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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[|X|] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the fiscal year ended December 31, 1998 Commission File Number 1-12579
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. | |
As of February 26, 1999, Common Shares outstanding were 77,801,317.
Based upon the closing price on the New York Stock Exchange on February 26,
1999, the aggregate market value of the voting stock held by nonaffiliates of
the Company was: Common Stock $1,848,833,372.
The proxy statement for the 1999 annual meeting of shareowners is
incorporated by reference into Part III of this Report.
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TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
Item 1. Business..............................................................1
The Company...........................................................1
Electric Operations...................................................2
General......................................................2
Regulation and Rates.........................................5
Rate Structure, Load Growth and Related Matters.............11
Fuel Supply.................................................12
Enogex...............................................................14
Origen...............................................................18
Finance and Construction.............................................18
Environmental Matters................................................19
Employees............................................................21
Item 2. Properties...........................................................22
Item 3. Legal Proceedings....................................................23
Item 4. Submission of Matters to a Vote of Security Holders..................26
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters...........................................31
Item 6. Selected Financial Data..............................................32
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...........................33
Item 8. Financial Statements and Supplementary Data..........................49
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure......................................80
PART III
Item 10. Directors and Executive Officers of the Registrant...................80
Item 11. Executive Compensation...............................................80
Item 12. Security Ownership of Certain Beneficial
Owners and Management.........................................80
Item 13. Certain Relationships and Related Transactions.......................80
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K...........................................80
i
PART I
ITEM 1. BUSINESS.
- ----------------
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. 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. The Company is 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 5,561,180
kilowatts.
Enogex owns and operates approximately 3,329 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") has initiated proceedings to
consider the implementation of a competitive retail market in Arkansas. See
"Electric Operations - Regulation and Rates - Recent Regulatory Matters" for
further discussion of these developments.
The Company's executive offices are located at 321 North Harvey, P. O.
Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
ELECTRIC OPERATIONS
GENERAL
OG&E furnishes retail electric service in 280 communities and their
contiguous rural and suburban areas. During 1998, six other communities and two
rural electric cooperatives in Oklahoma and western Arkansas purchased
electricity from OG&E for resale. The service area, with an estimated population
of 1.8 million, covers approximately 30,000 square miles in Oklahoma and western
Arkansas; including Oklahoma City, the largest city in Oklahoma, and Ft. Smith,
Arkansas, the second largest city in that state. Of the 286 communities served,
257 are located in Oklahoma and 29 in Arkansas. Approximately 91 percent of
total electric operating revenues for the year ended December 31, 1998, were
derived from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E's system control area peak demand as reported by the system
dispatcher for the year was approximately 5,529 megawatts, and occurred on
August 27, 1998. OG&E's load responsibility peak demand was approximately 5,247
megawatts on July 30, 1998, resulting in a capacity margin of approximately 14.4
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 4.2 percent in 1998 as compared to an increase of 1.6 percent in 1997
and a 1.5 percent increase in 1996. In 1998, kilowatt-hour sales to OG&E
customers ("system sales") increased 6.6 percent due to warmer weather and
continued customer growth. Sales to other utilities and power marketers
("off-system sales") decreased in 1998; however, various factors (including the
summer heat, unit availability and storms) drove prices of this off-system
electricity to record levels, increasing operating revenues and at margins
significantly higher than had been experienced in the past. There can be no
assurance that such margins on future off-system sales will occur again. In 1997
and 1996, total kilowatt-hour sales increased due to continued customer growth.
Variations in kilowatt-hour sales for the three years are reflected in
the following table:
SALES (Millions of Kwh)
INC/ Inc/ Inc/
1998 (DEC) 1997 (Dec) 1996 (Dec)
- --------------------------------------------------------------------------------
System Sales 23,642 6.6% 22,183 3.0% 21,541 3.4%
Off-System Sales 728 (39.5%) 1,202 (18.5%) 1,475 (20.4%)
------- ------- -------
Total Sales 24,370 4.2% 23,385 1.6% 23,016 1.5%
======= ======= =======
In 1998, OG&E's Sooner Generating Station (consisting of two coal-fired
units with an aggregate capability of 1,031 Mw) and OG&E's three coal-fired
units at its Muskogee Generating Station (with an aggregate capability of 1,491
Mw) were again recognized by an industry survey as being in the top 20 lowest
cost producers of electricity for the third consecutive year.
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.
2
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 relative costs and supplies of other
forms of energy. See "Electric Operations - Regulation and Rates - Recent
Regulatory Matters" for a discussion of the potential impact on competition from
federal and state legislation.
3
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
YEAR ENDED DECEMBER 31
1998 1997 1996
------------- ------------- -------------
ELECTRIC ENERGY:
(Millions of Kwh)
Generation (exclusive of station use)................... 22,565 21,620 21,253
Purchased............................................... 3,984 3,528 3,564
------------- ------------- -------------
Total generated and purchased..................... 26,549 25,148 24,817
Company use, free service and losses.................... (2,179) (1,763) (1,801)
------------- ------------- -------------
Electric energy sold.............................. 24,370 23,385 23,016
------------- ------------- -------------
ELECTRIC ENERGY SOLD:
(Millions of Kwh)
Residential............................................. 7,959 7,179 7,143
Commercial and industrial............................... 11,912 11,586 11,161
Public street and highway lighting...................... 68 68 67
Other sales to public authorities....................... 2,352 2,202 2,096
Sales for resale........................................ 2,079 2,350 2,549
------------- ------------- -------------
Total............................................. 24,370 23,385 23,016
============= ============= =============
ELECTRIC OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential......................................... $ 537,486 $ 474,419 $ 479,574
Commercial and industrial........................... 554,589 526,673 530,213
Public street and highway lighting.................. 9,618 9,456 9,367
Other sales to public authorities................... 110,522 98,818 98,209
Sales for resale.................................... 76,198 57,695 60,141
Provision for rate refund........................... --- --- (1,221)
Miscellaneous....................................... 23,665 24,630 24,054
------------- ------------- -------------
Total Electric Revenues........................... $ 1,312,078 $ 1,191,691 $ 1,200,337
============= ============= =============
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential............................................. 598,378 593,699 588,778
Commercial and industrial............................... 86,251 85,315 84,032
Public street and highway lighting...................... 249 249 249
Other sales to public authorities....................... 11,183 10,897 10,688
Sales for resale........................................ 39 40 41
------------- ------------- -------------
Total............................................. 696,100 690,200 683,788
============= ============= =============
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (Kwh)................................ 13,342 12,133 12,178
Average annual revenue.................................. $ 900.94 $ 801.74 $ 817.62
Average price per Kwh (cents)........................... 6.75 6.61 6.71
4
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, 1998, approximately 87 percent of
OG&E's electric revenue was subject to the jurisdiction of the OCC, seven
percent to the APSC, and six percent to the FERC.
RECENT REGULATORY MATTERS: In January 1998, 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.
As part of this transaction, the Company agreed to purchase the stock of
Oklahoma Loan Acquisition Corporation ("OLAC"), the company that owned the MCPC
plant, for approximately $25 million. OG&E obtained the required regulatory
approvals from the OCC, APSC and FERC. If the transaction had been completed,
the term of the existing cogeneration contract would have been reduced by four
and one-half years, which would have reduced the amounts to be paid by OG&E, and
would have provided savings for its Oklahoma customers, of approximately $46
million as compared to the existing cogeneration contract. Following an
arbitrator's decision that the owner of the stock of OLAC could not sell the
stock of OLAC to the Company until it had offered such stock to a third party on
the same terms as it was offered to the Company, the third party purchased the
stock of OLAC and assumed ownership of the cogeneration plant in October 1998.
The effect of this transaction is that OG&E's original contract with the
cogeneration plant remains in place.
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
1998, approximately $41.6 million or 8.2 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.
5
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 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 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 1998, the GEP Rider increased revenues by
approximately $10.0 million, or approximately $0.08 per share. The current GEP
Rider is estimated to positively impact revenue by $33 million or approximately
$0.26 per share during the 12 months ending June 1999.
As previously reported, Oklahoma enacted in April 1997 the Electric
Restructuring Act of 1997 (the "Act"). In June 1998, various amendments to the
Act were enacted. If implemented as proposed, the Act will significantly affect
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
6
5. To ensure that proper standards of safety, reliability and
service are maintained in a restructured electric service
industry.
Section 3 of the Act sets forth various definitions and exempts in
large part several electric cooperatives and municipalities from the Act unless
they choose to be governed by it.
Sections 4, 5 and 6 of the Act are designed to implement the goals of
the Act and provide for various studies and task forces to assess the issues and
consequences associated with the proposed restructuring of the electric utility
industry. In Section 4, the Joint Electric Utility Task Force (the "Joint Task
Force"), which is described below, is directed to undertake a study of all
relevant issues relating to restructuring the electric utility industry in
Oklahoma including, but not limited to, the issues set forth in Section 4, and
to develop a proposed electric utility framework for Oklahoma. The OCC is
prohibited from promulgating orders relating to the restructuring without prior
authorization of the Oklahoma Legislature. Also, in developing a framework for a
restructured electric utility industry, the OCC is to adhere to fourteen
principles set forth in Section 4, including the following:
1. Appropriate rules shall be promulgated, ensuring that reliable
and safe electric service is maintained.
2. Consumers shall be allowed to choose among retail electric
energy suppliers to help ensure competitive and innovative
markets. A process should be established whereby all retail
consumers are permitted to choose their retail electric energy
suppliers by July 1, 2002.
3. When consumer choice is introduced, rates shall be unbundled
to provide clear price information on the components of
generation, transmission and distribution and any other
ancillary charges. Charges for public benefit programs
currently authorized by statute or the OCC, or both, shall be
unbundled and appear in line item format on electric bills for
all classes of consumers.
4. An entity providing distribution services shall be relieved of
its traditional obligation to provide electric supply but
shall have a continuing obligation to provide distribution
service for all consumers in its service territory.
5. The benefits associated with implementing an independent
system planning committee composed of owners of electric
distribution systems to develop and 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.
7
8. The OCC shall consider the establishment of a distribution
access fee to be assessed to all consumers in Oklahoma
connected to electric distribution systems regulated by the
OCC. This fee shall be charged to cover social costs, capital
costs, operating costs, and other appropriate costs associated
with the operation of electric distribution systems and the
provision of electric services to the retail consumer.
9. Electric utilities have traditionally had an obligation to
provide service to consumers within their established service
territories and have entered into contracts, long-term
investments and federally mandated cogeneration contracts to
meet the needs of consumers. These investments and contracts
have resulted in costs, which may not be recoverable in a
competitive restructured market and thus may be "stranded."
Procedures shall be established for identifying and
quantifying stranded investments and for allocating costs; and
mechanisms shall be proposed for recovery of an appropriate
amount of prudently incurred, unmitigable and verifiable
stranded costs and investments. As part of this process, each
entity shall be required to propose a recovery plan which
establishes its unmitigable and verifiable stranded costs and
investments and a limited recovery period designed to recover
such costs expeditiously, provided that the recovery period
and the amount of qualified transition costs shall yield a
transition charge which shall not cause the total price for
electric power, including transmission and distribution
services, for any consumer to exceed the cost per
kilowatt-hour paid on the effective date of this Act during
the transition period. The transition charge shall be applied
to all consumers including direct access consumers, and shall
not disadvantage one class of consumer or supplier over
another, nor impede competition and shall be allocated over a
period of not less than three (3) years nor more than seven
(7) years.
10. It is the intent that all transition costs shall be recovered
by virtue of the savings generated by the increased efficiency
in markets brought about by restructuring of the electric
utility industry. All classes of consumers shall share in the
transition costs.
Subject to the principles set forth in Section 4, the Joint Task Force
is directed to prepare a four-part study. As a result of the 1998 amendments,
the time frame for the delivery of the remaining parts of the Study was
accelerated to October 1, 1999. This study is to address: (i) technical issues
(including reliability, safety, unbundling of generation, transmission and
distribution services, transition issues and market power); (ii) financial
issues (including rates, charges, access fees, transition costs and stranded
costs); (iii) consumer issues (such as the obligation to serve, service
territories, consumer choices, competition and consumer safeguards); and (iv)
tax issues (including sales and use taxes, ad valorem taxes and franchise fees).
Section 5 of the Act directs the Joint Task Force to study and submit a
report on the impact of the restructuring of the electric utility industry on
state tax revenues and all other facets of the current utility tax structure on
the state and all political subdivisions of the state. The Oklahoma Tax
Commission and the OCC are precluded from issuing any rules on such matters
without the approval of the Oklahoma Legislature. Also, the Act requires the
establishment, on or before July 1, 2002, of an uniform tax policy that allows
all competitors to be taxed on a fair and equitable basis.
8
Section 6 creates the Joint Task Force, which shall consist of seven
members from the Oklahoma Senate and seven members from the Oklahoma House of
Representatives. The Joint Task Force is directed to undertake the studies set
forth in Sections 4 and 5 of the Act. The Joint Task Force is permitted to make
final recommendations to the Governor and Oklahoma Legislature. The Joint Task
Force is also empowered to retain consultants to study the creation of an
Independent System Operator, which would coordinate the physical supply of
electricity throughout Oklahoma and maintain reliability, security and stability
of the bulk power system. In addition, such study shall assess the benefits of
establishing a power exchange that would operate as a power pool allowing power
producers to compete on common ground in Oklahoma. In fulfilling its tasks, the
Joint Task Force can appoint advisory councils made up of electric utilities,
regulators, residential customers and other constituencies.
Section 7 provides generally that, with respect to electric
distribution providers, no customer switching will be allowed from the effective
date of the Act until July 1, 2002, except by mutual consent. It also provides
that any municipality that fails to become subject to the Act will be prohibited
from selling power outside its municipal limits except from lines owned on the
effective date of the Act. Furthermore, this section provides generally that
out-of-state suppliers of electricity and their affiliates who make retail sales
of electricity in Oklahoma through the use of transmission and distribution
facilities of in-state suppliers must provide equal access to their transmission
and distribution facilities outside of Oklahoma. Section 8 sets forth the
effective date of the Act as April 25, 1997.
A new bill was introduced in the State Senate in January 1999 and if
enacted would clarify ambiguities by defining key terms in the Act.
In December 1997, the APSC established four generic proceedings to
consider the implementation of a competitive retail electric market in the State
of Arkansas. During 1998, the APSC held hearings to consider competitive retail
generation, market structure, market power, taxation, recovery and mitigation of
stranded costs, service and reliability, low income assistance, independent
system operators and transition issues. The Company participated actively in
those proceedings, and in October 1998 the APSC issued its report to the
Arkansas legislature recommending competitive retail electric generation to
begin no later than January 1, 2002. Several bills calling for electric industry
restructuring were introduced after the Arkansas General Assembly began its 1999
session. While it is not expected that the General Assembly will enact
legislation in regular session, a special session of the General Assembly may be
called to continue the debate.
The OCC has adopted rules that are designed to make the gas utility
business in Oklahoma more competitive. These rules do not impact the electric
industry. Yet, if implemented, the rules are expected to offer increased
opportunities to Enogex's pipeline and related businesses.
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). OG&E has filed its cost of service study and has requested a
$1.7 million annual rate increase. A decision on this rate case is expected in
the next few months.
AUTOMATIC FUEL ADJUSTMENT CLAUSES: Variances in the actual cost of fuel
---------------------------------
used in electric generation and certain purchased power costs, as compared to
that component in cost-of-service for ratemaking, are charged to substantially
all of the Company's electric customers through automatic fuel adjustment
clauses, which are subject to periodic review by the OCC, the APSC and the FERC.
9
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
are having a significant impact on wholesale markets. These orders were
subsequently amended in orders issued in March and November 1997. Order 888 set
forth rules on non-discriminatory open access transmission service to promote
wholesale competition. Order 888, which was effective on July 9, 1996, requires
utilities and other transmission users to abide by comparable terms, conditions
and pricing in transmitting power. Order 889, which had its effective date
extended to January 3, 1997, requires public utilities to implement Standards of
Conduct and an Open Access Same Time Information System ("OASIS," formerly known
as "Real-Time Information Networks"). These rules require transmission personnel
to provide the same information about the transmission system to all
transmission customers using the OASIS. In 1997, the FERC issued clarifying
final orders in response to rehearing requests by numerous market participants
regarding Orders No. 888 and 889. During 1998, OG&E submitted filings to the
FERC to comply with these Orders, and those filings have been accepted. As OG&E
continues to prepare for restructuring at the retail level, it is expected that
additional filings will be made in order to maintain continuing compliance with
the FERC's wholesale restructuring orders.
Another impact of complying with FERC's Order 888 is a requirement for
utilities to offer a transmission tariff that includes network transmission
service ("NTS") to transmission customers. NTS allows transmission service
customers to fully integrate load and resources on an instantaneous basis, in a
manner similar to how 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
10
in either full recovery of generation-related regulatory assets (net of related
regulatory liabilities) or a non-cash, pre-tax write-off as an extraordinary
charge of up to $31 million, depending on the transition mechanisms developed by
the legislature for the recovery of all or a portion of these net regulatory
assets.
The enacted Oklahoma legislation does not affect 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 legislative debate and other factors are expected to
significantly increase competition in the electric industry. The Company has
taken steps in the past and intends to take appropriate steps in the future to
remain a competitive supplier of electricity. Past actions include a redesign
and restructuring effort in 1994, 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 is advocating
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 had implemented numerous energy efficiency
programs and tariff schedules. In 1998, these programs and schedules included:
(i) the "Surprise Free Guarantee" program, which guarantees residential
customers comfort and annual energy consumption for heating, cooling and water
heating for new homes built to energy efficient standards; (ii) a load
curtailment rate for industrial and commercial customers who can demonstrate a
load curtailment of at least 500 kilowatts (the minimum load of the curtailment
rate was raised in the February 11, 1997, OCC order); and (iii) the time-of-use
rate schedules for various commercial, industrial and residential customers
designed to shift energy usage from peak demand periods during the hot summer
afternoon to non-peak hours.
OG&E continued a Real Time Pricing ("RTP") pilot program, first
implemented in 1997, for qualifying industrial and commercial customers. This
tariff gives customers additional options on total kilowatt-hour growth and the
control of growth of peak demand. Real Time Pricing is a tariff option, 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,
11
the balancing of electricity usage and capacity in the short and long term, and
provide customers assistance in controlling their costs.
OG&E's 1998 marketing efforts included geothermal heat pumps,
electrotechnologies, electric food service promotion and a heat pump promotion
in the residential, commercial and industrial markets. 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 ready, 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 1998, approximately 68 percent of the OG&E-generated energy was
produced by coal-fired units and 32 percent by natural gas-fired units. It is
estimated that the fuel mix for 1999 through 2003, based upon expected
generation for these years, will be as follows:
1999 2000 2001 2002 2003
- --------------------------------------------------------------------------------
Coal............................ 70% 76% 76% 74% 74%
Natural Gas..................... 30% 24% 24% 26% 26%
The increase from 70 percent to 76 percent in the percentage of
coal-fired generation relative to total generation is expected to result from
improvements in coal delivery performance. The slight decline from 76 percent to
74 percent in 2002 and 2003 is expected to result from increases in natural
gas-fired generation in those years, not from a reduction in Kwh of coal-fired
generation.
12
The average cost of fuel used, by type, per million Btu for each of the
5 years was as follows:
1998 1997 1996 1995 1994
- --------------------------------------------------------------------------------
Coal............................ $0.85 $0.84 $0.83 $0.83 $0.78
Natural Gas..................... $2.83 $3.60 $3.61 $3.19 $3.58
Weighted Avg.................... $1.48 $1.39 $1.45 $1.41 $1.58
A portion of the fuel cost is included in base rates and differs for
each jurisdiction. The portion of these costs that is not included in base rates
is recovered through automatic fuel adjustment clauses. See "Electric Operations
- - Regulation and Rates - Automatic Fuel Adjustment Clauses."
COAL-FIRED UNITS: All OG&E coal units, with an aggregate capability of
----------------
2,522 megawatts, are designed to burn low sulfur western coal. OG&E purchases
coal under a mix of long- and short-term contracts. During 1998, OG&E purchased
9.9 million tons of coal from the following Wyoming suppliers: Amax Coal West,
Inc., Caballo Rojo, Inc., Kennecott Energy Company, Thunder Basin Coal Company
and Powder River Coal Company. The combination of all coals has a weighted
average sulfur content of 0.3 percent and can be burned in these units under
existing federal, state and local environmental standards (maximum of 1.2 pounds
of sulfur dioxide per million Btu) without the addition of sulfur dioxide
removal systems. Based upon the average sulfur content, 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 1998, rail congestion continued on the Union Pacific Railroad
causing coal shortage among many of the utilities in the Southwest Power Pool
and the state of Texas. As a result, 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 1998, 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. 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 1999, OG&E expects to acquire less
----------------
than 1 percent of its gas needs from long-term gas purchase contracts. The
remainder of OG&E's gas needs during 1999 will be supplied by contracts with
at-market pricing or through day-to-day purchases on the spot market.
In 1993, 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.
13
ENOGEX
The Company's wholly-owned non-utility subsidiary, Enogex, Inc. is an
Oklahoma intrastate natural gas pipeline which also conducts operations in
related business segments through subsidiary companies. These business segments
include gas processing operations ("Gas Processing") conducted by and through
Enogex Products Corporation ("Products"); development and production of oil and
natural gas ("Development and Production") conducted through Enogex Exploration
Corporation ("Exploration"); and the marketing of natural gas, natural gas
liquids, and electricity ("Marketing") conducted by OGE Energy Resources Inc.
("Resources"). In addition Enogex's wholly-owned subsidiary, Enogex Arkansas
Pipeline Company ("EAPC") owns a 75percent interest in Ozark Gas Transmission,
LLC and related companies which are involved in gas gathering and interstate gas
transmission operations in eastern Oklahoma and Arkansas, through EAPC's
75percent interest in the Noark Pipeline System LP ("NOARK").
For the year ended December 31, 1998, and before elimination of
intercompany items between OG&E and Enogex, Enogex's consolidated revenues and
net income were approximately $505.5 million and $8.5 million, respectively.
Recent Actions. 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 1997 and 1998 represented 12.9 percent and 8.2
percent, respectively, of Enogex's consolidated revenues) will remain at $41.3
million per year through 1999 and will 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. 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.
In January 1998, Enogex, through its newly formed subsidiary, EAPC
acquired a 40 percent interest in the partnership that owns NOARK, a natural gas
pipeline, for approximately $30 million and agreed to acquire Ozark Pipeline
("Ozark"), for approximately $55 million. The NOARK line is a 302-mile
intra-state pipeline system that extends from near Fort Chaffee, Arkansas to
near Paragould, Arkansas. The Ozark line is a 437-mile inter-state pipeline
system that begins near McAlester, Oklahoma and terminates near Searcy,
Arkansas. In July 1998, EAPC completed its acquisition of Ozark and contributed
Ozark to NOARK. The two pipelines were integrated into a single, interstate
transmission
14
system on November 1, 1998 at an additional cost of approximately $16 million.
EAPC, which funded the integration, owns a 75 percent interest in NOARK and
Southwestern Energy Pipeline Company owns the remaining 25 percent interest in
the partnership. Current capacity of the integrated system, operating as Ozark
Gas Transmission LLC is approximately 330 million cubic feet per day.
In July 1998 Products acquired the Belvan Corporation and the Belvan
and Todd Ranch Limited Partnerships which possess gathering, processing and
treating assets in the vicinity of Products' NuStar processing operations in
Crockett, Upton and Reagan Counties in West Texas. Acquired assets included 345
miles of gathering system, capable of gathering approximately 15 million cubic
feet per day from 250 wells, natural gas liquid recovery facilities and sulfur
recovery facilities with an effective current capacity of 15 million cubic feet
per day and an eight-mile natural gas liquids pipeline. The acquisition cost was
approximately $13.7 million.
The fees charged by Ozark and by NOARK's second interstate pipeline,
Arkansas Western Pipeline ("AWP") are subject to regulation by the FERC. AWP is
an eight-mile pipeline segment crossing the border between eastern Arkansas and
Missouri. In November 1998, the FERC approved a maximum lawful rate of $0.2455
per mmbtu for the new, integrated NOARK-Ozark system and required Ozark to file
for a rate review by not later than March 2000. While Ozark cannot predict the
ultimate outcome of this forthcoming rate review, no material change in the
current maximum lawful rate is anticipated. AWP's current maximum lawful rate is
$0.0311 per mmbtu with no current requirement for filing for rate review.
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 3,329 miles of pipeline, extending
from the Arkoma Basin in eastern Oklahoma to the Anadarko Basin in western
Oklahoma.' Since 1960, Enogex has had a gas transmission agreement with OG&E
under which Enogex transports OG&E's natural gas supply on a fee basis. Under
the gas transmission agreement, 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 1998, Enogex transported 204 billion Btu of natural gas; of which
approximately 76 billion Btu, or about 37 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 $65.8
million for 1998.
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
15
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
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.
In 1998, Resources successfully initiated wholesale electric power
purchase and reselling operations. Resources received market-based rate
authority in 1997 from the FERC. See "Electric Operations - Regulation and
Rates". With 1998 power sales of 1.4 million Mwh, Resources ranked as the
nation's 71st largest power marketer in terms of Mwh sold. Resources acts as the
Company's natural gas purchasing arm for the natural gas fuel requirements of
the OG&E power stations. Additionally, beginning in 1999, all of the Company's
surplus power sales activity will be done through Resources.
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. 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' Calumet
facility 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 expires
in February 2000, but is renewable annually on an evergreen basis. Natural gas
liquids are marketed by Resources. Natural gas liquids from the NuStar Joint
Venture are sold to the Huntsman Chemicals plant (formerly Rexene Chemicals) in
Midland, Texas pursuant to a recently renewed contract expiring in February
2002.
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
16
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. 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
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
1998, Resources sold approximately 434 billion Btu of natural gas per day, of
which about 70 percent moved on the Enogex pipeline system.
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 provided include energy forward
price evaluations and centralized corporate commodity price risk management.
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.
Development and Production. Exploration was formed in 1988 primarily to
--------------------------
engage in the development and production of oil and natural gas. Exploration
focused its early 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, 1998, Exploration had interests in
550 active wells. Exploration's estimated proved reserves were 90,877 Mmcfe. The
standardized measure of discounted future net cash flow with related Section 29
tax credits of Exploration's proved reserves was $56.9 million at December 31,
1998. During the fourth quarter of 1998, Exploration (through Resources)
initiated a program of hedging the future gas selling price on a portion of its
lease production through commodity futures contracts to cushion against
unfavorable monthly price swings.
17
ORIGEN
The Company's newest wholly-owned non-regulated subsidiary, Origen is
currently engaged in geothermal heat pump systems and the development of new
products.
Origen plans to initiate another energy related business unit in 1999.
This new unit is anticipated to be a contractor/distributor in the geothermal
industry, located in the Detroit, Michigan area. In addition, Origen plans to
discontinue operations of its business unit, Geothermal Design and Engineering,
Inc., in the first quarter of 1999. Origen did not contribute to earnings in
1998 and is not anticipated to contribute to earnings in 1999.
FINANCE AND CONSTRUCTION
The Company generally meets its cash needs through internally generated
funds, short-term borrowings and permanent financing. Cash flows from operations
remained strong in 1998 and 1997, which enabled the Company to internally
generate the required funds to satisfy construction expenditures during these
years.
Management expects that internally generated funds will be adequate
over the next three years to meet the Company's anticipated construction
expenditures. The primary capital requirements for 1999 through 2001 are
estimated as follows:
(DOLLARS IN MILLIONS) 1999 2000 2001
- --------------------------------------------------------------------------------
Electric utility construction
expenditures including AFUDC............ $101.7 $100.0 $100.0
Non-utility construction expenditures
and pending acquisitions................ 35.0 25.0 30.0
Maturities of long-term debt.............. 2.0 169.0 2.0
- --------------------------------------------------------------------------------
Total................................. $138.7 $294.0 $132.0
================================================================================
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. Approximately $0.5 million of the Company's
construction expenditures budgeted for 1999 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.
18
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 1998 was $183.5 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
were redeemed or retired with the result that no first mortgage bonds remain
outstanding. OG&E has cancelled its First Mortgage Bond Trust Indenture and
caused the related first mortgage lien on substantially all of its properties to
be discharged and released. 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., 320 megawatts annually from Applied Energy Services, Inc.,
another qualified cogeneration facility and up to 110 megawatts of capacity from
MCPC. OG&E also has agreed to purchase energy not needed by the Sparks Regional
Medical Center from its nominal seven megawatt cogeneration facility.
The Company's financial results continue to depend to a large extent
upon the tariffs 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 $41.5 million during 1999, compared to
approximately $44.6 million utilized in 1998. Approximately $0.5 million of the
Company's construction expenditures budgeted for 1999 are to comply with
environmental laws and regulations. The Company continues to evaluate its
environmental management systems to ensure compliance with existing and proposed
environmental legislation and regulations and to better position itself in a
competitive market.
As required by Title IV of the Clean Air Act Amendments of 1990
("CAAA"), 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
19
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 1998, OG&E
emitted 54,801 tons of SO2.
With respect to the nitrogen oxide ("NOx") regulations of Title IV of
the CAAA, OG&E committed to meeting a 0.45 lbs/mmbtu NOx emission level in 1997
on all coal-fired boilers. As a result, 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 1998 was 0.36 lbs/mmbtu.
OG&E has submitted all of its required Title V permit applications. As
a result of the Title V Program, OG&E paid approximately $0.3 million in fees in
1998.
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
and 14 other states were exempted from any OTAG emission reduction requirements.
However, in the fall of 1998, EPA proposed a further study of ozone transport
from these 15 states to determine if emissions reductions in these states are
warranted. If reductions had been 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.
In 1997, EPA finalized revisions to the ambient ozone and particulate
standards. Based on current ozone data, Tulsa and Oklahoma counties will likely
fail to meet the proposed standard for ozone. In addition, EPA projects that
Muskogee, Kay, Tulsa and Comanche counties in Oklahoma would fail to meet the
standard for particulate matter. If reductions are required in Muskogee, Kay and
Oklahoma counties, significant capital expenditures could be required by OG&E.
By mid-1999, EPA is expected to issue regulations concerning regional
haze. This regulation is intended to protect visibility in national parks and
wilderness areas throughout the United States. In Oklahoma, the Wichita
Mountains would be the only area covered under the regulation. Emissions of
sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to
the degradation of visibility. It is possible that controls on sources hundreds
of miles away from the affected area may be required. Both Sooner and Muskogee
Generating Stations could face significant capital expenditures if reductions
are required.
In December 1997, the United States was a signatory to the Kyoto
Protocol for the reduction of greenhouse gases that contribute to global
warming. The U.S. committed to a 7 percent reduction from the 1990 levels. If
the Senate ratifies the Kyoto Protocol, this reduction could have a significant
impact on 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 1998, the Company obtained refunds of approximately
$155,000 from its recycling efforts. This figure does not include the additional
savings gained through the reduction and/or a avoidance of disposal costs and
the reduction in material purchases due to reuse of existing materials. Similar
savings are anticipated in future years.
20
OG&E has made application for renewal of all of its National Pollutant
Discharge Elimination system permits. OG&E has received all of the permits in
final form except one which is pending regulatory action. All of the permits
issued to date offer greater operational flexibility than those in the past.
OG&E has requested that the State agency responsible for the
development of Water Quality Standards remove the agriculture beneficial use
classification from one of its cooling water reservoirs. Without removal of this
classification, the facility could be subjected to standards that will require
costly treatment and/or facility reconfiguration. The request for the removal of
this classification has been approved at the state level and is awaiting
approval by EPA.
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
may be discovered from time to time. One site identified as having been
contaminated by historical operations was addressed during 1998. Remedial
options based on the future use of this site are being pursued with appropriate
regulatory agencies. The cost of these actions has not had and is not
anticipated to have a material adverse impact on the Company's financial
position or results of operations.
EMPLOYEES
The Company and its subsidiaries had 2,779 employees at December 31,
1998.
21
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 5,561 megawatts. The following table sets forth information with
respect to present electric generating facilities, all of which are located in
Oklahoma:
Unit Station
Year Capability Capability
Station & Unit Fuel Installed (Megawatts) (Megawatts)
- -------------- ---- --------- ----------- -----------
Seminole 1 Gas 1971 515.0
2 Gas 1973 507.0
3 Gas 1975 500.0 1,522
Muskogee 3 Gas 1956 165.0
4 Coal 1977 492.5
5 Coal 1978 492.5
6 Coal 1984 506.0 1,656
Sooner 1 Coal 1979 514.0
2 Coal 1980 517.0 1,031
Horseshoe 6 Gas 1958 172.0
Lake 7 Gas 1963 237.0
8 Gas 1969 396.0 805
Mustang 1 Gas 1950 58.0 Inactive
2 Gas 1951 57.0 Inactive
3 Gas 1955 120.0
4 Gas 1959 260.0
5 Gas 1971 63.0 443
Conoco 1 Gas 1991 25.5
2 Gas 1991 29.5 55
Arbuckle 1 Gas 1953 74.0 Inactive
Enid 1 Gas 1965 9.8
2 Gas 1965 9.6
3 Gas 1965 11.0
4 Gas 1965 9.6 40
Woodward 1 Gas 1963 9.0 9
-----------
Total Active Generating Capability (all stations) 5,561
===========
22
At December 31, 1998, 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) 300 substations with a total capacity of approximately 4.1
million kVA, 19,998 structure miles of overhead lines, 1,623 miles of
underground conduit and 6,623 miles of underground conductors in Oklahoma; and
(ii) 30 substations with a total capacity of approximately 617,500 kVA, 1,658
structure miles of overhead lines, 165 miles of underground conduit and 369
miles of underground conductors in Arkansas.
Substantially all of OG&E's electric facilities were previously subject
to a direct first mortgage lien under the Trust Indenture securing OG&E's first
mortgage bonds. The Trust Indenture and related lien were discharged in April
1998.
Enogex owns: (i) approximately 3,329 miles of natural gas gathering and
transmission pipeline extending from the Arkoma Basin in eastern Oklahoma to the
Anadarko Basin in western Oklahoma; (ii) a 75 percent interest in the Noark
Pipeline LP which in turn owns 100 percent of the Ozark Gas Transmission LLC and
related companies, a 924 mile interstate pipeline system with gathering and
transmission operations in eastern Oklahoma and Arkansas and an approximate
current capacity of 330 million cubic feet per day; (iii) a natural gas
processing plant near Calumet, Oklahoma, which has the capacity to process 250
Mmcf of natural gas per day; (iv) interests in 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; (v) 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; and (vi) 100% of
the gas gathering, processing and treating assets of the Belvan Corporation and
Belvan and Todd Ranch Limited Partnerships, consisting of 345 miles of gathering
system, gas liquid recovery and sulfur extraction facilities with a combined
effective current capacity of 15 million cubic feet per day, and an eight-mile
natural gas liquids pipeline.
During the three years ended December 31, 1998, the Company's gross
property, plant and equipment additions approximated $652 million and gross
retirements approximated $136 million. These additions were provided by
internally generated funds. The additions during this three-year period amounted
to approximately 14.7 percent of total property, plant and equipment at December
31, 1998.
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.
23
On October 10, 1994, Defendants filed a Motion to Dismiss Counts II,
IV, V, VI and VII of Plaintiffs' Amended Complaint. With regard to Counts I and
III, Defendants filed a Motion for Summary Judgment on January 18, 1996. On
September 8, 1997, the United States Magistrate Judge recommended the
Defendant's motions to dismiss and for summary judgment should be granted and
that the case be dismissed in its entirety and judgment entered for OG&E. The
United States District Judge accepted the recommendation of the Magistrate and
entered judgement for OG&E. 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 Parties ("PRP"), in an EPA administrative action involving the
facility in Holden, Missouri, of Martha C. Rose Chemicals, Inc. ("Rose").
Beginning in early 1983 through 1986, Rose was engaged in the business of
brokering of polychlorinated biphenyls ("PCBs") and PCB items, processing of PCB
capacitors and 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. Absent an unforeseen contingency, OG&E believes this
matter is now closed.
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.
24
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 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) tortuous
interference with contract; and (vi) tortuous interference with a prospective
economic advantage. On December 21, 1998, the jury awarded Trigen in excess of
$30 million in actual and punitive damages. On February 19, 1999, the trial
court entered judgement in favor of Trigen as follows: (i) $6.8 million for
various antitrust violations, (ii) $4 million for tortious interference with an
existing contract, (iii) $7 million for tortious interference with a prospective
economic advantage and (iv) $10 million in punitive damages. The trial judge, in
a companion order, acknowledged that the portions of the judgement could be
duplicative, that the antitrust amounts could be tripled and that parties should
address these issues in their post-trial motions. OG&E has filed its post trial
motions requesting judgement in its favor or a new trial. If a successful
result is not obtained at the trial level, OG&E will appeal. While the outcome
of an appeal is uncertain, legal counsel and management believe it is not
probable that Trigen will ultimately succeed in preserving the verdicts.
Accordingly, the Company has not accrued any loss associated with the damages
awarded. The Company believes that the ultimate resolution of this case will not
have a material adverse effect on the Company's consolidated financial position
or results of operations.
5. As previously reported, the State of Oklahoma, ex rel., Teresa
Harvey (Carroll); Margaret B. Fent and Jerry R. Fent v. Oklahoma Gas and
Electric Company, et al., District Court, Oklahoma County, Case No.
CJ-97-1242-63. On February 24, 1997, the taxpayers instituted litigation against
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 appealed. On April 10, 1998, the Court
of Civil Appeals affirmed the order of the trial court granting OG&E Summary
Judgement. On April 29, 1998, Plaintiffs petitioned the Court of Civil Appeals
for rehearing. Plaintiffs' Petition for Rehearing was overruled. Plaintiffs
timely filed a Petition for Certiorari with the Oklahoma Supreme Court. The
Oklahoma Supreme Court denied Certiorari. Plaintiffs did not file their Petition
for Certiorari with the United States Supreme Court in time required. Case
closed.
6. As reported, the City of Enid, Oklahoma ("Enid") through its City
Council, notified 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
25
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 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.
7. On February 18, 1998, Enogex was sued by Melvin Scoggin and Oak
Tree Resources,LLC, in the District Court of Oklahoma County, State of Oklahoma,
for alleged breach of contract, fraud,breach of fiduciary duty, misappropriation
and unjust enrichment arising from communications that allegedly created
agreements regarding oil and gas exploration activities. Plaintiffs seek damages
in excess of $25 million. enogex filed an answer denying Plaintiffs'
allegations. Various discovery disputes have been heard and favorable rulings
for Enogex were entered by the Court. Plaintiffs sought a Writ of Mandamus from
the Oklahoma Supreme Court regarding discovery denied by the district court on
three occaisions. On March 23, 1999, the Oklahoma Supreme court denied
Plaintiffs' request. Discovery continues. While Enogex believes all the
aforementioned claims are without merit, Enogex cannot predict the ultimate
outcome of this litigation.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
- ------------------------------------------------------------
None
26
EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------
The following persons were Executive Officers of the Registrant as of
March 15, 1999:
Name Age Title
- -------------------- --- --------------------------------------
Steven E. Moore 52 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 55 Executive Vice President and
Chief Operating Officer
Michael G. Davis 49 Vice President - Marketing and
Customer Care
James R. Hatfield 41 Vice President and Treasurer
Irma B. Elliott 60 Vice President and
Corporate Secretary
Steven R. Gerdes 42 Vice President, Shared
Services
Melvin D. Bowen, Jr. 57 Vice President - Power Delivery - OG&E
Jack T. Coffman 55 Vice President - Power Supply - OG&E
Donald R. Rowlett 41 Controller Corporate Accounting
Don L. Young 58 Controller Corporate Audits
No family relationship exists between any of the Executive Officers of
the Registrant. Messrs. Moore, Strecker, Davis, Hatfield, Gerdes, Rowlett, Young
and Ms. Elliott are also officers of OG&E. Each Officer is to hold office until
the Board of Directors meeting following the next Annual Meeting of Shareowners,
currently scheduled for May 27, 1999.
The business experience of each of the Executive Officers of the
Registrant for the past five years is as follows:
27
Name Business Experience
- -------------------- ------------------------------------------------
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
1994-1995: Senior Vice President - Law
and Public Affairs - OG&E
Al M. Strecker 1998-Present: Executive Vice President and
Chief Operating Officer
1998-Present: Executive Vice President and
Chief Operating Officer -
OG&E
1996-1998: Senior Vice President
1994-1998: Senior Vice President -
Finance and
Administration - OG&E
1994: Vice President and
Treasurer - OG&E
Michael G. Davis 1998-Present: Vice President - Marketing
and Customer Care
1998-Present: Vice President - Marketing
and Customer Care -
OG&E
1996-1998: Vice President
1994-1998: Vice President -
Marketing and Customer
Services - OG&E
1994: Director - Marketing
Division - OG&E
James R. Hatfield 1997-Present: Vice President and Treasurer
1997-Present: Vice President and
Treasurer - OG&E
1994-1997: Treasurer - OG&E
28
Name Business Experience
- -------------------- ------------------------------------------------
1994: Vice President - Investor
Relations & Corporate
Secretary - Aquila Gas
Pipeline Corporation
Irma B. Elliott 1996-Present: Vice President and
Corporate Secretary
1996-Present: Vice President and
Corporate Secretary -
OG&E
1994-1996: Corporate Secretary - OG&E
Steven R. Gerdes 1998-Present: Vice President, Shared
Services
1998-Present: Vice President, Shared
Services - OG&E
1997-1998: Director, Shared Services
1997: Manager, Enterprise Support
1994-1997: Manager, Purchasing &
Material Management
1994: Manager, Purchasing
Melvin D. Bowen, Jr. 1994-Present: Vice President -
Power Delivery - OG&E
1994: Metro Region
Superintendent - OG&E
Jack T. Coffman 1994-Present: Vice President -
Power Supply - OG&E
1994: Manager - Generation
Services - OG&E
Donald R. Rowlett 1998-Present: Controller Corporate
Accounting
1996-Present: Controller Corporate
Accounting - OG&E
1994-1996: Assistant Controller - OG&E
1994: Senior Specialist -
Tax Accounting - OG&E
29
Name Business Experience
- -------------------- ------------------------------------------------
Don L. Young 1998-Present: Controller Corporate
Audits
1996-Present: Controller Corporate
Audits - OG&E
1994-1996: Controller - OG&E
30
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.
1998 1997
----------------------------------------------------------------
DIVIDEND Dividend
PAID HIGH LOW Paid High Low
----------------------------------------------------------------
First Quarter $0.33 1/4 $28 15/16 $25 11/16 $0.33 1/4 $21 1/2 $20 1/4
Second Quarter 0.33 1/4 28 15/16 26 0.33 1/4 22 15/16 20 5/16
Third Quarter 0.33 1/4 29 9/16 25 5/8 0.33 1/4 23 5/8 22
Fourth Quarter 0.33 1/4 30 25 15/16 0.33 1/4 27 3/8 23 5/32
The number of record holders of Common Stock at December 31, 1998, was
39,008. The book value of the Company's Common Stock at December 31, 1998, was
$12.91.
31
ITEM 6. SELECTED FINANCIAL DATA.
- --------------------------------
HISTORICAL DATA
1998 1997 1996 1995 1994
---------------------------------------------------------------------------
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS EXCEPT
FOR PER SHARE DATA)
Operating revenues................. $1,617,737 $1,443,610 $1,387,435 $1,302,037 $1,355,168
Operating expenses................. 1,386,924 1,249,612 1,186,216 1,099,890 1,154,702
----------- ----------- ----------- ----------- -----------
Operating income................... 230,813 193,998 201,219 202,147 200,466
Other income and deductions........ 5,758 5,047 97 800 (2,167)
Interest charges................... 70,699 66,495 67,984 77,691 74,514
----------- ----------- ----------- ----------- -----------
Net income......................... 165,872 132,550 133,332 125,256 123,785
Preferred dividend
requirements..................... 733 2,285 2,302 2,316 2,317
Earnings available for
common........................... $ 165,139 $ 130,265 $ 131,030 $ 122,940 $ 121,468
=========== =========== =========== =========== ===========
Long-term debt..................... $ 935,583 $ 841,924 $ 829,281 $ 843,862 $ 730,567
Total assets....................... $2,983,929 $2,765,865 $2,762,355 $2,754,871 $2,782,629
Earnings per average common
share............................ $ 2.04 $ 1.61 $ 1.62 $ 1.52 $ 1.50
CAPITALIZATION RATIOS
Common equity...................... 52.72% 52.50% 52.26% 51.19% 54.13%
Cumulative preferred stock......... --- 2.63% 2.68% 2.73% 2.94%
Long-term debt..................... 47.28% 44.87% 45.06% 46.08% 42.93%
INTEREST COVERAGES
Before federal income taxes
(including AFUDC)................ 4.84X 4.11X 4.07X 3.48X 3.59X
(excluding AFUDC)................ 4.82X 4.10X 4.06X 3.46X 3.58X
After federal income taxes
(including AFUDC)................ 3.31X 2.98X 2.94X 2.59X 2.64X
(excluding AFUDC)................ 3.30X 2.97X 2.93X 2.57X 2.62X
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- --------------------------------------------------------------------------------
OF OPERATIONS.
- -------------
MANAGEMENT'S DISCUSSION AND ANALYSIS.
OVERVIEW
Percent Change
From Prior Year
---------------
(THOUSANDS EXCEPT PER SHARE AMOUNTS) 1998 1997 1996 1998 1997
==================================================================================================
Operating revenues...................... $1,617,737 $1,443,610 $1,387,435 12.1 4.0
Earnings available for common stock..... $ 165,139 $ 130,265 $ 131,030 26.8 (0.6)
Average shares outstanding.............. 80,772 80,745 80,734 --- ---
Earnings per average common share....... $ 2.04 $ 1.61 $ 1.62 26.7 (0.6)
Earnings per average common share -
assuming dilution..................... $ 2.04 $ 1.61 $ 1.62 26.7 (0.6)
Dividends paid per share................ $ 1.33 $ 1.33 $ 1.33 --- ---
==================================================================================================
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.
Average shares outstanding and all per share amounts have been restated to
reflect the two-for-one stock split that occurred in June 1998. 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 D