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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, 1993 Commission File Number 1-1097
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma 73-0382390
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
101 North Robinson
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 405-272-3000
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
Common Stock Pacific Stock Exchange
Preferred Stock 4% Cumulative New York Stock Exchange
First Mortgage Bonds, Series due 1995 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. X
-----
As of February 28, 1994, Common Shares outstanding were 40,346,477.
Based upon the closing price on the New York Stock Exchange on February 28,
1994, the aggregate market value of the voting stock held by nonaffiliates of
the Company was: Common Stock $1,410,647,749 and 4% Cumulative Preferred
Stock $5,241,753.
The proxy statement for the 1994 annual meeting of shareowners is
incorporated by reference into Part III of this Report.
PAGE>
TABLE OF CONTENTS
Item Page
---- ----
Part I
1. Business 1
The Company 1
Electric Operations: 2
General 2
Finance and Construction 5
Regulation and Rates 6
Rate Structure, Load Growth
and Related Matters 9
Fuel Supply 11
Environmental Matters 13
Enogex 14
2. Properties 18
3. Legal Proceedings 19
4. Submission of Matters to a Vote of Security Holders 27
Executive Officers of the Registrant 28
Part II
5. Market for Registrant's Common Equity and Related
Stockholder Matters 30
6. Selected Financial Data 31
7. Management's Discussion and Analysis of Results of
Operations and Financial Condition 32
8. Financial Statements and Supplementary Data 39
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 66
Part III
10. Directors and Executive Officers of the Registrant 67
11. Executive Compensation 67
12. Security Ownership of Certain Beneficial Owners
and Management 67
13. Certain Relationships and Related Transactions 67
Part IV
14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K 67
Signatures 81
1
Part I
Item 1. Business.
------------------
THE COMPANY
Oklahoma Gas and Electric Company ("OG&E") is a regulated
public utility engaged in the generation, transmission and
distribution of electricity to retail and wholesale customers.
Enogex Inc., a wholly-owned subsidiary of OG&E, and Enogex Inc.'s
subsidiaries (collectively, "Enogex") are engaged in non-utility
businesses, consisting of diverse natural gas activities. OG&E
and Enogex are herein referred to collectively as the "Company."
Financial information on the Company's two segments of business
is included in Note 8 of the Notes to Consolidated Financial
Statements.
OG&E, incorporated in 1902 under the laws of the Oklahoma
Territory, 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 5,637,300
kilowatts. Enogex owns and operates over 3,000 miles of natural
gas transmission and gathering pipelines, has interests in six
gas processing plants, markets natural gas and natural gas
products and invests in the exploration and production of natural
gas. At the end of 1993, Enogex had 361 members and OG&E had
3,408 members working in three operating regions and in a
corporate headquarters organization. OG&E's executive offices
are located at 101 North Robinson, P.O. Box 321, Oklahoma City,
Oklahoma 73101-0321; telephone (405) 272-3000.
OG&E's electric rates have been under review for the past
three years by the Oklahoma Corporation Commission ("OCC"). On
February 25, 1994, the OCC issued an order directing OG&E to
reduce its electric rates to its Oklahoma retail customers
prospectively by approximately $14 million annually (based on a
test year ended June 30, 1991) and to refund approximately $41.3
million. The $14 million annual reduction in rates is expected
to lower OG&E's rates to its Oklahoma customers by approximately
$17 million in 1994. Due to the rate order and the ever-
increasing competition in the utility industry, OG&E has
commenced a complete review and redesign of its operations that
could result in downsizing, debt refinancing or other cost-
cutting measures. As a part of this redesign, OG&E anticipates
offering an early retirement program. OG&E also froze salaries
and hiring in February 1994. These actions are intended to offset
some of the impact of the recent rate order and to make OG&E more
competitive in the years ahead. See "Regulation and Rates" for a
further discussion of the rate order.
2
ELECTRIC OPERATIONS
GENERAL
OG&E furnishes retail electric service in 270 communities
and their contiguous rural and suburban areas. During 1993, 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 1.4 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 276 communities served, 247 are located in Oklahoma and 29
in Arkansas. Approximately 91 percent of total electric
operating revenues for the year ended December 31, 1993, 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 5,010 megawatts,
and occurred on August 16, 1993. Excluding wheeling, the net on
system peak demand was about 4,700 megawatts. However, when firm
sales were included, total load responsibility was approximately
4,740 megawatts, resulting in a capacity margin of approximately
22 percent. As reflected in the table below and the operating
statistics on page 4, kilowatt-hour sales to OG&E customers
("system sales") increased 5.0 percent in 1993 compared to 1992.
This increase in system sales was offset by a 25 percent decline
in sales to other utilities ("off-system sales") which caused
total kilowatt-hour sales to be down by 0.3 percent for 1993.
However, off-system sales are at much lower prices per kilowatt-
hour and have less impact on operating revenues and income than
system sales. In 1992 and 1991, factors which resulted in an
overall increase in total kilowatt-hour sales included:
significant increases in off-system sales; increased total
customer usage in 1992 and 1991, which was offset by decreased
residential usage in 1992; and slight increases in customer
growth. Variations in kilowatt-hour sales for the three years
are reflected in the following table:
KWH SALES (millions)
Inc/ Inc/ Inc/
1993 (Dec) 1992 (Dec) 1991 (Dec)
---------------------------------------------------------
System Sales 20,202 5.0% 19,237 (1.5%) 19,527 1.1%
Off-System Sales 3,104 (25.0%) 4,141 62.1% 2,555 130.2%
------ ------ ------
Total Sales 23,306 (0.3%) 23,378 5.9% 22,082 8.1%
====== ====== ======
OG&E is subject to competition in some areas from
government-owned electric systems, municipally-owned electric
systems, rural electric cooperatives and, in certain respects,
from other private utilities and cogenerators. Oklahoma law
forbids the granting of an exclusive franchise to a utility for
providing electricity.
3
Besides competition from other suppliers 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. The
National Energy Policy Act of 1992 has increased competition in
the wholesale market for electricity. Although management
believes competitive pressures will continue to increase, it
cannot predict the precise extent to which OG&E's business may be
affected in the future by the supply, relative cost or promotion
of other forms of energy, or by other suppliers of electricity.
See "Regulation and Rates, National Energy Legislation" for
further discussion.
Electric and magnetic fields ("EMF") surround electric wires
or conductors of electricity such as electrical tools, household
wiring and appliances and high voltage electric transmission
lines such as those owned by OG&E. Some recent studies have
pointed to a possible correlation between EMF and health effects,
including various forms of cancer, while others have found no
correlation. The nation's electric utilities, including OG&E,
have participated with the Electric Power Research Institute in
the sponsorship of more than $75 million in research to determine
the possible effects of EMF. Beginning in fiscal year 1994, and
in association with the National Energy Policy Act of 1992,
Edison Electric Institute members will help fund $65 million for
EMF studies over the next five years. One half of this amount
will 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 Electric
Power Research Institute and the Edison Electric Institute, OG&E
will continue its investigation and research with regard to
possible health effects posed by exposure to electric and
magnetic fields.
4
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
Year Ended December 31
1993 1992 1991
- -----------------------------------------------------------------------------
ELECTRIC ENERGY:
(Millions of kWh)
Generation (exclusive of
station use) . . . . . . . . . . 21,789 21,960 20,616
Purchased . . . . . . . . . . . . 3,169 2,724 2,804
- -----------------------------------------------------------------------------
Total generated and purchased . 24,958 24,684 23,420
Company use, free service and
losses . . . . . . . . . . . . . (1,652) (1,306) (1,338)
- -----------------------------------------------------------------------------
Electric energy sold. . . . . . 23,306 23,378 22,082
=============================================================================
ELECTRIC ENERGY SOLD:
(Millions of kWh)
Residential . . . . . . . . . . . 6,631 5,980 6,433
Commercial and industrial. . . . . 10,595 10,341 10,182
Public street and highway lighting 64 63 62
Other sales to public authorities. 1,966 1,932 1,916
Sales for resale . . . . . . . . . 4,050 5,062 3,489
- -----------------------------------------------------------------------------
Total. . . . . . . . . . . . . 23,306 23,378 22,082
=============================================================================
OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential . . . . . . . . . . $ 488,921 $ 436,984 $ 459,881
Commercial and industrial. . . . 582,733 550,738 544,896
Public street and highway
lighting. . . . . . . . . . . . 9,433 9,134 8,984
Other sales to public
authorities. . . . . . . . . . 107,035 101,434 100,279
Sales for resale . . . . . . . . 89,945 95,529 78,842
Provision for rate refund. . . . (14,963) (18,000) -
Miscellaneous. . . . . . . . . . 19,712 18,174 17,844
- -----------------------------------------------------------------------------
Total Electric Revenues . . . . 1,282,816 1,193,993 1,210,726
Non-utility subsidiary . . . . . 164,436 120,991 104,044
- -----------------------------------------------------------------------------
Total . . . . . . . . . . . . $1,447,252 $1,314,984 $1,314,770
=============================================================================
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential . . . . . . . . . . . 568,780 563,261 557,438
Commercial and industrial . . . . 79,572 78,799 78,160
Public street and highway
lighting . . . . . . . . . . . . 248 248 247
Other sales to public authorities. 10,074 9,842 10,075
Sales for resale . . . . . . . . . 39 37 35
- -----------------------------------------------------------------------------
Total . . . . . . . . . . . . 658,713 652,187 645,955
=============================================================================
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (kWh) . . . . . 11,688 10,664 11,587
Average annual revenue . . . . . . $ 861.72 $ 779.21 $ 828.26
Average price per kWh (cents) . . 7.37 7.31 7.15
5
FINANCE AND CONSTRUCTION
Management expects that internally generated funds and short-
term borrowings will be adequate over the next three years to
meet the Company's capital requirements and to refund the $41.3
million ordered by the OCC in 1994. The primary capital require-
ments for 1994 through 1996 are estimated as follows:
(dollars in millions) 1994 1995 1996
----------------------------------------------------------------
Consolidated construction
expenditures including AFUDC ........... $143 $116 $118
Maturities of long-term debt and
sinking fund requirements .............. - 85 -
---- ---- ----
Total ............................... $143 $201 $118
================================================================
The three-year estimate includes construction expenditures for
rebuilding electric transmission lines, for upgrading electric
distribution systems, to replace or expand existing facilities in
both its electric and non-utility businesses, and to some extent,
for satisfying maturing debt and sinking fund obligations.
Approximately $6.9 million of the Company's construction
expenditures budgeted for 1994 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 a minimum capacity margin of
15.25 percent as stipulated by the Southwest Power Pool. See
"Rate Structure, Load Growth and Related Matters."
OG&E's ability to sell additional securities on satisfactory
terms to meet its capital needs is dependent upon numerous
factors, including general market conditions for utility
securities, which will impact OG&E's ability to meet earnings
tests for the issuance of additional first mortgage bonds and
preferred stock. Based on earnings for the twelve months ended
December 31, 1993, and assuming an annual interest rate of 7.6
percent, OG&E could issue approximately $870 million in principal
amount of additional first mortgage bonds under the earnings test
contained in OG&E's Trust Indenture (assuming adequate property
additions were available). Under the earnings test contained in
OG&E's Restated Certificate of Incorporation and assuming none of
the foregoing first mortgage bonds are issued, about $800 million
of additional preferred stock at an assumed annual dividend rate
of 8.0 percent could be issued as of December 31, 1993.
The Company will continue to use short-term borrowings to
meet temporary cash requirements. The Company has the necessary
regulatory approvals to incur up to $300 million in short-term
borrowings at any one time. The maximum amount of outstanding
short-term borrowings during 1993 was $136.6 million.
6
As described below, OG&E intends to meet its customers'
increased electricity needs during the foreseeable future by
maintaining the reliability and increasing the utilization of
existing capacity and increasing demand-side management efforts.
OG&E is not currently constructing any new base-load generating
plants and does not anticipate the need for another base-load
plant in the foreseeable future.
As part of its Integrated Resource Plan ("IRP") for
supplying energy through the next decade and beyond, OG&E is
evaluating measures to keep its existing generating plants
operating efficiently well past their traditional retirement
dates. As long as the cost to keep existing plants operating
reliably and efficiently is less than the cost of alternative
sources of capacity, existing plants will be operated.
OG&E entered into an agreement with Conoco, Inc. to provide
on-site cogeneration and supply steam to the Conoco Refinery in
Ponca City, Oklahoma. This facility became operational in 1991.
In accordance with the requirements of the Public Utility
Regulatory Policies Act of 1978 ("PURPA") (see "Regulation and
Rates, National Energy Legislation"), OG&E is obligated to
purchase 110 megawatts of capacity annually from Smith
Cogeneration, Inc. and 320 megawatts annually from Applied Energy
Services, Inc. ("AES"), another cogenerator. In 1986, a contract
was signed with Sparks Regional Medical Center to purchase energy
generated by its nominal seven megawatt cogeneration facility and
not needed by the hospital. In 1987, OG&E signed a contract to
purchase up to 100 megawatts of capacity from Mid-Continent Power
Company, Inc., beginning no later than 1998. This purchase of
capacity is currently planned to begin in 1998 and carries no
obligation on the part of OG&E to purchase energy. The purchases
under each of these cogeneration contracts were approved by the
appropriate regulatory commissions at rates set in accordance
with PURPA.
OG&E's financial results depend to a large extent upon the
tariffs it charges customers and the actions of the regulatory
bodies that set those tariffs, the amount of customer energy
usage, the cost and availability of external financing and the
cost of conforming to government regulations.
REGULATION AND RATES
OG&E's retail electric tariffs in Oklahoma are regulated by
the OCC, and in Arkansas are regulated by the Arkansas Public
Service Commission ("APSC"). The issuance of certain securities
by OG&E is also regulated by the OCC and the APSC. OG&E's
wholesale electric tariffs, short-term borrowing authorization
and accounting practices are subject to the jurisdiction of the
Federal Energy Regulatory Commission ("FERC"). The Secretary of
the Department of Energy has jurisdiction over some of OG&E's
facilities and operations.
7
For the year ended December 31, 1993, approximately 85
percent of OG&E's electric revenue was subject to the
jurisdiction of the OCC, eight percent to the APSC, and seven
percent to the FERC.
Recent Regulatory Matters: On February 25, 1994, the OCC
issued an order that, among other things, required OG&E to lower
its rates to its Oklahoma retail customers by approximately $14
million annually (based on a test year ended June 30, 1991) and
to refund approximately $41.3 million. The $14 million annual
reduction in rates is expected to lower OG&E's rates to its
Oklahoma customers by approximately $17 million in 1994. With
respect to the $41.3 million refund, $39.1 million is associated
with revenues prior to January 1, 1994, while the remaining $2.2
million relates to 1994.
During the first half of 1992 the Company participated in
settlement negotiations and offered a proposed refund and a
reduction in rates in an effort to reach settlement and conclude
the proceedings. As a result, the Company recorded an $18
million provision for a potential refund in 1992. After
receiving the February 25, 1994 order, the Company recorded an
additional provision for rate refund of approximately $21.1
million in 1993 (consisting of a $14.9 million reduction in
revenue and $6.2 million in interest), which reduced net income
by approximately $13 million or $0.32 per share.
Enogex transports natural gas to OG&E for use at its gas-
fired generating units and performs related gas gathering
activities for OG&E. The entire $41.3 million refund related to
the OCC's disallowance of a portion of the fees paid by OG&E to
Enogex for such services in the past. Of the approximately $17
million annual rate reduction, approximately $9.9 million
reflects the OCC's reduction of the amount to be recovered by
OG&E from its Oklahoma customers for the future performance of
such services by Enogex for OG&E.
In accordance with the OCC's rate order and a stipulation
approved by the OCC in July 1991, OG&E's electric rates for 1994
are designed to permit OG&E to earn a 12 percent return on equity
and the OCC staff is precluded from initiating an investigation
of OG&E's rates for three years from February 25, 1994, unless
OG&E's return on equity exceeds 12.75 percent. As explained
previously, OG&E has commenced a complete review and redesign of
its operations that could result in downsizing, debt refinancing
or other cost-cutting measures in response to the rate order
and the ever-increasing competition in the utility industry.
As a part of this redesign, OG&E anticipates offering an early
retirement program. OG&E also froze salaries and hiring in
February 1994. These actions are intended to offset some of the
impact of the recent rate order and to make OG&E more competitive
in the years ahead.
8
Pursuant to an Order from the APSC in July 1992, OG&E and
other electric utilities serving customers in Arkansas were to
submit a 20-year Integrated Resource Plan with the APSC by March
15, 1993. Subsequently, OG&E received extensions of the filing
date to June 15, 1994. In its IRP, each utility must set forth a
thoroughly documented plan to serve its customers' electric
energy needs. The utility, in developing this approach, must use
a planning process that evaluates the full range of alternatives,
including new generating capacity, purchased power, energy
conservation and efficiency, cogeneration and renewable energy
sources, in order to provide adequate and reliable service to its
electric customers at the lowest system cost. The process shall
take into account system operation features such as diversity,
reliability, dispatchability and other factors of risk, and shall
treat customer load reduction and conservation alternatives on a
consistent and integrated basis with new power supply
alternatives.
The Company anticipates that a similar IRP process will be
initiated by the OCC.
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 passed through to OG&E's electric customers
through automatic fuel adjustment clauses. A lag of 45 to 60
days occurs between the time costs are incurred and the time such
costs are reflected in bills to retail customers. OG&E records
an accrual in the financial statements for these differences.
The automatic fuel adjustment clauses are subject to periodic
review by the OCC, the APSC and the FERC. OG&E's non-utility
subsidiary, Enogex Inc., owns and operates a pipeline business
that delivers natural gas to the generating stations of OG&E.
The OCC, the APSC and the FERC have authority to examine the
appropriateness of any transportation charges or other fees OG&E
pays Enogex, which OG&E seeks to recover through the fuel
adjustment clause or other tariffs. As indicated above, the OCC
in its rate order of February 25, 1994, disallowed $41.3 million
previously recovered by OG&E through its fuel adjustment clause
for amounts Enogex has charged OG&E for transporting natural gas
to OG&E's generating stations and reduced OG&E's future recovery
of such charges by approximately $9.9 million annually.
PURPA requires that electric utilities purchase electric
power from qualifying cogeneration facilities ("QFs"). The costs
to OG&E in connection with the Oklahoma facilities for such
purchased power are recovered from Oklahoma customers with the
approval of the OCC.
9
National Energy Legislation: The National Energy Act of
1978 imposes numerous responsibilities and requirements on OG&E.
PURPA requires electric utilities, such as OG&E, to purchase
electric power from, and sell electric power to, QFs and small
power production facilities. Generally stated, electric
utilities must purchase electric energy and production capacity
made available by QFs and small power producers 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.
In 1991, the OCC approved standby service rates to meet this
need.
The National Energy Policy Act of 1992 (the "Act") is
expected to make some significant changes in the operations of
the electric utility industry and the federal policies governing
the generation and sale of electric power. The Act, among other
things, allows the FERC to order utilities to permit access to
their electrical transmission systems and to transmit power
produced by independent power producers at transmission rates set
by the FERC. The Act also provides funds to study electric
vehicle technology, the effects of electric and magnetic fields,
and institutes a tax credit for generating electricity using
renewable energy sources. The Act also is designed to promote
competition in the development of wholesale power generation in
the electric industry. It exempts a new class of independent
power producers from regulation under the Public Utility Holding
Company Act of 1935 and allows the FERC to order wholesale
"wheeling" by public utilities to provide utility and non-utility
generators access to public utility transmission facilities. The
Act 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.
RATE STRUCTURE, LOAD GROWTH
AND RELATED MATTERS
Two of OG&E's primary goals in its electric tariff designs
are: (i) to increase electric revenues by attracting and holding
job-producing businesses and industries; and (ii) to keep its
peak demand growth rate one-half of one percent less than the
kilowatt-hour growth rate annually, while providing a minimum
capacity margin of 15.25 percent. In order to meet these goals,
10
OG&E has implemented numerous demand-side management programs and
tariff schedules. These programs and schedules include: (i)
residential energy audits promoting efficient energy use, and
assistance programs that help residential customers live in
comfortable homes with lower energy costs; (ii) the PEAKS
program, which provides credit on a customer's bill for the
installation of a device that periodically cycles off the
customer's central air conditioner during peak summer periods;
(iii) a load curtailment rate for industrial and commercial
customers who can demonstrate a load curtailment of at least 300
kilowatts; (iv) 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
afternoons to non-peak hours; and (v) a thermal energy storage
program that promotes the shifting of cooling loads to off-peak
hours.
OG&E has developed the "ReSource" program for business and
industry which utilizes a group of highly specialized business
consultants that have worldwide reputations and preeminence in
their particular fields. These fields include management,
finance, marketing, power quality, pricing, plant modernization,
environmental, process technologies and architect/engineers.
Depending on the scope of the project, OG&E may pay a portion of
the costs associated with these consulting services. ReSource is
designed to answer needs in any phase of a business operation,
from general business management, to leading edge technology for
a manufacturing process, to the financing necessary to make
expansion and modernization possible.
In 1993, OG&E's marketing efforts included thermal storage,
electrotechnologies, an outdoor lighting promotion "Lite-
Watchman," an electric food service promotion and a heat pump
promotion in the residential, commercial and industrial markets.
Educating customers to use available time-of-use rates to lower
their energy costs was also pursued. These rates can make
commercial and industrial heating and cooling especially
economical if power is used with thermal storage systems which
chill water at night for cooling the next day.
To meet customers' electric power needs for their sensitive
electronic equipment, OG&E began the Power Quality program
several years ago. Through this program, a trained Power Quality
team works with the customer by performing a thorough survey of
wiring and grounding, transient surge protection checks and power
monitoring. The customer and the team then develop solutions and
alternatives to power needs at the facility.
OG&E continues studying other programs to keep its electric
tariffs attractive and to control peak demand growth. These
programs include the use of high efficiency lighting and
ballasts, high efficiency motors, high efficiency air
conditioners or chillers, direct load control of large customers,
use of home automation systems, high-tech refrigeration
11
equipment, adjustable speed drives on electric motors, high-tech
electric water heating systems, heating and cooling demand
controls and time scheduling of electric appliances, such as
water heaters. OG&E has also expanded its Positive Energy Home
finance programs for customers to include heat pump water heaters
as well as high efficiency heat pumps.
OG&E currently does not anticipate the need for new base-
load generating plants in the foreseeable future. For further
discussion, see "Finance and Construction."
FUEL SUPPLY
During 1993, approximately 30 percent of the OG&E-generated
energy was produced by natural gas-fired units and 70 percent by
coal-fired units. It is estimated that the fuel mix for 1994
through 1998 based upon expected generation for these years, will
be as follows:
1994 1995 1996 1997 1998
---- ---- ---- ---- ----
Natural Gas 22% 26% 27% 29% 31%
Coal 78% 74% 73% 71% 69%
The average cost of fuel used, by type, per million Btu
for the periods shown was as follows:
1993 1992 1991 1990 1989
----- ----- ----- ----- -----
Natural Gas $3.64 $3.48 $3.14 $3.06 $2.97
Coal $1.16 $1.18 $1.21 $1.38 $1.39
Total (Weighted Avg) $1.92 $1.88 $1.96 $2.08 $2.11
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 "Regulation and Rates, Automatic Fuel
Adjustment Clauses."
OG&E is continuing its program to improve the heat rate in
all of its power plants and has implemented changes which have
resulted in greater fuel efficiency. The improvements result in
savings in fuel costs and OG&E has budgeted approximately $5.5
million over the next three years to further improve its heat
rate.
Gas-Fired Units: OG&E has approximately 900 natural gas
purchase contracts covering approximately 550 wells and delivery
points. These contracts cover an estimated 167 billion cubic
feet of connected reserves.
12
OG&E acquires some natural gas at the wellhead under
purchase contracts which contain provisions allowing the owners
to require prepayments for gas if certain minimum quantities are
not taken (see "Note 9 of Notes to Consolidated Financial
Statements"). At December 31, 1993, outstanding prepayments for
gas, including the amounts classified as current assets, under
these contracts were approximately $22.2 million (including $16.2
million accrued but not yet paid). A contract with Oklahoma
Natural Gas Company for additional peaking gas is in place and is
renewed yearly.
To help lower fuel cost, the Company began utilizing a new
natural gas storage facility in 1993. OG&E is now pumping gas
into the storage reservoir, which will help OG&E get greater
value out of its remaining take-or-pay gas contracts. By
diverting natural gas into storage, for the first time OG&E will
be able to use as much coal as possible to make electricity, and
pull gas from storage only to meet increases in demand. In 1994,
gas storage will give OG&E the flexibility to generate about 78
percent of its electricity with coal, the highest percentage in
OG&E's history. With coal being approximately one-third the cost
of natural gas, running coal units at full capacity is expected
to cut fuel costs for OG&E's customers by about $90 million a
year.
Coal-Fired Units: Muskogee Units 4 and 5, with 500
megawatts of capacity each, Sooner Units 1 and 2, with 505 and
510 megawatts of capacity, respectively, and Muskogee Unit 6,
with 515 megawatts of capacity, are designed to burn low-sulfur
western coal. OG&E purchases coal under a mix of long and short-
term contracts. OG&E currently has a long-term, multiple option
agreement with Atlantic Richfield Company to supply coal for
these units. The combination of all coal has an average sulfur
content of 0.4 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.
In 1993, approximately 26,600 tons of Oklahoma coal was
blended with Wyoming coal and burned in OG&E's coal-fired
generating stations. During 1993, OG&E burned a total of 9.1
million tons of coal. Based upon the average sulfur content of
Wyoming and Oklahoma coal and the average heating value of the
coal, OG&E's units have an approximate emission rate of 0.78
pounds of sulfur dioxide per million Btu. See related discussion
in "Environmental Matters."
In 1993, OG&E negotiated new rail transportation contracts
for coal beginning in 1994, which will result in lower
transportation rates.
The Wyoming coal is transported to OG&E's generating
stations, a distance of about 1,000 miles, by unit trains. In
13
1993, OG&E leased 1,523 coal cars, of which 946 were aluminum,
at an approximate annual rental cost of $4.9 million. The
efficiencies related to this newer design of high volume aluminum
body railcar have reduced, by approximately six percent, the
number of trips from Wyoming and reduced railcar maintenance
expenses.
ENVIRONMENTAL MATTERS
OG&E management believes all of its operations are in
substantial compliance with present Federal, state and local
environmental standards. It is estimated that OG&E's capital,
maintenance and other costs toward the preservation and
enhancement of environmental quality will be approximately $58
million during 1994, compared to approximately $54 million in
1993. OG&E continues to evaluate its environmental programs to
assure compliance with new and proposed environmental legislation
and regulations and to position itself in a competitive market.
The Company continues to explore options to comply with the
Clean Air Act Amendments of 1990 (CAAA). All of OG&E's coal-
fired generating units currently burn low-sulfur coal and
consequently, OG&E will not need to take any steps to comply with
the new sulfur dioxide emission limits until January 1, 2000.
However, as of December 31, 1993, the Company had expended
approximately $3.0 million (of an estimated total cost of
approximately $8.0 million) for installation of continuous
emission monitors which must be installed on 12 units by January
1, 1995. The CAAA will also regulate emissions for nitrogen
oxides and certain air toxic compounds. Although final
regulations concerning all of these issues have not been written,
additional capital expenditures may be necessary, but an estimate
of cost can not be determined at this time. The Company will
continue to examine all alternatives to comply with the CAAA as
part of its Integrated Resource Planning process. This planning
approach will assure the Company has the least cost option to
comply with the CAAA and be in a competitive position to market
its services. The Company will not be required to file its
compliance plan with the Environmental Protection Agency (the
"EPA") until January 1996.
As part of the Company's continuing effort to assure
compliance with the annual report required by the Toxic Substance
Control Act (TSCA) for 1991, a review of the report was
undertaken beginning in 1992. The EPA was notified of
discrepancies in operating practices and documentation, PCB
handling and record-keeping requirements. See "Item 3. Legal
Proceedings" for additional discussion of this matter.
14
The Company is a party to three separate actions brought by
the EPA concerning cleanup of disposal sites for hazardous waste
and is involved in three other matters with the EPA. See "Item
3. Legal Proceedings."
ENOGEX
OG&E's wholly-owned non-utility subsidiary, Enogex Inc., is
the 36th largest pipeline in the nation in terms of miles of
pipeline. Enogex Inc. is engaged in gathering and transporting
natural gas for ultimate delivery to public utilities and other
suppliers and end-users of natural gas in Oklahoma and throughout
the nation. At December 31, 1993, Enogex Inc. had five wholly-
owned subsidiaries, Enogex Products Corporation ("Products"),
Enogex Services Corporation ("Services"), Enogex Exploration
Corporation ("Exploration"), ENGL Corporation ("ENGL") and
Clinton Gas Transmission, Inc. ("Clinton"). Products owns
interests in and operates five natural gas processing plants and
markets natural gas liquids. Services and Clinton are engaged in
the marketing (buying and selling) of natural gas. Exploration
is engaged in investing in the exploration and production of oil
and natural gas and the purchase of oil and gas reserves. ENGL
operates a natural gas processing plant and markets the natural
gas liquids.
For the year ended December 31, 1993, and before elimination
of intercompany items between OG&E and Enogex, Enogex's
consolidated revenues and net income were approximately $219.4
million and $9.5 million, respectively, as indicated in the
following table:
(dollars in millions) 1993 Revenues 1993 Net Income
------------- ---------------
Enogex Inc. $ 65.1 $10.0 (a)
Products 11.9 3.0
Services 108.6 0.1
Exploration 2.0 0.2
ENGL 0.8 (0.2)
Clinton 37.0 -
Eliminations within Enogex (6.0) (b) (3.6)
------ -----
Enogex consolidated amounts $219.4 $ 9.5
====== =====
(a) Includes $3.6 million of net income from Products, Services,
Exploration, ENGL and Clinton.
(b) Consists of intercompany natural gas transmission fees of
$3.0 million and sales of natural gas products amounting to
$3.0 million.
15
Enogex's natural gas transportation business in Oklahoma
consists primarily of gathering and transporting natural gas for
OG&E, Transok, Inc. (an affiliate of another electric utility)
and on an interruptible basis, third-party-owned gas. Enogex's
system consists of over 3,000 miles of pipeline, which extends
from the Arkoma Basin in eastern Oklahoma to the Anadarko Basin
in western Oklahoma. Since 1960, Enogex has had a gas
transmission contract with OG&E under which Enogex transports
OG&E's natural gas supply on a fee basis, and assists OG&E in the
negotiation and administration of short and long-term gas
purchase contracts with producers and other suppliers. Enogex
also provides accounting services and assists in payments to
producers and suppliers under the contract. Under the gas
transmission contract, OG&E agrees to tender to Enogex and Enogex
agrees to transport, on a firm, load-following basis, all of
OG&E's natural gas requirements for boiler fuel for its seven
gas-fired electric generating stations. In 1993, Enogex
transported nearly 142 Bcf of natural gas; approximately 67 Bcf,
or about 47 percent was delivered to OG&E's electric generating
stations, which resulted in approximately 84 percent of Enogex
Inc.'s revenue of $65.1 million for 1993. See "Regulation and
Rates."
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, Arkla Energy Resources, Phillips
Seagas Pipeline, ANR Pipeline 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 FERC. 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 its system. Enogex is required to conduct this
transportation on a non-discriminatory basis, although this
transportation is subordinate to that performed for OG&E. This
decision does not increase appreciably the federal regulatory
burden on Enogex, but does give Enogex the opportunity to utilize
any unused capacity on an interruptible basis and thus increase
its transportation revenues.
The fees charged by Enogex for transporting natural gas for
OG&E and Transok, Inc. are not subject to FERC regulation, as
this service is solely intrastate. With respect to state
regulation, the fees charged by Enogex to OG&E and Transok, Inc.
16
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. See "Regulation and Rates" for a
further discussion of this matter and the OCC's ruling on the
fees paid by OG&E to Enogex.
Products has been active since 1968 in the processing of
natural gas and marketing of natural gas liquids. Products has a
50 percent interest in and operates a natural gas processing
plant near Calumet, Oklahoma, which can process 250,000 Mcf of
natural gas per day. Products also owns four other natural gas
processing plants in Oklahoma, which have, in the aggregate, the
capacity to process approximately 36,000 Mcf of natural gas per
day. ENGL owns one natural gas processing plant in Oklahoma,
which became operational in 1993, and has the capacity to process
approximately 18,000 Mcf of natural gas per day. Products'
natural gas processing plant operations consist of off-lease
extraction of liquids from natural gas that is transported
through the Enogex pipeline, while ENGL's natural gas processing
operations consists of off-lease extraction of liquids from an
unaffiliated pipeline. The raw gas stream is processed and
converted into marketable ethane, propane, butane, and natural
gasoline mix. The residue gas remaining after the liquid
products have been extracted consists primarily of methane.
Commercial grade propane is sold on the local market and the
marketing of all other natural gas liquids extracted by Products
and ENGL is handled through independent brokers. The natural gas
liquids 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, commonly referred to as Group 140.
Independent brokers continuously monitor the marketplace on
behalf of Products and ENGL and recommend the time to sell. No
transactions take place until approved by authorized personnel.
Payments are made to Products and ENGL after sale of the natural
gas liquids and the brokers retain a marketing fee from the
settlement.
In processing and marketing natural gas liquids, Products
and ENGL compete against virtually all other gas processors
selling natural gas liquids. Products and ENGL believe that 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 Products and ENGL specifically,
the volume of natural gas processed at its plants is dependent
upon the volume of natural gas transported through the pipeline
system located "behind the plants" (i.e. the Enogex pipeline for
Products and an unaffiliated pipeline for ENGL). If the volume
17
of natural gas transported by such pipeline increases "behind the
plants," then the volume of liquids extracted by Products and
ENGL should normally increase.
Services is a natural gas marketing company serving both
producers and consumers of natural gas by buying natural gas at
the wellhead and from other sources in Oklahoma and other states,
and reselling the gas to local distribution companies, utilities
other than OG&E and industrial purchasers both within and outside
Oklahoma.
Although the margin on sales by Services is relatively
small, approximately 63 percent of the natural gas purchased and
resold is transported through the Enogex Inc. pipeline to one or
more interstate pipelines that deliver the gas to markets. Thus,
in addition to purchasing and selling natural gas, Services
seeks to use the space available in the Enogex Inc. pipeline and
increase the amount of natural gas available for processing by
Products. Clinton, which was acquired in 1993, is engaged in
essentially the same business as Services.
Enogex Inc. is committed to expand the activities of
Services in order to increase the amount of natural gas
transported through the pipeline and the amount of natural gas
processed by Products.
In its marketing and transportation services for third
parties, Enogex Inc., Services and Clinton encounter competition
from other natural gas transporters and marketers and from
available alternative energy sources. The effect of competition
from alternative energy sources is dependent upon the
availability and cost of competing supply sources.
Volumes of natural gas transported by Enogex Inc. for third
parties and the revenues derived from such activities increased
from the previous year. The contributing factors for the
increase were specific projects approved to strengthen Enogex's
position, with other similar projects under consideration.
Services and Clinton compete with all major suppliers of
natural gas in the geographic markets they serve, which 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 Services, the primary
factor is the total cost (including transportation fees) that the
buyer must pay. Natural gas transported for Services by Enogex
Inc. is billed at the same rate Enogex Inc. charges for
comparable third-party transportation. Exploration was formed in
1988 primarily to engage in the production and exploration of
natural gas. Exploration has focused its drilling activity in
the state of Michigan and also has interests in Oklahoma. As of
December 31, 1993, Exploration had interests in 238 active wells.
18
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 5,637
megawatts. The following table sets forth information with
respect to present electric generating facilities:
Unit Station
Year Capability Capability
Station & Unit Fuel Installed (Megawatts) (Megawatts)
------------------------------------------------------------
Seminole 1 Gas 1971 549
2 Gas 1973 507
3 Gas 1975 500 1,556
Muskogee 3 Gas 1956 184
4 Coal 1977 500
5 Coal 1978 500
6 Coal 1984 515 1,699
Sooner 1 Coal 1979 505
2 Coal 1980 510 1,015
Horseshoe 6 Gas 1958 178
Lake 7 Gas 1963 238
8 Gas 1969 394 810
Mustang 1 Gas 1950 58 Inactive
2 Gas 1951 57 Inactive
3 Gas 1955 122
4 Gas 1959 260
5 Gas 1971 64 446
Conoco 1 Gas 1991 26
2 Gas 1991 26 52
Arbuckle 1 Gas 1953 74 Inactive
Enid 1 Gas 1965 12
2 Gas 1965 12
3 Gas 1965 12
4 Gas 1965 12 48
Woodward 1 Gas 1963 11 11
-----
Total Active Generating Capability (all stations) 5,637
=====
At December 31, 1993, OG&E's transmission system included 65
substations with a total capacity of approximately 17.2 million
kVA and approximately 4,289 structure miles of lines. The
19
distribution system included 345 substations with a total
capacity of approximately 6.1 million kVA, 25,232 structure miles
of overhead lines, 1,565 miles of underground conduit and 6,184
miles of underground conductor.
The Trust Indenture securing OG&E's first mortgage bonds
constitutes a direct first mortgage lien on substantially all of
its electric facilities.
Enogex owns: (i) over 3,000 miles of natural gas pipeline
extending from the Arkoma Basin in eastern Oklahoma to the
Anadarko Basin in western Oklahoma; (ii) a 50 percent interest
in a natural gas processing plant near Calumet, Oklahoma, which
has the capacity to process 250,000 Mcf of natural gas per day;
and (iii) five other natural gas processing plants in Oklahoma,
which have, in the aggregate, the capacity to process
approximately 54,000 Mcf of natural gas per day.
During the three years ended December 31, 1993, the
Company's gross property, plant and equipment additions
approximated $384 million and gross retirements approximated $69
million. Over 90 percent of these additions were provided by
internally generated funds. The additions during this three-year
period amounted to approximately 10.4 percent of total property,
plant and equipment at December 31, 1993.
Item 3. Legal Proceedings.
--------------------------
1. In March 1991, the Director of the Public Utility
Division of the OCC filed an application with the OCC
challenging, among other things, OG&E's retail electric rates in
Oklahoma. On February 25, 1994, the OCC issued an order that,
among other things, lowered OG&E's rates to its Oklahoma retail
customers by approximately $17 million and ordered a refund of
approximately $41.3 million, including interest. See "Regulation
and Rates" under Item 1 for a further discussion of this matter.
2. On June 30, 1986, the United States government filed
suit against OG&E and 36 other defendants in case number
CIV-86-1401 W, in the United States District Court ("USDC") for
the Western District of Oklahoma. The complaint generally
alleges that a total of 18 million gallons of hazardous and toxic
waste are contained at the Hardage Criner site located
approximately 30 miles south of Oklahoma City, and that the
government has expended, as of the date of the filing of the
complaint, $1.44 million related to the site. The 37 defendants
are divided into three classes: 33 "generator" defendants, of
which OG&E is one; three "transporter" defendants; and the owner
of the site, Mr. Royal Hardage.
It is estimated that over 200 other entities, not presently
named in the government's complaint, have also disposed of
20
materials at the site. OG&E has disposed of an estimated 130,000
gallons at the site, or less than 1 percent of the total volume
of waste. OG&E, along with each other Potentially Responsible
Party ("PRP"), could be held jointly and severally liable for the
remediation of the site. In August 1990, the USDC issued its
rulings on the appropriate method for cleanup of the site. The
USDC selected the containment remedy proposed by the Hardage
Criner Steering Committee Defendants (the "Committee"), of which
OG&E is a member, with several modifications. The remedy ordered
by the USDC is estimated to cost approximately $60 million.
However, the actual costs are heavily dependent on the nature and
volume of liquids that will be extracted from the Hardage site.
It is possible that the remedy could cost substantially more than
the current $60 million estimate.
The USDC awarded the United States all of its claimed
"indirect" costs, and all of the costs incurred by the United
States Department of Justice, a total of approximately $3.2
million. These amounts are in addition to the past response
costs of approximately $5.4 million that the USDC awarded the
United States in a pre-trial summary judgment entered on December
8, 1989. That summary judgment also granted the United States
the right to recover future costs that are "not inconsistent with
the EPA's National Contingency Plan regulations." The Committee
estimates that the United States has obtained monetary judgments
which will allow it to recover approximately $12 million.
In a related ruling on cost issues, the USDC held that the
Committee had incurred recoverable response costs in the amount
of approximately $3.7 million. It further held that the United
States was obligated to pay 8.36 percent of the Committee's
costs, or approximately $311,000.
The USDC ruled that the United States' share of the total
cleanup costs should include 8.36 percent of the costs of the
court-ordered remedy and 8.36 percent of the approximately $12
million in costs that the United States itself was awarded in the
case, except for prejudgment interest and Department of Justice
costs.
The Committee appealed the USDC's rulings on the government
receiving 100 percent of its costs and the Committee receiving
only a portion of its costs to the Tenth Circuit Court of
Appeals. The Tenth Circuit Court of Appeals has not yet issued a
ruling in this appeal.
Settlements have been reached with other parties for their
share of costs incurred. The money collected through these
settlements is being used by the Hardage Site Remedy Corporation
(which was formed to implement the USDC-ordered remedy) to finance
21
the remedy and to reimburse the government for response costs it
may ultimately be awarded in the pending appeal in the Tenth
Circuit Court.
Even though the settlement funds, plus interest and the
United States contribution will raise a substantial portion of
the monies required, any remaining amounts that OG&E and the
other Hardage Steering Committee members are likely to pay may
still be substantial. A more accurate estimate of the amount of
the remaining costs must be determined after the remedy design
is completed.
The Hardage Steering Committee members have reached an
Agreement to pay the costs based on each company's respective
volume of waste sent to the site. OG&E's share of the total is
2.33 percent.
While it is not possible to determine the precise outcome of
this matter, in the opinion of management, OG&E's ultimate
liability for the 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: (1) the cleanup costs already paid by certain
parties; (2) the financial viability of the other PRPs; and (3)
the portion of the total waste disposed at this site attributable
to OG&E. Management also believes that costs incurred in
connection with this site, which are not recovered from insurance
carriers or other parties, may be allowable costs for future
ratemaking purposes.
3. OG&E is also involved, along with numerous other PRPs,
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
brokerage 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.
OG&E, along with the other PRPs, could be held jointly and
severally liable for the remediation of the site.
In March 1986, Rose abandoned its facility in Holden,
Missouri, and subsequently notified certain Generators of its
unwillingness and/or inability to come into compliance with the
PCB rules and regulations and to properly dispose of such PCBs
22
and PCB items at the facility. In addition to PCBs and PCB items
at the Rose facility, the EPA believes that contaminated soils,
sediments and/or sludge may be present off-site.
Several Generators, including OG&E, formed a Steering
Committee to investigate and possibly clean up the Rose facility.
On October 30, 1986, OG&E, along with other Generators, entered
into a negotiated Administrative Order of Consent with the EPA
for the first phase of the work which includes: (i) conducting
an assessment to determine the location and extent of any release
or immediate threat of release of PCBs which pose or may pose any
immediate danger to human health or welfare or the environment at
the Rose facility; (ii) depending upon the results of such
assessment, taking such response actions as are necessary to
address the releases of PCBs and to eliminate the threat of
further immediate releases of PCBs; (iii) providing such action
as necessary to restrict access to and secure the Rose facility;
and (iv) determining the nature and extent of the threat to the
public health or welfare or the environment by conducting such
site surveys, samplings and analyses, inventories and data
evaluations as necessary to support and determine potential
intermediate and final response actions. Currently, OG&E
management's estimate of the total cost for cleanup of the Rose
facility is in the range of $23 to $31 million, of which $18.5
million has already been collected from certain parties.
A second Administrative Order has been entered into which
provides that the Steering Committee: (1) develop a Statement of
Work following the Toxic Substances Control Act's guidelines; (2)
perform a Remedial Investigation/Feasibility Study ("RI/FS"); (3)
be given by the EPA a Covenant Not to Sue for work at the site
under certain conditions; and (4) with the EPA's agreement, not
to sue non-participating PRPs.
A Buyout Agreement with other parties was entered into in
1988. Work is progressing under the second Administrative Order
and the RI/FS. In 1989, the Steering Committee filed suit
against certain PRPs for cleanup costs.
On September 2, 1992, the EPA, Region VII, issued an
Administrative Order ("AO") for Remedial Design and Remedial
Action pursuant to Section 106 (a) of the Comprehensive
Environmental Response Compensation and Liability Act ("CERCLA").
The AO basically requires excavation, treatment and disposal of
remaining soils and debris, dismantling of buildings and
groundwater monitoring for a minimum of 10 years. The AO
contains a provision for an opportunity to confer between the EPA
and the Steering Committee. Such conference was held and a
notice to comply was given to the EPA by the Steering Committee
coupled with its concern over the issue of access to the
property.
23
The Company estimates its share of the total hazardous
wastes at the Rose facility to be less than six percent. Due to
the present stage of this matter, the Company cannot predict its
outcome or the precise amount that it may be required to pay.
Nevertheless, management believes that OG&E's ultimate liability
for the 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: (1)
the cleanup costs already paid by certain parties; (2) the
financial viability of the other PRPs; and (3) the portion of the
total waste disposed at this site attributable to OG&E.
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.
4. Reference is made to paragraph No. 4 under Item 3 of the
Company's 1992 Form 10-K regarding the suit filed by Charles D.
"Charley" Wilson against the Directors of OG&E seeking in excess
of $2 billion in damages. On July 13, 1993, the Oklahoma Supreme
Court held that the Plaintiff's lawsuit failed to state a claim
upon which relief could be granted. The Supreme Court held that
Oklahoma does not recognize a common law fiduciary duty on behalf
of the Directors to the ratepayers of OG&E. The Supreme Court
also found that any such cause of action, if recognized, would be
preempted by the Public Utility Regulatory Policies Act of 1978
and the Federal Energy Regulatory Commission regulations under
the facts of the case. Finally, because Wilson's lawsuit was
essentially a rate refund case, the Supreme Court held that
jurisdiction rested exclusively with the Oklahoma Corporation
Commission. The Supreme Court remanded the case to the trial
court with instructions to dismiss for lack of subject matter
jurisdiction.
Wilson filed a petition for rehearing with the Oklahoma
Supreme Court and a response was filed to that petition. On
October 5, 1993, the Oklahoma Supreme Court denied Wilson's
petition for rehearing. Wilson filed petition for a Writ of
Certiorari with the Supreme Court of the United States, October
term, 1993. On February 22, 1994, the United States Supreme
Court denied certiorari in this case.
This case is now concluded in favor of the Directors and
against Wilson in all respects.
5. In July 1989, OG&E, through various media reports,
became aware of an asbestos problem at one of its former power
plants known as the Osage Plant, which had been sold to Osage
Properties, Inc. in December 1986.
Under the terms of the Real Estate Purchase Contract, Osage
Properties, Inc., was informed of the presence of friable
asbestos in the plant, with their agreement to accept all
24
liability for the friable asbestos and indemnify OG&E against any
and all claims brought against OG&E for damages and/or injuries
to property or persons resulting from the existence and/or
removal of friable asbestos material from the property.
In September 1988, Osage Properties, Inc. apparently leased
the property to ACS Laboratories, Inc. for the stated purposes of
residential living, dismantling and workshop premises. Because
OG&E had no interest in the property after December 1986, OG&E
does not know what activities took place on the property after
that date.
According to public reports and television accounts, people
were living inside the building and dismantling equipment, etc.,
apparently disturbing the encapsulated asbestos. According to
the public reports, the people did not have protective clothing
or equipment for asbestos work and were not handling and/or
disposing of the asbestos properly. Further, neither Osage Prop-
erties, Inc. nor their Lessee had the proper licensing required
for such work.
As a result, the Oklahoma State Departments of Labor and
Health have closed the site and are investigating the situation
for possible solutions. OG&E intends to cooperate with the
agencies of the State of Oklahoma in resolving this matter and,
although the amount, if any, to be expended by OG&E has not been
determined, OG&E does not believe this matter will have a
material adverse effect on its financial position or its results
of operations.
6. In 1992, OG&E began a voluntary review of information
contained in the annual report required under the Toxic Substance
Control Act ("TSCA") for 1991. The initial result of the review
revealed some discrepancies in procedures and documentation.
The EPA, Region VI, was notified of these initial
discrepancies in December 1992. Because it was suspected that
additional discrepancies might be discovered during the
continuing review/audit, OG&E reached an agreement on January 12,
1993, with the EPA, Region VI, concerning the notification and
reporting requirements of any newly discovered discrepancies.
After further investigation, OG&E reported in September 1993
numerous additional discrepancies to the EPA, Region VI. Many of
the discrepancies could be deemed violations of the regulations
under TSCA. The discrepancies principally concerned the TSCA
regulations relating to PCB handling and record keeping
requirements. However, to the Company's knowledge, none of the
activities involved releases of materials into the environment or
caused harm to any individuals. Under the TSCA regulations, the
EPA has the authority to assess a maximum fine of up to $25,000
per day, and to treat each day of violation as the basis for a
separate fine. OG&E has taken and is taking corrective action to
remedy the discrepancies.
25
The position of the EPA and OG&E is that they are currently
in pre-settlement negotiations and no fines have been assessed as
of this date. Since this matter is currently being negotiated,
OG&E does not know the amount of fines that the EPA may seek.
The amount of the fine is dependent upon numerous interpretive
issues under the TSCA regulations and potentially could be in an
amount material to the Company's results of operations. However,
at the present time, the Company does not expect that the amount
of the fine will have a material effect on its results of
operations based primarily on having voluntarily reported the
discrepancies to the EPA coupled with the Company's efforts to
remedy the discrepancies and the lack of releases into the
environment or harm to individuals.
7. 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.
The Notice Letter, a formal demand for reimbursement of past
and future incurred costs (past costs are approximately $1.3
million), provided for a negotiation period of 60 days and
encouraged the PRPs to perform or finance the response activities
as set forth in the Record of Decision ("ROD") and the Draft
Statement of Work ("SOW").
The ROD addresses the source of contamination both on and
off the site and is divided into two operable units: 1) Source
Control Operable Unit, the remedy of which is addressed with the
SOW and has an estimated cost of $6.4 million; and 2) Groundwater
Operable Unit, which is still being evaluated to assess the
extent of contamination in the groundwater and any plumes. The
cost of remediation for this Unit cannot be estimated at this
time.
As to the Source Control Operable Unit and as a result of
the EPA's Notice Letter, companies listed as PRPs (including
OG&E) held several meetings to determine whether or not they
should form a Steering Committee, whether additional research
into volumetric shares should be conducted and a response, if
any, to be sent to the EPA. Several but not all of the 46
companies have signed a very limited Participation Agreement, the
purpose of which is to negotiate with the EPA.
On March 31, 1993, OG&E joined with the signatories to the
limited Participation Agreement in making a settlement offer to
the EPA. The EPA met with representatives of the PRPs group on
June 11, 1993, to discuss the current developments taking place.
The EPA is currently considering a modification of the remedy for
the Source Control Operable Unit because the remedy was
26
apparently selected without giving consideration to the presence
of listed hazardous waste, although the presence of this waste
was documented in the Record of Decision. The EPA explained at
the meeting that it will likely not make a decision in the near
future concerning the remedy for the Source Control Operable
Unit. The EPA informed the participating PRPs that it would not
pursue them through the issuance of a unilateral administrative
order relating to the Special Notice Letters.
As to the Groundwater Operable Unit, OG&E declined to either
participate in conducting or financing any remedial activities.
No further action on the Groundwater Operable Unit has been taken
by the EPA.
On February 1, 1994, OG&E received a Section 104 Letter from
the EPA, Region VI, which asked for either participation in or
financing of a Removal Action calling for netting of 2.5 acre on-
site sludge lagoon to preclude access to wildlife. The PRP
Group, for various reasons, declined on February 10, 1994, to
participate or finance the Removal Action.
Due to the present stage of this matter, the total cost of
the cleanup of the site and the Company's ultimate liability
cannot be estimated. Nevertheless, management believes that
OG&E's ultimate liability for the 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 financial viability of the other PRPs and the portion of the
total waste disposed at this site attributable to OG&E.
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.
8. OG&E has been requested by the EPA to permit the
inspection of two separate properties owned by OG&E for possible
hazardous substances, pollutants or contaminants. These sites
were used many years ago by OG&E or certain companies acquired by
OG&E for manufacturing gas from coal. In connection with
manufacturing gas, various by-products were produced (including
coal-tar and other potentially harmful materials), which could
remain on the sites. At the present time, OG&E does not know
whether any harmful materials remain at the sites and intends to
cooperate fully with the EPA in its investigation.
9. Puritan Oil and Gas Corp., and other Plaintiffs, filed
an amendment to a petition on February 19, 1993, to an action
previously filed in the District Court of Oklahoma County,
involving an alleged breach of an oil and gas contract by OG&E.
Enogex Inc. was also joined as a Defendant in the action.
Plaintiff alleges that OG&E and Enogex were in violation of the
Federal Racket Influenced and Corrupt Organizations Act ("RICO").
The case was removed to the United States District Court for the
27
Western District of Oklahoma. Plaintiff alleges the Defendants
refused to honor contractual obligations in certain gas purchase
contracts. The underlying dispute on the gas purchase contracts
arises in the ordinary course of OG&E's business and involves
whether OG&E must purchase gas thereunder, where the contract
provides for certain requirements be maintained by the well.
Actual damages under the RICO claim are sought in an amount of
$2,000,000. RICO provides that these damages be trebled in the
event of an adverse verdict. Punitive damages under the RICO
claim are also sought in the amount of $1,000,000.
A Motion to Dismiss the RICO claim was filed by OG&E and
Enogex. On January 4, 1994, the Court dismissed the RICO claim
and remanded the breach of contract action to the state court.
Plaintiffs filed a Motion to Amend the RICO claim. It was denied
by the court. Plaintiffs filed a Notice of Appeal on March 1,
1994, to perfect an appeal of the dismissal of the RICO claims to
the Tenth Circuit Court of Appeals.
Management believes the outcome of this proceeding will not
have a material adverse effect on the Company's financial
position or its results of operations for numerous reasons, which
include punitive damages do not appear to be available to the
Plaintiffs under RICO and the underlying dispute between the
parties of a gas purchase contract. Management intends to
vigorously pursue the defense of this matter.
In the normal course of business, other lawsuits, claims,
environmental actions and other governmental proceedings may
arise against the Company. Management, after consultation with
legal counsel, does not anticipate that liabilities arising out
of such other currently pending or threatened lawsuits and claims
will have a material adverse effect on the Company's financial
position or its results of operations.
Item 4. Submission of Matters to a Vote of Security Holders.
-------------------------------------------------------------
Not applicable.
28
Executive Officers of the Registrant
The following persons were Executive Officers of the Regis-
trant as of March 15, 1994:
Name Age Title
-----------------------------------------------------------------
James G. Harlow, Jr. 59 Chairman of the Board, President
and Chief Executive Officer
Patrick J. Ryan 55 Executive Vice President and Chief
Operating Officer
Bob G. Bunce 62 Senior Vice President-Accounting
and Administration
Kenneth J. Baltes 58 Vice President and Manager Eastern
Region
H. Leon Grover 57 Vice President and Manager Western
Region
James R. Helton 51 Vice President and Manager Metro
Region
Steven E. Moore 47 Vice President-Law and Public
Affairs
Al M. Strecker 50 Vice President and Treasurer
Don L. Young 53 Controller
Irma B. Elliott 55 Secretary
No family relationship exists between any of the Executive
Officers of the Registrant. Each Officer is to hold office until
the Board of Directors meeting following the next Annual Meeting
of Shareowners, currently scheduled for May 19, 1994.
29
The business experience of each of the Executive Officers of
the Registrant for the past five years is as follows:
Name Business Experience
-----------------------------------------------------------------
James G. Harlow, Jr. 1989-Present: Chairman of the Board,
President and Chief
Executive Officer
Patrick J. Ryan 1989-Present: Executive Vice President
and Chief Operating
Officer
Bob G. Bunce 1989-Present: Senior Vice President-
Accounting and
Administration
Kenneth J. Baltes 1989-Present: Vice President and Manager
Eastern Region
H. Leon Grover 1989-Present: Vice President and Manager
Western Region
James R. Helton 1989-Present: Vice President and Manager
Metro Region
Steven E. Moore 1989-Present: Vice President-Law and
Public Affairs
Al M. Strecker 1991-Present: Vice President and
Treasurer
1989-1991: Vice President, Secretary
and Treasurer
Don L. Young 1989-Present: Controller
Irma B. Elliott 1991-Present: Secretary
1989-1991: Assistant Secretary
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 "OklaGE" 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.
1993 1992
------------------------- -------------------------
Dividend Dividend
Paid High Low Paid High Low
-------- ---- --- -------- ---- ---
First Quarter $0.66-1/2 $35-7/8 $33 $0.66-1/2 $44 $37-5/8
Second Quarter 0.66-1/2 37-5/8 33-3/4 0.66-1/2 38-7/8 30-1/8
Third Quarter 0.66-1/2 38-5/8 34 0.66-1/2 34-7/8 31
Fourth Quarter 0.66-1/2 38-3/8 32-7/8 0.66-1/2 34-3/4 32-1/8
The number of record holders of Common Stock at December 31,
1993, was 36,201. The book value of the Company's Common Stock
at December 31, 1993, was $22.48.
31
Item 6. Selected Financial Data.
--------------------------------
HISTORICAL DATA.
1993 1992 1991 1990 1989
========================================================================================================================
SELECTED FINANCIAL DATA
(dollars in thousands except
per share data)
Operating revenues. . . . . . . $ 1,447,252 $ 1,314,984 $ 1,314,770 $ 1,230,769 $ 1,141,319
Operating expenses. . . . . . . 1,252,099 1,137,980 1,103,683 1,019,510 940,766
- -------------------------------------------------------------------------------------------------------------------------
Operating income. . . . . . . . 195,153 177,004 211,087 211,259 200,553
Other income and deductions . . (1,301) (567) (471) (263) 2,477
Interest charges. . . . . . . . 79,575 76,725 76,700 71,798 73,592
- -------------------------------------------------------------------------------------------------------------------------
Net income. . . . . . . . . . . 114,277 99,712 133,916 139,198 129,438
Preferred dividend
requirements . . . . . . . . . 2,317 2,317 2,317 2,467 2,518
Earnings available for common . $ 111,960 $ 97,395 $ 131,599 $ 136,731 $ 126,920
=========================================================================================================================
Long-term debt. . . . . . . . . $ 838,660 $ 838,654 $ 853,597 $ 853,540 $ 854,319
Total assets. . . . . . . . . . $ 2,731,424 $ 2,590,083 $ 2,566,089 $ 2,522,907 $ 2,524,254
Earnings per average common
share. . . . . . . . . . . . . $ 2.78 $ 2.42 $ 3.27 $ 3.38 $ 3.05
- ----------------------------------------------------------------------------------------------------------------------
CAPITALIZATION RATIOS
Common equity . . . . . . . . . 50.51% 50.36% 50.20% 49.44% 49.03%
Cumulative preferred stock. . . 2.78% 2.79% 2.75% 2.80% 3.08%
Long-term debt. . . . . . . . . 46.71% 46.85% 47.05% 47.76% 47.89%
- -------------------------------------------------------------------------------------------------------------------------
INTEREST COVERAGES
Before federal income taxes
(including AFUDC). . . . . . . 3.32X 3.05X 3.66X 3.91X 3.56X
(excluding AFUDC). . . . . . . 3.32X 3.04X 3.63X 3.87X 3.50X
After federal income taxes
(including AFUDC). . . . . . . 2.43X 2.29X 2.70X 2.84X 2.69X
(excluding AFUDC). . . . . . . 2.42X 2.28X 2.66X 2.79X 2.63X
- -------------------------------------------------------------------------------------------------------------------------
32
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition.
-----------------------------------------------------------
Management's Discussion and Analysis.
Overview
Percent Change
From Prior Year
-----------------
(thousands except per share amounts) 1993 1992 1991 1993 1992
Operating revenues............... $1,447,252 $1,314,984 $1,314,770 10.1 -
Earnings available for common
stock.......................... $ 111,960 $ 97,395 $ 131,599 15.0 (26.0)
Average shares outstanding....... 40,328 40,310 40,298 - -
Earnings per average common
share.......................... $ 2.78 $ 2.42 $ 3.27 14.9 (26.0)
Dividends paid per share......... $ 2.66 $ 2.66 $ 2.58 - 3.1
Earnings for 1993 increased to $2.78 per share from $2.42 in
1992, despite the recent rate order of February 25, 1994, from
the Oklahoma Corporation Commission (the "Commission"). The
Commission's order requires OG&E to reduce its electric rates to
its Oklahoma retail customers prospectively by approximately $14
million annually (based on a test year ended June 30, 1991) and
to refund approximately $41.3 million. The $14 million annual
reduction in rates is expected to lower OG&E's rates to its
Oklahoma customers by approximately $17 million in 1994. With
respect to the $41.3 million refund, $2.2 million will pertain to
1994, while the balance relates to prior periods which reduced
1993 earnings by $0.32 per share. Partially offsetting the impact
of the refund for 1993 was an $18 million provision for rate
refund established by the Company in 1992, which, in turn,
reduced 1992 earnings by $0.28 per share.
Due to the rate order and the ever-increasing competition in
the utility industry, OG&E has commenced a complete review and
redesign of its operations that could result in downsizing or
other cost-cutting measures. OG&E also froze salaries and hiring
in February 1994. These actions are intended to offset some of
the impact of the recent rate order and to make OG&E more
competitive in the years ahead.
The following discussion and analysis presents factors
(including the recent rate order of the Commission) which had a
material effect on the Company's operations and financial
position during the last three years and should be read in
33
conjunction with the Consolidated Financial Statements and Notes
thereto. Trends and contingencies of a material nature are
discussed to the extent known and considered relevant.
EARNINGS
The 1993 increase in earnings was attributable almost in its
entirety to increased retail electric sales from more normal
weather in the Company's service territory, which more than
offset the $0.32 reduction in earnings for 1993 related to the
Commission's recent refund order. Earnings in 1992 were lower
than 1991 due to the $18 million provision for refund recorded in
1992 ($0.28 per share), lower electric retail sales due to
unusually mild weather and reduced subsidiary earnings.
Results of Operations
REVENUES
Percent Change
From Prior Year
-----------------
(thousands) 1993 1992 1991 1993 1992
Sales of electricity
to OG&E customers . . . . . $ 1,242,964 $ 1,149,894 $ 1,169,455 8.1 (1.7)
Provision for rate refund . (14,963) (18,000) - * *
Sales of electricity
to other utilities. . . . 54,815 62,099 41,271 (11.7) 50.5
Enogex . . . . . . . . . . 164,436 120,991 104,044 35.9 16.3
------------------------------------------------------------------
Total operating revenues . $ 1,447,252 $ 1,314,984 $ 1,314,770 10.1 -
- --------------------------------------------------------------------------------------------------
System kilowatt-hour sales. 20,201,533 19,236,843 19,526,776 5.0 (1.5)
Kilowatt-hour sales to
other utilities . . . . . 3,103,977 4,141,084 2,554,987 (25.0) 62.1
------------------------------------------------------------------
Total kilowatt-hour sales. 23,305,510 23,377,927 22,081,763 (0.3) 5.9
=================================================================================================
* Not meaningful
Approximately 89 percent of the Company's revenues consist
of regulated sales of electricity as a public utility, while the
remaining 11 percent is provided by the non-utility operations of
the Company's wholly-owned subsidiary, Enogex Inc. and its
subsidiaries (collectively "Enogex"). Enogex's primary operations
consist of transporting natural gas through its intra-state
pipeline to various customers (including OG&E), buying and
selling natural gas to third parties, selling natural gas liquids
extracted by its natural gas processing plants and investing in
exploration activities. Actions of the regulatory commissions
34
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 through
Enogex's pipeline to OG&E's generating units.
During 1993, operating revenues increased 10.1 percent to
$1.45 billion compared to $1.31 billion in 1992 and 1991.
Increased kilowatt-hour sales to OG&E customers ("system sales"),
the recovery of higher purchased power costs and increased Enogex
revenues accounted for the improvement in revenues. These
increases were only partially offset by the Commission's recent
rate order, which reduced 1993 operating revenues by
approximately $15 million. See Note 10 of Notes to Consolidated
Financial Statements for a further discussion of the Commission's
recent rate order.
A return to near normal weather and continued slight
customer growth contributed to the increase in system sales for
1993. This increase in system sales was partially offset by a
25.0 percent decrease in sales to other utilities; causing total
kilowatt-hour sales to be down by 0.3 percent for 1993. However,
sales to other utilities are at much lower prices per kilowatt-
hour and have less impact on operating revenues and income than
system sales.
Enogex's 1993 revenues increased due to higher prices on
natural gas sales and increased sales of petroleum products. The
increased sales of petroleum products were primarily due to gas
sales to third parties by Enogex's newest subsidiary, Clinton Gas
Transmission, Inc., which was acquired early in 1993.
Operating revenues in 1992 were adversely affected by a
decrease in sales of electricity to OG&E customers, due to the
unusually mild weather in the Company's service territory and the
$18 million provision for rate refund recorded in 1992. These
factors were offset by increased sales of electricity to other
utilities and increased revenues by Enogex. Enogex's revenue
reflects increased volumes and prices for natural gas sales to
third parties.
The higher levels of sales to other utilities in 1992 were
due to the unusually mild weather and the significant amount of
power that the Company must purchase from cogenerators under
Federal law, which resulted in OG&E having surplus, relatively-
inexpensive power for sale to other utilities. Yet, as noted
above, sales to other utilities are at much lower prices per
kilowatt-hour and have less impact on operating revenues and
income than system sales. The Company's 1992 system kilowatt-hour
sales were down by approximately 1.5 percent compared to 1991 due
to decreased customer usage, while sales to other utilities
increased 62.1 percent from 1991 levels.
35
The Company's 1994 revenues will be affected by the
Commission's recent rate order, which will lower OG&E's rates to
its Oklahoma customers by approximately $17 million and result in
a charge of approximately $2.2 million relating to the portion of
the $41.3 million refund to be recognized in 1994.
EXPENSES AND OTHER ITEMS
Percent Change
From Prior Year
-------------------
(dollars in thousands) 1993 1992 1991 1993 1992
----------------------------------------------------------------------------------------
Fuel . . . . . . . . . . . . $ 383,207 $ 377,575 $ 368,978 1.5 2.3
Purchased power . . . . . . 218,689 182,230 173,846 20.0 4.8
Gas purchased for
resale (Enogex). . . . . . 140,311 97,486 77,351 43.9 26.0
Other operation and
maintenance. . . . . . . . 274,988 266,061 254,590 3.4 4.5
Depreciation . . . . . . . . 119,543 110,700 107,714 8.0 2.8
Taxes . . . . . . . . . . . 115,361 103,928 121,204 11.0 (14.3)
-------------------------------------------------------------------
Total operating expenses. . $1,252,099 $1,137,980 $1,103,683 10.0 3.1
========================================================================================
Total operating expenses rose 10.0 percent to $1.25 billion
during 1993 compared to an increase of 3.1 percent to $1.14
billion during 1992.
The Company's generating capability is almost evenly divided
between coal and natural gas and provides the flexibility to use
either fuel to the best economic advantage for the Company and
its customers. During 1993, the cost associated with coal
decreased $3.8 million or 2.0 percent. The cost associated with
natural gas, on the other hand, increased by $9.4 million or 3.9
percent. The total increase in fuel expense for 1993 was $5.6
million or 1.5 percent which compares to a total fuel expense
increase of $8.6 million or 2.3 percent for 1992. The consumption
of natural gas in 1993 was actually 3.5 percent less than in
1992, however, due to price fluctuations, natural gas expense on
a Btu basis increased 4.4 percent.
The cost of fuel in the generation of electricity (which
includes Enogex's charges to OG&E for transporting natural gas to
OG&E's gas-fired generating units) and the cost of purchased
power are recovered from customers pursuant to fuel adjustment
clauses or other tariffs, subject to periodic review by the
Oklahoma Corporation Commission, the Arkansas Public Service
Commission and the Federal Energy Regulatory Commission ("FERC").
See Note 10 of Notes to Consolidated Financial Statements.
Purchased power costs amounted to $218.7 million in 1993,
$182.2 million in 1992 and $173.8 million in 1991. As required by
36
the Public Utility Regulatory Policy Act of 1978 ("PURPA"), the
Company must currently purchase power from qualified cogeneration
facilities. Purchased power costs increased by more than $36
million in 1993 due to price escalation provisions contained in
certain cogeneration contracts. In 1998, another cogeneration
facility is scheduled to become operational. Under PURPA, the
Company is obligated to purchase capacity from this facility as
well. See Note 9 of Notes to Consolidated Financial Statements.
In 1992, the Company increased its electric sales to other
utilities. This increased volume caused fuel expense to exceed
1991 levels, despite the Company's various programs which,
overall, reduced fuel expense on a per kilowatt-hour basis.
To help lower fuel cost, the Company began utilizing a new
natural gas storage facility in 1993. OG&E is now pumping gas
into the storage reservoir, which will help OG&E get greater
value out of its remaining take-or-pay gas contracts. By
diverting natural gas into storage, for the first time OG&E will
be able to use as much coal as possible to make electricity, and
pull gas from storage only to meet increases in demand.
In 1994, gas storage will give OG&E the flexibility to
generate about 78 percent of its electricity with coal, the
highest percentage in OG&E's history. With coal being
approximately one-third the cost of gas, running coal units at
full capacity is expected to cut fuel costs for OG&E's customers
by about $90 million a year.
The Company has initiated numerous other ongoing programs
that have helped reduce the cost of generating electricity over
the last several years. These programs include: 1) spot market
purchases of coal; 2) renegotiated contracts for coal, gas,
railcar maintenance, and coal transportation; and 3) a heat rate
awareness program to produce kilowatt-hours with less fuel.
Together, these fuel management efforts help OG&E remain
competitive by cutting fuel costs with the savings being passed
on to OG&E's electric customers, which in turn allows them to
remain competitive in a global economy.
Enogex's gas purchased for resale increased $42.8 million or
43.9 percent for 1993 compared to $20.1 million or 26.0 percent
for 1992. The 1993 increase was due to higher gas prices and
increased volumes of natural gas purchased for resale by Clinton
Gas Transmission, Inc. The 1992 increase in gas purchased for
resale resulted from larger volumes and increased cost of natural
gas purchased by Enogex.
The increase in other operation and maintenance expenses for
1993 resulted from major overhauls at two generating plants and
increased labor costs. The 1992 increase in other operation and
37
maintenance expenses was primarily due to increased medical and
labor costs, higher expenses associated with the Company's
Oklahoma rate cases, rent expense for the corporate headquarters
and tree trimming activity along transmission and distribution
rights-of-way.
The increases in depreciation for 1993 and 1992 reflect
higher levels of depreciable plant. Also, the adoption of
Statement of Financial Accounting Standards No. 109, "Accounting
for Income Taxes," during 1993 and its effect on Enogex
contributed to the increase in depreciation. See Note 2 of Notes
to Consolidated Financial Statements.
Income taxes during 1993 increased primarily due to higher
pre-tax earnings and a one percent increase in the federal income
tax rate to 35 percent. Current income taxes decreased in 1992
primarily due to lower pre-tax earnings. The 1992 decrease in
current income taxes was partially offset by the tax effect of
the $18 million provision for a potential refund which increased
current income taxes by approximately $6.8 million and decreased
the provision for deferred income taxes by a like amount.
The increase in interest expense for 1993 resulted from
approximately $6.2 million of interest associated with the refund
ordered by the Commission. See Note 10 of Notes to Consolidated
Financial Statements.
Liquidity, Capital Resources and Contingencies
The primary capital requirements for 1993 and as estimated for
1994 through 1996 are as follows:
(dollars in millions) 1993 1994 1995 1996
----------------------------------------------------------------------
Construction expenditures
including AFUDC ................ $128 $143 $116 $118
Maturities of long-term debt
and sinking fund requirements .. 15 - 85 -
----------------------------------------------------------------------
Total ...................... $143 $143 $201 $118
======================================================================
CONSTRUCTION
The Company's need for capital is related to construction of
new facilities to meet anticipated demand for service, to replace
or expand existing facilities in both its electric and non-
38
utility businesses, and to some extent, for satisfying maturing
debt and sinking fund obligations. Approximately $6.9 million of
the Company's construction expenditures budgeted for 1994 are to
comply with environmental laws and regulations.
The construction program for the next several years does not
include any additional base-load generating units. Rather, to
meet the increased electricity needs of its customers during the
balance of this century, the Company will concentrate on
maintaining the reliability and increasing the utilization of
existing capacity and increasing demand-side management efforts.
FINANCE
The Company meets its cash needs through internally
generated funds, short-term borrowings and permanent financing.
The Company internally generated substantially all of its funds
for construction expenditures during 1993. Management expects
that internally generated funds will be adequate over the next
three years to meet these capital requirements and to refund the
$41.3 million ordered by the Commission in 1994. Short-term
borrowings will continue to be used to meet temporary cash
requirements. The maximum amount of outstanding short-term
borrowings during 1993 was $136.6 million. The Company has the
necessary regulatory approvals to incur up to $300 million in
short-term borrowings at any one time.
CONTINGENCIES
The Company is defending various claims and legal actions,
including environmental actions, which are common to its
operations. As to environmental matters, the Company has been
designated as a "potentially responsible party" ("PRP") with
respect to three waste disposal sites to which the Company sent
materials. Under applicable law, the Company along with each PRP,
could be held jointly and severally liable for site remediation.
Neither the amount of cleanup costs nor the final method of their
allocation among all designated PRPs at any of these sites has
been determined. While it is not possible to determine the
precise outcome of these matters, in the opinion of management,
the Company's ultimate liability for the clean-up costs of these
sites will not have a material effect on the Company's financial
position or results of operations. Management's opinion is based
on the following: 1) the clean-up costs already paid by certain
parties, 2) the financial viability of the other PRPs, and 3) the
portion of the total wastes disposed at the sites attributable to
the Company. Management also believes that costs incurred in
connection with the sites, which are not recovered from insurance
carriers or other parties, may be allowable costs for future
ratemaking purposes.
39
The Clean Air Act Amendments of 1990 (CAAA) among other
things, limit the emission of sulfur dioxide and nitrogen oxides.
All of OG&E's coal-fired generating units currently burn low-
sulfur coal and, consequently, OG&E will not need to take any
steps to comply with the new sulfur dioxide emission limits until
January 1, 2000. The Company has made a capital investment for
installation of continuous emission monitors on 12 units by
January 1, 1995. The CAAA will also regulate emissions for
nitrogen oxides and certain air toxic compounds. Although final
regulations concerning all of these issues have not been written,
some capital expenditures may be necessary, but an estimate of
cost can not be determined at this time. The Company will
continue to examine all alternatives to comply with the CAAA as
part of its Integrated Resource Planning process. This planning
approach will assure the Company has the least-cost option to
comply with the CAAA and be in a competitive position to market
its services. The Company will not be required to file its
compliance plan with the Environmental Protection Agency ("EPA")
until January 1996.
OG&E's review of its annual report for 1991 under the Toxic
Substance Control Act ("TSCA") revealed numerous discrepancies in
OG&E's operating practices and documentation, which have been
reported to the EPA. Many of the discrepancies could be deemed
violations of TSCA regulations. See Note 9 of Notes to
Consolidated Financial Statements for a further discussion of
this matter.
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. The Energy Act 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.
Besides the existing contingencies described above, and
those described in Note 9 of Notes to Consolidated Financial
Statements, the Company's ability to fund its future operational
needs and to finance its construction program is dependent upon
numerous other factors beyond its control, such as general
economic conditions,
abnormal weather, load growth, inflation, new environmental laws
or regulations, and the cost and availability of external
financing.
Item 8. Financial Statements and Supplementary Data.
----------------------------------------------------
40
CONSOLIDATED BALANCE SHEETS.
December 31 (dollars in thousands) 1993 1992 1991
=========================================================================================
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service . . . . . . . . . . . . . . $ 3,656,113 $ 3,471,588 $ 3,352,658
Construction work in progress . . . . . 33,970 37,147 48,988
- -----------------------------------------------------------------------------------------
Total property, plant and equipment . 3,690,083 3,508,735 3,401,646
Less accumulated depreciation . . . 1,370,227 1,267,472 1,178,615
- -----------------------------------------------------------------------------------------
Net property, plant and equipment . . . 2,319,856 2,241,263 2,223,031
- -----------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost . 6,920 6,269 5,270
- -----------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . 6,593 11,316 7,576
Accounts receivable-customers, less
reserve of $4,070, $4,039 and $3,775,
respectively . . . . . . . . . . . . . 126,997 107,805 109,608
Accrued unbilled revenues . . . . . . . 45,100 45,300 32,800
Accounts receivable-other . . . . . . . 6,269 6,378 6,475
Fuel inventories, at LIFO cost . . . . 27,127 37,066 42,792
Materials and supplies, at average cost 26,813 24,614 24,361
Prepayments and other . . . . . . . . . 28,648 5,215 4,356
Accumulated deferred tax assets . . . . 24,088 - -
- -----------------------------------------------------------------------------------------
Total current assets . . . . . . . . 291,635 237,694 227,968
- -----------------------------------------------------------------------------------------
DEFERRED CHARGES:
Advance payments for gas. . . . . . . . 21,165 22,743 19,351
Income taxes recoverable through
future rates . . . . . . . . . . . . . 47,593 44,387 48,578
Other . . . . . . . . . . . . . . . . . 44,255 37,727 41,891
- -----------------------------------------------------------------------------------------
Total deferred charges . . . . . . . 113,013 104,857 109,820
- -----------------------------------------------------------------------------------------
TOTAL ASSETS . . . . . . . . . . . . . . $ 2,731,424 $ 2,590,083 $ 2,566,089
=========================================================================================
The accompanying Notes to Consolidated Financial Statements are an integral
part hereof.
December 31 (dollars in thousands) 1993 1992 1991
=========================================================================================
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statements):
Common stock and retained earnings . . $ 1,120,183 $ 1,115,486 $ 1,125,373
Cumulative preferred stock . . . . . . 49,973 49,973 49,973
Treasury stock . . . . . . . . . . . . (213,379) (213,983) (214,631)
Long-term debt . . . . . . . . . . . . 838,660 838,654 853,597
- -----------------------------------------------------------------------------------------
Total capitalization . . . . . . . . 1,795,437 1,790,130 1,814,312
- -----------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Short-term debt . . . . . . . . . . . . 47,000 26,000 12,500
Accounts payable . . . . . . . . . . . 100,285 94,549 90,014
Dividends payable . . . . . . . . . . . 27,410 27,397 27,386
Customers' deposits . . . . . . . . . . 19,353 17,891 18,462
Accrued taxes . . . . . . . . . . . . . 24,717 27,169 34,500
Accrued interest . . . . . . . . . . . 26,712 29,961 25,424
Long-term debt due within one year . . 350 15,300 300
Accumulated provision for rate refund . 39,117 - -
Other . . . . . . . . . . . . . . . . . 48,666 45,541 40,548
- -----------------------------------------------------------------------------------------
Total current liabilities . . . . . . 333,610 283,808 249,134
- -----------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER
LIABILITIES:
Accrued pension and benefit obligation. 16,210 5,620 3,509
Accumulated provision for rate refund . - 18,000 -
Accumulated deferred income taxes . . . 484,003 384,114 383,964
Accumulated deferred investment
tax credits. . . . . . . . . . . . . . 93,478 98,627 104,093
Other . . . . . . . . . . . . . . . . . 8,686 9,784 11,077
- -----------------------------------------------------------------------------------------
Total deferred credits and other
liabilities. . . . . . . . . . . . . 602,377 516,145 502,643
- -----------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES
(Notes 9 and 10)
- -----------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES. . . $ 2,731,424 $ 2,590,083 $ 2,566,089
=========================================================================================
The accompanying Notes to Consolidated Financial Statements are an
integral part hereof.
41
CONSOLIDATED STATEMENTS OF INCOME.
Year ended December 31 (dollars in thousands
except per share data) 1993 1992 1991
===========================================================================================
OPERATING REVENUES. . . . . . . . . . . . . . $ 1,447,252 $ 1,314,984 $ 1,314,770
- -------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Fuel. . . . . . . . . . . . . . . . . . . . 383,207 377,575 368,978
Purchased Power . . . . . . . . . . . . . . 218,689 182,230 173,846
Gas purchased for resale . . . . . . . . . 140,311 97,486 77,351
Other operation . . . . . . . . . . . . . . 196,323 193,622 182,722
Maintenance . . . . . . . . . . . . . . . . 78,665 72,439 71,868
Depreciation. . . . . . . . . . . . . . . . 119,543 110,700 107,714
Current income taxes. . . . . . . . . . . . 72,003 61,325 79,839
Deferred income taxes, net. . . . . . . . . 5,286 4,346 4,048
Deferred investment tax credits, net. . . . (5,150) (5,465) (6,173)
Taxes other than income . . . . . . . . . . 43,222 43,722 43,490
- -------------------------------------------------------------------------------------------
Total operating expenses. . . . . . . . . 1,252,099 1,137,980 1,103,683
- -------------------------------------------------------------------------------------------
OPERATING INCOME. . . . . . . . . . . . . . . 195,153 177,004 211,087
- -------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
Interest income . . . . . . . . . . . . . . 1,431 629 860
Allowance for equity funds used
during construction. . . . . . . . . . . . - - 574
Other . . . . . . . . . . . . . . . . . . . (2,732) (1,196) (1,905)
- -------------------------------------------------------------------------------------------
Net other income and deductions . . . . . (1,301) (567) (471)
- -------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt. . . . . . . . . 70,490 71,230 70,149
Allowance for borrowed funds used
during construction . . . . . . . . . . . (433) (809) (2,296)
Other. . . . . . . . . . . . . . . . . . . 9,518 6,304 8,847
- -------------------------------------------------------------------------------------------
Total interest charges, net. . . . . . . . 79,575 76,725 76,700
- -------------------------------------------------------------------------------------------
NET INCOME. . . . . . . . . . . . . . . . . . 114,277 99,712 133,916
PREFERRED DIVIDEND REQUIREMENTS . . . . . . . 2,317 2,317 2,317
- -------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON . . . . . . . . $ 111,960 $ 97,395 $ 131,599
===========================================================================================
AVERAGE COMMON SHARES OUTSTANDING (thousands) 40,328 40,310 40,298
EARNINGS PER AVERAGE COMMON SHARE . . . . . . $ 2.78 $ 2.42 $ 3.27
===========================================================================================
The accompanying Notes to Consolidated Financial Statements are an integral
part hereof.
42
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS.
Year ended December 31 (dollars in thousands) 1993 1992 1991
===========================================================================================
BALANCE AT BEGINNING OF PERIOD . . . . . . . $ 391,135 $ 400,976 $ 374,160
ADD-net income . . . . . . . . . . . . . . . 114,277 99,712 133,916
- -------------------------------------------------------------------------------------------
Total. . . . . . . . . . . . . . . . . . 505,412 500,688 508,076
- -------------------------------------------------------------------------------------------
DEDUCT:
Cash dividends declared on preferred stock 2,317 2,317 2,317
Cash dividends declared on common stock. . 107,284 107,236 104,783
- -------------------------------------------------------------------------------------------
Total. . . . . . . . . . . . . . . . . . 109,601 109,553 107,100
- -------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD . . . . . . . . . . $ 395,811 $ 391,135 $ 400,976
===========================================================================================
The accompanying Notes to Consolidated Financial Statements are an
integral part hereof.
43
CONSOLIDATED STATEMENTS OF CAPITALIZATION.
December 31 (dollars in thousands) 1993 1992 1991
============================================================================================
COMMON STOCK AND RETAINED EARNINGS:
Common stock, par value $2.50 per share;
Authorized 100,000,000 shares;
issued 46,470,616 shares . . . . . . . . . . . $ 116,177 $ 116,177 $ 116,177
Premium on capital stock . . . . . . . . . . . . 608,195 608,174 608,220
Retained earnings . . . . . . . . . . . . . . . 395,811 391,135 400,976
Treasury stock-6,124,139, 6,141,591 and
6,160,222 shares, respectively . . . . . . . . (213,379) (213,983) (214,631)
- --------------------------------------------------------------------------------------------
Total common stock and retained earnings . . . 906,804 901,503 910,742
- --------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK:
Par value $20, authorized 675,000 shares-4%;
outstanding 423,663 shares . . . . . . . . . . 8,473 8,473 8,473
Par value $25, authorized and unissued
4,000,000 shares . . . . . . . . . . . . . . . - - -
Par value $100, authorized 1,865,000 shares-
SERIES SHARES OUTSTANDING:
4.20% 50,000. . . . . . . . . . . . . . . 5,000 5,000 5,000
4.24% 75,000. . . . . . . . . . . . . . . 7,500 7,500 7,500
4.44% 65,000. . . . . . . . . . . . . . . 6,500 6,500 6,500
4.80% 75,000. . . . . . . . . . . . . . . 7,500 7,500 7,500
5.34% 150,000. . . . . . . . . . . . . . . 15,000 15,000 15,000
- --------------------------------------------------------------------------------------------
Total cumulative preferred stock . . . . . . . . 49,973 49,973 49,973
- --------------------------------------------------------------------------------------------
LONG-TERM DEBT:
First mortgage bonds-
SERIES DATE DUE
4-1/4% March 1, 1993 . . . . . . . . . . . - 15,000 15,000
4-1/2% March 1, 1995 . . . . . . . . . . . 25,000 25,000 25,000
5-1/8% January 1, 1997 . . . . . . . . . . 15,000 15,000 15,000
6-3/8% January 1, 1998 . . . . . . . . . . 25,000 25,000 25,000
7-1/8% January 1, 1999 . . . . . . . . . . 12,500 12,500 12,500
8-5/8% January 1, 2000 . . . . . . . . . . 30,000 30,000 30,000
7-1/8% January 1, 2002 . . . . . . . . . . 40,000 40,000 40,000
8-3/8% January 1, 2004 . . . . . . . . . . 75,000 75,000 75,000
9-1/8% January 1, 2005 . . . . . . . . . . 60,000 60,000 60,000
8-5/8% January 1, 2006 . . . . . . . . . . 55,000 55,000 55,000
8-3/8% January 1, 2007 . . . . . . . . . . 75,000 75,000 75,000
8-5/8% November 1, 2007 . . . . . . . . . . 35,000 35,000 35,000
8-1/4% August 15, 2016 . . . . . . . . . . 100,000 100,000 100,000
8-7/8% December 1, 2020 . . . . . . . . . . 75,000 75,000 75,000
5-7/8% Pollution Control Series A,
December 1, 2007 . . . . . . . . . 47,000 47,000 47,000
7% Pollution Control Series C,
March 1, 2017 . . . . . . . . . . . 56,000 56,000 56,000
Other bonds-
6-3/4% Muskogee Industrial Trust Bonds,
March 1, 2006 . . . . . . . . . . . 32,400 32,700 33,000
Unamortized premium and discount, net. . . . . . (8,890) (9,246) (9,603)
Enogex Inc. medium-term notes. . . . . . . . . . 90,000 90,000 90,000
- --------------------------------------------------------------------------------------------
Total long-term debt . . . . . . . . . . . . . 839,010 853,954 853,897
Less long-term debt due within one year. . . 350 15,300 300
- --------------------------------------------------------------------------------------------
Total long-term debt (excluding long-term
debt due within one year). . . . . . . . . . 838,660 838,654 853,597
- --------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . $ 1,795,437 $ 1,790,130 $ 1,814,312
============================================================================================
The accompanying Notes to Consolidated Financial Statements are an
integral part hereof.
44
CONSOLIDATED STATEMENTS OF CASH FLOWS.
Year ended December 31 (dollars in thousands) 1993 1992 1991
=====================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income. . . . . . . . . . . . . . . . . . . . . . $ 114,277 $ 99,712 $ 133,916
Adjustments to Reconcile Net Income to Net Cash
Provided from Operating Activities:
Depreciation. . . . . . . . . . . . . . . . . . . . 119,543 110,700 107,714
Deferred income taxes and investment tax
credits, net . . . . . . . . . . . . . . . . . . . 136 (1,119) (2,125)
Allowance for equity funds used during
construction . . . . . . . . . . . . . . . . . . . - - (574)
Provision for rate refund . . . . . . . . . . . . . 21,117 18,000 -
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers . . . . . . . . . (19,192) 1,803 (5,160)
Accrued unbilled revenues . . . . . . . . . . . . 200 (12,500) 600
Fuel, materials and supplies inventories. . . . . 7,740 5,473 (6,268)
Accumulated deferred tax assets . . . . . . . . . (24,088) - -
Other current assets. . . . . . . . . . . . . . . (23,324) (762) (2,458)
Accounts payable. . . . . . . . . . . . . . . . . 5,268 6,220 10,546
Accrued taxes . . . . . . . . . . . . . . . . . . (2,452) (7,331) (1,644)
Accrued interest. . . . . . . . . . . . . . . . . (3,249) 4,537 (1,433)
Other current liabilities . . . . . . . . . . . . 4,600 4,433 20,259
Other operating activities. . . . . . . . . . . . . 26,276 12,863 (17,897)
- -----------------------------------------------------------------------------------------------------
Net cash provided from operating activities . . 226,852 242,029 235,476
- -----------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures. . . . . . . . . . . . . . . . (127,674) (141,936) (114,919)
- -----------------------------------------------------------------------------------------------------
Net cash used in investing activities . . . . . (127,674) (141,936) (114,919)
- -----------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt. . . . . . . . . . . . (15,300) (300) -
Short-term debt . . . . . . . . . . . . . . . . . . 21,000 13,500 (8,900)
Cash dividends declared on preferred stock. . . . . (2,317) (2,317) (2,317)
Cash dividends declared on common stock . . . . . . (107,284) (107,236) (104,783)
- -----------------------------------------------------------------------------------------------------
Net cash used in financing activities . . . . . (103,901) (96,353) (116,000)
- -----------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS. . (4,723) 3,740 4,557
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD. . . . 11,316 7,576 3,019
CASH AND CASH EQUIVALENTS AT END OF PERIOD. . . . . . . $ 6,593 $ 11,316 $ 7,576
=====================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash Paid During the Period for:
Interest (net of amount capitalized). . . . . . . . $ 71,401 $ 73,691 $ 75,828
Income taxes . . . . . . . . . . . . . . . . . . . $ 79,953 $ 60,229 $ 88,763
- -----------------------------------------------------------------------------------------------------
DISCLOSURE OF ACCOUNTING POLICY:
For purposes of this statement, the Company considers all highly
liquid debt instruments purchased with a maturity of three months or
less to be cash equivalents. These investments are carried at cost
which approximates market.
- -----------------------------------------------------------------------------------------------------
The accompanying Notes to Consolidated Financial Statements are an
integral part hereof.
45
Notes To Consolidated Financial Statements.
1. Summary of Significant Accounting Policies
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts
of Oklahoma Gas and Electric Company ("OG&E"), its wholly-owned
non-utility subsidiary Enogex Inc. and its subsidiaries
("Enogex") (collectively, the "Company"). 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 (the "Oklahoma Commission") and the
Arkansas Public Service Commission (the "Arkansas Commission").
Additionally, OG&E is subject to the accounting principles
prescribed by Statement of Financial Accounting Standards
("SFAS") No. 71, "Accounting for the Effects of Certain Types of
Regulation".
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 maintenance expense.
DEPRECIATION
The provision for depreciation, which was approximately 3.2%
of the average depreciable utility plant, for each of the years
1993, 1992 and 1991, 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 and gas processing plants are depreci-
ated on a straight-line method over a period of 20 to 48 years.
46
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 3.60%, 4.30% and
7.48% for the years 1993, 1992 and 1991, respectively.
OPERATING REVENUES
OG&E accrues estimated revenues for services provided but
not yet billed. The cost of providing service is recognized as
incur- red.
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 estimated cost-of-service for ratemaking, are
charged to substantially all of the Company's electric customers
through automatic fuel adjustment clauses. A lag of 45 to 60
days occurs between the time costs are incurred and the time such
costs are reflected in bills to retail customers. OG&E records
an accrual in the financial statements for these differences.
The automatic fuel adjustment clauses are subject to periodic
review by the Oklahoma Commission, the Arkansas Commission and
FERC.
FUEL INVENTORIES
Fuel inventories for the generation of electricity consist
of coal, oil and natural gas. These inventories are accounted
for under the last-in, first-out ("LIFO") cost method. Based on
the average cost of fuel purchased in late 1993, the estimated
replacement cost of fuel inventories at December 31, 1993,
exceeded the stated LIFO cost by approximately $2.3 million.
Natural gas products inventory are held for resale and accounted
for based on the weighted average cost of production.
47
2. Income Taxes
The items comprising tax expense are as follows:
(dollars in thousands)
Year ended December 31 1993 1992 1991
------------------------------------------------------------------
Current Income Taxes
Provision for current taxes:
Federal . . . . . . . . . . . $ 61,406 $ 52,191 $ 68,960
State . . . . . . . . . . . . 10,597 9,134 10,879
------------------------------------------------------------------
Total Current Income Taxes . 72,003 61,325 79,839
------------------------------------------------------------------
Deferred Income Taxes, net
Provision (benefit) for deferred taxes:
Federal
Depreciation . . . . . . . 9,673 6,185 7,086
Repair allowance . . . . . 1,306 1,908 (5,136)
Removal costs . . . . . . . 1,026 635 425
Provision for rate refund . (6,972) (5,774) -
Other . . . . . . . . . . . (225) 1,059 395
State . . . . . . . . . . . 424 333 1,278
------------------------------------------------------------------
Total Deferred Income Taxes, net 5,286 4,346 4,048
------------------------------------------------------------------
Deferred Investment Tax Credits,
net . . . . . . . . . . . . . (5,150) (5,465) (6,173)
Income Taxes Relating to Other
Income and Deductions . . . . (538) (1,006) (1,158)
------------------------------------------------------------------
Total Income Tax Expense . . $ 71,601 $ 59,200 $ 76,556
------------------------------------------------------------------
Pretax Income . . . . . . . . . $185,878 $158,912 $210,472
------------------------------------------------------------------
The following schedule reconciles the statutory federal tax
rate to the effective income tax rate:
Year ended December 31 1993 1992 1991
----------------------------------------------------------------
Statutory federal tax rate . . 35.0% 34.0% 34.0%
State income taxes, net of
federal income tax benefit . . 3.9 3.9 4.0
Investment tax credits, net . . (2.8) (3.4) (2.9)
Change in federal tax rate. . . 0.9 - -
Other, net . . . . . . . . . . 1.5 2.8 1.3
Effective income tax rate
as reported . . . . . . . 38.5% 37.3% 36.4%
48
The Company files consolidated income tax returns. Income
taxes are allocated to each company based on its separate taxable
income or loss.
Investment tax credits on electric utility property have been
deferred and are being amortized to income over the life of the
related property.
For 1992 and 1991, provisions for deferred income taxes were
recorded primarily as a result of the use of income tax law
provisions which allowed for the deduction or addition of items
to taxable income in the tax return prior to or after their being
recorded on the books of the Company.
Effective January 1, 1993, the Company adopted SFAS No. 109,
"Accounting for Income Taxes," which requires 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 Company elected not to restate the
financial statements for years ending before January 1, 1993.
When adopted, SFAS No. 109 had no effect on net income.
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.
49
The components of Accumulated Deferred Income Taxes adjusted
to reflect the impact of the increase in the federal income tax
rate, are as follows:
(dollars in thousands) Jan 1, 1993 Dec 31, 1993
Current Deferred Tax Assets:
Accrued vacation..................... $ 3,359 $ 4,177
Provision for rate refund............ - 14,965
Customer deposits.................... 1,102 -
Uncollectible accounts............... 3,669 4,946
Accumulated deferred tax assets...... $ 8,130 $ 24,088
Deferred Tax Liabilities:
Accelerated depreciation and other
property-related differences....... $438,419 $439,253
Allowance for funds used
during construction................ 61,346 57,074
Income taxes recoverable through
future rates....................... 61,829 62,441
Total.............................. 561,594 558,768
Deferred Tax Assets:
Deferred investment tax credits...... (32,850) (30,616)
Income taxes refundable through
future rates....................... (49,100) (44,022)
Provision for rate refund............ (7,074) -
Other................................ (411) (127)
Total.............................. (89,435) (74,765)
Accumulated Deferred Income Taxes...... $472,159 $484,003
The effect of adopting SFAS No. 109 at January 1, 1993,
before adjusting for the new tax rate, resulted in a net increase
in property, plant and equipment of approximately $73.9 million,
a net decrease in income taxes recoverable through future rates
of approximately $12.0 million and a net increase in accumulated
deferred income taxes of approximately $61.9 million. Also at
January 1, 1993, approximately $8.1 million of deferred tax
assets which were previously netted with accumulated deferred
income taxes, were reclassified as current assets as a result of
adopting SFAS No. 109.
At December 31, 1992, the Company had recorded $44.4 million
as unfunded deferred income taxes recoverable from customers. A
corresponding amount was reflected as a component of accumulated
deferred income taxes which represented amounts refundable to
customers. As a result of the adoption of SFAS No. 109, the
$44.4 million amount that was recorded as a component of
accumulated deferred income taxes at December 31, 1992, was
reclassified January 1, 1993, as a regulatory liability and
netted against the regulatory asset. This reclassification
combined with the $12.0 million net decrease in income taxes
recoverable through future rates discussed above, resulted in a
$32.4 million net increase in the amount recognized as income
taxes to be recovered through future rates.
50
The Omnibus Reconciliation Act of 1993, signed into law on
August 10, 1993, increased the top federal corporate tax rate
from 34 to 35 percent. The 35 percent rate was retroactively
made effective January 1, 1993.
For the temporary differences that existed at January 1,
1993, the change in the federal income tax rate increased the
provision for income taxes and accumulated deferred income taxes
approximately $1.6 and $18.0 million, respectively.
Approximately $16.4 million of the increase which was applicable
to utility operations was recorded as income taxes recoverable
from customers through future rates and therefore had no impact
on results of operations for the year ended December 31, 1993.
3. Common Stock and Retained Earnings
There were no new shares of common stock issued during 1993,
1992 or 1991. The changes in premium on capital stock as
presented on the Consolidated Statements of Capitalization
represents the gains and losses associated with the issuance of
common stock pursuant to the Restricted Stock Plan.
Changes in common stock were:
(thousands) 1993 1992 1991
-------------------------------------------------------------------------
Shares outstanding January 1............ 40,329 40,310 40,298
Issued/reacquired under the
Restricted Stock Plan, net............ 17 19 12
-------------------------------------------------------------------------
Shares outstanding December 31.......... 40,346 40,329 40,310
=========================================================================
There were 4,009,021 shares of unissued common stock
reserved for the various employee and Company stock plans at
December 31, 1993.
The Company's Restated Certificate of Incorporation and its
Trust Indenture, as supplemented, relating to the First Mortgage
Bonds, contained provisions which, under specific conditions,
limit the amount of dividends (other than in shares of common
stock) and/or other distributions which may be made to common
shareowners.
In December 1991, holders of the Company's First Mortgage
Bonds approved a series of amendments to the Company's Trust
Indenture. The amendments eliminated the cumulative amount of
the previous restrictions on retained earnings related to the
payment of dividends and provided management with the flexibility
to repurchase its common stock, when appropriate, in order to
maintain desired capitalization ratios and to achieve other
business needs. The Company is amortizing approximately $14
51
million of costs relating to obtaining such amendments over the
remaining life of the respective bond issues. At the end of
1993, there was approximately $11.6 million in unamortized costs
associated with obtaining these amendments.
RESTRICTED STOCK PLAN
The Company has a Restricted Stock Plan whereby certain
employees may periodically receive shares of the Company's common
stock at the discretion of the Board of Directors. The Company
distributed 18,687, 18,631 and 12,200 shares of common stock
during 1993, 1992 and 1991, respectively, pursuant to this plan.
The shares distributed in the reported periods were issued from
treasury stock.
SHAREOWNERS RIGHTS PLAN
In December 1990, the Company adopted a Shareowners Rights
Plan designed to protect shareowners' interests in the event that
the Company is ever confronted with an unfair or inadequate
acquisition proposal. Pursuant to the plan, the Company declared
a dividend distribution of one "right" for each share of Company
common stock. Each right entitles the holder to purchase from
the Company one one-hundredth of a share of new preferred stock
of the Company under certain circumstances. The rights may be
exercised if a person or group announces its intention to
acquire, or does acquire, 20 percent or more of the Company's
common stock. Under certain circumstances, the holders of the
rights will be entitled to purchase either shares of common stock
of the Company or common stock of the aquirer at a reduced
percentage of market value. The rights will expire on December
11, 2000.
4. Cumulative Preferred Stock
Preferred stock is redeemable at the option of OG&E at the
following amounts per share plus accrued dividends: the 4%
Cumulative Preferred Stock at the par value of $20 per share; the
Cumulative Preferred Stock, par value $100 per share, as follows:
4.20% series-$102; 4.24% series-$102.875; 4.44% series-$102;
4.80% series-$102; and 5.34% series-$101.
As approved by shareowners on May 16, 1991, the Restated
Certificate of Incorporation was amended to permit the issuance
of new series of preferred stock with dividends payable other
than quarterly.
52
5. Long-Term Debt
OG&E's Trust Indenture, as supplemented, relating to the
First Mortgage Bonds, requires OG&E to pay to the trustee
annually, an amount sufficient to redeem, for sinking fund
purposes, 1-1/4 % of the highest amount outstanding at any time.
This requirement has been satisfied by pledging permanent
additions to property to the extent of 166-2/3 % of principal
amounts of bonds otherwise required to be redeemed. Through Dec-
ember 31, 1993, gross property additions pledged totaled approxi-
mately $341 million.
Annual sinking fund requirements for each of the five years
subsequent to December 31, 1993, are as follows:
Year Amount
----------------------------------------
1994 ............ $15,114,583
1995 ............ 14,593,750
1996 ............ 14,593,750
1997 ............ 14,281,250
1998 ............ 13,760,417
----------------------------------------
As in prior years, OG&E expects to meet these requirements
by pledging permanent additions to property.
The 6-3/4 % Series, $33 million Muskogee Industrial Trust
Pollution Control Revenue Bonds of 1976, are subject to mandatory
annual cash sinking fund requirements, which began March 1, 1992.
Cash sinking fund payments for the next five years are as
follows: $350,000 in 1994 and 1995; and $500,000 in 1996, 1997
and 1998. The annual amount escalates to $900,000 due March 1,
2005, with the balance of $24,750,000 due March 1, 2006. These
amounts are not included in the above schedule.
Enogex debt consists of the following notes payable: $60
million, with interest rates between 9.88%-10.03%, maturing
December 21, 1995; and $30 million, with interest rates between
9.96%-10.11%, maturing December 21, 1998.
Maturities of First Mortgage Bonds during the next five
years consist of $25 million in 1995, $15 million in 1997 and $25
million in 1998.
Unamortized debt expense and unamortized premium and
discount on long-term debt are being amortized over the life of
the respective debt.
Substantially all electric plant was subject to lien of the
Trust Indenture at December 31, 1993.
53
6. Short-Term Debt
The Company borrows on a short-term basis, as necessary, by
the issuance of commercial paper and by obtaining short-term bank
loans. The maximum and average amounts of short-term borrowings
during 1993 were $136.6 million and $62.5 million, respectively,
at a weighted average interest rate of 3.60%. The Company has an
agreement for a flexible line of credit, up to $200 million,
through December 31, 1996. The line of credit which was
nominated by the Company at $160 million at year-end is
maintained on a fee basis of 1/8 of 1%, per year, on the unused
balance. Short-term debt in the amount of $47.0 million was
outstanding at December 31, 1993.
7. Postemployment Benefit Plans
PENSION PLAN
All eligible employees of the Company are covered by a
non-contributory defined benefit pension plan. Under the plan,
retirement benefits are primarily a function of both the years of
service and the highest average monthly compensation for 60
consecutive months out of the last 120 months of service.
It is the Company's policy to fund the plan on a current
basis to comply with the minimum required contributions under
existing tax regulations. Such contributions are intended to
provide not only for benefits attributed to service to date, but
also for those expected to be earned in the future.
Net periodic pension cost is computed in accordance with
provisions of SFAS No. 87, "Employers' Accounting for Pensions,"
and is recorded as other operation expense in the accompanying
Consolidated Statements of Income.
In determining the projected benefit obligation, the
weighted average discount rate used was 7.25% in 1993 and 8.5% in
1992 and 1991, while the assumed rate of increase in future
salary levels was 4.5% in 1993 and 5.5% in 1992 and 1991. The
expected long-term rate of return on assets used in determining
net periodic pension cost was 9.0% for the reported periods.
The plan's assets consist primarily of U. S. Government
securities, listed common stocks and corporate debt.
54
Net periodic pension costs for 1993, 1992 and 1991 included the
following:
(dollars in thousands) 1993 1992 1991
----------------------------------------------------------------------
Service costs-benefits earned
during year.......................... $ 7,630 $ 7,266 $ 6,518
Interest cost on projected
benefit obligation................... 14,557 13,657 13,242
Return on plan assets................... (15,697) (14,761) (13,047)
Net amortization and deferral........... (1,263) (1,263) (1,353)
Amortization of unrecognized
prior service cost................... 671 671 552
Settlement gain......................... - - (88)
----------------------------------------------------------------------
Net periodic pension cost............... $ 5,898 $ 5,570 $5,824
======================================================================
The following table sets forth the plan's funded status at December
31, 1993, 1992 and 1991:
(dollars in thousands) 1993 1992 1991
-------------------------------------------------------------------------------
Projected benefit obligation:
Vested benefits...................... $(140,958) $(113,072) $(105,544)
Nonvested benefits................... (21,435) (17,709) (16,568)
-------------------------------------------------------------------------------
Accumulated benefit obligation....... (162,393) (130,781) (122,112)
Effect of future
compensation levels............... (51,196) (47,632) (44,571)
-------------------------------------------------------------------------------
Projected benefit obligation........... (213,589) (178,413) (166,683)
Plan's assets at fair value............ 194,501 176,891 164,691
-------------------------------------------------------------------------------
Plan's assets less than
projected benefit obligation......... (19,088) (1,522) (1,992)
Unrecognized prior service cost........ 7,942 8,613 9,284
Unrecognized net asset from
application of SFAS No. 87........... (10,106) (11,369) (12,632)
Unrecognized net loss.................. 14,448 281 3,065
-------------------------------------------------------------------------------
Accrued pension liability.............. $ (6,804) $ (3,997) $ (2,275)
===============================================================================
55
POSTRETIREMENT HEALTH CARE AND LIFE INSURANCE BENEFITS
In addition to providing pension benefits, the Company
provides certain health care 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. Prior to January 1, 1993, the costs of retiree
health care and life insurance benefits were recognized as expense
when claims were paid ("pay-as-you-go"). Pay-as-you-go costs
totaled approximately $3,804,000, $3,443,000 and $3,272,000 for
1993, 1992 and 1991, respectively.
In December 1990, the Financial Accounting Standards Board
("FASB") issued SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." The Company adopted
the provisions of SFAS No. 106 beginning January 1, 1993. This
standard requires that employers accrue the cost of postretirement
benefits during the active service periods of employees until the
date they attain full eligibility for the benefits.
In the February 25, 1994 order from the Oklahoma Commission,
OG&E was directed to recover postretirement benefit costs following
the pay-as-you-go method and to defer the incremental cost
associated with accrual recognition of SFAS No. 106 related costs
following a "phase-in" plan proposed by the Commission staff. In
accordance with this phase-in plan, OG&E may defer the amortization
of the transition obligation for up to five years or until OG&E's
next general rate case, whichever occurs first. The phase-in plan
also provides for OG&E to defer 100% of the incremental cost
associated with accrual recognition of SFAS No. 106 related costs,
exclusive of the amortization of OG&E's transition obligation, in
1993. The percentage of these incremental costs that may be
deferred is reduced 25% each year beginning in 1994. OG&E deferred
approximately $8.9 million of postretirement costs in 1993.
The Company will record a regulatory asset for the difference
between any amounts using the pay-as-you-go method and those
required by SFAS No. 106 in accordance with the phase-in plan.
However, until the Oklahoma Commission issues an order approving
recovery for this difference, there can be no assurance that the
Company will be able to recover such costs in rates. Consequently,
the Company is unable to determine the final impact of
implementation of SFAS No. 106.
On March 25, 1993, the Arkansas Commission issued an order
adopting accrual accounting and deferral of the differential
between "pay-as-you-go" and accrued postretirement benefit costs
for those companies requesting such deferral. In 1993, the
Federal Energy Regulatory Commission issued its final agency action
for SFAS No. 106, approving accrual accounting and deferral of the
56
differential. Recovery is expected for the amounts deferred in
both of these jurisdictions.
The Company currently does not have a plan to fund postretire-
ment benefits. Any decisions on funding will be considered along
with requirements established by the commission in each jurisdic-
tion.
Net postretirement benefit expense for the year ended
December 31, 1993, included the following components:
(dollars in thousands)
------------------------------------------------
Service cost............................$ 2,812
Interest cost........................... 6,158
Amortization of transition obligation... 3,687
Net amount capitalized or deferred...... (8,853)
------------------------------------------------
Net postretirement benefit expense....$ 3,804
================================================
The following table sets forth the funded status of the plans
and amounts recognized in the Company's Consolidated Balance Sheets
as of December 31, 1993:
(dollars in thousands) Jan 1, 1993 Dec 31, 1993
---------------------------------------------------------------------------
Accumulated postretirement benefit
obligation:
Retirees................................ $(45,152) $(42,891)
Actives eligible to retire.............. (15,341) (17,479)
Actives not yet eligible to retire...... (13,241) (15,622)
---------------------------------------------------------------------------
Total ................................ $(73,734) $(75,992)
Plan assets at fair value................... - -
---------------------------------------------------------------------------
Funded status............................... $(73,734) $(75,992)
Unrecognized transition obligation.......... 73,734 70,047
Unrecognized net actuarial gain............. - (2,908)
---------------------------------------------------------------------------
Accrued postretirement benefit cost......... $ - $ (8,853)
===========================================================================
The discount rate used in determining the accumulated
postretirement benefit obligation was 8.5 percent and 7.25 percent
for January 1, 1993 and December 31, 1993, respectively. The rate
of increase in future compensation levels used in measuring the
life insurance accumulated postretirement benefit obligation was
5.5 percent and 4.5 percent for January 1, 1993 and December 31,
1993, respectively. A 14.0 percent annual rate of increase in the
per capita cost of covered health care benefits was assumed for
1993; the rate is assumed to decrease gradually to 5.5 percent by
the year 2005 and remain at that level thereafter. A one-
percentage-point increase in the assumed health care cost trend
rates would increase the accumulated postretirement benefit
57
obligation as of December 31, 1993, by approximately $6.8 million,
and the aggregate of the service and interest cost components of net
postretirement health care cost for 1993 by approximately $1.5
million.
POSTEMPLOYMENT BENEFITS
In November 1992, the FASB issued SFAS No. 112, "Employers'
Accounting for Postemployment Benefits," which will require the
Company to accrue the estimated cost of benefits provided to former
or inactive employees after employment but before retirement.
Adoption of SFAS No. 112 is required for fiscal years beginning
after December 15, 1993, with earlier application permitted for
which annual financial statements have not previously been issued.
The Company will adopt this new standard effective January 1, 1994,
and believes these costs will not have a material impact on its
consolidated financial position or results of operations.
8. Report of Business Segments
The Company's electric utility segment is an operating public
utility engaged in the generation, transmission, distribution, and
sale of electric energy. The non-utility subsidiary segment is
engaged in the gathering and transmission of natural gas, and
through its subsidiaries, is engaged in the processing of natural
gas and the marketing of natural gas liquids, in the buying and
selling of natural gas to third parties, and in the exploration for
and production of natural gas and related products.
58
(dollars in thousands) 1993 1992 1991
-------------------------------------------------------------------
Operating information:
Operating Revenues
Electric utility......... $1,282,816 $1,193,993 $1,210,726
Non-utility subsidiary... 219,376 189,574 170,490
Intersegment revenues (A) (54,940) (68,583) (66,446)
-------------------------------------------------------------------
Total................ $1,447,252 $1,314,984 $1,314,770
-------------------------------------------------------------------
Pre-tax Operating Income
Electric utility......... $ 238,761 $ 206,350 $ 249,559
Non-utility subsidiary... 28,531 30,860 39,242
-------------------------------------------------------------------
Total................ $ 267,292 $ 237,210 $ 288,801
-------------------------------------------------------------------
Net Income
Electric utility ........ $ 104,730 $ 88,293 $ 116,531
Non-utility subsidiary... 9,547 11,419 17,385
-------------------------------------------------------------------
Total................ $ 114,277 $ 99,712 $ 133,916
-------------------------------------------------------------------
Investment Information:
Identifiable Assets
as of December 31
Electric utility......... $2,443,651 $2,358,661 $2,356,712
Non-utility subsidiary... 287,773 231,422 209,377
-------------------------------------------------------------------
Total................ $2,731,424 $2,590,083 $2,566,089
-------------------------------------------------------------------
Other Information:
Depreciation
Electric utility......... $ 104,343 $ 100,531 $ 97,950
Non-utility subsidiary... 15,200 10,169 9,764
-------------------------------------------------------------------
Total................ $ 119,543 $ 110,700 $ 107,714
-------------------------------------------------------------------
Construction Expenditures
Electric utility......... $ 105,746 $ 109,650 $ 107,500
Non-utility subsidiary... 22,396 30,601 7,842
-------------------------------------------------------------------
Total................ $ 128,142 $ 140,251 $ 115,342
-------------------------------------------------------------------
(A) Intersegment revenues are recorded at prices
comparable to those of unaffiliated customers
and are affected by regulatory considerations.
59
9. Commitments and Contingencies
The Company has entered into purchase commitments in
connection with its construction program and the purchase of
necessary fuel supplies of coal and natural gas for its generating
units. The Company's construction expenditures for 1994 are
estimated at $143 million.
The Company acquires natural gas for boiler fuel under
approximately 900 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, 1993,
1992 and 1991, outstanding prepayments for gas, including the
amounts classified as current assets, under these contracts were
approximately $22,165,000, $24,543,000 and $20,851,000,
respectively. The Company may be required to make additional
prepayments in subsequent years. The Company expects to recover
these prepayments as fuel costs if unable to take the gas prior to
the expiration of the contracts.
At December 31, 1993, the Company held non-cancelable
operating leases covering approximately 1,523 coal hopper railcars.
Rental payments are charged to fuel expense and recovered through
the Company'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)
1994................ $4,749 1997................ $ 3,391
1995................ 3,850 1998................ 3,333
1996................ 3,508 1999 and beyond..... 78,703
Rental payments under operating leases were approximately $4.9
million in 1993, $3.6 million in 1992 and $3.0 million in 1991.
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.
The Company has entered into an agreement with an unrelated
third party to develop a natural gas storage facility. According
to that agreement, the Company made cash advances to the developer
amounting to approximately $24.4 million, as of December 31, 1993,
which is included in "Prepayments and other" in the accompanying
Balance Sheets.
The Company 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 the
60
Company to purchase power generated in a manufacturing process from
a qualified cogeneration facility ("QF"). The rate for such power
to be paid by the Company was approved by the Oklahoma Commission.
The rate generally consists of two components: one is a rate for
actual electricity purchased from the QF by the Company; the other
is a capacity charge which the Company must pay the QF for having
the capacity available. However, if no electrical power is made
available to the Company for a period of time (generally three
months), the Company's obligation to pay the capacity charge is
suspended. The total cost of cogeneration payments is currently
recoverable in rates from Oklahoma customers.
During 1993, 1992 and 1991, OG&E made total payments to
cogenerators of approximately $213.0 million, $179.4 million and
$170.5 million, of which $165.5 million, $101.6 million and $97.3
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: 1994 - $173 million, 1995 - $174
million, 1996 - $175 million, 1997 - $177 million and 1998 - $180
million.
The Company is a party to three separate actions brought by
the Environmental Protection Agency ("EPA") concerning cleanup of
disposal sites for hazardous waste. The Company was not the owner
or operator of those sites. Rather, the Company 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.
The Company has calculated that its portion of total waste disposed
at the sites is relatively minor. The cost of complying with the
EPA sanctions at these sites is difficult to estimate. However,
based on the relative percentage attributed to the Company and
other considerations, management believes the ultimate outcome of
these matters will not have a material adverse effect on the
Company's consolidated financial position or results of operations.
The Clean Air Act Amendments of 1990 among other things,
limits the amount of sulfur dioxide and nitrogen oxides that may be
released into the air. The Company will not be required to file
its compliance plan with the EPA until January 1996.
In 1992, OG&E began a voluntary review of information
contained in the annual report required under the Toxic Substance
Control Act ("TSCA") for 1991. The initial result of the review
revealed some discrepancies in operating practices and
documentation. The EPA was notified of these initial discrepancies
in December 1992. Because it was suspected that additional
discrepancies might be discovered during the continuing
review/audit, OG&E reached an agreement on January 12, 1993, with
the EPA, Region VI, concerning the notification and reporting
requirements of any newly discovered discrepancies.
61
After further investigation, OG&E reported in September 1993
numerous additional discrepancies to the EPA, Region VI. Many of
the discrepancies could be deemed violations of the regulations
under TSCA. Under the TSCA regulations, the EPA has the authority
to assess a maximum fine of up to $25,000 per day, and to treat
each day of violation as the basis for a separate fine. OG&E has
taken and is taking corrective action to remedy the discrepancies.
The position of the EPA and OG&E is that they are currently in
pre-settlement negotiations. No fines have been assessed as of
this date. Since this matter is currently being negotiated, OG&E
does not know the amount of fines that the EPA may seek. The
amount of the fine is dependent upon numerous interpretative issues
under the TSCA regulations and potentially could be in an amount
material to the Company's results of operations. However, at the
present time, the Company does not expect that the amount of the
fine will have a material effect on its results of operations based
primarily on having voluntarily reported the discrepancies to the
EPA coupled with the Company's efforts to remedy the discrepancies
and the lack of releases into the environment or harm to
individuals.
In the normal course of business, other lawsuits, claims,
environmental actions, and other governmental proceedings arise
against the Company. Management, after consultation with legal
counsel, does not anticipate that liabilities arising out of other
currently pending or threatened lawsuits and claims will have a
material adverse effect on the Company's consolidated financial
position or results of operations.
10. Rate Matters And Regulation
On February 25, 1994, the Oklahoma Commission issued an order
that, among other things, effectively lowered OG&E's rates to its
Oklahoma retail customers by approximately $14 million annually
(based on a test year ended June 30, 1991) and to refund
approximately $41.3 million. The $14 million annual reduction in
rates is expected to lower OG&E's rates to its Oklahoma customers
by approximately $17 million in 1994. With respect to the $41.3
million refund, $39.1 million is associated with revenues prior to
January 1, 1994, while the remaining $2.2 million relates to 1994.
During the first half of 1992 the Company participated in
settlement negotiations and offered a proposed refund and a
reduction in rates in an effort to reach settlement and conclude
the proceedings. As a result, the Company recorded an $18 million
provision for a potential refund in 1992. After receiving the
February 25, 1994 order, the Company recorded an additional
provision for rate refund of approximately $21.1 million in 1993,
(consisting of a $14.9 million reduction in revenue and $6.2
million in interest) which reduced net income by some $13 million or
$0.32 per share.
62
Enogex transports natural gas to OG&E for use at its gas-fired
generating units and performs related gas gathering activities for
OG&E. The entire $41.3 million refund relates to the Oklahoma
Commission's disallowance of a portion of the fees paid by OG&E to
Enogex for such services in the past. Of the approximately $17
million annual rate reduction, approximately $9.9 million reflects
the Oklahoma Commission's reduction of the amount to be recovered
by OG&E from its Oklahoma customers for the future performance of
such services by Enogex for OG&E.
11. Disclosures about Fair Value of Financial Instruments
The following methods and assumptions were used to estimate
the fair value of each class of financial instruments:
Cash and Cash Equivalents and Customer Deposits
The fair value of cash and cash equivalents and customer
deposits approximate the carrying amount due to their
short maturity.
Capitalization
The fair value of Long-term Debt and Preferred Stocks is
estimated based on quoted market prices and management's
estimate of current rates available for similar issues.
The fair value of Medium-term 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:
1993 1992
------------------- -------------------
Carrying Fair Carrying Fair
(dollars in thousands) Amount Value Amount Value
ASSETS:
CASH AND CASH EQUIVALENTS ...... $ 6,593 $ 6,593 $ 11,316 $ 11,316
_________________________________________________________________________________
LIABILITIES:
CUSTOMER DEPOSITS .............. $ 19,353 $ 19,353 $ 17,891 $ 17,891
_________________________________________________________________________________
CAPITALIZATION:
First Mortgage Bonds ........... $716,610 $749,684 $731,254 $740,755
Industrial Trust Bonds ......... 32,400 32,604 32,700 32,746
Medium-term Notes .............. 90,000 100,486 90,000 95,715
Preferred Stock:
4% Series through 5.34% Series-
838,663 Shares outstanding ... 49,973 34,523 49,973 31,332
_________________________________________________________________________________
Total ....................... $888,983 $917,297 $903,927 $900,548
_________________________________________________________________________________
63
In May 1993, the Financial Accounting Standards Board issued
SFAS No. 115, "Accounting for Certain Investments in Debt and
Equity Securities." This statement addresses the accounting and
reporting for investments in equity securities that have readily
determinable fair values and for all investments in debt
securities. Adoption of SFAS No. 115 is required for fiscal
years beginning after December 15, 1993, with earlier application
permitted for which annual financial statements have not
previously been issued. The Company will adopt this new standard
effective January 1, 1994, and believes these costs will not have
a material impact on its consolidated financial position or
results of operations.
64
Report of Independent Public Accountants
----------------------------------------
To the Shareowners of
Oklahoma Gas and Electric Company:
We have audited the accompanying consolidated balance sheets
and statements of capitalization of Oklahoma Gas and Electric
Company (an Oklahoma corporation) and its subsidiaries as of
December 31, 1993, 1992 and 1991, 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 Oklahoma Gas and Electric Company and its subsidiaries as of
December 31, 1993, 1992 and 1991, and the results of their
operations and their cash flows for the years then ended in
conformity with generally accepted accounting principles.
Arthur Andersen & Co.
Oklahoma City, Oklahoma,
February 28, 1994
65
Report of Management
--------------------
To Our Shareowners:
The management of Oklahoma Gas and Electric Company 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.
66
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:
Dec 31 Sep 30 Jun 30 Mar 31
Quarter ended (dollars in thousands except per share data)
-------------------------------------------------------------------------
Operating revenues..... 1993 $301,392 $500,639 $341,799 $303,422
1992 304,093 443,327 306,341 261,223
1991 284,619 426,580 329,375 274,196
-------------------------------------------------------------------------
Operating income....... 1993 $ 18,899 $111,576 $ 39,457 $ 25,221
1992 32,043 94,319 36,072 14,570
1991 30,870 93,646 55,968 30,603
-------------------------------------------------------------------------
Net income (loss)...... 1993 $ (3,619) $ 90,810 $ 20,396 $ 6,690
1992 10,629 76,035 17,015 (3,967)
1991 12,260 75,255 33,474 12,927
-------------------------------------------------------------------------
Earnings (loss)
available for common.. 1993 $ (4,199) $ 90,231 $ 19,817 $ 6,111
1992 10,050 75,456 16,436 (4,547)
1991 11,680 74,676 32,895 12,348
-------------------------------------------------------------------------
Earnings (loss) per
average common share.. 1993 $ (0.10) $ 2.24 $ 0.49 $ 0.15
1992 0.25 1.87 0.41 (0.11)
1991 0.29 1.85 0.82 0.31
-------------------------------------------------------------------------
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.
---------------------------------------------------------
Not applicable.
67
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 OG&E filed copies of a
definitive proxy statement with the Securities and Exchange
Commission on or about March 28, 1994. 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:
Consolidated Balance Sheets at December 31, 1993, 1992 and
1991
Consolidated Statements of Income for the years ended
December 31, 1993, 1992 and 1991
Consolidated Statements of Retained Earnings for the years
ended December 31, 1993, 1992 and 1991
Consolidated Statements of Capitalization at December 31,
1993, 1992 and 1991
Consolidated Statements of Cash Flows for the years ended
December 31, 1993, 1992 and 1991
Notes to Consolidated Financial Statements
Report of Independent Public Accountants
Report of Management
68
Supplementary Data
------------------
Interim Consolidated Financial Information
2. Financial Statement Schedules (included in Part IV) Page
------------------------------------------------------ ----
Schedule V - Property, plant and equipment 75
Schedule VI - Accumulated depreciation, depletion,
and amortization of property, plant,
and equipment 76
Schedule VIII - Valuation and qualifying accounts 77
Schedule IX - Short-term borrowings 78
Schedule X - Supplementary income statement
information 79
Report of Independent Public Accountants 80
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 4.01 to the Company's Post-
Effective Amendment No. Two to Registration
Statement No. 2-94973, and incorporated by
reference herein)
3.02 By-laws. (Filed as Exhibit 4.02 to Post-Effective
Amendment No. Two to Registration Statement No.
2-94973 and incorporated by reference herein)
4.01 Copy of Trust Indenture, dated February 1, 1945,
from OG&E to The First National Bank and Trust Company
of Oklahoma City, Trustee. (Filed as Exhibit 7-A to
Registration Statement No. 2-5566 and incorporated by
reference herein)
4.02 Copy of Supplemental Trust Indenture, dated
December 1, 1948, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 7.03 to Registration Statement No.
2-7744 and incorporated by reference herein)
69
4.03 Copy of Supplemental Trust Indenture, dated
June 1, 1949, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.03
to Registration Statement No. 2-7964 and
incorporated by reference herein)
4.04 Copy of Supplemental Trust Indenture, dated
May 1, 1950, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.04
to Registration Statement No. 2-8421 and
incorporated by reference herein)
4.05 Copy of Supplemental Trust Indenture, dated
March 1, 1952, a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to
Registration Statement No. 2-9415 and
incorporated by reference herein)
4.06 Copy of Supplemental Trust Indenture, dated
June 1, 1955, being a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.07 to
Registration Statement No. 2-12274 and
incorporated by reference herein)
4.07 Copy of Supplemental Trust Indenture, dated
January 1, 1957, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.07
to Registration Statement No. 2-14115 and
incorporated by reference herein)
4.08 Copy of Supplemental Trust Indenture, dated
June 1, 1958, being a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.09 to
Registration Statement No. 2-19757 and
incorporated by reference herein)
4.09 Copy of Supplemental Trust Indenture, dated
March 1, 1963, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.09
to Registration Statement No. 2-23127 and
incorporated by reference herein)
4.10 Copy of Supplemental Trust Indenture, dated
March 1, 1965, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.10
to Registration Statement No. 2-25808 and
incorporated by reference herein)
70
4.11 Copy of Supplemental Trust Indenture, dated
January 1, 1967, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.11
to Registration Statement No. 2-27854 and
incorporated by reference herein)
4.12 Copy of Supplemental Trust Indenture, dated
January 1, 1968, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.12
to Registration Statement No. 2-31010 and
incorporated by reference herein)
4.13 Copy of Supplemental Trust Indenture, dated
January 1, 1969, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.13
to Registration Statement No. 2-35419 and
incorporated by reference herein)
4.14 Copy of Supplemental Trust Indenture, dated
January 1, 1970, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.14
to Registration Statement No. 2-42393 and
incorporated by reference herein)
4.15 Copy of Supplemental Trust Indenture, dated
January 1, 1972, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.15
to Registration Statement No. 2-49612 and
incorporated by reference herein)
4.16 Copy of Supplemental Trust Indenture, dated
January 1, 1974, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.16
to Registration Statement No. 2-52417 and
incorporated by reference herein)
4.17 Copy of Supplemental Trust Indenture, dated
January 1, 1975, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.17
to Registration Statement No. 2-55085 and
incorporated by reference herein)
4.18 Copy of Supplemental Trust Indenture, dated
January 1, 1976, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.18
to Registration Statement No. 2-57730 and
incorporated by reference herein)
71
4.19 Copy of Supplemental Trust Indenture, dated
September 14, 1976, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 2.19 to Registration Statement No.
2-59887 and incorporated by reference herein)
4.20 Copy of Supplemental Trust Indenture, dated
January 1, 1977, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.20
to Registration Statement No. 2-59887 and
incorporated by reference herein)
4.21 Copy of Supplemental Trust Indenture, dated
November 1, 1977, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.21 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.22 Copy of Supplemental Trust Indenture, dated
December 1, 1977, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.22 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.23 Copy of Supplemental Trust Indenture, dated
February 1, 1980, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.23 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.24 Copy of Supplemental Trust Indenture, dated
April 15, 1982, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.24
to the Company's Form 10-K Report, File No. 1-1097,
for the year ended December 31, 1982, and incorporated
by reference herein)
4.25 Copy of Supplemental Trust Indenture, dated
August 15, 1986, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.25
to the Company's Form 10-K Report, File No. 1-1097,
for the year ended December 31, 1986 and incorporated
by reference herein)
4.26 Copy of Supplemental Trust Indenture, dated
March 1, 1987, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.26
to the Company's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
72
4.27 Copy of form of Medium-Term Note of Enogex Inc.
due December 21, 1995, and December 21, 1998.
(Filed as Exhibit 4.27 to the Company's Form 10-K
Report for the year ended December 31, 1988, File
No. 1-1097, and incorporated by reference herein)
4.28 Copy of Supplemental Trust Indenture, dated
November 15, 1990, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.28
to the Company's Form 10-K Report for the year
ended December 31, 1990, File No. 1-1097, and
incorporated by reference herein)
4.29 Copy of Supplemental Trust Indenture, dated
December 9, 1991, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.29 to
the Company's Form 10-K Report for the year ended
December 31, 1991, 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 (Exhibit 10.10
hereto), 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 (Exhibit 10.04 hereto).
(Filed as Exhibit 5.28 to Registration Statement
No. 2-62208 and incorporated by reference herein)
10.04 Lease of Railroad Equipment dated February 1, 1979,
between Mercantile-Safe Deposit and Trust Company
and OG&E. (Filed as Exhibit 5.30 to Registration
Statement No.2-64965 and incorporated by reference
herein)
73
10.05 Participation Agreement dated as of January 1, 1980,
among First National Bank and Trust Company of
Oklahoma City, Thrall Car Manufacturing Company,
OG&E and other parties, including Lease of Railroad
Equipment dated January 1, 1980, between
Mercantile-Safe Deposit and Trust Company and
OG&E. (Filed as Exhibit 10.32 to the Company's
Form 10-K Report for the year ended December 31,
1980, File No. 1-1097, and incorporated by reference
herein)
10.06 Participation Agreement dated January 1, 1981,
among The First National Bank and Trust Company
of Oklahoma City, Thrall Car Manufacturing Company,
OG&E and other parties, including Lease for
Railroad Equipment dated January 1, 1981, between
Wells Fargo Equipment Leasing Corporation and OG&E.
(Filed as Exhibit 20.01 to the Company's Form 10-Q
for June 30, 1981, File No. 1-1097, and incorporated
by reference herein)
10.07 Agreement for Guaranty, dated November 30, 1982,
between OG&E and Railcar Maintenance Company. (Filed
as Exhibit 10.34 to OG&E's Form 10-K Report for
the year ended December 31, 1982, File No. 1-1097,
and incorporated by reference herein)
10.08 Form of Deferred Compensation Agreement for Directors,
as amended. (Filed as Exhibit 10.08 to the Company's
Form 10-K Report for the year ended December 31, 1992,
File No. 1-1097, and incorporated by reference herein)
10.09 Restricted Stock Plan of the Company. (Filed as
Exhibit 10.36 to the Company's Form 10-K Report for
the year ended December 31, 1986, File No. 1-1097, and
incorporated by reference herein)
10.10 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)
10.11 Gas Service Agreement dated January 1, 1988, between
OG&E and Oklahoma Natural Gas Company. (Filed as
Exhibit 10.26 to the Company's Form 10-K Report
for the year ended December 31, 1987, File No. 1-1097,
and incorporated by reference herein)
10.12 Company's Restoration of Retirement Income Plan, as
amended.
74
10.13 Company's Restoration of Retirement Savings Plan.
10.14 Gas Service Agreement dated July 23, 1987, between
OG&E and Arkla Services Company. (Filed as Exhibit
10.29 to the Company's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
10.15 Company's Supplemental Executive Retirement Plan.
10.16 Company's Annual Incentive Compensation Plan.
23.01 Consent of Arthur Andersen & Co.
24.01 Power of Attorney.
99.01 1993 Form 11-K Annual Report for Oklahoma Gas
and Electric Company Employees' Retirement Savings
Plan.
Executive Compensation Plans and Arrangements
---------------------------------------------
10.08 Form of Deferred Compensation Agreement for Directors,
as amended. (Filed as Exhibit 10.08 to the Company's
Form 10-K Report for the year ended December 31, 1992,
File No. 1-1097, and incorporated by reference herein)
10.09 Restricted Stock Plan of the Company. (Filed as
Exhibit 10.36 to the Company's Form 10-K Report for the
year ended December 31, 1986, File No. 1-1097, and
incorporated by reference herein)
10.12 Company's Restoration of Retirement Income Plan, as
amended.
10.13 Company's Restoration of Retirement Savings Plan.
10.15 Company's Supplemental Executive Retirement Plan.
10.16 Company's Annual Incentive Compensation Plan.
(b) Reports on Form 8-K
------------------------
Item 5. Other Events, dated October 1, 1993.
75
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE V - Property, Plant & Equipment
Column A Column B Column C Column D Column E Column F
Balance Retire-
Beginning Additions ments Other Balance
Classification of Year At Cost At Cost Changes(a) End of Year
-------------- --------- --------- ------- ---------- -----------
(Thousands)
FOR THE YEAR ENDED
DECEMBER 31, 1993
Electric Utility Plant:
Intangible $ 948 $ 20 $ - $ - $ 968
Production 1,490,406 9,891 (2,558) 11,728 1,509,467
Transmission 476,279 14,935 (1,652) 3,987 493,549
Distribution 1,062,366 71,881 (11,056) 8,121 1,131,312
General 179,721 13,302 (2,477) 707 191,253
Property Under Capital Leases 7,000 (1,781) - - 5,219
Plant Held for Future Use 10,961 - - 3 10,964
Construction Work in Progress 32,667 (2,502) - (105) 30,060
---------- -------- -------- ------- ----------
Total Electric Utility Plant $3,260,348 $105,746 $(17,743) $24,441 $3,372,792
Non-Utility Plant 248,387 22,396 (1,761) 48,269 317,291
---------- -------- -------- ------- ----------
Total Property, Plant & Equipment $3,508,735 $128,142 $(19,504) $72,710 $3,690,083
========== ======== ======== ======= ==========
FOR THE YEAR ENDED
DECEMBER 31, 1992
Electric Utility Plant:
Intangible $ 674 $ 274 $ - $ - $ 948
Production 1,487,146 13,483 (10,224) 1 1,490,406
Transmission 456,973 25,313 (4,023) (1,984) 476,279
Distribution 1,001,943 72,274 (13,835) 1,984 1,062,366
General 170,377 12,218 (2,873) (1) 179,721
Property Under Capital Leases 8,673 (1,673) - - 7,000
Plant Held for Future Use 10,916 - - 45 10,961
Construction Work in Progress 45,135 (12,239) - (229) 32,667
---------- -------- -------- ------- ----------
Total Electric Utility Plant $3,181,837 $109,650 $(30,955) $ (184) $3,260,348
Non-Utility Plant 219,809 30,601 (2,163) 140 248,387
---------- -------- -------- ------- ----------
Total Property, Plant & Equipment $3,401,646 $140,251 $(33,118) $ (44) $3,508,735
========== ======== ======== ======= ==========
FOR THE YEAR ENDED
DECEMBER 31, 1991
Electric Utility Plant:
Intangible $ 654 $ 20 $ - $ - $ 674
Production 1,438,532 49,859 (1,245) - 1,487,146
Transmission 447,345 8,495 (1,397) 2,530 456,973
Distribution 954,500 58,527 (8,554) (2,530) 1,001,943
General 159,101 14,268 (2,992) - 170,377
Property Under Capital Leases 4,662 4,011 - - 8,673
Plant Held for Future Use 10,668 - - 248 10,916
Construction Work in Progress 73,216 (27,680) - (401) 45,135
---------- -------- -------- ------- ----------
Total Electric Utility Plant $3,088,678 $107,500 $(14,188) $ (153) $3,181,837
Non-Utility Plant 213,491 7,842 (1,715) 191 219,809
---------- -------- --------- ------- ----------
Total Property, Plant & Equipment $3,302,169 $115,342 $(15,903) $ 38 $3,401,646
========== ======== ========= ======= ==========
(a) Column E includes transfers between electric plant accounts and the depletion on gas wells.
76
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE VI - Accumulated Depreciation, Depletion and Amortization
of Property, Plant and Equipment
Column A Column B Column C Column D Column E Column F
Additions Charged to Salvage
Balance Costs and Expenses Net of
Beginning Depre- Clearing Retire- Removal Other Balance
Description of Year ciation Accounts ments Costs Changes End of Year
----------- --------- --------- -------- -------- ------- ------- -----------
(Thousands)
FOR THE YEAR ENDED
DECEMBER 31, 1993
Electric Utility Plant:
Intangible $ 315 $ 44 $ - $ - $ - $ (26)a $ 333
Production 649,578 49,162 - (2,558) (324) - 695,858
Transmission 184,622 14,338 - (1,653) 1,721 - 199,028
Distribution 317,201 33,637 - (11,056) 51 - 339,833
General 60,659 5,972 1,329 (2,477) (362) 302 65,423
---------- -------- -------- --------- -------- ------ ----------
Total Electric Utility Plant $1,212,375 $103,153 $ 1,329 $(17,744) $ 1,086 $ 276 $1,300,475
Non-Utility Plant 55,097 15,200 - (885) - 340 69,752
---------- -------- -------- --------- -------- ------ ----------
Total Property, Plant & Equipment $1,267,472 $118,353 $ 1,329 $(18,629) $ 1,086 $ 616 $1,370,227
========== ======== ======== ========= ======== ====== ==========
FOR THE YEAR ENDED
DECEMBER 31, 1992
Electric Utility Plant:
Intangible $ 286 $ 32 $ - $ - $ - $ (3)a $ 315
Production 608,107 48,827 - (10,224) 2,692 176 649,578
Transmission 169,551 13,672 - (4,023) 5,404 18 184,622
Distribution 298,689 31,826 - (13,835) 521 - 317,201
General 56,397 5,590 1,377 (2,873) 100 68 60,659
---------- -------- -------- --------- -------- ------ ----------
Total Electric Utility Plant $1,133,030 $ 99,947 $ 1,377 $(30,955) $ 8,717 $ 259 $1,212,375
Non-Utility Plant 45,585 10,169 - (798) - 141 55,097
---------- -------- -------- --------- -------- ------ ----------
Total Property, Plant & Equipment $1,178,615 $110,116 $ 1,377 $(31,753) $ 8,717 $ 400 $1,267,472
========== ======== ======== ========= ======== ====== ==========
FOR THE YEAR ENDED
DECEMBER 31, 1991
Electric Utility Plant:
Intangible $ 272 $ 36 $ - $ - $ - $ (22)a $ 286
Production 562,533 48,030 - (1,245) (418) (793) 608,107
Transmission 157,487 13,350 - (1,397) 111 - 169,551
Distribution 276,918 30,212 - (8,554) 113 - 298,689
General 53,184 5,032 1,301 (2,992) (91) (37) 56,397
---------- -------- --------- --------- -------- ------ ----------
Total Electric Utility Plant $1,050,394 $ 96,660 $ 1,301 $(14,188) $ (285) $(852) $1,133,030
Non-Utility Plant 36,545 9,764 - (915) - 191 45,585
---------- -------- -------- --------- -------- ------ ----------
Total Property, Plant & Equipment $1,086,939 $106,424 $ 1,301 $(15,103) $ (285) $(661) $1,178,615
========== ======== ======== ========= ======== ====== ==========
(a) Expiration of limited-term franchises
77
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE VIII - Valuation and Qualifying Accounts
Column A Column B Column C Column D Column E
Balance Charged to Charged to Balance
Beginning Cost and Other End of
Description of Year Expenses Accounts Deductions Year
----------- --------- ---------- ---------- ---------- --------
(Thousands)
1993
Reserve for
Uncollectible Accounts $4,039 $6,669 - $6,638 $4,070
1992
Reserve for
Uncollectible Accounts $3,775 $7,549 - $7,285 $4,039
1991
Reserve for
Uncollectible Accounts $3,108 $7,583 - $6,916 $3,775
78
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE IX - Short-Term Borrowings
Maximum Average Weighted
Weighted Amount Amount Average
Balance Average Outstanding Outstanding Interest
Category of Aggregate at end Interest During During Rate During
Short-Term Borrowings of Period Rate the Period the Period(a) the Period(b)
--------------------- --------- -------- ----------- ------------- -------------
(Thousands except Percentages)
December 31, 1993
Notes payable to banks - - - - -
Payable to holders of
commercial paper $47,000 3.5% $136,600 $ 62,500 3.6%
December 31, 1992
Notes payable to banks - - - - -
Payable to holders of
commercial paper $26,000 3.4% $111,900 $ 52,214 4.3%
December 31, 1991
Notes payable to banks - 8.9% $ 14,800 $ 41 8.9%
Payable to holders of
commercial paper $12,500 5.1% $105,200 $ 44,376 6.6%
(a) Average amount outstanding during the period is computed by dividing the
total of daily outstanding principal balances by 360.
(b) Average interest rates for the year are computed by dividing the actual
short-term interest expense, including commitment fees, by the average
short-term debt outstanding.
79
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE X - Supplementary Income Statement Information
Column A Column B
----------------------------------------------- -------------------------------
Year Ended December 31,
Item 1993 1992 1991
----------------------------------------------- ------- ------- -------
(Thousands)
Maintenance $78,665 $72,439 $71,868
Depreciation and amortization of intangible assets (a) (a) (a)
Taxes other than payroll and income taxes:
Real and personal property $33,613 $34,659 $34,672
Franchise (a) (a) (a)
Royalties (a) (a) (a)
Advertising costs (a) (a) (a)
(a) Amounts are not presented as such amounts are less than 1% of operating revenues.
80
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Oklahoma Gas and Electric Company:
We have audited in accordance with generally accepted auditing
standards, the consolidated financial statements of Oklahoma Gas
and Electric Company included in this Form 10-K, and have issued
our report thereon dated February 28, 1994. Our audits were made
for the purpose of forming an opinion on those statements taken
as a whole. The schedules listed on Page 68, Item 14 (a) 2. are
the responsibility of the Company's management and are presented
for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic financial
statements. These schedules have been subjected to the auditing
procedures applied in the audits of the basic financial state-
ments and, in our opinion, fairly state in all material respects
the financial data required to be set forth therein in relation
to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Oklahoma City, Oklahoma,
February 28, 1994
81
SIGNATURES
Pursuant to the requirements of the Securities and 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 28th day of March, 1994.
OKLAHOMA GAS & ELECTRIC COMPANY
(REGISTRANT)
/s/ J. G. Harlow, Jr.
By J. G. Harlow, Jr.
Chairman of the Board
and President
Pursuant to the requirements of the Securities and 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/ J. G. Harlow, Jr.
J. G. Harlow, Jr. Principal Executive
Officer and Director; March 28, 1994
/s/ A. M. Strecker
A. M. Strecker Principal Financial
Officer; and March 28, 1994
/s/ B. G. Bunce
B. G. Bunce Principal Accounting
Officer. March 28, 1994
Herbert H. Champlin Director;
William E. Durrett Director;
Martha W. Griffin Director;
Hugh L. Hembree, III Director;
John F. Snodgrass Director;
Bill Swisher Director;
John A. Taylor Director; and
Ronald H. White, M.D. Director.
/s/ J. G. Harlow, Jr.
By J. G. Harlow, Jr. (attorney-in-fact) March 28, 1994
E X H I B I T I N D E X
Exhibit No. Description
----------- -----------
3.01 Copy of Restated Certificate of Incorporation.
(Filed as Exhibit 4.01 to the Company's Post-
Effective Amendment No. Two to Registration
Statement No. 2-94973, and incorporated by
reference herein)
3.02 By-laws. (Filed as Exhibit 4.02 to Post-Effective
Amendment No. Two to Registration Statement No.
2-94973 and incorporated by reference herein)
4.01 Copy of Trust Indenture, dated February 1, 1945,
from OG&E to The First National Bank and Trust Company
of Oklahoma City, Trustee. (Filed as Exhibit 7-A to
Registration Statement No. 2-5566 and incorporated by
reference herein)
4.02 Copy of Supplemental Trust Indenture, dated
December 1, 1948, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 7.03 to Registration Statement No.
2-7744 and incorporated by reference herein)
4.03 Copy of Supplemental Trust Indenture, dated
June 1, 1949, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.03
to Registration Statement No. 2-7964 and
incorporated by reference herein)
4.04 Copy of Supplemental Trust Indenture, dated
May 1, 1950, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.04
to Registration Statement No. 2-8421 and
incorporated by reference herein)
4.05 Copy of Supplemental Trust Indenture, dated
March 1, 1952, a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to
Registration Statement No. 2-9415 and
incorporated by reference herein)
4.06 Copy of Supplemental Trust Indenture, dated
June 1, 1955, being a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.07 to
Registration Statement No. 2-12274 and
incorporated by reference herein)
4.07 Copy of Supplemental Trust Indenture, dated
January 1, 1957, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.07
to Registration Statement No. 2-14115 and
incorporated by reference herein)
4.08 Copy of Supplemental Trust Indenture, dated
June 1, 1958, being a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.09 to
Registration Statement No. 2-19757 and
incorporated by reference herein)
4.09 Copy of Supplemental Trust Indenture, dated
March 1, 1963, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.09
to Registration Statement No. 2-23127 and
incorporated by reference herein)
4.10 Copy of Supplemental Trust Indenture, dated
March 1, 1965, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.10
to Registration Statement No. 2-25808 and
incorporated by reference herein)
4.11 Copy of Supplemental Trust Indenture, dated
January 1, 1967, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.11
to Registration Statement No. 2-27854 and
incorporated by reference herein)
4.12 Copy of Supplemental Trust Indenture, dated
January 1, 1968, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.12
to Registration Statement No. 2-31010 and
incorporated by reference herein)
4.13 Copy of Supplemental Trust Indenture, dated
January 1, 1969, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.13
to Registration Statement No. 2-35419 and
incorporated by reference herein)
4.14 Copy of Supplemental Trust Indenture, dated
January 1, 1970, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.14
to Registration Statement No. 2-42393 and
incorporated by reference herein)
4.15 Copy of Supplemental Trust Indenture, dated
January 1, 1972, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.15
to Registration Statement No. 2-49612 and
incorporated by reference herein)
4.16 Copy of Supplemental Trust Indenture, dated
January 1, 1974, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.16
to Registration Statement No. 2-52417 and
incorporated by reference herein)
4.17 Copy of Supplemental Trust Indenture, dated
January 1, 1975, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.17
to Registration Statement No. 2-55085 and
incorporated by reference herein)
4.18 Copy of Supplemental Trust Indenture, dated
January 1, 1976, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.18
to Registration Statement No. 2-57730 and
incorporated by reference herein)
4.19 Copy of Supplemental Trust Indenture, dated
September 14, 1976, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 2.19 to Registration Statement No.
2-59887 and incorporated by reference herein)
4.20 Copy of Supplemental Trust Indenture, dated
January 1, 1977, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.20
to Registration Statement No. 2-59887 and
incorporated by reference herein)
4.21 Copy of Supplemental Trust Indenture, dated
November 1, 1977, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.21 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.22 Copy of Supplemental Trust Indenture, dated
December 1, 1977, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.22 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.23 Copy of Supplemental Trust Indenture, dated
February 1, 1980, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.23 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.24 Copy of Supplemental Trust Indenture, dated
April 15, 1982, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.24
to the Company's Form 10-K Report, File No. 1-1097,
for the year ended December 31, 1982, and incorporated
by reference herein)
4.25 Copy of Supplemental Trust Indenture, dated
August 15, 1986, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.25
to the Company's Form 10-K Report, File No. 1-1097,
for the year ended December 31, 1986 and incorporated
by reference herein)
4.26 Copy of Supplemental Trust Indenture, dated
March 1, 1987, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.26
to the Company's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
4.27 Copy of form of Medium-Term Note of Enogex Inc.
due December 21, 1995, and December 21, 1998.
(Filed as Exhibit 4.27 to the Company's Form 10-K
Report for the year ended December 31, 1988, File
No. 1-1097, and incorporated by reference herein)
4.28 Copy of Supplemental Trust Indenture, dated
November 15, 1990, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.28
to the Company's Form 10-K Report for the year
ended December 31, 1990, File No. 1-1097, and
incorporated by reference herein)
4.29 Copy of Supplemental Trust Indenture, dated
December 9, 1991, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.29 to
the Company's Form 10-K Report for the year ended
December 31, 1991, 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 (Exhibit 10.10
hereto), 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 (Exhibit 10.04 hereto).
(Filed as Exhibit 5.28 to Registration Statement
No. 2-62208 and incorporated by reference herein)
10.04 Lease of Railroad Equipment dated February 1, 1979,
between Mercantile-Safe Deposit and Trust Company
and OG&E. (Filed as Exhibit 5.30 to Registration
Statement No.2-64965 and incorporated by reference
herein)
10.05 Participation Agreement dated as of January 1, 1980,
among First National Bank and Trust Company of
Oklahoma City, Thrall Car Manufacturing Company,
OG&E and other parties, including Lease of Railroad
Equipment dated January 1, 1980, between
Mercantile-Safe Deposit and Trust Company and
OG&E. (Filed as Exhibit 10.32 to the Company's
Form 10-K Report for the year ended December 31,
1980, File No. 1-1097, and incorporated by reference
herein)
10.06 Participation Agreement dated January 1, 1981,
among The First National Bank and Trust Company
of Oklahoma City, Thrall Car Manufacturing Company,
OG&E and other parties, including Lease for
Railroad Equipment dated January 1, 1981, between
Wells Fargo Equipment Leasing Corporation and OG&E.
(Filed as Exhibit 20.01 to the Company's Form 10-Q
for June 30, 1981, File No. 1-1097, and incorporated
by reference herein)
10.07 Agreement for Guaranty, dated November 30, 1982,
between OG&E and Railcar Maintenance Company. (Filed
as Exhibit 10.34 to OG&E's Form 10-K Report for
the year ended December 31, 1982, File No. 1-1097,
and incorporated by reference herein)
10.08 Form of Deferred Compensation Agreement for Directors,
as amended. (Filed as Exhibit 10.08 to the Company's
Form 10-K Report for the year ended December 31, 1992,
File No. 1-1097, and incorporated by reference herein)
10.09 Restricted Stock Plan of the Company. (Filed as
Exhibit 10.36 to the Company's Form 10-K Report for
the year ended December 31, 1986, File No. 1-1097, and
incorporated by reference herein)
10.10 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)
10.11 Gas Service Agreement dated January 1, 1988, between
OG&E and Oklahoma Natural Gas Company. (Filed as
Exhibit 10.26 to the Company's Form 10-K Report
for the year ended December 31, 1987, File No. 1-1097,
and incorporated by reference herein)
10.12 Company's Restoration of Retirement Income Plan, as
amended.
10.13 Company's Restoration of Retirement Savings Plan.
10.14 Gas Service Agreement dated July 23, 1987, between
OG&E and Arkla Services Company. (Filed as Exhibit
10.29 to the Company's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
10.15 Company's Supplemental Executive Retirement Plan.
10.16 Company's Annual Incentive Compensation Plan.
23.01 Consent of Arthur Andersen & Co.
24.01 Power of Attorney.
99.01 1993 Form 11-K Annual Report for Oklahoma Gas
and Electric Company Employees' Retirement Savings
Plan.