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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[|X|] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the fiscal year ended December 31, 1998 Commission File Number 1-12579
OGE ENERGY CORP.
(Exact name of registrant as specified in its charter)
Oklahoma 73-1481638
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which
so registered each class is registered
------------------- ------------------------------
Common Stock New York Stock Exchange and Pacific Stock Exchange
Rights to Purchase-
Series A Preferred Stock New York Stock Exchange and Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes |X| No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. | |
As of February 26, 1999, Common Shares outstanding were 77,801,317.
Based upon the closing price on the New York Stock Exchange on February 26,
1999, the aggregate market value of the voting stock held by nonaffiliates of
the Company was: Common Stock $1,848,833,372.
The proxy statement for the 1999 annual meeting of shareowners is
incorporated by reference into Part III of this Report.
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TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
Item 1. Business..............................................................1
The Company...........................................................1
Electric Operations...................................................2
General......................................................2
Regulation and Rates.........................................5
Rate Structure, Load Growth and Related Matters.............11
Fuel Supply.................................................12
Enogex...............................................................14
Origen...............................................................18
Finance and Construction.............................................18
Environmental Matters................................................19
Employees............................................................21
Item 2. Properties...........................................................22
Item 3. Legal Proceedings....................................................23
Item 4. Submission of Matters to a Vote of Security Holders..................26
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters...........................................31
Item 6. Selected Financial Data..............................................32
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...........................33
Item 8. Financial Statements and Supplementary Data..........................49
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure......................................80
PART III
Item 10. Directors and Executive Officers of the Registrant...................80
Item 11. Executive Compensation...............................................80
Item 12. Security Ownership of Certain Beneficial
Owners and Management.........................................80
Item 13. Certain Relationships and Related Transactions.......................80
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K...........................................80
i
PART I
ITEM 1. BUSINESS.
- ----------------
THE COMPANY
OGE Energy Corp. (the "Company") is a public utility holding company,
which was incorporated in August 1995 in the State of Oklahoma. The Company
became the parent company of Oklahoma Gas and Electric Company ("OG&E") and its
former subsidiary, Enogex Inc. on December 31, 1996 pursuant to a mandatory
share exchange whereby each share of outstanding common stock of OG&E was
exchanged on a share-for-share basis for common stock of the Company.
Immediately following this exchange, OG&E transferred its shares of Enogex stock
to the Company and Enogex Inc. became a direct subsidiary of the Company.
The Company now serves as the parent company to OG&E, Enogex Inc.,
Origen Inc. and any other companies that may be formed within the organization
in the future. The holding company structure is intended to provide greater
flexibility to take advantage of opportunities in an increasingly competitive
business environment and to clearly separate the Company's electric utility
business from its non-utility businesses. The Company is not engaged in any
business independent of that conducted through its subsidiaries OG&E, Enogex
Inc. and Enogex Inc.'s subsidiaries ("Enogex"), and Origen Inc. and Origen
Inc.'s subsidiaries ("Origen").
The Company's principal subsidiary is OG&E and, accordingly, the
Company's financial results and condition are substantially dependent at this
time on the financial results and conditions of OG&E. OG&E is a regulated public
utility engaged in the generation, transmission and distribution of electricity
to retail and wholesale customers. OG&E was incorporated in 1902 under the laws
of the Oklahoma Territory and is the largest electric utility in the State of
Oklahoma. OG&E sold its retail gas business in 1928 and now owns and operates an
interconnected electric production, transmission and distribution system which
includes eight active generating stations with a total capability of 5,561,180
kilowatts.
Enogex owns and operates approximately 3,329 miles of natural gas
transmission and gathering pipelines, has interests in five gas processing
plants, markets electricity, natural gas and natural gas products and invests in
the drilling for and production of crude oil and natural gas.
OG&E's regulated utility business has been and will continue to be
affected by competitive changes to the utility industry. Significant changes
already have occurred in the wholesale electric markets at the Federal level. In
Oklahoma, legislation was passed in 1997 to provide for the orderly
restructuring of the electric industry with the goal to provide retail customers
with the ability to choose their generation suppliers by July 1, 2002. This
legislation, if implemented as proposed, would significantly impact OG&E. The
Arkansas Public Service Commission ("APSC") has initiated proceedings to
consider the implementation of a competitive retail market in Arkansas. See
"Electric Operations - Regulation and Rates - Recent Regulatory Matters" for
further discussion of these developments.
The Company's executive offices are located at 321 North Harvey, P. O.
Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
ELECTRIC OPERATIONS
GENERAL
OG&E furnishes retail electric service in 280 communities and their
contiguous rural and suburban areas. During 1998, six other communities and two
rural electric cooperatives in Oklahoma and western Arkansas purchased
electricity from OG&E for resale. The service area, with an estimated population
of 1.8 million, covers approximately 30,000 square miles in Oklahoma and western
Arkansas; including Oklahoma City, the largest city in Oklahoma, and Ft. Smith,
Arkansas, the second largest city in that state. Of the 286 communities served,
257 are located in Oklahoma and 29 in Arkansas. Approximately 91 percent of
total electric operating revenues for the year ended December 31, 1998, were
derived from sales in Oklahoma and the remainder from sales in Arkansas.
OG&E's system control area peak demand as reported by the system
dispatcher for the year was approximately 5,529 megawatts, and occurred on
August 27, 1998. OG&E's load responsibility peak demand was approximately 5,247
megawatts on July 30, 1998, resulting in a capacity margin of approximately 14.4
percent. OG&E is a member, along with neighboring utilities and other electric
suppliers, in the Southwest Power Pool ("SPP"), which requires that OG&E
maintain a capacity reserve margin of 13 percent. As reflected in the table
below and in the operating statistics on page 4, total kilowatt-hour sales
increased 4.2 percent in 1998 as compared to an increase of 1.6 percent in 1997
and a 1.5 percent increase in 1996. In 1998, kilowatt-hour sales to OG&E
customers ("system sales") increased 6.6 percent due to warmer weather and
continued customer growth. Sales to other utilities and power marketers
("off-system sales") decreased in 1998; however, various factors (including the
summer heat, unit availability and storms) drove prices of this off-system
electricity to record levels, increasing operating revenues and at margins
significantly higher than had been experienced in the past. There can be no
assurance that such margins on future off-system sales will occur again. In 1997
and 1996, total kilowatt-hour sales increased due to continued customer growth.
Variations in kilowatt-hour sales for the three years are reflected in
the following table:
SALES (Millions of Kwh)
INC/ Inc/ Inc/
1998 (DEC) 1997 (Dec) 1996 (Dec)
- --------------------------------------------------------------------------------
System Sales 23,642 6.6% 22,183 3.0% 21,541 3.4%
Off-System Sales 728 (39.5%) 1,202 (18.5%) 1,475 (20.4%)
------- ------- -------
Total Sales 24,370 4.2% 23,385 1.6% 23,016 1.5%
======= ======= =======
In 1998, OG&E's Sooner Generating Station (consisting of two coal-fired
units with an aggregate capability of 1,031 Mw) and OG&E's three coal-fired
units at its Muskogee Generating Station (with an aggregate capability of 1,491
Mw) were again recognized by an industry survey as being in the top 20 lowest
cost producers of electricity for the third consecutive year.
OG&E is subject to competition in various degrees from government-owned
electric systems, municipally-owned electric systems, rural electric
cooperatives and, in certain respects, from other private utilities, power
marketers and cogenerators. Oklahoma law forbids the granting of an exclusive
franchise to a utility for providing electricity.
2
Besides competition from other suppliers or marketers of electricity,
OG&E competes with suppliers of other forms of energy. The degree of competition
between suppliers may vary depending on relative costs and supplies of other
forms of energy. See "Electric Operations - Regulation and Rates - Recent
Regulatory Matters" for a discussion of the potential impact on competition from
federal and state legislation.
3
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
YEAR ENDED DECEMBER 31
1998 1997 1996
------------- ------------- -------------
ELECTRIC ENERGY:
(Millions of Kwh)
Generation (exclusive of station use)................... 22,565 21,620 21,253
Purchased............................................... 3,984 3,528 3,564
------------- ------------- -------------
Total generated and purchased..................... 26,549 25,148 24,817
Company use, free service and losses.................... (2,179) (1,763) (1,801)
------------- ------------- -------------
Electric energy sold.............................. 24,370 23,385 23,016
------------- ------------- -------------
ELECTRIC ENERGY SOLD:
(Millions of Kwh)
Residential............................................. 7,959 7,179 7,143
Commercial and industrial............................... 11,912 11,586 11,161
Public street and highway lighting...................... 68 68 67
Other sales to public authorities....................... 2,352 2,202 2,096
Sales for resale........................................ 2,079 2,350 2,549
------------- ------------- -------------
Total............................................. 24,370 23,385 23,016
============= ============= =============
ELECTRIC OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential......................................... $ 537,486 $ 474,419 $ 479,574
Commercial and industrial........................... 554,589 526,673 530,213
Public street and highway lighting.................. 9,618 9,456 9,367
Other sales to public authorities................... 110,522 98,818 98,209
Sales for resale.................................... 76,198 57,695 60,141
Provision for rate refund........................... --- --- (1,221)
Miscellaneous....................................... 23,665 24,630 24,054
------------- ------------- -------------
Total Electric Revenues........................... $ 1,312,078 $ 1,191,691 $ 1,200,337
============= ============= =============
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential............................................. 598,378 593,699 588,778
Commercial and industrial............................... 86,251 85,315 84,032
Public street and highway lighting...................... 249 249 249
Other sales to public authorities....................... 11,183 10,897 10,688
Sales for resale........................................ 39 40 41
------------- ------------- -------------
Total............................................. 696,100 690,200 683,788
============= ============= =============
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (Kwh)................................ 13,342 12,133 12,178
Average annual revenue.................................. $ 900.94 $ 801.74 $ 817.62
Average price per Kwh (cents)........................... 6.75 6.61 6.71
4
REGULATION AND RATES
OG&E's retail electric tariffs in Oklahoma are regulated by the
Oklahoma Corporation Commission ("OCC"), and in Arkansas by the APSC. The
issuance of certain securities by OG&E is also regulated by the OCC and the
APSC. OG&E's wholesale electric tariffs, short-term borrowing authorization and
accounting practices are subject to the jurisdiction of the Federal Energy
Regulatory Commission ("FERC"). The Secretary of the Department of Energy has
jurisdiction over some of OG&E's facilities and operations.
As part of the corporate reorganization whereby the Company became the
holding company parent of OG&E, OG&E obtained the approval of the OCC. The order
of the OCC authorizing OG&E to reorganize into a holding company structure
contains certain provisions which, among other things, ensure the OCC access to
the books and records of the Company and its affiliates relating to transactions
with OG&E; require the Company and its subsidiaries to employ accounting and
other procedures and controls to protect against subsidization of non-utility
activities by OG&E's customers; and prohibit the Company from pledging OG&E
assets or income for affiliate transactions.
For the year ended December 31, 1998, approximately 87 percent of
OG&E's electric revenue was subject to the jurisdiction of the OCC, seven
percent to the APSC, and six percent to the FERC.
RECENT REGULATORY MATTERS: In January 1998, OG&E filed an application
--------------------------
with the OCC seeking approval to revise an existing cogeneration contract with
Mid-Continent Power Company ("MCPC"), a cogeneration plant near Pryor, Oklahoma.
As part of this transaction, the Company agreed to purchase the stock of
Oklahoma Loan Acquisition Corporation ("OLAC"), the company that owned the MCPC
plant, for approximately $25 million. OG&E obtained the required regulatory
approvals from the OCC, APSC and FERC. If the transaction had been completed,
the term of the existing cogeneration contract would have been reduced by four
and one-half years, which would have reduced the amounts to be paid by OG&E, and
would have provided savings for its Oklahoma customers, of approximately $46
million as compared to the existing cogeneration contract. Following an
arbitrator's decision that the owner of the stock of OLAC could not sell the
stock of OLAC to the Company until it had offered such stock to a third party on
the same terms as it was offered to the Company, the third party purchased the
stock of OLAC and assumed ownership of the cogeneration plant in October 1998.
The effect of this transaction is that OG&E's original contract with the
cogeneration plant remains in place.
On February 11, 1997, the OCC issued an order that, among other things,
effectively lowered OG&E's rates to its Oklahoma retail customers by $50 million
annually (based on a test year ended December 31, 1995). Of the $50 million rate
reduction, approximately $45 million became effective on March 5, 1997, and the
remaining $5 million became effective March 1, 1998. The February 11, 1997 order
also directed OG&E to transition to competitive bidding of its gas
transportation requirements currently met by Enogex no later than April 30, 2000
and set annual compensation for the transportation services provided by Enogex
to OG&E at $41.3 million until competitively-bid gas transportation begins. In
1998, approximately $41.6 million or 8.2 percent of Enogex's revenues were
attributable to transporting gas for OG&E. Other pipelines seeking to compete
with Enogex for OG&E's business will likely have to pay a fee to Enogex for
transporting gas on Enogex's system or incur capital expenditures to develop the
necessary infrastructure to connect with OG&E's gas-fired generating stations.
Nevertheless, a potential outcome of the competitive bidding process is that the
revenues of Enogex derived from transporting gas for OG&E may be significantly
less after April 30, 2000.
5
The Order also contained a Generation Efficiency Performance Rider
("GEP Rider"), which is designed so that when OG&E's average annual cost of fuel
per kwh is less than 96.261 percent of the average non-nuclear fuel cost per kwh
of certain other investor-owned utilities in the region, OG&E is allowed to
collect, through the GEP Rider, one-third of the amount by which OG&E's average
annual cost of fuel comes in below 96.261 percent of the average of the other
specified utilities. If OG&E's fuel cost exceeds 103.739 percent of the stated
average, the Company will not be allowed to recover one-third of the fuel costs
above that average from Oklahoma customers.
The fuel cost information used to calculate the GEP Rider is based on
fuel cost data submitted by each of the utilities in their Form No. 1 Annual
Report filed with the FERC. The GEP Rider is revised effective July 1 of each
year to reflect any changes in the relative annual cost of fuel reported for the
preceding calendar year. For 1998, the GEP Rider increased revenues by
approximately $10.0 million, or approximately $0.08 per share. The current GEP
Rider is estimated to positively impact revenue by $33 million or approximately
$0.26 per share during the 12 months ending June 1999.
As previously reported, Oklahoma enacted in April 1997 the Electric
Restructuring Act of 1997 (the "Act"). In June 1998, various amendments to the
Act were enacted. If implemented as proposed, the Act will significantly affect
OG&E's future operations. The following summary of the Act does not purport to
be complete and is subject to the specific provisions of the Act, which is
codified at Sections 190.2 et. seq. of Title 17 of the Oklahoma Statutes.
The Act consists of eight sections, with Section 1 designating the name
of the Act. Section 2 describes the purposes of the Act, which is generally to
restructure the electric industry to provide for more competition and, in
particular, to provide for the orderly restructuring of the electric utility
industry in the State of Oklahoma in order to allow direct access by retail
consumers to the competitive market for the generation of electricity while
maintaining the safety and reliability of the electric system in the state.
The primary goals of a restructured electric utility industry, as set
forth in Section 2 of the Act, are as follows:
l. To reduce the cost of electricity for as many consumers as
possible, helping industry to be more competitive, to create
more jobs in Oklahoma and help lower the cost of government by
reducing the amount and type of regulation now paid for by
taxpayers;
2. To encourage the development of a competitive electricity
industry through the unbundling of prices and services and
separation of generation services from transmission and
distribution services;
3. To enable retail electric energy suppliers to engage in fair
and equitable competition through open, equal and comparable
access to transmission and distribution systems and to avoid
wasteful duplication of facilities;
4. To ensure that direct access by retail consumers to the
competitive market for generation be implemented in Oklahoma
by July 1, 2002; and
6
5. To ensure that proper standards of safety, reliability and
service are maintained in a restructured electric service
industry.
Section 3 of the Act sets forth various definitions and exempts in
large part several electric cooperatives and municipalities from the Act unless
they choose to be governed by it.
Sections 4, 5 and 6 of the Act are designed to implement the goals of
the Act and provide for various studies and task forces to assess the issues and
consequences associated with the proposed restructuring of the electric utility
industry. In Section 4, the Joint Electric Utility Task Force (the "Joint Task
Force"), which is described below, is directed to undertake a study of all
relevant issues relating to restructuring the electric utility industry in
Oklahoma including, but not limited to, the issues set forth in Section 4, and
to develop a proposed electric utility framework for Oklahoma. The OCC is
prohibited from promulgating orders relating to the restructuring without prior
authorization of the Oklahoma Legislature. Also, in developing a framework for a
restructured electric utility industry, the OCC is to adhere to fourteen
principles set forth in Section 4, including the following:
1. Appropriate rules shall be promulgated, ensuring that reliable
and safe electric service is maintained.
2. Consumers shall be allowed to choose among retail electric
energy suppliers to help ensure competitive and innovative
markets. A process should be established whereby all retail
consumers are permitted to choose their retail electric energy
suppliers by July 1, 2002.
3. When consumer choice is introduced, rates shall be unbundled
to provide clear price information on the components of
generation, transmission and distribution and any other
ancillary charges. Charges for public benefit programs
currently authorized by statute or the OCC, or both, shall be
unbundled and appear in line item format on electric bills for
all classes of consumers.
4. An entity providing distribution services shall be relieved of
its traditional obligation to provide electric supply but
shall have a continuing obligation to provide distribution
service for all consumers in its service territory.
5. The benefits associated with implementing an independent
system planning committee composed of owners of electric
distribution systems to develop and maintain planning and
reliability criteria for distribution facilities shall be
evaluated.
6. A defined period for the transition to a restructured electric
utility industry shall be established. The transition period
shall reflect a suitable time frame for full compliance with
the requirements of a restructured utility industry.
7. Electric rates for all consumer classes shall not rise above
current levels throughout the transition period. If possible,
electric rates for all consumers shall be lowered when
feasible as markets become more efficient in a restructured
industry.
7
8. The OCC shall consider the establishment of a distribution
access fee to be assessed to all consumers in Oklahoma
connected to electric distribution systems regulated by the
OCC. This fee shall be charged to cover social costs, capital
costs, operating costs, and other appropriate costs associated
with the operation of electric distribution systems and the
provision of electric services to the retail consumer.
9. Electric utilities have traditionally had an obligation to
provide service to consumers within their established service
territories and have entered into contracts, long-term
investments and federally mandated cogeneration contracts to
meet the needs of consumers. These investments and contracts
have resulted in costs, which may not be recoverable in a
competitive restructured market and thus may be "stranded."
Procedures shall be established for identifying and
quantifying stranded investments and for allocating costs; and
mechanisms shall be proposed for recovery of an appropriate
amount of prudently incurred, unmitigable and verifiable
stranded costs and investments. As part of this process, each
entity shall be required to propose a recovery plan which
establishes its unmitigable and verifiable stranded costs and
investments and a limited recovery period designed to recover
such costs expeditiously, provided that the recovery period
and the amount of qualified transition costs shall yield a
transition charge which shall not cause the total price for
electric power, including transmission and distribution
services, for any consumer to exceed the cost per
kilowatt-hour paid on the effective date of this Act during
the transition period. The transition charge shall be applied
to all consumers including direct access consumers, and shall
not disadvantage one class of consumer or supplier over
another, nor impede competition and shall be allocated over a
period of not less than three (3) years nor more than seven
(7) years.
10. It is the intent that all transition costs shall be recovered
by virtue of the savings generated by the increased efficiency
in markets brought about by restructuring of the electric
utility industry. All classes of consumers shall share in the
transition costs.
Subject to the principles set forth in Section 4, the Joint Task Force
is directed to prepare a four-part study. As a result of the 1998 amendments,
the time frame for the delivery of the remaining parts of the Study was
accelerated to October 1, 1999. This study is to address: (i) technical issues
(including reliability, safety, unbundling of generation, transmission and
distribution services, transition issues and market power); (ii) financial
issues (including rates, charges, access fees, transition costs and stranded
costs); (iii) consumer issues (such as the obligation to serve, service
territories, consumer choices, competition and consumer safeguards); and (iv)
tax issues (including sales and use taxes, ad valorem taxes and franchise fees).
Section 5 of the Act directs the Joint Task Force to study and submit a
report on the impact of the restructuring of the electric utility industry on
state tax revenues and all other facets of the current utility tax structure on
the state and all political subdivisions of the state. The Oklahoma Tax
Commission and the OCC are precluded from issuing any rules on such matters
without the approval of the Oklahoma Legislature. Also, the Act requires the
establishment, on or before July 1, 2002, of an uniform tax policy that allows
all competitors to be taxed on a fair and equitable basis.
8
Section 6 creates the Joint Task Force, which shall consist of seven
members from the Oklahoma Senate and seven members from the Oklahoma House of
Representatives. The Joint Task Force is directed to undertake the studies set
forth in Sections 4 and 5 of the Act. The Joint Task Force is permitted to make
final recommendations to the Governor and Oklahoma Legislature. The Joint Task
Force is also empowered to retain consultants to study the creation of an
Independent System Operator, which would coordinate the physical supply of
electricity throughout Oklahoma and maintain reliability, security and stability
of the bulk power system. In addition, such study shall assess the benefits of
establishing a power exchange that would operate as a power pool allowing power
producers to compete on common ground in Oklahoma. In fulfilling its tasks, the
Joint Task Force can appoint advisory councils made up of electric utilities,
regulators, residential customers and other constituencies.
Section 7 provides generally that, with respect to electric
distribution providers, no customer switching will be allowed from the effective
date of the Act until July 1, 2002, except by mutual consent. It also provides
that any municipality that fails to become subject to the Act will be prohibited
from selling power outside its municipal limits except from lines owned on the
effective date of the Act. Furthermore, this section provides generally that
out-of-state suppliers of electricity and their affiliates who make retail sales
of electricity in Oklahoma through the use of transmission and distribution
facilities of in-state suppliers must provide equal access to their transmission
and distribution facilities outside of Oklahoma. Section 8 sets forth the
effective date of the Act as April 25, 1997.
A new bill was introduced in the State Senate in January 1999 and if
enacted would clarify ambiguities by defining key terms in the Act.
In December 1997, the APSC established four generic proceedings to
consider the implementation of a competitive retail electric market in the State
of Arkansas. During 1998, the APSC held hearings to consider competitive retail
generation, market structure, market power, taxation, recovery and mitigation of
stranded costs, service and reliability, low income assistance, independent
system operators and transition issues. The Company participated actively in
those proceedings, and in October 1998 the APSC issued its report to the
Arkansas legislature recommending competitive retail electric generation to
begin no later than January 1, 2002. Several bills calling for electric industry
restructuring were introduced after the Arkansas General Assembly began its 1999
session. While it is not expected that the General Assembly will enact
legislation in regular session, a special session of the General Assembly may be
called to continue the debate.
The OCC has adopted rules that are designed to make the gas utility
business in Oklahoma more competitive. These rules do not impact the electric
industry. Yet, if implemented, the rules are expected to offer increased
opportunities to Enogex's pipeline and related businesses.
On February 13, 1998, the APSC Staff filed a motion for a show cause
order to review OG&E's electric rates in the State of Arkansas. The staff is
recommending a $3.1 million annual rate reduction (based on a test year ended
December 31, 1996). OG&E has filed its cost of service study and has requested a
$1.7 million annual rate increase. A decision on this rate case is expected in
the next few months.
AUTOMATIC FUEL ADJUSTMENT CLAUSES: Variances in the actual cost of fuel
---------------------------------
used in electric generation and certain purchased power costs, as compared to
that component in cost-of-service for ratemaking, are charged to substantially
all of the Company's electric customers through automatic fuel adjustment
clauses, which are subject to periodic review by the OCC, the APSC and the FERC.
9
NATIONAL ENERGY LEGISLATION: Federal law imposes numerous
--------------------------------
responsibilities and requirements on OG&E. The Public Utility Regulatory
Policies Act of 1978 requires electric utilities, such as OG&E, to purchase
electric power from, and sell electric power to, qualified cogeneration
facilities and small power production facilities ("QFs"). Generally stated,
electric utilities must purchase electric energy and production capacity made
available by QFs at a rate reflecting the cost that the purchasing utility can
avoid as a result of obtaining energy and production capacity from these
sources; rather than generating an equivalent amount of energy itself or
purchasing the energy or capacity from other suppliers. OG&E has entered into
agreements with four such cogenerators. See "Finance and Construction." Electric
utilities also must furnish electric energy to QFs on a non-discriminatory basis
at a rate that is just and reasonable and in the public interest and must
provide certain types of service which may be requested by QFs to supplement or
back up those facilities' own generation.
The Energy Policy Act of 1992 ("EPAct") has resulted in some
significant changes in the operations of the electric utility industry and the
federal policies governing the generation, transmission and sale of electric
power. The EPAct, among other things, authorized the FERC to order transmitting
utilities to provide transmission services to any electric utility, Federal
power marketing agency, or any other person generating electric energy for sale
or resale, at transmission rates set by the FERC. The EPAct also is designed to
promote competition in the development of wholesale power generation in the
electric industry. It exempts a new class of independent power producers from
regulation under the Public Utility Holding Company Act of 1935.
In April 1996, FERC issued two final rules, Orders 888 and 889, which
are having a significant impact on wholesale markets. These orders were
subsequently amended in orders issued in March and November 1997. Order 888 set
forth rules on non-discriminatory open access transmission service to promote
wholesale competition. Order 888, which was effective on July 9, 1996, requires
utilities and other transmission users to abide by comparable terms, conditions
and pricing in transmitting power. Order 889, which had its effective date
extended to January 3, 1997, requires public utilities to implement Standards of
Conduct and an Open Access Same Time Information System ("OASIS," formerly known
as "Real-Time Information Networks"). These rules require transmission personnel
to provide the same information about the transmission system to all
transmission customers using the OASIS. In 1997, the FERC issued clarifying
final orders in response to rehearing requests by numerous market participants
regarding Orders No. 888 and 889. During 1998, OG&E submitted filings to the
FERC to comply with these Orders, and those filings have been accepted. As OG&E
continues to prepare for restructuring at the retail level, it is expected that
additional filings will be made in order to maintain continuing compliance with
the FERC's wholesale restructuring orders.
Another impact of complying with FERC's Order 888 is a requirement for
utilities to offer a transmission tariff that includes network transmission
service ("NTS") to transmission customers. NTS allows transmission service
customers to fully integrate load and resources on an instantaneous basis, in a
manner similar to how OG&E has historically integrated its load and resources.
Under NTS, OG&E and participating customers share the total annual transmission
cost for their combined joint-use systems, net of related transmission revenues,
based upon each company's share of the total system load. Management expects
minimal annual expenses as a result of Orders 888 and 889.
As discussed previously, Oklahoma enacted legislation that will
restructure the electric utility industry in Oklahoma by July 2002, assuming
that all the conditions in the legislation are met. This legislation would
deregulate OG&E's electric generation assets and the continued use of Statement
of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects
of Certain Types of Regulation", with respect to the related regulatory assets
may no longer be appropriate. This may result
10
in either full recovery of generation-related regulatory assets (net of related
regulatory liabilities) or a non-cash, pre-tax write-off as an extraordinary
charge of up to $31 million, depending on the transition mechanisms developed by
the legislature for the recovery of all or a portion of these net regulatory
assets.
The enacted Oklahoma legislation does not affect OG&E's electric
transmission and distribution assets and the Company believes that the continued
use of SFAS No. 71 with respect to the related regulatory assets is appropriate.
However, if utility regulators in Oklahoma and Arkansas were to adopt regulatory
methodologies in the future that are not based on cost-of-service, the continued
use of SFAS No. 71 with respect to the regulatory assets related to the electric
transmission and distribution assets may no longer be appropriate.
Based on a current evaluation of the various factors and conditions
that are expected to impact future cost recovery, management believes that its
regulatory assets, including those related to generation, are probable of future
recovery.
The EPAct, the actions of the FERC, the restructuring proposal in
Oklahoma, the Arkansas legislative debate and other factors are expected to
significantly increase competition in the electric industry. The Company has
taken steps in the past and intends to take appropriate steps in the future to
remain a competitive supplier of electricity. Past actions include a redesign
and restructuring effort in 1994, continuing actions to reduce fuel costs,
improvements in customer service and efforts to improve OG&E's electric
transmission and distribution network to reduce outages, all of which enhance
OG&E's ability to deliver electricity competitively. While the Company is
supportive of competition, it believes that all electric suppliers must be
required to compete on a fair and equitable basis and the Company is advocating
this position vigorously.
RATE STRUCTURE, LOAD GROWTH
AND RELATED MATTERS
Two of OG&E's primary goals are: (i) to increase electric revenues by
attracting and expanding job-producing businesses and industries; and (ii) to
encourage the efficient electrical energy use by all of OG&E's customers. In
order to meet these goals, OG&E has reduced and restructured its rates to its
customers. At the same time, OG&E had implemented numerous energy efficiency
programs and tariff schedules. In 1998, these programs and schedules included:
(i) the "Surprise Free Guarantee" program, which guarantees residential
customers comfort and annual energy consumption for heating, cooling and water
heating for new homes built to energy efficient standards; (ii) a load
curtailment rate for industrial and commercial customers who can demonstrate a
load curtailment of at least 500 kilowatts (the minimum load of the curtailment
rate was raised in the February 11, 1997, OCC order); and (iii) the time-of-use
rate schedules for various commercial, industrial and residential customers
designed to shift energy usage from peak demand periods during the hot summer
afternoon to non-peak hours.
OG&E continued a Real Time Pricing ("RTP") pilot program, first
implemented in 1997, for qualifying industrial and commercial customers. This
tariff gives customers additional options on total kilowatt-hour growth and the
control of growth of peak demand. Real Time Pricing is a tariff option, which
prices electricity so that current price varies hourly with short notice to
reflect current expected costs. The RTP technique will allow a measure of
competitive pricing, a broadening of customer choice,
11
the balancing of electricity usage and capacity in the short and long term, and
provide customers assistance in controlling their costs.
OG&E's 1998 marketing efforts included geothermal heat pumps,
electrotechnologies, electric food service promotion and a heat pump promotion
in the residential, commercial and industrial markets. OG&E works closely with
individual customers to provide the best information on how current technologies
can be combined with OG&E's marketing programs to maximize the customer's
benefit.
Other recent efforts to improve OG&E's services included the
implementation of a new customer service telephone system capable of handling
approximately ten times more calls simultaneously than the prior system and
implementation of a Company-wide enterprise software system that, besides being
Year 2000 ready, enables OG&E and the Company's other subsidiaries to obtain
extensive business information on nearly a real-time basis. Also, OG&E is in the
process of implementing a new outage management system that should improve
OG&E's ability to restore service, and a new mapping system that, when
completed, will provide OG&E up-to-date information on its transmission and
distribution assets.
Electric and magnetic fields ("EMFs") surround all electric tools and
appliances, internal home wiring and external power lines such as those owned by
OG&E. During the last several years considerable attention has focused on
possible health effects from EMFs. While some studies indicate a possible weak
correlation, other similar studies indicate no correlation between EMFs and
health effects. The nation's electric utilities, including OG&E, have
participated with the Electric Power Research Institute ("EPRI") in the
sponsorship of more than $75 million in research to determine the possible
health effects of EMFs. In addition, the Edison Electric Institute ("EEI") is
helping fund $65 million for EMF studies over a five-year period, that began in
1994. One-half of this amount is expected to be funded by the federal
government, and two-thirds of the non-federal funding is expected to be provided
by the electric utility industry. Through its participation with the EPRI and
EEI, OG&E will continue its support of the research with regard to the possible
health effects of EMFs. OG&E is dedicated to delivering electric service in a
safe, reliable, environmentally acceptable and economical manner.
FUEL SUPPLY
During 1998, approximately 68 percent of the OG&E-generated energy was
produced by coal-fired units and 32 percent by natural gas-fired units. It is
estimated that the fuel mix for 1999 through 2003, based upon expected
generation for these years, will be as follows:
1999 2000 2001 2002 2003
- --------------------------------------------------------------------------------
Coal............................ 70% 76% 76% 74% 74%
Natural Gas..................... 30% 24% 24% 26% 26%
The increase from 70 percent to 76 percent in the percentage of
coal-fired generation relative to total generation is expected to result from
improvements in coal delivery performance. The slight decline from 76 percent to
74 percent in 2002 and 2003 is expected to result from increases in natural
gas-fired generation in those years, not from a reduction in Kwh of coal-fired
generation.
12
The average cost of fuel used, by type, per million Btu for each of the
5 years was as follows:
1998 1997 1996 1995 1994
- --------------------------------------------------------------------------------
Coal............................ $0.85 $0.84 $0.83 $0.83 $0.78
Natural Gas..................... $2.83 $3.60 $3.61 $3.19 $3.58
Weighted Avg.................... $1.48 $1.39 $1.45 $1.41 $1.58
A portion of the fuel cost is included in base rates and differs for
each jurisdiction. The portion of these costs that is not included in base rates
is recovered through automatic fuel adjustment clauses. See "Electric Operations
- - Regulation and Rates - Automatic Fuel Adjustment Clauses."
COAL-FIRED UNITS: All OG&E coal units, with an aggregate capability of
----------------
2,522 megawatts, are designed to burn low sulfur western coal. OG&E purchases
coal under a mix of long- and short-term contracts. During 1998, OG&E purchased
9.9 million tons of coal from the following Wyoming suppliers: Amax Coal West,
Inc., Caballo Rojo, Inc., Kennecott Energy Company, Thunder Basin Coal Company
and Powder River Coal Company. The combination of all coals has a weighted
average sulfur content of 0.3 percent and can be burned in these units under
existing federal, state and local environmental standards (maximum of 1.2 pounds
of sulfur dioxide per million Btu) without the addition of sulfur dioxide
removal systems. Based upon the average sulfur content, OG&E units have an
approximate emission rate of 0.63 pounds of sulfur dioxide per million Btu. In
anticipation of the more strict provisions of Phase II of The Clean Air Act
starting in the year 2000, OG&E has contracts in place that will allow for a
supply of very low sulfur coal from suppliers in the Powder River Basin to meet
the new sulfur dioxide standards.
During 1998, rail congestion continued on the Union Pacific Railroad
causing coal shortage among many of the utilities in the Southwest Power Pool
and the state of Texas. As a result, OG&E depleted its coal stockpiles and was
forced to take some coal conservation measures in November and December. Since
that time, rail service has improved. During 1998, 1997, and 1996, OG&E used
larger unit trains with a maximum of 135 cars instead of a maximum of 112 cars
in unit train service to the Muskogee Generating Station. Increasing the unit
train size allows for an increase of delivered tons by approximately 21 percent.
The combination of high volume, aluminum design and increased train size to the
Muskogee Generating Station reduces the number of trips from Wyoming by
approximately 29 percent. OG&E continued its efforts to maximize the utilization
of its coal units by optimizing the boiler operations at both the Sooner and
Muskogee generating plants. See "Environmental Matters" for a discussion of an
environmental proposal that, if implemented as proposed, could inhibit OG&E's
ability to use coal as its primary boiler fuel.
GAS-FIRED UNITS: For calendar year 1999, OG&E expects to acquire less
----------------
than 1 percent of its gas needs from long-term gas purchase contracts. The
remainder of OG&E's gas needs during 1999 will be supplied by contracts with
at-market pricing or through day-to-day purchases on the spot market.
In 1993, OG&E began utilizing a natural gas storage facility which
helps lower fuel costs by allowing OG&E to optimize economic dispatch between
fuel types and take advantage of seasonal variations in natural gas prices. By
diverting gas into storage during low demand periods, OG&E is able to use as
much coal as possible to generate electricity and utilize the stored gas to meet
the additional demand for electricity.
13
ENOGEX
The Company's wholly-owned non-utility subsidiary, Enogex, Inc. is an
Oklahoma intrastate natural gas pipeline which also conducts operations in
related business segments through subsidiary companies. These business segments
include gas processing operations ("Gas Processing") conducted by and through
Enogex Products Corporation ("Products"); development and production of oil and
natural gas ("Development and Production") conducted through Enogex Exploration
Corporation ("Exploration"); and the marketing of natural gas, natural gas
liquids, and electricity ("Marketing") conducted by OGE Energy Resources Inc.
("Resources"). In addition Enogex's wholly-owned subsidiary, Enogex Arkansas
Pipeline Company ("EAPC") owns a 75percent interest in Ozark Gas Transmission,
LLC and related companies which are involved in gas gathering and interstate gas
transmission operations in eastern Oklahoma and Arkansas, through EAPC's
75percent interest in the Noark Pipeline System LP ("NOARK").
For the year ended December 31, 1998, and before elimination of
intercompany items between OG&E and Enogex, Enogex's consolidated revenues and
net income were approximately $505.5 million and $8.5 million, respectively.
Recent Actions. Enogex is the exclusive transporter of natural gas to
--------------
OG&E's electric power generating stations. The OCC in its order on February 11,
1997 directed OG&E to transition to competitive bidding of its gas
transportation no later than April 30, 2000. The order also set annual
compensation for the transportation services provided by Enogex to OG&E at $41.3
million until competitively-bid gas transportation begins. As a result of the
foregoing, Enogex expects that revenues generated from its transportation
services for OG&E (which in 1997 and 1998 represented 12.9 percent and 8.2
percent, respectively, of Enogex's consolidated revenues) will remain at $41.3
million per year through 1999 and will decline after 1999 since Enogex may no
longer be the exclusive provider of transportation services to OG&E after 1999.
As a result, the Company's plan has been and is for Enogex to diversify
its revenue and income sources by increasing revenues from transmission services
provided to third parties, by increasing the net income of Enogex subsidiaries'
natural gas processing and development and production operations, and by
actively evaluating potential acquisitions of complementary businesses or
assets.
In May 1997, Products acquired an 80 percent interest in the NuStar
Joint Venture from Nuevo Liquids Inc. for $26 million. The joint venture assets
include a 66.67 percent interest in the Benedum gas processing plant with an
inlet capacity of 110 million cubic feet per day; a 100 percent interest in a
second bypass plant with a capacity of 30 million cubic feet per day; 52 miles
of natural gas liquid pipeline and over 200 miles of related gas gathering
facilities located in Upton, Crockett, Reagan and neighboring counties in the
Permian Basin in West Texas.
In January 1998, Enogex, through its newly formed subsidiary, EAPC
acquired a 40 percent interest in the partnership that owns NOARK, a natural gas
pipeline, for approximately $30 million and agreed to acquire Ozark Pipeline
("Ozark"), for approximately $55 million. The NOARK line is a 302-mile
intra-state pipeline system that extends from near Fort Chaffee, Arkansas to
near Paragould, Arkansas. The Ozark line is a 437-mile inter-state pipeline
system that begins near McAlester, Oklahoma and terminates near Searcy,
Arkansas. In July 1998, EAPC completed its acquisition of Ozark and contributed
Ozark to NOARK. The two pipelines were integrated into a single, interstate
transmission
14
system on November 1, 1998 at an additional cost of approximately $16 million.
EAPC, which funded the integration, owns a 75 percent interest in NOARK and
Southwestern Energy Pipeline Company owns the remaining 25 percent interest in
the partnership. Current capacity of the integrated system, operating as Ozark
Gas Transmission LLC is approximately 330 million cubic feet per day.
In July 1998 Products acquired the Belvan Corporation and the Belvan
and Todd Ranch Limited Partnerships which possess gathering, processing and
treating assets in the vicinity of Products' NuStar processing operations in
Crockett, Upton and Reagan Counties in West Texas. Acquired assets included 345
miles of gathering system, capable of gathering approximately 15 million cubic
feet per day from 250 wells, natural gas liquid recovery facilities and sulfur
recovery facilities with an effective current capacity of 15 million cubic feet
per day and an eight-mile natural gas liquids pipeline. The acquisition cost was
approximately $13.7 million.
The fees charged by Ozark and by NOARK's second interstate pipeline,
Arkansas Western Pipeline ("AWP") are subject to regulation by the FERC. AWP is
an eight-mile pipeline segment crossing the border between eastern Arkansas and
Missouri. In November 1998, the FERC approved a maximum lawful rate of $0.2455
per mmbtu for the new, integrated NOARK-Ozark system and required Ozark to file
for a rate review by not later than March 2000. While Ozark cannot predict the
ultimate outcome of this forthcoming rate review, no material change in the
current maximum lawful rate is anticipated. AWP's current maximum lawful rate is
$0.0311 per mmbtu with no current requirement for filing for rate review.
Gas Transportation. Enogex's primary business is natural gas
--------------------
transportation and it consists primarily of gathering and transporting natural
gas in Oklahoma for OG&E and on an interruptible basis, for other customers.
Enogex's system consists of approximately 3,329 miles of pipeline, extending
from the Arkoma Basin in eastern Oklahoma to the Anadarko Basin in western
Oklahoma.' Since 1960, Enogex has had a gas transmission agreement with OG&E
under which Enogex transports OG&E's natural gas supply on a fee basis. Under
the gas transmission agreement, OG&E agrees to tender to Enogex and Enogex
agrees to transport, on a firm, load-following basis, all of OG&E's natural gas
requirements for boiler fuel for its seven gas-fired electric generating
stations. In 1998, Enogex transported 204 billion Btu of natural gas; of which
approximately 76 billion Btu, or about 37 percent, was delivered to OG&E's
electric generating stations and storage facility, which resulted in
approximately 63 percent of Enogex Inc.'s transportation revenues of $65.8
million for 1998.
Enogex's pipeline system also gathers and transports natural gas
destined for interstate markets through interconnections in Oklahoma with other
pipeline companies. Among others, these interconnections include Panhandle
Eastern Pipeline, Williams Natural Gas Pipeline, Natural Gas Pipeline Company of
America, Northern Natural Gas Company, NorAm Gas Transmission Company and Ozark
Gas Transmission Company.
The rates charged by Enogex for transporting natural gas on behalf of
an interstate natural gas pipeline company or a local distribution company
served by an interstate natural gas pipeline company are subject to the
jurisdiction of FERC under Section 311 of the Natural Gas Policy Act. The
statute entitles Enogex to charge a "fair and equitable" rate that is subject to
review and approval by the FERC at least once every three years. This rate
review may involve an administrative-type trial and an administrative appellate
review. In addition, Enogex has agreed to open its system to all interstate
shippers that are interested in moving natural gas through the Enogex system.
Enogex is required to conduct this transportation on a non-discriminatory basis,
although this transportation is subordinate to that performed for OG&E. This
decision does not increase appreciably the federal regulatory burden on
15
Enogex, but does give Enogex the opportunity to utilize any unused capacity on
an interruptible basis and thus increase its transportation revenues.
The fees charged by Enogex for transporting natural gas for OG&E and
other intrastate shippers are not subject to FERC regulation. With respect to
state regulation, the fees charged by Enogex for any intrastate transportation
service have not been subject to direct state regulation by the OCC. Even though
the intrastate pipeline business of Enogex is not directly regulated, the OCC,
the APSC and the FERC have the authority to examine the appropriateness of any
transportation charge or other fees paid by OG&E to Enogex, which OG&E seeks to
recover from ratepayers. As stated above, OCC issued an order on February 11,
1997 directing OG&E to transition to competitive bidding of its gas
transportation no later than April 30, 2000 and set an annual compensation for
the transportation services provided by Enogex to OG&E at $41.3 million until
competitively-bid gas transportation begins.
In 1998, Resources successfully initiated wholesale electric power
purchase and reselling operations. Resources received market-based rate
authority in 1997 from the FERC. See "Electric Operations - Regulation and
Rates". With 1998 power sales of 1.4 million Mwh, Resources ranked as the
nation's 71st largest power marketer in terms of Mwh sold. Resources acts as the
Company's natural gas purchasing arm for the natural gas fuel requirements of
the OG&E power stations. Additionally, beginning in 1999, all of the Company's
surplus power sales activity will be done through Resources.
Gas Processing. Products has been active since 1968 in the processing
---------------
of natural gas and marketing of natural gas liquids. The NuStar Joint Venture,
in which Products recently acquired an 80 percent interest, has been engaged in
the processing of natural gas since 1951. Products' and NuStar's natural gas
processing plant operations consist of the extraction and sale of natural gas
liquids. The products extracted from the gas stream include marketable ethane,
propane, butane and natural gasoline mix. The residue gas remaining after the
liquid products have been extracted consists primarily of ethane and methane. In
addition to the 66.67 percent interest in the Benedum gas processing plant owned
by NuStar Joint Venture, Products also owns the second largest natural gas
processing plant in Oklahoma, which is located near Calumet, Oklahoma and has
the capacity to process 250 million cubic feet of natural gas per day. Products
also owns interests in three other natural gas processing plants in Oklahoma,
which have, in the aggregate, the capacity to process approximately 46 million
cubic feet of natural gas per day.
Most of the commercial grade propane processed at Products' Calumet
facility is sold on the local market. The other natural gas liquids, commonly
referred to as Group 140 are delivered to Conway, Kansas (which is one of the
nation's largest wholesale markets for gas liquids), where they are sold on the
spot market. Ethane, which is produced at all of Products' plants except
Calumet, is sold under a contract with Equistar Chemicals. This contract expires
in February 2000, but is renewable annually on an evergreen basis. Natural gas
liquids are marketed by Resources. Natural gas liquids from the NuStar Joint
Venture are sold to the Huntsman Chemicals plant (formerly Rexene Chemicals) in
Midland, Texas pursuant to a recently renewed contract expiring in February
2002.
In processing and marketing natural gas liquids, the Enogex companies
compete against virtually all other gas processors selling natural gas liquids.
The Enogex companies believe they will be able to continue to compete favorably
against such companies. With respect to factors affecting the natural gas
liquids industry generally, as the price of natural gas liquids fall without a
corresponding decrease in the price of natural gas, it may become uneconomical
to extract certain natural gas liquids. As to factors affecting the Enogex
companies specifically, the volume of natural gas processed at their plants is
dependent upon the volume of natural gas transported through the pipeline system
located "behind the
16
plants." If the volume of natural gas transported by such pipeline increases
"behind the plants," then the volume of liquids extracted by Products should
normally increase.
Marketing. Enogex's natural gas marketing is conducted through
---------
Resources. Resources serves both producers and consumers of natural gas by
buying natural gas at the wellhead or at gathering points both on and off the
Enogex pipeline system and reselling to interstate pipelines, end-users or
downstream purchasers both within and outside Oklahoma. Resources has placed
emphasis on the purchase and sale of volumes of gas moving on the Enogex
pipeline system in order to enhance utilization of pipeline capacity. During
1998, Resources sold approximately 434 billion Btu of natural gas per day, of
which about 70 percent moved on the Enogex pipeline system.
Resources purchases and sells gas under long-term contracts, as well as
in the "spot" market. In response to changes currently taking place in the gas
industry, Resources has been de-emphasizing its short-term markets, and an
increasing proportion of its revenues are earned pursuant to long-term sales
contracts. However, short-term or "spot" sales of natural gas will continue to
play a critical role in overall strategy because they provide an important
source of market intelligence, while serving a portfolio balancing function.
Price risk on extended term gas purchase or sales contracts entered into by
Resources is hedged on the NYMEX futures exchange as a matter of corporate
policy. Commencing in 1995, Resources began serving Products by purchasing and
marketing the natural gas liquids produced by Products. In addition, Resources
also markets natural gas developed by Exploration when volumes are sufficiently
concentrated to justify Resources marketing these volumes directly instead of
through the property operator. Other services provided include energy forward
price evaluations and centralized corporate commodity price risk management.
In its marketing and transportation services for third parties, Enogex
Inc. and Resources encounter competition from other natural gas transporters and
marketers and from other available alternative energy sources. The effect of
competition from alternative energy sources is dependent upon the availability
and cost of competing supply sources. Resources competes with all major
suppliers of natural gas and natural gas liquids in the geographic markets they
serve. For natural gas, those geographic markets are primarily the areas served
by pipelines with which Enogex is interconnected. Although the price of the gas
is an important factor to a buyer of natural gas from Resources, the primary
factor is the total cost (including transportation fees) that the buyer must
pay. Natural gas transported for Resources by Enogex Inc. is billed at the same
rate Enogex Inc. charges for comparable third-party transportation.
Development and Production. Exploration was formed in 1988 primarily to
--------------------------
engage in the development and production of oil and natural gas. Exploration
focused its early drilling activity in the Antrim Devonian shale trend in the
state of Michigan and also has interests in Oklahoma, Utah, Texas, Indiana,
Mississippi and Louisiana. As of December 31, 1998, Exploration had interests in
550 active wells. Exploration's estimated proved reserves were 90,877 Mmcfe. The
standardized measure of discounted future net cash flow with related Section 29
tax credits of Exploration's proved reserves was $56.9 million at December 31,
1998. During the fourth quarter of 1998, Exploration (through Resources)
initiated a program of hedging the future gas selling price on a portion of its
lease production through commodity futures contracts to cushion against
unfavorable monthly price swings.
17
ORIGEN
The Company's newest wholly-owned non-regulated subsidiary, Origen is
currently engaged in geothermal heat pump systems and the development of new
products.
Origen plans to initiate another energy related business unit in 1999.
This new unit is anticipated to be a contractor/distributor in the geothermal
industry, located in the Detroit, Michigan area. In addition, Origen plans to
discontinue operations of its business unit, Geothermal Design and Engineering,
Inc., in the first quarter of 1999. Origen did not contribute to earnings in
1998 and is not anticipated to contribute to earnings in 1999.
FINANCE AND CONSTRUCTION
The Company generally meets its cash needs through internally generated
funds, short-term borrowings and permanent financing. Cash flows from operations
remained strong in 1998 and 1997, which enabled the Company to internally
generate the required funds to satisfy construction expenditures during these
years.
Management expects that internally generated funds will be adequate
over the next three years to meet the Company's anticipated construction
expenditures. The primary capital requirements for 1999 through 2001 are
estimated as follows:
(DOLLARS IN MILLIONS) 1999 2000 2001
- --------------------------------------------------------------------------------
Electric utility construction
expenditures including AFUDC............ $101.7 $100.0 $100.0
Non-utility construction expenditures
and pending acquisitions................ 35.0 25.0 30.0
Maturities of long-term debt.............. 2.0 169.0 2.0
- --------------------------------------------------------------------------------
Total................................. $138.7 $294.0 $132.0
================================================================================
The three-year estimate includes expenditures for construction of new
facilities to meet anticipated demand for service, to replace or expand existing
facilities in both its electric and non-utility businesses, to fund pending
acquisitions (including any related capital expenditures), and to some extent,
for satisfying maturing debt. Approximately $0.5 million of the Company's
construction expenditures budgeted for 1999 are to comply with environmental
laws and regulations. OG&E's construction program was developed to support an
anticipated peak demand growth of one to two percent annually and to maintain
minimum capacity reserve margins as stipulated by the Southwest Power Pool. See
"Electric Operations - Rate Structure, Load Growth and Related Matters."
OG&E intends to meet its customers' increased electricity needs during
the foreseeable future primarily by maintaining the reliability and increasing
the utilization of existing capacity. OG&E's current resource strategy includes
the reactivation of existing plants and the addition of peaking resources. OG&E
does not anticipate the need for another base-load plant in the foreseeable
future.
18
The Company will continue to use short-term borrowings to meet
temporary cash requirements. OG&E has the necessary regulatory approvals to
incur up to $400 million in short-term borrowings at any one time. The maximum
amount of outstanding short-term borrowings during 1998 was $183.5 million.
In October 1995, OG&E changed its primary method of long-term debt
financing from issuing first mortgage bonds under its First Mortgage Bond Trust
Indenture to issuing Senior Notes under a new Indenture (the "Senior Note
Indenture"). Each series of Senior Notes issued under the Senior Note Indenture
was secured in essence by a series of first mortgage bonds (the "Back-up First
Mortgage Bonds"), subject to the condition that, upon retirement or redemption
of all first mortgage bonds issued prior to October 1995 (the "Prior First
Mortgage Bonds"), each series of Back-up First Mortgage Bonds would
automatically be canceled. In April 1998, all of the Prior First Mortgage Bonds
were redeemed or retired with the result that no first mortgage bonds remain
outstanding. OG&E has cancelled its First Mortgage Bond Trust Indenture and
caused the related first mortgage lien on substantially all of its properties to
be discharged and released. OG&E expects to have more flexibility in future
financings under its Senior Note Indenture than existed under the First Mortgage
Bond Trust Indenture.
In accordance with the requirements of the PURPA (see "Electric
Operations - Regulation and Rates - National Energy Legislation"), OG&E is
obligated to purchase 110 megawatts of capacity annually from Smith
Cogeneration, Inc., 320 megawatts annually from Applied Energy Services, Inc.,
another qualified cogeneration facility and up to 110 megawatts of capacity from
MCPC. OG&E also has agreed to purchase energy not needed by the Sparks Regional
Medical Center from its nominal seven megawatt cogeneration facility.
The Company's financial results continue to depend to a large extent
upon the tariffs OG&E charges customers and the actions of the regulatory bodies
that set those tariffs, the amount of energy used by OG&E's customers, the cost
and availability of external financing and the cost of conforming to government
regulations.
ENVIRONMENTAL MATTERS
The Company's management believes all of its operations are in
substantial compliance with present federal, state and local environmental
standards. It is estimated that the Company's total expenditures for capital,
operating, maintenance and other costs to preserve and enhance environmental
quality will be approximately $41.5 million during 1999, compared to
approximately $44.6 million utilized in 1998. Approximately $0.5 million of the
Company's construction expenditures budgeted for 1999 are to comply with
environmental laws and regulations. The Company continues to evaluate its
environmental management systems to ensure compliance with existing and proposed
environmental legislation and regulations and to better position itself in a
competitive market.
As required by Title IV of the Clean Air Act Amendments of 1990
("CAAA"), OG&E has completed installation and certification of all required
continuous emissions monitors ("CEMs") at its generating stations. OG&E submits
emissions data quarterly to the Environmental Protection Agency ("EPA") as
required by the CAAA. Phase II sulfur dioxide ("SO2") emission requirements will
affect
19
OG&E beginning in the year 2000. Based on current information, OG&E believes it
can meet the SO2 limits without additional capital expenditures. In 1998, OG&E
emitted 54,801 tons of SO2.
With respect to the nitrogen oxide ("NOx") regulations of Title IV of
the CAAA, OG&E committed to meeting a 0.45 lbs/mmbtu NOx emission level in 1997
on all coal-fired boilers. As a result, OG&E was eligible to exercise its option
to extend the effective date of the lower emission requirements from the year
2000 until 2008. OG&E's average NOx emissions for 1998 was 0.36 lbs/mmbtu.
OG&E has submitted all of its required Title V permit applications. As
a result of the Title V Program, OG&E paid approximately $0.3 million in fees in
1998.
Other potential air regulations have emerged that could impact OG&E.
The Ozone Transport Assessment Group ("OTAG") studied long range transport of
ozone and its precursors across a thirty-seven state area. The study was
completed in 1997 but as a result of the efforts of OG&E and others, Oklahoma
and 14 other states were exempted from any OTAG emission reduction requirements.
However, in the fall of 1998, EPA proposed a further study of ozone transport
from these 15 states to determine if emissions reductions in these states are
warranted. If reductions had been required in Oklahoma, OG&E could have been
forced to reduce its NOx emissions even further from the limits imposed by Title
IV of the Act.
In 1997, EPA finalized revisions to the ambient ozone and particulate
standards. Based on current ozone data, Tulsa and Oklahoma counties will likely
fail to meet the proposed standard for ozone. In addition, EPA projects that
Muskogee, Kay, Tulsa and Comanche counties in Oklahoma would fail to meet the
standard for particulate matter. If reductions are required in Muskogee, Kay and
Oklahoma counties, significant capital expenditures could be required by OG&E.
By mid-1999, EPA is expected to issue regulations concerning regional
haze. This regulation is intended to protect visibility in national parks and
wilderness areas throughout the United States. In Oklahoma, the Wichita
Mountains would be the only area covered under the regulation. Emissions of
sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead to
the degradation of visibility. It is possible that controls on sources hundreds
of miles away from the affected area may be required. Both Sooner and Muskogee
Generating Stations could face significant capital expenditures if reductions
are required.
In December 1997, the United States was a signatory to the Kyoto
Protocol for the reduction of greenhouse gases that contribute to global
warming. The U.S. committed to a 7 percent reduction from the 1990 levels. If
the Senate ratifies the Kyoto Protocol, this reduction could have a significant
impact on OG&E's use of coal as a boiler fuel. Based on current load and fuel
budget projections, a 7 percent reduction of greenhouse gases would require OG&E
to substantially increase gas burning in the year 2008 and to significantly
reduce its use of coal as a boiler fuel. Since there are numerous issues which
will affect how this reduction would be implemented, if at all, the cost to the
Company to comply with this reduction cannot be established at this time, but is
expected to be substantial.
The Company has and will continue to seek new pollution prevention
opportunities and to evaluate the effectiveness of its waste reduction, reuse
and recycling efforts. In 1998, the Company obtained refunds of approximately
$155,000 from its recycling efforts. This figure does not include the additional
savings gained through the reduction and/or a avoidance of disposal costs and
the reduction in material purchases due to reuse of existing materials. Similar
savings are anticipated in future years.
20
OG&E has made application for renewal of all of its National Pollutant
Discharge Elimination system permits. OG&E has received all of the permits in
final form except one which is pending regulatory action. All of the permits
issued to date offer greater operational flexibility than those in the past.
OG&E has requested that the State agency responsible for the
development of Water Quality Standards remove the agriculture beneficial use
classification from one of its cooling water reservoirs. Without removal of this
classification, the facility could be subjected to standards that will require
costly treatment and/or facility reconfiguration. The request for the removal of
this classification has been approved at the state level and is awaiting
approval by EPA.
OG&E remains a party to two separate actions brought by the EPA
concerning cleanup of disposal sites for hazardous and toxic waste. See "Item 3.
Legal Proceedings".
The Company has and will continue to evaluate the impact of its
operations on the environment. As a result, contamination on Company property
may be discovered from time to time. One site identified as having been
contaminated by historical operations was addressed during 1998. Remedial
options based on the future use of this site are being pursued with appropriate
regulatory agencies. The cost of these actions has not had and is not
anticipated to have a material adverse impact on the Company's financial
position or results of operations.
EMPLOYEES
The Company and its subsidiaries had 2,779 employees at December 31,
1998.
21
ITEM 2. PROPERTIES.
- ------------------
OG&E owns and operates an interconnected electric production,
transmission and distribution system, located in Oklahoma and western Arkansas,
which includes eight active generating stations with an aggregate active
capability of 5,561 megawatts. The following table sets forth information with
respect to present electric generating facilities, all of which are located in
Oklahoma:
Unit Station
Year Capability Capability
Station & Unit Fuel Installed (Megawatts) (Megawatts)
- -------------- ---- --------- ----------- -----------
Seminole 1 Gas 1971 515.0
2 Gas 1973 507.0
3 Gas 1975 500.0 1,522
Muskogee 3 Gas 1956 165.0
4 Coal 1977 492.5
5 Coal 1978 492.5
6 Coal 1984 506.0 1,656
Sooner 1 Coal 1979 514.0
2 Coal 1980 517.0 1,031
Horseshoe 6 Gas 1958 172.0
Lake 7 Gas 1963 237.0
8 Gas 1969 396.0 805
Mustang 1 Gas 1950 58.0 Inactive
2 Gas 1951 57.0 Inactive
3 Gas 1955 120.0
4 Gas 1959 260.0
5 Gas 1971 63.0 443
Conoco 1 Gas 1991 25.5
2 Gas 1991 29.5 55
Arbuckle 1 Gas 1953 74.0 Inactive
Enid 1 Gas 1965 9.8
2 Gas 1965 9.6
3 Gas 1965 11.0
4 Gas 1965 9.6 40
Woodward 1 Gas 1963 9.0 9
-----------
Total Active Generating Capability (all stations) 5,561
===========
22
At December 31, 1998, OG&E's transmission system included: (i) 65
substations with a total capacity of approximately 15.5 million kVA and
approximately 4,003 structure miles of lines in Oklahoma; and (ii) six
substations with a total capacity of approximately 1.9 million kVA and
approximately 241 structure miles of lines in Arkansas. OG&E's distribution
system included: (i) 300 substations with a total capacity of approximately 4.1
million kVA, 19,998 structure miles of overhead lines, 1,623 miles of
underground conduit and 6,623 miles of underground conductors in Oklahoma; and
(ii) 30 substations with a total capacity of approximately 617,500 kVA, 1,658
structure miles of overhead lines, 165 miles of underground conduit and 369
miles of underground conductors in Arkansas.
Substantially all of OG&E's electric facilities were previously subject
to a direct first mortgage lien under the Trust Indenture securing OG&E's first
mortgage bonds. The Trust Indenture and related lien were discharged in April
1998.
Enogex owns: (i) approximately 3,329 miles of natural gas gathering and
transmission pipeline extending from the Arkoma Basin in eastern Oklahoma to the
Anadarko Basin in western Oklahoma; (ii) a 75 percent interest in the Noark
Pipeline LP which in turn owns 100 percent of the Ozark Gas Transmission LLC and
related companies, a 924 mile interstate pipeline system with gathering and
transmission operations in eastern Oklahoma and Arkansas and an approximate
current capacity of 330 million cubic feet per day; (iii) a natural gas
processing plant near Calumet, Oklahoma, which has the capacity to process 250
Mmcf of natural gas per day; (iv) interests in three other natural gas
processing plants in Oklahoma, which have, in the aggregate, the capacity to
process approximately 46 Mmcf of natural gas per day; (v) an 80 percent interest
in the NuStar Joint Venture, whose assets include a 66.67 percent interest in
the Benedum gas processing plant with an inlet capacity of 110 million cubic
feet per day, a 100 percent interest in a second bypass plant with a capacity of
30 million cubic feet per day, 52 miles of natural gas liquid pipeline and over
200 miles of related gas gathering facilities located in Upton, Crockett, Reagan
and neighboring counties in the Permian Basin in West Texas; and (vi) 100% of
the gas gathering, processing and treating assets of the Belvan Corporation and
Belvan and Todd Ranch Limited Partnerships, consisting of 345 miles of gathering
system, gas liquid recovery and sulfur extraction facilities with a combined
effective current capacity of 15 million cubic feet per day, and an eight-mile
natural gas liquids pipeline.
During the three years ended December 31, 1998, the Company's gross
property, plant and equipment additions approximated $652 million and gross
retirements approximated $136 million. These additions were provided by
internally generated funds. The additions during this three-year period amounted
to approximately 14.7 percent of total property, plant and equipment at December
31, 1998.
ITEM 3. LEGAL PROCEEDINGS.
- -------------------------
1. On July 8,1994, an employee of OG&E filed a lawsuit in state court
against OG&E in connection with OG&E's VERP. The case was removed to the U.S.
District Court in Tulsa, Oklahoma. On August 23, 1994, the trial court granted
OG&E's Motion to Dismiss Plaintiff's Complaint in its entirety.
On September 12, 1994, Plaintiff, along with two other Plaintiffs,
filed an Amended Complaint alleging substantially the same allegations, which
were in the original complaint. The action was filed as a class action, but no
motion to certify a class was ever filed. Plaintiffs want credit, for retirement
purposes, for years they worked prior to a pre-ERISA (1974) break in service.
They allege violations of ERISA, the Veterans Reemployment Act, Title VII, and
the Age Discrimination in Employment Act. State law claims, including one for
intentional infliction of emotional distress, are also alleged.
23
On October 10, 1994, Defendants filed a Motion to Dismiss Counts II,
IV, V, VI and VII of Plaintiffs' Amended Complaint. With regard to Counts I and
III, Defendants filed a Motion for Summary Judgment on January 18, 1996. On
September 8, 1997, the United States Magistrate Judge recommended the
Defendant's motions to dismiss and for summary judgment should be granted and
that the case be dismissed in its entirety and judgment entered for OG&E. The
United States District Judge accepted the recommendation of the Magistrate and
entered judgement for OG&E. Plaintiffs have filed an appeal, which is pending
with the Tenth Circuit Court of Appeals.
While the Company cannot predict the precise outcome of the proceeding,
the Company continues to believe that the lawsuit is without merit and will not
have a material adverse effect on its consolidated results of operations or
financial condition.
2. OG&E is also involved, along with numerous other Potentially
Responsible Parties ("PRP"), in an EPA administrative action involving the
facility in Holden, Missouri, of Martha C. Rose Chemicals, Inc. ("Rose").
Beginning in early 1983 through 1986, Rose was engaged in the business of
brokering of polychlorinated biphenyls ("PCBs") and PCB items, processing of PCB
capacitors and transformers for disposal, and decontamination of mineral oil
dielectric fluids containing PCBs. During this time period, various generators
of PCBs ("Generators"), including OG&E, shipped materials containing PCBs to the
facility. Contrary to its contractual obligation with OG&E and other Generators,
it appears that Rose failed to manage, handle and dispose of the PCBs and the
PCB items in accordance with the applicable law. Rose has been issued citations
by both the EPA and the Occupational Safety and Health Administration. Several
Generators, including OG&E, formed a Steering Committee to investigate and clean
up the Rose facility.
The Company's share of the total hazardous wastes at the Rose facility
was less than six percent. The remediation of this site was completed in 1995 by
the Steering Committee and is currently in the final stages of closure with the
EPA, which includes operation and maintenance activities as required in the
Administrative Order on Consent with the EPA. Due to additional funds resulting
from payments by third party companies who were not a part of the Steering
Committee, and also reduced remedy implementation costs, the Company received a
refund in December 1995 under the allocation formula. OG&E has reached a
settlement agreement with its insurance carrier, AEGIS Insurance Company, with
respect to costs incurred at this site. The Company considers this insurance
matter to be closed.
Management believes that OG&E's ultimate liability for any additional
cleanup costs of this site will not have a material adverse effect on OG&E's
financial position or its results of operations. Management's opinion is based
on the following: (i) the present status of the site; (ii) the cleanup costs
already paid by certain parties; (iii) the financial viability of the other
PRPs; (iv) the portion of the total waste disposed at this site attributable to
OG&E; and (v) the Company's settlement agreement with its insurer. Management
also believes that costs incurred in connection with this site, which are not
recovered from insurance carriers or other parties, may be allowable costs for
future ratemaking purposes. Absent an unforeseen contingency, OG&E believes this
matter is now closed.
3. On January 11, 1993, OG&E received a Section 107 (a) Notice Letter
from the EPA, Region VI, as authorized by the CERCLA, 42 USC Section 9607 (a),
concerning the Double Eagle Refinery Superfund Site located at 1900 NE First
Street in Oklahoma City, Oklahoma. The EPA has named OG&E and 45 others as PRPs.
Each PRP could be held jointly and severally liable for remediation of this
site.
24
On February 15, 1996, OG&E elected to participate in the de minimis
settlement of EPA's Administrative Order on Consent. This would limit OG&E's
financial obligation and also would eliminate its involvement in the design and
implementation of the site remedy. A third party is currently contesting OG&E's
participation as a de minimis party. Regardless of the outcome of this issue,
OG&E believes that its ultimate liability for this site will not be material
primarily due to the limited volume of waste sent by OG&E to the site.
4. As previously reported, on September 18,1996, Trigen-Oklahoma City
Energy Corporation ("Trigen") sued OG&E in the United States District Court,
Western District of Oklahoma, Case No. CIV-96-1595-M. Trigen alleged six causes
of action: (i) monopolization in violation of Section 2 of the Sherman Act; (ii)
attempt to monopolize in violation of Section 2 of the Sherman Act; (iii) acts
in restraint of trade in violation of Oklahoma law, 79 O.S. 1991, ss. 1; (iv)
discriminatory sales in violation of 79 O.S. 1991, ss. 4; (v) tortuous
interference with contract; and (vi) tortuous interference with a prospective
economic advantage. On December 21, 1998, the jury awarded Trigen in excess of
$30 million in actual and punitive damages. On February 19, 1999, the trial
court entered judgement in favor of Trigen as follows: (i) $6.8 million for
various antitrust violations, (ii) $4 million for tortious interference with an
existing contract, (iii) $7 million for tortious interference with a prospective
economic advantage and (iv) $10 million in punitive damages. The trial judge, in
a companion order, acknowledged that the portions of the judgement could be
duplicative, that the antitrust amounts could be tripled and that parties should
address these issues in their post-trial motions. OG&E has filed its post trial
motions requesting judgement in its favor or a new trial. If a successful
result is not obtained at the trial level, OG&E will appeal. While the outcome
of an appeal is uncertain, legal counsel and management believe it is not
probable that Trigen will ultimately succeed in preserving the verdicts.
Accordingly, the Company has not accrued any loss associated with the damages
awarded. The Company believes that the ultimate resolution of this case will not
have a material adverse effect on the Company's consolidated financial position
or results of operations.
5. As previously reported, the State of Oklahoma, ex rel., Teresa
Harvey (Carroll); Margaret B. Fent and Jerry R. Fent v. Oklahoma Gas and
Electric Company, et al., District Court, Oklahoma County, Case No.
CJ-97-1242-63. On February 24, 1997, the taxpayers instituted litigation against
OG&E and Co-Defendants Oklahoma Corporation Commission, Oklahoma Tax Commission
and individual commissioners seeking judgment in the amount of $970,184.14 and
treble penalties of $2,910,552.42, plus interest and costs, for overcharges
refunded by OG&E to its ratepayers in compliance with an Order of the OCC which
Plaintiffs allege was illegal. Plaintiffs allege the refunds should have been
paid into the state Unclaimed Property Fund. In June 1997, OG&E's Motion for
Summary Judgment was granted. Plaintiffs appealed. On April 10, 1998, the Court
of Civil Appeals affirmed the order of the trial court granting OG&E Summary
Judgement. On April 29, 1998, Plaintiffs petitioned the Court of Civil Appeals
for rehearing. Plaintiffs' Petition for Rehearing was overruled. Plaintiffs
timely filed a Petition for Certiorari with the Oklahoma Supreme Court. The
Oklahoma Supreme Court denied Certiorari. Plaintiffs did not file their Petition
for Certiorari with the United States Supreme Court in time required. Case
closed.
6. As reported, the City of Enid, Oklahoma ("Enid") through its City
Council, notified OG&E of its intent to purchase OG&E's electric distribution
facilities for Enid and to terminate OG&E's franchise to provide electricity
within Enid as of June 26, 1998. On August 22, 1997, the City Council of Enid
adopted Ordinance No. 97-30, which in essence granted OG&E a new 25-year
franchise subject to approval of the electorate of Enid on November 18, 1997. In
October 1997, eighteen residents of Enid filed a lawsuit against Enid, OG&E and
others in the District Court of Garfield County, State of Oklahoma, Case No.
CJ-97-829-01. Plaintiffs seek a declaration holding that (a) the Mayor of Enid
and the City Council breached their fiduciary duty to the public and violated
Article 10, Section 17 of the Oklahoma Constitution by
25
allegedly "gifting" to OG&E the option to acquire OG&E's electric system when
the City Council approved the new franchise by Ordinance No. 97-30; (b) the
subsequent approval of the new franchise by the electorate of the City of Enid
at the November 18, 1997, franchise election cannot cure the alleged breach of
fiduciary duty or the alleged constitutional violation; (c) violations of the
Oklahoma Open Meetings Act occurred and that such violations render the
resolution approving Ordinance No. 97-30 invalid; (d) OG&E's support of the Enid
Citizens' Against the Government Takeover was improper; (e) OG&E has violated
the favored nations clause of the existing franchise; and (f) the City of Enid
and OG&E have violated the competitive bidding requirements found at 11 O.S.
35-201, et seq. Plaintiffs seek money damages against the Defendants under 62
O.S. 372 and 373. Plaintiffs allege that the action of the City Council in
approving the proposed franchise allowed the option to purchase OG&E's property
to be transferred to OG&E for inadequate consideration. Plaintiffs demand
judgment for treble the value of the property allegedly wrongfully transferred
to OG&E. On October 28, 1997, another resident filed a similar lawsuit against
OG&E, Enid and the Garfield County Election Board in the District Court of
Garfield County, State of Oklahoma, Case No. CJ-97-852-01. However, Case No.
CJ-97-852-01 was dismissed without prejudice in December 1997. On December 8,
1997, OG&E filed a Motion to Dismiss Case No. CJ-97-829-01 for failure to state
claims upon which relief may be granted. This motion is currently pending. While
the Company cannot predict the precise outcome of this proceeding, the Company
believes at the present time that this lawsuit is without merit and intends to
vigorously defend this case.
7. On February 18, 1998, Enogex was sued by Melvin Scoggin and Oak
Tree Resources,LLC, in the District Court of Oklahoma County, State of Oklahoma,
for alleged breach of contract, fraud,breach of fiduciary duty, misappropriation
and unjust enrichment arising from communications that allegedly created
agreements regarding oil and gas exploration activities. Plaintiffs seek damages
in excess of $25 million. enogex filed an answer denying Plaintiffs'
allegations. Various discovery disputes have been heard and favorable rulings
for Enogex were entered by the Court. Plaintiffs sought a Writ of Mandamus from
the Oklahoma Supreme Court regarding discovery denied by the district court on
three occaisions. On March 23, 1999, the Oklahoma Supreme court denied
Plaintiffs' request. Discovery continues. While Enogex believes all the
aforementioned claims are without merit, Enogex cannot predict the ultimate
outcome of this litigation.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
- ------------------------------------------------------------
None
26
EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------
The following persons were Executive Officers of the Registrant as of
March 15, 1999:
Name Age Title
- -------------------- --- --------------------------------------
Steven E. Moore 52 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 55 Executive Vice President and
Chief Operating Officer
Michael G. Davis 49 Vice President - Marketing and
Customer Care
James R. Hatfield 41 Vice President and Treasurer
Irma B. Elliott 60 Vice President and
Corporate Secretary
Steven R. Gerdes 42 Vice President, Shared
Services
Melvin D. Bowen, Jr. 57 Vice President - Power Delivery - OG&E
Jack T. Coffman 55 Vice President - Power Supply - OG&E
Donald R. Rowlett 41 Controller Corporate Accounting
Don L. Young 58 Controller Corporate Audits
No family relationship exists between any of the Executive Officers of
the Registrant. Messrs. Moore, Strecker, Davis, Hatfield, Gerdes, Rowlett, Young
and Ms. Elliott are also officers of OG&E. Each Officer is to hold office until
the Board of Directors meeting following the next Annual Meeting of Shareowners,
currently scheduled for May 27, 1999.
The business experience of each of the Executive Officers of the
Registrant for the past five years is as follows:
27
Name Business Experience
- -------------------- ------------------------------------------------
Steven E. Moore 1996-Present: Chairman of the Board,
President and Chief
Executive Officer
1996-Present: Chairman of the Board,
President and Chief
Executive Officer - OG&E
1995-1996: President and Chief
Operating Officer - OG&E
1994-1995: Senior Vice President - Law
and Public Affairs - OG&E
Al M. Strecker 1998-Present: Executive Vice President and
Chief Operating Officer
1998-Present: Executive Vice President and
Chief Operating Officer -
OG&E
1996-1998: Senior Vice President
1994-1998: Senior Vice President -
Finance and
Administration - OG&E
1994: Vice President and
Treasurer - OG&E
Michael G. Davis 1998-Present: Vice President - Marketing
and Customer Care
1998-Present: Vice President - Marketing
and Customer Care -
OG&E
1996-1998: Vice President
1994-1998: Vice President -
Marketing and Customer
Services - OG&E
1994: Director - Marketing
Division - OG&E
James R. Hatfield 1997-Present: Vice President and Treasurer
1997-Present: Vice President and
Treasurer - OG&E
1994-1997: Treasurer - OG&E
28
Name Business Experience
- -------------------- ------------------------------------------------
1994: Vice President - Investor
Relations & Corporate
Secretary - Aquila Gas
Pipeline Corporation
Irma B. Elliott 1996-Present: Vice President and
Corporate Secretary
1996-Present: Vice President and
Corporate Secretary -
OG&E
1994-1996: Corporate Secretary - OG&E
Steven R. Gerdes 1998-Present: Vice President, Shared
Services
1998-Present: Vice President, Shared
Services - OG&E
1997-1998: Director, Shared Services
1997: Manager, Enterprise Support
1994-1997: Manager, Purchasing &
Material Management
1994: Manager, Purchasing
Melvin D. Bowen, Jr. 1994-Present: Vice President -
Power Delivery - OG&E
1994: Metro Region
Superintendent - OG&E
Jack T. Coffman 1994-Present: Vice President -
Power Supply - OG&E
1994: Manager - Generation
Services - OG&E
Donald R. Rowlett 1998-Present: Controller Corporate
Accounting
1996-Present: Controller Corporate
Accounting - OG&E
1994-1996: Assistant Controller - OG&E
1994: Senior Specialist -
Tax Accounting - OG&E
29
Name Business Experience
- -------------------- ------------------------------------------------
Don L. Young 1998-Present: Controller Corporate
Audits
1996-Present: Controller Corporate
Audits - OG&E
1994-1996: Controller - OG&E
30
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
- ---------------------------------------------------------
STOCKHOLDER MATTERS.
- -------------------
The Company's Common Stock is listed for trading on the New York and
Pacific Stock Exchanges under the ticker symbol "OGE." Quotes may be obtained in
daily newspapers where the common stock is listed as "OGE Engy" in the New York
Stock Exchange listing table. The following table gives information with respect
to price ranges, as reported in THE WALL STREET JOURNAL as New York Stock
-------------------------
Exchange Composite Transactions, and dividends paid for the periods shown.
1998 1997
----------------------------------------------------------------
DIVIDEND Dividend
PAID HIGH LOW Paid High Low
----------------------------------------------------------------
First Quarter $0.33 1/4 $28 15/16 $25 11/16 $0.33 1/4 $21 1/2 $20 1/4
Second Quarter 0.33 1/4 28 15/16 26 0.33 1/4 22 15/16 20 5/16
Third Quarter 0.33 1/4 29 9/16 25 5/8 0.33 1/4 23 5/8 22
Fourth Quarter 0.33 1/4 30 25 15/16 0.33 1/4 27 3/8 23 5/32
The number of record holders of Common Stock at December 31, 1998, was
39,008. The book value of the Company's Common Stock at December 31, 1998, was
$12.91.
31
ITEM 6. SELECTED FINANCIAL DATA.
- --------------------------------
HISTORICAL DATA
1998 1997 1996 1995 1994
---------------------------------------------------------------------------
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS EXCEPT
FOR PER SHARE DATA)
Operating revenues................. $1,617,737 $1,443,610 $1,387,435 $1,302,037 $1,355,168
Operating expenses................. 1,386,924 1,249,612 1,186,216 1,099,890 1,154,702
----------- ----------- ----------- ----------- -----------
Operating income................... 230,813 193,998 201,219 202,147 200,466
Other income and deductions........ 5,758 5,047 97 800 (2,167)
Interest charges................... 70,699 66,495 67,984 77,691 74,514
----------- ----------- ----------- ----------- -----------
Net income......................... 165,872 132,550 133,332 125,256 123,785
Preferred dividend
requirements..................... 733 2,285 2,302 2,316 2,317
Earnings available for
common........................... $ 165,139 $ 130,265 $ 131,030 $ 122,940 $ 121,468
=========== =========== =========== =========== ===========
Long-term debt..................... $ 935,583 $ 841,924 $ 829,281 $ 843,862 $ 730,567
Total assets....................... $2,983,929 $2,765,865 $2,762,355 $2,754,871 $2,782,629
Earnings per average common
share............................ $ 2.04 $ 1.61 $ 1.62 $ 1.52 $ 1.50
CAPITALIZATION RATIOS
Common equity...................... 52.72% 52.50% 52.26% 51.19% 54.13%
Cumulative preferred stock......... --- 2.63% 2.68% 2.73% 2.94%
Long-term debt..................... 47.28% 44.87% 45.06% 46.08% 42.93%
INTEREST COVERAGES
Before federal income taxes
(including AFUDC)................ 4.84X 4.11X 4.07X 3.48X 3.59X
(excluding AFUDC)................ 4.82X 4.10X 4.06X 3.46X 3.58X
After federal income taxes
(including AFUDC)................ 3.31X 2.98X 2.94X 2.59X 2.64X
(excluding AFUDC)................ 3.30X 2.97X 2.93X 2.57X 2.62X
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- --------------------------------------------------------------------------------
OF OPERATIONS.
- -------------
MANAGEMENT'S DISCUSSION AND ANALYSIS.
OVERVIEW
Percent Change
From Prior Year
---------------
(THOUSANDS EXCEPT PER SHARE AMOUNTS) 1998 1997 1996 1998 1997
==================================================================================================
Operating revenues...................... $1,617,737 $1,443,610 $1,387,435 12.1 4.0
Earnings available for common stock..... $ 165,139 $ 130,265 $ 131,030 26.8 (0.6)
Average shares outstanding.............. 80,772 80,745 80,734 --- ---
Earnings per average common share....... $ 2.04 $ 1.61 $ 1.62 26.7 (0.6)
Earnings per average common share -
assuming dilution..................... $ 2.04 $ 1.61 $ 1.62 26.7 (0.6)
Dividends paid per share................ $ 1.33 $ 1.33 $ 1.33 --- ---
==================================================================================================
The following discussion and analysis presents factors which had a
material effect on the operations and financial position of OGE Energy Corp.
(the "Company") and its subsidiaries: Oklahoma Gas and Electric Company
("OG&E"), Enogex Inc. and its subsidiaries ("Enogex") and Origen Inc. and its
subsidiaries ("Origen") during the last three years and should be read in
conjunction with the Consolidated Financial Statements and Notes thereto.
Average shares outstanding and all per share amounts have been restated to
reflect the two-for-one stock split that occurred in June 1998. Trends and
contingencies of a material nature are discussed to the extent known and
considered relevant.
The Company became the parent company of OG&E and OG&E's former
subsidiary, Enogex, on December 31, 1996, in a corporate reorganization whereby
all common stock of OG&E was exchanged on a share-for-share basis for common
stock of the Company. Prior to December 31, 1996, the Company had no operations
and the financial results discussed herein for 1996 essentially represent the
consolidated statements of OG&E; and comparisons to the 1996 results represent
comparisons to the consolidated results of OG&E. Under this corporate structure,
the Company serves as the parent holding company to OG&E, Enogex, Origen and any
other companies that may be formed within the organization in the future. This
holding company structure is intended to provide greater flexibility, allowing
the Company to take advantage of opportunities in an increasingly competitive
business environment and to clearly separate the Company's electric utility
business from its non-utility businesses. Because OG&E is the Company's
principal subsidiary, the Company's financial results and condition are
substantially dependent at this time on the financial results and condition of
OG&E.
Earnings for 1998 increased 26.7 percent from $1.61 per share in 1997
to $2.04 per share in 1998. The increase was primarily the result of higher
revenues at OG&E due to warmer weather, the Generation Efficiency Performance
Rider ("GEP Rider"), higher margin sales to other utilities and power marketers
("off-system sales"), customer growth and lower operation and maintenance
expense. The increase in earnings was partially offset by lower earnings at
Enogex and Origen. The GEP Rider allows OG&E to retain part of the fuel savings
achieved through cost efficiencies and is discussed in more detail
33
below. The 1997 decrease from $1.62 per share to $1.61 per share resulted
primarily from the $45 million annual reduction in OG&E's electric rates that
became effective in March 1997, slightly lower earnings by Enogex and a loss by
Origen, the Company's new non-regulated subsidiary, during its first year of
operation. The decrease in earnings was partially offset by the GEP Rider,
customer growth in the OG&E service area and lower interest costs.
The dividend payout ratio (expressed as a percentage of earnings
available for common) decreased to 65 percent (or 78 percent weather adjusted)
in 1998 from 83 percent in 1997. The Company's goal is to maintain a dividend
payout ratio of approximately 75 percent based on the current business
environment.
The Company's regulated utility business has been and will continue to
be affected by competitive changes to the utility industry. Significant changes
already have occurred in the wholesale electric markets at the Federal level. In
Oklahoma, legislation was passed in 1997 to provide for the orderly
restructuring of the electric industry with the goal to provide retail customers
with the ability to choose their generation suppliers by June 30, 2002. The
Arkansas Public Service Commission ("APSC") has initiated proceedings to
consider the implementation of a competitive retail market in Arkansas. These
developments are described in more detail below under "Regulation; Competition."
In 1996, the Company decided upon an enterprise-wide software system,
which is Year 2000 ready. Enterprise software is a corporate software system
designed to handle most of the Company's information processing needs and to
improve work processes throughout the Company. The enterprise software system
was successfully implemented throughout the Company on January 1, 1997 and is
expected to significantly enhance the Company's abilities in the more
competitive years ahead.
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.
34
RESULTS OF OPERATIONS
REVENUES
Percent Change
From Prior Year
---------------
(THOUSANDS) 1998 1997 1996 1998 1997
===================================================================================================
Sales of electricity to OG&E customers... $1,274,643 $1,168,663 $1,172,740 9.1 (0.3)
Sales of electricity to other utilities.. 37,435 23,027 27,597 62.6 (16.6)
Enogex................................... 304,694 251,575 187,098 21.1 34.5
Origen................................... 965 345 --- 179.4 ---
- ----------------------------------------------------------------------------------
Total operating revenues............... $1,617,737 $1,443,610 $1,387,435 12.1 4.0
===================================================================================================
System kilowatt-hour sales............... 23,642,599 22,182,992 21,540,670 6.6 3.0
Kilowatt-hour sales to other utilities... 727,601 1,201,933 1,475,449 (39.5) (18.5)
- ----------------------------------------------------------------------------------
Total kilowatt-hour sales.............. 24,370,200 23,384,925 23,016,119 4.2 1.6
===================================================================================================
In 1998, approximately 81 percent of the Company's revenues consisted
of regulated sales of electricity as a public utility, while the remaining 19
percent were provided primarily 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, producing natural
gas liquids, transporting natural gas through its pipelines in Oklahoma and
Arkansas for various customers (including OG&E), marketing electricity, natural
gas and natural gas liquids and investing in the drilling for and production of
crude oil and natural gas. Origen's operations remained immaterial to the
Company during 1998. The Company continues to evaluate the existing business
lines of Origen (which to date has consisted of geothermal design and
engineering) and potential new ventures for Origen. 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 $174.1 million or 12.1 percent during
1998, primarily due to a significant increase in revenue from OG&E and Enogex.
In 1998, OG&E revenues increased $120.4 million or 10.1 percent primarily due to
an increase in kilowatt-hour sales to OG&E customers ("system sales") from
warmer weather, the GEP Rider, higher margin sales to other utilities and power
marketers ("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.
35
Enogex revenues increased $53.1 million or 21.1 percent during 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 these 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.
On February 11, 1997, the OCC issued an order (the "Order") that, among
other things, effectively lowered OG&E's rates to its Oklahoma retail customers
by $50 million annually (based on a test year ended December 31, 1995). Of the
$50 million rate reduction, approximately $45 million became effective on March
5, 1997, and the remaining $5 million became effective March 1, 1998. This $50
million rate reduction was in addition to the $15 million rate reduction that
was effective January 1, 1995. The Order also directed OG&E to transition to
competitive bidding of its gas transportation requirements, currently met by
Enogex, no later than April 30, 2000, and set annual compensation for the
transportation services provided by Enogex to OG&E at $41.3 million until
competitively-bid gas transportation begins.
The 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.
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 1998,
the GEP Rider increased revenues (compared to 1997) by approximately $10.0
million, or approximately $0.08 per share. The current GEP Rider is estimated to
positively impact revenue by $33 million or approximately $0.26 per share during
the 12 months ending June 1999.
During 1997, operating revenues increased $56.2 million or 4.0 percent
primarily due to a significant increase in revenue from Enogex. In 1997, Enogex
revenues increased $64.5 million or 34.5 percent, primarily as a result of
significant increases in the volume of natural gas sold through its gas
marketing activities ($53.6 million), and of natural gas liquids processed and
sold ($7.2 million), mainly due to the acquisition of the NuStar Joint Venture
in May 1997, with a modest increase in prices for natural gas.
The increased revenues from Enogex were partially offset by decreased
revenues at OG&E. Decreased revenues at OG&E were primarily attributable to the
rate reduction in March 1997, and milder weather in the first and second
quarters of 1997, partially offset by continued customer growth, the effect of
the GEP Rider and warmer weather in the third quarter of 1997.
36
EXPENSES AND OTHER ITEMS
Percent Change
From Prior Year
---------------
(DOLLARS IN THOUSANDS) 1998 1997 1996 1998 1997
==================================================================================================
Fuel .................................... $ 315,194 $ 277,806 $ 279,083 13.5 (0.5)
Purchased power.......................... 240,542 222,464 222,070 8.1 0.2
Gas and electricity purchased for
resale (Enogex)..................... 216,432 172,764 117,343 25.3 47.2
Other operation and maintenance.......... 305,106 311,337 307,154 (2.0) 1.4
Depreciation and amortization............ 149,818 142,632 136,140 5.0 4.8
Taxes.................................... 159,832 122,609 124,426 30.4 (1.5)
- ----------------------------------------------------------------------------------
Total operating expenses............... $1,386,924 $1,249,612 $1,186,216 11.0 5.3
==================================================================================================
Total operating expenses increased $137.3 million or 11.0 percent in
1998, primarily due to increases at OG&E in quantities of fuel burned and
increased taxes. At Enogex, the increase was primarily due to increases in
quantities of gas and electricity purchased for resale by its gas and electric
marketing businesses.
Enogex's gas and electricity purchased for resale pursuant to its
energy-marketing operations increased $43.7 million or 25.3 percent for 1998
compared to $55.4 million or 47.2 percent for 1997. The 1998 increase was due to
a significant increase in sales volumes of natural gas (84,261 Bbtu or 97.2
percent) which more than offset a decrease in sales prices due to depressed
commodity prices. This increase was also due to the recent expansion into the
marketing of electricity. The 1997 increase was due to a significant increase in
sales volumes (29,236 Bbtu or 53.7 percent) and an increase in purchase prices
of approximately 15 percent.
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 1998, fuel costs increased due to a
modest increase in total generation and a slight increase in the average cost of
fuel burned for generation of electricity. During 1997, despite a slight
increase in kwh sales, fuel costs decreased $1.3 million or 0.5 percent
primarily due to an increase in the percentage of coal-fired generation relative
to total generation.
Other operation and maintenance decreased $6.2 million or 2.0 percent
in 1998 primarily because of decreases at OG&E in post retirement medical costs
($3.8 million), 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 general corporate
expenses ($4.5 million). These decreases were partially offset by expansion
activities at Enogex ($8.4 million). In 1997, other operation and maintenance
expenses increased $4.2 million primarily because of increased costs associated
with expansion activities at Enogex.
In 1998, taxes increased $37.2 million or 30.4 percent primarily due to
significantly higher pre-tax income and normally occurring temporary
differences. In 1997, taxes had a net decrease of $1.8
37
million or 1.5 percent primarily due to slightly lower pre-tax income and
normally occurring temporary differences.
Purchased power costs increased $18.1 million or 8.1 percent in 1998
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. In 1997, purchased power costs were $222.5 million, remaining
relatively constant compared to the $222.1 million in 1996. As required by the
Public Utility Regulatory Policy Act ("PURPA"), OG&E is currently purchasing
power from qualified cogeneration facilities.
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are passed through to OG&E's electric customers through
automatic fuel adjustment clauses. The automatic fuel adjustment clauses are
subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC
and the FERC have authority to review the appropriateness of gas transportation
charges or other fees OG&E pays Enogex, which OG&E seeks to recover through the
fuel adjustment clause or other tariffs. In addition to the February 11, 1997,
OCC Order, the APSC issued an order in July 1996 requiring, among other things,
a $4.5 million refund. See Note 11 of Notes to Consolidated Financial Statements
for a discussion of the July 1996 order.
OG&E has initiated numerous ongoing programs that have helped reduce
the cost of generating electricity over the last several years. These programs
include: 1) utilizing a natural gas storage facility; 2) spot market purchases
of coal; 3) renegotiated contracts for coal, gas, railcar maintenance and coal
transportation; and 4) a heat-rate awareness program to produce kilowatt-hours
with less fuel. Reducing fuel costs helps OG&E remain competitive, which in turn
helps OG&E's electric customers remain competitive in a global economy.
The increases in depreciation and amortization for 1998 and 1997
reflect higher levels of depreciable plant.
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. In 1997, the decrease in interest expense was
attributable to OG&E retiring $15 million of 5.125 percent First Mortgage Bonds
in January 1997, the successful refinancing of $336 million of short-term and
long-term debt by OG&E and Enogex in 1997, and a lower average daily balance in
short-term debt.
38
LIQUIDITY AND CAPITAL RESOURCES
The primary capital requirements for 1998 and as estimated for 1999
through 2001 are as follows:
(DOLLARS IN MILLIONS) 1998 1999 2000 2001
================================================================================
Electric utility construction
expenditures including AFUDC........... $ 96.7 $101.7 $100.0 $100.0
Non-utility construction expenditures
and acquisitions....................... 138.5 35.0 25.0 30.0
Maturities of long-term debt............. 26.0 2.0 169.0 2.0
- --------------------------------------------------------------------------------
Total................................ $261.2 $138.7 $294.0 $132.0
================================================================================
The Company's primary needs for capital are related to construction of
new facilities to meet anticipated demand for utility service, to replace or
expand existing facilities in both its electric and non-utility businesses, to
expand its non-utility businesses and to some extent, for satisfying maturing
debt and sinking fund obligations. The Company generally meets its cash needs
through a combination of internally generated funds, short-term borrowings and
permanent financing.
1998 CAPITAL REQUIREMENTS AND FINANCING ACTIVITIES
Capital requirements were $261.2 million in 1998. Approximately $1.0
million of the 1998 capital requirements were to comply with environmental
regulations. This compares to capital requirements of $163.6 million in 1997, of
which $1.1 million was to comply with environmental regulations.
During 1998, the Company's sources of capital were internally generated
funds from operating cash flows, permanent financing and short-term borrowings.
Operating cash flow remained strong in 1998 as internally generated funds,
short-term debt and long-term debt issued by NOARK Pipeline Systems, L.P.
("NOARK"), met virtually all of the Company's capital expenditures. Variations
in accounts receivable and accounts payable are not generally significant
indicators of the Company's liquidity, as such variations are primarily
attributable to fluctuations in weather in OG&E's service territory, which has a
direct effect on sales of electricity.
Short-term borrowings were used during 1998 to meet temporary cash
requirements. At December 31, 1998, the Company had outstanding short-term
borrowings of $119.1 million.
On January 2, 1998, OG&E retired $25 million principal amount of 6.375
percent First Mortgage Bonds due January 1, 1998.
On April 15, 1998, OG&E issued $100.0 million in Senior Notes at 6.50
percent due April 15, 2028. The proceeds from the sale of this new debt were
applied to the redemption on April 21, 1998 of $12.5 million principal amount of
OG&E's 7.125 percent First Mortgage Bonds due January 1, 1999, $40.0 million
principal amount of OG&E's 7.125 percent First Mortgage Bonds due
39
January 1, 2002 and $35.0 million principal amount of OG&E's 8.625 percent First
Mortgage Bonds due November 1, 2007 and for general corporate purposes.
In October 1998, the Company made a $53 million capital contribution to
Enogex reflecting the Company's commitment to maintaining Enogex's strong credit
rating and financial health.
In January 1998, Enogex, through a newly formed subsidiary, Enogex
Arkansas Pipeline Corp. ("EAPC") acquired a 40 percent interest in the
partnership that owns NOARK, a natural gas pipeline, for approximately $30
million and agreed to acquire Ozark Pipeline ("Ozark"), for approximately $55
million. The NOARK line is a 302-mile intra-state pipeline system that extends
from near Fort Chaffee, Arkansas to near Paragould, Arkansas. The Ozark line is
a 437-mile inter-state pipeline system that begins near McAlester, Oklahoma and
terminates near Searcy, Arkansas. In July 1998, EAPC completed its acquisition
of Ozark and contributed Ozark to NOARK. The two pipelines were integrated into
a single, interstate transmission system on November 1, 1998 at an additional
cost of approximately $16 million. Current throughput capacity on the
NOARK/Ozark line is approximately 330 million cubic feet per day. 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.
In January 1998, EAPC issued a $5.7 million Note at 7 percent, due July
1, 2020. The proceeds from the Note were utilized by EAPC in the NOARK
acquisition. Annual payments of approximately $0.8 million (including principal
and accrued interest) begin July 1, 2004.
In June 1998, NOARK Pipeline Finance, L.L.C., a finance company
subsidiary of NOARK, issued $80.0 million aggregate principal amount of
unsecured 7.15 percent Notes due 2018. These Notes are entitled to the benefits
of a guaranty issued by Enogex pursuant to which Enogex has guaranteed 40
percent (subject to certain adjustments) of the principal, interest and premium
on such Notes. The remaining 60 percent of the principal, interest and premium
on such Notes are guaranteed by Southwestern Energy Company, the parent company
of Southwestern Energy Pipeline Company. The proceeds from the sale of the Notes
were loaned by NOARK Pipeline Finance, L.L.C. to NOARK and utilized by NOARK (i)
to repay a bank revolving line of credit (approximately $29.75 million), (ii) to
repay an outstanding short-term loan from Enogex (approximately $48.825 million)
and (iii) for general corporate purposes. Principal payments of $1.0 million
plus accrued interest are due semi-annually.
In July 1998, Enogex agreed to lease underground gas storage from
Central Oklahoma Oil and Gas Corp. ("COOG"). COOG currently leases gas storage
capacity to OG&E. In connection with 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.
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 $0.5 million of the Company's construction expenditures budgeted
for 1999 are to comply with environmental laws and regulations.
40
In November 1998, the Company announced plans to repurchase up to 6
million shares of its Common Stock over the next two years. 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 will
bear the risk of increases and the benefit of decreases on the price of the
Common Stock until CIBC Oppenheimer Corp. replaces, through open market
purchases or privately negotiated transactions, the shares sold to the Company.
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 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, 1998, the Company had in place a
line of credit for up to $160 million, which was to expire December 6, 2000. In
January 1999, the Company's line of credit was increased to $200 million and the
Company entered into a $75 million credit agreement with CIBC Oppenheimer Corp.
to fund the share repurchase described above.
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
There has been a great deal of publicity about the Year 2000 ("Y2K")
and the possible problems that information technology systems may suffer as a
result. The Y2K problem originated with the early development of computerized
business applications. To save then-expensive storage space, reduce the
complexity of calculations and yield better system performance, programmers and
developers used a two-digit date scheme to represent the year (i.e., "72" for
"1972"). This two-digit date scheme was used well into the 1980s and 1990s in
traditional computer hardware such as mainframe systems, desktop personal
computers and network servers, in customized software systems, off-the-shelf
applications and operating systems, as well as in embedded systems ("chips") in
everything from elevators to industrial plants to consumer products. As the Year
2000 approaches, date-sensitive systems may recognize the Year 2000 as 1900, or
not at all. This inability to recognize or properly treat the Year 2000 may
cause systems, including those of the Company, its customers, suppliers,
business partners and neighboring utilities to process critical financial and
operational information incorrectly, if they are not Year 2000 ready. A failure
to identify and correct any such processing problems prior to January 1, 2000
could result in material operational and financial risks if the affected systems
either cease to function or produce erroneous data. Such risks are described in
more detail below, but could include an inability to operate OG&E's generating
plants, disruptions in the operation of its transmission and distribution system
and an inability to access interconnections with the systems of neighboring
utilities.
41
After the Company's mainframe conversion in 1994, some 300 programs
were identified as having date sensitive code. All of these programs have since
been corrected or will be replaced by Y2K ready packaged applications.
The Company continues to address the Y2K issues in an aggressive
manner. This is reflected by the January 1, 1997 implementation throughout the
Company of SAP Enterprise Software, which is Y2K ready, for the financial
systems. The SAP installation significantly reduced the potential risks in our
older computer systems. The Company is making significant progress towards the
implementation of the enterprise-wide software system for customer systems. In
addition to significantly reducing the potential risks of its current customer
systems, the Company is set to streamline work processes in customer service and
power delivery by integrating separate systems into a single system using the
enterprise-wide software system. This new single system will also provide for a
more flexible automated billing system and enhancements in handling customer
service orders, energy outage incidents and customer services.
In October of 1997, the Company formed a multi-functional Y2K Project
Team of experienced and knowledgeable members from each business unit to review
and test its operational systems in an effort to further eliminate any potential
problems, should they exist. The team provides regular monthly reports on its
progress to the Y2K Executive Steering Committee and senior management as well
as helping prepare presentations to the Board of Directors.
The Company's Year 2000 effort generally follows a three-phase process:
Phase I - Inventory and Assess Y2K Issues
Phase II - Determine Y2K Readiness of Vendors, Suppliers & Customers
Phase III - Correct, Test, Implement Solutions and Contingency
Planning
STATE OF READINESS
The Company has substantially completed the internal inventory and
assessment (Phase I) of the Year 2000 plan. Follow-up vendor surveys are being
sent to vendors that have not responded to our original requests for information
(Phase II). Remediation efforts are ongoing and even though contingency planning
is a normal part of our business, plans are being prepared to include specific
activities with regard to Y2K issues (Phase III).
In addition, as a part of the Company's three-year lease agreement for
personal computers, all new personal computers are being issued with operating
systems and application software that is Y2K ready. All existing personal
computers will be upgraded with Y2K ready operating systems before the turn of
the century. For embedded and plant operational systems, the Company has
generally completed the evaluative process and is commencing corrective plans.
In particular, the Company's Energy Management System ("EMS") that monitors
transmission interconnections and automatically signals generation output
changes, has been contracted for replacement in 1999. Equipment is currently
being installed and software is being configured.
The Company is also participating in an "Electric System Readiness
Assessment" program, which provides monthly reports to the Southwest Power Pool
("SPP") and the North American Electric Reliability Council ("NERC"). The
responses from all participating companies are being compiled for an
industry-wide status report to the Department of Energy ("DOE"). In addition,
the Company is in the
42
process of developing its contingency plans that will be submitted shortly to
the SPP and NERC to assist them in assessing Y2K readiness of the regional
electric grid.
COSTS OF YEAR 2000 ISSUES
As described above, with the mainframe conversion, the enterprise
software installations and the EMS replacement, 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. In addition to
the $1 million spent to date for Y2K issues, since 1995 the Company has spent in
excess of $29 million on the mainframe conversion, the enterprise software
installations and the EMS replacement. The Company expects to spend slightly
less than $5 million in 1999. These costs represent estimates, however, and
there can be no assurance that actual costs associated with the Company's Y2K
issues will not be higher.
RISKS OF YEAR 2000 ISSUES
As described above, the Company has made significant progress in the
implementation of its Year 2000 plan. Based upon the information currently known
regarding its internal operations and assuming successful and timely completion
of its remediation plan, the Company does not anticipate significant business
disruptions from its internal systems due to the Y2K issue. However, the Company
may possibly experience limited interruptions to some aspects of its activities,
whether information technology, operational, administrative or otherwise, and
the Company is considering such potential occurrences in planning for its most
reasonably likely worst case scenarios.
Additionally, risk exists regarding the non-readiness of third parties
with key business or operational importance to the Company. Year 2000 problems
affecting key customers, interconnected utilities, fuel suppliers and
transporters, telecommunications providers or financial institutions could
result in lost power or gas sales, reductions in power production or
transmission or internal functional and administrative difficulties on the part
of the Company. Although the Company is not presently aware of any such
situations, occurrences of this type, if severe, could have material adverse
impacts upon the business, operating results or financial condition of the
Company. There can be no assurance that the Company will be able to identify and
correct all aspects of the Year 2000 problem that affect it in sufficient time,
that it will develop adequate contingency plans or that the costs of achieving
Y2K readiness will not be material.
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 materials. Remediation of one of these
sites has been completed and the required monitoring is in place. OG&E's total
waste disposed at the remaining site is minimal and on February 15, 1996, the
Company elected to participate in the de minimis settlement offered by the
Environmental Protection Agency ("EPA"), which is being contested by one party.
This limits the Company's financial obligation in addition to removing any
participation in the site remedy. While it is not possible to determine the
precise outcome of these matters, in the opinion of management, OG&E's ultimate
liability for these sites will not be material.
43
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.
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 January 1, 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 $0.3
million in 1998 and are estimated to be approximately $0.4 million in 1999.
REGULATION; COMPETITION
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 purpose of the Act, as set forth therein, is generally to
restructure the electric utility industry to provide for more competition and,
in particular, to provide for the orderly restructuring of the electric utility
industry in the State of Oklahoma in order to allow customers to choose their
electricity suppliers while maintaining the safety and reliability of the
electric system in the state.
The Act directs the 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 is to address: (i) technical issues (including reliability, safety,
unbundling of generation, transmission and distribution services, transition
issues and market power); (ii) financial issues (including rates, charges,
access fees, transition costs and stranded costs); (iii) consumer issues (such
as the obligation to serve, service territories, consumer choices, competition
and consumer safeguards); and (iv) tax issues (including sales and use taxes, ad
valorem taxes and franchise fees).
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
44
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.
A new bill was introduced in the State Senate in January 1999 and if
enacted would clarify certain ambiguities by defining key terms in the Act.
In December 1997, the APSC established four generic proceedings to
consider the implementation of a competitive retail electric market in the State
of Arkansas. During 1998, the APSC held hearings to consider competitive retail
generation, market structure, market power, taxation, recovery and mitigation of
stranded costs, service and reliability, low income assistance, independent
system operators and transition issues. The Company participated actively in
those proceedings, and in October 1998, the APSC issued its report on these
issues to the Arkansas General Assembly.
On February 11, 1997, the OCC issued an Order, among other things,
directing OG&E to transition to competitive bidding for its gas transportation
requirements, currently met by Enogex, no later than April 30, 2000. This Order
also set annual compensation for the transportation services provided by Enogex
to OG&E at $41.3 million until competitively-bid gas transportation begins. In
1998, approximately $41.6 million or 8.2 percent of Enogex's revenues were
attributable to transporting gas for OG&E. Other pipelines seeking to compete
with Enogex for OG&E's business will likely have to pay a fee to Enogex for
transporting gas on Enogex's system or incur capital expenditures to develop the
necessary infrastructure to connect with OG&E's gas-fired generating stations.
Nevertheless, a potential outcome of the competitive bidding process is that the
revenues of Enogex derived from transporting gas for OG&E may be significantly
less after April 30, 2000.
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.
In October 1992, the National Energy Policy Act of 1992 ("Energy Act")
was enacted. Among many other provisions, the Energy Act is designed to promote
competition in the development of wholesale power generation in the electric
utility industry. It exempts a new class of independent power producers from
regulation under the Public Utility Holding Company Act of 1935 and allows the
FERC to order wholesale "wheeling" by public utilities to provide utility and
non-utility generators access to public utility transmission facilities.
In April 1996, the FERC issued two final rules, Orders 888 and 889,
which are having a significant impact on wholesale markets. Order 888, sets
forth rules on non-discriminatory open access transmission service to promote
wholesale competition. Order 888, which was effective on July 9, 1996, requires
utilities and other transmission users to abide by comparable terms, conditions
and pricing in transmitting power. Order 889, which had its effective date
extended to January 3, 1997, requires public utilities to implement Standards of
Conduct and an Open Access Same Time Information System ("OASIS", formerly known
as "Real-Time Information Networks"). These rules require transmission personnel
to provide the same information about the transmission system to all
transmission customers using the OASIS. In 1997, the FERC issued clarifying
final orders in response to rehearing requests by numerous market participants
regarding Orders No. 888 and 889. During 1998, OG&E submitted filings to the
FERC to comply with these Orders, and those filings have been accepted. As OG&E
continues to prepare for restructuring at the retail level, it is expected that
additional filings will be made in order to ensure continuing compliance with
the FERC's wholesale restructuring orders.
45
Another impact of complying with FERC's Order 888 is a requirement for
utilities to offer a transmission tariff that includes network transmission
service ("NTS") to transmission customers. NTS allows transmission service
customers to fully integrate load and resources on an instantaneous basis, in a
manner similar to how OG&E has historically integrated its load and resources.
Under NTS, OG&E and participating customers share the total annual transmission
cost for their combined joint-use systems, net of related transmission revenues,
based upon each company's share of the total system load. Management expects
minimal annual expenses as a result of Orders 888 and 889.
As discussed previously, Oklahoma enacted legislation that will
restructure the electric utility industry in Oklahoma by July 2002, assuming
that all the conditions in the legislation are met. This legislation would
deregulate OG&E's electric generation assets and the continued use of Statement
of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects
of Certain Types of Regulation" with respect to the related regulatory assets
may no longer be appropriate. This may result in either full recovery of
generation-related regulatory assets (net of related regulatory liabilities) or
a non-cash, pre-tax write-off as an extraordinary charge of up to $31 million,
depending on the transition mechanisms developed by the legislature for the
recovery of all or a portion of these net regulatory assets.
The enacted Oklahoma legislation does not affect OG&E's electric
transmission and distribution assets and the Company believes that the continued
use of SFAS No. 71 with respect to the related regulatory assets is appropriate.
However, if utility regulators in Oklahoma and Arkansas were to adopt regulatory
methodologies in the future that are not based on cost-of-service, the continued
use of SFAS No. 71 with respect to the regulatory assets related to the electric
transmission and distribution assets may no longer be appropriate.
Based on a current evaluation of the various factors and conditions
that are expected to impact future cost recovery, management believes that its
regulatory assets, including those related to generation, are probable of future
recovery.
On February 13, 1998, the APSC Staff filed a motion for a show cause
order to review OG&E's electric rates in the State of Arkansas. The staff is
recommending a $3.1 million annual rate reduction (based on a test year ended
December 31, 1996). OG&E filed a cost of service study and has requested a $1.7
million annual rate increase. A decision on this rate case is expected in the
next few months.
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 market value and sensitivity analysis.
46
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 does not currently participate in
interest rate-related derivative financial instruments. 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.
=============================================================================================================
1998
Year-end
(DOLLARS IN MILLIONS) 1999 2000 2001 2002 2003 Thereafter Total Fair Value
- -------------------------------------------------------------------------------------------------------------
Fixed rate debt
Principal amount...... $ 2.0 $169.0 $ 2.0 $ 65.0 $ 2.0 $564.7 $804.7 $844.8
Weighted-average
interest rate....... 7.15% 6.41% 7.15% 7.05% 7.15% 6.79% 6.95% ---
Variable-rate debt
Principal amount...... --- --- --- --- --- $135.4 $135.4 $135.4
Weighted-average
interest rate....... --- --- --- --- --- 3.77% 3.77% ---
=============================================================================================================
COMMODITY PRICE EXPOSURE
The market risk inherent in our market risk sensitive instruments and
positions is the potential loss arising from adverse changes in our 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's policy is to 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 1999:
(DOLLARS IN THOUSANDS) Wholesale Non-Trading
================================================================================
Commodity market risk, net........ $ 823 $ 877
================================================================================
47
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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
- -------------------------------------------------------------------
See Management's Discussion and Analysis of Financial Condition and
Results of Operations, Market Risk.
48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
- ---------------------------------------------------
CONSOLIDATED BALANCE SHEETS
December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service................................................... $4,391,232 $4,125,858 $4,005,532
Construction work in progress................................ 50,039 25,799 27,968
- ------------------------------------------------------------------------------------------------------------
Total property, plant and equipment........................ 4,441,271 4,151,657 4,033,500
Less accumulated depreciation............................ 1,914,721 1,797,806 1,687,423
- ------------------------------------------------------------------------------------------------------------
Net property, plant and equipment............................ 2,526,550 2,353,851 2,346,077
- ------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost........................ 31,682 37,898 24,802
- ------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents.................................... 378 4,257 2,523
Accounts receivable - customers, less reserve of $3,342,
$4,507 and $4,626, respectively............................ 141,235 117,842 128,974
Accrued unbilled revenues.................................... 22,500 36,900 34,900
Accounts receivable - other.................................. 12,902 11,470 11,748
Fuel inventories, at LIFO cost............................... 57,288 49,369 62,725
Materials and supplies, at average cost...................... 29,734 28,430 24,827
Prepayments and other........................................ 31,551 4,489 4,300
Accumulated deferred tax assets.............................. 7,811 6,925 10,067
- ------------------------------------------------------------------------------------------------------------
Total current assets....................................... 303,399 259,682 280,064
- ------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Advance payments for gas..................................... 15,000 10,500 9,500
Income taxes recoverable through future rates................ 40,731 42,549 44,368
Other........................................................ 66,567 61,385 57,544
- ------------------------------------------------------------------------------------------------------------
Total deferred charges..................................... 122,298 114,434 111,412
- ------------------------------------------------------------------------------------------------------------
TOTAL ASSETS................................................... $2,983,929 $2,765,865 $2,762,355
============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
49
CONSOLIDATED BALANCE SHEETS (Continued)
December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statements):
Common stock and retained earnings........................... $1,043,382 $ 984,960 $ 961,603
Cumulative preferred stock................................... --- 49,266 49,379
Long-term debt............................................... 935,583 841,924 829,281
- ------------------------------------------------------------------------------------------------------------
Total capitalization....................................... 1,978,965 1,876,150 1,840,263
- ------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Short-term debt.............................................. 119,100 1,000 41,400
Accounts payable............................................. 96,936 77,733 86,856
Dividends payable............................................ 26,865 27,428 27,421
Customers' deposits.......................................... 23,985 23,847 23,257
Accrued taxes................................................ 30,500 21,677 26,761
Accrued interest............................................. 21,081 20,041 19,832
Long-term debt due within one year........................... 2,000 25,000 15,000
Other........................................................ 50,266 38,518 39,188
- ------------------------------------------------------------------------------------------------------------
Total current liabilities.................................. 370,733 235,244 279,715
- ------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation....................... 17,952 62,023 61,335
Accumulated deferred income taxes............................ 531,940 503,952 488,016
Accumulated deferred investment tax credits.................. 67,728 72,878 78,028
Other........................................................ 16,611 15,618 14,998
- ------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities............... 634,231 654,471 642,377
- ------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 10, 11 and 13)
- ------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES........................... $2,983,929 $2,765,865 $2,762,355
============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
50
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
==================================================================================================================
COMMON STOCK AND RETAINED EARNINGS:
Common stock, par value $0.01 per share, authorized
125,000,000 shares; and outstanding 80,797,539,
80,771,834, and 92,941,232 shares, respectively.................. $ 808 $ 808 $ 929
Premium on capital stock........................................... 512,806 512,089 936,108
Retained earnings.................................................. 529,768 472,063 449,198
Treasury stock, zero, zero, and 12,183,742 shares,
respectively..................................................... --- --- (424,632)
- ------------------------------------------------------------------------------------------------------------------
Total common stock and retained earnings....................... 1,043,382 984,960 961,603
- ------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK:
Par value $20, authorized 675,000 shares - 4%;
zero, 418,963, and 421,963 shares, respectively.................. --- 8,379 8,439
Par value $100, authorized 1,865,000 shares-
SERIES SHARES OUTSTANDING
4.20% zero, 49,750, and 49,950 shares, respectively.......... --- 4,975 4,995
4.24% zero, 74,990, and 75,000 shares, respectively.......... --- 7,499 7,500
4.44% zero, 63,200, and 63,500 shares, respectively.......... --- 6,320 6,350
4.80% zero, 70,925, and 70,950 shares, respectively.......... --- 7,093 7,095
5.34% zero, 150,000, and 150,000 shares, respectively........ --- 15,000 15,000
- ------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock............................... --- 49,266 49,379
- ------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT:
First mortgage bonds-
SERIES DATE DUE
5.125% January 1, 1997........................................ --- --- 15,000
6.375% January 1, 1998........................................ --- 25,000 25,000
7.125% January 1, 1999........................................ --- 12,500 12,500
6.250% Senior Notes Series B, October 15, 2000................ 110,000 110,000 110,000
7.125% January 1, 2002........................................ --- 40,000 40,000
8.375% January 1, 2007........................................ --- --- 75,000
8.625% November 1, 2007....................................... --- 35,000 35,000
8.250% August 15, 2016........................................ --- --- 100,000
7.000% Pollution Control Series C, March 1, 2017.............. --- --- 56,000
6.500% Senior Notes Series D, July 15, 2017................... 125,000 125,000 ---
8.875% December 1, 2020....................................... --- --- 75,000
7.300% Senior Notes Series A, October 15, 2025................ 110,000 110,000 110,000
6.650% Senior Notes Series C, July 15, 2027................... 125,000 125,000 ---
6.500% Senior Notes Series E, April 15, 2028.................. 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 ---
Unamortized premium and discount, net.............................. (2,488) (976) (8,619)
Enogex Inc. notes (Note 6)......................................... 234,671 150,000 120,000
- ------------------------------------------------------------------------------------------------------------------
Total long-term debt........................................... 937,583 866,924 844,281
Less long-term debt due within one year...................... 2,000 25,000 15,000
- ------------------------------------------------------------------------------------------------------------------
Total long-term debt (excluding long-term
debt due within one year).................................... 935,583 841,924 829,281
- ------------------------------------------------------------------------------------------------------------------
Total Capitalization................................................. $1,978,965 $1,876,150 $1,840,263
==================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
51
CONSOLIDATED STATEMENTS OF INCOME
Year ended December 31 (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1998 1997 1996
================================================================================================================
OPERATING REVENUES................................................. $1,617,737 $1,443,610 $1,387,435
- ----------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Fuel............................................................. 315,194 277,806 279,083
Purchased power.................................................. 240,542 222,464 222,070
Gas and electricity purchased for resale......................... 216,432 172,764 117,343
Other operation and maintenance.................................. 305,106 311,337 307,154
Depreciation and amortization.................................... 149,818 142,632 136,140
Current income taxes............................................. 84,722 57,347 81,227
Deferred income taxes, net....................................... 29,072 22,255 2,150
Deferred investment tax credits, net............................. (5,150) (5,150) (5,150)
Taxes other than income.......................................... 51,188 48,157 46,199
- ----------------------------------------------------------------------------------------------------------------
Total operating expenses....................................... 1,386,924 1,249,612 1,186,216
- ----------------------------------------------------------------------------------------------------------------
OPERATING INCOME................................................... 230,813 193,998 201,219
- ----------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
Interest income.................................................. 3,561 3,873 2,198
Other............................................................ 2,197 1,174 (2,101)
- ----------------------------------------------------------------------------------------------------------------
Net other income and deductions................................ 5,758 5,047 97
- ----------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt....................................... 60,856 62,572 62,412
Allowance for borrowed funds used during construction............ (1,071) (599) (709)
Other............................................................ 10,914 4,522 6,281
- ----------------------------------------------------------------------------------------------------------------
Total interest charges, net.................................... 70,699 66,495 67,984
- ----------------------------------------------------------------------------------------------------------------
NET INCOME......................................................... 165,872 132,550 133,332
PREFERRED DIVIDEND REQUIREMENTS.................................... 733 2,285 2,302
- ----------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON STOCK................................ $ 165,139 $ 130,265 $ 131,030
================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (thousands)...................... 80,772 80,745 80,734
EARNINGS PER AVERAGE COMMON SHARE.................................. $ 2.04 $ 1.61 $ 1.62
AVERAGE COMMON SHARES OUTSTANDING
ASSUMING DILUTION (thousands).................................... 80,787 80,745 80,734
EARNINGS PER AVERAGE COMMON SHARE
ASSUMING DILUTION................................................ $ 2.04 $ 1.61 $ 1.62
================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
52
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year ended December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
BALANCE AT BEGINNING OF PERIOD................................. $ 472,063 $ 449,198 $ 425,545
ADD - net income............................................... 165,872 132,550 133,332
Total...................................................... 637,935 581,748 558,877
DEDUCT:
Cash dividends declared on preferred stock................... 733 2,285 2,302
Cash dividends declared on common stock...................... 107,434 107,400 107,377
- ------------------------------------------------------------------------------------------------------------
Total...................................................... 108,167 109,685 109,679
- ------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD....................................... $ 529,768 $ 472,063 $ 449,198
============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
53
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income................................................... $ 165,872 $ 132,550 $ 133,332
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation and amortization.............................. 149,818 142,632 136,140
Deferred income taxes and investment tax credits, net...... 23,922 17,105 (3,000)
Gain on sale of assets..................................... --- (2,511) ---
Provision for rate refund.................................. --- --- 1,804
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers........................ (23,393) 11,132 (16,533)
Accrued unbilled revenues.............................. 14,400 (2,000) 8,650
Fuel, materials and supplies inventories............... (9,223) 9,753 (4,200)
Accumulated deferred tax assets........................ (886) 3,142 692
Other current assets................................... (25,627) 89 (2,361)
Accounts payable....................................... 19,203 (9,123) 13,401
Accrued taxes.......................................... 8,823 (5,084) (1,176)
Accrued interest....................................... 1,040 209 688
Accumulated provision for rate refund.................. --- --- (2,650)
Other current liabilities.............................. 11,323 (73) 7,131
Other operating activities................................. (43,003) (2,503) 22,753
- ------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities............ 292,269 295,318 294,671
- ------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures....................................... (235,231) (163,571) (161,129)
Other investing activities................................. (8,084) 4,900 ---
- ------------------------------------------------------------------------------------------------------------
Net cash used in investing activities.................. (243,315) (158,671) (161,129)
- ------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt............................... (113,500) (321,000) ---
Proceeds from long-term debt............................... 100,000 336,000 ---
Short-term debt, net....................................... 118,100 (40,400) (26,200)
Redemption of preferred stock.............................. (49,266) (113) (560)
Retirement of treasury stock............................... --- 285 ---
Cash dividends declared on preferred stock................. (733) (2,285) (2,302)
Cash dividends declared on common stock.................... (107,434) (107,400) (107,377)
- ------------------------------------------------------------------------------------------------------------
Net cash used in financing activities.................. (52,833) (134,913) (136,439)
- ------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS.................................................. (3,879) 1,734 (2,897)
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD....................................................... 4,257 2,523 5,420
CASH AND CASH EQUIVALENTS AT END OF PERIOD..................... $ 378 $ 4,257 $ 2,523
============================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Cash Paid During the Period for:
Interest (net of amount capitalized)................... $ 59,792 $ 64,081 $ 64,882
Income taxes .......................................... $ 77,150 $ 64,705 $ 82,970
- ------------------------------------------------------------------------------------------------------------
NON-CASH INVESTING AND FINANCING ACTIVITIES
Debt assumed in acquisition of subsidiary.................. $ 80,000 --- ---
Capital lease financing.................................... $ 9,818 --- ---
Other investing and financing activities................... $ (3,000) $ 5,185 ---
============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
REORGANIZATION AND PRINCIPALS OF CONSOLIDATION
OGE Energy Corp. (the "Company") became the parent company of Oklahoma
Gas and Electric Company ("OG&E") and OG&E's former subsidiary, Enogex Inc.
("Enogex") on December 31, 1996. On that date, all outstanding OG&E common stock
was exchanged on a share-for-share basis for common stock of OGE Energy Corp.
and the common stock of Enogex was distributed to the Company. In 1997, the
Company also became the parent company of Origen Inc. and its subsidiaries
("Origen"), the newly formed non-regulated businesses. The financial information
presented through December 31, 1996, represents the consolidated results of
OG&E. All significant intercompany transactions have been eliminated in
consolidation.
ACCOUNTING RECORDS
The accounting records of OG&E are maintained in accordance with the
Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission ("FERC") and adopted by the Oklahoma Corporation Commission ("OCC")
and the Arkansas Public Service Commission ("APSC"). Additionally, OG&E, as a
regulated utility, is subject to the accounting principles prescribed by the
Financial Accounting Standards Board ("FASB") Statement of Financial Accounting
Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of
Regulation." SFAS No. 71 provides that certain costs that would otherwise be
charged to expense can be deferred as regulatory assets, based on expected
recovery from customers in future rates. Likewise, certain credits that would
otherwise 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, 1998, regulatory assets and regulatory liabilities are being reflected in
rates charged to customers over periods ranging from one to 20 years.
The components of deferred charges - other, and regulatory assets and
liabilities on the Consolidated Balance Sheets included the following, as of
December 31:
55
DEFERRED CHARGES - OTHER
(DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
Regulated Deferred Charges:
Workforce reduction.......................................... $ --- $ --- $ 3,759
Unamortized debt expense..................................... 8,566 6,776 10,291
Unamortized loss on reacquired debt.......................... 29,072 28,660 10,253
Miscellaneous................................................ 2,217 403 435
- ------------------------------------------------------------------------------------------------------------
Total regulated deferred charges........................... 39,855 35,839 24,738
- ------------------------------------------------------------------------------------------------------------
Non-Regulated Deferred Charges:
Enogex gas sales contracts................................... 12,389 13,925 14,949
Insurance claims - property damage........................... --- --- 6,231
Miscellaneous................................................ 14,323 11,621 11,626
- ------------------------------------------------------------------------------------------------------------
Total non-regulated deferred charges....................... 26,712 25,546 32,806
- ------------------------------------------------------------------------------------------------------------
Total Deferred Charges......................................... $ 66,567 $ 61,385 $ 57,544
============================================================================================================
REGULATORY ASSETS AND LIABILITIES
(DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
Regulatory Assets:
Income taxes recoverable from customers...................... $ 104,160 $ 115,989 $ 127,819
Unamortized loss on reacquired debt.......................... 29,072 28,660 10,253
Workforce reduction.......................................... --- --- 3,759
Miscellaneous................................................ 2,217 403 435
- ------------------------------------------------------------------------------------------------------------
Total Regulatory Assets.................................... 135,449 145,052 142,266
Regulatory Liabilities:
Income taxes refundable to customers......................... (63,429) (73,440) (83,451)
Gain on disposition of allowances............................ --- --- (329)
- ------------------------------------------------------------------------------------------------------------
Net Regulatory Assets.......................................... $ 72,020 $ 71,612 $ 58,486
============================================================================================================
Management continuously monitors the future recoverability of
regulatory assets. When, in management's judgment, future recovery becomes
impaired; the amount of the regulatory asset is reduced or written-off, as
appropriate.
If the Company were required to discontinue the application of SFAS No.
71 for some or all of its operations, it would result in writing off the related
regulatory assets; the financial effects of which could be significant.
56
ACCOUNTING PRONOUNCEMENTS
In June 1997, the FASB issued SFAS No. 131, "Disclosures About Segments
of an Enterprise and Related Information". Adoption of SFAS No. 131 is required
for fiscal years beginning after December 15, 1997. The Company adopted this new
standard effective December 31, 1998. Adoption of this new standard changed the
presentation of certain disclosure information of the Company, but did not
affect reported earnings.
In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits". Adoption of SFAS No. 132 is
required for financial statements for periods beginning after December 15, 1997.
The Company adopted this new standard effective December 31, 1998. Adoption of
this new standard changed the presentation of certain disclosure information of
the Company, but did not affect reported earnings.
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
will adopt this new standard effective January 1, 1999, and management believes
the adoption of this new standard will not have a material impact on its
consolidated financial position or results of operations.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and for Hedging Activities". Adoption of SFAS No. 133 is required
for financial statements for periods beginning after June 15, 1999. The Company
will adopt this new standard effective January 1, 2000, and management believes
the adoption of this new standard will not have a material impact on its
consolidated financial position or results of operations.
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 effect of initial application of
EITF Issue 98-10 will be reported as a cumulative effect of a change in
accounting principle. The Company will adopt this new Issue effective January 1,
1999, and management believes the adoption of the new Issue will not have a
material impact on its consolidated financial position or results of operations.
DERIVATIVES
Enogex, in the normal course of business, enters into fixed price
contracts for either the purchase or sale of natural gas and electricity at
future dates. Due to fluctuations in the natural gas and electricity markets,
the Company buys or sells natural gas and electricity futures contracts, swaps
or options to hedge the price and basis risk associated with the specifically
identified purchase or sales contracts. Additionally, the Company will use these
contracts as an enhancement or speculative trade. For qualifying hedges, the
Company accounts for changes in the market value of futures contracts as a
deferred gain or loss until the production month for hedged transactions, at
which time the gain or loss on the natural gas or electricity futures contract,
swap or option is recognized in the results of operations. The Company
recognizes the gain or loss on enhancement or speculative contracts as market
values change in the results of operations.
57
USE OF ESTIMATES
In preparing the consolidated financial statements, management is
required to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
PROPERTY, PLANT AND EQUIPMENT
All property, plant and equipment is recorded at cost. Electric utility
plant is recorded at its original cost. Newly constructed plant is added to
plant balances at costs which include contracted services, direct labor,
materials, overhead and allowance for funds used during construction.
Replacement of major units of property are capitalized as plant. The replaced
plant is removed from plant balances and the cost of such property together with
the cost of removal less salvage is charged to accumulated depreciation. Repair
and replacement of minor items of property are included in the Consolidated
Statements of Income as other operation and maintenance expense.
DEPRECIATION
The provision for depreciation, which was approximately 3.2 percent of
the average depreciable utility plant, for each of the years 1998, 1997 and
1996, is provided on a straight-line method over the estimated service life of
the property. Depreciation is provided at the unit level for production plant
and at the account or sub-account level for all other plant, and is based on the
average life group procedure.
Enogex's gas pipeline, gathering systems, compressors and gas
processing plants are depreciated on a straight-line method over periods ranging
from 10 to 48 years.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction ("AFUDC") is calculated
according to FERC pronouncements for the imputed cost of equity and borrowed
funds. AFUDC, a non-cash item, is reflected as a credit on the Consolidated
Statements of Income and a charge to construction work in progress.
AFUDC rates, compounded semi-annually, were 5.75, 5.94 and 5.63 percent
for the years 1998, 1997 and 1996, 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.
58
The Company's cash management program utilizes controlled disbursement
banking arrangements. Outstanding checks in excess of cash balances totaled
$27.8 million, $18.5 million and $24.0 million at December 31, 1998, 1997 and
1996, respectively, and are classified as accounts payable in the accompanying
Consolidated Balance Sheets. Sufficient funds were available to fund these
outstanding checks when they were presented for payment.
HEAT PUMP LOANS
OG&E has a heat pump loan program, whereby, qualifying customers may
obtain a loan from OG&E to purchase a heat pump. Customer loans are available
from a minimum of $1,500 to a maximum of $13,000 with a term of 6 months to 72
months. The finance rate is based upon short-term loan rates and is reviewed and
updated periodically. The interest rates were 8.25, 8.25 and 9.75 percent at
December 31, 1998, 1997 and 1996, respectively.
The current portion of these loans totaled $1.0 million, $4.9 million
and $4.0 million at December 31, 1998, 1997 and 1996, respectively, and are
classified as accounts receivable - customers in the accompanying Consolidated
Balance Sheets. The noncurrent portion of these loans totaled $4.0 million,
$19.1 million and $15.3 million at December 31, 1998, 1997 and 1996,
respectively, and are classified as other property and investments in the
accompanying Consolidated Balance Sheets. In 1998 OG&E sold approximately $25.0
million of its heat pump loans.
UNBILLED REVENUE
OG&E accrues estimated revenues for services provided but not yet
billed. The cost of providing service is recognized as incurred.
AUTOMATIC FUEL ADJUSTMENT CLAUSES
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are charged to substantially all of OG&E's electric customers
through automatic fuel adjustment clauses, which are subject to periodic review
by the OCC, the APSC and the FERC.
FUEL INVENTORIES
Fuel inventories for the generation of electricity consists of coal,
oil and natural gas. These inventories are accounted for under the last-in,
first-out ("LIFO") cost method. The estimated replacement cost of fuel
inventories was lower than the stated LIFO cost by approximately $4.4 million
for 1998 and $1.1 million for 1997, and exceeded the stated LIFO cost by
approximately $4.6 million for 1996, based on the average cost of fuel purchased
late in the respective years. Natural gas products inventories are held for sale
and accounted for based on the weighted average cost of production.
ACCRUED VACATION
The Company accrues vacation pay by establishing a liability for
vacation earned during the current year, but is not payable until the following
year. The accrued vacation totaled $13.4 million, $13.2 million and $11.4
million at December 31, 1998, 1997 and 1996, respectively, and is classified as
other current liabilities in the accompanying Consolidated Balance Sheets.
59
ENVIRONMENTAL COSTS
Accruals for environmental costs are recognized when it is probable
that a liability has been incurred and the amount of the liability can be
reasonably estimated. When a single estimate of the liability cannot be
determined, the low end of the estimated range is recorded. Costs are charged to
expense or deferred as a regulatory asset based on expected recovery from
customers in future rates, if they relate to the remediation of conditions
caused by past operations or if they are not expected to mitigate or prevent
contamination from future operations. Where environmental expenditures relate to
facilities currently in use, such as pollution control equipment, the costs may
be capitalized and depreciated over the future service periods. Estimated
remediation costs are recorded at undiscounted amounts, independent of any
insurance or rate recovery, based on prior experience, assessments and current
technology. Accrued obligations are regularly adjusted as environmental
assessments and estimates are revised, and remediation efforts proceed. For
sites where OG&E has been designated as one of several potentially responsible
parties, the amount accrued represents OG&E's estimated share of the cost.
RECLASSIFICATIONS AND STOCK SPLIT
Certain amounts have been reclassified on the consolidated financial
statements to conform with the 1998 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.
60
2. INCOME TAXES
The items comprising tax expense are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
================================================================================================================
Provision For Current Income Taxes:
Federal.......................................................... $ 72,084 $ 47,676 $ 72,633
State............................................................ 12,638 9,671 8,594
- ----------------------------------------------------------------------------------------------------------------
Total Provision For Current Income Taxes..................... 84,722 57,347 81,227
- ----------------------------------------------------------------------------------------------------------------
Provisions (Benefit) For Deferred Income Taxes, net:
Federal
Depreciation................................................... 1,490 11,344 2,671
Repair allowance............................................... 1,200 794 2,100
Removal costs.................................................. (220) 774 630
Provision for rate refund...................................... --- --- 928
Software implementation costs.................................. --- 4,840 (1,727)
Company restructuring.......................................... 22 (494) (8,250)
Pension expense................................................ 14,806 --- ---
Bond Redemption-unamortized costs.............................. 8,458 --- ---
Other.......................................................... 20 2,093 1,433
State............................................................ 3,296 2,904 4,365
- ----------------------------------------------------------------------------------------------------------------
Total Provision (Benefit) For Deferred Income Taxes, net.... 29,072 22,255 2,150
- ----------------------------------------------------------------------------------------------------------------
Deferred Investment Tax Credits, net............................... (5,150) (5,150) (5,150)
Income Taxes Relating to Other Income and Deductions............... --- 2,114 (515)
- ----------------------------------------------------------------------------------------------------------------
Total Income Tax Expense..................................... $ 108,644 $ 76,566 $ 77,712
- ----------------------------------------------------------------------------------------------------------------
Pretax Income...................................................... $274,516 $ 209,116 $ 211,044
================================================================================================================
The following schedule reconciles the statutory federal tax rate to the
effective income tax rate:
Year ended December 31 1998 1997 1996
================================================================================================================
Statutory federal tax rate......................................... 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit.............. 3.8 3.9 4.0
Tax credits, net................................................... (3.0) (4.0) (4.1)
Other, net......................................................... 3.8 1.7 1.9
- ----------------------------------------------------------------------------------------------------------------
Effective income tax rate as reported............................ 39.6% 36.6% 36.8%
================================================================================================================
The Company files consolidated income tax returns. Income taxes are
allocated to each company based on its separate taxable income or loss.
61
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, 1998, 1997 and 1996 are as follows:
(DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
Current Deferred Tax Assets:
Accrued vacation............................................. $ 5,088 $ 4,221 $ 4,171
Uncollectible accounts....................................... 1,242 1,898 1,748
Capitalization of indirect costs............................. 172 106 2,583
RAR interest................................................. 774 --- ---
Provision for Worker's Compensation claims................... 462 595 1,207
Other........................................................ 73 105 358
- ------------------------------------------------------------------------------------------------------------
Accumulated deferred tax assets.......................... $ 7,811 $ 6,925 $ 10,067
============================================================================================================
Deferred Tax Liabilities:
Accelerated depreciation and other property-related
differences................................................ $ 491,943 $ 489,739 $ 469,949
Allowance for funds used during construction................. 38,575 43,327 46,429
Income taxes recoverable through future rates................ 40,310 44,888 49,466
- ------------------------------------------------------------------------------------------------------------
Total.................................................... 570,828 577,954 565,844
- ------------------------------------------------------------------------------------------------------------
Deferred Tax Assets:
Deferred investment tax credits.............................. (21,875) (23,623) (25,372)
Income taxes refundable through future rates................. (24,547) (28,421) (32,296)
Postemployment medical and life insurance benefits........... (3,100) (4,174) (2,301)
Company pension plan......................................... (682) (16,242) (16,465)
Bond redemption-unamortized costs............................ 9,353 --- ---
Other........................................................ 1,963 (1,542) (1,394)
- ------------------------------------------------------------------------------------------------------------
Total.................................................... (38,888) (74,002) (77,828)
- ------------------------------------------------------------------------------------------------------------
Accumulated Deferred Income Tax Liabilities.................... $ 531,940 $ 503,952 $ 488,016
============================================================================================================
62
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.
There were 25,705, 28,896 and zero shares of new stock issued pursuant
to the Restricted Stock Plan during 1998, 1997 and 1996, respectively. The $0.7
million increase in 1998 in premium on capital stock as presented on the
Consolidated Statements of Capitalization, represents a gain on the issuance of
common stock pursuant to the Restricted Stock Plan. The $424.0 million decrease
in 1997 in premium on capital stock represents the gains and losses associated
with the issuance of common stock pursuant to the Restricted Stock Plan,
repurchased preferred stock and the retirement of treasury stock.
There were 10,110,846 shares of unissued common stock reserved for the
various employee and Company stock plans at December 31, 1998. 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.
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 25,705, 28,896 and 32,048 shares of common stock
during 1998, 1997 and 1996, respectively. The Company also reacquired 13,195,
14,552 and 21,076 shares in 1998, 1997 and 1996, respectively. The shares
distributed in 1996 and the shares reacquired in 1997 and 1996 were recorded as
treasury stock. The restricted stock distributed in 1998
63
vests at the end of three years. The restricted stock distributed in 1997 and
1996 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:
(THOUSANDS) 1998 1997 1996
============================================================================================================
Shares outstanding January 1................................... 80,772 80,758 80,747
Issued/reacquired under the Restricted Stock Plan, net......... 26 14 11
- ------------------------------------------------------------------------------------------------------------
Shares outstanding December 31................................. 80,798 80,772 80,758
============================================================================================================
STOCK OPTIONS
In January 1998, the Company awarded approximately 443,800 stock
options, with an exercise price of $25.9375 (adjusted for stock split). These
options vest in one-third annual installments beginning one year from the date
of grant and have a contractual life of 10 years. During 1998, 19,200 stock
options were forfeited. At December 31, 1998, 424,600 stock options were
outstanding. The remaining contractual life of these options is approximately
nine years.
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 $2.34.
The following table shows assumptions used to estimate the fair value
of options granted on January 21, 1998:
Expected life of options............................... 7 years
Risk-free interest rate................................ 5.57%
Expected volatility.................................... 15.59%
Expected dividend yield................................ 6.47%
The following table reflects pro forma earnings available for common
stock had the Company elected to adopt the fair value approach to SFAS 123:
1998 1997 1996
============================================================================================================
Earnings available for common stock:
As Reported.................................................. $ 165,139 $ 130,265 $ 131,030
Pro Forma.................................................... 164,933 130,002 130,971
============================================================================================================
Reported and pro forma earnings per share amounts are equivalent for
1996 through 1998.
5. CUMULATIVE PREFERRED STOCK OF SUBSIDIARY
On January 15, 1998, all outstanding shares of OG&E's 4% Cumulative
Preferred Stock were redeemed at the par value of $20 per share plus accrued
dividends. On January 20, 1998, all outstanding
64
shares of OG&E's Cumulative Preferred Stock, par value $100 per share, were
redeemed at the following amounts per share plus accrued dividends: 4.20%
series-$102; 4.24% series-$102.875; 4.44% series-$102; 4.80% series-$102; and
5.34% series-$101.
In February 1997, OG&E filed a registration statement for up to $50
million of grantor trust preferred securities.
OG&E's Restated Certificate of Incorporation permits the issuance of
new series of preferred stock with dividends payable other than quarterly.
6. LONG-TERM DEBT
On January 2, 1998, OG&E retired $25 million principal amount of 6.375
percent First Mortgage Bonds due January 1, 1998.
On April 15, 1998, OG&E issued $100.0 million in Senior Notes at 6.50
percent due April 15, 2028. The proceeds from the sale of this new debt were
applied to the redemption on April 21, 1998 of $12.5 million principal amount of
OG&E's 7.125 percent First Mortgage Bonds due January 1, 1999, $40.0 million
principal amount of OG&E's 7.125 percent First Mortgage Bonds due January 1,
2002 and $35.0 million principal amount of OG&E's 8.625 percent First Mortgage
Bonds due November 1, 2007 and for general corporate purposes.
The $112.5 million principal amount of OG&E's First Mortgage Bonds
retired in 1998 was the last subject to the lien of the Trust Indenture.
Therefore, no electric plant is now subject to the lien of the Trust Indenture
and the lien has been discharged.
In January 1998, EAPC issued a $5.7 million Note at 7 percent, due July
1, 2020. The proceeds from the Note were utilized by EAPC in the NOARK
acquisition. Annual payments of approximately $0.8 million (including principal
and accrued interest) begin July 1, 2004.
In June 1998, NOARK Pipeline Finance, L.L.C., a finance company
subsidiary of NOARK, issued $80.0 million principal amount of unsecured 7.15
percent Notes due July 18, 2018. These Notes are entitled to the benefits of a
guaranty issued by Enogex pursuant to which Enogex has guaranteed 40 percent
(subject to certain adjustments) of the principal, interest and premium on such
Notes. The remaining 60 percent of the principal, interest and premium on such
notes are guaranteed by Southwestern Energy Company, the parent company of
Southwestern Energy Pipeline Company. The proceeds from the sale of the Notes
were loaned by NOARK Pipeline Finance, L.L.C. to NOARK and utilized by NOARK (i)
to repay a bank revolving line of credit (approximately $29.75 million), (ii) to
repay an outstanding term loan from Enogex (approximately $48.825 million) and
(iii) for general corporate purposes. Principal payments of $1.0 million plus
accrued interest are due semi-annually.
As of December 31, 1998, Enogex long-term debt consisted of $79 million
principal amount of 7.15 percent Senior Notes due July 19, 2018, $5.7 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 Enogex long-term debt at December 31, 1998, 1997 and 1996:
65
December 31 (DOLLARS IN THOUSANDS) 1998 1997 1996
=======================================================================================================
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 ---
Series Due July 18, 2018 -- 7.15%.............................. 79,000 --- ---
Series Due July 1, 2020 -- 7.00%............................... 5,671 --- ---
- -------------------------------------------------------------------------------------------------------
Total.................................................... $234,671 $150,000 $120,000
=======================================================================================================
Maturities of the Company's long-term debt during the next five years
consist of $2 million in 1999; $169 million in 2000; $2 million in 2001; $65
million in 2002 and $2 million in 2003.
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 1998 were $183.5 million and
$114.6 million, respectively, at a weighted average interest rate of 5.75%. The
weighted average interest rates for 1997 and 1996 were 5.94% and 5.63%,
respectively. Short-term debt in the amount of $119.1 million was outstanding at
December 31, 1998. The Company has the necessary regulatory approvals to incur
up to $400 million in short-term borrowings at any one time. At December 31,
1998, the Company had in place a line of credit for up to $160 million, which
was to expire December 6, 2000. In January 1999, the Company's line of credit
was increased to $200 million and the Company entered into a $75 million credit
agreement with CIBC Oppenheimer Corp. to fund the share repurchase program. See
Note 13 of Notes to Consolidated Financial Statements for related discussion.
8. PENSION AND POSTRETIREMENT BENEFIT PLANS
During 1994, the Company restructured its operations, reducing its
workforce by approximately 24 percent. This was accomplished through a Voluntary
Early Retirement Package ("VERP") and an enhanced severance package. The VERP
included enhanced pension benefits as well as postemployment medical and life
insurance benefits.
As a result of the postemployment benefits provided in connection with
this workforce reduction, the Company incurred severance costs and certain
one-time costs computed in accordance with SFAS No. 88, "Employers' Accounting
for Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits" and SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." In response to an application
filed by the Company, the OCC directed the Company to defer the one-time costs,
which had not been offset by labor savings through December 31, 1994. The
66
remaining balance of approximately $48.9 million was amortized over 26 months,
commencing January 1, 1995.
The amortization of the deferred regulatory asset was zero, $3.7
million and $22.6 million at December 31, 1998, 1997 and 1996, respectively.
All eligible employees of the Company are covered by a non-contributory
defined benefit pension plan. Under the plan, retirement benefits are primarily
a function of both the years of service and the highest average monthly
compensation for 60 consecutive months out of the last 120 months of service.
It is the Company's policy to fund the plan on a current basis to
comply with the minimum required contributions under existing tax regulations.
The Company made contributions of $51.6 million during 1998 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:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Beginning obligations........... $(320,842) $(284,973) $(295,573) $ (94,199) $ (94,272) $(102,789)
Service cost.................... (8,272) (6,529) (6,493) (2,030) (2,144) (2,317)
Interest cost................... (21,766) (20,803) (20,909) (5,748) (6,365) (6,824)
Participant contributions....... --- --- --- (1,077) (902) (1,157)
Plan changes.................... (3,561) --- (5,308) --- --- ---
Actuarial gains (losses)........ (8,568) (32,667) 20,588 6,029 3,198 11,174
Benefits paid................... 20,345 24,130 22,722 7,931 6,286 7,641
Expenses........................ 231 --- --- --- --- ---
- --------------------------------------------------------------------------------------------------------------------
Ending obligations.............. $(342,433) $(320,842) $(284,973) $ (89,094) $ (94,199) $ (94,272)
====================================================================================================================
67
Fair value of plans' assets:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Beginning fair value............ $ 242,254 $ 222,912 $ 214,986 $ 47,130 $ 39,066 $ 23,864
Actual return on plans' assets.. 30,865 33,489 22,896 5,133 8,047 2,128
Employer contributions.......... 51,626 9,983 7,752 5,474 5,271 19,459
Participants' contributions..... --- --- --- 915 874 1,135
Benefits paid................... (20,345) (24,130) (22,722) (6,388) (6,128) (7,520)
Expenses........................ (231) --- --- --- --- ---
- --------------------------------------------------------------------------------------------------------------------
Ending fair value............... $ 304,169 $ 242,254 $ 222,912 $ 52,264 $ 47,130 $ 39,066
====================================================================================================================
Funded status of plans:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Funded status of the plans...... $ (38,264) $ (78,588) $ (62,061) $ (36,830) $ (47,069) $ (55,206)
Unrecognized net gain (loss).... 1,435 2,295 (15,254) (18,713) (13,886) (7,937)
Unrecognized prior service
benefit (cost)................ 40,448 40,047 42,986 --- --- ---
Unrecognized transition
obligation.................... (3,790) (5,053) (6,316) 38,487 41,236 43,985
- --------------------------------------------------------------------------------------------------------------------
Net balance sheet asset
(liability)................... $ (171) $ (41,299) $ (40,645) $ (17,056) $ (19,719) $ (19,158)
====================================================================================================================
68
Net Periodic Benefit Cost:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Service cost.................... $ 8,272 $ 6,529 $ 6,493 $ 2,030 $ 2,144 $ 2,317
Interest cost................... 21,766 20,803 20,909 5,748 6,365 6,824
Return on plan assets........... (21,443) (19,142) (18,742) (4,309) (3,445) (2,166)
Amortization of transition
obligation.................... (1,263) (1,263) (1,263) 2,749 2,749 2,749
Amortization of net gain
(loss)........................ --- 788 --- (2,105) (858) (2)
Net amount capitalized or
deferred...................... --- --- --- (613) (1,293) (2,157)
Amortization of unrecognized
prior service cost............ 3,159 2,939 2,939 --- --- ---
- --------------------------------------------------------------------------------------------------------------------
Net periodic benefit costs...... $ 10,491 $ 10,654 $ 10,336 $ 3,500 $ 5,662 $ 7,565
====================================================================================================================
Rate Assumptions:
====================================================================================================================
Postretirement
Pension Plan Benefit Plans
- --------------------------------------------------------------------------------------------------------------------
1998 1997 1996 1998 1997 1996
- --------------------------------------------------------------------------------------------------------------------
Discount rate..................... 6.75% 7.00% 7.75% 6.75% 7.00% 7.75%
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 7.50% 8.25% 9.00%
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 2006
====================================================================================================================
N/A - not applicable
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 $0.9 million, $1.0 million and $1.1 million at
December 31, 1998, 1997 and 1996, respectively. The effects of a one-percentage
point decrease on the aggregate of the service and interest components of the
net periodic
69
postretirement health care benefits would be decreases of approximately $0.7
million, $1.0 million and $1.0 million at December 31, 1998, 1997 and 1996,
respectively.
The effects of a one-percentage point increase on the aggregate of
accumulated postretirement benefit obligation for health care benefits would be
approximately $8.2 million, $11.4 million and $9.1 million at December 31, 1998,
1997 and 1996, 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 $6.9 million, $9.4 million and $8.5
million at December 31, 1998, 1997 and 1996, 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
conducted through Enogex and Origen. Enogex is engaged in gathering and
processing natural gas, producing natural gas liquids, transporting natural gas
through its pipelines in Oklahoma and Arkansas for various customers (including
OG&E), marketing electricity, natural gas and natural gas liquids and investing
in the drilling for and production of crude oil and natural gas. Origen is
engaged in geothermal heat pump systems and the development of new products.
Origen's results to date have not been material to the Company.
(DOLLARS IN THOUSANDS) 1998 1997 1996
============================================================================================================
Operating Information:
Operating Revenues
Electric utility........................................... $1,312,078 $1,191,691 $1,200,337
Non-utility................................................ 506,471 293,608 231,427
Intersegment revenues (A).................................. (200,812) (41,689) (44,329)
- ------------------------------------------------------------------------------------------------------------
Total.................................................... $1,617,737 $1,443,610 $1,387,435
============================================================================================================
Pre-tax Operating Income
Electric utility........................................... $ 315,798 $ 246,038 $ 247,527
Non-utility................................................ 23,659 22,412 31,919
- ------------------------------------------------------------------------------------------------------------
Total.................................................... $ 339,457 $ 268,450 $ 279,446
============================================================================================================
Income Tax Expense
Electric utility........................................... $ 105,574 $ 71,321 $ 70,177
Non-utility................................................ 3,070 3,131 8,050
- ------------------------------------------------------------------------------------------------------------
Total.................................................... $ 108,644 $ 74,452 $ 78,227
============================================================================================================
Interest Income
Electric utility........................................... $ 2,314 $ 4,531 $ 3,186
Non-utility................................................ 7,046 1,993 533
Intersegment (B)........................................... (5,799) (2,651) (1,521)
- ------------------------------------------------------------------------------------------------------------
Total.................................................... $ 3,561 $ 3,873 $ 2,198
============================================================================================================
70
Interest Expense
Electric utility........................................... $ 49,941 $ 56,546 $ 60,276
Non-utility................................................ 27,628 13,199 9,939
Intersegment (B)........................................... (5,799) (2,651) (1,521)
- ------------------------------------------------------------------------------------------------------------
Total.................................................... $ 71,770 $ 67,094 $ 68,694
============================================================================================================
Net Income
Electric utility........................................... $ 160,338 $ 120,994 $ 116,869
Non-utility................................................ 5,534 11,556 16,463
- ------------------------------------------------------------------------------------------------------------
Total.................................................... $ 165,872 $ 132,550 $ 133,332
============================================================================================================
Investment Information:
Identifiable Assets as of December 31
Electric utility........................................... $2,320,097 $2,350,782 $2,388,012
Non-utility................................................ 663,832 415,083 374,343
- ------------------------------------------------------------------------------------------------------------
Total.................................................... $2,983,929 $2,765,865 $2,762,355
============================================================================================================
Other Information:
Depreciation and amortization
Electric utility........................................... $ 116,213 $ 114,760 $ 112,232
Non-utility................................................ 33,605 27,872 23,908
- ------------------------------------------------------------------------------------------------------------
Total.................................................... $ 49,818 $ 142,632 $ 136,140
============================================================================================================
Construction Expenditures
Electric utility........................................... $ 96,678 $ 100,079 $ 94,019
Non-utility................................................ 138,553 63,492 56,155
- ------------------------------------------------------------------------------------------------------------
Total.................................................... $ 235,231 $ 163,571 $ 150,174
============================================================================================================
(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 1999 are estimated at $137 million.
OG&E acquires natural gas for boiler fuel under 67 individual
contracts, some of which contain provisions allowing the owners to require
prepayments for gas if certain minimum quantities are not taken. At December 31,
1998, 1997 and 1996, outstanding prepayments for gas, including the amounts
classified as current assets, under these contracts were approximately $15.2
million, $10.7 million and $9.9 million, respectively. OG&E may be required to
make additional prepayments in subsequent years.
71
OG&E expects to recover these prepayments as fuel costs if unable to take the
gas prior to the expiration of the contracts.
At December 31, 1998, 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:
(DOLLARS IN THOUSANDS)
1999.................... $5,130 2002.................... $ 4,841
2000.................... 5,034 2003.................... 4,745
2001.................... 4,938 2004 and beyond......... 49,412
=========
Total Minimum Lease Payments................................ $74,100
=========
Rental payments under operating leases were approximately $5.3 million
in 1998, $5.4 million in 1997 and $5.4 million in 1996.
OG&E is required to maintain the railcars it has under lease to
transport coal from Wyoming and has entered into an agreement with Railcar
Maintenance Company, a non-affiliated company, to furnish this maintenance.
OG&E had entered into an agreement with 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),
72
OG&E's obligation to pay the capacity charge is suspended. The total cost of
cogeneration payments is recoverable in rates from customers.
In January 1998, OG&E filed an application with the OCC seeking
approval to revise an existing cogeneration contract with Mid-Continent Power
Company ("MCPC"), a cogeneration plant near Pryor, Oklahoma. As part of this
transaction, the Company agreed to purchase the stock of Oklahoma Loan
Acquisition Corporation ("OLAC"), the company that owns the MCPC plant, for
approximately $25 million. OG&E obtained the required regulatory approvals from
the OCC, APSC and FERC. If the transaction was completed, the term of the
existing cogeneration contract would have been reduced by four and one-half
years, which would have reduced the amounts to be paid by OG&E, and would have
provided savings for its Oklahoma customers, of approximately $46 million as
compared to the existing cogeneration contract. Following an arbitrator's
decision that the owner of the stock of OLAC could not sell the stock of OLAC to
the Company until it had offered such stock to a third party on the same terms
as it was offered to the Company, the third party purchased the stock of OLAC
and assumed ownership of the cogeneration plant in October 1998. The effect of
this transaction is that OG&E's original contract with the cogeneration plant
remains in place.
During 1998, 1997 and 1996, OG&E made total payments to cogenerators of
approximately $226.5 million, $212.2 million and $210.0 million, of which $185.5
million, $176.2 million and $175.2 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:
1999 - $189 million, 2000 - $190 million, 2001 - $191 million, 2002 - $192
million and 2003 - $163 million.
Approximately $0.5 million of the Company's construction expenditures
budgeted for 1999 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 $41.5 million during 1999, compared to
approximately $44.6 million in 1998. 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.
73
OG&E is a party to two separate actions brought by the EPA concerning
cleanup of disposal sites for hazardous waste. OG&E was not the owner or
operator of those sites, rather OG&E, along with many others, shipped materials
to the owners or operators of the sites who failed to dispose of the materials
in an appropriate manner. Remediation at one of these sites has been completed.
OG&E's total waste disposed at the remaining site is minimal and on February 15,
1996, OG&E elected to participate in the de minimis settlement offered by EPA.
One of the other potentially responsible parties is currently contesting OG&E's
participation as a de minimis party. Regardless of the outcome of this issue,
OG&E believes its ultimate liability for this site is minimal.
On October 22, 1998, Enogex entered into an option agreement with
certain cancellation provisions to purchase two gas turbine generators for use
in normal operations for approximately $26.3 million. Absent cancellation, the
balance is due upon receipt of the generators in 1999.
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
judgement 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 the portions of the judgement could be duplicative, that the
antitrust amounts could be tripled and that parties should address these issues
in their post-trial motions. 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
On February 11, 1997, the OCC issued an order that, among other things,
effectively lowered OG&E's rates to its Oklahoma retail customers by $50 million
annually (based on a test year ended December 31, 1995). The OCC order also
directed OG&E to transition to competitive bidding of its gas transportation
requirements currently met by Enogex no later than April 30, 2000. The order
also set annual compensation for the transportation services provided by Enogex
at $41.3 million until competitively bid gas transportation begins.
As discussed in Note 8 of Notes to Consolidated Financial Statements,
during the third quarter of 1994, the Company incurred $63.4 million of costs
related to the VERP and enhanced severance package. Pending an OCC order, OG&E
deferred these costs; however, between August 1, and December 31, 1994, the
amount deferred was reduced by approximately $14.5 million. In response to an
application filed by OG&E on August 9, 1994, the OCC issued an order on October
26, 1994, that permitted the Company to amortize the December 31, 1994,
regulatory asset of $48.9 million over 26 months and reduced OG&E's electric
rates during such period by approximately $15 million annually,
74
effective January 1995. The labor savings from the VERP and severance package
substantially offset the amortization of the regulatory asset and annual rate
reduction of $15 million.
On June 18, 1996, the APSC staff and OG&E filed a Joint Stipulation
recommending settlement of certain issues resulting from the APSC review of the
amounts that OG&E pays Enogex and recovers through its fuel clause or other
tariffs for transporting natural gas to OG&E's gas-fired generating stations. On
July 11, 1996, the APSC issued an order that, among other things, required OG&E
to refund approximately $4.5 million in 1996 to its Arkansas retail electric
customers. The $4.5 million refund related to the disallowance of a portion of
the fees paid by OG&E to Enogex for such transportation services and was
recorded as a provision for a potential refund prior to August 1996.
On February 13, 1998, the APSC Staff filed a motion for a show cause
order to review OG&E's electric rates in the State of Arkansas. The staff is
recommending a $3.1 million annual rate reduction (based on a test year ended
December 31, 1996). OG&E filed a cost of service study and has requested a $1.7
million annual rate increase. A decision on this rate case is expected in the
next few months.
12. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of Long-Term Debt and Preferred Stock is estimated based
on quoted market prices and management's estimate of current rates available for
similar issues. The fair value of the Enogex Notes is based on management's
estimate of current rates available for similar issues with the same remaining
maturities.
Indicated below are the carrying amounts and estimated fair values of
the Company's financial instruments as of December 31:
1998 1997 1996
------------------- ------------------- ------------------
CARRYING FAIR Carrying Fair Carrying Fair
(DOLLARS IN THOUSANDS) AMOUNT VALUE Amount Value Amount Value
======================================================================================================================
Long-Term Debt and Preferred Stock:
Senior Notes........................ $567,512 $593,313 $581,524 $594,357 $644,881 $656,362
Industrial Authority Bonds.......... 135,400 135,400 135,400 135,400 79,400 79,400
Enogex Inc. Notes................... 232,671 251,505 150,000 152,915 120,000 120,379
Preferred Stock:
4% - 5.34% Series - zero,
827,828 and 831,363 shares,
respectively...................... --- --- 49,266 49,997 49,379 35,829
======================================================================================================================
13. SUBSEQUENT EVENTS
On January 15, 1999, the Company repurchased 3 million of its common
shares under an Advanced Share Repurchase Agreement with CIBC Oppenheimer Corp.
The Company acquired the 3 million shares from CIBC Oppenheimer Corp. in a $80.4
million transaction, or $26.8125 per share, the closing price on January 15,
1999. The Company immediately retired the 3 million shares in accordance with a
plan announced in 1998 to repurchase up to 6 million shares over the next two
years. The
75
buyback, when completed, will reduce the Company's total shares outstanding by
approximately 7.4 percent, to 74.7 million shares from 80.7 million shares. All
repurchased shares will be retired.
Under the terms of the Advanced Share Repurchase Program, the Company
will bear the risk of increases and the benefit of decreases in the price of the
common shares until CIBC Oppenheimer Corp. has replaced the shares sold to the
Company. CIBC Oppenheimer Corp. may replace the shares through purchases on the
open market or through privately negotiated transactions. The Company may elect
to settle its obligations under this arrangement with either cash or shares of
its common stock.
In January 1999, the Company increased its agreement for a line of
credit from $160 million to $200 million.
76
Report of Independent Public Accountants
- ----------------------------------------
TO THE SHAREOWNERS OF
OGE ENERGY CORP.:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of OGE Energy Corp. (an Oklahoma corporation),
formerly Oklahoma Gas & Electric Company, and its subsidiaries as of December
31, 1998, 1997 and 1996, and the related consolidated statements of income,
retained earnings and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of OGE Energy Corp. and
its subsidiaries as of December 31, 1998, 1997 and 1996, and the results of
their operations and their cash flows for the years then ended in conformity
with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 21, 1999
77
Report of Management
- --------------------
TO OUR SHAREOWNERS:
The management of OGE Energy Corp. and its subsidiaries has prepared,
and is responsible for the integrity and objectivity of the financial and
operating information contained in this Annual Report. The consolidated
financial statements have been prepared in accordance with generally accepted
accounting principles and include certain amounts that are based on the best
estimates and judgments of management.
To meet its responsibility for the reliability of the consolidated
financial statements and related financial data, the Company's management has
established and maintains an internal control structure. This structure provides
management with reasonable assurance in a cost-effective manner that, among
other things, assets are properly safeguarded and transactions are executed and
recorded in accordance with its authorizations so as to permit preparation of
financial statements in accordance with generally accepted accounting
principles. The Company's internal auditors assess the effectiveness of this
internal control structure and recommend possible improvements thereto on an
ongoing basis.
The Company maintains high standards in selecting, training and
developing its members. This, combined with Company policies and procedures,
provides reasonable assurance that operations are conducted in conformity with
applicable laws and with its commitment to the highest standards of business
conduct.
/s/ Steven E. Moore /s/ James R. Hatfield
Steven E. Moore James R. Hatfield
Chairman of the Board, President Vice President and Treasurer
and Chief Executive Officer
78
Supplementary Data
- ------------------
Interim Consolidated Financial Information (Unaudited)
In the opinion of the Company, the following quarterly information
includes all adjustments, consisting of normal recurring adjustments, necessary
for a fair statement of the results of operations for such periods:
Quarter ended (DOLLARS IN THOUSANDS EXCEPT Dec 31 Sep 30 Jun 30 Mar 31
PER SHARE DATA)
=============================================================================================================
Operating revenues............................. 1998 $ 361,750 $ 555,999 $ 412,621 $ 287,367
1997 344,580 474,587 333,228 291,215
1996 311,515 449,224 348,644 278,052
=============================================================================================================
Operating income............................... 1998 $ 25,147 $ 126,602 $ 64,660 $ 14,404
1997 26,680 103,268 48,049 16,001
1996 23,227 107,152 53,623 17,217
=============================================================================================================
Net income (loss).............................. 1998 $ 10,230 $ 108,117 $ 47,865 $ (340)
1997 12,205 89,520 31,085 (260)
1996 7,301 90,165 35,328 538
=============================================================================================================
Earnings (loss) available for common........... 1998 $ 10,230 $ 108,117 $ 47,865 $ (1,073)
1997 11,634 88,949 30,513 (831)
1996 6,729 89,593 34,749 (41)
=============================================================================================================
Earnings (loss) per average common share....... 1998 $ 0.13 $ 1.34 $ 0.59 $ (0.01)
1997 0.14 1.10 0.38 (0.01)
1996 0.08 1.11 0.43 0.00
=============================================================================================================
79
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 29, 1999. 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, 1998, 1997 and 1996
o Consolidated Statements of Income for the years ended December 31,1998,
1997 and 1996
o Consolidated Statements of Retained Earnings for the years ended
December 31, 1998, 1997 and 1996
o Consolidated Statements of Capitalization at December 31, 1998, 1997
and 1996
o Consolidated Statements of Cash Flows for the years ended December 31,
1998, 1997 and 1996
o Notes to Consolidated Financial Statements
o Report of Independent Public Accountants
o Report of Management
80
Supplementary Data
------------------
o Interim Consolidated Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE
- ----------------------------------------------------- ----
Schedule II - Valuation and Qualifying Accounts 85
Report of Independent Public Accountants 86
Financial Data Schedule 120
All other schedules have been omitted since the required information is
not applicable or is not material, or because the information required is
included in the respective financial statements or notes thereto.
3. EXHIBITS
- -----------
EXHIBIT NO. DESCRIPTION
- ---------- -----------
3.01 Copy of Restated Certificate of Incorporation. (Filed as Exhibit
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)
81
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 Amended and Restated Stock Equivalent and Deferred
Compensation Plan for Directors, as amended. (Filed as Exhibit
10.08 to OGE Energy's Form 10-K for the year ended December
31, 1996 (File No. 1-12579) and incorporated by reference
herein)
10.07 Company's Stock Incentive Plan.
82
10.08 Agreement and Plan of Reorganization, dated May 14, 1986,
between OG&E and Mustang Fuel Corporation. (Attached as
Appendix A to Registration Statement No. 33-7472 and
incorporated by reference herein)
10.09 OG&E's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.10 Company's Restoration of Retirement Savings Plan, as amended.
(Filed as Exhibit 10.13 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.11 OG&E's Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.12 Company's Annual Incentive Compensation Plan.
21.01 Subsidiaries of the Registrant.
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995.
99.02 Description of Common Stock.
83
Executive Compensation Plans and Arrangements
---------------------------------------------
10.05 Form of Change of Control Agreement for Officers of the
Company and OG&E. (Filed as Exhibit 10.07 to OGE Energy's Form
10-K for the year ended December 31, 1996 (File No. 1-12579)
and incorporated by reference herein)
10.06 Amended and Restated Stock Equivalent and Deferred
Compensation Plan for Directors, as amended. (Filed as Exhibit
10.08 to OGE Energy's Form 10-K for the year ended December
31, 1996 (File No. 1-12579) and incorporated by reference
herein)
10.07 Company's Stock Incentive Plan.
10.09 OG&E's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.10 Company's Restoration of Retirement Savings Plan, as amended.
(Filed as Exhibit 10.13 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.11 OG&E's Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.12 Company's Annual Incentive Compensation Plan.
(B) REPORTS ON FORM 8-K
- ------------------------
Item 5. Other Events, dated January 6, 1998.
Item 5. Other Events, dated May 21, 1998.
Item 7. Exhibits, dated May 21, 1998.
Item 5. Other Events, dated June 12, 1998.
Item 5. Other Events, dated November 20, 1998.
Item 7. Exhibits, dated November 20, 1998.
Item 5. Other Events, dated December 28, 1998.
Item 7. Exhibits, dated December 28, 1998.
84
OGE ENERGY CORP.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
BALANCE CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS YEAR
- ----------- --------- --------------------------- ---------- --------
1998 (THOUSANDS)
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
1996
Reserve for Uncollectible Accounts $ 4,205 $ 7,720 - $ 7,299 $ 4,626
85
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To OGE Energy Corp.:
We have audited in accordance with generally accepted auditing
standards, the consolidated financial statements of OGE Energy Corp. (an
Oklahoma Corporation), formerly Oklahoma Gas & Electric Company, and its
subsidiaries included in this Form 10-K, and have issued our report thereon
dated January 21, 1999. Our audits were made for the purpose of forming an
opinion on those statements taken as a whole. The schedule listed on Page 81
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 21, 1999
86
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 26th day of March, 1999.
OGE ENERGY CORP.
(REGISTRANT)
/s/ Steven E. Moore
By Steven E. Moore
Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this Report has been signed below by the following persons in the
capacities and on the dates indicated.
Signature Title Date
- ----------------------------- ----------------------- --------------
/ s / Steven E. Moore
Steven E. Moore Principal Executive
Officer and Director; March 26, 1999
/ s / James R. Hatfield
James R. Hatfield Principal Financial
Officer. March 26, 1999
/ s / Donald R. Rowlett
Donald R. Rowlett Principal Accounting
Officer. March 26, 1999
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 26, 1999
87
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
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)
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)
88
10.03 Second Amendment dated March 1, 1978, to Coal Supply Agreement
dated March 1, 1973, between OG&E and Atlantic Richfield
Company. (Filed as Exhibit 5.28 to Registration Statement No.
2-62208 and incorporated by reference herein)
10.04 Amendment dated June 27, 1990, between OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between OG&E and Atlantic
Richfield Company. (Filed as Exhibit 10.04 to
OG&E's Form 10-K Report for the year ended
December 31, 1994, File No. 1-1097, and incorporated
by reference herein) [Confidential Treatment has been
requested for certain portions of this exhibit.]
10.05 Form of Change of Control Agreement for Officers of the
Company and OG&E. (Filed as Exhibit 10.07 to OGE Energy's Form
10-K for the year ended December 31, 1996 (File No. 1-12579)
and incorporated by reference herein)
10.06 Amended and Restated Stock Equivalent and Deferred
Compensation Plan for Directors, as amended. (Filed as Exhibit
10.08 to OGE Energy's Form 10-K for the year ended December
31, 1996 (File No. 1-12579) and incorporated by reference
herein)
10.07 Company's Stock Incentive Plan.
10.09 OG&E's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.10 Company's Restoration of Retirement Savings Plan, as amended.
(Filed as Exhibit 10.13 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.11 OG&E's Supplemental Executive Retirement Plan, as amended.
(Filed as Exhibit 10.15 to OGE Energy's Form 10-K for the year
ended December 31, 1996 (File No. 1-12579) and incorporated by
reference herein)
10.12 Company's Annual Incentive Compensation Plan.
21.01 Subsidiaries of the Registrant.
89
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995
99.02 Description of Common Stock.
90