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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>
<CAPTION>
TABLE OF CONTENTS
ITEM PAGE
- ---- ----
<S> <C>
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
</TABLE>
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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.
<PAGE>
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:
<TABLE>
<CAPTION>
SALES (Millions of Kwh)
Inc/ Inc/ Inc/
1999 (Dec) 1998 (Dec) 1997 (Dec)
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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%
======= ======= =======
</TABLE>
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.
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<TABLE>
<CAPTION>
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
YEAR ENDED DECEMBER 31
1999 1998 1997
------------- ------------- -------------
<S> <C> <C> <C>
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
</TABLE>
3
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REGULATION AND RATES
OG&E's retail electric tariffs in Oklahoma are regulated by the
Oklahoma Corporation Commission ("OCC"), and in Arkansas by the 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
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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
<PAGE>
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
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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
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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
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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
<PAGE>
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
<PAGE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
</TABLE>
12
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
(dollars in millions) 2000 2001 2002
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
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
=============================================================================
</TABLE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
ITEM 2. PROPERTIES.
- ------------------
OG&E owns and operates an interconnected electric production,
transmission and distribution system, located in Oklahoma and western Arkansas,
which includes eight active generating stations with an aggregate active
capability of 5,513 megawatts. The following table sets forth information with
respect to present electric generating facilities, all of which are located in
Oklahoma:
<TABLE>
<CAPTION>
Unit Station
Year Capability Capability
Station & Unit Fuel Installed (Megawatts) (Megawatts)
- -------------- ---- --------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Seminole 1 Gas 1971 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
===========
</TABLE>
23
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------
The following persons were Executive Officers of the Registrant as of
March 15, 2000:
<TABLE>
<CAPTION>
Name Age Title
- -------------------- --- --------------------------------------
<S> <C> <C>
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.
</TABLE>
29
<PAGE>
<TABLE>
<CAPTION>
The business experience of each of the Executive Officers of the
Registrant for the past five years is as follows:
Name Business Experience
- -------------------- ------------------------------------------------------
<S> <C> <C>
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
</TABLE>
30
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
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
</TABLE>
31
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
- ---------------------------------------------------------
STOCKHOLDER MATTERS.
- -------------------
The Company's Common Stock is listed for trading on the New York and
Pacific Stock Exchanges under the ticker symbol "OGE." Quotes may be obtained in
daily newspapers where the common stock is listed as "OGE Engy" in the New York
Stock Exchange listing table. The following table gives information with respect
to price ranges, as reported in THE WALL STREET JOURNAL as New York Stock
-------------------------
Exchange Composite Transactions, and dividends paid for the periods shown.
<TABLE>
<CAPTION>
1999 1998
----------------------------------------------------------------
Dividend Dividend
Paid High Low Paid High Low
----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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 Quarter 0.3325 23 3/16 18 1/2 0.3325 30 25 15/16
</TABLE>
The number of record holders of Common Stock at December 31, 1999, was
37,233. The book value of the Company's Common Stock at December 31, 1999, was
$13.09.
32
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA.
- -------------------------------
<TABLE>
<CAPTION>
HISTORICAL DATA
1999 1998 1997 1996 1995
---------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS EXCEPT
FOR PER SHARE DATA)
Operating revenues................. $2,172,434 $1,617,737 $1,443,610 $1,387,435 $1,302,037
Operating expenses................. 1,834,269 1,278,280 1,175,160 1,107,989 1,031,073
----------- ----------- ----------- ----------- -----------
Operating income................... 338,165 339,457 268,450 279,446 270,964
Other income and deductions........ 3,317 5,758 5,047 97 800
Interest charges................... 100,279 70,699 66,495 67,984 77,691
----------- ----------- ----------- ----------- -----------
Net income......................... 151,259 165,872 132,550 133,332 125,256
Preferred dividend
requirements..................... --- 733 2,285 2,302 2,316
Earnings available for
common........................... $ 151,259 $ 165,139 $ 130,265 $ 131,030 $ 122,940
=========== =========== =========== =========== ===========
Long-term debt..................... $1,140,532 $ 935,583 $ 841,924 $ 829,281 $ 843,862
Total assets....................... $3,921,334 $2,983,929 $2,765,865 $2,762,355 $2,754,871
Earnings per average common
share............................ $ 1.94 $ 2.04 $ 1.61 $ 1.62 $ 1.52
CAPITALIZATION RATIOS
Common equity...................... 47.20% 52.72% 52.50% 52.26% 51.19%
Cumulative preferred stock......... --- --- 2.63% 2.68% 2.73%
Long-term debt..................... 52.80% 47.28% 44.87% 45.06% 46.08%
INTEREST COVERAGES
Before federal income taxes
(including AFUDC)................ 3.39X 4.84X 4.11X 4.07X 3.48X
(excluding AFUDC)................ 3.38X 4.82X 4.10X 4.06X 3.46X
After federal income taxes
(including AFUDC)................ 2.50X 3.31X 2.98X 2.94X 2.59X
(excluding AFUDC)................ 2.49X 3.30X 2.97X 2.93X 2.57X
====================================================================================================================
</TABLE>
33
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- --------------------------------------------------------------------------------
OF OPERATIONS.
- -------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
OVERVIEW
OGE Energy Corp. (the "Company") reported earnings of $1.94 a share in
1999, a 4.9 percent decrease from $2.04 a share in 1998. The decrease was
primarily the result of lower revenues at Oklahoma Gas and Electric Company
("OG&E") due to milder weather in the OG&E service area, lower recoveries under
the Generation Efficiency Performance Rider ("GEP Rider") and less revenue from
sales to other utilities and power marketers ("off-system sales"). The GEP
Rider, which was implemented in 1997, allows OG&E to retain part of the fuel
savings achieved through cost efficiencies and is discussed in more detail
below. The decrease in earnings was partially offset by significantly higher
earnings at the Company's Enogex Inc. natural gas pipeline business, and
benefits resulting from the Company repurchasing 3 million shares of its common
stock on January 15, 1999.
The 1998 increase in earnings to $2.04 a share from $1.61 a share in
1997 was primarily the result of higher revenues at OG&E due to warmer weather,
the GEP Rider, higher margin off-system sales, customer growth and lower
operation and maintenance expense. The increase in earnings in 1998 was
partially offset by lower earnings at Enogex Inc. and its subsidiaries
("Enogex").
<TABLE>
<CAPTION>
Percent Change
From Prior Year
---------------
(THOUSANDS EXCEPT PER SHARE AMOUNTS) 1999 1998 1997 1999 1998
==================================================================================================
<S> <C> <C> <C> <C> <C>
Operating revenues...................... $2,172,434 $1,617,737 $1,443,610 34.3 12.1
Earnings available for common stock..... $ 151,259 $ 165,139 $ 130,265 (8.4) 26.8
Average shares outstanding.............. 77,916 80,772 80,745 (3.5) ---
Earnings per average common share....... $ 1.94 $ 2.04 $ 1.61 (4.9) 26.7
Earnings per average common share -
assuming dilution..................... $ 1.94 $ 2.04 $ 1.61 (4.9) 26.7
Dividends paid per share................ $ 1.33 $ 1.33 $ 1.33 --- ---
==================================================================================================
</TABLE>
The Company serves as the parent holding company to OG&E, Enogex and
OGE Energy Capital Trust I, a financing trust established in 1999. This holding
company structure is intended to provide greater flexibility, allowing the
Company to take advantage of opportunities in an increasingly competitive
business environment and to clearly separate the Company's electric utility
business from its non-utility businesses. Because OG&E is the Company's
principal subsidiary, the Company's financial results and condition are
substantially dependent at this time on the financial results and condition of
OG&E.
The following discussion and analysis presents factors which had a
material effect on the operations and financial position of the Company and its
subsidiaries during the last three years and should be read in conjunction with
the Consolidated Financial Statements and Notes thereto. Average shares
outstanding and all per share amounts have been restated to reflect the
two-for-one stock split that occurred in June 1998. Trends and contingencies of
a material nature are discussed to the extent known and considered relevant.
34
<PAGE>
The dividend payout ratio (expressed as a percentage of earnings
available for common shareholders) was 69 percent in 1999 as compared to 65
percent in 1998, within the Company's desired dividend payout ratio of 75
percent or below based on the current business environment. Future dividend
action will be dependent primarily on two factors. First, the appropriate payout
ratio will be determined by the pace and structure of the deregulation of the
electric utility business. Second, the payout rates will continue to be based on
current and anticipated operating results. On a positive note, the Staff of the
Oklahoma Corporation Commission reported in OG&E's recent performance-based rate
filing that OG&E's electric rates as a whole were appropriate and did not
warrant a general rate review, which in the Company's judgment, virtually
eliminates the likelihood of an adverse general rate case in Oklahoma prior to
the start of deregulation.
The Company's regulated utility business has been and will continue to
be affected by competitive changes to the utility industry. Significant changes
already have occurred in the wholesale electric markets at the Federal level and
significant changes are expected at the retail level in the states served by
OG&E. In Oklahoma, legislation was passed in 1997 to provide for the orderly
restructuring of the electric industry with the goal to provide retail customers
with the ability to choose their generation suppliers by June 30, 2002. 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. These developments at the
federal and state levels are described in more detail below under "Regulation;
Competition."
On July 1, 1999, the Company, through Enogex, completed its largest
acquisition in its history by acquiring Tejas Transok Holding, L.L.C. and its
subsidiaries ("Transok"), a gatherer, processor and transporter of natural gas
in Oklahoma and Texas. Transok's principal assets include approximately 4,900
miles of natural gas pipelines in Oklahoma and Texas with a capacity of
approximately 2.6 billion cubic feet per day and 18 billion cubic feet of
underground natural gas storage. Transok also owns 9 gas processing plants,
which produced approximately 26,000 barrels per day of natural gas liquids in
1998. Enogex purchased Transok for $710.3 million, which includes assumption of
$173 million of long-term debt. Integration of Transok's operations continues on
schedule and operation of the combined natural gas pipelines turned accretive to
OGE Energy's earnings in the fourth quarter, earlier than previously expected.
Transok posted net income of $3.8 million in the fourth quarter of 1999. While
$20 million in synergies were expected with the acquisition, about $22 million
in synergies already have been realized or identified and further improvement is
possible in the coming year.
Forward-Looking Statements
Except for the historical statements contained herein, the matters
discussed in the following discussion and analysis, are forward-looking
statements that are subject to certain risks, uncertainties and assumptions.
Such forward-looking statements are intended to be identified in this document
by the words "anticipate", "estimate", "objective", "possible", "potential" and
similar expressions. Actual results may vary materially. Factors that could
cause actual results to differ materially include, but are not limited to:
general economic conditions, including their impact on capital expenditures;
business conditions in the energy industry; competitive factors; unusual
weather; regulatory decisions; and the other risk factors listed in the reports
filed by the Company with the Securities and Exchange Commission.
35
<PAGE>
RESULTS OF OPERATIONS
REVENUES
<TABLE>
<CAPTION>
Percent Change
From Prior Year
---------------
(THOUSANDS) 1999 1998 1997 1999 1998
===================================================================================================
<S> <C> <C> <C> <C> <C>
Sales of electricity to OG&E customers... $1,258,950 $1,274,643 $1,168,663 (1.2) 9.1
Off-system sales......................... 27,894 37,435 23,027 (25.5) 62.6
Enogex................................... 885,512 304,694 251,575 190.6 21.1
Miscellaneous............................ 78 965 345 (91.9) 179.4
- ----------------------------------------------------------------------------------
Total operating revenues............... $2,172,434 $1,617,737 $1,443,610 34.3 12.1
===================================================================================================
System megawatt-hour sales............... 23,468,130 23,642,599 22,182,992 (0.7) 6.6
Off-system megawatt-hour sales........... 374,027 727,601 1,201,933 (48.6) (39.5)
- ----------------------------------------------------------------------------------
Total megawatt-hour sales.............. 23,842,157 24,370,200 23,384,925 (2.2) 4.2
===================================================================================================
</TABLE>
In 1999, approximately 59 percent of the Company's revenues consisted
of regulated sales of electricity as a public utility, while the remaining 41
percent were provided by the non-utility operations of Enogex. Revenues from
sales of electricity are somewhat seasonal, with a large portion of the
Company's annual electric revenues occurring during the summer months when the
electricity needs of its customers increase. Enogex's primary operations consist
of gathering and processing natural gas, transporting natural gas through its
pipelines in Oklahoma, Arkansas and Texas for various customers (including
OG&E), marketing electricity, natural gas and natural gas liquids and investing
in the drilling for and production of natural gas and crude oil. Actions of the
regulatory commissions that set OG&E's electric rates will continue to affect
the Company's financial results. The commissions also have the authority to
examine the appropriateness of OG&E's recovery from its customers of fuel costs,
which include the transportation fees that OG&E pays Enogex for transporting
natural gas to OG&E's generating units. See "Regulation; Competition" and Note
11 of Notes to Consolidated Financial Statements for a discussion of the impact
of the Oklahoma Corporation Commission ("OCC") rate order dated
February 11, 1997, on these transportation fees.
Operating revenues increased $554.7 million or 34.3 percent during
1999, due to a significant increase in revenue from Enogex. In 1999, Enogex
consolidated revenues increased $580.8 million or 190.6 percent, primarily due
to a significant increase in sales volumes and rising prices in natural gas and
natural gas liquids, the acquisition of Transok in July 1999 ($274.9 million)
and increased power marketing sales ($18.5 million).
The increased revenues from Enogex were partially offset by decreased
revenues at OG&E. Revenues at OG&E decreased $25.2 million or 1.9 percent
primarily due to a decrease in kilowatt-hour sales to OG&E customers ("system
sales") and off-system sales, both of which were higher in 1998 because of the
record heat of 1998. Lower recoveries under the GEP Rider also contributed to
lower revenues at OG&E.
On February 11, 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
36
<PAGE>
test year ended December 31, 1995). Of the $50 million rate reduction,
approximately $45 million became effective on March 5, 1997, and the remaining
$5 million became effective March 1, 1998. This $50 million rate reduction was
in addition to the $15 million rate reduction that was effective January 1,
1995. The 1997 Order also directed OG&E to transition to competitive bidding of
its gas transportation requirements, currently met by Enogex, no later than
April 30, 2000, and set annual compensation for the transportation services
provided by Enogex to OG&E at $41.3 million until competitively-bid gas
transportation begins. The $41.3 million included $12.8 million associated with
the amortization of the acquisition premium paid by OG&E when it acquired Enogex
in 1986. Such premium was fully recovered at March 1, 2000, and as a result, the
$41.3 million annual rate will be lowered to $28.5 million annually.
The 1997 Order also established the 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 is less than
96.261 percent of the average of the other specified utilities. If OG&E's fuel
cost exceeds 103.739 percent of the stated average, OG&E will not be allowed to
recover one-third of the fuel costs above that amount from Oklahoma customers.
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 Federal Energy Regulatory Commission ("FERC"). The GEP
Rider is revised effective July 1 of each year to reflect any changes in the
relative annual cost of fuel reported for the preceding calendar year. For 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.
During 1998, revenues increased $174.1 million or 12.1 percent.
Revenues at OG&E increased $120.4 million or 10.1 percent and at Enogex
increased $53.1 million or 21.1 percent. In 1998, OG&E revenues increased
primarily due to higher system sales from warmer weather, the GEP Rider, higher
off-system sales and customer growth. Kilowatt-hour sales by OG&E to other
utilities decreased 39.5 percent in 1998; however, the summer heat drove prices
of this off-system electricity to record levels, increasing operating revenues
approximately $14.4 million in 1998 and at margins significantly higher than had
been experienced in the past. There can be no assurance that such margins on
future off-system sales will occur again.
Enogex revenues increased in 1998 primarily as a result of significant
increases in the volumes of natural gas sold through its gas marketing
activities ($17.2 million), gas transportation services ($7.0 million) and
marketing of electricity ($46.3 million). These increases were partially offset
by a decrease in natural gas liquids processed and sold ($17.4 million). The
increased gas-related revenues were attributable primarily to significantly
higher volumes sold which more than offset a decrease in sales prices as such
commodity prices were depressed. Other factors contributing to the revenue
increases were the acquisitions in 1998 of the Noark Pipeline and Ozark
Pipeline, which are described below. The increased electricity-related revenues
were due to the expansion in 1998 into the marketing of electricity.
37
<PAGE>
EXPENSES AND OTHER ITEMS
<TABLE>
<CAPTION>
Percent Change
From Prior Year
---------------
(DOLLARS IN THOUSANDS) 1999 1998 1997 1999 1998
==================================================================================================
<S> <C> <C> <C> <C> <C>
Fuel .................................... $ 309,327 $ 315,194 $ 277,806 (1.9) 13.5
Purchased power.......................... 249,203 240,542 222,464 3.6 8.1
Gas and electricity purchased for
resale (Enogex)........................ 672,281 216,432 172,764 210.6 25.3
Other operation and maintenance.......... 382,235 305,106 311,337 25.3 (2.0)
Depreciation and amortization............ 165,041 149,818 142,632 10.2 5.0
Taxes other than income.................. 56,182 51,188 48,157 9.8 6.3
- ----------------------------------------------------------------------------------
Total operating expenses............. $1,834,269 $1,278,280 $1,175,160 43.5 8.8
- ----------------------------------------------------------------------------------
Total other income (expenses)........ $ (96,962) $ (64,941) $ (61,448) 49.3 5.7
- ----------------------------------------------------------------------------------
Provision for income taxes........... $ 89,944 $ 108,644 $ 74,452 (17.2) 45.9
==================================================================================================
</TABLE>
Total operating expenses increased $556.0 million or 43.5 percent in
1999, primarily due to a significant increase in sales volumes, rising prices
for natural gas and natural gas liquids, the mid-year acquisition of Transok by
Enogex, and due to the record numbers and severity of tornadoes that damaged
OG&E facilities.
Enogex's gas and electricity purchased for resale pursuant to its
energy-marketing operations increased $455.8 million or 210.6 percent for 1999
as compared to $43.7 million or 25.3 percent for 1998. The 1999 increase was due
to a significant increase in sales volumes of natural gas, the acquisition of
Transok ($173.3 million), and increased power marketing sales. The 1998 increase
was due to a significant increase in sales volumes of natural gas which more
than offset a decrease in sales prices due to depressed commodity prices, and
the expansion into the marketing of electricity.
Other operation and maintenance increased $77.1 million or 25.3 percent
in 1999 primarily because of expansion activities at Enogex ($66.1 million) and
higher bad debt expense at OG&E ($5.2 million). These increases were partially
offset by reduced general corporate expenses ($2.7 million). In 1998, other
operation and maintenance decreased $6.2 million or 2.0 percent primarily
because of decreases at OG&E in post retirement medical costs ($3.8 million),
lower bad debt expense ($3.0 million), completion in February 1997 of the
amortization of the $48.9 million regulatory asset established in connection
with OG&E's 1994 workforce reduction ($3.8 million) and lower general corporate
expenses ($4.5 million). These decreases were partially offset by expansion
activities at Enogex ($8.4 million).
In 1999, depreciation and amortization increased $15.2 million or 10.2
percent, reflecting increased depreciable plant, primarily property of Transok
($10.0 million). The increase in 1998 reflects higher levels of depreciable
plant.
In 1999, taxes decreased $13.7 million or 8.6 percent primarily due to
the reduction of pre-tax income from 1998 to 1999. In 1998, taxes increased
$37.2 million or 30.4 percent due to significantly higher pre-tax income.
38
<PAGE>
OG&E's purchased power costs increased $8.7 million or 3.6 percent in
1999 due in large part to emergency purchases in the aftermath of tornadoes, on
May 3, 1999 and June 1, 1999, which inflicted heavy damage to the OG&E power
supply, transmission and delivery systems. In 1999, the cost of purchased energy
per kwh increased 8.7 percent. During 1998, purchased power costs increased
$18.1 million or 8.1 percent primarily due to a 13 percent increase in the
quantities purchased. During 1998, OG&E also began purchasing power from
Mid-Continent Power Company ("MCPC"). Payments to MCPC in 1998 were
approximately $8 million. MCPC is a qualified cogeneration facility from which
OG&E is required to purchase peaking capacity through 2007. As required by the
Public Utility Regulatory Policy Act ("PURPA"), OG&E is currently purchasing
power from qualified cogeneration facilities.
Interest expense increased $29.6 million or 41.8 percent in 1999
primarily due to higher interest charges at Enogex and costs associated with
increased short-term debt incurred to finance the Transok acquisition.
The increase in interest expense for 1998 was attributable to an
increase in the average daily balance of short-term debt. Interest on long-term
debt decreased as a result of OG&E refinancing $100.0 million of long-term debt
at favorable rates. The resulting savings was partially offset by Enogex issuing
$85.7 million of long-term debt.
OG&E's generating capability is fairly evenly divided between coal and
natural gas and provides for flexibility to use either fuel to the best economic
advantage for OG&E and its customers. In 1999, fuel costs decreased $5.9 million
or 1.9 percent primarily due to a 3.4 percent decrease in total energy generated
which offset a 1.9 percent increase in the average cost of fuel burned for
generation of electricity. During 1998, fuel costs increased due to a modest
increase in total generation and a slight increase in the average cost of fuel
burned.
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are passed through to OG&E's electric customers through
automatic fuel adjustment clauses. The automatic fuel adjustment clauses are
subject to periodic review by the OCC, the Arkansas Public Service Commission
("APSC") and the FERC. The OCC, the APSC and the FERC have authority to review
the appropriateness of gas transportation charges or other fees OG&E pays
Enogex, which OG&E seeks to recover through the fuel adjustment clause or other
tariffs. Also, as explained below, the OCC Staff recently filed an application
to review issues under OG&E's fuel adjustment clause in Oklahoma.
39
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
The primary capital requirements for 1999 and as estimated for 2000
through 2002 are as follows:
<TABLE>
<CAPTION>
(DOLLARS IN MILLIONS) 1999 2000 2001 2002
================================================================================
<S> <C> <C> <C> <C>
Electric utility construction
expenditures including AFUDC........... $101.3 $109.0 $100.0 $100.0
Non-utility construction expenditures
and acquisitions....................... 611.6 141.9 71.3 50.6
Maturities of long-term debt............. 17.0 169.0 2.0 115.0
- --------------------------------------------------------------------------------
Total................................ $729.9 $419.9 $173.3 $265.6
================================================================================
</TABLE>
The Company's primary needs for capital are related to construction of
new facilities to meet anticipated demand for OG&E's utility service, to replace
or expand existing facilities in OG&E's electric utility business, to replace or
expand existing facilities in its non-utility businesses, to acquire new
non-utility facilities or businesses and, to some extent, to satisfy maturing
debt. The Company generally meets its cash needs through a combination of
internally generated funds, short-term borrowings and permanent financing.
1999 CAPITAL REQUIREMENTS AND FINANCING ACTIVITIES
Capital requirements were $729.9 million in 1999. A substantial portion
of this was related to the acquisition of Transok. Approximately $2.0 million of
the 1999 capital requirements were to comply with environmental regulations.
This compares to capital requirements of $261.2 million in 1998, of which $1.0
million was to comply with environmental regulations.
During 1999, the Company's sources of capital were internally generated
funds from operating cash flows, permanent financing and short-term borrowings.
Variations in accounts receivable and accounts payable are not generally
significant indicators of the Company's liquidity, as such variations are
primarily attributable to fluctuations in weather in OG&E's service territory,
which has a direct effect on sales of electricity.
Short-term borrowings were used during 1999 to meet temporary cash
requirements. At December 31, 1999, the Company had outstanding short-term
borrowings of $589.1 million, of which approximately $345 million pertained to
debt incurred to finance the acquisition of Transok. Through the recent
financing described below by Enogex in January 2000, the short-term debt of the
Company at January 31, 2000 was $214.1 million.
On July 1, 1999, Enogex completed its acquisition of Transok for
approximately $710.3 million, which included assumption of $173 million of
long-term debt. The purchase of Transok was temporarily funded through a $560
million revolving bank credit agreement. On October 21, 1999, the Company,
through a new financing subsidiary trust, issued $200 million of 8.375 percent
trust preferred securities which mature October 15, 2039, and all of the
proceeds were used to repay a portion of outstanding borrowings under the
revolving bank credit agreement implemented in connection with the acquisition
of Transok. To repay the balance of the temporary short-term debt associated
with the Transok acquisition
40
<PAGE>
($345 million), on January 14, 2000, Enogex sold $400 million of 8.125 percent
senior unsecured notes due January 15, 2010. Enogex entered into a series of
interest rate swap agreements to manage interest costs associated with this $400
million issue. The effect of these swap agreements reduces the overall effective
interest rate from 8.125 percent to 6.6875 percent during the first year. The
balance of the proceeds from the sale was used for general corporate purposes.
On September 1, 1999, Enogex retired $15 million principal amount of
6.75 percent medium-term notes due September 1, 1999. Enogex assumed this debt
as a current liability in the acquisition of Transok in July 1999.
On January 15, 1999, the Company repurchased 3 million shares of its
Common Stock under an Advanced Share Repurchase Agreement with CIBC Oppenheimer
Corp. The purchase price was $80.4 million or $26.8125 per share, the closing
price on January 15, 1999. Under the terms of this Advanced Share Repurchase
Agreement, the Company agreed to bear the risk of increases and the benefit of
decreases on the price of the Common Stock until CIBC Oppenheimer Corp.
replaced, through open market purchases or privately negotiated transactions,
the shares sold to the Company. The Company previously announced, in November
1998, plans to repurchase up to 6 million shares of its Common Stock over the
succeeding two years. However, the Company has chosen not to repurchase any
additional shares of its Common Stock at this time and this Advanced Share
Repurchase Agreement was terminated on January 14, 2000.
FUTURE CAPITAL REQUIREMENTS
The Company's construction program for the next several years does not
include additional base-load generating units. Rather, to meet the increased
electricity needs of OG&E's electric utility customers during the foreseeable
future, OG&E will concentrate on maintaining the reliability, increasing the
utilization of existing capacity and increasing demand-side management efforts.
Approximately $1.0 million of the Company's construction expenditures budgeted
for 2000 are to comply with environmental laws and regulations.
On October 22, 1998, Enogex entered into an option agreement to
purchase two gas turbine generators for use in normal operations for
approximately $27.5 million. This agreement was transferred to the Company in
September 1999. These two generators produce approximately 50 megawatts of
additional peak-load each. The total cost of this project is expected to be
approximately $47 million. In August 1999, OG&E announced the reactivation of
two of its generators that have been idle for several years. These two
generators together produce approximately 115 megawatts of additional
peak-load. The total cost of this reactivation project is expected to be
approximately $9 million. By June 1, 2000, the Company plans to begin using
these four generators, increasing its electric generating capacity by
approximately 4 percent.
Future financing requirements may be dependent, to varying degrees,
upon numerous factors such as general economic conditions, abnormal weather,
load growth, acquisitions of other businesses, inflation, changes in
environmental laws or regulations, rate increases or decreases allowed by
regulatory agencies, new legislation and market entry of competing electric
power generators.
FUTURE SOURCES OF FINANCING
Management expects that internally generated funds will be adequate
over the next three years to meet anticipated construction expenditures, while
maturities of long-term debt will require permanent financing, with the amount
and type dependent on market conditions at the time. Short-term borrowings
41
<PAGE>
will continue to be used to meet temporary cash requirements. The Company has
the necessary regulatory approvals to incur up to $400 million in short-term
borrowings at any one time. At December 31, 1999, the Company had in place a
line of credit for up to $200 million, $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, $200
million to expire on January 15, 2001, and $100 million to expire on January 15,
2004.
The Company continues to evaluate opportunities to enhance shareowner
returns and achieve long-term financial objectives through acquisitions of
non-utility businesses. Permanent financing could be required for such
acquisitions.
THE YEAR 2000 ISSUE (A NON-EVENT)
There was a great deal of publicity about the Year 2000 ("Y2K") and the
possible problems that information technology systems may have suffered as a
result. As the Year 2000 approached, it was feared that date-sensitive systems
might recognize the Year 2000 as 1900, or not at all, potentially causing
systems, including those of the Company, its customers, suppliers, business
partners and neighboring utilities to process critical financial and operational
information incorrectly, if they were not Year 2000 ready. A failure to identify
and correct any such processing problems prior to January 1, 2000 could have
resulted in material operational and financial risks if the affected systems
either ceased to function or produced erroneous data. However, the Company was
aggressive and did its work well in addressing the risks associated with the Y2K
issue. The Company's goal was to minimize the impact of Y2K and our goal was
accomplished. Y2K was a non-event.
COSTS OF YEAR 2000 ISSUES
With the Company's mainframe conversion in 1994, the SAP Enterprise
Software installations for the financial and customer systems in 1997 and 1999,
respectively, and the Energy Management System replacement in 1999, a number of
Y2K issues were addressed as part of the Company's normal course upgrades to the
information technology systems. These upgrades were already contemplated and
provided additional benefits or efficiencies beyond the Year 2000 aspect. Since
1995, the Company has spent approximately $45 million on the mainframe
conversion, the initial financial enterprise software systems, the customer care
enterprise software installations and the SCADA/EMS replacement.
RISKS OF YEAR 2000 ISSUES
The Company experienced only one minor problem which occurred on New
Year's Day when a computer system in OG&E's Outage Management System showed an
error that was corrected within an hour with a vendor-provided patch. Although
the Company has not experienced any major Y2K problems to date, the Company
believes some risks still exist as it may take a full year to identify and
address all the potential problems in the Company's business systems resulting
from Y2K upgrades, corrections and patches.
CONTINGENCIES
The Company through its subsidiaries is defending various claims and
legal actions, including environmental actions, which are common to its
operations. For a further discussion of these actions, including a lawsuit
involving Trigen-Oklahoma City Energy Corporation, see Note 10 of Notes to
Consolidated Financial Statements. As to environmental matters, OG&E has been
designated as a "potentially responsible party" ("PRP") with respect to two
waste disposal sites to which OG&E sent
42
<PAGE>
materials. Remediation and required monitoring of one of these sites has been
completed. While it is not possible to determine the precise outcome of these
matters, in the opinion of management, OG&E's ultimate liability for these sites
will not be material.
Beginning in 2000, OG&E will be limited in the amount of sulfur dioxide
it will be allowed to emit into the atmosphere. In order to comply with this
limit, the Company has contracted for lower sulfur coal. OG&E believes this
will allow it to meet this limit without additional capital expenditures. With
respect to nitrogen oxides, OG&E continues to meet the current emission
standard. However, regulations on regional haze, the possibility of having a new
ozone ambient standard that Oklahoma will not be able to meet, and Oklahoma's
potential for not being able to meet the new particulate standard, could require
further reductions in sulfur dioxide and nitrogen oxides. If this occurs,
significant capital expenditures and increased operating and maintenance costs
would result.
In 1997, the United States was a signatory to the Kyoto Protocol on
global warming. If ratified by the U.S. Senate, this Protocol could have a
tremendous impact on the Company's operations, by requiring the Company to
significantly reduce the use of coal as a fuel source, since the Protocol would
require a seven percent reduction in greenhouse gas emissions below the 1990
level.
The Oklahoma Department of Environmental Quality's CAAA Title V
permitting program was approved by the EPA in March 1996. By March of 1997, OG&E
had submitted all required permit applications and by December 31, 2000, OG&E
expects to have new Title V permits for all of its major source generating
stations. Air permit fees for generating stations were approximately $0.4
million in 1999 and are estimated to be about the same in 2000.
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, limits on the amount of mercury emitted are expected to be
proposed by December 2003 with the Company's compliance required by 2008. This
could result in significant capital and operating expenditures.
COMPETITION; REGULATION
As previously reported, Oklahoma enacted in April 1997 the Electric
Restructuring Act of 1997 (the "Act"). Various amendments to the Act were
enacted in 1998. If implemented as proposed, the Act will significantly affect
OG&E's future operations.
The purpose of the Act, as set forth therein, is generally to
restructure the electric utility industry to provide for more competition and,
in particular, to provide for the orderly restructuring of the electric utility
industry in Oklahoma in order to allow customers to choose their electricity
suppliers while maintaining the safety and reliability of the electric system in
the state.
The Act directed the Joint Electric Utility Task Force, composed of
seven members from the Oklahoma Senate and seven members from the Oklahoma House
of Representatives, to undertake a study of all relevant issues relating to
restructuring the electric utility industry in Oklahoma and to develop a
proposed electric utility framework for Oklahoma. The study was to be delivered
in several parts. As a result of the 1998 amendments, the 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).
43
<PAGE>
Neither the Oklahoma Tax Commission nor the OCC is authorized to issue
any rules on such matters without the approval of the Oklahoma Legislature.
Other provisions of the Act (i) authorize the Joint Electric Utility Task Force
to retain consultants to study, among other things, the creation of an
independent system operator, (ii) prohibit customer switching prior to July 1,
2002, except by mutual consent, (iii) prohibit municipalities that do not become
subject to the Act, from selling power outside their municipal limits, except
from lines owned on April 25, 1997, (iv) require a uniform tax policy be
established by July 1, 2002 and (v) require out-of-state suppliers of
electricity and their affiliates who make retail sales of electricity in
Oklahoma through the use of transmission and distribution facilities of in-state
suppliers to provide equal access to their transmission and distribution
facilities outside of Oklahoma. The Act was modified during the 1999 session of
the Oklahoma Legislature to clarify certain ambiguities by defining key terms in
the Act.
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.
In April 1999, Arkansas became the 18th state to pass a law calling for
restructuring of the electric utility industry. 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. As required by the new law, the
APSC is in the process of adopting regulations that will implement the new law.
The new law and related regulations will significantly affect OG&E's future
Arkansas operations. OG&E's electric service area includes parts of western
Arkansas, including Fort Smith, the second-largest metropolitan market in the
state.
The OCC also 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.
These efforts to increase competition in the electric industry at the
state level in Oklahoma and Arkansas have been paralleled and even surpassed by
efforts at the federal level to increase competition in the wholesale markets
for electricity. In October 1992, the National Energy Policy Act of 1992
("Energy Act") was enacted. Among many other provisions, the Energy Act is
designed to promote competition in the development of wholesale power generation
in the electric utility industry. It exempts a new class of independent power
producers ("IPPs") from regulation under the Public Utility Holding Company Act
of 1935 and allows the FERC to order wholesale "wheeling" by public utilities to
provide utility and non-utility generators access to public utility transmission
facilities.
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 (1) offer comparable open-access
transmission service for wholesale transactions under a tariff of general
applicability on file at FERC and (2) 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
44
<PAGE>
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.
The Energy Act, Orders 888 and 889, and other FERC policies and
initiatives have had a tremendous impact on the development of a competitive
wholesale power market. Utilities, including OG&E, have increased their own
in-house wholesale marketing efforts and the number of entities with whom they
trade. Moreover, power marketers are an increasingly important presence in the
industry. These entities typically arbitrage wholesale price differentials by
buying power produced by others in one market and selling it in another. IPPs
also are becoming a more significant sector of the electric utility industry. In
both Oklahoma and Arkansas, significant additions of new power plants have been
announced, almost all of it from IPPs.
Notwithstanding these developments in the wholesale power market, FERC
recognized that impediments remained to the achievement of fully competitive
wholesale markets including: (1) engineering and economic inefficiencies
inherent in the current operation and expansion of the transmission grid and (2)
continuing opportunities for transmission owners to discriminate in the
operation of their transmission facilities in favor of their own or affiliated
power marketing activities. Whereas FERC in the past only encouraged utilities
to join and place their transmission systems under the operational control of
independent system operators ("ISOs"), FERC, issued Order 2000 on December 20,
1999, its final rule on regional transmission organizations ("RTOs"). Order 2000
sets out a timetable for every jurisdictional utility (including OG&E) to either
join in an RTO filing, or, alternatively, to submit a filing by October 15, 2000
describing its efforts to join in an RTO, the reasons for not participating in
an RTO proposal and any obstacles to participation, and its plans for further
work toward participation. Public utilities that have already transferred
control of their facilities to a FERC-approved RTO must file with FERC by
January 15, 2001, a statement explaining, among other things, how such RTO has
the minimum characteristics and performs the minimum functions identified by
FERC in the final rule. These minimum characteristics and functions are intended
to have the effect of turning the nation's transmission facilities into
independently operated "common carriers" that offer comparable service to all
would-be-users. Although adopting a voluntary approach towards RTO formation,
FERC stressed that Order 2000 does not preclude it from requiring RTO
participation.
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. OG&E presently intends to
meet its obligations to transfer operational control of its transmission system
to an RTO under Order 2000 and under the new Arkansas deregulation law through
the SPP. The SPP has asked for FERC recognition as an ISO consistent with FERC's
ISO guidelines in its Order 888 and related provisions in Order 2000. The
transfer of operational control of OG&E's transmission system to a FERC-approved
RTO is not expected to impact significantly OG&E's financial results. Yet, it is
expected to increase the markets in which OG&E can sell power at wholesale and,
at the same time, to increase competition in such wholesale markets. As a
low-cost producer of electricity with two of the most efficient power plants in
the country, OG&E expects to remain a competitive supplier of electricity.
As discussed previously, legislation was enacted in Oklahoma and
Arkansas 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
45
<PAGE>
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.
As stated previously, the OCC in its 1997 Order, 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 firms 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 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
OCC 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 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.
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
46
<PAGE>
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.
MARKET RISK
RISK MANAGEMENT
The risk management process established by the Company is designed to
measure both quantitative and qualitative risks in its businesses. A senior risk
management committee has been established to review these risks on a regular
basis. The Company is exposed to market risk, including changes in interest
rates and certain commodity prices.
To manage the volatility relating to these exposures, the Company
enters into various derivative transactions pursuant to the Company's policies
on hedging practices. Derivative positions are monitored using techniques such
as mark-to-market valuation, value-at-risk and sensitivity analysis.
INTEREST RATE RISK
The Company's exposure to changes in interest rates relates primarily
to long-term debt obligations and commercial paper. The Company manages its
interest rate exposure by limiting its variable-rate debt to a certain
percentage of total capitalization and by monitoring the effects of market
changes in interest rates. The Company may utilize interest rate derivatives to
alter interest rate exposure in an attempt to reduce interest rate expense
related to existing debt issues. Interest rate derivatives are used solely to
modify interest rate exposure and not to modify the overall leverage of the debt
portfolio. The fair value of long-term debt is estimated based on quoted market
prices and management's estimate of current rates available for similar issues.
The following table itemizes the Company's long-term debt maturities and the
weighted-average interest rates by maturity date.
<TABLE>
<CAPTION>
=============================================================================================================
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1999
Year-end
(DOLLARS IN MILLIONS) 2000 2001 2002 2003 2004 Thereafter Total Fair Value
- -------------------------------------------------------------------------------------------------------------
Fixed rate debt
Principal amount...... $169.0 $ 2.0 $115.0 $ 14.3 $ 57.8 $818.4 $1,176.5 $1,032.8
Weighted-average
interest rate....... 6.42% 7.15% 7.34% 7.70% 7.20% 7.27% 7.18% ---
Variable-rate debt
Principal amount...... --- --- --- --- --- $135.4 $ 135.4 $ 135.4
Weighted-average
interest rate....... --- --- --- --- --- 3.42% 3.42% ---
=============================================================================================================
</TABLE>
47
<PAGE>
COMMODITY PRICE EXPOSURE
The market risk inherent in the Company's market risk sensitive
instruments and positions is the potential loss in value arising from adverse
changes in the Company's commodity prices.
The prices of natural gas and electricity are subject to fluctuations
resulting from changes in supply and demand. To partially reduce price risk
caused by these market fluctuations, the Company may hedge (through the
utilization of derivatives) a portion of the Company's supply and related
purchase and sale contracts, as well as any anticipated transactions (purchases
and sales). Because the commodities covered by these derivatives are
substantially the same commodities that the Company buys and sells in the
physical market, no special studies other than monitoring the degree of
correlation between the derivative and cash markets, are deemed necessary.
A sensitivity analysis has been prepared to estimate the price exposure
to the market risk of the Company's natural gas and electricity commodity
positions. The Company's daily net commodity position consists of natural gas
inventories, purchased electric capacity, commodity purchase and sales
contracts, and derivative financial and commodity instruments. The fair value of
such position is a summation of the fair values calculated for each commodity by
valuing each net position at quoted futures prices. Market risk is estimated as
the potential loss in fair value resulting from a hypothetical 10 percent
adverse change in such prices over the next 12 months. The results of this
analysis, which may differ from actual results, are as follows for fiscal 2000:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) Wholesale Non-Trading
================================================================================
<S> <C> <C>
Commodity market risk, net................ $ 779 $ 853
================================================================================
</TABLE>
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and for Hedging Activities", with an effective date for
periods beginning after June 15, 1999. In July 1999, the FASB issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133". As a result of SFAS No. 137,
adoption of SFAS No. 133 is now required for financial statements for periods
beginning after June 15, 2000. SFAS No. 133 sweeps in a broad population of
transactions and changes the previous accounting definition of a derivative
instrument. Under SFAS No. 133, every derivative instrument is recorded on the
balance sheet as either an asset or liability measured at its fair value. SFAS
No. 133 requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. The
Company will prospectively adopt this new standard effective January 1, 2001,
and management believes the adoption of this new standard will not have a
material impact on its consolidated financial position or results of operation.
Besides the various existing contingencies herein described, and those
described in Note 10 of Notes to Consolidated Financial Statements, the
Company's ability to fund its future operational needs and to finance its
construction program is dependent upon numerous other factors beyond its
control, such as general economic conditions, abnormal weather, load growth,
inflation, new environmental laws or regulations, and the cost and availability
of external financing.
48
<PAGE>
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
- -------------------------------------------------------------------
See Management's Discussion and Analysis of Financial Condition and
Results of Operations, Market Risk.
49
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
- ---------------------------------------------------
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents.................................... $ 7,271 $ 378 $ 4,257
Accounts receivable - customers, less reserve of $5,270,
$3,342 and $4,507, respectively............................ 263,708 141,235 117,842
Accrued unbilled revenues.................................... 40,200 22,500 36,900
Accounts receivable - other.................................. 10,462 12,902 11,470
Fuel inventories, at LIFO cost............................... 117,185 57,288 49,369
Materials and supplies, at average cost...................... 39,194 29,734 28,430
Prepayments and other........................................ 16,911 31,551 4,489
Accumulated deferred tax assets.............................. 8,729 7,811 6,925
- --------------------------------------------------------------- ----------- ----------- -----------
Total current assets....................................... 503,660 303,399 259,682
- --------------------------------------------------------------- ----------- ----------- -----------
OTHER PROPERTY AND INVESTMENTS, at cost........................ 31,012 31,682 37,898
- --------------------------------------------------------------- ----------- ----------- -----------
PROPERTY, PLANT AND EQUIPMENT:
In service................................................... 5,209,783 4,391,232 4,125,858
Construction work in progress................................ 56,553 50,039 25,799
- --------------------------------------------------------------- ----------- ----------- -----------
Total property, plant and equipment........................ 5,266,336 4,441,271 4,151,657
Less accumulated depreciation............................ 2,024,349 1,914,721 1,797,806
- --------------------------------------------------------------- ----------- ----------- -----------
Net property, plant and equipment............................ 3,241,987 2,526,550 2,353,851
- --------------------------------------------------------------- ----------- ----------- -----------
DEFERRED CHARGES:
Advance payments for gas..................................... 11,800 15,000 10,500
Income taxes recoverable through future rates................ 39,692 40,731 42,549
Other........................................................ 93,183 66,567 61,385
- --------------------------------------------------------------- ----------- ----------- -----------
Total deferred charges..................................... 144,675 122,298 114,434
- --------------------------------------------------------------- ----------- ----------- -----------
TOTAL ASSETS................................................... $3,921,334 $2,983,929 $2,765,865
=============================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
50
<PAGE>
CONSOLIDATED BALANCE SHEETS (Continued)
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt.............................................. $ 589,100 $ 119,100 $ 1,000
Accounts payable............................................. 161,183 96,936 77,733
Dividends payable............................................ 25,889 26,865 27,428
Customers' deposits.......................................... 22,138 23,985 23,847
Accrued taxes................................................ 41,215 30,500 21,677
Accrued interest............................................. 28,191 21,081 20,041
Long-term debt due within one year........................... 169,000 2,000 25,000
Other........................................................ 40,145 35,366 38,518
- --------------------------------------------------------------- ----------- ----------- -----------
Total current liabilities.................................. 1,076,861 355,833 235,244
- --------------------------------------------------------------- ----------- ----------- -----------
LONG-TERM DEBT................................................. 1,140,532 935,583 841,924
- --------------------------------------------------------------- ----------- ----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation....................... 16,686 17,952 62,023
Accumulated deferred income taxes............................ 566,137 531,940 503,952
Accumulated deferred investment tax credits.................. 62,578 67,728 72,878
Other........................................................ 39,161 31,511 15,618
- --------------------------------------------------------------- ----------- ----------- -----------
Total deferred credits and other liabilities............... 684,562 649,131 654,471
- --------------------------------------------------------------- ----------- ----------- -----------
STOCKHOLDERS' EQUITY:
Common stockholders' equity.................................. 441,847 513,614 512,897
Preferred stockholders' equity............................... --- --- 49,266
Retained earnings............................................ 577,532 529,768 472,063
- --------------------------------------------------------------- ----------- ----------- -----------
Total stockholder's equity................................. 1,019,379 1,043,382 1,034,226
- --------------------------------------------------------------- ----------- ----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY..................... $3,921,334 $2,983,929 $2,765,865
=============================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
51
<PAGE>
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
==================================================================================================================
<S> <C> <C> <C>
COMMON STOCK AND RETAINED EARNINGS:
Common stock, par value $0.01 per share;
authorized 125,000,000 shares; and
outstanding 77,863,370, 80,797,539,
and 80,771,834 shares, respectively.............................. $ 779 $ 808 $ 808
Premium on capital stock........................................... 411,068 512,806 512,089
Retained earnings.................................................. 577,532 529,768 472,063
- --------------------------------------------------------------------- ----------- ----------- -----------
Total common stock and retained earnings....................... 1,019,379 1,043,382 984,960
- --------------------------------------------------------------------- ----------- ----------- -----------
CUMULATIVE PREFERRED STOCK:
Par value $20, authorized 675,000 shares - 4%;
zero, zero, and 418,963 shares, respectively..................... --- --- 8,379
Par value $100, authorized 1,865,000 shares-
SERIES SHARES OUTSTANDING
4.20% zero, zero, and 49,750 shares, respectively............ --- --- 4,975
4.24% zero, zero, and 74,990 shares, respectively............ --- --- 7,499
4.44% zero, zero, and 63,200 shares, respectively............ --- --- 6,320
4.80% zero, zero, and 70,925 shares, respectively............ --- --- 7,093
5.34% zero, zero, and 150,000 shares, respectively........... --- --- 15,000
- --------------------------------------------------------------------- ----------- ----------- -----------
Total cumulative preferred stock............................... --- --- 49,266
- --------------------------------------------------------------------- ----------- ----------- -----------
LONG-TERM DEBT:
SERIES DATE DUE
6.375% January 1, 1998........................................ --- --- 25,000
7.125% January 1, 1999........................................ --- --- 12,500
6.250% Senior Notes Series B, October 15, 2000................ 110,000 110,000 110,000
7.125% January 1, 2002........................................ --- --- 40,000
8.625% November 1, 2007....................................... --- --- 35,000
6.500% Senior Notes Series D, July 15, 2017................... 125,000 125,000 125,000
7.300% Senior Notes Series A, October 15, 2025................ 110,000 110,000 110,000
6.650% Senior Notes Series C, July 15, 2027................... 125,000 125,000 125,000
6.500% Senior Notes Series E, April 15, 2028.................. 100,000 100,000 ---
Other bonds-
Var. % Garfield Industrial Authority, January 1, 2025......... 47,000 47,000 47,000
Var. % Muskogee Industrial Authority, January 1, 2025......... 32,400 32,400 32,400
Var. % Muskogee Industrial Authority, June 1, 2027............ 56,000 56,000 56,000
Unamortized premium and discount, net.............................. (2,354) (2,488) (976)
Enogex Inc. notes (Note 6)......................................... 233,486 234,671 150,000
Transok Holding LLC (Note 6)....................................... 173,000 --- ---
Trust Originated Preferred Securities (Note 5)..................... 200,000 --- ---
- --------------------------------------------------------------------- ----------- ----------- -----------
Total long-term debt........................................... 1,309,532 937,583 866,924
Less long-term debt due within one year...................... 169,000 2,000 25,000
- --------------------------------------------------------------------- ----------- ----------- -----------
Total long-term debt (excluding long-term
debt due within one year).................................... 1,140,532 935,583 841,924
- --------------------------------------------------------------------- ----------- ----------- -----------
Total Capitalization................................................. $2,159,911 $1,978,965 $1,876,150
===================================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
52
<PAGE>
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1999 1998 1997
================================================================================================================
<S> <C> <C> <C>
OPERATING REVENUES................................................. $2,172,434 $1,617,737 $1,443,610
- ------------------------------------------------------------------- ----------- ----------- -----------
OPERATING EXPENSES:
Fuel............................................................. 309,327 315,194 277,806
Purchased power.................................................. 249,203 240,542 222,464
Gas and Electricity purchased for resale......................... 672,281 216,432 172,764
Other operation and maintenance.................................. 382,235 305,106 311,337
Depreciation and amortization.................................... 165,041 149,818 142,632
Taxes other than income.......................................... 56,182 51,188 48,157
- ------------------------------------------------------------------- ----------- ----------- -----------
Total operating expenses....................................... 1,834,269 1,278,280 1,175,160
- ------------------------------------------------------------------- ----------- ----------- -----------
OPERATING INCOME................................................... 338,165 339,457 268,450
- ------------------------------------------------------------------- ----------- ----------- -----------
OTHER INCOME (EXPENSES):
Interest charges................................................. (100,279) (70,699) (66,495)
Other, net....................................................... 3,317 5,758 7,161
- ------------------------------------------------------------------- ----------- ----------- -----------
Total other income (expenses).................................. (96,962) (64,941) (59,334)
- ------------------------------------------------------------------- ----------- ----------- -----------
EARNINGS BEFORE INCOME TAXES....................................... 241,203 274,516 209,116
PROVISION FOR INCOME TAXES......................................... 89,944 108,644 76,566
- ------------------------------------------------------------------- ----------- ----------- -----------
NET INCOME......................................................... 151,259 165,872 132,550
PREFERRED DIVIDEND REQUIREMENTS.................................... --- 733 2,285
- ------------------------------------------------------------------- ----------- ----------- -----------
EARNINGS AVAILABLE FOR COMMON STOCK................................ $ 151,259 $ 165,139 $ 130,265
=================================================================== =========== =========== ===========
AVERAGE COMMON SHARES OUTSTANDING (thousands)...................... 77,916 80,772 80,745
EARNINGS PER AVERAGE COMMON SHARE.................................. 1.94 2.04 1.61
AVERAGE COMMON SHARES OUTSTANDING ASSUMING DILUTION (thousands).... 77,916 80,787 80,745
EARNINGS PER AVERAGE COMMON SHARE ASSUMING DILUTION................ $ 1.94 $ 2.04 $ 1.61
=================================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
53
<PAGE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
BALANCE AT BEGINNING OF PERIOD................................. $ 529,768 $ 472,063 $ 449,198
ADD - net income............................................... 151,259 165,872 132,550
- --------------------------------------------------------------- ----------- ----------- -----------
Total........................................................ 681,027 637,935 581,748
- --------------------------------------------------------------- ----------- ----------- -----------
DEDUCT:
Cash dividends declared on preferred stock................... --- 733 2,285
Cash dividends declared on common stock...................... 103,495 107,434 107,400
- --------------------------------------------------------------- ----------- ----------- -----------
Total...................................................... 103,495 108,167 109,685
- --------------------------------------------------------------- ----------- ----------- -----------
BALANCE AT END OF PERIOD....................................... $ 577,532 $ 529,768 $ 472,063
=============================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
54
<PAGE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income................................................... $ 151,259 $ 165,872 $ 132,550
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation and amortization.............................. 165,041 149,818 142,632
Deferred income taxes and investment tax credits, net...... 31,093 23,922 17,105
Gain on sale of assets..................................... --- --- (2,511)
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers.......................... (69,875) (23,393) 11,132
Accrued unbilled revenues................................ (17,700) 14,400 (2,000)
Fuel, materials and supplies inventories................. (25,049) (9,223) 9,753
Accumulated deferred tax assets.......................... (918) (886) 3,142
Other current assets..................................... 17,192 (25,627) 89
Accounts payable......................................... 9,668 19,203 (9,123)
Accrued taxes............................................ 10,715 8,823 (5,084)
Accrued interest......................................... 7,110 1,040 209
Other current liabilities................................ (48,451) (3,577) (73)
Other operating activities................................... (5,832) (28,103) (2,218)
- --------------------------------------------------------------- ----------- ----------- -----------
Net cash provided from operating activities............ 224,253 292,269 295,603
- --------------------------------------------------------------- ----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures......................................... (181,163) (235,231) (163,571)
Acquisition of Transok....................................... (531,767) --- ---
Other investing activities................................... 2,832 (8,084) 4,900
- --------------------------------------------------------------- ----------- ----------- -----------
Net cash used in investing activities.................. (710,098) (243,315) (158,671)
- --------------------------------------------------------------- ----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt................................. (2,000) (113,500) (321,000)
Proceeds from long-term debt................................. --- 100,000 336,000
Short-term debt, net......................................... 470,000 118,100 (40,400)
Retirement of common stock................................... (71,767) --- ---
Issuance of trust originated preferred securities............ 200,000 --- ---
Redemption of preferred stock................................ --- (49,266) (113)
Cash dividends declared on preferred stock................... --- (733) (2,285)
Cash dividends declared on common stock...................... (103,495) (107,434) (107,400)
- --------------------------------------------------------------- ----------- ----------- -----------
Net cash provided from (used in) financing activities.. 492,738 (52,833) (135,198)
- --------------------------------------------------------------- ----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........... 6,893 (3,879) 1,734
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............... 378 4,257 2,523
CASH AND CASH EQUIVALENTS AT END OF PERIOD..................... $ 7,271 $ 378 $ 4,257
=============================================================== =========== =========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash Paid During the Period for:
Interest (net of amount capitalized)....................... $ 76,047 $ 59,792 $ 64,081
Income taxes............................................... $ 52,428 $ 77,150 $ 64,705
- --------------------------------------------------------------- ----------- ----------- -----------
NON-CASH INVESTING AND FINANCING ACTIVITIES
Capital lease financing...................................... $ --- $ 9,818 $ ---
Debt assumed in acquisition.................................. $ 173,000 $ 80,000 $ ---
Other investing and financing activities..................... $ 3,182 $ (3,000) $ 5,185
Current liabilities assumed in acquisition of Transok........ $ 98,917 $ --- $ ---
=============================================================== =========== =========== ===========
</TABLE>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
55
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
OGE Energy Corp. (the "Company") is the parent company of Oklahoma Gas
and Electric Company ("OG&E"), Enogex Inc. ("Enogex") and OGE Energy Capital
Trust I, a financing trust established in 1999. All significant intercompany
transactions have been eliminated in consolidation.
The Company distributes operating costs to its affiliates based on
several factors. Operating costs directly related to specific affiliates are
assigned to those affiliates. Where more than one affiliate benefits from
certain expenditures, the costs are shared between those affiliates receiving
the benefits. Operating costs incurred for the benefit of all affiliates are
allocated among the affiliates, based primarily upon head-count, occupancy,
usage or the "Distragas" method. The Distragas method is a three-factor formula
that uses an equal weighting of payroll, operating income and assets. The
Company believes this method provides a reasonable basis for allocating common
expenses.
On July 1, 1999, Enogex completed its acquisition of Tejas Transok
Holding, L.L.C. and its subsidiaries ("Transok"), a gatherer, processor and
transporter of natural gas in Oklahoma and Texas. Transok's principal assets
include approximately 4,900 miles of natural gas pipelines in Oklahoma and Texas
with a capacity of approximately 2.6 billion cubic feet per day and 18 billion
cubic feet of underground natural gas storage. Transok also owns 9
gas-processing plants, which produced approximately 26,000 barrels per day of
natural gas liquids in 1998. Enogex purchased Transok for $710.3 million, which
included assumption of $173 million of long-term debt. The transaction was
treated as a purchase for accounting purposes. The Company did not recognize any
goodwill with this transaction.
The following unaudited pro forma financial information presents total
operating revenues, net income and net income per share of the Company after
giving effect to the Transok acquisition. The unaudited pro forma financial
information for the twelve months ended December 31, 1999 gives effect to the
acquisition as if it had occurred at January 1, 1999. The unaudited pro forma
financial information for the twelve months ended December 31, 1998 gives effect
to the acquisition as if it had occurred at January 1, 1998.
The following unaudited pro forma financial information has been
prepared from, and should be read in conjunction with, the historical
consolidated financial statements and related notes thereto of the Company. The
following information is not necessarily indicative of the financial position or
operating results that would have occurred had the transaction been consummated
on the date, or at the beginning of the periods, for which the transaction is
being given effect, nor is it necessarily indicative of future operating results
or financial position.
56
<PAGE>
Unaudited Pro Forma Financial Information
<TABLE>
<CAPTION>
PRO FORMA PRO FORMA
YEAR ENDED YEAR ENDED
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) DECEMBER 31, 1999 DECEMBER 31, 1998
==================================================================================================
<S> <C> <C>
Total operating revenues............................. $ 2,423,670 $ 2,088,497
Net income........................................... 146,991 132,728
Earnings per average common share.................... 1.89 1.63
Earnings per average common share -
assuming dilution.................................. 1.89 1.63
==================================================================================================
</TABLE>
ACCOUNTING RECORDS
The accounting records of OG&E are maintained in accordance with the
Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission ("FERC") and adopted by the Oklahoma Corporation Commission ("OCC")
and the Arkansas Public Service Commission ("APSC"). Additionally, OG&E, as a
regulated utility, is subject to the accounting principles prescribed by the
Financial Accounting Standards Board ("FASB") Statement of Financial Accounting
Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS No. 71 provides that certain costs that would otherwise be
charged to expense can be deferred as regulatory assets, based on expected
recovery from customers in future rates. Likewise, certain credits that would
otherwise reduce expense are deferred as regulatory liabilities based on
expected flowback to customers in future rates. Management's expected recovery
of deferred costs and flowback of deferred credits generally results from
specific decisions by regulators granting such ratemaking treatment. At December
31, 1999, regulatory assets and regulatory liabilities are being amortized and
reflected in rates charged to customers over periods up to 20 years.
57
<PAGE>
The components of deferred charges - other, and regulatory assets and
liabilities on the Consolidated Balance Sheets included the following, as of
December 31:
<TABLE>
<CAPTION>
DEFERRED CHARGES - OTHER
(DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
Electric Utility Deferred Charges:
Generating stations.......................................... $ 4,654 $ --- $ ---
Unamortized debt expense..................................... 5,196 8,566 6,776
Unamortized loss on reacquired debt.......................... 27,281 29,072 28,660
Miscellaneous................................................ 4,116 2,217 403
- --------------------------------------------------------------- ----------- ----------- -----------
Total electric utility deferred charges.................... 41,247 39,855 35,839
- --------------------------------------------------------------- ----------- ----------- -----------
Non-Electric Utility Deferred Charges:
Enogex gas sales contracts................................... 10,891 12,389 13,925
Enogex pipeline imbalance.................................... 11,238 --- ---
Unamortized debt expense..................................... 10,008 --- ---
Enogex minority interest asset............................... 6,845 --- ---
Miscellaneous................................................ 12,954 14,323 11,621
- --------------------------------------------------------------- ----------- ----------- -----------
Total non-electric utility deferred charges................ 51,936 26,712 25,546
- --------------------------------------------------------------- ----------- ----------- -----------
Total Deferred Charges......................................... $ 93,183 $ 66,567 $ 61,385
============================================================================================================
REGULATORY ASSETS AND LIABILITIES
(DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
Regulatory Assets:
Income taxes recoverable from customers...................... $ 93,888 $ 104,160 $ 115,989
Unamortized loss on reacquired debt.......................... 27,281 29,072 28,660
Miscellaneous................................................ 4,116 2,217 403
- --------------------------------------------------------------- ----------- ----------- -----------
Total Regulatory Assets.................................... 125,285 135,449 145,052
Regulatory Liabilities:
Income taxes refundable to customers......................... (54,196) (63,429) (73,440)
- --------------------------------------------------------------- ----------- ----------- -----------
Net Regulatory Assets.......................................... $ 71,089 $ 72,020 $ 71,612
============================================================================================================
</TABLE>
Management continuously monitors the future recoverability of
regulatory assets. When, in management's judgment, future recovery becomes
impaired; the amount of the regulatory asset is reduced or written-off, as
appropriate.
If the Company were required to discontinue the application of SFAS No.
71 for some or all of its operations, it could result in writing off the related
regulatory assets; the financial effects of which could be significant.
58
<PAGE>
ACCOUNTING PRONOUNCEMENTS
In March 1998, the American Institute of Certified Public Accountants
("AICPA") issued Statement of Position ("SOP") 98-1, "Accounting for the Costs
of Computer Software Developed or Obtained for Internal Use." Adoption of SOP
98-1 is required for fiscal years beginning after December 15, 1998. The Company
adopted this new standard effective January 1, 1999. Adoption of this new
standard did not have a material impact on consolidated financial position or
results of operations.
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and for Hedging Activities", with an effective date for
periods beginning after June 15, 1999. In July 1999, the FASB issued SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133". As a result of SFAS No. 137,
adoption of SFAS No. 133 is now required for financial statements for periods
beginning after June 15, 2000. SFAS No. 133 sweeps in a broad population of
transactions and changes the previous accounting definition of a derivative
instrument. Under SFAS No. 133, every derivative instrument is recorded in the
balance sheet as either an asset or liability measured at its fair value. SFAS
No. 133 requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. The
Company will prospectively adopt this new standard effective January 1, 2001,
and management believes the adoption of this new standard will not have a
material impact on its consolidated financial position or results of operation.
In December 1998, the FASB Emerging Issues Task Force reached consensus
on Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk
Management Activities ("EITF Issue 98-10"). EITF Issue 98-10 is effective for
fiscal years beginning after December 15, 1998. EITF Issue 98-10 requires energy
trading contracts to be recorded at fair value on the balance sheet, with
changes in fair value included in earnings. The Company adopted this new Issue
effective January 1, 1999. Adoption of this Issue did not have a material impact
on consolidated financial position or results of operations.
DERIVATIVES
In the normal course of business, Enogex and its subsidiaries utilize
energy derivative contracts to hedge the price and basis risk associated with
specifically identified purchase or sales contracts, natural gas inventories,
production of gas reserves or operational needs. The Company accounts for
changes in the market value of qualifying hedging instruments as deferred gains
or losses until the production month of the hedged transaction, at which time
the gain or loss on the hedging instrument and hedged transaction is recognized
in the results of operations.
Additionally, Enogex through its energy trading subsidiary will utilize
derivative contracts in its energy trading activities. Derivatives utilized in
the energy trading activities are marked to market with the corresponding market
gains or losses recognized in the results of operations as the market value
changes.
USE OF ESTIMATES
In preparing the consolidated financial statements, management is
required to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent
59
<PAGE>
assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results
could differ from those estimates.
PROPERTY, PLANT AND EQUIPMENT
All property, plant and equipment is recorded at cost. Electric utility
plant is recorded at its original cost. Newly constructed plant is added to
plant balances at costs which include contracted services, direct labor,
materials, overhead and allowance for funds used during construction.
Replacement of major units of property are capitalized as plant. The replaced
plant is removed from plant balances and the cost of such property together with
the cost of removal less salvage is charged to accumulated depreciation. Repair
and replacement of minor items of property are included in the Consolidated
Statements of Income as other operation and maintenance expense.
DEPRECIATION
The provision for depreciation, which was approximately 3.2 percent of
the average depreciable utility plant, for each of the years 1999, 1998 and
1997, is provided on a straight-line method over the estimated service life of
the property. Depreciation is provided at the unit level for production plant
and at the account or sub-account level for all other plant, and is based on the
average life group procedure.
Enogex's gas pipeline, gathering systems, compressors and gas
processing plants are depreciated on a straight-line method over periods ranging
from 17 to 83 years. Development and production properties are depreciated using
the units-of-production method.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction ("AFUDC") is calculated
according to FERC pronouncements for the imputed cost of equity and borrowed
funds. AFUDC, a non-cash item, is reflected as a credit on the Consolidated
Statements of Income and a charge to construction work in progress.
AFUDC rates, compounded semi-annually, were 5.36, 5.75 and 5.94 percent
for the years 1999, 1998 and 1997, respectively.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value of the financial instruments on the Consolidated
Balance Sheets not otherwise discussed in these notes approximate fair value.
CASH AND CASH EQUIVALENTS
For purposes of these statements, the Company considers all highly
liquid debt instruments purchased with a maturity of three months or less to be
cash equivalents. These investments are carried at cost, which approximates
market.
The Company's cash management program utilizes controlled disbursement
banking arrangements. Outstanding checks in excess of cash balances totaled
$11.7 million, $27.8 million and $18.5 million at December 31, 1999, 1998 and
1997, respectively, and are classified as accounts payable in the accompanying
Consolidated Balance Sheets. Sufficient funds were available to fund these
outstanding checks when they were presented for payment.
60
<PAGE>
HEAT PUMP LOANS
OG&E has a heat pump loan program, whereby, qualifying customers may
obtain a loan from OG&E to purchase a heat pump. Customer loans are available
from a minimum of $1,500 to a maximum of $13,000 with a term of 6 months to 84
months. The finance rate is based upon short-term loan rates and is reviewed and
updated periodically. The interest rates were 8.99, 8.25 and 8.25 percent at
December 31, 1999, 1998 and 1997, respectively.
The current portion of these loans totaled $0.6 million, $1.0 million
and $4.9 million at December 31, 1999, 1998 and 1997, respectively, and are
classified as accounts receivable - customers in the accompanying Consolidated
Balance Sheets. The noncurrent portion of these loans totaled $2.3 million, $4.0
million and $19.1 million at December 31, 1999, 1998 and 1997, respectively, and
are classified as other property and investments in the accompanying
Consolidated Balance Sheets. OG&E sold approximately $12.7 million and $25.0
million of its heat pump loans in 1999 and 1998 respectively.
REVENUE RECOGNITION
OG&E customers are billed monthly on a cycle basis. OG&E accrues
estimated revenues for services provided but not yet billed, as the cost of
providing service is recognized as incurred. Enogex accrues revenues as the
products and services are delivered.
AUTOMATIC FUEL ADJUSTMENT CLAUSES
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are charged to substantially all of OG&E's electric customers
through automatic fuel adjustment clauses, which are subject to periodic review
by the OCC, the APSC and the FERC.
FUEL INVENTORIES
Fuel inventories for the generation of electricity consists of coal,
natural gas and oil. These inventories are accounted for under the last-in,
first-out ("LIFO") cost method. The estimated replacement cost of fuel
inventories was lower than the stated LIFO cost by approximately $0.9 million
for 1999, $4.4 million for 1998, and $1.1 million for 1997, based on the average
cost of fuel purchased late in the respective years. Natural gas products
inventories are held for sale and accounted for based on the weighted average
cost of production.
ACCRUED VACATION
The Company accrues vacation pay by establishing a liability for
vacation earned during the current year, but is not payable until the following
year. The accrued vacation totaled $14.4 million, $13.4 million and $13.2
million at December 31, 1999, 1998 and 1997, respectively, and is classified as
other current liabilities in the accompanying Consolidated Balance Sheets.
ENVIRONMENTAL COSTS
Accruals for environmental costs are recognized when it is probable
that a liability has been incurred and the amount of the liability can be
reasonably estimated. When a single estimate of the liability cannot be
determined, the low end of the estimated range is recorded. Costs are charged to
61
<PAGE>
expense or deferred as a regulatory asset based on expected recovery from
customers in future rates, if they relate to the remediation of conditions
caused by past operations or if they are not expected to mitigate or prevent
contamination from future operations. Where environmental expenditures relate to
facilities currently in use, such as pollution control equipment, the costs may
be capitalized and depreciated over the future service periods. Estimated
remediation costs are recorded at undiscounted amounts, independent of any
insurance or rate recovery, based on prior experience, assessments and current
technology. Accrued obligations are regularly adjusted as environmental
assessments and estimates are revised, and remediation efforts proceed. For
sites where OG&E has been designated as one of several potentially responsible
parties, the amount accrued represents OG&E's estimated share of the cost.
RECLASSIFICATIONS AND STOCK SPLIT
Certain amounts have been reclassified on the consolidated financial
statements to conform with the 1999 presentation. Effective June 15, 1998, the
outstanding shares of the Company's common stock were split on a two-for-one
basis. The new shares were issued to shareowners of record on June 1, 1998.
Prior period shares, dividends and earnings per share of common stock have been
restated to reflect the stock split.
62
<PAGE>
2. INCOME TAXES
The items comprising tax expense are as follows:
<TABLE>
<CAPTION>
Year ended December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
================================================================================================================
<S> <C> <C> <C>
Provision For Current Income Taxes:
Federal.......................................................... $ 50,090 $ 72,084 $ 47,676
State............................................................ 8,617 12,638 9,671
- ------------------------------------------------------------------- ----------- ----------- -----------
Total Provision For Current Income Taxes..................... 58,707 84,722 57,347
- ------------------------------------------------------------------- ----------- ----------- -----------
Provisions (Benefit) For Deferred Income Taxes, net:
Federal
Depreciation................................................... 29,392 1,490 11,344
Repair allowance............................................... 1,978 1,200 794
Removal costs.................................................. 3,461 (220) 774
Salvage........................................................ (3,131) --- ---
Casualty losses................................................ 5,167 --- ---
Software implementation costs.................................. --- --- 4,840
Company restructuring.......................................... 100 22 (494)
Pension expense................................................ (2,626) 14,806 ---
Bond redemption-unamortized costs.............................. 249 8,458 ---
Other.......................................................... (207) 20 2,093
State............................................................ 1,858 3,296 2,904
- ------------------------------------------------------------------- ----------- ----------- -----------
Total Provision (Benefit) For Deferred Income Taxes, net.... 36,241 29,072 22,255
- ------------------------------------------------------------------- ----------- ----------- -----------
Deferred Investment Tax Credits, net............................... (5,150) (5,150) (5,150)
Income Taxes Relating to Other Income and Deductions............... 146 --- 2,114
- ------------------------------------------------------------------- ----------- ----------- -----------
Total Income Tax Expense..................................... $ 89,944 $ 108,644 $ 76,566
- ------------------------------------------------------------------- ----------- ----------- -----------
Pretax Income...................................................... $ 241,203 $ 274,516 $ 209,116
=================================================================== =========== =========== ===========
The following schedule reconciles the statutory federal tax rate to the
effective income tax rate:
Year ended December 31 1999 1998 1997
================================================================================================================
Statutory federal tax rate......................................... 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit.............. 2.8 3.8 3.9
Tax credits, net................................................... (3.4) (3.0) (4.0)
Other, net......................................................... 2.9 3.8 1.7
- ------------------------------------------------------------------- ----------- ----------- -----------
Effective income tax rate as reported............................ 37.3% 39.6% 36.6%
=================================================================== =========== =========== ===========
</TABLE>
63
<PAGE>
The Company files consolidated income tax returns. Income taxes are
allocated to each company based on its separate taxable income or loss.
Investment tax credits on electric utility property have been deferred
and are being amortized to income over the life of the related property.
The Company follows the provisions of SFAS No. 109, "Accounting for
Income Taxes", which uses an asset and liability approach to accounting for
income taxes. Under SFAS No. 109, deferred tax assets or liabilities are
computed based on the difference between the financial statement and income tax
bases of assets and liabilities ("temporary differences") using the enacted
marginal tax rate. Deferred income tax expenses or benefits are based on the
changes in the asset or liability from period to period.
The deferred tax provisions, set forth above, are recognized as costs
in the ratemaking process by the commissions having jurisdiction over the rates
charged by OG&E. The components of Accumulated Deferred Income Taxes at December
31, 1999, 1998 and 1997 are as follows:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
Current Deferred Tax Assets:
Accrued vacation............................................. $ 5,497 $ 5,088 $ 4,221
Uncollectible accounts....................................... 1,776 1,242 1,898
Capitalization of indirect costs............................. 249 172 106
RAR interest................................................. 774 774 ---
Provision for Worker's Compensation claims................... 348 462 595
Other........................................................ 85 73 105
- --------------------------------------------------------------- ----------- ----------- -----------
Accumulated deferred tax assets.......................... $ 8,729 $ 7,811 $ 6,925
============================================================================================================
Deferred Tax Liabilities:
Accelerated depreciation and other property-related
differences................................................ $ 532,814 $ 491,943 $ 489,739
Allowance for funds used during construction................. 37,152 38,575 43,327
Income taxes recoverable through future rates................ 36,335 40,310 44,888
Bond redemption-unamortized costs............................ 9,640 9,353 ---
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... 615,941 580,181 577,954
- --------------------------------------------------------------- ----------- ----------- -----------
Deferred Tax Assets:
Deferred investment tax credits.............................. (20,130) (21,875) (23,623)
Income taxes refundable through future rates................. (20,974) (24,547) (28,421)
Postemployment medical and life insurance benefits........... (1,795) (3,100) (4,174)
Company pension plan......................................... (5,206) (682) (16,242)
Other........................................................ (1,699) 1,963 (1,542)
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... (49,804) (48,241) (74,002)
- --------------------------------------------------------------- ----------- ----------- -----------
Accumulated Deferred Income Tax Liabilities.................... $ 566,137 $ 531,940 $ 503,952
============================================================================================================
</TABLE>
64
<PAGE>
3. COMMON STOCK AND RETAINED EARNINGS
In May 1998, the Company's Board of Directors approved a two-for-one
stock split of its common stock, par value $0.01 per share (the "Common Stock"),
by declaring a 100 percent stock dividend payable June 15, 1998. Accordingly,
each shareowner of record of the Common Stock received one additional share of
Common Stock for each share of Common Stock held on June 1, 1998.
On January 15, 1999, the Company repurchased 3 million shares of its
Common Stock under an Advanced Share Repurchase agreement with CIBC Oppenheimer
Corp. The purchase price was $80.4 million or $26.8125 per share, the closing
price on January 15, 1999. Under the terms of this Advanced Share Repurchase
Agreement, the Company agreed to bear the risk of increases and the benefit of
decreases on the price on the Common Stock until CIBC Oppenheimer Corp.
replaced, through open market purchases or privately negotiated transactions,
the shares sold to the Company. Also, there were 65,831, 25,705 and 28,896
shares of new stock issued pursuant to the Stock Incentive Plan during 1999,
1998 and 1997, respectively. The $71.7 million decrease in 1999 in premium on
capital stock as presented on the Consolidated Statements of Capitalization,
represents the repurchase of common stock which was only partially offset by the
issuance of common stock pursuant to the Stock Incentive Plan. The $0.7 million
increase in 1998 in premium on capital stock represents the issuance of common
stock pursuant to the Stock Incentive Plan.
There were 8,509,564 shares of unissued common stock reserved for the
various employee and Company stock plans at December 31, 1999. With the
exception of the Stock Incentive Plan, the common stock requirements, pursuant
to those plans, are currently being satisfied with stock purchased on the open
market.
SHAREOWNERS RIGHTS PLAN
In December 1990, OG&E adopted a Shareowners Rights Plan designed to
protect shareowners' interests in the event that OG&E was ever confronted with
an unfair or inadequate acquisition proposal. In connection with the corporate
restructuring, the Company adopted a substantially identical Shareowners Rights
Plan in August 1995. Pursuant to the plan, the Company declared a dividend
distribution of one "right" for each share of Company common stock. As a result
of the June 1998 two-for-one stock split, each share of common stock is now
entitled to one-half of a right. Each right entitles the holder to purchase from
the Company one one-hundredth of a share of new preferred stock of the Company
under certain circumstances. The rights may be exercised if a person or group
announces its intention to acquire, or does acquire, 20 percent or more of the
Company's common stock. Under certain circumstances, the holders of the rights
will be entitled to purchase either shares of common stock of the Company or
common stock of the acquirer at a reduced percentage of market value. The rights
are scheduled to expire on December 11, 2000.
4. STOCK INCENTIVE PLAN
On January 21, 1998, the Company adopted a Stock Incentive Plan. Under
this plan, restricted stock, stock options, stock appreciation rights and
performance units may be granted to officers, directors and other key employees.
The Company has authorized the issuance of up to 4,000,000 shares under the
plan.
65
<PAGE>
RESTRICTED STOCK
The Company had a Restricted Stock Plan whereby certain employees
periodically received shares of the Company's common stock at the discretion of
the Board of Directors. The Stock Incentive Plan replaced the Restricted Stock
Plan. The Company distributed 65,831, 25,705 and 28,896 shares of common stock
during 1999, 1998 and 1997, respectively. The Company also reacquired 13,195 and
14,552 shares in 1998 and 1997, respectively. The shares reacquired in 1997 were
recorded as treasury stock. The restricted stock distributed in 1999 and 1998
vests at the end of three years. The restricted stock distributed in 1997 vests
over four years at (20 percent in each of the first three years and 40 percent
in the final year).
Changes in common stock were:
<TABLE>
<CAPTION>
(THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
Shares outstanding January 1................................... 80,798 80,772 80,758
Repurchased shares............................................. (3,000) --- ---
Issued/reacquired under the Restricted Stock Plan, net......... 65 26 14
- ------------------------------------------------------------------------------------------------------------
Shares outstanding December 31................................. 77,863 80,798 80,772
============================================================================================================
</TABLE>
STOCK OPTIONS
In January 1999, the Company awarded approximately 443,600 stock
options, with an exercise price of $28.75. In January 1998, the Company awarded
approximately 443,800 stock options, with an exercise price of $25.9375. During
1998, 19,200 stock options were forfeited. These options vest in one-third
annual installments beginning one year from the date of grant and have a
contractual life of 10 years. At December 31, 1999, 868,200 stock options were
outstanding. The remaining contractual life of these options is approximately
nine years and eight years, respectively.
During 1996, the Company adopted SFAS 123 and pursuant to its provision
elected to continue using the intrinsic value method of accounting for
stock-based awards granted to employees in accordance with APB 25. Accordingly,
the Company has not recognized compensation expense for its stock-based awards
to employees. Using the Black-Scholes pricing model, the estimated fair value of
each option granted was $2.07 in 1999.
The following table shows assumptions used to estimate the fair value
of options granted in 1999:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Expected life of options................... 7 years
Risk-free interest rate.................... 4.74%
Expected volatility........................ 15.75%
Expected dividend yield.................... 6.77%
</TABLE>
66
<PAGE>
The following table reflects pro forma earnings available for common
stock had the Company elected to adopt the fair value approach to SFAS 123:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1999 1998 1997
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Earnings available for
common stock: As Reported...... $151,259 $165,139 $130,265
Pro Forma........ 150,864 164,933 130,002
</TABLE>
Reported and pro forma earnings per share amounts are equivalent for
1997 through 1999.
5. TRUST PREFERRED SECURITIES OF SUBSIDIARY
On October 21, 1999, the OGE Energy Capital Trust I, a wholly-owned
financing trust of the Company, issued $200 million principal amount of 8.375
percent trust preferred securities that mature in 2039. The proceeds of this new
debt were used to repay a portion of outstanding short-term borrowings under the
revolving credit agreement implemented in connection with the Transok
acquisition. Distributions paid by the financing trust on the preferred
securities are financed through payments on debt securities issued by the
Company and held by the financing trust, which are eliminated in the Company's
consolidation. The preferred securities are redeemable at $25 per share
beginning in 2004. Distributions and redemption payments are guaranteed by the
Company. Distributions paid to preferred security holders are recorded as
interest expense in the Consolidated Statements of Income.
6. LONG-TERM DEBT
On July 1, 1999, Enogex completed its acquisition of Transok for
approximately $710.3 million, which included assumption of $173 million of
long-term debt. To repay the remaining balance of the temporary short-term debt
associated with the Transok acquisition, Enogex, on January 14, 2000, sold $400
million of unsecured 8.125 percent Senior Notes due January 15, 2010. Enogex
entered into a series of interest rate swap agreements to manage interest costs
associated with this $400 million issue. The effect of these swap agreements
reduces the overall effective interest rate from 8.125 percent to 6.6875 percent
during the first year. The balance of the proceeds from this new debt was used
for general corporate purposes. The following table itemizes the new Enogex
long-term debt assumed as part of the Transok acquisition:
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1999
=============================================================================
<S> <C>
Series Due 2002 -- 7.32% - 8.13%............................... $ 50,000
Series Due 2003 -- 6.60% - 8.28%............................... 12,300
Series Due 2004 -- 6.71% - 8.34%............................... 25,750
Series Due 2005 -- 6.81% -- 7.71%.............................. 40,950
Series Due 2007 -- 8.28%....................................... 3,000
Series Due 2008 -- 7.07%....................................... 1,000
Series Due 2012 -- 8.35% - 8.90%............................... 10,000
Series Due 2017 -- 8.96%....................................... 15,000
Series Due 2023 -- 7.75%....................................... 15,000
- --------------------------------------------------------------- ---------
Total.................................................... $173,000
=============================================================== =========
</TABLE>
67
<PAGE>
As of December 31, 1999, other Enogex long-term debt consisted of $77
million principal amount of 7.15 percent Senior Notes subject to semiannual
principal payments of $1 million each and due June 1, 2018, $6.5 million
principal amount of 7.00 percent Notes due July 1, 2020 and $150 million of
medium-term notes at a composite rate of 6.97 percent. The following table
itemizes the other Enogex long-term debt at December 31, 1999, 1998 and 1997:
<TABLE>
<CAPTION>
December 31 (DOLLARS IN THOUSANDS) 1999 1998 1997
=======================================================================================================
<S> <C> <C> <C>
Series Due August 7, 2000 -- 6.76% - 6.77%..................... $ 27,000 $ 27,000 $ 27,000
Series Due August 31, 2000 -- 6.68%............................ 20,000 20,000 20,000
Series Due September 1, 2000 -- 6.70%.......................... 10,000 10,000 10,000
Series Due August 7, 2002 -- 7.02% - 7.05%..................... 63,000 63,000 63,000
Series Due July 23, 2004 -- 6.79%.............................. 30,000 30,000 30,000
Series Due July 18, 2018 -- 7.15%.............................. 77,000 79,000 ---
Series Due July 1, 2020 -- 7.00%............................... 6,486 5,671 ---
- --------------------------------------------------------------- --------- --------- ---------
Total.................................................... $233,486 $234,671 $150,000
=============================================================== ========= ========= =========
</TABLE>
Maturities of the Company's long-term debt during the next five years
consist of $169 million in 2000; $2 million in 2001; $115 million in 2002; $14.3
million in 2003, and $55.8 million in 2004.
The Company has previously incurred costs related to debt refinancings.
Unamortized debt expense and unamortized loss on reacquired debt, and
unamortized premium and discount on long-term debt are being amortized over the
life of the respective debt and are classified as deferred charges - other and
long-term debt, respectively, in the accompanying Consolidated Balance Sheets.
7. SHORT-TERM DEBT
The Company borrows on a short-term basis, as necessary, by the
issuance of commercial paper and by obtaining short-term bank loans. The maximum
and average amounts of short-term borrowings during 1999 were $198.9 million and
$154.91 million, respectively, at a weighted average interest rate of 5.36%. The
weighted average interest rates for 1998 and 1997 were 5.75% and 5.94%,
respectively. Short-term debt in the amount of $589.1 million was outstanding at
December 31, 1999. The Company 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, $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 ($200 million to expire on January 15, 2001, and $100
million to expire on January 15, 2004) and the Company terminated its $75
million credit agreement with CIBC Oppenheimer Corp. which was entered into for
the share repurchase program.
8. PENSION AND POSTRETIREMENT BENEFIT PLANS
All eligible employees of the Company are covered by a non-contributory
defined benefit pension plan. Under the plan, retirement benefits are primarily
a function of both the years of service and the highest average monthly
compensation for 60 consecutive months out of the last 120 months of service.
68
<PAGE>
It is the Company's policy to fund the plan on a current basis to
comply with the minimum required contributions under existing tax regulations.
The Company made contributions of $3.8 million during 1999 to increase the
Plan's funded status. Such contributions are intended to provide not only for
benefits attributed to service to date, but also for those expected to be earned
in the future.
The plan's assets consist primarily of U.S. Government securities,
listed common stock and corporate debt.
In addition to providing pension benefits, the Company provides certain
medical and life insurance benefits for retired members ("postretirement
benefits"). Employees retiring from the Company on or after attaining age 55 who
have met certain length of service requirements are entitled to these benefits.
The benefits are subject to deductibles, co-payment provisions and other
limitations. OG&E charges to expense the SFAS No. 106 costs and includes an
annual amount as a component of cost-of-service in future ratemaking
proceedings.
A reconciliation of the funded status of the plans and the amounts
included in the Company's Consolidated Balance Sheets:
Projected benefit obligations are as follows:
<TABLE>
<CAPTION>
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Beginning obligations........... $(342,433) $(320,842) $(284,973) $ (89,094) $ (94,199) $ (94,272)
Service cost.................... (8,241) (8,272) (6,529) (2,695) (2,030) (2,144)
Interest cost................... (21,363) (21,766) (20,803) (6,003) (5,748) (6,365)
Participant contributions....... --- --- --- (1,143) (1,077) (902)
Plan changes.................... --- (3,561) --- (1,500) --- ---
Actuarial gains (losses)........ 53,535 (8,568) (32,667) 7,950 6,029 3,198
Benefits paid................... 17,695 20,345 24,130 9,057 7,931 6,286
Expenses........................ 811 231 --- --- --- ---
- --------------------------------------------------------------------------------------------------------------------
Ending obligations.............. $(299,996) $(342,433) $(320,842) $ (83,428) $ (89,094) $ (94,199)
====================================================================================================================
</TABLE>
69
<PAGE>
Fair value of plans' assets:
<TABLE>
<CAPTION>
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Beginning fair value............ $ 304,169 $ 242,254 $ 222,912 $ 52,264 $ 45,619 $ 39,066
Actual return on plans' assets.. 22,517 30,865 33,489 3,245 5,133 8,047
Employer contributions.......... 3,757 51,626 9,983 6,307 5,474 5,271
Participants' contributions..... --- --- --- 980 915 874
Benefits paid................... (17,695) (20,345) (24,130) (7,287) (6,388) (6,128)
Expenses........................ (811) (231) --- --- --- ---
Other........................... --- --- --- --- 1,511 (1,511)
- --------------------------------------------------------------------------------------------------------------------
Ending fair value............... $ 311,937 $ 304,169 $ 242,254 $ 55,509 $ 52,264 $ 45,619
====================================================================================================================
Funded status of plans:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
Funded status of the plans...... $ 11,941 $ (38,264) $ (78,588) $ (27,919) $ (36,831) $ (47,068)
Unrecognized net gain (loss).... (47,326) 1,435 2,295 (24,337) (18,713) (13,886)
Unrecognized prior service
benefit....................... 37,289 40,448 40,047 1,396 --- ---
Unrecognized transition
obligation.................... (2,527) (3,790) (5,053) 35,738 38,487 41,236
- --------------------------------------------------------------------------------------------------------------------
Net balance sheet asset
(liability)................... $ (623) $ (171) $ (41,299) $ (15,122) $ (17,057) $ (19,718)
====================================================================================================================
</TABLE>
70
<PAGE>
Net Periodic Benefit Cost:
<TABLE>
<CAPTION>
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Service cost.................... $ 8,241 $ 8,272 $ 6,529 $ 2,695 $ 2,030 $ 2,144
Interest cost................... 21,363 21,766 20,803 6,003 5,748 6,365
Return on plan assets........... (27,374) (21,443) (19,142) (3,963) (4,309) (3,445)
Amortization of transition
obligation.................... (1,263) (1,263) (1,263) 2,749 2,749 2,749
Amortization of net gain (loss). --- --- 788 (1,244) (2,105) (858)
Net amount capitalized or
deferred...................... (880) --- --- (1,087) (613) (1,293)
Net amortization and deferral... (29) --- --- --- --- ---
Amortization of unrecognized
prior service cost............ 3,159 3,159 2,939 104 --- ---
- --------------------------------------------------------------------------------------------------------------------
Net periodic benefit costs...... $ 3,217 $ 10,491 $ 10,654 $ 5,257 $ 3,500 $ 5,662
====================================================================================================================
Rate Assumptions:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------------------------------
Discount rate..................... 8.00% 6.75% 7.00% 8.00% 6.75% 7.00%
Rate of return on plans' assets... 9.00% 9.00% 9.00% 9.00% 9.00% 9.00%
Compensation increases............ 4.50% 4.50% 4.50% 4.50% 4.50% 4.50%
Assumed health care cost trend:
Initial trend................... N/A N/A N/A 7.00% 7.50% 8.25%
Ultimate trend rate............. N/A N/A N/A 4.50% 4.50% 4.50%
Ultimate trend year............. N/A N/A N/A 2007 2007 2007
====================================================================================================================
N/A - not applicable
</TABLE>
Assumed health care cost trend rates have a significant effect on the
amounts reported for the postretirement medical benefit plans.
The effects of a one-percentage point increase on the aggregate of the
service and interest components of the net periodic postretirement health care
benefits would be approximately $1.0 million, $0.9 million and $1.0 million at
December 31, 1999, 1998 and 1997, respectively. The effects of a one-percentage
point decrease on the aggregate of the service and interest components of the
net periodic
71
<PAGE>
postretirement health care benefits would be decreases of approximately $0.9
million, $0.7 million and $1.0 million at December 31, 1999, 1998 and 1997,
respectively.
The effects of a one-percentage point increase on the aggregate of
accumulated postretirement benefit obligation for health care benefits would be
approximately $7.1 million, $8.2 million and $11.4 million at December 31, 1999,
1998 and 1997, respectively. The effects of a one-percentage point decrease on
the aggregate of accumulated postretirement benefit obligation for health care
benefits would be decreases of approximately $6.0 million, $6.9 million and $9.4
million at December 31, 1999, 1998 and 1997, respectively.
9. REPORT OF BUSINESS SEGMENTS
The Company's electric utility operations are conducted through OG&E,
an operating public utility engaged in the generation, transmission,
distribution and sale of electric energy. The non-utility operations are
primarily conducted through Enogex. Enogex is engaged in transporting natural
gas through its intra-state pipeline to various customers (including OG&E),
gathering and processing natural gas, marketing electricity, natural gas and
natural gas liquids and investing in the development for and production of
natural gas and crude oil.
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1999 1998 1997
============================================================================================================
<S> <C> <C> <C>
Operating Information:
Operating Revenues
Electric utility........................................... $1,286,844 $1,312,078 $1,191,691
Non-utility................................................ 1,086,105 506,471 293,608
Intersegment revenues (A).................................. (200,515) (200,812) (41,689)
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... $2,172,434 $1,617,737 $1,443,610
=============================================================== =========== =========== ===========
Pre-tax Operating Income
Electric utility........................................... $ 269,564 $ 315,798 $ 246,038
Non-utility................................................ 68,601 23,659 22,412
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... $ 338,165 $ 339,457 $ 268,450
=============================================================== =========== =========== ===========
Income Tax Expense
Electric utility........................................... $ 84,965 $ 105,574 $ 71,321
Non-utility................................................ 4,979 3,070 3,131
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... $ 89,944 $ 108,644 $ 74,452
=============================================================== =========== =========== ===========
Interest Income
Electric utility........................................... $ 1,710 $ 2,314 $ 4,531
Non-utility................................................ 9,929 7,046 1,993
Intersegment (B)........................................... (8,801) (5,799) (2,651)
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... $ 2,838 $ 3,561 $ 3,873
=============================================================== =========== =========== ===========
</TABLE>
72
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Interest Expense
Electric utility........................................... $ 46,658 $ 49,941 $ 56,546
Non-utility................................................ 63,142 27,628 13,199
Intersegment (B)........................................... (8,801) (5,799) (2,651)
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... $ 100,999 $ 71,770 $ 67,094
=============================================================== =========== =========== ===========
Net Income
Electric utility........................................... $ 139,041 $ 160,338 $ 120,994
Non-utility................................................ 12,218 5,534 11,556
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... $ 151,259 $ 165,872 $ 132,550
=============================================================== =========== =========== ===========
Investment Information:
Identifiable Assets as of December 31
Electric utility........................................... $2,320,660 $2,320,097 $2,350,782
Non-utility................................................ 1,600,674 663,832 415,083
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... $3,921,334 $2,983,929 $2,765,865
=============================================================== =========== =========== ===========
Other Information:
Depreciation and amortization
Electric utility........................................... $ 119,059 $ 116,213 $ 114,760
Non-utility................................................ 45,982 33,605 27,872
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... $ 165,041 $ 149,818 $ 142,632
=============================================================== =========== =========== ===========
Construction Expenditures
Electric utility........................................... $ 101,263 $ 96,678 $ 100,079
Non-utility................................................ 79,900 138,553 63,492
- --------------------------------------------------------------- ----------- ----------- -----------
Total.................................................... $ 181,163 $ 235,231 $ 163,571
=============================================================== =========== =========== ===========
</TABLE>
(A) Intersegment revenues are recorded at prices comparable to those of
unaffiliated customers and are affected by regulatory considerations.
(B) Intersegment interest is calculated based upon short-term loan rates and is
reviewed and updated periodically.
10. COMMITMENTS AND CONTINGENCIES
OG&E has entered into purchase commitments in connection with OG&E's
construction program and the purchase of necessary fuel supplies of coal and
natural gas for OG&E's generating units. The Company's construction expenditures
for 2000 are estimated at $251 million.
OG&E acquires some of its natural gas for boiler fuel under four
wellhead contracts, some of which contain provisions allowing the owners to
require prepayments for gas if certain minimum quantities are not taken. At
December 31, 1999, 1998 and 1997, outstanding prepayments for gas,
73
<PAGE>
including the amounts classified as current assets, under these contracts were
approximately $14.9 million, $15.2 million and $10.7 million, respectively.
At December 31, 1999, OG&E held non-cancelable operating leases
covering 1,495 coal hopper railcars. Rental payments are charged to fuel expense
and recovered through OG&E's tariffs and automatic fuel adjustment clauses. The
leases have purchase and renewal options. Future minimum lease payments due
under the railcar leases, assuming the leases are renewed under the renewal
option are as follows:
<TABLE>
<CAPTION>
DOLLARS IN THOUSANDS
================================================================================
<S> <C> <C> <C>
2000.................... $ 4,990 2003.................... $ 4,708
2001.................... 4,896 2004.................... 4,615
2002.................... 4,802 2005 and beyond......... 44,562
--------
Total Minimum Lease Payments............................... $68,573
================================================================================
</TABLE>
Rental payments under operating leases were approximately $4.9 million
in 1999, $5.3 million in 1998 and $5.4 million in 1997.
OG&E is required to maintain the railcars it has under lease to
transport coal from Wyoming and has entered into agreements with Pregressive
Rail Services and WATCO, both of which are non-affiliated companies, to furnish
this maintenance.
OG&E had entered into an agreement with Central Oklahoma Oil and Gas
Corp. ("COOG"), an unrelated third party, to develop a natural gas storage
facility. Operation of the gas storage facility proved beneficial by allowing
OG&E to lower fuel costs by base loading coal generation, a less costly fuel
supply. During 1996, OG&E completed negotiations and contracted with COOG for
gas storage service. Pursuant to the contract, COOG reimbursed OG&E for all
outstanding cash advances and interest amounting to approximately $46.8 million.
OG&E also entered into a bridge financing agreement as guarantor for COOG. In
July 1997, COOG obtained permanent financing and issued a note in the amount of
$49.5 million. The proceeds from the permanent financing were applied to repay
the outstanding bridge financing. In connection with the permanent financing,
the Company entered into a note purchase agreement, where it has agreed, upon
the occurrence of a monetary default by COOG on its permanent financing, to
purchase COOG's note at a price equal to the unpaid principal and interest under
the COOG note. In July 1998, Enogex also agreed to lease underground gas storage
from COOG. As part of this lease transaction, the Company agreed to make up to a
$12 million secured loan to an affiliate of COOG. As part of this agreement, the
Company has an $8 million loan outstanding repayable in 2003 and secured by the
assets and stock of COOG. This loan is classified as other property and
investments in the accompanying Consolidated Balance Sheets.
OG&E has entered into agreements with four qualifying cogeneration
facilities having initial terms of 3 to 32 years. These contracts were entered
into pursuant to the Public Utility Regulatory Policy Act of 1978 ("PURPA").
Stated generally, PURPA and the regulations thereunder promulgated by FERC
require OG&E to purchase power generated in a manufacturing process from a
qualified cogeneration facility ("QF"). The rate for such power to be paid by
OG&E was approved by the OCC. The rate generally consists of two components: one
is a rate for actual electricity purchased from the QF by OG&E; the other is a
capacity charge which OG&E must pay the QF for having the capacity available.
However, if no electrical power is made available to OG&E for a period of time
(generally three months), OG&E's obligation to pay the capacity charge is
suspended. The total cost of cogeneration payments is recoverable in rates from
customers.
74
<PAGE>
During 1999, 1998 and 1997, OG&E made total payments to cogenerators of
approximately $229.3 million, $226.5 million and $212.2 million, of which $188.8
million, $185.5 million and $176.2 million, respectively, represented capacity
payments. All payments for purchased power, including cogeneration, are included
in the Consolidated Statements of Income as purchased power. The future minimum
capacity payments under the contracts for the next five years are approximately:
2000 - $190 million, 2001 - $191 million, 2002 - $192 million, 2003 - $163
million and 2004 - $151 million.
Approximately $1.0 million of the Company's construction expenditures
budgeted for 2000 are to comply with environmental laws and regulations.
The Company's management believes all of its operations are in
substantial compliance with present federal, state and local environmental
standards. It is estimated that the Company's total expenditures for capital,
operating, maintenance and other costs to preserve and enhance environmental
quality will be approximately $44.4 million during 2000, compared to
approximately $43.5 million in 1999. 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.
Beginning in 2000, OG&E will be limited in the amount of sulfur dioxide
it will be allowed to emit into the atmosphere. In order to meet this limit the
Company has contracted for lower sulfur coal. OG&E believes this will allow it
to meet this limit without additional capital expenditures. With respect to
nitrogen oxides, OG&E continues to meet the current emission standard. However,
pending regulations on regional haze, and Oklahoma's potential for not being
able to meet the new ozone and particulate standards, could require further
reductions in sulfur dioxide and nitrogen oxides. If this happens, significant
capital expenditures and increased operating and maintenance costs would occur.
In 1997, the United States was a signatory to the Kyoto Protocol on
global warming. If ratified by the U.S. Senate, this Protocol could have a
tremendous impact on the Company's operations, by requiring the Company to
significantly reduce the use of coal as a fuel source, since the Protocol would
require a seven percent reduction in greenhouse gas emissions below the 1990
level.
OG&E is a party to two separate actions brought by the EPA concerning
cleanup of disposal sites. OG&E was not the owner or operator of those sites,
rather OG&E, along with many others, shipped materials to the owners or
operators of the sites who disposed of the materials. Remediation and required
monitoring at one of these sites has been completed and a consent decree from
the EPA is being obtained for this site. OG&E's total waste disposed at the
remaining site is minimal and on February 15, 1996, OG&E elected to participate
in the de minimis settlement offered by EPA. One of the other potentially
responsible parties is currently contesting OG&E's participation as a de minimis
party. Regardless of the outcome of this issue, OG&E believes its ultimate
liability for this site is minimal.
On October 22, 1998, Enogex entered into an option agreement to
purchase two gas turbine generators for use in normal operations for
approximately $27.5 million. This agreement was transferred to the Company in
September 1999. These two generators produce approximately 50 megawatts of
additional peak-load each. The total cost of this project is expected to be
approximately $47 million. In August 1999, OG&E announced the reactivation of
two of its generators that have been idle for several years. These two
generators together produce approximately 115 megawatts of additional peak-load.
The total cost of this reactivation project is expected to be approximately $9
million. By June 1, 2000, the Company plans to begin using these four
generators, increasing its electric generating capacity by approximately 4
percent.
75
<PAGE>
Trigen-Oklahoma City Energy Corp. ("Trigen") sued OG&E in the United
States District Court, Western District of Oklahoma, alleging numerous causes of
action, including monopolization of cooling services in violation of the Sherman
Act. On December 21, 1998, the jury awarded Trigen in excess of $30 million in
actual and punitive damages. On February 19, 1999, the trial court entered
judgment in favor of Trigen as follows: (i) $6.8 million for various anti-trust
violations, (ii) $4 million for tortious interference with an existing contract,
(iii) $7 million for tortious interference with a prospective economic advantage
and (iv) $10 million in punitive damages. The trial judge, in a companion order,
acknowledged that portions of the judgment could be duplicative, that the
antitrust amounts could be tripled and that parties should address these issues
in their post-trial motions. 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. OG&E expects to appeal the trial court's ruling. While the outcome of
an appeal is uncertain, legal counsel and management believe it is not probable
that Trigen will ultimately succeed in preserving the verdicts. Accordingly, the
Company has not accrued any loss associated with the damages awarded. The
Company believes that the ultimate resolution of this case will not have a
material adverse effect on the Company's consolidated financial position or
results of operations.
In the normal course of business, other lawsuits, claims, environmental
actions and other governmental proceedings arise against the Company and its
subsidiaries. Management, after consultation with legal counsel, does not
anticipate that liabilities arising out of other currently pending or threatened
lawsuits and claims will have a material adverse effect on the Company's
consolidated financial position or results of operations.
11. RATE MATTERS AND REGULATION
The OCC in its 1997 Order, 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 firms 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 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 OCC 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 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.
76
<PAGE>
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.
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 and the APSC issued an order approving the settlement on
August 6, 1999.
12. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of Long-Term Debt and Preferred Securities is estimated
based on quoted market prices and management's estimate of current rates
available for similar issues. The fair value of the Enogex Notes is based on
management's estimate of current rates available for similar issues with the
same remaining maturities.
Indicated below are the carrying amounts and estimated fair values of
the Company's financial instruments as of December 31:
<TABLE>
<CAPTION>
1999 1998 1997
------------------- ------------------- ------------------
CARRYING FAIR Carrying Fair Carrying Fair
(DOLLARS IN THOUSANDS) AMOUNT VALUE Amount Value Amount Value
======================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
Long-Term Debt and Preferred Securities:
Senior Notes........................ $457,646 $422,181 $567,512 $593,313 $581,524 $594,357
Industrial Authority Bonds.......... 135,400 135,400 135,400 135,400 135,400 135,400
Enogex Inc. Notes................... 347,486 410,578 232,671 251,505 150,000 152,915
Trust Originated Preferred
Securities........................ 200,000 200,000 --- --- --- ---
Preferred Stock:
4% - 5.34% Series - zero, zero
and 827,828 shares, respectively.. --- --- --- --- 49,266 49,997
======================================================================================================================
</TABLE>
77
<PAGE>
13. SUBSEQUENT EVENTS
In January 2000, the Company increased its agreement for a line of
credit from $200 million to $300 million, $200 million to expire on January 15,
2001, and $100 million to expire on January 15, 2004.
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 January 14, 2000, Enogex sold $400 million of 8.125 percent senior
unsecured notes due January 15, 2010. Enogex entered into a series of interest
rate swap agreements to manage interest costs associated with this $400 million
issue. The effect of these swap agreements reduces the overall effective
interest rate from 8.125 percent to 6.6875 percent during the first year. The
proceeds from the sale of this new debt were used to repay the remaining balance
of the temporary short-term debt associated with the Transok acquisition and for
general corporate purposes.
78
<PAGE>
Report of Independent Public Accountants
- ----------------------------------------
ARTHUR ANDERSEN LLP
TO THE SHAREOWNERS OF
OGE ENERGY CORP.:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of OGE Energy Corp. (an Oklahoma corporation) and
its subsidiaries as of December 31, 1999, 1998 and 1997, and the related
consolidated statements of income, retained earnings and cash flows for the
years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of OGE Energy Corp. and
its subsidiaries as of December 31, 1999, 1998 and 1997, and the results of
their operations and their cash flows for the years then ended in conformity
with accounting principles generally accepted in the United States.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 20, 2000
79
<PAGE>
Report of Management
- --------------------
TO OUR SHAREOWNERS:
The management of OGE Energy Corp. is responsible for the preparation,
integrity and objectivity of the consolidated financial statements of the
Company and its subsidiaries and other information included in this report. The
consolidated financial statements have been prepared in conformity with
accounting principles generally accepted in the United States. As appropriate,
the statements include amounts based on informed estimates and judgments of
management.
The management of the Company has established and maintains a system of
internal control designed to provide reasonable assurance, on a cost-effective
basis, that assets are safeguarded, transactions are executed in accordance with
management's authorization and financial records are reliable for preparing
consolidated financial statements. Management believes that the system of
control provides reasonable assurance that errors or irregularities that could
be material to the consolidated financial statements are prevented or would be
detected within a timely period. Key elements of this system include the
effective communication of established written policies and procedures,
selection and training of qualified personnel and organizational arrangements
that provide an appropriate division of responsibility. This system of control
is augmented by an ongoing internal audit program designed to evaluate its
adequacy and effectiveness. Management considers the recommendations of the
internal auditors and independent certified public accountants concerning the
Company's system of internal control and takes timely and appropriate actions to
alleviate their concerns. Management believes that as of December 31, 1999, the
Company's system of internal control was adequate to accomplish the objectives
discussed herein.
The Board of Directors of the Company addresses its oversight
responsibility for the consolidated financial statements through its Audit
Committee, which is composed of directors who are not employees of the Company.
The Audit Committee meets regularly with the Company's management, internal
auditors and independent certified public accountants to review matters relating
to financial reporting, auditing and internal control. To ensure auditor
independence, both the internal auditors and independent certified public
accountants have full and free access to the Audit Committee.
The independent certified public accounting firm of Arthur Andersen LLP
is engaged to audit, in accordance with auditing standards generally accepted in
the United States, the consolidated financial statements of the Company and its
subsidiaries and to issue their report thereon.
/s/ Steven E. Moore /s/ Al M. Strecker
---------------------------------------- -------------------------------
Steven E. Moore, Chairman of the Board, Al M. Strecker, Executive Vice
President and Chief Executive Officer President and Chief Operating
Officer
/s/ James R. Hatfield /s/ Donald R. Rowlett
---------------------------------------- -------------------------------
James R. Hatfield, Sr. Vice President, Donald R. Rowlett, Vice
Chief Financial Officer and Treasurer President and Controller
80
<PAGE>
SUPPLEMENTARY DATA
- ------------------
Interim Consolidated Financial Information (Unaudited)
- ------------------------------------------------------
In the opinion of the Company, the following quarterly information
includes all adjustments, consisting of normal recurring adjustments, necessary
for a fair statement of the results of operations for such periods:
<TABLE>
<CAPTION>
Quarter ended (DOLLARS IN THOUSANDS EXCEPT Dec 31 Sep 30 Jun 30 Mar 31
PER SHARE DATA)
=============================================================================================================
<S> <C> <C> <C> <C> <C>
Operating revenues............................. 1999 $ 575,978 $ 767,390 $ 450,861 $ 378,205
1998 361,750 555,999 412,621 287,367
1997 344,580 474,587 333,228 291,215
=============================================================================================================
Operating income............................... 1999 $ 50,570 $ 180,373 $ 73,147 $ 34,075
1998 25,147 126,602 64,660 14,404
1997 26,680 103,268 48,049 16,001
=============================================================================================================
Net income (loss).............................. 1999 $ 12,179 $ 90,204 $ 37,744 $ 11,132
1998 10,230 108,117 47,865 (340)
1997 12,205 89,520 31,085 (260)
=============================================================================================================
Earnings (loss) available for common.stock..... 1999 $ 12,179 $ 90,204 $ 37,744 $ 11,132
1998 10,230 108,117 47,865 (1,073)
1997 11,634 88,949 30,513 (831)
=============================================================================================================
Earnings (loss) per average common share....... 1999 $ 0.15 $ 1.16 $ 0.49 $ 0.14
1998 0.13 1.33 0.59 (0.01)
1997 0.14 1.10 0.38 (0.01)
=============================================================================================================
</TABLE>
81
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
- --------------------------------------------------------------------
AND FINANCIAL DISCLOSURE.
------------------------
Not Applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
- -----------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION.
- -------------------------------
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
- -------------------------------------------------
OWNERS AND MANAGEMENT.
---------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
- -------------------------------------------------------
Items 10, 11, 12 and 13 are omitted pursuant to General Instruction G
of Form 10-K, since the Company filed copies of a definitive proxy statement
with the Securities and Exchange Commission on or about March 28, 2000. Such
proxy statement is incorporated herein by reference. In accordance with
Instruction G of Form 10-K, the information required by Item 10 relating to
Executive Officers has been included in Part I, Item 4, of this Form 10-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
- ----------------------------------------------------
REPORTS ON FORM 8-K.
-------------------
(A) 1. FINANCIAL STATEMENTS
- ---------------------------
The following consolidated financial statements and supplementary data
are included in Part II, Item 8 of this Report:
o Consolidated Balance Sheets at December 31, 1999, 1998 and 1997
o Consolidated Statements of Income for the years ended December 31, 1999,
1998 and 1997
o Consolidated Statements of Retained Earnings for the years ended December
31, 1999, 1998 and 1997
o Consolidated Statements of Capitalization at December 31, 1999, 1998 and
1997
o Consolidated Statements of Cash Flows for the years ended December 31, 1999,
1998 and 1997
o Notes to Consolidated Financial Statements
o Report of Independent Public Accountants
o Report of Management
82
<PAGE>
SUPPLEMENTARY DATA
------------------
o Interim Consolidated Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE
- ----------------------------------------------------- ----
Schedule II - Valuation and Qualifying Accounts 87
Report of Independent Public Accountants 88
Financial Data Schedule 106
All other schedules have been omitted since the required information is
not applicable or is not material, or because the information required is
included in the respective financial statements or notes thereto.
3. EXHIBITS
- -----------
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ---------- -----------
<S> <C>
2.01 Purchase Agreement, dated as of May 14, 1999, by and between
Tejas Gas, LLC and Enogex Inc. (Filed as Exhibit 2.01
to OGE Energy's Form 10-Q for the quarter ended
June 30, 1999 (File No. 1-12579) and incorporated by
reference herein)
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit
3.01 to OGE Energy's Form 10-K for the year ended
December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 3.02 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
4.01 Copy of Trust Indenture dated
October 1, 1995, from OG&E to
Boatmen's First National Bank of Oklahoma, Trustee.
(Filed as Exhibit 4.29 to Registration Statement No. 33-61821
and incorporated by reference herein)
4.02 Copy of Supplemental Trust Indenture No. 1 dated
October 16, 1995, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to
OG&E's Form 8-K Report dated October 23, 1995,
File No. 1-1097, and incorporated by reference herein)
</TABLE>
83
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
4.03 Supplemental Indenture No. 2, dated as of July 1, 1997,
being a supplemental instrument to Exhibit
4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K
filed on July 17, 1997, (File No. 1-1097) and incorporated
by reference herein)
4.04 Supplemental Indenture No. 3, dated as of April 1, 1998,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.01 to OG&E's Form 8-K filed on
April 16, 1998 (File No. 1-1097) and incorporated
by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between
OG&E and Atlantic Richfield Company. (Filed as
Exhibit 5.19 to Registration Statement No. 2-59887
and incorporated by reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between OG&E
and Atlantic Richfield Company, together with
related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply
Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company.
(Filed as Exhibit 5.28 to Registration Statement
No. 2-62208 and incorporated by reference herein)
10.04 Amendment dated June 27, 1990, between OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between OG&E and Atlantic
Richfield Company. (Filed as Exhibit 10.04 to
OG&E's Form 10-K Report for the year ended
December 31, 1994, File No. 1-1097, and incorporated
by reference herein) [Confidential Treatment has been
requested for certain portions of this exhibit.]
10.05 Form of Change of Control Agreement for Officers of the
Company and OG&E. (Filed as Exhibit 10.07 to
OGE Energy's Form 10-K for the year ended
December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.06 Directors' Deferred Compensation Plan
10.07 Company's Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE
Energy's Form 10-K for the year ended December 31, 1998
(File No. 1-12579) and incorporated by reference herein)
</TABLE>
84
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
10.08 OG&E's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.09 OG&E's Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.10 Company's Annual Incentive Compensation Plan. (Filed as
Exhibit 10.12 to OGE Energy's Form 10-K for the
year ended December 31, 1998 (File No. 1-12579)
and incorporated by reference herein)
10.11 Company's Deferred Compensation Plan (Filed as Exhibit 4
to the Company's Form S-8 Registration Statement
No. 333-92433 and incorporated by reference herein)
21.01 Subsidiaries of the Registrant.
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995.
</TABLE>
85
<PAGE>
<TABLE>
<CAPTION>
Executive Compensation Plans and Arrangements
---------------------------------------------
<S> <C>
10.05 Form of Change of Control Agreement for Officers of the
Company and OG&E. (Filed as Exhibit 10.07 to
OGE Energy's Form 10-K for the year ended
December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.06 Directors' Deferred Compensation Plan
10.07 Company's Stock Incentive Plan. (Filed as Exhibit 10.07 to
OGE Energy's Form 10-K for the year ended
December 31, 1998 (File No. 1-12579) and
incorporated by reference herein)
10.08 OG&E's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.09 OG&E's Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.10 Company's Annual Incentive Compensation Plan. (Filed as
Exhibit 10.12 to OGE Energy's Form 10-K for the
year ended December 31, 1998 (File No. 1-12579)
and incorporated by reference herein)
10.11 Company's Deferred Compensation Plan (Filed as Exhibit 4
to the Company's Form S-8 Registration Statement
No. 333-92423 and incorporated by reference herein)
</TABLE>
(B) REPORTS ON FORM 8-K
- ------------------------
Item 5. Other Events, dated May 20, 1999.
Item 5. Other Events, dated July 8, 1999.
Item 2. Acquisition of Assets, dated July 13, 1999.
Item 5. Other Events, dated July 16, 1999.
Item 7. Financial statements and Exhibits, dated July 13, 1999
(Form 8-K/A filed on September 13, 1999).
Item 7. Financial Statements and Exhibits, dated July 13, 1999
(Form 8-K/A-2 filed on September 14, 1999).
Item 5. Other Events, dated October 21, 1999.
Item 5. Other Events, dated December 8, 1999.
86
<PAGE>
OGE ENERGY CORP.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
BALANCE CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS YEAR
- ----------- --------- --------------------------- ---------- --------
<S> <C> <C> <C> <C>
1999 (THOUSANDS)
Reserve for Uncollectible Accounts $ 3,342 $ 9,560 - $ 7,632 $ 5,270
1998
Reserve for Uncollectible Accounts $ 4,507 $11,507 - $12,672 $ 3,342
1997
Reserve for Uncollectible Accounts $ 4,626 $ 7,334 - $ 7,453 $ 4,507
</TABLE>
87
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To OGE Energy Corp.:
We have audited in accordance with auditing standards generally
accepted in the United States, the consolidated financial statements of OGE
Energy Corp. (an Oklahoma Corporation), and its subsidiaries included in this
Form 10-K, and have issued our report thereon dated January 20, 2000. Our audits
were made for the purpose of forming an opinion on those statements taken as a
whole. The schedule listed on Page 83 Item 14 (a) 2. is the responsibility of
the Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
/ s / Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 20, 2000
88
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, the Registrant has duly caused this Report to be signed on its behalf
by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and
State of Oklahoma on the 24th day of March, 2000.
OGE ENERGY CORP.
(REGISTRANT)
/s/ Steven E. Moore
By Steven E. Moore
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this Report has been signed below by the following persons in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
- ----------------------------- ----------------------- --------------
<S> <C> <C>
/ s / Steven E. Moore
Steven E. Moore Principal Executive
Officer and Director; March 24, 2000
/ s / James R. Hatfield
James R. Hatfield Principal Financial
Officer. March 24, 2000
/ s / Donald R. Rowlett
Donald R. Rowlett Principal Accounting
Officer. March 24, 2000
Herbert H. Champlin Director;
Luke R. Corbett Director;
William E. Durrett Director;
Martha W. Griffin Director;
Hugh L. Hembree, III Director;
Robert Kelley Director;
Bill Swisher Director; and
Ronald H. White, M.D. Director.
/ s / Steven E. Moore
By Steven E. Moore (attorney-in-fact) March 24, 2000
</TABLE>
89
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ---------- -----------
<S> <C>
2.01 Purchase Agreement, dated as of May 14, 1999, by and between
Tejas Gas, LLC and Enogex Inc. (Filed as Exhibit 2.01
to OGE Energy's Form 10-Q for the quarter ended
June 30, 1999 (File No. 1-12579) and incorporated
by reference herein)
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit
3.01 to OGE Energy's Form 10-K for the year ended
December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
3.02 By-laws. (Filed as Exhibit 3.02 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
4.01 Copy of Trust Indenture, dated
October 1, 1995, from OG&E to
Boatmen's First National Bank of Oklahoma, Trustee.
(Filed as Exhibit 4.29 to Registration Statement No. 33-61821
and incorporated by reference herein)
4.02 Copy of Supplemental Trust Indenture No. 1, dated
October 16, 1995, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.01 to
OG&E's Form 8-K Report dated October 23, 1995,
(File No. 1-1097) and incorporated by reference herein)
4.03 Supplemental Indenture No. 2, dated as of July 1, 1997,
being a supplemental instrument to Exhibit
4.01 hereto. (Filed as Exhibit 4.01 to OG&E's Form 8-K
filed on July 17, 1997, (File No. 1-1097) and incorporated
by reference herein)
4.04 Supplemental Indenture No. 3, dated as of April 1, 1998,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.01 to OG&E's Form 8-K filed on
April 16, 1998 (File No. 1-1097) and incorporated
by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between
OG&E and Atlantic Richfield Company. (Filed as
Exhibit 5.19 to Registration Statement No. 2-59887
and incorporated by reference herein)
</TABLE>
90
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between OG&E
and Atlantic Richfield Company, together with
related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply
Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company.
(Filed as Exhibit 5.28 to Registration Statement
No. 2-62208 and incorporated by reference herein)
10.04 Amendment dated June 27, 1990, between OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between OG&E and Atlantic
Richfield Company. (Filed as Exhibit 10.04 to
OG&E's Form 10-K Report for the year ended
December 31, 1994, (File No. 1-1097) and incorporated
by reference herein) [Confidential Treatment has been
requested for certain portions of this exhibit.]
10.05 Form of Change of Control Agreement for Officers of the
Company and OG&E. (Filed as Exhibit 10.07 to
OGE Energy's Form 10-K for the year ended
December 31, 1996 (File No. 1-12579) and
incorporated by reference herein)
10.06 Directors' Deferred Compensation Plan
10.07 Company's Stock Incentive Plan. (Filed as Exhibit 10.07 to OGE
Energy's Form 10-K for the year ended December 31, 1998
(File No. 1-12579) and incorporated by reference herein)
10.08 OG&E's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.09 OG&E's Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K
for the year ended December 31, 1996 (File No.
1-12579) and incorporated by reference herein)
10.10 Company's Annual Incentive Compensation Plan. (Filed as
Exhibit 10.12 to OGE Energy's Form 10-K for the
Year ended December 31, 1998 (File No. 1-12579)
and incorporated by reference herein)
</TABLE>
91
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
10.11 Company's Deferred Compensation Plan (Filed as Exhibit 4
to the Company's Form S-8 Registration statement
No. 333-92423 and incorporated by reference herein)
21.01 Subsidiaries of the Registrant.
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995
</TABLE>
92
EXHIBIT 10.06
OGE ENERGY CORP.
DIRECTORS' DEFERRED COMPENSATION PLAN
Effective January 1, 2000
93
<PAGE>
OGE ENERGY CORP.
DIRECTORS' DEFERRED COMPENSATION PLAN
-------------------------------------
I. PURPOSE AND EFFECTIVE DATE
1.1. Purpose. The OGE Energy Corp. Directors' Deferred Compensation
-------
Plan has been established by OGE Energy Corp. to attract and
retain non-employee members of its Board of Directors by
providing a tax-deferred capital accumulation vehicle for such
directors.
1.2. Effective Date. The Plan shall be effective January 1, 2000
---------------
and shall remain in effect until terminated in accordance with
Article 9.
1.3. Continuation of Prior Plan. The Plan is intended to be an
----------------------------
amendment, restatement and continuation of the Stock
Equivalent and Deferred Compensation Plan For Directors of OGE
Energy Corp. (the "Prior Plan").
II. DEFINITIONS
When used in the Plan and initially capitalized, the following words
and phrases shall have the meanings indicated:
2.1. "Account" means the recordkeeping account established for each
Participant in the Plan for purposes of accounting for the
amount of Compensation deferred or Discretionary Awards, if
any, awarded under Article 4, adjusted periodically to reflect
assumed investment return on such deferrals and awards in
accordance with Article 5.
2.2. "Administrator" means a committee consisting of the Chairman
of the Board and the Company's President, Chief Financial
Officer and Corporate Secretary or such other individual or
committee appointed by the Board to administer the Plan in
accordance with Article 8.
2.3. "Beneficiary" means the person or entity designated by the
Participant to receive the Participant's Plan benefits in the
event of the Participant's death. If the Participant does not
designate a Beneficiary, or if the Participant's designated
Beneficiary predeceases the Participant, the Participant's
estate shall be the Participant's Beneficiary under the Plan.
2.4. "Board" means the Board of Directors of the Company.
2.5. "Change in Control" means the happening of any of the
following events:
(a) An acquisition by any individual, entity or group
(within the meaning of Section 13(d)(3) or 14(d)(2)
of the Securities Exchange Act of 1934 ("Exchange
Act")) (a "Person") of beneficial ownership (within
the meaning of Rule 13d-3 promulgated under the
Exchange Act) of 20% or more of either (1) the then
outstanding shares of common stock of the Company
(the "Outstanding Company Common Stock") or (2) the
combined voting power of the then outstanding voting
securities of the Company entitled to vote generally
in the
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<PAGE>
election of directors (the "Outstanding Company
Voting Securities"); excluding however the following:
(1) any acquisition directly from the Company, (2)
any acquisition by the Company, (3) any acquisition
by any employee benefit plan (or related trust)
sponsored by or maintained by the Company or any
corporation controlled by the Company or (4) any
acquisition by any corporation pursuant to a
transaction which complies with clauses (1), (2) and
(3) of subsection (c) of this Section 2.5;
(b) a change in the composition of the Board such that
the individuals who as of January 1, 2000, constitute
the Board (the "Incumbent Board") cease for any
reason to constitute at least a majority of the
Board; provided, however, for purposes of this
Section 2.5, that any individual who becomes a member
of the Board subsequent to January 1, 2000, whose
election or nomination for election by the Company's
shareowners was approved by a vote of at least a
majority of those individuals then comprising the
Incumbent Board shall be considered as though such
individual were a member of the Incumbent Board; but
provided further, that any such individual whose
initial assumption of office occurs as a result of
either an actual or threatened election contest with
respect to the election or removal of directors or
other actual or threatened solicitation of proxies or
consents by or on behalf of a Person other than the
Board shall not be so considered as a member of the
Incumbent Board; or
(c) consummation of a reorganization, merger, share
exchange or consolidation or sale or other
disposition of all or substantially all of the assets
of the Company (a "Business Combination"), excluding,
however, such a Business Combination pursuant to
which (1) all or substantially all of the individuals
and entities who are the beneficial owners,
respectively, of the Outstanding Company Common Stock
and Outstanding Company Voting Securities immediately
prior to such Business Combination beneficially own,
directly or indirectly, more than 60% of,
respectively, the outstanding shares of common stock
and the combined voting power of the then outstanding
voting securities entitled to vote generally in the
election of directors, as the case may be, of the
corporation resulting from such Business Combination
(including, without limitation, a corporation which
as a result of such transaction owns the Company or
all or substantially all of the Company's assets
either directly or through one or more subsidiaries)
in substantially the same proportions as their
ownership, immediately prior to such Business
Combination, of the Outstanding Company Common Stock
and Outstanding Company Voting Securities, as the
case may be, (2) no Person (other than the
corporation resulting from such Business Combination
or any employee benefit plan (or related trust) of
the Company or such corporation resulting from such
Business Combination) beneficially owns, directly or
indirectly, 20% or more of, respectively, the
outstanding shares of common stock of the corporation
resulting from such Business Combination or the
combined voting power of the outstanding voting
securities of such corporation except to the extent
that such ownership existed prior to the Business
Combination and (3) at least a majority of the
members of the board of directors of the corporation
resulting from such Business Combination were members
of the Incumbent Board at the time of the execution
of the initial agreement, or the action of the Board
providing for such Business Combination; or
95
<PAGE>
(d) the approval by the shareholders of the Company of a
complete liquidation or dissolution of the Company.
2.6. "Code" means the Internal Revenue Code of 1986, as amended.
2.7. "Company" means OGE Energy Corp. and any successor thereto.
2.8. "Compensation" means annual retainer and attendance fees
payable to an Eligible Director for services as a member of
the Board.
2.9. "Deferral Election" means the election made by an Eligible
Director to defer Compensation in accordance with Article 4.
2.10. "Discretionary Award" means an award granted under the Plan to
an Eligible Director in accordance with Section 4.5.
2.11. "Election Period" means the period specified by the
Administrator during which a Deferral Election may be made
with respect to Compensation payable for a Plan Year.
2.12. "Eligible Director" means a member of the Board who is not
also an employee of the Company.
2.13. "Participant" means an Eligible Director who has elected to
defer Compensation under the Plan or who has been credited
with a Discretionary Award.
2.14. "Plan" means the OGE Energy Corp. Directors' Deferred
Compensation Plan, as amended from time to time.
2.15. "Plan Year" means the calendar year.
2.16. "Valuation Date" means a date on which a Participant's Account
is valued, which shall be the last day of each calendar month
and such other dates as may be specified by the Administrator.
III. PARTICIPATION
An Eligible Director shall become a Participant in the Plan by filing a
Deferral Election with the Administrator in accordance with Article 4.
An Eligible Director who is not otherwise a Participant in the Plan
shall become a Participant in the Plan on the date he or she is
credited with a Discretionary Award.
IV. DEFERRAL OF COMPENSATION
4.1. Deferral of Compensation. An Eligible Director may elect to
-------------------------
defer up to 100% of his or her Compensation for a Plan Year by
filing a Deferral Election in accordance with Section 4.2.
96
<PAGE>
4.2. Deferral Elections. A Participant's Deferral Election shall be
------------------
in writing, and filed with the Administrator at such time and
in such manner as the Administrator shall provide, subject to
the following:
(a) Except as provided in subsection (d) below, a
Deferral Election shall be made during the election
period established by the Administrator which shall
end no later than the day preceding the first day of
the Plan Year in which such Compensation would
otherwise be payable.
(b) Deferral Elections may be expressed as a percentage
or fixed dollar amount of Compensation, within the
limits provided under the Plan.
(c) The minimum annual deferral under the Plan shall be
$2,500 and any Deferral Election which would provide
a lesser deferral for a Plan Year shall be
disregarded for such Plan Year.
(d) Notwithstanding the foregoing provisions of this
Section 4.2, the Administrator, in its sole
discretion, may provide that an individual who
becomes an Eligible Director after the first day of a
Plan Year may make a Deferral Election within 30 days
of first becoming an Eligible Director, which
Deferral Election shall relate to Compensation earned
for periods after the date such election is made.
Once made, a Deferral Election shall remain in effect for
subsequent Plan Years unless changed or revoked by the
Participant in accordance with rules established by the
Administrator. Any such modification or revocation shall be
effective for the Plan Year following the Plan Year in which
it is made; provided that such revocation shall become
effective as soon as practicable in the event it is made
because of the Participant's disability (as determined by the
Administrator) or if the Administrator, in its sole
discretion, determines that the Participant has suffered a
severe financial hardship or a bona fide administrative
mistake was made. If a Deferral Election is revoked in
accordance with the preceding sentence, the Participant may
not make a new Deferral Election until the election period
established by the Administrator for making deferrals for the
next Plan Year.
4.4. Crediting of Deferral Elections. The amount of Compensation
--------------------------------
that a Participant elects to defer under the Plan shall be
credited by the Company to the Participant's Account as of the
first day of the month next following the date the
Compensation would have been payable absent the Deferral
Election.
4.5. Discretionary Awards. The Administrator, in its sole
----------------------
discretion, may grant an Eligible Director a Discretionary
Award under the Plan which shall be subject to the terms and
conditions established by the Administrator, including those
relating to how such credit shall be deemed invested and when
such amount shall be credited to the Eligible Director's
Account.
4.6. Account Under Prior Plan. As of the effective date of the
--------------------------
Plan, each Participant's account balance under the Prior Plan,
if any, shall be credited to the Participant's Account under
this Plan.
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<PAGE>
V. PLAN ACCOUNTS
5.1. Valuation of Accounts. The Administrator shall establish an
---------------------
Account for each Participant who has filed a Deferral Election
to defer Compensation, who has been awarded a Discretionary
Award, or who has an account under the Prior Plan on the
effective date of this Plan. Such Account shall be credited
with a Participant's deferrals or Discretionary Awards as set
forth in Sections 4.4 and 4.5, respectively, and with the
Participant's Prior Plan account balance, if any. As of each
Valuation Date, the Participant's Account shall be adjusted
upward or downward to reflect (i) the investment return to be
credited as of such Valuation Date pursuant to Section 5.2,
and (ii) the amount of distributions, if any, to be debited as
of that Valuation Date under Article 6 or Article 7.
5.2. Crediting of Investment Return. Subject to such rules and
---------------------------------
limitations as the Administrator may determine, each
Participant shall designate from among the assumed investment
alternatives established by the Administrator under Section
5.3, one or more assumed investments in which the amounts
credited to his or her Account shall be deemed invested. As of
each Valuation Date, a Participant's Account balance shall be
adjusted upward or downward for increases and decreases in the
fair market value of the investments in which it is deemed
invested during the period since the immediately preceding
Valuation Date. On or before the first day of each month, a
Participant may make a new election with respect to the
assumed investments in which his or her Account shall be
deemed invested in the future. Any such election shall be made
in the form and at the time specified by the Administrator;
provided, however, that deferred amounts that would have been
received in the form of Company common stock absent a deferral
election shall be deemed to be invested in the assumed
investment alternative based on the Company's common stock. If
the Participant elected to have any portion of his or her
account under the Prior Plan governed under Article 3 of the
Prior Plan (relating to split dollar life insurance), the
portion so elected shall continue to be subject to the
provisions of such Article 3 and no assumed investment
elections may be made with respect to such amount under this
Section 5.2.
5.3. Assumed Investment Alternatives. The Administrator shall
---------------------------------
designate the assumed investment alternatives that will be
available from time to time under the Plan for purposes of
measuring a Participant's investment return under Section 5.2.
Such assumed investment alternatives shall include an assumed
investment in Company common stock. The value of deemed
investments in Company common stock shall be determined based
on the fair market value of a share of Company common stock as
reported on the New York Stock Exchange composite tape at the
close of business on the last business day of the month
preceding the date on which the amount or value of such
investment is being determined.
5.4. Investment Alternatives After Death. For periods after the
-------------------------------------
Valuation Date coincident with or following a Participant's
death, the Participant's Account balance shall be treated as
if it were invested in a fixed interest rate account at
prevailing short-term interest rates, as determined by the
Administrator. Beneficiaries shall not be permitted to make
elections with respect to assumed investment alternatives
under the Plan.
98
<PAGE>
VI. PAYMENT OF BENEFITS
6.1. Distribution at Specific Future Date. At the time a
------------------------------------------
Participant initially elects to participate in the Plan, the
Participant may elect one or more future Valuation Dates on
which all or a portion of his or her Account as of such date
shall be paid. Any such future date shall be a Valuation Date
in a specific future year which is at least two Plan Years
after the Plan Year for which the initial Deferral Election is
made; provided, however, that only one distribution per Plan
Year may be elected under this Section 6.1; provided, further
that, if the Participant elects a distribution at one or more
specific future dates and terminates service on the Board
prior to any such date, distribution shall commence pursuant
to Sections 6.2 or 7.1, as applicable. A distribution election
under this Section 6.1 may be revoked or extended to a
Valuation Date in a future Plan Year by filing a one-time
revocation or extension election with the Administrator at
least 12 months prior to the first day of the Plan Year in
which such distribution was scheduled to take place.
6.2. Distribution Upon Termination of Board Service. Distribution
-----------------------------------------------
of a Participant's Account shall be made or commence as of the
Valuation Date coincident with or next following the
Participant's termination of service on the Board.
Distribution shall be made (i) in a lump sum, (ii) in
substantially equal annual installments of up to 15 years, or
(iii) in a combination of (i) and (ii), as elected by the
Participant. A Participant may change the time and form of his
or her distribution election under this Section 6.2 by filing
a new election with the Administrator; provided, however, that
any election that has not been on file with the Administrator
at least 12 months prior to the first day of the Plan Year in
which the Participant's termination of service on the Board
occurs shall be disregarded. If the Participant does not have
a valid election on file with the Administrator at the time
Board membership ceases, the Participant's Account shall be
paid in a single lump sum.
6.3. Unscheduled Withdrawal. A Participant may request a withdrawal
----------------------
of all or a portion of his or her Account by filing an
election with the Administrator specifying the amount of the
Account to be withdrawn. Payment of such amount, adjusted by
the amount forfeited in subsection (a) below, shall be made as
of the first Valuation Date administratively practicable after
such request is received, and shall be subject to the
following:
(a) An amount equal to 10% of the withdrawal requested
shall be debited to the Participant's Account and
permanently forfeited.
(b) Any Deferral Election in effect at the time of such
withdrawal shall be void for periods after such
withdrawal.
(c) The Participant shall not be eligible to file a new
Deferral Election until the election period for the
Plan Year commencing at least one year after such
withdrawal.
6.4. Unforeseeable Emergency. Prior to the date otherwise scheduled
-----------------------
for payment under the Plan, upon showing an unforeseeable
emergency, a Participant may request that the Administrator
accelerate payment of all or a portion of his or her Account
in an amount not exceeding the amount necessary to meet the
unforeseeable emergency. For purposes of the Plan, an
unforeseeable emergency means an unanticipated emergency that
is caused by an event beyond the control of the Participant
and that would result in severe
99
<PAGE>
financial hardship to the Participant if early withdrawal were
not permitted. The determination of an unforeseeable emergency
shall be made by the Administrator in its sole discretion,
based on such information as the Administrator shall deem to
be necessary.
6.5. Time and Form of Elections. All distribution and withdrawal
--------------------------
elections under this Article 6 shall be made at the time and
in the form established by the Administrator and shall be
subject to such other rules and limitations that the
Administrator, in its sole discretion, may establish.
VII. DEATH BENEFITS
7.1. Death Prior to Commencement of Benefits. If a Participant dies
---------------------------------------
prior to commencement of payment of his or her Account, the
Participant's Beneficiary shall receive a survivor benefit in
an amount equal to the sum of:
(a) the Participant's Account balance,
plus
----
(b) the Participant's total Compensation deferrals under
the Plan for periods on or after January 1, 2000,
multiplied by two.
Such survivor benefit shall be paid in a single lump sum as
soon as practicable following the Participant's death.
7.2. Death After Commencement of Benefits. If a Participant dies
-------------------------------------
after commencement of benefits but prior to the time his or
her Account balance has been fully distributed, the
Participant's Beneficiary shall receive the remaining portion
of the Participant's Account at the regularly scheduled date
of payment for any remaining installments payments of the
Participant's Account.
7.3. Other Conditions. Notwithstanding the foregoing provisions of
----------------
this Article 7, if the Participant's death occurs within two
years of initial Plan participation, and such death occurs by
reason of suicide (as reported on the Participant's death
certificate or determined by the Administrator in good faith),
the Participant's Beneficiary shall receive the Participant's
Account balance as of the date of his or her death in full
satisfaction of the Company's obligations under the Plan.
7.4. Administrator Discretion Regarding Form. Notwithstanding the
----------------------------------------
foregoing provisions of this Article 7, a Beneficiary may
request that the Administrator approve an alternate form of
payment of survivor benefits under this Article 7 which
request may be granted in the sole discretion of the
Administrator.
VIII. ADMINISTRATION
8.1. Authority of Administrator. The Administrator shall have full
--------------------------
power and authority to carry out the terms of the Plan. The
Administrator's interpretation, construction and
100
<PAGE>
administration of the Plan, including any adjustment of the
amount or recipient of the payments to be made, shall be
binding and conclusive on all persons for all purposes.
Neither the Company, including its officers, employees or
directors, nor the Administrator or the Board or any member
thereof, shall be liable to any person for any action taken or
omitted in connection with the interpretation, construction
and administration of the Plan.
8.2. Participant's Duty to Furnish Information. Each Participant
-------------------------------------------
shall furnish to the Administrator such information as it may
from time to time request for the purpose of the proper
administration of this Plan.
8.3. Claims Procedure. If a Participant or Beneficiary ("Claimant")
----------------
is denied all or a portion of an expected benefit under this
Plan for any reason, he or she may file a claim with the
Administrator. The Administrator shall notify the Claimant
within 90 days of allowance or denial of the claim, unless the
Claimant receives written notice from the Administrator prior
to the end of the 90-day period stating that special
circumstances require an extension (of up to 90 additional
days) of the time for decision. The notice of the decision
shall be in writing, sent by mail to Claimant's last known
address, and if a denial of the claim, shall contain the
following information: (a) the specific reasons for the
denial; (b) specific reference to pertinent provisions of the
Plan on which the denial is based; and (c) if applicable, a
description of any additional information or material
necessary to perfect the claim, an explanation of why such
information or material is necessary, and an explanation of
the claims review procedure. A Claimant is entitled to request
a review of any denial of his or her claim by the Board. The
request for review must be submitted within 60 days of mailing
of notice of the denial. Absent a request for review within
the 60-day period, the claim shall be deemed to be
conclusively denied. The Claimant or his or her
representatives shall be entitled to review all pertinent
documents, and to submit issues and comments in writing. The
Board shall render a review decision in writing within 60 days
after receipt of a request for a review, provided that, in
special circumstances the Board may extend the time for
decision by not more than 60 days upon written notice to the
Claimant. The Claimant shall receive written notice of the
Board's review decision, together with specific reasons for
the decision and reference to the pertinent provisions of the
Plan.
IX. AMENDMENT AND TERMINATION
The Board may amend or terminate the Plan at any time; provided,
however, that no such amendment or termination shall have a material
adverse effect on any Participant's rights under the Plan accrued as of
the date of such amendment or termination. Upon termination of the
Plan, the Board, in its discretion, may cause a lump-sum payment of all
benefits for all Participants at substantially the same time.
X. MISCELLANEOUS
10.1. No Implied Rights; Rights on Termination of Service. Neither
----------------------------------------------------
the establishment of the Plan nor any amendment thereof shall
be construed as giving any Participant, Beneficiary or any
other person, individually or as a member of a group, any
legal or equitable right unless such right shall be
specifically provided for in the Plan or
101
<PAGE>
conferred by specific action of the Board or the Administrator
in accordance with the terms and provisions of the Plan.
Except as expressly provided in this Plan, neither the Company
nor any of its Affiliates shall be required or be liable to
make any payment under the Plan.
10.2. Unfunded Plan. No funds shall be segregated or earmarked for
--------------
any current or former Participant, Beneficiary or other person
under the Plan. However, the Company may establish one or more
trusts to assist in meeting its obligations under the Plan,
the assets of which shall be subject to the claims of the
Company's general creditors. No current or former Participant,
Beneficiary or other person, individually or as a member of a
group, shall have any right, title or interest in any account,
fund, grantor trust, or any asset that may be acquired by the
Company in respect of its obligations under the Plan (other
than as a general creditor of the Company with an unsecured
claim against its general assets). The Company may also choose
to use life insurance to assist it in meeting its obligations
under the Plan. As a condition of participation in the Plan,
each Participant agrees to execute any documents that may be
required in connection with obtaining such insurance and to
cooperate with any life insurance underwriting requirements;
provided, however, that a Participant shall not be required to
undergo a medical examination in connection therewith.
10.3. Nontransferability. Prior to payment thereof, no benefit under
------------------
the Plan shall be assignable or subject to any manner of
alienation, sale, transfer, claims of creditors, pledge,
attachment or encumbrances of any kind, except pursuant to a
domestic relations order awarding benefits to an "alternate
payee" (within the meaning of Code Section 414(p)(8)) that the
Administrator determines satisfies the criteria set forth in
paragraphs (1), (2) and (3) of Code Section 414(p) (a "DRO").
Notwithstanding any provision of the Plan to the contrary, the
Plan benefits awarded to an alternate payee under a DRO shall
be paid in a single lump sum to the alternate payee on the
Valuation Date as soon as administratively practicable
following the date the Administrator determines the order is a
DRO, and such amounts, as adjusted for earnings, gains and
losses, will be deducted from the Participant's Account as of
such Valuation Date.
10.4. Successors and Assigns. The rights, privileges, benefits and
----------------------
obligations under the Plan are intended to be, and shall be
treated as legal obligations of and binding upon the Company,
its successors and assigns, including successors by merger,
consolidation, reorganization or otherwise.
10.5. Applicable Law. This Plan is established under and will be
---------------
construed according to the laws of the State of Oklahoma.
* * *
IN WITNESS WHEREOF, the undersigned has caused this Plan to be executed
this ______ day of _________________, 2000.
OGE ENERGY CORP.
By_____________________________
102
EXHIBIT 21.01
OGE ENERGY CORP.
SUBSIDIARIES OF THE REGISTRANT
Jurisdiction of Percentage of
Name of Subsidiary Incorporation Ownership
- ------------------ --------------- -------------
Oklahoma Gas and Electric Company Oklahoma 100.0
Enogex Inc. Oklahoma 100.0
Transok Delaware 100.0
The above listed subsidiaries have been consolidated in the Registrant's
financial statements.
103
EXHIBIT 23.01
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports dated January 20, 2000 included in the OGE Energy
Corp. Form 10-K for the year ended December 31, 1999, into the previously filed
Post-Effective Amendment No. 1-B to Registration Statement No. 33-61699,
Post-Effective Amendment No. 2-B to Registration Statement No. 33-61699, Form
S-8 Registration Statement No. 333-71327 and Form S-8 Registration Statement No.
333-92423.
/ s / Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
March 24, 2000
104
EXHIBIT 24.01
POWER OF ATTORNEY
WHEREAS, OGE ENERGY CORP., an Oklahoma corporation (herein referred to
as the "Company"), is about to file with the Securities and Exchange Commission,
under the provisions of the Securities Exchange Act of 1934, as amended, its
annual report on Form 10-K for the year ended December 31, 1999; and
WHEREAS, each of the undersigned holds the office or offices in the
Company herein-below set opposite his or her name,
respectively;
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints
STEVEN E. MOORE, JAMES R. HATFIELD and DONALD R. ROWLETT and each of them
individually, his or her attorney with full power to act for him or her and in
his or her name, place and stead, to sign his name in the capacity or capacities
set forth below to said Form 10-K and to any and all amendments thereto, and
hereby ratifies and confirms all that said attorney may or shall lawfully do or
cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this
19th day of January 2000.
Steven E. Moore, Chairman, Principal
Executive Officer and Director / s / Steven E. Moore
-----------------------------
Herbert H. Champlin, Director / s / Herbert H. Champlin
-----------------------------
Luke R. Corbett, Director / s / Luke R. Corbett
-----------------------------
William E. Durrett, Director / s / William E. Durrett
-----------------------------
Martha W. Griffin, Director / s / Martha W. Griffin
-----------------------------
Hugh L. Hembree, III, Director / s / Hugh L. Hembree, III
-----------------------------
Robert Kelley, Director / s / Robert Kelley
-----------------------------
Bill Swisher, Director / s / Bill Swisher
-----------------------------
Ronald H. White, M.D., Director / s / Ronald H. White, M.D.
-----------------------------
James R. Hatfield, Principal Financial Officer / s / James R. Hatfield
-----------------------------
Donald R. Rowlett, Principal Accounting Officer / s / Donald R. Rowlett
-----------------------------
STATE OF OKLAHOMA )
) SS
COUNTY OF OKLAHOMA )
On the date indicated above, before me, Debbie Peters, Notary Public in
and for said County and State, personally appeared the above named directors and
officers of OGE ENERGY CORP., an Oklahoma corporation, and known to me to be the
persons whose names are subscribed to the foregoing instrument, and they
severally acknowledged to me that they executed the same as their own free act
and deed.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official
seal on the 19th day of January, 2000.
/s/ Debbie Peters
Debbie Peters
Notary Public in and for the County
of Oklahoma, State of Oklahoma
My Commission
Expires: May 3, 2003
105
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
OGE Energy Corp. Consolidated Statements of Income, Balance Sheets, and
Statements of Cash Flow as reported on Form 10-K as of December 31, 1999 and is
qualified in its entirety by reference to such Form 10-K.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,241,987
<OTHER-PROPERTY-AND-INVEST> 31,012
<TOTAL-CURRENT-ASSETS> 503,660
<TOTAL-DEFERRED-CHARGES> 144,675
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,921,334
<COMMON> 779
<CAPITAL-SURPLUS-PAID-IN> 441,068
<RETAINED-EARNINGS> 577,532
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,019,379
0
0
<LONG-TERM-DEBT-NET> 1,140,532
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 589,100
<LONG-TERM-DEBT-CURRENT-PORT> 169,000
0
<CAPITAL-LEASE-OBLIGATIONS> 9,831
<LEASES-CURRENT> 2,475
<OTHER-ITEMS-CAPITAL-AND-LIAB> 991,017
<TOT-CAPITALIZATION-AND-LIAB> 3,921,334
<GROSS-OPERATING-REVENUE> 2,172,434
<INCOME-TAX-EXPENSE> 89,944
<OTHER-OPERATING-EXPENSES> 1,834,269
<TOTAL-OPERATING-EXPENSES> 1,924,213
<OPERATING-INCOME-LOSS> 248,221
<OTHER-INCOME-NET> 3,317
<INCOME-BEFORE-INTEREST-EXPEN> 251,538
<TOTAL-INTEREST-EXPENSE> 100,279
<NET-INCOME> 151,259
0
<EARNINGS-AVAILABLE-FOR-COMM> 151,259
<COMMON-STOCK-DIVIDENDS> 103,495
<TOTAL-INTEREST-ON-BONDS> 60,727
<CASH-FLOW-OPERATIONS> 224,253
<EPS-BASIC> 1.94
<EPS-DILUTED> 1.94
</TABLE>
EXHIBIT 99.01
OGE ENERGY CORP. CAUTIONARY FACTORS
The Private Securities Litigation Reform Act of 1995 provides a "safe
harbor" for forward-looking statements to encourage such disclosures without the
threat of litigation providing those statements are identified as
forward-looking and are accompanied by meaningful, cautionary statements
identifying important factors that could cause the actual results to differ
materially from those projected in the statement. Forward-looking statements
have been and will be made in written documents and oral presentations of OGE
Energy Corp. (the "Company"). Such statements are based on management's beliefs
as well as assumptions made by and information currently available to
management. When used in the Company's documents or oral presentations, the
words "anticipate", "estimate", "expect", "objective" and similar expressions
are intended to identify forward-looking statements. In addition to any
assumptions and other factors referred to specifically in connection with such
forward-looking statements, factors that could cause the Company's actual
results to differ materially from those contemplated in any forward-looking
statements include, among others, the following:
o Increased competition in the utility industry, including effects of:
decreasing margins as a result of competitive pressures; industry
restructuring initiatives; transmission system operation and/or
administration initiatives; recovery of investments made under
traditional regulation; nature of competitors entering the industry;
retail wheeling; a new pricing structure; and former customers entering
the generation market;
o Changing market conditions and a variety of other factors associated
with physical energy and financial trading activities including, but
not limited to, price, basis, credit, liquidity, volatility, capacity,
transmission, currency, interest rate and warranty risks;
o Risks associated with price risk management strategies intended to
mitigate exposure to adverse movement in the prices of electricity and
natural gas on both a global and regional basis;
o Economic conditions including inflation rates and monetary
fluctuations;
o Customer business conditions including demand for their products or
services and supply of labor and materials used in creating their
products and services;
o Financial or regulatory accounting principles or policies imposed by
the Financial Accounting Standards Board, the Securities and Exchange
Commission, the Federal Energy Regulatory Commission, state public
utility commissions, state entities which regulate natural gas
transmission, gathering and processing and similar entities with
regulatory oversight.
o Availability or cost of capital such as changes in: interest rates,
market perceptions of the utility and energy-related industries, the
Company or any of its subsidiaries or security ratings;
o Factors affecting utility operations such as unusual weather
conditions; catastrophic weather-related damage; unscheduled generation
outages, unusual maintenance or repairs; unanticipated changes to
fossil fuel, or gas supply costs or availability due to higher demand,
shortages, transportation problems or other developments; environmental
incidents; or electric transmission or gas pipeline system constraints;
107
<PAGE>
o Employee workforce factors including changes in key executives,
collective bargaining agreements with union employees, or work
stoppages;
o Rate-setting policies or procedures of regulatory entities, including
environmental externalities;
o Social attitudes regarding the utility, natural gas and power
industries;
o Identification of suitable investment opportunities to enhance
shareowner returns and achieve long-term financial objectives through
business acquisitions;
o Some future investments made by the Company could take the form of
minority interests which would limit the Company's ability to control
the development or operation of an investment;
o Costs and other effects of legal and administrative proceedings,
settlements, investigations, claims and matters, including but not
limited to those described in Note 10 of the Notes to the Consolidated
Financial Statements of the Company's Annual Report on Form 10-K for
the year ended December 31, 1999, under the caption Commitments and
Contingencies;
o Technological developments, changing markets and other factors that
result in competitive disadvantages and create the potential for
impairment of existing assets;
o Other business or investment considerations that may be disclosed from
time to time in the Company's Securities and Exchange Commission
filings or in other publicly disseminated written documents.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
108
