies;
o Technological developments, changing markets and other factors that
result in competitive disadvantages and create the potential for
impairment of existing assets;
o Other business or investment considerations that may be disclosed from
time to time in the Company's Securities and Exchange Commission
filings or in other publicly disseminated written documents.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
99
