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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, 1999 Commission File Number 1-12579
OGE ENERGY CORP.
(Exact name of registrant as specified in its charter)
Oklahoma 73-1481638
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which
so registered each class is registered
------------------- ------------------------------
Common Stock New York Stock Exchange and Pacific Stock Exchange
Rights to Purchase-
Series A Preferred Stock New York Stock Exchange and Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
As of February 29, 2000, Common Shares outstanding were 77,863,370.
Based upon the closing price on the New York Stock Exchange on February 29,
2000, the aggregate market value of the voting stock held by nonaffiliates of
the Company was: Common Stock $1,326,618,666.
The proxy statement for the 2000 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.........................................4
Rate Structure, Load Growth and Related Matters.............11
Fuel Supply.................................................12
Enogex...............................................................14
Finance and Construction.............................................19
Environmental Matters................................................20
Employees............................................................22
Item 2. Properties...........................................................23
Item 3. Legal Proceedings....................................................24
Item 4. Submission of Matters to a Vote of Security Holders..................28
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters...........................................32
Item 6. Selected Financial Data..............................................33
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...........................34
Item 8. Financial Statements and Supplementary Data..........................50
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure......................................82
PART III
Item 10. Directors and Executive Officers of the Registrant...................82
Item 11. Executive Compensation...............................................82
Item 12. Security Ownership of Certain Beneficial
Owners and Management.........................................82
Item 13. Certain Relationships and Related Transactions.......................82
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K...........................................82
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 is not engaged in any business independent of that
conducted through its subsidiaries, Oklahoma Gas and Electric Company ("OG&E"),
Enogex Inc. and Enogex Inc.'s subsidiaries ("Enogex"), and OGE Energy Capital
Trust I, a financing trust established in 1999.
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 5,512,599 kilowatts.
Enogex owns and operates approximately 9,700 miles of natural gas
transmission and gathering pipelines, has interests in 15 gas processing plants,
markets electricity, natural gas and natural gas liquids 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
both Oklahoma and Arkansas, legislation has been passed to provide for the
restructuring of the electric industry with the goal to provide retail customers
with the ability to choose their generation suppliers by July 1, 2002 and
January 1, 2002, respectively. The Oklahoma Legislature is considering
implementation legislation which is expected to be enacted in May, 2000. This
legislation, if implemented as proposed, would significantly impact OG&E. 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 1999, 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 90 percent of
total electric operating revenues for the year ended December 31, 1999, were
derived from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E's system control area peak demand as reported by the system
dispatcher for the year was approximately 5,748 megawatts, and occurred on
August 11, 1999. OG&E's load responsibility peak demand was approximately 5,569
megawatts on August 11, 1999, resulting in a capacity margin of approximately
10.0 percent. As reflected in the table below and in the operating statistics on
page 3, total kilowatt-hour sales decreased 2.2 percent in 1999 as compared to
an increase of 4.2 percent in 1998 and a 1.6 percent increase in 1997. In 1999,
kilowatt-hour sales to OG&E customers ("system sales") and sales to other
utilities and power marketers ("off-system sales") decreased 0.7 percent and
48.6 percent, because of the record heat of 1998. In 1997, total kilowatt-hour
sales increased due to continued customer growth.
Variations in kilowatt-hour sales for the three years are reflected in
the following table:
SALES (Millions of Kwh)
Inc/ Inc/ Inc/
1999 (Dec) 1998 (Dec) 1997 (Dec)
- -------------------------------------------------------------------------------
System Sales 23,468 (0.7%) 23,642 6.6% 22,183 3.0%
Off-System Sales 374 (48.6%) 728 (39.5%) 1,202 (18.5%)
------- ------- -------
Total Sales 23,842 (2.2%) 24,370 4.2% 23,385 1.6%
======= ======= =======
In 1999, OG&E's Sooner Generating Station (consisting of two coal-fired
units with an aggregate capability of 1,012 Mw) and OG&E's three coal-fired
units at its Muskogee Generating Station (with an aggregate capability of 1,481
Mw) were recognized by an industry survey as being among the top seven percent
of more than 400 major coal-fired plants across the United States.
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. See Item 3 "Legal Proceedings" for a further
discussion of this matter. Oklahoma law forbids the granting of an exclusive
franchise to a utility for providing electricity.
Besides competition from other suppliers or marketers of electricity,
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.
2
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
YEAR ENDED DECEMBER 31
1999 1998 1997
------------- ------------- -------------
ELECTRIC ENERGY:
(Millions of Kwh)
Generation (exclusive of station use)................... 21,788 22,565 21,620
Purchased............................................... 3,795 3,984 3,528
------------- ------------- -------------
Total generated and purchased..................... 25,583 26,549 25,148
Company use, free service and losses.................... (1,741) (2,179) (1,763)
------------- ------------- -------------
Electric energy sold.............................. 23,842 24,370 23,385
------------- ------------- -------------
ELECTRIC ENERGY SOLD:
(Millions of Kwh)
Residential............................................. 7,509 7,959 7,179
Commercial and industrial............................... 11,985 11,912 11,586
Public street and highway lighting...................... 69 68 68
Other sales to public authorities....................... 2,354 2,352 2,202
System sales for resale................................. 1,551 1,351 1,148
------------- ------------- -------------
Total system sales................................ 23,468 23,642 22,183
Off-system sales........................................ 374 728 1,202
------------- ------------- -------------
Total sales....................................... 23,842 24,370 23,385
============= ============= =============
ELECTRIC OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential........................................... $ 515,299 $ 537,486 $ 474,419
Commercial and industrial............................. 557,884 554,589 526,673
Public street and highway lighting.................... 9,736 9,618 9,456
Other sales to public authorities..................... 108,159 110,522 98,818
System sales for resale............................... 42,918 38,763 34,667
------------- ------------- -------------
Total system sales................................ 1,233,996 1,250,978 1,144,033
Off-system sales...................................... 27,894 37,435 23,028
------------- ------------- -------------
Total Electric Revenues........................... 1,261,890 1,288,413 1,167,061
Miscellaneous......................................... 24,954 23,665 24,629
Total Operating Revenues.......................... $ 1,286,844 $ 1,312,078 $ 1,191,690
============= ============= =============
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential............................................. 599,702 598,378 593,699
Commercial and industrial............................... 86,837 86,251 85,315
Public street and highway lighting...................... 249 249 249
Other sales to public authorities....................... 11,151 11,183 10,897
Sales for resale........................................ 56 39 40
------------- ------------- -------------
Total............................................. 697,995 696,100 690,200
============= ============= =============
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (Kwh)................................ 12,546 13,342 12,133
Average annual revenue.................................. $ 860.98 $ 900.94 $ 801.74
Average price per Kwh (cents)........................... 6.86 6.75 6.61
3
REGULATION AND RATES
OG&E's retail electric tariffs in Oklahoma are regulated by the
Oklahoma Corporation Commission ("OCC"), and in Arkansas by the Arkansas Public
Service Commission ("APSC"). The issuance of certain securities by 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, 1999, approximately 87 percent of
OG&E's electric revenue was subject to the jurisdiction of the OCC, eight
percent to the APSC, and five percent to the FERC.
RECENT REGULATORY MATTERS
In February 1997, the OCC issued an order (the "1997 Order") that,
among other things, effectively lowered 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 1997 Order also directed OG&E to commence competitively bid gas
transportation service to its gas-fired plants no later than April 30, 2000. The
order also set annual compensation for the transportation services provided by
Enogex to OG&E at $41.3 million annually until March 1, 2000, at which time the
rate would drop to $28.5 million (reflecting the completion of the recovery from
ratepayers of the amortization premium paid by OG&E when it acquired Enogex in
1986) and remain at that level until competitively-bid gas transportation
begins. Final firm bids were submitted by Enogex and other pipelines on April
15, 1999. In July 1999, OG&E filed an application with the OCC requesting
approval of a performance-based rate plan for its Oklahoma retail customers from
April 2000 until the introduction of customer choice for electric power in July
2002. As part of this application, OG&E stated that Enogex had submitted the
only viable bid ($33.4 million per year) for gas transportation to its six
gas-fired power plants that were the subject of the competitive bid. As part of
its application to the OCC, OG&E offered to discount Enogex's bid from $33.4
million annually to $25.2 million annually. OG&E has executed a new gas
transportation contract with Enogex under which Enogex would continue serving
the needs of OG&E's power plants at a price to be paid by OG&E of $33.4 million
annually and, if OG&E's proposal had been approved by the OCC, OG&E would have
recovered a portion of such amount ($25.2 million) from its ratepayers. The OCC
Staff (the "Staff"), the Office of the Oklahoma Attorney General and a coalition
of industrial customers filed testimony questioning various parts of OG&E's
performance-based rate plan, including the result of the competitive bid
process, and suggested, among other things, that the bidding process be repeated
or that gas transportation service to five of OG&E's gas-fired plants be awarded
to parties other than Enogex. The Staff also filed testimony stating in
substance that OG&E's electric rates as a whole were appropriate and did not
warrant a rate review. OG&E negotiated with these parties in an effort to settle
all issues (including the competitive bid process) associated with its
4
application for a performance-based rate plan. When these negotiations failed,
OG&E withdrew its application, which withdrawal was approved by the OCC in
December 1999. Based on filed testimony, OG&E believes that Enogex properly won
the competitive bid and, unless OG&E's decision to award its gas transportation
service to Enogex is abrogated by order of the OCC (which order is upheld on
appeal), that it intends to fulfill its obligations under its new gas
transportation contract with Enogex at a price of $33.4 million annually.
Whether OG&E will be able to recover the entire amount from its ratepayers has
not been determined as explained below.
The 1997 Order also contained the 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. As explained below, the GEP
Rider is currently under review by the OCC.
The fuel cost information used to calculate the GEP Rider is based on
fuel cost data submitted by each of the utilities in their Form No. 1 Annual
Report filed with the FERC. The GEP Rider is revised effective July 1 of each
year to reflect any changes in the relative annual cost of fuel reported for the
preceding calendar year. For 1999, the GEP Rider contributed approximately $20.8
million to revenues, which was approximately $9.5 million, or approximately
$0.07 per share lower than 1998. The current GEP Rider is estimated to
positively impact revenue by $13.1 million or approximately $0.10 per share
during the 12 months ending June 2000.
On January 12, 2000, the Staff filed three applications to address
various aspects of OG&E's electric rates. Two of the applications were expected,
while the third pertains to recoveries under OG&E's fuel adjustment clause. The
first application relates to the completion of the recovery of the amortization
premium paid by OG&E when it acquired Enogex in 1986 and the resulting removal
of this $12.8 million from the amounts currently being paid annually by OG&E to
Enogex and being recovered by OG&E from its ratepayers. OG&E has consented to
this action. The second application relates to a review of the GEP Rider, which,
as part of the OCC's 1997 Order, was scheduled for review in March 2000. OG&E
collected approximately $20.8 million pursuant to the GEP Rider during 1999. A
hearing on the GEP Rider is scheduled in May 2000 and OG&E intends to support
the retention of the GEP Rider with only minor modifications. The final
application relates to a review of 1999 fuel cost recoveries. OG&E assumes that
this application also will be used to address the competitive bid process of its
gas transportation service. The Company cannot predict the precise outcome of
these proceedings at this time, but does not expect that they will have a
material effect on its operations.
On February 13, 1998, the APSC Staff filed a motion for a show cause
order to review OG&E's electric rates in the State of Arkansas. The Staff
recommended a $3.1 million annual rate reduction (based on a test year ended
December 31, 1996). The Staff and OG&E reached a settlement for a $2.3 million
annual rate reduction, which was approved by the APSC in August 1999.
STATE RESTRUCTURING INITIATIVES
OKLAHOMA: As previously reported, Oklahoma enacted in April 1997 the
Electric Restructuring Act of 1997 (the "Act"). In June 1998, various amendments
to the Act were enacted. If implemented as proposed, the Act will significantly
affect OG&E's future operations. The following summary of the Act
5
does not purport to be complete and is subject to the specific provisions of the
Act, which is codified at Sections 190.2 et. seq. of Title 17 of the Oklahoma
Statutes.
The Act consists of eight sections, with Section 1 designating the name
of the Act. Section 2 describes the purposes of the Act, which is generally to
restructure the electric industry to provide for more competition and, in
particular, to provide for the orderly restructuring of the electric utility
industry in the State of Oklahoma in order to allow direct access by retail
consumers to the competitive market for the generation of electricity while
maintaining the safety and reliability of the electric system in the state.
The primary goals of a restructured electric utility industry, as set
forth in Section 2 of the Act, are as follows:
l. To reduce the cost of electricity for as many consumers as
possible, helping industry to be more competitive, to create more
jobs in Oklahoma and help lower the cost of government by reducing
the amount and type of regulation now paid for by taxpayers;
2. To encourage the development of a competitive electricity industry
through the unbundling of prices and services and separation of
generation services from transmission and distribution services;
3. To enable retail electric energy suppliers to engage in fair and
equitable competition through open, equal and comparable access to
transmission and distribution systems and to avoid wasteful
duplication of facilities;
4. To ensure that direct access by retail consumers to the
competitive market for generation be implemented in Oklahoma by
July 1, 2002; and
5. To ensure that proper standards of safety, reliability and service
are maintained in a restructured electric service industry.
Section 3 of the Act sets forth various definitions and exempts in
large part several electric cooperatives and municipalities from the Act unless
they choose to be governed by it.
Sections 4, 5 and 6 of the Act are designed to implement the goals of
the Act and provide for various studies and task forces to assess the issues and
consequences associated with the proposed restructuring of the electric utility
industry. In Section 4, the 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
6
established whereby all retail consumers are permitted to choose
their retail electric energy suppliers by July 1, 2002.
3. When consumer choice is introduced, rates shall be unbundled to
provide clear price information on the components of generation,
transmission and distribution and any other ancillary charges.
Charges for public benefit programs currently authorized by
statute or the OCC, or both, shall be unbundled and appear in line
item format on electric bills for all classes of consumers.
4. An entity providing distribution services shall be relieved of its
traditional obligation to provide electric supply but shall have a
continuing obligation to provide distribution service for all
consumers in its service territory.
5. The benefits associated with implementing an independent system
planning committee composed of owners of electric distribution
systems to develop and maintain planning and reliability criteria
for distribution facilities shall be evaluated.
6. A defined period for the transition to a restructured electric
utility industry shall be established. The transition period
shall reflect a suitable time frame for full compliance with the
requirements of a restructured utility industry.
7. Electric rates for all consumer classes shall not rise above
current levels throughout the transition period. If possible,
electric rates for all consumers shall be lowered when feasible
as markets become more efficient in a restructured industry.
8. The OCC shall consider the establishment of a distribution access
fee to be assessed to all consumers in Oklahoma connected to
electric distribution systems regulated by the OCC. This fee shall
be charged to cover social costs, capital costs, operating costs,
and other appropriate costs associated with the operation of
electric distribution systems and the provision of electric
services to the retail consumer.
9. Electric utilities have traditionally had an obligation to provide
service to consumers within their established service territories
and have entered into contracts, long-term investments and
federally mandated cogeneration contracts to meet the needs of
consumers. These investments and contracts have resulted in
costs, which may not be recoverable in a competitive restructured
market and thus may be "stranded." Procedures shall be
established for identifying and quantifying stranded investments
and for allocating costs; and mechanisms shall be proposed for
for recovery of an appropriate amount of prudently incurred,
unmitigable and verifiable stranded costs and investments. As
As part of this process, each entity shall be required to propose
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
7
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, not impede competition
and shall be allocated over a period of not less than three (3)
years nor more than seven (7) years.
10. It is the intent that all transition costs shall be recovered by
virtue of the savings generated by the increased efficiency in
markets brought about by restructuring of the electric utility
industry. All classes of consumers shall share in the transition
costs.
Subject to the principles set forth in Section 4, the Joint Task Force
is directed to prepare a four-part study. As a result of the 1998 amendments,
the time frame for the delivery of the remaining parts of the Study was
accelerated to October 1, 1999. This study addressed: (i) technical issues
(including reliability, safety, unbundling of generation, transmission and
distribution services, transition issues and market power); (ii) financial
issues (including rates, charges, access fees, transition costs and stranded
costs); (iii) consumer issues (such as the obligation to serve, service
territories, consumer choices, competition and consumer safeguards); and (iv)
tax issues (including sales and use taxes, ad valorem taxes and franchise fees).
Section 5 of the Act directs the Joint Task Force to study and submit a
report on the impact of the restructuring of the electric utility industry on
state tax revenues and all other facets of the current utility tax structure on
the state and all political subdivisions of the state. The Oklahoma Tax
Commission and the OCC are precluded from issuing any rules on such matters
without the approval of the Oklahoma Legislature. Also, the Act requires the
establishment, on or before July 1, 2002, of a uniform tax policy that allows
all competitors to be taxed on a fair and equitable basis.
Section 6 creates the Joint Task Force, which shall consist of seven
members from the Oklahoma Senate and seven members from the Oklahoma House of
Representatives. The Joint Task Force is directed to undertake the studies set
forth in Sections 4 and 5 of the Act. The Joint Task Force is permitted to make
final recommendations to the Governor and Oklahoma Legislature. The Joint Task
Force is also empowered to retain consultants to study the creation of an
Independent System Operator, which would coordinate the physical supply of
electricity throughout Oklahoma and maintain reliability, security and stability
of the bulk power system. In addition, such study shall assess the benefits of
establishing a power exchange that would operate as a power pool allowing power
producers to compete on common ground in Oklahoma. In fulfilling its tasks, the
Joint Task Force can appoint advisory councils made up of electric utilities,
regulators, residential customers and other constituencies.
Section 7 provides generally that, with respect to electric
distribution providers, no customer switching will be allowed from the effective
date of the Act until July 1, 2002, except by mutual consent. It also provides
that any municipality that fails to become subject to the Act will be prohibited
from selling power outside its municipal limits except from lines owned on the
effective date of the Act. Furthermore, this section provides generally that
out-of-state suppliers of electricity and their affiliates who make retail sales
of electricity in Oklahoma through the use of transmission and distribution
facilities of in-state suppliers must provide equal access to their transmission
and distribution facilities outside of Oklahoma. Section 8 sets forth the
effective date of the Act as April 25, 1997.
Another provision of the Act enacted in 1998 requires a uniform tax
policy be established by July 1, 2002. The Act was modified during the 1999
session of the Oklahoma Legislature to clarify certain ambiguities by defining
key terms in the Act.
8
With the completion of the studies described above in October 1999, the
Oklahoma legislature is expected to implement additional legislation, which will
address many specific issues associated with deregulation. Several bills have
already been introduced. While the Company cannot predict the terms of the new
legislation, the Company intends to participate actively in the legislative
process.
The OCC has adopted rules that are designed to make the gas utility
business in Oklahoma more competitive. These rules do not impact the electric
industry. Yet, if implemented, the rules are expected to offer increased
opportunities to Enogex's pipeline and related businesses.
ARKANSAS: In December 1997, the APSC established four generic
proceedings to consider the implementation of a competitive retail electric
market in the State of Arkansas. During 1998, the APSC held hearings to consider
competitive retail generation, market structure, market power, taxation,
recovery and mitigation of stranded costs, service and reliability, low income
assistance, independent system operators and transition issues. The Company
participated actively in those proceedings, and in October 1998 the APSC issued
its report to the Arkansas Legislature recommending competitive retail electric
generation to begin no later than January 1, 2002. Several bills calling for
electric industry restructuring were introduced after the Arkansas General
Assembly began its 1999 session.
In April 1999, Arkansas became the 18th state to pass a law calling for
restructuring of the electric utility industry at the retail level. The new law
targets customer choice of electricity providers by January 1, 2002. The new law
also provides that utilities owning or controlling transmission assets must
transfer control of such transmission assets to an independent system operator,
independent transmission company or regional transmission group, if any such
organization has been approved by the FERC. Other provisions of the new law
permit municipal electric systems to opt in or out, permit recovery of stranded
costs and transition costs and require unbundled rates by July 1, 2000 for
generation, transmission, distribution and customer service. The APSC has
established a timetable to establish rules implementing the Arkansas
restructuring statutes. The new law will significantly affect OG&E's future
Arkansas operations. OG&E's electric service area includes parts of western
Arkansas, including Ft. Smith, the second-largest metropolitan market in the
state.
AUTOMATIC FUEL ADJUSTMENT CLAUSES
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are charged to substantially all of the Company's electric
customers through automatic fuel adjustment clauses, which are subject to
periodic review by the OCC, the APSC and the FERC.
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
9
public interest and must provide certain types of service which may be requested
by QFs to supplement or back up those facilities' own generation.
The Energy Policy Act of 1992 ("Energy Act") has resulted in some
significant changes in the operations of the electric utility industry and the
federal policies governing the generation, transmission and sale of electric
power. The Energy Act, among other things, authorized the FERC to order
transmitting utilities to provide transmission services to any electric utility,
Federal power marketing agency, or any other person generating electric energy
for sale or resale, at transmission rates set by the FERC. The Energy Act also
is designed to promote competition in the development of wholesale power
generation in the electric industry. It exempts a new class of independent power
producers from regulation under the Public Utility Holding Company Act of 1935.
Within four years of the enactment of the Energy Act, FERC issued Order
888 and Order 889 to facilitate third-party utilization of the transmission grid
as the vehicle for developing a more competitive wholesale bulk power market.
Order 888 requires all transmission owners to (i) offer comparable open-access
transmission service for wholesale transactions under a tariff of general
applicability on file at FERC and (ii) take transmission service for their own
wholesale sales under their open-access tariff. Order 889 requires electric
utilities to functionally separate their transmission and reliability functions
from their wholesale power marketing functions. In this connection, Order 889
required electric utilities to develop and maintain an Open Access Same-Time
Information System ("OASIS") to ensure that transmission customers have access
to transmission information, through electronic means, that will enable them to
obtain open-access transmission service on a basis comparable to a transmitting
utility's own use of its system.
OG&E is a member of the Southwest Power Pool ("SPP"), the regional
reliability organization for Oklahoma, Arkansas, Kansas, Louisiana, Missouri and
part of Texas. OG&E participated with the SPP in the development of regional
transmission tariffs and executed an Agency Agreement with the SPP to facilitate
interstate transmission operations within this region. The SPP has asked for
FERC recognition as an Independent System Operator ("ISO") consistent with
FERC's guidelines in its Order 888.
Another impact of complying with FERC's Order 888 is a requirement for
utilities to offer a transmission tariff that includes network transmission
service ("NTS") to transmission customers. NTS allows transmission service
customers to fully integrate load and resources on an instantaneous basis, in a
manner similar to how 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.
In December 1999, the FERC issued Order 2000 to advance the formation
of Regional Transmission Organizations ("RTOs"). The rule requires that each
public utility that owns, operates or controls facilities for the transmission
of electric energy in interstate commerce file by October 15, 2000, a proposal
with respect to forming and participating in an RTO. The FERC also codified
minimum characteristics and functions that a transmission entity must satisfy in
order to be considered an RTO. The FERC's goal is to promote efficiency in
wholesale electricity markets and to ensure that electricity consumers pay the
lowest price possible for reliable service. The FERC expects that the RTOs will
be operational by December 15, 2001.
10
REGULATORY ASSETS AND LIABILITIES
As discussed previously, Oklahoma and Arkansas enacted legislation that
will restructure the electric utility industry in those states, assuming that
all the conditions in the legislation are met. This legislation would deregulate
OG&E's electric generation assets and the continued use of Statement of
Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of
Certain Types of Regulation", with respect to the related regulatory assets may
no longer be appropriate. This may result in either full recovery of
generation-related regulatory assets (net of related regulatory liabilities) or
a non-cash, pre-tax write-off as an extraordinary charge of up to $30 million,
depending on the transition mechanisms developed by the legislature for the
recovery of all or a portion of these net regulatory assets.
The enacted Oklahoma and Arkansas legislation does not affect 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.
SUMMARY
The Energy Act, the actions of the FERC, the restructuring proposal in
Oklahoma, the Arkansas legislation and other factors are expected to
significantly increase competition in the electric industry. The Company has
taken steps in the past and intends to take appropriate steps in the future to
remain a competitive supplier of electricity. Past actions include a redesign
and restructuring effort in 1994, continuing actions to reduce fuel costs,
improvements in customer service, installation of the SAP Enterprise Software
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 1999, these programs and schedules included:
(i) the "Surprise Free Guarantee" program, which guarantees residential
customers comfort and annual energy consumption for heating, cooling and water
heating for new homes built to energy efficient standards; (ii) a load
curtailment rate for industrial and commercial customers who can demonstrate a
load curtailment of at least 500 kilowatts; and (iii) the
11
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 made it's pilot Real Time Pricing ("RTP") program permanent in
1999. The program was first implemented in 1996 for qualifying industrial and
commercial customers. This tariff gives customers additional options on total
kilowatt-hour growth and the control of growth of peak demand. RTP is a tariff
option, which prices electricity so that the current price varies hourly with
short notice to reflect current expected costs. The RTP technique will allow a
measure of competitive pricing, a broadening of customer choice, the balancing
of electricity usage and capacity in the short-and long-term, and provide
customers assistance in controlling their costs.
OG&E's 1999 marketing efforts included geothermal heat pumps,
electrotechnologies, electric food service promotion and a heat pump promotion
in the residential, commercial and industrial markets. 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.
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. As part of the Energy Act Congress established the National EMF
Research and Public Information Dissemination ("RAPID") Program to address the
question of whether EMF posed a risk to human health. In the National Institute
of Environmental Health Sciences ("NIEHS") report of June 1999 with regard to
the findings of RAPID, it is concluded that it is their belief that the
probability of EMF exposure truly being a health hazard is currently small. The
nation's electric utilities, including 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, during
the past decade OG&E has cooperatively funded Edison Electric Institute ("EEI")
research to study the possible health effects of EMFs. 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 1999, approximately 71 percent of the OG&E-generated energy was
produced by coal-fired units and 29 percent by natural gas-fired units. A slight
decline in the percentage of coal generation in future years is expected to
result from increases in natural gas-fired generation required to meet growing
energy needs while coal generation will remain fairly constant. Over the last 5
years, the average cost of fuel used, by type, per million Btu was as follows:
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------
Coal.................. $0.85 $0.85 $0.84 $0.83 $0.83
Natural Gas........... $3.14 $2.83 $3.60 $3.61 $3.19
Weighted Avg.......... $1.54 $1.48 $1.39 $1.45 $1.41
12
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
----------------
2,493 megawatts, are designed to burn low sulfur western coal. OG&E purchases
coal under a mix of long- and short-term contracts. During 1999, OG&E purchased
11.5 million tons of coal from the following Wyoming suppliers: Caballo Rojo
Complex, Kennecott Energy Company, Thunder Basin Coal Company, Powder River Coal
Company, and Triton Coal Company. The combination of all coals has a weighted
average sulfur content of 0.3 percent and can be burned in these units under
existing federal, state and local environmental standards (maximum of 1.2 pounds
of sulfur dioxide per million Btu) without the addition of sulfur dioxide
removal systems. Based upon the average sulfur content, 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.
OG&E has continued its efforts to maximize the utilization of its coal
units by optimizing the boiler operations at both the Sooner and Muskogee
generating plants. See "Environmental Matters" for a discussion of an
environmental proposal that, if implemented as proposed, could inhibit OG&E's
ability to use coal as its primary boiler fuel.
GAS-FIRED UNITS: For calendar year 2000, 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 2000 will be supplied by contracts with
at-market pricing. These volumes of gas will be acquired through day-to-day
purchases on the spot market, as well as monthly purchase agreements.
In 1993, 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 businesses through subsidiary companies. These businesses include gas
processing operations and natural gas liquids marketing ("Gas Processing")
conducted by Enogex Products Corporation ("Products") and a subsidiary of
Transok Holding LLC ("Transok"); exploration and production of oil and natural
gas ("Exploration and Production") conducted through Enogex Exploration
Corporation ("Exploration"); marketing of natural gas, natural gas liquids, and
electricity ("Marketing") conducted primarily by OGE Energy Resources Inc.
("Resources") and Transok; and the gas gathering and interstate gas transmission
operations ("Gas Transportation") conducted by Enogex Arkansas Pipeline Company
("EAPC"), Enogex Gas Gathering LLC ("EGG") and Transok.
For the year ended December 31, 1999, and before elimination of
intercompany items between OG&E and Enogex, Enogex's consolidated revenues and
net income were approximately $1.0 billion and $21.7 million, respectively.
Recent Actions. Enogex is the exclusive transporter of natural gas to
--------------
OG&E's electric power generating stations. The OCC, the regulatory body which
sets OG&E's electric rates, issued an order on February 11, 1997 directing OG&E
to commence competitively bid gas transportation service to its gas-fired plants
no later than April 30, 2000. The order also set annual compensation that can be
recovered from ratepayers for the transportation services provided by Enogex to
OG&E at $41.3 million annually until March 1, 2000, at which time the rate would
drop to $28.5 million and remain in effect until competitively-bid gas
transportation begins. On November 30, 1998, OG&E issued a detailed Request for
Proposal ("RFP") to potential transportation bidders to begin the process of
competitive bidding. Final firm bids were submitted by Enogex and others on
April 15, 1999. In July 1999, OG&E filed an application with the OCC requesting
approval of a performance-based rate plan for its Oklahoma retail customers from
April 2000 until the introduction of customer choice for electric power in July
2002. As part of this application, OG&E stated that Enogex had submitted the
only viable bid ($33.4 million per year) for gas transportation to its six
gas-fired power plants that were the subject of the competitive bid. As part of
its application to the OCC, OG&E offered to discount Enogex's bid from $33.4
million annually to $25.2 million annually. Enogex has executed a new gas
transportation contract with OG&E under which Enogex will continue serving the
needs of OG&E's power plants identified in the RFP at a price to be paid by OG&E
of $33.4 million annually. The Company cannot predict what further action the
OCC or others may take regarding the competitive bid process. These actions
could include hearings by the OCC and attempts to force OG&E to use parties
other than Enogex for its gas transportation service. Based on filed testimony
and advice from OG&E, Enogex believes that it properly won the competitive bid
and, unless OG&E's decision to award its gas transportation service to Enogex is
abrogated by order of the OCC (which order is upheld on appeal), OG&E will
fulfill its obligations under its new gas transportation contract with Enogex at
a price of $33.4 million annually. As a result of the foregoing, Enogex expects
that revenues generated from its transportation services for OG&E (which in 1998
and 1999 represented 8.2 percent and 3.8 percent, respectively, of Enogex's
consolidated revenues) will remain at a rate of $41.3 million per year until
April 30, 2000 and will decline to $33.4 million thereafter. Whether OG&E will
be able to recover the full amount from its ratepayers has not been determined.
Enogex plans to diversify its revenue and income sources by increasing
revenues and net income from transmission services provided to third parties, by
increasing the revenues and net income from
14
Enogex subsidiaries' natural gas gathering and processing, by continuing
development and production operations around our systems, and by actively
pursuing 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 processing 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 NOARK Pipeline Systems, L.P. ("NOARK"), for
approximately $30 million and agreed to acquire the assets of Ozark Pipeline
("Ozark"), for approximately $55 million. In July 1998, EAPC completed its
acquisition of Ozark and contributed Ozark to NOARK. The two pipelines were
integrated into a single, interstate transmission system, Ozark Gas Transmission
LLC ("OGT") on November 1, 1998 at an additional cost of approximately $15
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 is approximately
330 million cubic feet per day.
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 OGT. AWP's current maximum lawful rate is $0.0311 per mmbtu.
In July 1998, Products acquired Belvan Corporation and the Belvan
Partners, L.P. and Todd Ranch Partners, L.P. 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.
In July 1998, Enogex entered into a capital lease of 5 billion cubic
feet of firm gas storage capacity plus certain rights to an additional 8 billion
cubic feet of capacity in an existing gas storage field located in Hughes
County, Oklahoma. The lease was for five years firm with seven five-year renewal
terms for a total of 40 years, and provides for annual rental payments of $1.1
million payable quarterly. The first three renewal terms provide for annual
payments of $900,000 and the remaining terms provide for annual payments of
$100,000. Enogex paid $10.5 million on execution of the agreement. This storage,
which can accommodate injections of up to 150 million cubic feet per day and
withdrawals of up to 400 million cubic feet per day, has enhanced the operating
flexibility of Enogex in serving end-user markets and has permitted Enogex to
capture seasonal swings in the value of system supply gas.
In July 1999, Enogex acquired Transok. Transok's principal assets
include approximately 4,900 miles of natural gas gathering and transmission
pipelines and related compression assets located in Oklahoma and Texas with a
current throughput of approximately 1.1 billion cubic feet per day and a 18
billion cubic feet underground gas storage field at Greasy Creek, Oklahoma.
Transok also owns nine gas processing plants with inlet capacities totaling 779
million cubic feet per day, which produce
15
approximately 26,500 gross barrels per day of natural gas liquids. Enogex
purchased Transok from Tejas Energy LLC, an affiliate of Shell Oil Company, for
approximately $710.3 million, which included acquisition costs, reserves and
assumption of $173 million of long term debt.
Gas Transportation. One of Enogex's primary lines of business is the
-------------------
transportation of natural gas, which includes both interstate and intrastate
transportation along with natural gas gathering. This business is conducted by
Enogex and several of its subsidiaries in Oklahoma, Arkansas and Texas.
Interruptible transportation service is offered to most interstate and
intrastate pipelines and end-users connected to Enogex's systems. Enogex and its
subsidiaries operate approximately 9,700 miles of pipeline that gather and
transport gas from the Arkoma basin of eastern Oklahoma and Arkansas, the
Anadarko basin of western Oklahoma and the Permian basin of West Texas.
As stated above, the Company completed in July 1999 its acquisition of
Transok. Transok was established in 1955 to transport boiler fuel to the
gas-powered electric generating facilities of Public Service Company of Oklahoma
("PSO"). PSO, a subsidiary of Central and South West Corporation, is the second
largest electric utility in Oklahoma, serving the Tulsa market. Transok was
acquired by PSO in 1961 and maintained a sole-supplier relationship with PSO
until 1998, when ONG began supplying gas to three of the PSO generating stations
pursuant to a competitive bid process put in place by the OCC. Notwithstanding
the loss of the sole-supplier status, PSO remains an important customer of
Transok services. Transok continues to provide gas transmission delivery
services to all of PSO's gas-fueled electric generation units in Oklahoma under
a firm intrastate transportation contract. The current contract, which expires
January 1, 2003, provides for a monthly demand charge plus a variable
transportation rate depending on the origins of the gas supply being
transported. In addition, Transok provides straight fee transportation services
to West Texas Utilities ("WTU"), an affiliate of PSO, for gas delivery service
to certain WTU generating stations in the Texas Panhandle under a contract that
expires on December 31, 2004. In 1999, Transok's revenues from the PSO and WTU
contracts were $14.5 million and $2.5 million respectively.
The rates charged by Enogex and Transok 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 and Transok 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 and Transok have agreed to open their
systems to all interstate shippers that are interested in transporting natural
gas through the systems. Enogex and Transok are required to conduct this
transportation on a non-discriminatory basis, although this transportation is
subordinate to that performed for OG&E and PSO. This decision does not increase
appreciably the federal regulatory burden on Enogex and Transok, but does give
Enogex and Transok the opportunity to utilize any unused capacity on an
interruptible basis and thus increase its transportation revenues.
Gas Processing. Products has been active since 1968 in the processing
---------------
of natural gas and marketing of natural gas liquids. With the acquisition of
Transok, Enogex is now the largest gas processor in the State of Oklahoma. The
NuStar Joint Venture, in which Products owns 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. Transok's gas processing operations include nine plants in
Oklahoma with a total inlet capacity of 780 million cubic feet per day. The
products extracted from the natural 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
16
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. As stated above,
Transok owns and operates nine natural gas processing plants in Oklahoma with an
aggregate inlet capacity of 779 million cubic feet per day. All Transok
processing plants are cryogenic expander processing plants capable of recovering
or rejecting ethane. Product from these plants is delivered into pipeline
facilities owned and operated by Koch Industries, Inc. ("Koch").
A portion of the commercial grade propane processed at Products'
Calumet facility and two Transok plants are sold on the local market. The other
natural gas liquids are delivered into pipeline facilities of Koch and
transported to Conway, Kansas (which is one of the nation's largest wholesale
markets for natural gas liquids), where they are sold on the spot market.
Ethane, which is produced at all of Products' plants except Calumet, is sold
under a contract with Equistar Chemicals. This contract expired in February
2000, but is renewable annually on an evergreen basis. Except for a limited
number of ethane contracts with polyethylene producers and terminal sales of
propane, Transok delivers natural gas liquids via Koch at Conway, Kansas and Mt.
Belvieu, Texas, for sale at wholesale prices. Natural gas liquids from the
NuStar Joint Venture are sold to the Huntsman Chemicals plant (formerly Rexene
Chemicals) in Midland, Texas.
In processing and marketing natural gas liquids, Enogex competes
against virtually all other gas processors producing and selling natural gas
liquids. Enogex believes it 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 Enogex
specifically, the volume of natural gas processed at their plants is dependent
upon the volume of natural gas gathered by Enogex and other gatherers through
their pipeline systems. Generally, if the volume of natural gas gathered
increases, then the volume of liquids extracted by Enogex should also 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 pooling 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 1999, Resources sold approximately 805
billion Btu of natural gas per day, of which about 37 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. Resources 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
assessment.
17
In its marketing business, Resources encounters 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 in the geographic markets they
serve. For natural gas, those geographic markets are primarily the areas served
by pipelines with which Enogex, Transok or NOARK are 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,
Transok or NOARK are billed at the same rates charged for comparable third-party
transportation.
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." During 1999, Resources had approximately 2.0 million Mwh of power sales.
Resources acts as OG&E's natural gas purchasing arm for the natural gas fuel
requirements of the OG&E power stations. Additionally, since March 1999,
virtually all of the Company's surplus power sales activity has been performed
by Resources.
Exploration 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, 1999, Exploration had interests in
240 active wells and estimated proved reserves of 95,086 MMcfe. The standardized
measure of discounted future net cash flow with related Section 29 tax credits
of Exploration's proved reserves was $56.5 million at December 31, 1999. 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.
18
FINANCE AND CONSTRUCTION
The Company generally meets its cash needs through internally generated
funds, short-term borrowings and permanent financing. Cash flows from operations
have enabled the Company to internally generate the required funds to satisfy
construction expenditures. Additional capital expenditures, primarily to fund
the acquisition of Transok, were funded temporarily through revolving credit.
Management expects that internally generated funds will be adequate
over the next three years to meet the Company's anticipated construction
expenditures. The primary capital requirements for 2000 through 2002 are
estimated as follows:
(dollars in millions) 2000 2001 2002
- -----------------------------------------------------------------------------
Electric utility construction
expenditures including AFUDC............ $109.0 $100.0 $100.0
Non-utility construction expenditures
and pending acquisitions................ 141.9 71.3 50.6
Maturities of long-term debt.............. 169.0 2.0 115.0
- -----------------------------------------------------------------------------
Total................................ $419.9 $173.3 $265.6
=============================================================================
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 $1.0 million of the Company's
construction expenditures budgeted for 2000 are to comply with environmental
laws and regulations. OG&E's construction program was developed to support an
anticipated peak demand growth of one to two percent annually and to maintain
minimum capacity reserve margins as stipulated by the Southwest Power Pool. See
"Electric Operations - Rate Structure, Load Growth and Related Matters."
OG&E intends to meet its customers' increased electricity needs during
the foreseeable future primarily by maintaining the reliability and increasing
the utilization of existing capacity. OG&E's current resource strategy includes
the reactivation of existing plants and the addition of peaking resources. OG&E
does not anticipate the need for another base-load plant in the foreseeable
future.
The 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. At December
31, 1999, the Company had in place a line of credit for up to $200 million, of
which $100 million was to expire on January 15, 2000, and the remaining $100
million was to expire on January 15, 2004. In January 2000, the Company's line
of credit was increased to $300 million; with $200 million to expire on January
15, 2001 and $100 million to expire on January 15, 2004. The maximum amount of
outstanding short-term borrowings during 1999 was $198.9 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
19
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
Mid-Continent Power Company ("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 $44.4 million during 2000, compared to
approximately $43.5 million utilized in 1999. Approximately $1.0 million of the
Company's construction expenditures budgeted for 2000 are to comply with
environmental laws and regulations. The Company continues to evaluate its
environmental management systems to ensure compliance with existing and proposed
environmental legislation and regulations and to better position itself in a
competitive market.
As required by Title IV of the Clean Air Act Amendments of 1990
("CAAA"), OG&E has completed installation and certification of all required
continuous emissions monitors ("CEMs") at its generating stations. OG&E submits
emissions data quarterly to the Environmental Protection Agency ("EPA") as
required by the CAAA. Phase II sulfur dioxide ("SO2") emission requirements will
affect OG&E beginning in the year 2000. Based on current information, OG&E
believes it can meet the SO2 limits without additional capital expenditures. In
1999, OG&E emitted 54,845 tons of SO2.
With respect to the nitrogen oxide ("NOx") regulations of Title IV of
the CAAA, OG&E committed to meeting a 0.45 lbs/mmbtu NOx emission level in 1997
on all coal-fired boilers. As a result, 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 from its coal-fired boilers for
1999 was 0.37 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 $0.4 million in fees in
1999.
20
Other potential air regulations have emerged that could impact OG&E. By
December 15, 2000 the EPA is expected to decide whether or not to regulate
mercury emissions from coal-fired utility boilers. If the decision is made to
regulate them, limits on the amount of mercury emitted are expected to be
proposed by December 2003 with company compliance required by 2008.
In 1997, EPA finalized revisions to the ambient ozone and particulate
standards. However the standards were challenged in court and the ozone standard
was subsequently remanded back to EPA for further consideration. EPA has
appealed the decision to the US Supreme Court. If the proposed standard is
upheld then it is likely that Tulsa and Oklahoma counties will fail to meet the
new standard for ozone. In addition, EPA projects that Muskogee, Kay, Tulsa and
Comanche counties in Oklahoma would fail to meet the standard for particulate
matter. If reductions are required in Muskogee, Kay and Oklahoma counties,
significant capital expenditures could be required by OG&E.
EPA has issued regulations concerning regional haze. This regulation is
intended to protect visibility in national parks and wilderness areas throughout
the United States. In Oklahoma, the Wichita Mountains would be the only area
covered under the regulation. Emissions of sulfates and nitrate aerosols (both
emitted from coal-fired boilers) can lead to the degradation of visibility. It
is possible that controls on sources hundreds of miles away from the affected
area may be required. EPA and the states will perform studies of the areas to
determine what if any controls are needed in Oklahoma. Both Sooner and Muskogee
Generating Stations could face significant capital expenditures if reductions
are required.
In December 1997, the United States was a signatory to the Kyoto
Protocol for the reduction of greenhouse gases that contribute to global
warming. The U.S. committed to a 7 percent reduction from the 1990 levels. If
the Senate ratifies the Kyoto Protocol, this reduction could have a significant
impact on 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 1999, the Company obtained refunds of approximately
$355,225 from its recycling efforts. This figure does not include the additional
savings gained through the reduction and/or avoidance of disposal costs and the
reduction in material purchases due to reuse of existing materials. Similar
savings are anticipated in future years.
OG&E has received renewal of all of its Oklahoma Pollution Discharge
Elimination System ("OPDES") permits for all facilities except one, which is
pending regulatory action. All of the renewed permits issued to date offer
greater operational flexibility than those in the past. In addition, OG&E has
made application for a new OPDES permit to cover Gas Turbine generating units
currently being constructed at one of our existing power plants. No problems are
foreseen in the ultimate regulatory approval of this permit.
OG&E 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, one OG&E facility could be subjected to costly treatment and/or
facility reconfiguration requirements. The State has approved the request and
EPA, in their review of Oklahoma's Water Quality Standards, has not disapproved
this issue.
21
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 has been identified as having
been contaminated by historical operations. Remedial options based on the future
use of this site are being pursued with appropriate regulatory agencies. The
cost of these actions has not had and is not anticipated to have a material
adverse impact on the Company's financial position or results of operations.
EMPLOYEES
The Company and its subsidiaries had 3,074 employees at December 31,
1999.
22
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 5,513 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 517.0
2 Gas 1973 505.0
3 Gas 1975 496.0 1,518
Muskogee 3 Gas 1956 171.0
4 Coal 1977 515.0
5 Coal 1978 478.0
6 Coal 1984 488.0 1,652
Sooner 1 Coal 1979 500.0
2 Coal 1980 512.0 1,012
Horseshoe 6 Gas 1958 171.0
Lake 7 Gas 1963 234.0
8 Gas 1969 390.0 795
Mustang 1 Gas 1950 58.0 Inactive
2 Gas 1951 57.0 Inactive
3 Gas 1955 118.0
4 Gas 1959 239.0
5 Gas 1971 63.0 420
Conoco 1 Gas 1991 32.0
2 Gas 1991 31.0 63
Arbuckle 1 Gas 1953 74.0 Inactive
Enid 1 Gas 1965 11.0
2 Gas 1965 8.0
3 Gas 1965 12.0
4 Gas 1965 12.0 43
Woodward 1 Gas 1963 10.0 10
-----------
Total Active Generating Capability (all stations) 5,513
===========
23
At December 31, 1999, OG&E's transmission system included: (i) 65
substations with a total capacity of approximately 15.5 million kVA and
approximately 3,997 structure miles of lines in Oklahoma; and (ii) six
substations with a total capacity of approximately 1.9 million kVA and
approximately 241 structure miles of lines in Arkansas. OG&E's distribution
system included: (i) 301 substations with a total capacity of approximately 4.2
million kVA, 20,205 structure miles of overhead lines, 1,700 miles of
underground conduit and 6,924 miles of underground conductors in Oklahoma; and
(ii) 30 substations with a total capacity of approximately 737,500 kVA, 1,684
structure miles of overhead lines, 186 miles of underground conduit and 397
miles of underground conductors in Arkansas.
Substantially all of 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 and its subsidiaries own: (i) approximately 8,229 miles of
intrastate transmission and gathering lines in the states of Oklahoma and Texas;
(ii) 13 natural gas processing plants with a capacity to process over one
billion cubic feet per day ("bcfd"), all located in Oklahoma; (iii) 75 percent
interest in NOARK Pipeline System L.P., which consists of 925 miles of
interstate transmission and gathering pipelines, located in eastern Oklahoma and
Arkansas; (iv) an 18 billion cubic feet ("bcf") gas storage field in Oklahoma
with a withdrawal capacity of 450 million cubic feet per day ("mmcfd"); (v)
leased capacity of five bcf of gas storage in Oklahoma with a withdrawal
capacity of 400 mmcfd; (vi) an 80 percent interest in the NuStar Joint Venture,
which includes a 66.67 percent interest in the 110 mmcfd capacity Benedum
processing plant, a 100 percent interest in a smaller 30 mmcfd by-pass plant,
over 185 miles of gathering pipelines and 52 miles of NGL pipeline, all located
in the Permian Basin of West Texas; and (vii) 100 percent of the Belvan Corp.,
which consists of a natural gas processing plant with a capacity of process 15
mmcfd, a sulfur recovery plant, and an eight mile NGL pipeline, and 260 miles of
gathering lines in West Texas.
During the three years ended December 31, 1999, the Company's gross
property, plant and equipment additions approximated $1.4 billion and gross
retirements approximated $132.6 million. These additions were provided by
internally generated funds from operating cash flows, permanent financing and
short-term borrowings. The additions during this three-year period amounted to
approximately 26.3 percent of total property, plant and equipment at
December 31, 1999.
ITEM 3. LEGAL PROCEEDINGS.
- -------------------------
1. On July 8, 1994, an employee of OG&E filed a lawsuit in state court
against OG&E in connection with OG&E's VERP. The case was removed to the U.S.
District Court in Tulsa, Oklahoma. On August 23, 1994, the trial court granted
OG&E's Motion to Dismiss Plaintiff's Complaint in its entirety.
On September 12, 1994, Plaintiff, along with two other Plaintiffs,
filed an Amended Complaint alleging substantially the same allegations, which
were in the original complaint. The action was filed as a class action, but no
motion to certify a class was ever filed. Plaintiffs want credit, for retirement
purposes, for years they worked prior to a pre-ERISA (1974) break in service.
They allege violations of ERISA, the Veterans Reemployment Act, Title VII, and
the Age Discrimination in Employment Act. State law claims, including one for
intentional infliction of emotional distress, are also alleged.
On October 10, 1994, Defendants filed a Motion to Dismiss Counts II,
IV, V, VI and VII of Plaintiffs' Amended Complaint. With regard to Counts I and
III, Defendants filed a Motion for Summary Judgment on January 18, 1996. On
September 8, 1997, the United States Magistrate Judge recommended
24
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 judgment for OG&E. Plaintiffs filed an appeal with the Tenth Circuit
Court of Appeals. In August 1999, the Tenth Circuit affirmed in all respects the
District Courts' decision dismissing Plaintiff's case and entering judgment for
OG&E. Since the Plaintiffs have failed to file a timely writ of certiorari to
the U.S. Supreme Court, the Company considers this case closed.
2. On January 11, 1993, OG&E received a Section 107 (a) Notice Letter
from the EPA, Region VI, as authorized by the CERCLA, 42 USC Section 9607 (a),
concerning the Double Eagle Refinery Superfund Site located at 1900 NE First
Street in Oklahoma City, Oklahoma. The EPA has named OG&E and 45 others as PRPs.
Each PRP could be held jointly and severally liable for remediation of this
site.
On February 15, 1996, OG&E elected to participate in the de minimis
settlement of EPA's Administrative Order on Consent. This would limit OG&E's
financial obligation and also would eliminate its involvement in the design and
implementation of the site remedy. A third party is currently contesting OG&E's
participation as a de minimis party. Regardless of the outcome of this issue,
OG&E 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.
3. 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, 1; (iv)
discriminatory sales in violation of 79 O.S. 1991, 4; (v) tortious
interference with contract; and (vi) tortious interference with a prospective
economic advantage. On December 21, 1998, the jury awarded Trigen in excess of
$30 million in actual and punitive damages. On February 19, 1999, the trial
court entered judgment in favor of Trigen as follows: (i) $6.8 million for
various antitrust violations, (ii) $4 million for tortious interference with an
existing contract, (iii) $7 million for tortious interference with a prospective
economic advantage and (iv) $10 million in punitive damages. The trial judge, in
a companion order, acknowledged that the portions of the judgment could be
duplicative, that the antitrust amounts could be tripled and that parties should
address these issues in their post-trial motions. On March 5, 1999, OG&E filed
its post trial motions requesting judgment in its favor as a matter of law, a
new trial and a reduction in amount of any judgment to eliminate duplication of
damages. On January 25, 2000, a trial judge rejected OG&E's post-trial motions
to reverse the jury verdict or to grant OG&E a new trial. The judge did,
however, reduce the original $30 million judgment against OG&E to $20 million.
On February 4, 2000, OG&E filed a notice of appeal. In addition, Trigen has
filed a motion seeking attorneys' fees and costs in an amount over $3 million.
Trigen will not be entitled to attorneys' fees or costs unless it prevails on
appeal. While the outcome of the appeal is uncertain, legal counsel and
management believe that it is not probable that Trigen will ultimately succeed
in preserving the verdicts or judgment. Accordingly, the Company has not accrued
any loss associated with the damages awarded. The Company believes that the
ultimate resolution of this case will not have a material adverse effect on the
Company's consolidated financial position or results of operations.
4. 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
25
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 (i)
the Mayor of Enid and the City Council breached their fiduciary duty to the
public and violated Article 10, Section 17 of the Oklahoma Constitution by
allegedly "gifting" to OG&E the option to acquire OG&E's electric system when
the City Council approved the new franchise by Ordinance No. 97-30; (ii) the
subsequent approval of the new franchise by the electorate of the City of Enid
at the November 18, 1997, franchise election cannot cure the alleged breach of
fiduciary duty or the alleged constitutional violation; (iii) violations of the
Oklahoma Open Meetings Act occurred and that such violations render the
resolution approving Ordinance No. 97-30 invalid; (iv) OG&E's support of the
Enid Citizens' Against the Government Takeover was improper; (v) OG&E has
violated the favored nations clause of the existing franchise; and (vi) 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.
5. On February 19, 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 and various motions for summary judgment. On October 20, 1999, and
October 25, 1999, the trial judge granted Enogex's motions for summary judgment
and entered judgment in favor of Enogex on all claims raised by the Plaintiffs.
The time for Plaintiffs to appeal the trial court's decision has not expired as
of the date of this report. The Company continues to believe that this case is
without merit.
6. United States of America ex rel., Jack J. Grynberg v Enogex Inc.,
Enogex Services Corporation (now, Resources) and OG&E. (United States District
Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.) United
States of America ex rel., Jack J. Grynberg v. Transok Inc. et al. (United
States District Court for the Eastern District of Louisiana, Case No. 97-2089;
United States District Court for the Western District of Oklahoma, Case No.
97-1009M.) On June 15, 1999, the Company was served with Plaintiff's Complaint.
Plaintiff's action is a qui tam action under the False Claims Act. Jack J.
Grynberg, as individual Relator on behalf of the United States Government,
Plaintiff, alleges: (i) each of the named Defendants have improperly and
intentionally mismeasured gas (both volume and BTU content) purchased from
federal and Indian lands which have resulted in the under-reporting and
underpayment of gas royalties owed to the Federal Government; (ii) certain
provisions generally found in gas purchase contracts are improper; (iii)
transactions by affiliated companies are not arms-length; (iv) excess processing
cost deduction; and (v) failure to account for production separated out as a
result of gas processing. Grynberg seeks the following damages: (a) additional
royalties which he claims should have been paid to the Federal Government, some
percentage of which Grynberg, as Relator, may be entitled to recover; (b) treble
damages; (c) civil penalties; (d) an order requiring Defendants to measure the
way Grynberg contends is the better way to do so; (e) interest, costs and
attorneys' fees. Plaintiff has filed over 70 other cases naming over 300 other
defendants in various Federal Courts across the country containing nearly
identical allegations.
26
In qui tam actions, the United States Government can intervene and take
over such actions from the Relator. The Department of Justice, on behalf of the
United States Government, has decided not to intervene in this action or any of
the other Grynberg qui tam actions.
On November 16, 1999, the Multidistrict Litigation Panel ("MDL Panel")
entered its order transferring and consolidating for pretrial purposes
approximately 76 other similar actions filed in nine other Federal Courts. The
consolidated cases are now before the United States District Court for the
District of Wyoming.
On November 17, 1999, the Company filed a motion to dismiss, seeking:
(i) a stay of discovery until after the dispositive motions are resolved; and
(ii) dismissal of the complaint on various basis under the Federal Rules of
Civil Procedure. A number of other defendants adopted the Company's pleadings or
filed similar motions. On December 22, 1999, the Company joined a number of
other defendants in filing Defendants' Statement of Points and Authorities
regarding discovery issues. Grynberg's responses to all motions to dismiss were
filed on January 14, 2000, and the Company's reply and those of other defendants
were filed on February 14, 2000. A hearing on the motions to dismiss was held on
March 17, 2000.
On December 15, 1999, the Court held a Pretrial conference for all
MDL-consolidated cases. A number of issues were discussed at such Pretrial
conference and the above-listed schedule was established. All discovery is
stayed until further order of the Court.
While the Company cannot predict the precise outcome of this
proceeding, the Company believes, at the present time, that this lawsuit is
without merit and intends to vigorously defend this case.
7. On September 28, 1999, the Company was served with an Amended Class
Action Petition filed in United States District Court, State of Kansas by
Quinque Operating Company, on behalf of itself and others, alleging
approximately 200 defendants, including OG&E, Enogex and two subsidiaries of
Enogex, including Transok, have improperly and intentionally mismeasured gas
(both volume and Btu content) purchased from all lands in the United States
except from federal and Indian lands. Plaintiffs claim (i) underpayment by the
Company and all other Defendants of gas royalties claimed to be owed to the
Plaintiffs and the punitive class; (ii) breach of contract; (iii) negligence or
intentional misrepresentation; (iv) civil conspiracy; (v) fraud; and (vi) breach
of fiduciary duty. Plaintiffs seek the following damages: a) actual damages in
excess of $75,000; b) punitive damages; c) certification of the class; and d)
injunction to prevent mismeasurement in the future.
On October 5, 1999, the Company filed its notice with the MDL Panel
advising the MDL Panel that this case involved the same measurement issues and
was a potential tag-along to the Grynberg matter discussed in Item No. 6 above.
Plaintiffs opposed the MDL Panel transfer. The MDL Panel has scheduled a hearing
on the transfer issue for March 30, 2000.
On October 28, 1999, the Company and a number of the Defendants filed a
"Joint Request for Extension or Enlargement of Time to Answer or Otherwise
Respond to the First Amended Class Action filed. On December 1, 1999, the Court
granted the Company, and all other Defendants who requested relief, until thirty
(30) days after the Court rules on Plaintiff's Motion to Remand for the Company
to answer or otherwise plead in this case. There has been no ruling to date on
the Plaintiffs' Motion to Remand.
27
While the Company cannot predict the precise outcome of this
proceeding, the Company believes at the present time that this lawsuit is
without merit and intends to vigorously defend this case.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
- -----------------------------------------------------------
None
28
EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------
The following persons were Executive Officers of the Registrant as of
March 15, 2000:
Name Age Title
- -------------------- --- --------------------------------------
Steven E. Moore 53 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 56 Executive Vice President and
Chief Operating Officer
Roger A. Farrell 47 President and Chief Executive
Officer - Enogex Inc.
James R. Hatfield 42 Senior Vice President,
Chief Financial Officer and
Treasurer
Jack T. Coffman 56 Senior Vice President - Power
Supply - OG&E
Melvin D. Bowen, Jr. 58 Vice President - Power Delivery - OG&E
Michael G. Davis 50 Vice President - Marketing and
Customer Care
Irma B. Elliott 61 Vice President and
Corporate Secretary
Steven R. Gerdes 43 Vice President - Shared
Services
David J. Kurtz 38 Vice President - Business
Development
Donald R. Rowlett 42 Vice President and Controller
Don L. Young 59 Controller Corporate Audits
No family relationship exists between any of the Executive Officers of
the Registrant. Messrs. Moore, Strecker, Hatfield, Davis, Gerdes, Kurtz,
Rowlett, Young and Ms. Elliott are also officers of 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 18, 2000.
29
The business experience of each of the Executive Officers of the
Registrant for the past five years is as follows:
Name Business Experience
- -------------------- ------------------------------------------------------
Steven E. Moore 1996-Present: Chairman of the Board,
President and Chief
Executive Officer
1995-1996: President and Chief
Operating Officer - OG&E
1995: Senior Vice President - Law
and Public Affairs - OG&E
Al M. Strecker 1998-Present: Executive Vice President and
Chief Operating Officer
1996-1998: Senior Vice President
1995-1996: Senior Vice President -
Finance and
Administration - OG&E
Roger A. Farrell 1998-Present: President and Chief Executive
Officer - Enogex Inc.
1997-1998 Executive Vice President -
Enogex Inc.
1995-1997 Vice President - Business
Development - Enogex Inc.
James R. Hatfield 1999-Present: Senior Vice President,
Chief Financial Officer
and Treasurer
1997-1999: Vice President and Treasurer
1995-1997: Treasurer - OG&E
Jack T. Coffman 1999-Present: Senior Vice President -
Power Supply - OG&E
1995-1999: Vice President -
Power Supply - OG&E
Melvin D. Bowen, Jr. 1995-Present: Vice President -
Power Delivery - OG&E
30
Michael G. Davis 1998-Present: Vice President - Marketing
and Customer Care
1995-1998: Vice President -
Marketing and Customer
Services - OG&E
Irma B. Elliott 1996-Present: Vice President and
Corporate Secretary
1995-1996: Corporate Secretary - OG&E
Steven R. Gerdes 1998-Present: Vice President - Shared
Services
1997-1998: Director - Shared Services
1997: Manager - Enterprise Support
1995-1997: Manager - Purchasing and
Material Management -
OG&E
David J. Kurtz 1999-Present: Vice President - Business
Development
1997-1999: Vice President - Business
Development -
Enogex Inc.
1995-1997: Director - Gas Supply -
Enogex Inc.
Donald R. Rowlett 1999-Present: Vice President and Controller
1996-1999: Controller Corporate
Accounting
1995-1996: Assistant Controller - OG&E
Don L. Young 1996-Present: Controller Corporate
Audits
1995-1996: Controller - OG&E
31
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.
1999 1998
----------------------------------------------------------------
Dividend Dividend
Paid High Low Paid High Low
----------------------------------------------------------------
First Quarter $0.3325 $29 1/16 $22 9/16 $0.3325 $28 15/16 $25 11/16
Second Quarter 0.3325 25 15/16 21 13/16 0.3325 28 15/16 26
Third Quarter 0.3325 24 9/16 21 11/16 0.3325 29 9/16 25 5/8
Fourth