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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, 1995 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: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which
so registered each class is registered
------------------- ------------------------------
Common Stock New York Stock Exchange
Common Stock Pacific Stock Exchange
Preferred Stock 4% Cumulative 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. [ ]
As of February 29, 1996, Common Shares outstanding were 40,371,409. Based
upon the closing price on the New York Stock Exchange on February 29, 1996, the
aggregate market value of the voting stock held by nonaffiliates of the Company
was: Common Stock $1,658,173,234 and 4% Cumulative Preferred Stock $5,590,308.
The proxy statement for the 1996 annual meeting of shareowners is
incorporated by reference into Part III of this Report.
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TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
Item 1. Business. ..................................................... 1
The Company ................................................... 1
Electric Operations............................................ 2
General 2
Finance and Construction..................................... 5
Regulation and Rates......................................... 7
Rate Structure, Load Growth and Related Matters.............. 9
Fuel Supply.................................................. 11
Environmental Matters.......................................... 13
Enogex 14
Item 2. Properties..................................................... 17
Item 3. Legal Proceedings. ............................................ 18
Item 4. Submission of Matters to a Vote of Security Holders............ 21
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters...................................... 25
Item 6. Selected Financial Data........................................ 26
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition....................... 27
Item 8. Financial Statements and Supplementary Data.................... 36
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure ................................ 69
PART III
Item 10. Directors and Executive Officers of the Registrant............. 69
Item 11. Executive Compensation......................................... 69
Item 12. Security Ownership of Certain Beneficial
Owners and Management.................................... 69
Item 13. Certain Relationships and Related Transactions................. 69
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K...................................... 69
i
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
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 5,647,300 kilowatts. Enogex owns
and operates over 3,000 miles of natural gas transmission and gathering
pipelines, has interests in five gas processing plants, markets natural gas and
natural gas products and invests in the exploration and production of natural
gas. At the end of 1995, Enogex had 290 members and OG&E had 2,475 members.
OG&E's executive offices are located at 101 North Robinson, P.O. Box 321,
Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
On February 25, 1994, the Oklahoma Corporation Commission ("OCC") issued an
order that, among other things, effectively lowered OG&E's rates to its Oklahoma
retail customers by approximately $17 million annually and required OG&E to
refund approximately $41.3 million. Of the $41.3 million refund, $39.1 million
was associated with revenues prior to January 1, 1994, while the remaining $2.2
million related to 1994. See "Regulation and Rates - Recent Regulatory Matters"
for a further discussion of this order.
In 1994, the Company restructured and redesigned its operations to reduce
costs in order to more favorably position itself for the competitive electric
utility environment. As part of this process, the Company implemented a
Voluntary Early Retirement Package ("VERP") and a severance package in 1994.
These two packages reduced the Company's workforce by approximately 900
employees.
In response to an application filed by OG&E on August 9, 1994, the OCC
issued an order on October 26, 1994, that permitted OG&E to: (1) establish a
regulatory asset in connection with the costs associated with the workforce
reduction; (2) amortize the December 31, 1994, balance of the regulatory asset
over 26 months; and (3) reduce OG&E's electric rates by approximately $15
million annually, effective January 1995. In 1995, the labor savings
substantially offset the amortization of the regulatory asset and the annual
rate reduction of $15 million. See "Regulation and Rates - Recent Regulatory
Matters" and Note 10 of Notes to Consolidated Financial Statements for a further
discussion of the OCC's orders in February and October 1994.
On July 19, 1995, OG&E announced plans to create a holding company
structure with OGE Energy Corp. becoming the parent company of OG&E. At a
special meeting of shareowners on November 16, 1995, OG&E shareowners approved
the new holding company structure. Upon receiving
regulatory approval, which is currently expected by mid-1996, OG&E's common
stock will be exchanged on a share-for-share basis for common stock of OGE
Energy Corp. and OG&E will become a subsidiary of OGE Energy Corp. See
"Regulation and Rates - Recent Regulatory Matters" and "Supplementary Data -
Unaudited Pro Forma Financial Information" for a further discussion of this
matter.
ELECTRIC OPERATIONS
GENERAL
OG&E furnishes retail electric service in 274 communities and their
contiguous rural and suburban areas. During 1995, five 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 1.7 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 279 communities served,
248 are located in Oklahoma and 31 in Arkansas. Approximately 91 percent of
total electric operating revenues for the year ended December 31, 1995, 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 5,130 megawatts, and occurred on July 12, 1995.
OG&E's native load was approximately 4,793 megawatts on July 12, 1995, resulting
in a capacity margin of approximately 21.5 percent. As reflected in the table
below and in the operating statistics on page 4, total kilowatt-hour sales
increased 7.0 percent in 1995 as compared to a decrease of 9.0 percent in 1994
and a 0.3 percent decrease in 1993. In 1995, kilowatt-hour sales to OG&E
customers ("system sales") increased slightly due to continued customer growth.
Sales to other utilities ("off-system sales") increased significantly, 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 1994 and 1993, factors
which resulted in variations in total kilowatt-hour sales included: (i) the
decrease in off-system sales in 1994, (ii) continued customer growth; and (iii)
more normal weather in 1993.
Variations in kilowatt-hour sales for the three years are reflected in the
following table:
SALES (Millions of kWh)
Inc/ Inc/ Inc/
1995 (Dec) 1994 (Dec) 1993 (Dec)
- ------------------------------------------------------------------------------
System Sales 20,828 0.9% 20,642 2.2% 20,202 5.0%
Off-System Sales 1,852 232.6% 557 (82.1%) 3,104 (25.0%)
------ ------ ------
Total Sales 22,680 7.0% 21,199 (9.0%) 23,306 (0.3%)
====== ====== ======
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.
2
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. 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. Also, numerous states are considering proposals to require "retail
wheeling" which is the delivery of power generated by a third party to retail
customers. The Energy Act, these proposals 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. See "Regulation and Rates - Recent
Regulatory Matters" for a further discussion of this matter.
Electric and magnetic fields ("EMFs") surround all electric tools and
appliances, internal home wiring and external power lines such as those owned by
OG&E. During the last several years considerable attention has focused on
possible health effects from EMFs. While some recent studies indicate a possible
correlation, other similar studies indicate no correlation between EMFs and
health effects. The nation's electric utilities, including OG&E, have
participated with the Electric Power Research Institute ("EPRI") in the
sponsorship of more than $75 million in research to determine the possible
health effects of EMFs. In addition, the Edison Electric Institute ("EEI") will
help fund $65 million for EMF studies over a five-year period, beginning in
1994. One-half of this amount is expected to be funded by the federal
government, and two-thirds of the non-federal funding is expected to be provided
by the electric utility industry. Through its participation with the EPRI and
EEI, OG&E will continue its support of the research with regard to the possible
health effects of EMFs. OG&E is dedicated to delivering electric service in a
safe, reliable, environmentally acceptable and economical manner.
3
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
Year Ended December 31
1995 1994 1993
---- ---- ----
ELECTRIC ENERGY:
(Millions of kWh)
Generation (exclusive of station use)... 20,639 18,325 21,789
Purchased............................... 3,578 4,387 3,169
---------- ---------- ----------
Total generated and purchased....... 24,217 22,712 24,958
Company use, free service and losses.... (1,537) (1,513) (1,652)
---------- ---------- ----------
Electric energy sold................ 22,680 21,199 23,306
========== ========== ==========
ELECTRIC ENERGY SOLD:
(Millions of kWh)
Residential............................. 6,848 6,739 6,631
Commercial and industrial............... 10,963 10,886 10,595
Public street and highway lighting...... 66 66 64
Other sales to public authorities....... 2,087 2,018 1,966
Sales for resale........................ 2,716 1,490 4,050
---------- ---------- ----------
Total............................... 22,680 21,199 23,306
========== ========== ==========
OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential......................... $ 471,313 $ 476,441 $ 488,921
Commercial and industrial........... 512,212 549,528 582,733
Public street and highway lighting.. 9,115 9,294 9,433
Other sales to public authorities... 95,660 99,789 107,035
Sales for resale.................... 63,340 43,001 89,945
Provision for rate refund .......... (2,437) (3,417) (14,963)
Miscellaneous....................... 19,084 22,262 19,712
---------- ---------- ----------
Total Electric Revenues........... 1,168,287 1,196,898 1,282,816
Non-utility subsidiary................ 133,750 158,270 164,436
---------- ---------- ----------
Total........................... $1,302,037 $1,355,168 $1,447,252
========== ========== ==========
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential............................. 583,741 578,044 568,780
Commercial and industrial............... 82,577 81,175 79,572
Public street and highway lighting...... 249 249 248
Other sales to public authorities....... 10,340 10,198 10,074
Sales for resale........................ 43 39 39
---------- ---------- ----------
Total............................... 676,950 669,705 658,713
========== ========== ==========
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (kWh)................ 11,786 11,724 11,688
Average annual revenue.................. $ 811.10 $ 828.86 $ 861.72
Average price per kWh (cents)........... 6.88 7.07 7.37
4
FINANCE AND CONSTRUCTION
The Company meets its cash needs through internally generated funds,
short-term borrowings and permanent financing. Cash flows from operations
remained strong in 1995 and 1994, which enabled the Company to internally
generate the required funds to satisfy construction expenditures during 1995 and
1994.
Management expects that internally generated funds will be adequate over
the next three years to meet OG&E's capital requirements. The primary capital
requirements for 1996 through 1998 are estimated as follows:
(dollars in millions) 1996 1997 1998
- --------------------------------------------------------------------------------
Consolidated construction
expenditures including AFUDC ..... $147 $134 $138
Maturities of long-term debt and
sinking fund requirement ......... --- 15 25
================================================================================
Total ......................... $147 $149 $163
================================================================================
The three-year estimate includes expenditures for construction of new
facilities to meet anticipated demand for service, to replace or expand existing
facilities in both its electric and non-utility businesses, and to some extent,
for satisfying maturing debt and sinking fund obligations. Approximately $1.6
million of the Company's construction expenditures budgeted for 1996 are to
comply with environmental laws and regulations. OG&E's construction program was
developed to support an anticipated peak demand growth of one to two percent
annually and to maintain minimum capacity reserve margins as stipulated by the
Southwest Power Pool. See "Rate Structure, Load Growth and Related Matters."
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. OG&E's current resource strategy includes the reactivation
of existing plants and the addition of peaking resources. OG&E does not
anticipate the need for another base-load plant in the foreseeable future.
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, 1995, and
assuming an annual interest rate of 8.2 percent, OG&E could issue more than $900
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, more than $900 million of additional preferred stock at an
assumed annual dividend rate of 8.0 percent could be issued as of December 31,
1995.
The Company will continue to use short-term borrowings to meet temporary
cash requirements and has the necessary regulatory approvals to incur up to $400
million in short-term borrowings at any one time. The maximum amount of
outstanding short-term borrowings during 1995 was $267.7 million.
5
OG&E's resource strategy for supplying energy through the next decade and
beyond consists of 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.
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., another cogenerator. In 1986, a contract was signed with Sparks
Regional Medical Center to purchase energy not needed by the hospital from its
nominal seven megawatt cogeneration facility. In 1987, OG&E signed a contract to
purchase up to 110 megawatts of capacity from Mid-Continent Power Company, Inc.
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 energy used by its customers, the cost and availability
of external financing and the cost of conforming to government regulations.
6
REGULATION AND RATES
OG&E's retail electric tariffs in Oklahoma are regulated by the OCC, and in
Arkansas by the Arkansas Public Service Commission ("APSC"). The issuance of
certain securities by OG&E is also regulated by the OCC and the APSC. OG&E's
wholesale electric tariffs, short-term borrowing authorization and accounting
practices are subject to the jurisdiction of the Federal Energy Regulatory
Commission ("FERC"). The Secretary of the Department of Energy has jurisdiction
over some of OG&E's facilities and operations.
For the year ended December 31, 1995, approximately 87 percent of
OG&E's electric revenue was subject to the jurisdiction of the OCC, seven
percent to the APSC, and six percent to the FERC.
RECENT REGULATORY MATTERS: On February 25, 1994, the OCC issued an order
---------------------------
that, among other things, effectively lowered OG&E's rates to its Oklahoma
retail customers by approximately $17 million annually and required OG&E to
refund approximately $41.3 million. Of the $41.3 million refund, $39.1 million
is associated with revenues prior to January 1, 1994, while the remaining $2.2
million related to 1994.
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 are designed to permit OG&E to earn a 12 percent regulatory
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 regulatory
return on equity exceeds 12.75 percent.
The Company will file for an electric utility rate review with the OCC in
mid-1996. This review of OG&E's electric utility rates should conclude no later
than six months after the rate case filing, a new requirement under Oklahoma
law.
In 1994, the Company underwent a significant restructuring effort and
redesign of its operations to more favorably position itself for the competitive
electric utility environment. The Company incurred $63.4 million of
restructuring costs in 1994. Pending an OCC order, OG&E deferred the costs
associated with a VERP and severance package in the third quarter of 1994.
Between August 1, and December 31, 1994, the amount deferred was reduced by
approximately $14.5 million. In response to an application filed by OG&E on
August 9, 1994, the OCC issued an order on October 26, 1994, that permitted OG&E
to amortize the December 31, 1994, regulatory asset of $48.9 million over 26
months and reduced OG&E's electric rates by approximately $15 million annually,
effective January 1995. Management anticipates that labor savings from the VERP
and severance package will substantially offset the amortization of the
regulatory asset and annual rate reduction of $15 million. Labor savings in 1994
and 1995 approximated the amortization of the deferred amount and therefore, did
not significantly impact 1994 or 1995 results. However, approximately $6.5
million in other restructuring expenses reduced 1994 earnings by $0.10 per
share. At December 31, 1995, the deferred amount was $26.3 million, which is
included on the Consolidated Balance Sheets as Deferred Charges - Other.
7
On July 19, 1995, OG&E announced plans to create a holding company
structure with OGE Energy Corp. becoming the parent company of OG&E. At a
special meeting of shareowners on November 16, 1995, OG&E shareowners approved
the new holding company structure. Upon regulatory approval, which is currently
expected by mid-1996, OG&E's common stock will be exchanged on a share-for-share
basis for common stock of OGE Energy Corp. and OG&E will become a subsidiary of
OGE Energy Corp. As part of this corporate restructuring, OG&E's wholly-owned
subsidiary, Enogex Inc. and Enogex's subsidiaries (collectively "Enogex") will
also become a direct subsidiary of OGE Energy Corp. The holding company
structure will provide greater flexibility to take advantage of opportunities to
develop or acquire other businesses, providing opportunities for increased
earnings in an increasingly competitive business environment. The holding
company structure will clearly separate the Company's electric utility business
from the non-utility businesses of the other OGE Energy Corp. subsidiaries for
regulatory, capital structure and other purposes. See "Supplementary
Data-Unaudited Pro Forma Financial Information" for a further discussion of this
matter.
On October 5, 1994, the OCC issued an order instructing the OCC staff of
the Public Utility Division ("PUD") to move forward with the development of OCC
rules to implement the mandates of Sections 111 and 115 of the National Energy
Policy Act of 1992, requiring OG&E and other electric utilities to each submit
20-year Integrated Resource Plans ("IRP"). Following several technical
conferences, in Order No. 398049, Cause No. RM 950000011 issued December 18,
1995, the OCC stated that it encourages Oklahoma electric and gas utilities to
utilize IRP principles, but found it unnecessary to set new rules dictating
requirements for IRP.
Pursuant to an order from the APSC in July 1992, OG&E and other electric
utilities serving customers in Arkansas were required to submit 20-year IRP with
the APSC. On October 10, 1995, the APSC issued Order No. 9, Docket No. 92-164-U,
which recognized the shifting pressures on today's utility industry, the
industry's good planning practices, the increasing competitive markets for
energy services and the need for publicly available information on utility plans
and planning processes. The APSC also recognized that long-term integrated
resource planning under prescriptive regulatory guidelines is no longer the most
appropriate or, more importantly, most effective means to protect the public
interest. Therefore, the APSC is not utilizing the IRP.
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, which are subject to periodic review by the OCC, the APSC
and the FERC.
The APSC is currently reviewing the amounts that OG&E pays Enogex and
recovers through its fuel adjustment clause for transporting natural gas to
OG&E's gas-fired generating stations. OG&E cannot predict the outcome of this
review. Nevertheless, at the present time, management does not believe this
proceeding will have a material adverse effect on the Company's consolidated
financial position or its results of operations.
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, qualified cogeneration facilities ("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.
8
OG&E has entered into agreements with four such cogenerators. See "Finance and
Construction." Electric utilities also must furnish electric energy to QFs on a
non-discriminatory basis at a rate that is just and reasonable and in the public
interest and must provide certain types of service which may be requested by QFs
to supplement or back up those facilities' own generation.
The National Energy Policy Act of 1992 ("Energy 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
Energy 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 Energy
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 Energy Act also is designed to
promote competition in the development of wholesale power generation in the
electric industry. It exempts a new class of independent power producers from
regulation under the Public Utility Holding Company Act of 1935 and allows the
FERC to order "wholesale wheeling" by public utilities to provide utility and
non-utility generators access to public utility transmission facilities. Also,
numerous states are considering proposals to require "retail wheeling."
Pursuant to the Energy Act, in 1995 the FERC issued a Notice of Proposed
Rulemaking on Open Access Non-discriminatory Transmission Services and a
Supplemental Notice of Proposed Rulemaking on Stranded Investment (collectively,
the Mega-NOPR). The Mega-NOPR is intended, among other things, to create a
vigorous wholesale electric market by requiring transmission providers to offer
open access to their transmission systems. Concurrently with the Mega-NOPR, FERC
issued a proposal for a Real-Time Information Network intended to facilitate
open access by requiring each electric utility to create an electronic bulletin
board of information regarding their transmission system services, availability
and rates. The Energy Act, these proposals and other factors are expected to
significantly increase competition in the electric industry. The Company has
taken steps in the past and intends to take appropriate steps in the future to
remain a competitive supplier of electricity. Past actions include the redesign
and restructuring effort in 1994 and continuing actions to reduce fuel costs,
both of which have resulted in lower retail rates, especially for industrial
customers. While the Company is supportive of competition, it believes that all
electric suppliers must be required to compete on a fair and equitable basis and
the Company intends to vigorously advocate this position.
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 expanding job-producing businesses
and industries; and (ii) to encourage the efficient use of energy by all of its
customers. In order to meet these goals, OG&E has reduced and restructured its
rates to its key customers while at the same time implementing numerous energy
efficiency 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; and (iv) time-of-use rate schedules for
various commercial, industrial and residential
9
customers designed to shift energy usage from peak demand periods during the hot
summer afternoons to non-peak hours.
In 1995, OG&E's marketing efforts included electrotechnologies, 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 chills water at night for cooling the next day.
OG&E works closely with individual customers to provide the best information on
how current technologies can be combined with OG&E's marketing programs to
maximize the customer's benefit.
OG&E continues studying programs such as Real Time Pricing to keep its
electric tariffs attractive and to control peak demand growth. Real Time Pricing
is a service option which prices electricity so that current price varies hourly
with short notice to reflect current expected cost. The technique will allow a
measure of competitive pricing, a broadening of customer choice, balancing of
electricity usage and capacity in the short and long term, and help customers to
control their costs. OG&E will implement a pilot program in 1996 with some
industrial customers.
OG&E currently does not anticipate the need for new baseload generating
plants in the foreseeable future. For further discussion, see "Finance and
Construction."
10
FUEL SUPPLY
During 1995, approximately 23 percent of the OG&E-generated energy was
produced by natural gas-fired units and 77 percent by coal-fired units. It is
estimated that the fuel mix for 1996 through 2000, based upon expected
generation for these years, will be as follows:
1996 1997 1998 1999 2000
- --------------------------------------------------------------------------------
Natural Gas...... 18% 22% 22% 23% 25%
Coal............. 82% 78% 78% 77% 75%
The decline in the percentage of coal-fired generation relative to total
generation will result from projected increases in natural gas-fired generation,
not a reduction in kwh of coal-fired generation.
The average cost of fuel used, by type, per million Btu for each of the 5
years was as follows:
1995 1994 1993 1992 1991
- --------------------------------------------------------------------------------
Natural Gas...... $3.19 $3.58 $3.64 $3.48 $3.14
Coal............. $0.83 $0.78 $1.16 $1.18 $1.21
Weighted Avg..... $1.41 $1.58 $1.92 $1.88 $1.96
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."
GAS-FIRED UNITS: For calendar year 1996, OG&E will acquire approximately 25% of
- ---------------
its gas needs from long-term gas purchase contracts. The remainder of OG&E's gas
needs during 1996 will be supplied by contracts with at-market pricing or
through day to day purchases on the spot market.
In 1993, OG&E began utilizing a natural gas storage facility which helps
lower fuel costs by allowing OG&E to optimize economic dispatch between fuel
types and take advantage of seasonal variations in natural gas prices. By
diverting gas into storage during low demand periods, OG&E is able to use as
much coal as possible to generate electricity and utilize the stored gas to meet
the additional demand for electricity. In 1996, gas storage will give OG&E the
flexibility to generate about 82 percent of its electricity with coal. It is
expected that with the continued utilization of the gas storage facility, OG&E
will be able to further reduce its fuel costs in 1996.
COAL-FIRED UNITS: All OG&E coal units, with an aggregate capacity of 2,530
- -----------------
megawatts, are designed to burn low sulfur western coal. OG&E purchases coal
under a mix of long- and short-term contracts. During 1995, OG&E purchased 11
million tons of coal from the following Wyoming suppliers: Amax Coal West, Inc.,
Kerr-McGee Coal Corporation, Caballo Rojo, Inc., Kennecott Energy Company,
Thunder Basin Coal Company and Powder River Coal Company. The combination of all
coals has an average sulfur content of 0.33 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.
11
During 1995, OG&E burned a total of 9.4 million tons of coal. Based upon
the average sulfur content of Wyoming coal, OG&E units have an approximate
emission rate of 0.76 pounds of sulfur dioxide per million Btu.
Wyoming coal is transported to OG&E generating stations, a distance of
approximately 1,000 miles, by 112 rail car unit trains. In 1995, OG&E completed
the upgrading of its unit train fleet to high volume aluminum body rail cars.
Currently, the fleet is comprised of 1,495 leased cars. Each aluminum rail car
has a maximum capacity of 120 net tons allowing for the movement of 13,440 net
tons per unit train. High volume and aluminum design combine to offer a 19
percent increase in net loading per car over a conventional steel car. Also, in
December 1995, OG&E increased the number of rail cars in unit train service to
Muskogee generating station from 112 rail cars to a maximum of 135 cars.
Increasing the unit train size allowed for an additional increase of delivered
tons by 17 percent. The combination of high volume, aluminum design and
increased train size to Muskogee generating station will reduce the number of
trips from Wyoming by approximately 28 percent and reduce rail car maintenance
expenses accordingly.
12
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 the Company's total expenditures for capital, operating,
maintenance and other costs to preserve and enhance environmental quality will
be approximately $37 million during 1996, approximately the same amount utilized
in 1995. OG&E continues to evaluate its environmental management systems to
ensure compliance with existing and proposed environmental legislation and
regulations and to better position itself in a competitive market.
The Company continues to explore options to comply with the Clean Air Act
Amendments of 1990 ("CAAA"). Since all of OG&E's coal-fired generating units
currently burn low-sulfur coal, OG&E will not be required to take any steps to
comply with the new sulfur dioxide emission limits until January 1, 2000. The
CAAA will also regulate emissions of nitrogen oxides and possibly certain
hazardous air pollutants. The Company believes it can meet the current EPA Phase
II limit for nitrogen oxides without additional expenditures. EPA's report on
utility air toxic emissions has not been issued to date. With this uncertainty,
it is possible that additional capital expenditures may be necessary in future
years.
In compliance with Title IV of the CAAA, the Company completed installation
of continuous emission monitors ("CEMs") on each of its generating units in
1995, a project which began in 1994. Capital expenditures on CEMs in 1995
totalled approximately $767,000, with operating and maintenance expenses of
$113,000. Capital expenditures in 1996 to complete the CEM project are expected
to be negligible, while operating and maintenance expenses are expected to total
approximately $125,000.
The Oklahoma Department of Environmental Quality's ("ODEQ") CAAA Title V
air permitting program was approved by the EPA in March 1996. Comprehensive site
air permits, as required under CAAA Title V, should be administratively complete
and submitted to the ODEQ by the end of July 1996 for two of the company's six
major source generating stations. Title V permits for the remaining major source
generating stations should be complete within six months thereafter. Air permit
fees for all generating stations are expected to cost approximately $340,000 in
1996.
The Company has and will continue to seek new pollution prevention
opportunities and to evaluate the effectiveness of its waste reduction, reuse
and recycling efforts. In 1995, OG&E obtained refunds of $460,000 from its
recycling efforts. This figure does not include the additional savings gained
through the reduction and/or avoidance of disposal costs and the reduction in
material purchases due to reuse of existing materials. Similar savings are
anticipated in future years.
OG&E remains a party to three separate actions brought by the EPA
concerning cleanup of disposal sites for hazardous and toxic waste, See "Item 3.
Legal Proceedings."
The Company has and will continue to evaluate the impact of its operations
on the environment. As a result, contamination on Company property will be
discovered from time to time. Three separate sites have been thus identified as
having been contaminated by historical operations, and during 1996 the Company
will pursue the appropriate corrective action at these sites. The cost of these
remedial actions is not anticipated to have a material adverse impact on the
Company's financial position or results of operations.
13
ENOGEX
OG&E's wholly-owned non-utility subsidiary, Enogex Inc., is the 40th
largest pipeline in the nation in terms of miles of pipeline. Enogex Inc.'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 natural gas exploration and production
activities. At December 31, 1995, Enogex Inc. had three wholly-owned
subsidiaries, Enogex Products Corporation ("Products"), Enogex Services
Corporation ("Services") and Enogex Exploration Corporation ("Exploration"). On
December 31, 1995, the assets of two former wholly-owned subsidiaries of Enogex
Inc., ENGL Corporation ("ENGL") and Clinton Gas Transmission Inc. ("Clinton"),
were transferred to Products and Services, respectively, and ENGL and Clinton
were dissolved. Enogex Inc. also owns an 80 percent interest in Centoma Gas
Systems, Inc. ("Centoma"). Products owns interests in and operates five natural
gas processing plants. Exploration is engaged in investing in the exploration
and production of oil and natural gas and the purchase of oil and gas reserves.
Services is engaged in the marketing (buying and selling) of natural gas and
also markets natural gas liquids of Products. Centoma both purchases and gathers
gas for subsequent processing at one of three processing plants, two of which
are owned by Products. The residue gas is then sold under a combination of
contract and spot market prices.
For the year ended December 31, 1995, and before elimination of
intercompany items between OG&E and Enogex, Enogex's consolidated revenues and
net income were approximately $178.1 million and $12.7 million, respectively, as
indicated in the following table:
(dollars in millions) 1995 Revenues 1995 Net Income
- ------------------------------------------------------- ------- ----------------
Enogex Inc...................... $ 59.4 $12.7 (a)
Products........................ 16.5 2.3
Services........................ 105.1 0.9
Exploration..................... 10.3 2.4
ENGL............................ 6.2 (0.4)
Clinton......................... --- ---
Centoma......................... 9.6 (0.9)
Eliminations within Enogex...... (29.0) (b) (4.3)
------ -----
Enogex consolidated amounts..... $178.1 $12.7
====== =====
(a) Includes $4.3 million of net income from Products, Services, Exploration,
ENGL, Clinton and Centoma.
(b) Consists of intercompany natural gas transmission fees of $5.7 million and
sales of natural gas products amounting to $23.3 million.
Enogex's natural gas transportation business in Oklahoma consists primarily
of gathering and transporting natural gas for OG&E and on an interruptible
basis, for other customers. 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. 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
14
generating stations. In 1995, Enogex transported 127 Bcf of natural gas; of
which approximately 50 Bcf, or about 39 percent, was delivered to OG&E's
electric generating stations and storage facility, which resulted in
approximately 75 percent of Enogex Inc.'s revenue of $59.4 million for 1995. See
"Regulation and Rates" and "Management's Discussion and Anaylsis of Results of
Operations and Financial Condition -- Contingencies."
Enogex's pipeline system also gathers and transports natural gas destined
for interstate markets through interconnections in Oklahoma with other pipeline
companies. Among others, these interconnections include Panhandle Eastern
Pipeline, Williams Natural Gas Pipeline, Natural Gas Pipeline Company of
America, Northern Natural Gas Company, Noram Gas Transmission Company, 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 the FERC at least once every three years. This rate review may
involve an administrative-type trial and an administrative appellate review. In
addition, Enogex has agreed to open its system to all interstate shippers that
are interested in moving natural gas through the Enogex system. Enogex is
required to conduct this transportation on a non-discriminatory basis, although
this transportation is subordinate to that performed for OG&E. This decision
does not increase appreciably the federal regulatory burden on Enogex, but does
give Enogex the opportunity to utilize any unused capacity on an interruptible
basis and thus increase its transportation revenues.
The fees charged by Enogex for transporting natural gas for OG&E and other
intrastate shippers are not subject to FERC regulation. With respect to state
regulation, the fees charged by Enogex for any intrastate transportation service
have not been subject to direct state regulation by the OCC. Even though the
intrastate pipeline business of Enogex is not directly regulated, the OCC, the
APSC and the FERC have the authority to examine the appropriateness of any
transportation charge or other fees paid by OG&E to Enogex, which OG&E seeks to
recover from ratepayers. 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 Mmcf 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 56 Mmcf 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 at four of the
plants, and off-lease extraction of liquids from an unaffiliated pipeline at one
plant. 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 is handled by Services. The
natural gas liquids are sold to Services at a price equal to the Oil Price
Information Service average monthly price.
In processing and marketing natural gas liquids, the Enogex companies
compete against virtually all other gas processors selling natural gas liquids.
The Enogex companies believe they will be able to continue to compete favorably
against such companies. With respect to factors affecting the natural gas
15
liquids industry generally, as the price of natural gas liquids fall without a
corresponding decrease in the price of natural gas, it may become uneconomical
to extract certain natural gas liquids. As to factors affecting the Enogex
companies specifically, the volume of natural gas processed at their plants is
dependent upon the volume of natural gas transported through the pipeline system
located "behind the plants." If the volume of natural gas transported by such
pipeline increases "behind the plants," then the volume of liquids extracted by
Products should normally increase.
Services is a natural gas and natural gas liquids 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. It also serves Products by
purchasing and marketing the natural gas liquids they produce. 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.
Although the margin on gas sales by Services is relatively small,
approximately 71 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.
Enogex Inc. is committed to continue 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.
and Services 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 1994. The contributing
factors for the increase were specific projects implemented to strengthen
Enogex's position, with other similar projects under consideration.
Services competes with all major suppliers of natural gas and natural gas
liquids in the geographic markets they serve. For natural gas, those geographic
markets are primarily the areas served by pipelines with which Enogex is
interconnected. Although the price of the gas is an important factor to a buyer
of natural gas from 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 exploration and
production of natural gas. Exploration has focused its drilling activity in the
Antrim Devonian shale trend in the state of Michigan and also has interests in
Oklahoma. As of December 31, 1995, Exploration had interests in 280 active wells
and total assets, including such interests, of approximately $45 million.
Centoma was formed in 1994 and is Enogex's gas gatherer within an area of
mutual interest located on Enogex's inner system. All gas gathered by Centoma is
processed at one of three gas plants owned by Products. Centoma derives revenues
from gas gathering and also from the resale of residue gas during the winter
under premium price contracts.
16
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
5,647 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 404 820
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) 5,647
=====
17
At December 31, 1995, OG&E's transmission system included 71 substations
with a total capacity of approximately 17.2 million kVA and approximately 4,227
structure miles of lines. The distribution system included 332 substations with
a total capacity of approximately 6.1 million kVA, 21,245 structure miles of
overhead lines, 1,677 miles of underground conduit and 6,571 miles of
underground conductor.
Substantially all of OG&E's electric facilities are subject to a direct
first mortgage lien under the Trust Indenture securing OG&E's first mortgage
bonds.
Enogex owns: (1) over 3,000 miles of natural gas pipeline extending from
the Arkoma Basin in eastern Oklahoma to the Anadarko Basin in western Oklahoma;
(2) a 50 percent interest in a natural gas processing plant near Calumet,
Oklahoma, which has the capacity to process 250 Mmcf of natural gas per day; (3)
four other natural gas processing plants in Oklahoma, which have, in the
aggregate, the capacity to process approximately 56 Mmcf of natural gas per day;
and (4) an 80 percent interest in approximately 110 miles of gas gathering
pipeline owned by Centoma.
During the three years ended December 31, 1995, the Company's gross
property, plant and equipment additions approximated $421 million and gross
retirements approximated $71 million. Over 95 percent of these additions were
provided by internally generated funds. The additions during this three-year
period amounted to approximately 10.7 percent of total property, plant and
equipment at December 31, 1995.
ITEM 3. LEGAL PROCEEDINGS.
- --------------------------
1. 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 oil and gas contract by
OG&E. This case was removed to the United States District Court for the Western
District of Oklahoma. Enogex Inc. was also joined as a Defendant in the action.
Plaintiffs allege that OG&E and Enogex were in violation of the Federal Racket
Influenced and Corrupt Act ("RICO"). OG&E filed its Motion to Dismiss the RICO
claim on March 26, 1993. Plaintiffs allege 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 to 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.
On January 4, 1994, the United States District Court for the Western
District of Oklahoma entered its Order and dismissed Plaintiffs' RICO claim as
well as Plaintiffs' claim for punitive damages under RICO. On January 14, 1994,
Plaintiffs filed a Motion to Alter or Amend Judgment seeking leave of Court to
file its Amended Complaint asserting different allegations under RICO. On
January 31, 1994, the Court denied Plaintiffs' motion.
Plaintiffs filed their Appeal with the United States Court of Appeals for
the 10th Circuit. In addition, the United States District for the Western
District of Oklahoma remanded the breach of contract claim to the District Court
of Oklahoma County, Oklahoma. By Order filed January 11, 1995, the Court
dismissed the appeal pursuant to a stipulation of the parties. The RICO case is
now dismissed.
The remaining breach of contract claims were submitted to private binding
arbitration during 1995. On November 22, 1995, the arbitration panel issued a
confidential order which closes this matter. The
18
outcome of the arbitration does not have a material adverse effect on the
Company's consolidated financial position or its results of operations.
2. On July 8, 1994, an employee of OG&E filed a lawsuit in state court
against OG&E in connection with OG&E's voluntary early retirement package. The
case was removed to the U.S. District Court in Tulsa, Oklahoma. On August 23,
1994, the trial court granted OG&E's Motion to Dismiss Plaintiff's Complaint in
its entirety.
On September 12, 1994, Plaintiff, along with two other Plaintiffs, filed an
Amended Complaint alleging substantially the same allegations which were in the
original complaint. The action was filed as a class action, but no motion to
certify a class was ever filed. Plaintiffs want credit, for retirement purposes,
for years they worked prior to a pre-ERISA (1974) break in service. They allege
violations of ERISA, the Veterans Reemployment Act, Title VII, and the Age
Discrimination in Employment Act. State law claims, including one for
intentional infliction of emotional distress, are also alleged.
On October 10, 1994, Defendants filed a Motion to Dismiss Counts II, IV, V,
VI and VII of Plaintiffs' Amended Complaint. With regard to Counts I and III,
Defendants filed a Motion for Summary Judgment on January 18, 1996. One
Plaintiff was killed in a car accident in January of 1996. The Plaintiff never
retired and Defendants allege the Plaintiff does not have a claim for retirement
benefits. The Plaintiff's beneficiary will receive death benefits.
While the Company cannot predict the precise outcome of the proceeding, the
Company continues to believe that the lawsuit is without merit and will not have
a material adverse effect on its consolidated results of operations or financial
condition.
3. On June 30, l986, the United States government filed suit against OG&E
and 36 other defendants in case number CIV-86-l40l W, in the United States
District Court ("USDC") for the Western District of Oklahoma. The Complaint
generally alleged that a total of l8 million gallons of hazardous and toxic
waste were contained at the Hardage Criner site located approximately 30 miles
south of Oklahoma City, and that the government had expended, as of the date of
the filing of the Complaint, $l.44 million related to the site. The 37
defendants are divided into three classes: 33 "generator" defendants, of which
the Company is one; three "transporter" defendants; and the owner of the site,
Mr. Royal Hardage.
It is estimated that over 200 other entities, not named in the government's
Complaint, also disposed of materials at the site. OG&E 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 was estimated to cost
approximately $60 million.
The design and construction of the remedy was completed in 1995 and is now
in an operation and maintenance mode.
Settlements have been reached with numerous parties that were not members
of the Committee for their share of costs incurred. The money collected through
these settlements has been used to finance the remedy and to reimburse the
government for response costs.
19
Even though the settlement funds, plus interest and the United States
contribution raised a substantial portion of the monies required for
construction of the remedy and future maintenance, any remaining amounts that
OG&E and the other Committee members are likely to pay may still be substantial
due to maintenance of the remedy over time.
The Committee members have reached an Agreement to pay the on-going
maintenance 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, or approximately $1.4 million.
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; (3) the portion of the total waste disposed at this
site attributable to OG&E; and (4) the remedy construction is complete.
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. 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 brokering of polychlorinated biphenyls ("PCBs") and
PCB items, processing of PCB capacitors and transformers for disposal, and
decontamination of mineral oil dielectric fluids containing PCBs. During this
time period, various generators of PCBs ("Generators"), including OG&E, shipped
materials containing PCBs to the facility. Contrary to its contractual
obligation with OG&E and other Generators, it appears that Rose failed to
manage, handle and dispose of the PCBs and the PCB items in accordance with the
applicable law. Rose has been issued citations by both the EPA and the
Occupational Safety and Health Administration. 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 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. 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.
The Company estimates its share of the total hazardous wastes at the Rose
facility to be less than six percent. A Settlement Agreement between AEGIS
Insurance Company and OG&E was reached in 1994. The remediation of this site was
completed in 1995 by the Steering Committee and is currently in the final stages
of closure with the EPA, which includes operation and maintenance activities as
required in the Administrative Order on Consent with the EPA.
Due to additional funds resulting from payments by third party companies
who were not a part of the Steering Committee, and also reduced remedy
implementation costs, the Company received a refund in December 1995 under the
allocation formula.
20
Although the Company cannot predict the precise outcome of this matter,
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; (3) the portion of the total waste disposed at this site
attributable to OG&E and (4) the Company's settlement agreement with its
insurer. Management also believes that costs incurred in connection with this
site, which are not recovered from insurance carriers or other parties, may be
allowable costs for future ratemaking purposes.
5. 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 of 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.
On February 15, 1996, OG&E elected to participate in the de minimis
settlement of EPA's Administrative Order on Consent. This limits OG&E's
financial obligation to less than $2,000 and also eliminates its involvement in
the design and implementation of the site remedy.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
- -------------------------------------------------------------
Special Meeting of shareowners on November 16, 1995 for the purpose of
Approving an Agreement and Plan of Share Acquisition, whereby
OGE Energy Corp. will become the holding company parent of
the Company and the holders of Company Common Stock will
become holders of OGE Energy Corp. Common Stock.
Votes For: 33,932,508
Votes Against: 1,271,000
Votes Abstained: 866,451
21
EXECUTIVE OFFICERS OF THE REGISTRANT.
- -------------------------------------
The following persons were Executive Officers of the Registrant as of
March 15, 1996:
Name Age Title
- ------------------- --- -------------------------------
James G. Harlow, Jr 61 Chairman of the Board and
Chief Executive Officer
Steven E. Moore 49 President and Chief Operating
Officer
Patrick J. Ryan 57 Vice Chairman
Al M. Strecker 52 Senior Vice President - Finance
and Administration
Melvin D. Bowen, Jr. 54 Vice President - Power Delivery
Jack T. Coffman 52 Vice President - Power Supply
Michael G. Davis 46 Vice President - Marketing and
Customer Services
Irma B. Elliott 57 Vice President and
Corporate Secretary
James R. Hatfield 38 Treasurer
Don L. Young 55 Controller
Donald R. Rowlett 38 Assistant Controller
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
16, 1996.
22
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. 1995-Present: Chairman of the Board and
Chief Executive Officer
1991-1995: Chairman of the Board,
President and Chief
Executive Officer
Steven E. Moore 1995-Present: President and
Chief Operating Officer
1991-1995: Vice President - Law
and Public Affairs
Patrick J. Ryan 1994-Present: Vice Chairman
1991-1994: Executive Vice President
and Chief Operating
Officer
Al M. Strecker 1994-Present: Senior Vice President -
Finance and
Administration
1991-1994: Vice President and
Treasurer
1991: Vice President, Secretary
and Treasurer
Melvin D. Bowen, Jr. 1994-Present: Vice President -
Power Delivery
1991-1994: Metro Region
Superintendent
Jack T. Coffman 1994-Present: Vice President -
Power Supply
1991-1994: Manager - Generation
Services
23
Name Business Experience
- ------------------ ------------------------------------------
Michael G. Davis 1994-Present: Vice President -
Marketing and
Customer Services
1992-1994: Director-Marketing
Division
1991-1992: Manager - Industrial
Services
Irma B. Elliott Present: Vice President and
Corporate Secretary
1991-1996: Secretary
1991: Assistant Secretary
James R. Hatfield 1994-Present: Treasurer
1994: Vice President - Investor
Relations & Corporate
Secretary - Aquila Gas
Pipeline Corporation
(an intrastate gas
pipeline subsidiary of
UtiliCorp United Inc.)
1991-1993: Assistant Treasurer -
UtiliCorp United Inc.
(an electric and
natural gas utility
company)
Don L. Young 1991-Present: Controller
Donald R. Rowlett 1994-Present: Assistant Controller
1992-1994: Senior Specialist -
Tax Accounting
1991-1992: Specialist - Tax
Accounting
24
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.
1995 1994
--------------------------------------------------------------
Dividend Dividend
Paid High Low Paid High Low
--------------------------------------------------------------
First Quarter $0.66 1/2 $36 1/4 $32 9/16 $0.66 1/2 $37 1/4 $33 1/2
Second Quarter 0.66 1/2 36 3/8 33 1/4 0.66 1/2 36 1/2 29 3/8
Third Quarter 0.66 1/2 38 33 3/8 0.66 1/2 34 3/8 29 5/8
Fourth Quarter 0.66 1/2 43 5/8 36 7/8 0.66 1/2 34 1/4 32
The number of record holders of Common Stock at December 31, 1995, was
44,594. The book value of the Company's Common Stock at December 31, 1995, was
$23.22.
25
ITEM 6. SELECTED FINANCIAL DATA.
- ---------------------------------
HISTORICAL DATA
1995 1994 1993 1992 1991
-------------------------------------------------------------------------
SELECTED FINANCIAL DATA
(dollars in thousands except
for per share data)
Operating revenues ................ $1,302,037 $1,355,168 $1,447,252 $1,314,984 $1,314,770
Operating expenses................. 1,099,890 1,154,702 1,252,099 1,137,980 1,103,683
---------- ---------- ---------- ---------- ----------
Operating income................... 202,147 200,466 195,153 177,004 211,087
Other income and deductions........ 800 (2,167) (1,301) (567) (471)
Interest charges................... 77,691 74,514 79,575 76,725 76,700
---------- ---------- ---------- ---------- ----------
Net income......................... 125,256 123,785 114,277 99,712 133,916
Preferred dividend
requirements...................... 2,316 2,317 2,317 2,317 2,317
Earnings available for
common............................ $ 122,940 $ 121,468 $ 111,960 $ 97,395 $ 131,599
========== ========== ========== ========== ==========
Long-term debt..................... $ 843,862 $ 730,567 $ 838,660 $ 838,654 $ 853,597
Total assets....................... $2,754,871 $2,782,629 $2,731,424 $2,590,083 $2,566,089
Earnings per average common
share............................. $ 3.05 $ 3.01 $ 2.78 $ 2.42 $ 3.27
CAPITALIZATION RATIOS
Common equity...................... 51.19% 54.13% 50.51% 50.36% 50.20%
Cumulative preferred stock......... 2.73% 2.94% 2.78% 2.79% 2.75%
Long-term debt..................... 46.08% 42.93% 46.71% 46.85% 47.05%
INTEREST COVERAGES
Before federal income taxes
(including AFUDC).............. 3.48X 3.59X 3.32X 3.05X 3.66X
(excluding AFUDC).............. 3.46X 3.58X 3.32X 3.04X 3.63X
After federal income taxes
(including AFUDC).............. 2.59X 2.64X 2.43X 2.29X 2.70X
(excluding AFUDC).............. 2.57X 2.62X 2.42X 2.28X 2.66X
26
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) 1995 1994 1993 1995 1994
- ---------------------------------------------------------------------------------------------------
Operating revenues....................... $1,302,037 $1,355,168 $1,447,252 (3.9) (6.4)
Earnings available for common stock ..... $ 122,940 $ 121,468 $ 111,960 1.2 8.5
Average shares outstanding .............. 40,356 40,344 40,328 --- ---
Earnings per average common share........ $ 3.05 $ 3.01 $ 2.78 1.3 8.3
Dividends paid per share................. $ 2.66 $ 2.66 $ 2.66 --- ---
===================================================================================================
Earnings for 1995 increased from $3.01 per share in 1994 to $3.05 per share
in 1995, an increase of 1.3 percent. The increase is primarily the result of
continued customer growth in the OG&E service area and improved operating
efficiencies resulting from the 1994 restructuring of the Company's
operations. The 1994 increase resulted primarily from increased retail electric
kilowatt-hour sales and less impact than in 1993 from the February 1994 rate
order of the Oklahoma Corporation Commission ("OCC"), which reduced earnings for
1993 by $.32 per share. See Note 10 of Notes to Consolidated Financial
Statements.
The dividend payout ratio (expressed as a percentage of earnings available
for common) improved in 1995 to 87 percent as compared to 88 percent for 1994.
The Company's long-term goal is to achieve a dividend payout ratio of 75 percent
based on long-term earnings expectations.
In 1994, the Company restructured and redesigned its operations to reduce
costs in order to more favorably position itself for the competitive electric
utility environment. As part of this process, the Company implemented a
Voluntary Early Retirement Package ("VERP") and a severance package in 1994.
Those two programs reduced the Company's workforce by more than 900 employees.
In January 1995, OG&E began amortizing a regulatory asset of $48.9 million
consisting of the balance of the deferred costs associated with the VERP and the
severance package, in accordance with an order of the OCC issued on October 26,
1994. The OCC order permitted the Company to amortize the $48.9 million over 26
months and reduced electric rates by approximately $15 million annually. At
December 31, 1995, the unamortized regulatory asset was $26.3 million, which is
included on the Consolidated Balance Sheets as Deferred Charges - Other. In
1995, the labor savings from the VERP and severance package approximated the
amortization of the regulatory asset and the annual rate reduction of $15
million and therefore, did not significantly impact 1995 operating results. In
1996, the labor savings are again expected to substantially offset the
amortization of the regulatory asset and the rate reduction of $15 million.
On July 19, 1995, OG&E announced plans to create a holding company
structure with OGE Energy Corp. becoming the parent company of OG&E. At a
special meeting of shareowners on November 16, 1995, OG&E shareowners approved
the new holding company structure. Upon regulatory approval, which is currently
expected by mid-1996, OG&E's common stock will be exchanged on a share-for-share
basis for common stock of OGE Energy Corp. and OG&E will become a subsidiary of
OGE Energy Corp. As part of this corporate restructuring, OG&E's wholly-owned
subsidiary,
27
Enogex, Inc. and Enogex's subsidiaries (collectively "Enogex") will also
become a direct subsidiary of OGE Energy Corp. The holding company structure
will provide greater flexibility to take advantage of opportunities to develop
or acquire other businesses, providing opportunities for increased earnings in
an increasingly competitive business environment. The holding company structure
will clearly separate the Company's electric utility business from the
non-utility businesses of the other OGE Energy Corp. subsidiaries for
regulatory, capital structure and other purposes.
The Company will file with the OCC for an electric utility rate review in
mid-1996. This review of our electric utility rates should conclude no later
than six months after the rate case filing, a new requirement under Oklahoma
law.
The following discussion and analysis presents factors which had a material
effect on the Company's operations and financial position during the last three
years and should be read in 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.
RESULTS OF OPERATIONS
REVENUES
Percent Change
From Prior Year
---------------
(THOUSANDS) 1995 1994 1993 1995 1994
- ---------------------------------------------------------------------------------------------------------------
Sales of electricity to OG&E customers...... $1,135,720 $1,188,550 $1,242,964 (4.4) (4.4)
Provisions for rate refund ................. (2,437) (3,417) (14,963) * *
Sales of electricity to other utilities..... 35,004 11,765 54,815 197.5 (78.5)
Enogex...................................... 133,750 158,270 164,436 (15.5) (3.7)
- ------------------------------------------------------------------------------------------
Total operating revenues .............. $1,302,037 $1,355,168 $1,447,252 (3.9) (6.4)
============================================================================================================
System kilowatt-hour sales 20,828,415 20,642,675 20,201,533 0.9 2.2
Kilowatt-hour sales to other utilities...... 1,851,839 556,765 3,103,977 232.6 (82.1)
- ------------------------------------------------------------------------------------------------------------
Total kilowatt-hour sales ............. 22,680,254 21,199,440 23,305,510 7.0 (9.0)
=============================================================================================================
*Not meaningful
In 1995, approximately 90 percent of the Company's revenues consisted of
regulated sales of electricity as a public utility, while the remaining 10
percent was provided by the non-utility operations of Enogex. Revenues from
sales of electricity are somewhat seasonal, with a large portion of the
Company's annual electric revenues occurring during the summer months when the
electricity needs of its customers increase. Enogex's primary operations consist
of 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 natural gas exploration and production activities. Actions of the
regulatory commissions that set OG&E's electric rates will continue to affect
the Company's financial results. The commissions also have the authority to
examine the
28
appropriateness of OG&E's recovery from its customers of fuel costs, which
include the transportation fees that OG&E pays Enogex for transporting natural
gas to OG&E's generating units.
During 1995, operating revenues decreased $53.1 million or 3.9 percent,
primarily due to lower revenue from Enogex businesses, the $15 million rate
reduction, mild weather, and recovery of lower fuel costs. Partially offsetting
the impact of these reductions was continued growth in kilowatt-hour sales to
OG&E customers ("system sales") and a significant increase in kilowatt-hour
sales to other utilities.
Enogex revenues decreased 15.5 percent in 1995. This reduction is primarily
attributable to a reduced emphasis on low margin off-system natural gas sales
and lower natural gas prices on gas purchased for resale.
Operating revenues in 1994 decreased $92.1 million or 6.4 percent,
primarily due to recovery of substantially reduced fuel costs, a significant
reduction in kilowatt-hour sales to other utilities, milder weather and lower
revenue from Enogex businesses. Partially offsetting the impact of these
reductions was a 2.2 percent growth in system sales. The OCC issued an order on
February 25, 1994, that effectively reduced OG&E's rates by $17 million annually
and required OG&E to refund $41.3 million. Approximately $39.1 million of the
refund was charged to periods prior to 1994 and did not significantly affect
1994 results. See Note 10 of the Notes to Consolidated Financial Statements.
Enogex revenues decreased 3.7 percent in 1994. Primary factors for the
decrease were lower natural gas prices and slightly lower volumes of natural gas
sold by Enogex. These decreases were partially offset by increased sales of
natural gas liquids.
EXPENSES AND OTHER ITEMS
Percent Change
From Prior Year
---------------
(DOLLARS IN THOUSANDS) 1995 1994 1993 1995 1994
- ------------------------------------------------------------------------------------------------------
Fuel ..................................... $ 260,443 $ 263,329 $ 383,207 (1.1) (31.3)
Purchased power........................... 216,598 228,701 218,689 (5.3) 4.6
Gas purchased for resale (Enogex)......... 87,293 114,044 140,311 (23.5) (18.7)
Other operation and maintenance........... 290,824 284,194 274,988 2.3 3.3
Restructuring ............................ --- 21,035 --- * *
Depreciation and Amortization............. 132,135 126,377 119,543 4.6 5.7
Taxes..................................... 112,597 117,022 115,361 (3.8) 1.4
- -------------------------------------------------------------------------------------
Total operating expenses............. $1,099,890 $1,154,702 $1,252,099 (4.7) (7.8)
======================================================================================================
* Not meaningful
Total operating expenses decreased approximately $54.8 million or 4.7
percent in 1995, due to decreases in quantities and prices of gas purchased for
resale by Enogex, lower maintenance costs, reduced purchases of power from other
utilities, lower income taxes and reduced fuel costs for the production of
electricity. These reductions were partially offset by increases in depreciation
and amortization.
29
OG&E's generating capability is evenly divided between coal and natural gas
and provides for flexibility to use either fuel to the best economic advantage
for the Company and its customers. In 1995, fuel costs decreased $2.9 million or
1.1 percent due to lower prices and usage of natural gas and a higher volume of
kilowatt-hours generated with lower priced coal. During 1994, fuel costs
decreased approximately $120 million or 31.3 percent, due to renegotiated coal
and transportation contracts, lower natural gas usage and a 15.9 percent
reduction in the volume of kilowatt-hours generated (due to economic purchases
of power from other utilities and a reduction in sales to other utilities).
Purchased power costs decreased $12.1 million or 5.3 percent in 1995,
primarily due to the availability of larger quantities of economically priced
energy in 1994. Economic purchases of power from other utilities resulted in a
$10 million increase in 1994. As required by the Public Utility Regulatory
Policy Act ("PURPA"), the Company is currently purchasing power from qualified
cogeneration facilities. In 1998, another qualified cogeneration facility is
scheduled to become operational and the Company is obligated to purchase up to
100 megawatts of capacity from this facility as well. See related discussion of
purchased power in Note 9 of Notes to Consolidated Financial Statements.
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are passed through to OG&E's electric customers through
automatic fuel adjustment clauses. The automatic fuel adjustment clauses are
subject to periodic review by the OCC, the Arkansas Public Service Commission
("APSC") and the Federal Energy Regulatory Commission ("FERC"). The OCC, the
APSC, and the FERC have authority to review the appropriateness of gas
transportation charges or other fees OG&E pays Enogex, which OG&E seeks to
recover through the fuel adjustment clause or other tariffs. See Note 10 of
Notes to Consolidated Financial Statements for a discussion of the OCC order in
February 1994 requiring, among other things, a $41.3 million refund relating to
the fees OG&E paid Enogex. The APSC is in the process of reviewing the gas
transportation charges OG&E pays Enogex. See related discussion of the APSC
review in Note 9 of Notes to Consolidated Financial Statements.
Even though increases and decreases are passed through to customers, in
1993 the Company began utilizing a natural gas storage facility which helps OG&E
lower fuel costs and receive greater value from its remaining take-or-pay gas
contracts. By diverting natural gas into storage, OG&E is able to use as much
coal as possible to generate electricity, and use gas from storage when needed
to meet increases in demand for electricity. The higher levels of fuel
inventories at the end of 1995 and 1994 were attributable to increased usage of
the natural gas storage facility and the relatively low level of fuel
inventories at the end of 1993 was due to significant kilowatt-hour sales to
other utilities.
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. Reducing fuel costs
helps OG&E remain competitive, which in turn helps OG&E's electric customers
remain competitive in a global economy.
Enogex's gas purchased for resale decreased $26.7 million or 23.5 percent
and $26.3 million or 18.7 percent in 1995 and 1994, respectively. These
decreases are primarily the result of the continued trend of declining natural
gas prices and Enogex's reduced emphasis on marketing low margin off-system
natural gas.
Other operation and maintenance increased $6.6 million in 1995, due to
$22.6 million of amortization of the regulatory asset resulting from the 1994
restructuring of the Company's operations,
30
costs associated with a major storm in the Company's service area and the
write-off of obsolete inventory, offset by lower costs due to the 1994 workforce
reduction and efficiencies gained in the maintenance of the Company's generating
plants. Other operation and maintenance increased by approximately $9.2 million
in 1994. A $5.4 million decrease in production maintenance in 1994, net of labor
savings, was more than offset by: (i) expensing $8.4 million of previously
deferred costs associated with Statement of Financial Accounting Standards
("SFAS") No. 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions;" (ii) current recognition of SFAS No. 106 costs; and (iii) increased
costs of producing natural gas liquids at Enogex.
The increases in depreciation and amortization for 1995 and 1994 reflects
higher levels of depreciable plant and amortization of gas sales contracts by
Enogex.
In 1995, income taxes decreased primarily due to an increase in tax credits
earned during 1995 and lower pre-tax earnings. Income taxes during 1994
increased primarily due to higher pre-tax earnings.
The Company successfully refinanced approximately $396 million of
short-term and long-term debt in 1995, resulting in a $7 million reduction in
annual interest expense. The decrease in interest expense in 1994 from 1993 was
primarily attributable to the approximate $6.2 million of interest in 1993,
associated with the refund ordered by the OCC in February 1994. See Note 10 of
Notes to Consolidated Financial Statements.
LIQUIDITY, CAPITAL RESOURCES AND CONTINGENCIES
The primary capital requirements for 1995 and as estimated for 1996 through
1998 are as follows:
(DOLLARS IN MILLIONS) 1995 1996 1997 1998
- --------------------------------------------------------------------------------
Construction expenditures
including AFUDC .............. $154 $147 $134 $138
Maturities of long-term debt and
sinking fund requirements..... 25 --- 15 25
- --------------------------------------------------------------------------------
Total..................... $179 $147 $149 $163
================================================================================
The Company's primary needs for capital are related to construction of new
facilities to meet anticipated demand for utility service, to replace or expand
existing facilities in both its electric and non-utility businesses, and to some
extent, for satisfying maturing debt and sinking fund obligations. The Company
generally meets its cash needs through a combination of internally generated
funds, short-term borrowings and permanent financing. Because of the continuing
trend toward greater environmental awareness and increasingly stringent
regulations, the Company has been experiencing increasing construction
expenditures related to compliance with environmental laws and regulations.
1995 CAPITAL REQUIREMENTS
Construction expenditures were $154 million in 1995. Approximately $1
million of the 1995 construction expenditures were to comply with environmental
regulations. This compares to construction
31
expenditures of $150 million in 1994, of which $9.4 million were to comply with
environmental regulations.
1995 FINANCING ACTIVITIES
During 1995, the Company's primary source of capital was internally
generated funds from operating cash flows. Operating cash flow remained strong
in 1995 as internally generated funds provided financing for all of the
Company's capital expenditures. Variations in accounts receivable and accounts
payable are not generally significant indicators of the Company's liquidity, as
such variations are primarily attributable to fluctuations in weather in the
Company's service territory, which has a direct effect on sales of electricity.
In 1995, accounts receivable and accounts payable were higher due to more
favorable weather in the last quarter of the year as compared to 1994.
Short-term borrowings were used during 1995 to meet temporary cash
requirements. At December 31, 1995, the Company had outstanding short-term
borrowings of $67.6 million.
In January 1995, OG&E issued two series of pollution control revenue bonds
bearing interest at variable, tax-exempt rates, to refinance its obligations
with respect to $47 million of 5.875 percent pollution control bonds and $32
million of 6.75 percent pollution control revenue bonds. The annualized
composite interest rate on the two new series of bonds was approximately 3.50
percent for the period from their date of issuance through December 31, 1995.
In August and September 1995, Enogex issued $120 million of medium-term
notes at a composite interest rate of 6.89 percent. These notes were issued to
replace $90 million of short-term borrowings incurred by Enogex in August 1994
in connection with the refinancing of outstanding medium-term notes with an
annualized composite rate of 9.99 percent, the redemption of a $6.9 million
long-term note payable which carried an interest rate of prime less one-quarter
of one percent and the redemption of $22 million of associated companies
short-term borrowings.
In October 1995, OG&E issued $220 million of long-term debt with a
composite interest rate of 6.775 percent. The proceeds were applied to the
redemption, in November 1995, of $220 million principal amount of outstanding
first mortgage bonds, which had a weighted average interest rate of 8.676
percent.
FUTURE CAPITAL REQUIREMENTS
The Company's construction program for the next several years does not
include additional base-load generating units. Rather, to meet the increased
electricity needs of its customers during the balance of the century, the
Company will concentrate on maintaining the reliability and increasing the
utilization of existing capacity and increasing demand-side management efforts.
Approximately $1.6 million of the Company's construction expenditures budgeted
for 1996 are to comply with environmental laws and regulations. Assuming
favorable market conditions, the Company anticipates refinancing at lower
interest rates up to $300 million of long-term debt in 1996.
Future financing requirements may be dependent, to varying degrees, upon
numerous factors such as general economic conditions, abnormal weather, load
growth, inflation, changes in environmental laws or regulations, rate increases
or decreases allowed by regulatory agencies, new legislation and market entry of
competing electric power generators.
32
FUTURE SOURCES OF FINANCING
Management expects that internally generated funds will be adequate over
the next three years to meet anticipated capital requirements. Short-term
borrowings will continue to be used to meet temporary cash requirements. The
Company has the necessary regulatory approvals to incur up to $400 million in
short-term borrowings at any one time. The Company has in place a line of credit
for up to $160 million which expires December 6, 2000.
The Company continues to evaluate opportunities to enhance shareowner
returns and achieve long-term financial objectives through acquisitions of
non-utility businesses. Permanent financing could be required for any such
acquisitions.
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. Two of the sites are in an operating and maintenance mode and will
require minimal financial support from OG&E. The Company's total waste disposed
at the remaining site is minimal. The Company recently elected to participate in
the de minimis settlement offered by the EPA. This limits the Company's
financial obligation in addition to removing any participation in the site
remedy. While it is not possible to determine the precise outcome of these
matters, in the opinion of management, the Company's ultimate liability for the
clean-up costs of these sites will not have a material adverse effect on the
Company's consolidated 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.
Gas transportation within Oklahoma appears to be moving towards a
market-based rate environment at the urging of the OCC. Recently, the OCC
ordered local distribution company affiliates of NORAM (an interstate natural
gas pipeline) to implement a competitive bidding process by September 1996 for
100% of their gas transportation requirements to the cities they serve.
Currently, these local distribution companies are served by a regulated
interstate gas pipeline that is an affiliate of NORAM. In addition, in March
1995, the OCC reached a revenue requirement and rate design joint settlement
with Public Service Company of Oklahoma ("PSO") and its interstate pipeline
affiliate Transok Inc. which will require, among other provisions, that a
competitive bidding process for PSO's gas transportation requirements be phased
in over a five-year period beginning January 1, 1998. The OCC order provides
that a minimum of 25% of PSO's capacity requirements must be met by
non-affiliated transporters by January 1, 1998, if justified by the bidding and
evaluation process.
The Company is unable to predict what rates will be approved by the OCC in
future years for the transportation services provided by Enogex to OG&E, but the
Company anticipates that OG&E will in the future transition to a market-based
rate environment for some portion of its gas transportation requirements
currently met by Enogex. In 1995, approximately $44 million or 25 percent of
Enogex's revenues were attributable to transporting natural gas for OG&E. The
Company further anticipates that OG&E will release firm capacity on the Enogex
pipeline system as part of the transition process which will enable Enogex to
compete for the new Oklahoma markets which are developing. Other pipelines
seeking to compete with Enogex for OG&E's business will likely have to pay a fee
to Enogex for transporting the gas
33
on Enogex's system or incur capital expenditures to develop the necessary
infrastructure to connect with OG&E's gas-fired generating stations.
The Company has contracted for low-sulphur coal to comply with the sulfur
dioxide limitations of the Clean Air Act Amendments of 1990 ("CAAA"). Since all
of OG&E's coal-fired generating units currently burn low-sulfur coal, OG&E is
not required to take any steps to comply with the new sulfur dioxide emission
limits until January 1, 2000. The CAAA will also regulate emissions of nitrogen
oxides and possibly certain hazardous air pollutants. The Company believes it
can meet the current EPA Phase II limit for nitrogen oxides without additional
expenditures. EPA's report on utility air toxic emissions has not been issued to
date. With this uncertainty, it is possible that additional capital expenditures
may be necessary in future years.
In compliance with Title IV of the CAAA, the Company completed installation
of continuous emission monitors ("CEMs") on each of its generating units in
1995, a project which had begun in 1994. Capital expenditures on CEMs in 1995
totalled approximately $767,000, with operating and maintenance expenses of
$113,000. Capital expenditures in 1996 to complete the CEM project are expected
to be negligible, while operating and maintenance expenses are expected to total
approximately $125,000.
The Oklahoma Department of Environmental Quality's ("ODEQ") CAAA Title V
air permitting program by the EPA was approved in March 1996. Comprehensive site
air permits, as required under CAAA Title V, should be administratively complete
and submitted to the ODEQ by the end of July 1996 for two of the company's six
major source generating stations. Title V permits for the remaining major source
generating stations should be complete within six months thereafter. Air permit
fees for all generating stations are expected to cost approximately $340,000 in
1996.
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.
Pursuant to the Energy Act, the FERC earlier this year issued a Notice of
Proposed Rulemaking on Open Access Non-discriminatory Transmission Services and
a Supplemental Notice of Proposed Rulemaking on Stranded Investment
(collectively, the Mega-NOPR). The Mega-NOPR is intended, among other things, to
create a vigorous wholesale electric market by requiring transmission providers
to offer open access to their transmission systems. Concurrently with the
Mega-NOPR, FERC issued a proposal for a Real-Time Information Network intended
to facilitate open access by requiring each electric utility to create an
electronic bulletin board of information regarding their transmission system
services, availability and rates. At the state level, several states are
considering proposals to require "retail wheeling," which is the transmission of
power generated by a third party to retail customers of another utility. During
1995, the OCC conducted an energy symposium to discuss retail wheeling and the
state legislature is conducting hearings during the 1996 legislative session.
The Arkansas legislature had a retail wheeling bill introduced in 1995, but it
was not passed out of committee and the issue probably will not be introduced
again until the 1997 legislative session. OG&E believes it is premature to order
retail wheeling since the FERC has not fully adopted rules for the wholesale
power market. The Company also believes before any retail competition is
ordered, there must be revisions in state and federal laws to discontinue tax
subsidies and other preferences to federal, state, and municipal power
authorities as well as rural electric cooperatives. All electric providers must
compete on a fair and equitable basis. The Energy Act and other factors are
expected to significantly increase competition in the electric industry. The
Company has taken
34
steps such as its 1994 restructuring of its operations and its anticipated
holding company reorganization, 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.
35
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
- -----------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
Year ended December 31 (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1995 1994 1993
=====================================================================================================================
OPERATING REVENUES $1,302,037 $1,355,168 $1,447,252
- ---------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Fuel ....................................................... 260,443 263,329 383,207
Purchased power............................................. 216,598 228,701 218,689
Gas purchased for resale.................................... 87,293 114,044 140,311
Other operation............................................. 233,250 216,961 196,323
Maintenance................................................. 57,574 67,233 78,665
Restructuring .............................................. --- 21,035 ---
Depreciation................................................ 132,135 126,377 119,543
Current income taxes........................................ 77,895 50,129 72,003
Deferred income taxes, net.................................. (3,928) 27,092 5,286
Deferred investment tax credits, net........................ (5,150) (5,150) (5,150)
Taxes other than income..................................... 43,780 44,951 43,222
- ---------------------------------------------------------------------------------------------------------------------
Total operating expenses................................ 1,099,890 1,154,702 1,252,099
- ---------------------------------------------------------------------------------------------------------------------
OPERATING INCOME ................................................ 202,147 200,466 195,153
- ---------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
Interest income............................................. 4,380 3,409 1,431
Other....................................................... (3,580) (5,576) (2,732)
- ---------------------------------------------------------------------------------------------------------------------
Net other income and deductions......................... 800 (2,167) (1,301)
- ---------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt.................................. 67,549 67,680 70,490
Allowance for borrowed funds used during construction....... (1,224) (1,073) (433)
Other....................................................... 11,366 7,907 9,518
- ---------------------------------------------------------------------------------------------------------------------
Total interest charges, net............................. 77,691 74,514 79,575
- ---------------------------------------------------------------------------------------------------------------------
NET INCOME ...................................................... 125,256 123,785 114,277
PREFERRED DIVIDEND REQUIREMENTS.................................. 2,316 2,317 2,317
- ---------------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON.................................... $ 122,940 $ 121,468 $ 111,960
=====================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (thousands).................... 40,356 40,344 40,328
EARNINGS PER AVERAGE COMMON SHARE................................ $ 3.05 $ 3.01 $ 2.78
=====================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
36
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year ended December 31 (DOLLARS IN THOUSANDS) 1995 1994 1993
=====================================================================================================================
BALANCE AT BEGINNING OF PERIOD................................. $ 409,960 $ 395,811 $ 391,135
ADD - net income 125,256 123,785 114,277
Total................................................. 535,216 519,596 505,412
DEDUCT:
Cash dividends declared on preferred stock................ 2,316 2,317 2,317
Cash dividends declared on common stock................... 107,355 107,319 107,284
- ---------------------------------------------------------------------------------------------------------------------
Total................................................. 109,671 109,636 109,601
- ---------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD....................................... $ 425,545 $ 409,960 $ 395,811
=====================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
37
CONSOLIDATED BALANCE SHEETS
December 31 (DOLLARS IN THOUSANDS) 1995 1994 1993
=====================================================================================================================
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service................................................ $3,898,829 $3,770,247 $3,656,113
Construction work in progress............................. 29,705 43,943 33,970
- ---------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment................... 3,928,534 3,814,190 3,690,083
Less accumulated depreciation.................... 1,585,274 1,487,300 1,370,227
- ---------------------------------------------------------------------------------------------------------------------
Net property, plant and equipment......................... 2,343,260 2,326,890 2,319,856
- ---------------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost........................ 9,943 7,868 6,920
- ---------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents................................. 5,420 2,455 6,593
Accounts receivable - customers, less reserve of $4,205,
$3,719 and $4,070, respectively......................... 126,273 118,318 126,997
Accrued unbilled revenues................................. 43,550 36,800 45,100
Accounts receivable - other............................... 9,152 8,601 6,269
Fuel inventories, at LIFO cost............................ 60,356 46,494 27,127
Materials and supplies, at average cost................... 22,996 30,401 26,813
Prepayments and other..................................... 4,535 43,137 28,648
Accumulated deferred tax assets........................... 10,759 12,077 24,088
- ---------------------------------------------------------------------------------------------------------------------
Total current assets.................................. 283,041 298,283 291,635
- ---------------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Advance payments for gas.................................. 6,500 10,000 21,165
Income taxes recoverable through future rates............. 41,934 47,246 47,593
Other..................................................... 70,193 92,342 44,255
- ---------------------------------------------------------------------------------------------------------------------
Total deferred charges................................ 118,627 149,588 113,013
- ---------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS .................................................. $2,754,871 $2,782,629 $2,731,424
=====================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
38
CONSOLIDATED BALANCE SHEETS (Continued)
December 31 (DOLLARS IN THOUSANDS) 1995 1994 1993
=====================================================================================================================
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statements):
Common stock and retained earnings........................ $ 937,535 $ 921,177 $ 906,804
Cumulative preferred stock................................ 49,939 49,973 49,973
Long-term debt............................................ 843,862 730,567 838,660
- ---------------------------------------------------------------------------------------------------------------------
Total capitalization.................................. 1,831,336 1,701,717 1,795,437
- ---------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Short-term debt........................................... 67,600 182,750 47,000
Accounts payable ......................................... 72,089 66,391 100,285
Dividends payable ........................................ 27,427 27,415 27,410
Customers' deposits....................................... 21,920 20,904 19,353
Accrued taxes ............................................ 27,937 25,153 24,717
Accrued interest.......................................... 19,144 23,873 26,712
Long-term debt due within one year........................ --- 25,350 350
Accumulated provision for rate refund..................... 2,650 2,970 39,117
Other..................................................... 33,388 41,321 48,666
- ---------------------------------------------------------------------------------------------------------------------
Total current liabilities............................. 272,155 416,127 333,610
- ---------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation.................... 67,350 71,014 16,210
Accumulated deferred income taxes......................... 485,078 497,056 484,003
Accumulated deferred investment tax credits............... 83,178 88,328 93,478
Other..................................................... 15,774 8,387 8,686
- ---------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities.......... 651,380 664,785 602,377
- ---------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 9 and 10)
- ---------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES........................... $2,754,871 $2,782,629 $2,731,424
=====================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
39
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31 (DOLLARS IN THOUSANDS) 1995 1994 1993
=====================================================================================================================
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................................... 608,273 608,158 608,195
Retained earnings ......................................... 425,545 409,960 395,811
Treasury stock - 6,097,357, 6,116,229, and 6,124,139
shares, respectively................................... (212,460) (213,118) (213,379)
- ---------------------------------------------------------------------------------------------------------------------
Total common stock and retained earnings.......... 937,535 921,177 906,804
- ---------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK:
Par value $20, authorized 675,000 shares - 4%;
421,963, 423,663, and 423,663 shares, respectively..... 8,439 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.................. 49,939 49,973 49,973
- ---------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT:
First mortgage bonds-
SERIES DATE DUE
4.50 % March 1, 1995............................. --- 25,000 25,000
5.125% January 1, 1997........................... 15,000 15,000 15,000
6.375% January 1, 1998........................... 25,000 25,000 25,000
7.125% January 1, 1999........................... 12,500 12,500 12,500
8.625% January 1, 2000........................... --- 30,000 30,000
6.25 % Senior Notes Series B, October 15, 2000... 110,000 --- ---
7.125% January 1, 2002........................... 40,000 40,000 40,000
8.375% January 1, 2004........................... --- 75,000 75,000
9.125% January 1, 2005........................... --- 60,000 60,000
8.625% January 1, 2006........................... --- 55,000 55,000
8.375% January 1, 2007........................... 75,000 75,000 75,000
8.625% November 1, 2007.......................... 35,000 35,000 35,000
8.25 % August 15, 2016........................... 100,000 100,000 100,000
8.875% December 1, 2020.......................... 75,000 75,000 75,000
7.30 % Senior Notes Series A, October 15, 2025... 110,000 --- ---
5.875% Pollution Control Series A, 12-1-2007..... --- 47,000 47,000
7.00 % Pollution Control Series C, 3-1-2017...... 56,000 56,000 56,000
Other bonds-
6.75 % Muskogee Industrial Trust Bonds,
March 1, 2006............................. --- 32,050 32,400
Var. % Garfield Industrial Authority, 1-1-2025 ... 47,000 --- ---
Var. % Muskogee Industrial Authority, 1-1-2025 ... 32,400 --- ---
Unamortized premium and discount, net...................... (9,038) (8,533) (8,890)
Enogex Inc. notes (Note 5)................................. 120,000 6,900 90,000
- ---------------------------------------------------------------------------------------------------------------------
Total long-term debt.............................. 843,862 755,917 839,010
Less long-term debt due within one year....... --- 25,350 350
- ---------------------------------------------------------------------------------------------------------------------
Total long-term debt (excluding long-term
debt due within one year)..................... 843,862 730,567 838,660
- ---------------------------------------------------------------------------------------------------------------------
Total Capitalization .......................................... $1,831,336 $1,701,717 $1,795,437
=====================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
40
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31 (DOLLARS IN THOUSANDS) 1995 1994 1993
=====================================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income................................................... $ 125,256 $ 123,785 $ 114,277
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation.............................................. 132,135 126,377 119,543
Deferred income taxes and investment tax credits, net..... (9,078) 21,942 136
Provision for rate refund................................. 3,112 4,200 21,117
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers....................... (7,955) 8,679 (19,192)
Accrued unbilled revenues............................. (6,750) 8,300 200
Fuel, materials and supplies inventories.............. (6,457) (22,955) 7,740
Accumulated deferred tax assets....................... 1,318 12,011 (24,088)
Other current assets.................................. 38,051 (16,821) (23,324)
Accounts payable...................................... 5,887 (35,667) 5,268
Accrued taxes ........................................ 2,784 436 (2,452)
Accrued interest...................................... (4,729) (2,839) (3,249)
Accumulated provision for rate refund................. (320) (36,147) 39,117
Other current liabilities............................. (6,905) (5,789) 4,600
Other operating activities................................ 15,160 18,698 (12,841)
- ---------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities........... 281,509 204,210 226,852
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures...................................... (141,439) (151,012) (127,674)
- ---------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities................. (141,439) (151,012) (127,674)
- ---------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt, net......................... 87,750 (83,450) (15,300)
Short-term debt, net...................................... (115,150) 135,750 21,000
Redemption of preferred stock............................. (34) --- ---
Cash dividends declared on preferred stock................ (2,316) (2,317) (2,317)
Cash dividends declared on common stock................... (107,355) (107,319) (107,284)
- ---------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities................. (137,105) (57,336) (103,901)
- ---------------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS................................................. 2,965 (4,138) (4,723)
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD...................................................... 2,455 6,593 11,316
CASH AND CASH EQUIVALENTS AT END OF PERIOD..................... $ 5,420 $ 2,455 $ 6,593
=====================================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Cash Paid During the Period for:
Interest (net of amount capitalized).................. $ 76,860 $ 74,372 $ 71,401
Income taxes ......................................... $ 77,752 $ 57,416 $ 79,953
- ---------------------------------------------------------------------------------------------------------------------
DISCLOSURE OF ACCOUNTING POLICY:
For purposes of these statements, the Company considers all highly liquid debt
instruments purchased with a maturity of three months or less to be cash
equivalents. These investments are carried at cost which approximates market.
=====================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
41
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 ("OCC")
and the Arkansas Public Service Commission ("APSC"). Additionally, OG&E, as a
regulated utility, 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". SFAS No. 71 provides that certain costs
that would otherwise be charged to expense can be deferred as regulatory assets,
based on expected recovery from customers in future rates. Likewise, certain
credits that would otherwise be charged to expense are deferred as regulatory
liabilities based on expected flowback to customers in future rates.
Management's expected recovery of deferred costs and flowback of deferred
credits generally results from specific decisions by regulators granting such
ratemaking treatment. Regulatory assets and liabilities are amortized consistent
with ratemaking treatment established by regulators. Management continuously
monitors the future recoverability of regulatory assets. When, in management's
judgment, future recovery becomes impaired, the amount of the regulatory asset
is reduced or written-off, as appropriate. See Notes 7 and 10 of Notes to
Consolidated Financial Statements for related discussion.
In March 1995 the Financial Accounting Standards Board issued SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." Adoption of SFAS No. 121 is required for fiscal years beginning
after December 15, 1995. The Company will adopt this new standard effective
January 1, 1996, and believes it will not have a material impact on the
Company's financial position or its results of operations.
USE OF ESTIMATES
In preparing the consolidated financial statements, management is required
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
PROPERTY, PLANT AND EQUIPMENT
All property, plant and equipment is recorded at cost. Electric utility
plant is recorded at its original cost. Newly constructed plant is added to
plant balances at costs which include contracted services, direct labor,
materials, overhead, and allowance for funds used during construction.
Replacement of major units of property are capitalized as plant. The replaced
plant is removed from plant balances and
42
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 percent of the
average depreciable utility plant, for each of the years 1995, 1994 and 1993, is
provided on a straight-line method over the estimated service life of the
property. Depreciation is provided at the unit level for production plant and at
the account or sub-account level for all other plant, and is based on the
average life group procedure.
Enogex's gas pipeline, gathering systems, compressors and gas processing
plants are depreciated on a straight-line method over periods ranging from 15 to
48 years.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction ("AFUDC") is calculated
according to FERC pronouncements for the imputed cost of equity and borrowed
funds. AFUDC, a non-cash item, is reflected as a credit on the Consolidated
Statements of Income and a charge to construction work in progress.
AFUDC rates, compounded semi-annually, were 6.3, 4.58, and 3.6 percent for
the years 1995, 1994 and 1993, respectively.
UNBILLED REVENUE
OG&E accrues estimated revenues for services provided but not yet billed.
The cost of providing service is recognized as incurred.
AUTOMATIC FUEL ADJUSTMENT CLAUSES
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in estimated
cost-of-service for ratemaking, are charged to substantially all of the
Company's electric customers through automatic fuel adjustment clauses, which
are subject to periodic review by the OCC, the APSC and the FERC.
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. The estimated replacement cost of fuel inventories
exceeded the stated LIFO cost by approximately $2.4 million, $2.5 million, and
$2.3 million for 1995, 1994 and 1993, respectively, based on the average cost of
fuel purchased late in the respective years. LIFO liquidation gains and losses
(no gains or losses in 1995 and 1994, and approximately $500,000 gain in 1993)
reduces or increases the Company's recovery under its automatic fuel adjustment
clauses, with no impact on net income. Natural gas products inventories are held
for sale and accounted for based on the weighted average cost of production.
43
ENVIRONMENTAL COSTS
Accruals for environmental costs are recognized when it is probable that a
liability has been incurred and the amount of the liability can be reasonably
estimated. When a single estimate of the liability cannot be determined, the low
end of the estimated range is recorded. Costs are charged to expense or deferred
as a regulatory asset based on expected recovery from customers in future rates,
if they relate to the remediation of conditions caused by past operations or if
they are not expected to mitigate or prevent contamination from future
operations. Where environmental expenditures relate to facilities currently in
use, such as pollution control equipment, the costs may be capitalized and
depreciated over the future service periods. Estimated remediation costs are
recorded at undiscounted amounts, independent of any insurance or rate recovery,
based on prior experience, assessments and current technology. Accrued
obligations are regularly adjusted as environmental assessments and estimates
are revised, and remediation efforts proceed. For sites where OG&E has been
designated as one of several potentially responsible parties, the amount accrued
represents OG&E's estimated share of the cost.
2. Income Taxes
The items comprising tax expense are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------
Provision For Current Income Taxes:
Federal............................................. $ 65,173 $ 42,974 $ 61,406
State............................................... 12,722 7,155 10,597
- ---------------------------------------------------------------------------------------------------------
Total Provision For Current Income Taxes.......... 77,895 50,129 72,003
- ---------------------------------------------------------------------------------------------------------
Provisions (Benefit) For Deferred Income Taxes, net:
Federal
Depreciation...................................... 6,084 7,372 9,673
Repair allowance.................................. 2,101 1,109 1,360
Removal costs..................................... 700 1,542 1,026
Provision for rate refund......................... (588) 12,406 (6,972)
Company restructuring............................. (8,373) --- ---
Other............................................. (2,678) 812 (225)
State............................................... (1,174) 3,851 424
- ---------------------------------------------------------------------------------------------------------
Total Provision (Benefit) For Deferred Income Taxes, net (3,928) 27,092 5,286
- ---------------------------------------------------------------------------------------------------------
Deferred Investment Tax Credits, net.................. (5,150) (5,150) (5,150)
Income Taxes Relating to Other Income and Deductions.. 1,436 203 (538)
- ---------------------------------------------------------------------------------------------------------
Total Income Tax Expense.......................... $ 70,253 $ 72,274 $ 71,601
- ---------------------------------------------------------------------------------------------------------
Pretax Income......................................... $195,509 $196,059 $185,878
=========================================================================================================
44
The following schedule reconciles the statutory federal tax rate to the
effective income tax rate:
Year ended December 31 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------
Statutory federal tax rate............................ 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit. 3.8 3.7 3.9
Tax credits, net...................................... (4.8) (3.8) (3.2)
Change in federal tax rate............................ --- --- 0.9
Other, net............................................ 1.9 2.0 1.9
- ---------------------------------------------------------------------------------------------------------
Effective income tax rate as reported............... 35.9% 36.9% 38.5%
=========================================================================================================
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.
Current income tax expense increased in 1995 primarily due to costs
incurred related to the Company restructuring and payment of the rate refund in
1994. The expenses accrued for the Company restructuring will not be deductible
for income tax purposes until the benefits are paid in future years.
The Company follows the provisions of SFAS No. 109, "Accounting for Income
Taxes", which it adopted effective January 1, 1993. SFAS No. 109 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.
45
The components of Accumulated Deferred Income Taxes at December 31, 1995,
1994 and 1993 are as follows:
(DOLLARS IN THOUSANDS) 1995 1994 1993
==================================================================================================
Current Deferred Tax Assets:
Accrued vacation ..................................... $ 3,666 $ 3,363 $ 4,177
Postemployment medical and life insurance benefits.... --- 3,235 ---
Provision for rate refund............................. 1,025 375 14,965
Uncollectible accounts................................ 1,782 1,218 2,130
Capitalization of indirect costs...................... 2,583 2,583 2,816
Provision for Worker's Compensation claims............ 1,568 --- ---
Other................................................. 135 1,303 ---
- --------------------------------------------------------------------------------------------------
Accumulated deferred tax assets..................... $ 10,759 $ 12,077 $ 24,088
==================================================================================================
Deferred Tax Liabilities:
Accelerated depreciation and other property-related
differences........................................... $460,332 $455,943 $439,253
Allowance for funds used during construction.......... 49,572 53,317 57,074
Income taxes recoverable through future rates......... 54,023 58,470 62,441
- --------------------------------------------------------------------------------------------------
Total............................................... 563,927 567,730 558,768
- --------------------------------------------------------------------------------------------------
Deferred Tax Assets:
Deferred investment tax credits....................... (27,120) (28,868) (30,616)
Income taxes refundable through future rates.......... (37,795) (40,186) (44,022)
Postemployment medical and life insurance benefits.... (2,347) --- ---
Company pension plan.................................. (11,612) (6,417) (3,255)
Other................................................. 25 4,797 3,128
- --------------------------------------------------------------------------------------------------
Total............................................... (78,849) (70,674) (74,765)
- --------------------------------------------------------------------------------------------------
Accumulated Deferred Income Tax Liabilities............. $485,078 $497,056 $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 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.
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. The change in the
federal income tax rate increased the provision for income taxes approximately
$1.6 million.
46
3. COMMON STOCK AND RETAINED EARNINGS
There were no new shares of common stock issued during 1995, 1994 or 1993.
The $115,000 increase in 1995, $37,000 decrease in 1994 and $21,000 increase in
1993 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.
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 18,872, 18,950, and 18,687
shares of common stock during 1995, 1994 and 1993, respectively. The Company
also reacquired 11,040 and 1,235 shares in 1994 and 1993, respectively. The
shares distributed/reacquired in the reported periods were recorded as treasury
stock.
Changes in common stock were:
(thousands) 1995 1994 1993
- ---------------------------------------------------------------------------------------------
Shares outstanding January 1............................ 40,354 40,346 40,329
Issued/reacquired under the Restricted Stock Plan, net.. 19 8 17
- ---------------------------------------------------------------------------------------------
Shares outstanding December 31.......................... 40,373 40,354 40,346
=============================================================================================
There were 4,009,021 shares of unissued common stock reserved for the
various employee and Company stock plans at December 31, 1995. With the
exception of the Restricted Stock Plan, the common stock requirements, pursuant
to those plans, are currently being satisfied with stock purchased on the open
market.
In October 1995 the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation." The Company has elected to continue to measure stock compensation
cost as prescribed by APB Opinion No. 25, "Accounting for Stock Issued to
Employees" and make the appropriate pro forma disclosures of net income and
earnings effective January 1, 1996.
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 incurred
$14 million relating to obtaining such amendments and began amortizing these
costs over the remaining life of the respective bond issues. In November 1995,
the Company redeemed $220 million principal amount of outstanding First Mortgage
Bonds and expensed approximately $3 million of the costs incurred in obtaining
the amendments. At the end of 1995, there was approximately $6.3 million in
unamortized costs associated with obtaining these amendments.
47
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 acquirer 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.
The Company's Restated Certificate of Incorporation permits the issuance of
new series of preferred stock with dividends payable other than quarterly.
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 percent 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 percent of principal
amounts of bonds otherwise required to be redeemed. Through December 31, 1995,
gross property additions pledged totaled approximately $369 million.
Annual sinking fund requirements for each of the five years subsequent to
December 31, 1995, are as follows:
Year Amount
================================================================
1996........................................ $ 13,614,583
1997........................................ $ 13,302,083
1998........................................ $ 12,781,249
1999........................................ $ 12,520,833
2000........................................ $ 10,229,166
================================================================
As in prior years, OG&E expects to meet these requirements by pledging
permanent additions to property.
48
The Company successfully refinanced approximately $306 million of long-term
debt in 1995. The following table summarizes the 1995 refinancing activity:
(DOLLARS IN THOUSANDS) Series New Debt Old Debt
- ----------------------------------------------------------------------------
Senior Notes Series B............. 6.25 % $110,000 $ ---
Senior Notes Series A............. 7.30 % 110,000 ---
First Mortgage Bonds.............. 8.625% --- 30,000
First Mortgage Bonds.............. 8.375% --- 75,000
First Mortgage Bonds.............. 9.125% --- 60,000
First Mortgage Bonds.............. 8.625% --- 55,000
Garfield Industrial Authority..... Var. % 47,000 ---
Muskogee Industrial Authority..... Var. % 32,400 ---
Pollution Control Series A........ 5.875% --- 47,000
Muskogee Industrial Trust......... 6.75 % --- 32,050
Enogex Inc. Notes ................ 6.89 % 120,000 ---
Enogex Inc. Notes ................ Var. % --- 6,900
- ----------------------------------------------------------------------------
Total........................ $419,400 $305,950
============================================================================
As of December 31, 1995, Enogex long-term debt consisted of $120 million of
medium-term notes at a composite rate of 6.89%. The following table itemizes the
Enogex long-term debt at December 31, 1995, 1994 and 1993:
December 31 (DOLLARS IN THOUSANDS) 1995 1994 1993
- ----------------------------------------------------------------------------------------
Series Due December 21, 1995--9.88%-10.03%....... $ --- $ --- $ 60,000
Series Due December 21, 1998--9.96%-10.11%....... --- --- 30,000
Series Due August 7, 2000--6.76%-6.77%........... 27,000 --- ---
Series Due August 31, 2000--6.68%................ 20,000 --- ---
Series Due September 1, 2000--6.70%.............. 10,000 --- ---
Variable Rate Note Due July 31, 2001............. --- 6,900 ---
Series Due August 7, 2002--7.02%-7.05%........... 63,000 --- ---
- ----------------------------------------------------------------------------------------
Total....................................... $120,000 $ 6,900 $ 90,000
========================================================================================
Maturities of long-term debt during the next five years consist of $15
million in 1997, $25 million in 1998, $12.5 million in 1999 and $167 million in
2000.
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, 1995.
49
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 1995 were $267.7 million and $146.6
million, respectively, at a weighted average interest rate of 6.39%. The
weighted average interest rates for 1994 and 1993 were 4.76% and 3.60%,
respectively. OG&E has an agreement for a flexible line of credit, up to $160
million, through December 6, 2000. The line of credit is maintained on a
variable fee basis on the unused balance. Short-term debt in the amount of $67.6
million was outstanding at December 31, 1995.
7. POSTEMPLOYMENT BENEFIT PLANS
During 1994, the Company restructured its operations, reducing its
workforce by approximately 24 percent. This was accomplished through a Voluntary
Early Retirement Package ("VERP") and an enhanced severance package. The VERP
included enhanced pension benefits as well as postemployment medical and life
insurance benefits.
As a result of the postemployment benefits provided in connection with this
workforce reduction, the Company incurred severance costs and certain one-time
costs computed in accordance with SFAS No. 88, "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits" and SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions". In response to an application
filed by the Company, the OCC directed the Company to defer the one-time costs
which had not been offset by labor savings through December 31, 1994. The
remaining balance of the one-time costs is being amortized over 26 months,
commencing January 1, 1995. The components of the severance and VERP costs and
the amount deferred are as follows:
SFAS SFAS
(DOLLARS IN THOUSANDS) No. 88 No. 106 Severance Total
=============================================================================================
Curtailment Loss....................... $ 1,042 $ 5,457 $ --- $ 6,499
Recognition of Transition Obligation... --- 17,268 --- 17,268
Special Retirement Benefits............ 28,198 6,566 --- 34,764
Enhanced Severance..................... --- --- 4,891 4,891
- ---------------------------------------------------------------------------------------------
Total VERP and Severance Costs......... $29,240 $29,291 $ 4,891 63,422
- ---------------------------------------------------------------------------------------------
Deferred as a Regulatory Asset at December 31, 1994....................... (48,903)
- ---------------------------------------------------------------------------------------------
Postemployment Costs Recognized as Restructuring in 1994.................. 14,519
Consulting Fees........................................................... 2,750
Other..................................................................... 3,766
- ---------------------------------------------------------------------------------------------
1994 Restructuring Expenses............................................... $21,035
=============================================================================================
The restructuring charges reflected above, include only costs that were
actually incurred in 1994. In 1995, amortization of the deferred regulatory
asset was $22.6 million.
50
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 in the
accompanying Consolidated Statements of Income as Other operation.
In determining the projected benefit obligation, the weighted average
discount rates used were 7.25, 8.25 and 7.25 percent for 1995, 1994 and 1993,
respectively. The assumed rate of increase in future salary levels was 4.5
percent in 1995, 1994 and 1993. The expected long-term rate of return on plan
assets used in determining net periodic pension cost was 9 percent for the
reported periods.
The plan's assets consist primarily of U. S. Government securities, listed
common stocks and corporate debt.
Net periodic pension costs for 1995, 1994 and 1993 included the following:
(DOLLARS IN THOUSANDS) 1995 1994 1993
==============================================================================================
Service costs...................................... $ 4,714 $ 7,824 $ 7,630
Interest cost on projected benefit obligation...... 20,392 17,851 14,557
Return on plan assets ............................. (15,036) (17,510) (15,697)
Net amortization and deferral...................... (1,263) (1,263) (1,263)
Amortization of unrecognized prior service cost.... 2,634 1,489 671
- ----------------------------------------------------------------------------------------------
Net periodic pension costs......................... $11,441 $ 8,391 $ 5,898
==============================================================================================
51
The following table sets forth the plan's funded status at December 31,
1995, 1994 and 1993:
(DOLLARS IN THOUSANDS) 1995 1994 1993
=======================================================================================================
Projected benefit obligation:
Vested benefits....................................... $(232,457) $(208,438) $(140,958)
Nonvested benefits.................................... (18,263) (14,664) (21,435)
- -------------------------------------------------------------------------------------------------------
Accumulated benefit obligation........................ (250,720) (223,102) (162,393)
Effect of future compensation levels.................. (44,853) (29,425) (51,196)
- -------------------------------------------------------------------------------------------------------
Projected benefit obligation............................ (295,573) (252,527) (213,589)
Plan's assets at fair value............................. 214,986 177,045 194,501
- -------------------------------------------------------------------------------------------------------
Plan's assets less than projected benefit obligation.... (80,587) (75,482) (19,088)
Unrecognized prior service cost......................... 40,616 43,250 7,942
Unrecognized net asset from application of SFAS No. 87.. (7,580) (8,842) (10,106)
Unrecognized net (gain) loss............................ 9,489 (900) 14,448
- -------------------------------------------------------------------------------------------------------
Accrued pension liability............................... $ (38,062) $ (41,974) $ (6,804)
=======================================================================================================
POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
In addition to providing pension benefits, the Company provides certain
medical and life insurance benefits for retired members ("postretirement
benefits"). Employees retiring from the Company on or after attaining age 55 who
have met certain length of service requirements are entitled to these benefits.
The benefits are subject to deductibles, co-payment provisions and other
limitations. Prior to January 1, 1993, the costs of retiree medical and life
insurance benefits were recognized as expense when claims were paid
("pay-as-you-go").Pay-as-you-go costs totaled approximately $6,513,000,
$4,621,000, and $3,804,000 for 1995, 1994 and 1993, respectively.
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.
During 1993, OG&E expensed pay-as-you-go postretirement benefits and
recorded a deferral for the difference between pay-as-you-go and SFAS No. 106
requirements. The February 25, 1994, OCC rate order directed OG&E 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. Accordingly, OG&E recorded a regulatory asset
for the difference between the amounts using the pay-as-you-go method (adjusted
for the phase-in plan) and those required by SFAS No. 106.
A decision was made in the second quarter of 1994 to discontinue deferral
of the differential and to charge to expense $8.4 million of postretirement
benefits that had been recorded as a regulatory asset. Although OG&E continues
to believe that it could have recovered these costs in future rate proceedings
before the OCC, OG&E decided to recognize these expenses currently, due to its
strategy to reduce its cost-structure, which minimizes future revenue
requirements. OG&E expects to continue charging to expense the SFAS No. 106
costs and to include an annual amount as a component of cost-of-service in
future ratemaking proceedings.
52
Net postretirement benefit expense for 1995, 1994 and 1993 included the
following components:
(DOLLARS IN THOUSANDS) 1995 1994 1993
===================================================================================
Service cost................................ $ 1,932 $ 2,714 $ 2,812
Interest cost............................... 7,242 5,978 6,158
Return on plan assets....................... (576) --- ---
Net amortization............................ 3,325 3,549 3,687
Net amount capitalized or deferred.......... (2,399) (4,557) (8,853)
Discontinued deferral of regulatory asset... --- 8,359 ---
- -----------------------------------------------------------------------------------
Net postretirement benefit expense...... $ 9,524 $16,043 $ 3,804
===================================================================================
The discount rates used in determining the accumulated postretirement
benefit obligation were 7.25, 8.25 and 7.25 percent for December 31, 1995, 1994
and 1993, respectively. The rate of increase in future compensation levels used
in measuring the life insurance accumulated postretirement benefit obligation
was 4.5 percent for December 31, 1995, 1994 and 1993. An 11 percent annual rate
of increase in the per capita cost of covered health care benefits was assumed
for 1995; the rate is assumed to decrease gradually to 4.5 percent by the year
2006 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 obligation as of December 31, 1995, by approximately
$11.2 million, and the aggregate of the service and interest cost components of
net postretirement health care cost for 1995 by approximately $1.1 million.
The following table sets forth the funded status of the postretirement
benefits and amounts recognized in the Company's Consolidated Balance Sheets as
of December 31, 1995, 1994 and 1993:
(DOLLARS IN THOUSANDS) 1995 1994 1993
============================================================================================
Accumulated postretirement benefit obligation:
Retirees................................... $(88,500) $(81,688) $(42,891)
Actives eligible to retire................. (2,420) (2,716) (17,479)
Actives not yet eligible to retire......... (11,869) (7,870) (15,622)
- --------------------------------------------------------------------------------------------
Total.................................... (102,789) (92,274) (75,992)
Plan assets at fair value.................... 23,864 17,279 ---
- --------------------------------------------------------------------------------------------
Funded status ............................... (78,925) (74,995) (75,992)
Unrecognized transition obligation........... 46,734 49,483 70,047
Unrecognized net actuarial loss (gain)....... 4,331 (2,930) (2,908)
- --------------------------------------------------------------------------------------------
Accrued postretirement benefit obligation.... $(27,860) $(28,442) $ (8,853)
============================================================================================
POSTEMPLOYMENT BENEFITS
In November 1992, the FASB issued SFAS No. 112, "Employers' Accounting for
Postemployment Benefits," which requires the accrual of the estimated cost of
benefits provided to former or inactive employees after employment but before
retirement. The Company adopted this new standard effective January 1, 1994,
recording $4.7 million of postemployment benefit cost for 1994 and $2.0 million
for 1995.
53
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.
(DOLLARS IN THOUSANDS) 1995 1994 1993
=================================================================================================
Operating Information:
Operating Revenues
Electric utility........................ $1,168,287 $1,196,898 $1,282,816
Non-utility subsidiary.................. 178,082 203,079 219,376
Intersegment revenues (A)............... (44,332) (44,809) (54,940)
- -------------------------------------------------------------------------------------------------
Total............................... $1,302,037 $1,355,168 $1,447,252
=================================================================================================
Pre-tax Operating Income
Electric utility........................ $ 246,333 $ 248,827 $ 238,761
Non-utility subsidiary.................. 24,631 23,710 28,531
- -------------------------------------------------------------------------------------------------
Total............................... $ 270,964 $ 272,537 $ 267,292
=================================================================================================
Net Income
Electric utility........................ $ 112,545 $ 113,795 $ 104,730
Non-utility subsidiary.................. 12,711 9,990 9,547
- -------------------------------------------------------------------------------------------------
Total............................... $ 125,256 $ 123,785 $ 114,277
=================================================================================================
Investment Information:
Identifiable Assets as of December 31
Electric utility........................ $2,422,609 $2,471,902 $2,443,651
Non-utility subsidiary.................. 332,262 310,727 287,773
- -------------------------------------------------------------------------------------------------
Total............................... $2,754,871 $2,782,629 $2,731,424
=================================================================================================
Other Information:
Depreciation
Electric utility........................ $ 110,719 $ 107,239 $ 104,343
Non-utility subsidiary.................. 21,416 19,138 15,200
- -------------------------------------------------------------------------------------------------
Total............................... $ 132,135 $ 126,377 $ 119,543
=================================================================================================
Construction Expenditures
Electric utility........................ $ 110,276 $ 104,256 $ 105,746
Non-utility subsidiary.................. 43,242 45,634 22,396
- -------------------------------------------------------------------------------------------------
Total............................... $ 153,518 $ 149,890 $ 128,142
=================================================================================================
(A) Intersegment revenues are recorded at prices comparable to those of
unaffiliated customers and are affected by regulatory considerations.
54
On July 19, 1995, OG&E announced plans to create a holding company
structure with OGE Energy Corp. becoming the parent company of OG&E. At a
special meeting of shareowners on November 16, 1995, OG&E shareowners approved
the new holding company structure. Upon regulatory approval, which is currently
expected by mid-1996, OG&E's common stock will be exchanged on a share-for-share
basis for common stock of OGE Energy Corp. and OG&E will become a subsidiary of
OGE Energy Corp. As part of this corporate restructuring, OG&E's wholly-owned
subsidiary, Enogex, will also become a direct subsidiary of OGE Energy Corp.
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 1996 are estimated at $147 million.
The Company acquires natural gas for boiler fuel under 585 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,
1995, 1994 and 1993, outstanding prepayments for gas, including the amounts
classified as current assets, under these contracts were approximately
$7,402,000, $10,879,000 and $22,165,000, 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, 1995, the Company held non-cancelable operating leases
covering 1,518 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)
1996............ $5,991 1999.................... $ 5,644
1997............ 5,875 2000.................... 5,529
1998............ 5,759 2001 and beyond......... 116,930
---------
Total Minimum Lease Payments............................... $145,728
=========
Rental payments under operating leases were approximately $6.5 million in
1995, $5.6 million in 1994 and $4.9 million in 1993.
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 had entered into an agreement with an unrelated third-party to
develop a natural gas storage facility. During 1995, operation of the gas
storage facility proved beneficial by allowing the Company to lower fuel costs
by base loading coal generation, a less costly fuel supply. Also during 1995,
the Company entered into negotiations with the third-party developer for gas
storage service. Pursuant to those ongoing negotiations, the third-party
developer reimbursed OG&E for all outstanding cash advances and interest
amounting to approximately $46.8 million. The Company also entered into a bridge
financing agreement as guarantor for the third-party developer for a period of
one year. Upon final execution of an
55
agreement for storage services, permanent financing by the third-party will
replace the bridge finance agreement with OG&E as guarantor.
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 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 OCC. 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 1995, 1994 and 1993, OG&E made total payments to cogenerators of
approximately $210.4 million, $210.3 million, $213.0 million, of which $174.1
million, $173.2 million, $165.5 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:
1996 - $175 million, 1997 - $176 million, 1998 - $184 million, 1999 - $189
million and 2000 - $190 million.
Approximately $1.6 million of the Company's construction expenditures
budgeted for 1996 are to comply with environmental laws and regulations.
OG&E management believes all of its operations are in substantial
compliance with present federal, state and local environmental standards. It is
estimated that the Company's total expenditures for capital, operating,
maintenance and other costs to preserve and enhance environmental quality will
be approximately $37 million during 1996, compared to approximately $37 million
in 1995. OG&E continues to evaluate its environmental management systems to
ensure compliance with existing and proposed environmental legislation and
regulations and to better position itself in a competitive market.
The Company has contracted for low-sulphur coal to comply with the sulphur
dioxide limitations of the Clean Air Act Amendments of 1990 ("CAAA"). Since all
of OG&E's coal-fired generating units currently burn low-sulfur coal, OG&E is
not required to take any steps to comply with the new sulfur dioxide emission
limits until January 1, 2000. The CAAA will also regulate emissions of nitrogen
oxides and possibly certain hazardous air pollutants. The Company believes it
can meet the current EPA Phase II limit for nitrogen oxides without additional
expenditures. EPA's report on utility air toxic emissions has not been issued to
date. With this uncertainty, it is possible that additional capital expenditures
may be necessary in future years.
The Company is a party to three separate actions brought by the 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. Two of the sites are in an operating
and maintenance mode and will require minimal financial support from OG&E. The
Company's total waste disposed at the remaining site is minimal. The Company
recently elected to participate in the de minimis settlement offered by EPA.
This limits the Company's financial obligation in addition to removing any
participation in the site remedy.
56
The APSC is currently reviewing the amounts that OG&E pays Enogex and
recovers through its fuel adjustment clause for transporting natural gas to
OG&E's gas-fired generating stations. OG&E cannot predict the outcome of this
review. Nevertheless, at the present time, management does not believe this
proceeding will have a material adverse effect on the Company's consolidated
financial position or its results of operations.
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 OCC 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 required OG&E 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 annually. With respect to the $41.3 million refund,
$39.1 million was associated with revenues prior to January 1, 1994, while the
remaining $2.2 million related 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.
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 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.
As discussed in Note 7 of Notes to Consolidated Financial Statements,
during the third quarter of 1994, the Company incurred $63.4 million of costs
related to the VERP and enhanced severance package. Pending an OCC order, OG&E
deferred these costs; however, between August 1, and December 31, 1994, the
amount deferred was reduced by approximately $14.5 million. In response to an
application filed by OG&E on August 9, 1994, the OCC issued an order on October
26, 1994, that permitted the Company to amortize the December 31, 1994,
regulatory asset of $48.9 million over 26 months and reduced OG&E's electric
rates by approximately $15 million annually, effective January 1995. The Company
anticipates that labor savings from the VERP and severance package will
substantially offset the amortization of the regulatory asset and annual rate
reduction of $15 million.
57
The components of Deferred Charges - Other, on the Consolidated Balance
Sheets included the following, as of December 31:
(DOLLARS IN THOUSANDS) 1995 1994 1993
==========================================================================================
Regulatory asset (restructuring)............. $ 26,331 $ 48,903 $ ---
Unamortized debt expense..................... 10,919 12,871 14,146
Enogex gas sales contracts................... 11,294 12,690 ---
Unamortized loss on reacquired debt.......... 11,197 5,487 5,711
Miscellaneous................................ 10,452 12,391 24,398
- ------------------------------------------------------------------------------------------
Total............................... $ 70,193 $ 92,342 $ 44,255
==========================================================================================
Regulatory Assets and Liabilities consisted of the following as of December 31:
(DOLLARS IN THOUSANDS) 1995 1994 1993
==========================================================================================
Regulatory Assets:
Income Taxes Recoverable from Customers.... $139,594 $ 151,086 $161,346
Workforce Reduction (Restructuring)........ 26,331 48,903 ---
Miscellaneous 455 2,214 12,090
- ------------------------------------------------------------------------------------------
Total Regulatory Assets................ 166,380 202,203 173,436
Regulatory Liabilities:
Income Taxes Refundable to Customers....... (97,660) (103,840) (113,753)
Gain on Disposition of Allowances.......... (282) (187) (79)
- ------------------------------------------------------------------------------------------
Net Regulatory Assets........................ $ 68,438 $ 98,176 $ 59,604
==========================================================================================
While the Company does not expect to cease meeting the criteria for
application of SFAS No. 71 in the foreseeable future, if the Company were
required to discontinue the application of SFAS No. 71 for some or all of its
operations, it would result in writing off the related regulatory assets; the
financial effects of which could be significant.
58
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 the Enogex Notes is based on management's
estimate of current rates available for similar issues with the same remaining
maturities.
Indicated below are the carrying amounts and estimated fair values of the
Company's financial instruments as of December 31:
1995 1994 1993
--------------------- --------------------- ---------------------
Carrying Fair Carrying Fair Carrying Fair
(DOLLARS IN THOUSANDS) Amount Value Amount Value Amount Value
====================================================================================================================
ASSETS:
CASH AND CASH EQUIVALENTS......... $ 5,420 $ 5,420 $ 2,455 $ 2,455 $ 6,593 $ 6,593
====================================================================================================================
LIABILITIES:
CUSTOMER DEPOSITS................. $ 21,920 $ 21,920 $ 20,904 $ 20,904 $ 19,353 $ 19,353
====================================================================================================================
CAPITALIZATION:
First Mortgage Bonds.............. $644,462 $671,356 $716,967 $710,523 $716,610 $749,684
Industrial Authority Bonds........ 79,400 79,400 32,050 32,044 32,400 32,604
Enogex Inc. Notes 120,000 124,853 6,900 6,900 90,000 100,486
Preferred Stock:
4% - 5.34% Series -836,963,
838,663 and 838,663 Shares...... 49,939 35,541 49,973 27,442 49,973 34,523
- --------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION............. $893,801 $911,150 $805,890 $776,909 $888,983 $917,297
====================================================================================================================
59
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 31,1995, 1994 and 1993, 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, 1995, 1994 and 1993, and the
results of their operations and their cash flows for the years then ended in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 24, 1996
60
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.
61
Supplementary Data
- ------------------
Interim Consolidated Financial Information (Unaudited)
In the opinion of the Company, the following quarterly information includes
all adjustments, consisting of normal recurring adjustments, necessary for a
fair statement of the results of operations for such periods:
Quarter ended (DOLLARS IN THOUSANDS EXCEPT Dec 31 Sep 30 Jun 30 Mar 31
PER SHARE DATA)
- ----------------------------------------------------------------------------------------------------------------
Operating revenues......................... 1995 $283,898 $467,510 $304,113 $246,516
1994 281,388 443,173 346,623 283,984
1993 301,392 500,639 341,799 303,422
- ----------------------------------------------------------------------------------------------------------------
Operating income........................... 1995 $ 24,948 $115,991 $ 42,800 $ 18,408
1994 23,792 105,563 50,427 20,684
1993 18,899 111,576 39,457 25,221
- ----------------------------------------------------------------------------------------------------------------
Net income (loss).......................... 1995 $ 4,890 $ 96,969 $ 24,258 $ (861)
1994 4,952 86,251 31,082 1,500
1993 (3,619) 90,810 20,396 6,690
- ----------------------------------------------------------------------------------------------------------------
Earnings (loss) available for common....... 1995 $ 4,311 $ 96,390 $ 23,679 $ (1,440)
1994 4,372 85,672 30,503 921
1993 (4,199) 90,231 19,817 6,111
- ----------------------------------------------------------------------------------------------------------------
Earnings (loss) per average common share... 1995 $ 0.11 $ 2.39 $ 0.59 $ (0.04)
1994 0.11 2.12 0.76 0.02
1993 (0.10) 2.24 0.49 0.15
- ----------------------------------------------------------------------------------------------------------------
62
Unaudited Pro Forma Financial Information
- -----------------------------------------
The following unaudited pro forma financial information presents the
historical consolidated balance sheet, statement of income and retained earnings
and ratio of earnings to fixed charges of OG&E after giving effect to the
restructuring, including the transfer of Enogex Inc. and its subsidiaries to OGE
Energy Corp. The unaudited pro forma balance sheet at December 31, 1995, gives
effect to the restructuring as if it had occurred at December 31, 1995. The
unaudited pro forma statements of income and retained earnings for each of the
years in the three-year period ended December 31, 1995, gives effect to the
restructuring as if it had occurred at January 1, 1993. The unaudited pro forma
ratio of earnings to fixed charges for each of the years in the three years
ended December 31, 1995, gives effect to the restructuring as if it had occurred
at January 1, 1993.
The pro forma financial information has been prepared from, and should be
read in conjunction with, the historical consolidated financial statements and
related notes thereto of OG&E. The following information is not necessarily
indicative of the financial position or operating results that would have
occurred had the transaction been consummated on the date, or at the beginning
of the periods, for which the transaction is being given effect nor is it
necessarily indicative of future operating results or financial position.
UNAUDITED PRO FORMA RATIO OF EARNINGS TO FIXED CHARGES
Year Ended December 31,
-----------------------
1995 1994 1993
---- ---- ----
Unaudited Pro Forma Ratio of
Earnings to Fixed Charges 3.59 3.75 3.35
For purposes of this ratio, "Earnings" consist of the aggregate of net
income, taxes on income, investment tax credit (net) and "fixed charges." "Fixed
charges" consist of interest on long term debt, related amortization, interest
on short-term borrowings and a calculated portion of rents considered to be
interest.
See Notes to Unaudited Pro Forma Financial Statements for a description of
the assumptions used to prepare the unaudited pro forma ratio of earnings to
fixed charges.
63
Oklahoma Gas and Electric Company
Unaudited Pro Forma Balance Sheet
December 31, 1995
- -----------------------------------------------------------------------------------------------------------------
OG&E Pro Forma Pro Forma
(As Reported) Adjustments (1) OG&E
------------------- ------------------ ----------------
(DOLLARS IN THOUSANDS)
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service.................................... $3,898,829 $(375,121) $3,523,708
Construction work in progress................. 29,705 (5,259) 24,446
------------------- ------------------ ----------------
Total property, plant and equipment...... 3,928,534 (380,380) 3,548,154
Less accumulated depreciation.......... 1,585,274 (101,375) 1,483,899
------------------- ------------------ ----------------
Net property, plant and equipment........ 2,343,260 (279,005) 2,064,255
------------------- ------------------ ----------------
OTHER PROPERTY AND INVESTMENTS, at cost............ 9,943 (1,917) 8,026
------------------- ------------------ ----------------
CURRENT ASSETS:
Cash and cash equivalents..................... 5,420 (5,023) 397
Accounts receivable - customers, less reserve. 126,273 (23,932) 102,341
Accrued unbilled revenues..................... 43,550 --- 43,550
Accounts receivable - other................... 9,152 1,773 10,925
Fuel inventories, at LIFO cost................ 60,356 (1,079) 59,277
Materials and supplies, at average cost....... 22,996 (4,140) 18,856
Prepayments and other......................... 4,535 (1,056) 3,479
Accumulated deferred tax assets............... 10,759 (717) 10,042
------------------- ------------------ ----------------
Total current assets..................... 283,041 (34,174) 248,867
------------------- ------------------ ----------------
DEFERRED CHARGES:
Advance payments for gas...................... 6,500 --- 6,500
Income taxes recoverable - future rates....... 41,934 --- 41,934
Other......................................... 70,193 (14,525) 55,668
------------------- ------------------ ----------------
Total deferred charges................... 118,627 (14,525) 104,102
------------------- ------------------ ----------------
TOTAL ASSETS....................................... $2,754,871 $(329,621) $2,425,250
=================== ================== ================
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stock and retained earnings............ $ 937,535 $(120,243) $ 817,292
Cumulative preferred stock.................... 49,939 --- 49,939
Long-term debt................................ 843,862 (120,000) 723,862
------------------- ------------------ ----------------
Total capitalization..................... 1,831,336 (240,243) 1,591,093
------------------- ------------------ ----------------
CURRENT LIABILITIES:
Short-term debt............................... 67,600 --- 67,600
Accounts payable.............................. 72,089 (16,814) 55,275
Dividends payable............................. 27,427 --- 27,427
Customers' deposits........................... 21,920 --- 21,920
Accrued taxes................................. 27,937 (1,381) 26,556
Accrued interest.............................. 19,144 (3,177) 15,967
Long-term debt due within one year............ --- --- ---
Accumulated provision for rate refunds........ 2,650 --- 2,650
Other......................................... 33,388 (3,085) 30,303
------------------- ------------------ ----------------
Total current liabilities................ 272,155 (24,457) 247,698
------------------- ------------------ ----------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........ 67,350 (3,367) 63,983
Accumulated deferred income taxes............. 485,078 (57,900) 427,178
Accumulated deferred investment tax credits... 83,178 --- 83,178
Other......................................... 15,774 (3,654) 12,120
------------------- ------------------ ----------------
Total deferred credits and other
liabilities............................ 651,380 (64,921) 586,459
------------------- ------------------ ----------------
TOTAL CAPITALIZATION AND LIABILITIES............... $2,754,871 $(329,621) $2,425,250
=================== ================== ================
SEE ACCOMPANYING NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS.
64
Oklahoma Gas and Electric Company
Unaudited Pro Forma Statements of Income and Retained Earnings
For the year ended December 31, 1995
- --------------------------------------------------------------------------------------------------------------
OG&E Pro Forma Pro Forma
(As Reported) Adjustments(2) OG&E
---------------- ---------------- ---------------
(THOUSANDS EXCEPT PER SHARE DATA)
OPERATING REVENUES:
Electric Utility......................... $1,168,287 $ --- $1,168,287
Non-Utility Subsidiary................... 133,750 (133,750) ---
---------------- ---------------- ---------------
Total Operating Revenues............... 1,302,037 (133,750) 1,168,287
OPERATING EXPENSES:
Fuel .................................... 260,443 44,332 304,775
Purchased power.......................... 216,598 --- 216,598
Gas purchased for resale................. 87,293 (87,293) ---
Other operation.......................... 233,250 (39,016) 194,234
Maintenance.............................. 57,574 (1,935) 55,639
Depreciation and amortization............ 132,135 (21,416) 110,719
Current income taxes..................... 77,895 (5,095) 72,800
Deferred income taxes, net............... (3,928) 1,593 (2,335)
Deferred investment tax credits, net..... (5,150) --- (5,150)
Taxes other than income.................. 43,780 (3,790) 39,990
- ------------------------------------------------- ---------------- ---------------- ---------------
Total operating expenses............... 1,099,890 (112,620) 987,270
- ------------------------------------------------- ------------------------------------- ---------------
OPERATING INCOME.............................. 202,147 (21,130) 181,017
- ------------------------------------------------- ---------------- ---------------- ---------------
OTHER INCOME AND DEDUCTIONS:
Interest income.......................... 4,380 (309) 4,071
Other.................................... (3,580) (704) (4,284)
- ------------------------------------------------- ---------------- ---------------- ---------------
Net other income and deductions........ 800 (1,013) (213)
- ------------------------------------------------- ---------------- ---------------- ---------------
INTEREST CHARGES:
Interest on long-term debt............... 67,549 (3,579) 63,970
Allowance for borrowed funds used
during construction.................... (1,224) --- (1,224)
Other.................................... 11,366 (5,852) 5,514
- ------------------------------------------------- ---------------- ---------------- ---------------
Total interest charges, net............ 77,691 (9,431) 68,260
- ------------------------------------------------- ---------------- ---------------- ---------------
NET INCOME ................................... 125,256 (12,712) 112,544
PREFERRED DIVIDEND REQUIREMENTS............... 2,316 --- 2,316
---------------- ---------------- ---------------
EARNINGS AVAILABLE FOR COMMON................ $ 122,940 $ (12,712) $ 110,228
================ ================ ===============
AVERAGE COMMON SHARES
OUTSTANDING............................... 40,356 --- 40,356
EARNINGS PER AVERAGE COMMON SHARE............. $ 3.05 $ (0.32) $ 2.73
STATEMENT OF RETAINED EARNINGS
OG&E Pro Forma Pro Forma
(As Reported) Adjustments OG&E
---------------- ---------------- ---------------
BALANCE AT BEGINNING OF PERIOD................ $ 409,960 $ (104,197) $ 305,763
ADD-net income................................ 125,256 (12,712) 112,544
---------------- ---------------- ---------------
Total..................................... 535,216 (116,909) 418,307
DEDUCT:
Cash dividends declared on preferred stock.. 2,316 --- 2,316
Cash dividends declared on common stock..... 107,355 (12,666) 94,689
---------------- ---------------- ---------------
Total..................................... 109,671 (12,666) 97,005
---------------- ---------------- ---------------
BALANCE AT END OF PERIOD...................... $ 425,545 $ (104,243) $ 321,302
================ ================ ===============
SEE ACCOMPANYING NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS.
65
OKLAHOMA GAS AND ELECTRIC COMPANY
UNAUDITED PRO FORMA STATEMENTS OF INCOME AND RETAINED EARNINGS
FOR THE YEAR ENDED DECEMBER 31, 1994
==============================================================================================================
OG&E PRO FORMA PRO FORMA
(AS REPORTED) ADJUSTMENTS(2) OG&E
---------------- ---------------- ---------------
(THOUSANDS EXCEPT PER SHARE DATA)
OPERATING REVENUES:
Electric Utility......................... $1,196,898 $ --- $1,196,898
Non-Utility Subsidiary................... 158,270 (158,270) ---
--------------- ---------------- ---------------
Total Operating Revenues............... 1,355,168 (158,270) 1,196,898
OPERATING EXPENSES:
Fuel .................................... 263,329 44,810 308,139
Purchased power.......................... 228,701 --- 228,701
Gas purchased for resale................. 114,044 (114,044) ---
Other operation.......................... 216,961 (40,293) 176,668
Maintenance.............................. 67,233 (2,051) 65,182
Restructuring............................ 21,035 --- 21,035
Depreciation and amortization............ 126,377 (19,138) 107,239
Current income taxes..................... 50,129 (2,288) 47,841
Deferred income taxes, net............... 27,092 (1,780) 25,312
Deferred investment tax credits, net..... (5,150) --- (5,150)
Taxes other than income.................. 44,951 (3,844) 41,107
- ---------------------------------------------- --------------- ---------------- ---------------
Total operating expenses............... 1,154,702 (138,628) 1,016,074
- ---------------------------------------------- --------------- ---------------- ---------------
OPERATING INCOME.............................. 200,466 (19,642) 180,824
- ---------------------------------------------- --------------- ---------------- ---------------
OTHER INCOME AND DEDUCTIONS:
Interest income.......................... 3,409 (234) 3,175
Other.................................... (5,576) 693 (4,883)
- ---------------------------------------------- --------------- ---------------- ---------------
Net other income and deductions........ (2,167) 459 (1,708)
- ---------------------------------------------- --------------- ---------------- ---------------
INTEREST CHARGES:
Interest on long-term debt............... 67,680 (6,454) 61,226
Allowance for borrowed funds used
during construction.................... (1,073) --- (1,073)
Other.................................... 7,907 (2,739) 5,168
- ---------------------------------------------- --------------- ---------------- ---------------
Total interest charges, net............ 74,514 (9,193) 65,321
- ---------------------------------------------- --------------- ---------------- ---------------
NET INCOME ................................... 123,785 (9,990) 113,795
PREFERRED DIVIDEND REQUIREMENTS............... 2,317 --- 2,317
--------------- ---------------- ---------------
EARNINGS AVAILABLE FOR COMMON................ $ 121,468 $ (9,990) $ 111,478
=============== ================ ===============
AVERAGE COMMON SHARES
OUTSTANDING............................... 40,344 --- 40,344
EARNINGS PER AVERAGE COMMON SHARE............. $ 3.01 $ (0.25) $ 2.76
STATEMENT OF RETAINED EARNINGS
OG&E PRO FORMA PRO FORMA
(AS REPORTED) ADJUSTMENTS OG&E
--------------- ---------------- ----------------
BALANCE AT BEGINNING OF PERIOD................ $ 395,811 $ (103,277) $ 292,534
ADD-net income................................ 123,785 (9,990) 113,795
--------------- ---------------- ----------------
Total..................................... 519,596 (113,267) 406,329
DEDUCT:
Cash dividends declared on preferred stock.. 2,317 --- 2,317
Cash dividends declared on common stock..... 107,319 (9,070) 98,249
--------------- ---------------- ----------------
Total..................................... 109,636 (9,070) 100,566
--------------- ---------------- ----------------
BALANCE AT END OF PERIOD...................... $ 409,960 $ (104,197) $ 305,763
=============== ================ ================
SEE ACCOMPANYING NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS.
66
OKLAHOMA GAS AND ELECTRIC COMPANY
UNAUDITED PRO FORMA STATEMENTS OF INCOME AND RETAINED EARNINGS
FOR THE YEAR ENDED DECEMBER 31, 1993
==============================================================================================================
OG&E PRO FORMA PRO FORMA
(AS REPORTED) ADJUSTMENTS(2) OG&E
---------------- ---------------- ---------------
(THOUSANDS EXCEPT PER SHARE DATA)
OPERATING REVENUES:
Electric Utility......................... $1,282,816 $ --- $1,282,816
Non-Utility Subsidiary................... 164,436 (164,436) ---
--------------- ---------------- ---------------
Total Operating Revenues............... 1,447,252 (164,436) 1,282,816
OPERATING EXPENSES:
Fuel .................................... 383,207 54,940 438,147
Purchased power.......................... 218,689 --- 218,689
Gas purchased for resale................. 140,311 (140,311) ---
Other operation.......................... 196,323 (29,696) 166,627
Maintenance.............................. 78,665 (1,878) 76,787
Depreciation and amortization............ 119,543 (15,200) 104,343
Current income taxes..................... 72,003 (7,357) 64,646
Deferred income taxes, net............... 5,286 (2,018) 3,268
Deferred investment tax credits, net..... (5,150) --- (5,150)
Taxes other than income.................. 43,222 (3,760) 39,462
- ---------------------------------------------- --------------- ---------------- ---------------
Total operating expenses............... 1,252,099 (145,280) 1,106,819
- ---------------------------------------------- --------------- ---------------- ---------------
OPERATING INCOME.............................. 195,153 (19,156) 175,997
- ---------------------------------------------- --------------- ---------------- ---------------
OTHER INCOME AND DEDUCTIONS:
Interest income.......................... 1,431 (398) 1,033
Other.................................... (2,732) (63) (2,795)
- ---------------------------------------------- --------------- ---------------- ---------------
Net other income and deductions........ (1,301) (461) (1,762)
- ---------------------------------------------- --------------- ---------------- ---------------
INTEREST CHARGES:
Interest on long-term debt............... 70,490 (9,093) 61,397
Allowance for borrowed funds used
during construction.................... (433) --- (433)
Other.................................... 9,518 (977) 8,541
- ---------------------------------------------- --------------- ---------------- ---------------
Total interest charges, net............ 79,575 (10,070) 69,505
- ---------------------------------------------- --------------- ---------------- ---------------
NET INCOME ................................... 114,277 (9,547) 104,730
PREFERRED DIVIDEND REQUIREMENTS............... 2,317 --- 2,317
--------------- ---------------- ---------------
EARNINGS AVAILABLE FOR COMMON................ $ 111,960 $ (9,547) $ 102,413
=============== ================ ===============
AVERAGE COMMON SHARES
OUTSTANDING............................... 40,328 --- 40,328
EARNINGS PER AVERAGE COMMON SHARE............. $ 2.78 $ (0.24) $ 2.54
STATEMENT OF RETAINED EARNINGS
OG&E PRO FORMA PRO FORMA
(AS REPORTED) ADJUSTMENTS OG&E
--------------- ---------------- ----------------
BALANCE AT BEGINNING OF PERIOD................ $ 391,135 $ (87,089) $ 304,046
ADD-net income................................ 114,277 (9,547) 104,730
--------------- ---------------- ----------------
Total..................................... 505,412 (96,636) 408,776
DEDUCT:
Cash dividends declared on preferred stock.. 2,317 --- 2,317
Cash dividends declared on common stock..... 107,284 6,641 113,925
--------------- ---------------- ----------------
Total..................................... 109,601 6,641 116,242
--------------- ---------------- ----------------
BALANCE AT END OF PERIOD...................... $ 395,811 $ (103,277) $ 292,534
=============== ================ ================
SEE ACCOMPANYING NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS.
67
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS
1. Subsidiary assets, liabilities, equity and results of operations have been
eliminated from consolidated Oklahoma Gas and Electric Company amounts to
reflect the transfer of ownership and control of all consolidated
subsidiaries from Oklahoma Gas and Electric Company to OGE Energy Corp.
2. After the transaction, Oklahoma Gas and Electric Company will not retain
ownership of the subsidiary currently being consolidated. Consequently,
intercompany transactions between Oklahoma Gas and Electric Company and its
current consolidated subsidiary have not been eliminated in the pro forma
financial statements.
The most significant intercompany transactions are transmission fees and
related charges to Oklahoma Gas and Electric Company from Enogex, its
subsidiary whose core business has been to deliver natural gas to Oklahoma
Gas and Electric Company power plants. The amount of these charges were
$44.3 million for the year ended December 31, 1995; $44.8 million for the
year ended December 31, 1994; and $54.9 million for the year ended December
31, 1993.
68
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
- --------------------------------------------------------------------
AND FINANCIAL DISCLOSURE.
-------------------------
Not Applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION.
- --------------------------------
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
- -------------------------------------------------
OWNERS AND MANAGEMENT.
----------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
- --------------------------------------------------------
Items 10, 11, 12 and 13 are omitted pursuant to General Instruction G of
Form 10-K, since OG&E filed copies of a definitive proxy statement with the
Securities and Exchange Commission on or about March 27, 1996. Such proxy
statement is incorporated herein by reference. In accordance with Instruction G
of Form 10-K, the information required by Item 10 relating to Executive Officers
has been included in Part I, Item 4, of this Form 10-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
- ----------------------------------------------------
REPORTS ON FORM 8-K.
--------------------
(A) 1. FINANCIAL STATEMENTS
- ---------------------------
The following consolidated financial statements and supplementary data are
included in Part II, Item 8 of this Report:
o Consolidated Balance Sheets at December 31, 1995, 1994 and 1993
o Consolidated Statements of Income for the years ended December 31, 1995,
1994 and 1993
o Consolidated Statements of Retained Earnings for the years ended December
31, 1995, 1994 and 1993
o Consolidated Statements of Capitalization at December 31, 1995, 1994 and
1993
o Consolidated Statements of Cash Flows for the years ended December 31,
1995, 1994 and 1993
o Notes to Consolidated Financial Statements
o Report of Independent Public Accountants
o Report of Management
69
SUPPLEMENTARY DATA
------------------
o Interim Consolidated Financial Information
o Unaudited Pro Forma Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE
- ----------------------------------------------------- ----
Schedule II - Valuation and Qualifying Accounts 78
Report of Independent Public Accountants 79
Financial Data Schedule 84
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. Three 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. Three 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)
70
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)
71
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)
72
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)
73
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)
4.30 Copy of Supplemental Trust Indenture dated October 1, 1995,
being a supplemental instrument to Exhibit 4.01 hereto. (Filed
as Exhibit 4.02 to the Company's Form 8-K Report dated October
23, 1995, File No. 1-1097, and incorporated by reference
herein)
4.31 Copy of Supplemental Trust Indenture dated
October 1, 1995, from OG&E to
Boatmen's First National Bank of Oklahoma, Trustee.
(Filed as Exhibit 4.29 to Registration Statement No. 33-61821
and incorporated by reference herein)
4.32 Copy of Supplemental Trust Indenture No. 1 dated
October 16, 1995, being a supplemental instrument
to Exhibit 4.31 hereto. (Filed as Exhibit 4.01 to
the Company's Form 8-K Report dated October 23, 1995,
File No. 1-1097, and incorporated by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company. (Filed as Exhibit 5.19 to
Registration Statement No. 2-59887 and incorporated by
reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between OG&E
and Atlantic Richfield Company, together with
related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply
Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company.
(Filed as Exhibit 5.28 to Registration Statement
No. 2-62208 and incorporated by reference herein)
74
10.04 Amendment dated June 27, 1990, between OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement dated March 1,
1973, between OG&E and Atlantic Richfield Company. (Filed as
Exhibit 10.04 to the Company's Form 10-K Report for the year
ended December 31, 1994, File No. 1-1097, and incorporated by
reference herein) [Confidential Treatment has been requested
for certain portions of this exhibit.]
10.05 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)
10.08 Form of Amended and Restated Stock Equivalent and
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, 1994,
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)
75
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.
(Filed as Exhibit 10.12 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
10.13 Company's Restoration of Retirement Savings Plan.
(Filed as Exhibit 10.13 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
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.
(Filed as Exhibit 10.1 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
10.16 Company's Annual Incentive Compensation Plan.
(Filed as Exhibit 10.16 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097, and incorporated by reference herein)
21.01 Subsidiaries of the Registrant.
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.02 Description of Common Stock. (Filed as Exhibit 99.02
to the Company's Form 10-K Report for the year
ended December 31, 1994, File No. 1-1097, and
incorporated by reference herein)
76
Executive Compensation Plans and Arrangements
---------------------------------------------
10.08 Form of Amended and Restated Stock Equivalent and
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, 1994, 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.
(Filed as Exhibit 10.12 to the Company's Form 10-K Report
for the year ended December 31, 1993, File No. 1-1097
and incorporated by reference herein)
10.13 Company's Restoration of Retirement Savings Plan.
(Filed as Exhibit 10.13 to the Company's Form 10-K Report
for the year ended December 31, 1993, File No. 1-1097
and incorporated by reference herein)
10.15 Company's Supplemental Executive Retirement Plan.
(Filed as Exhibit 10.15 to the Company's Form 10-K Report
for the year ended December 31, 1993, File No. 1-1097
and incorporated by reference herein)
10.16 Company's Annual Incentive Compensation Plan.
(Filed as Exhibit 10.16 to the Company's Form 10-K Report for
the year ended December 31, 1993, File No. 1-1097 and
incorporated by reference herein)
(B) REPORTS ON FORM 8-K
- ------------------------
Item 5. Other Events, dated July 26, 1995.
Item 7. Financial Statements and Exhibits, dated August 3, 1995.
Item 5. Other Events, dated October 23, 1995.
Item 7. Financial Statements and Exhibits, dated October 23, 1995.
Item 5. Other Events, dated October 25, 1995.
77
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
BALANCE CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS YEAR
----------- ------------ ----------------------------- ------------ -----------
1995 (THOUSANDS)
Reserve for Uncollectible Accounts $3,719 $7,588 - $7,102 $4,205
1994
Reserve for Uncollectible Accounts $4,070 $6,767 - $7,118 $3,719
1993
Reserve for Uncollectible Accounts $4,039 $6,669 - $6,638 $4,070
78
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 January 24,
1996. Our audits were made for the purpose of forming an opinion on those
statements taken as a whole. The schedule listed on Page 70, Item 14 (a) 2. is
the responsibility of the Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 24, 1996
79
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, the Registrant has duly caused this Report to be signed on its behalf
by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and
State of Oklahoma on the 22nd day of March, 1996.
OKLAHOMA GAS AND ELECTRIC COMPANY
(REGISTRANT)
/s/ J. G. Harlow, Jr.
By J. G. Harlow, Jr.
Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this Report has been signed below by the following persons in the
capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ J. G. Harlow, Jr.
J. G. Harlow, Jr. Principal Executive
Officer and Director; March 22, 1996
/s/ A. M. Strecker
A. M. Strecker Principal Financial
Officer; and March 22, 1996
/s/ D. L. Young
D. L. Young Principal Accounting
Officer. March 22, 1996
Herbert H. Champlin Director;
William E. Durrett Director;
Martha W. Griffin Director;
Hugh L. Hembree, III Director;
Steven E. Moore Director;
Bill Swisher Director; and
Ronald H. White, M.D. Director.
/s/ J. G. Harlow, Jr.
By J. G. Harlow, Jr. (attorney-in-fact) March 22, 1996
80
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
3.01 Copy of Restated Certificate of Incorporation.
(Filed as Exhibit 4.01 to the Company's Post-
Effective Amendment No. Three 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. Three 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)
4.28 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)
4.30 Copy of Supplemental Trust Indenture dated October 1, 1995,
being a supplemental instrument to Exhibit 4.01 hereto. (Filed
as Exhibit 4.02 to the Company's Form 8-K Report dated October
23, 1995, File No. 1-1097, and incorporated by reference
herein)
4.31 Copy of Supplemental Trust Indenture dated
October 1, 1995, from OG&E to
Boatmen's First National Bank of Oklahoma, Trustee.
(Filed as Exhibit 4.29 to Registration Statement No. 33-61821
and incorporated by reference herein)
4.32 Copy of Supplemental Trust Indenture No. 1 dated
October 16, 1995, being a supplemental instrument
to Exhibit 4.31 hereto. (Filed as Exhibit 4.01 to
the Company's Form 8-K Report dated October 23, 1995,
File No. 1-1097, and incorporated by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company. (Filed as Exhibit 5.19 to
Registration Statement No. 2-59887 and incorporated by
reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between OG&E
and Atlantic Richfield Company, together with
related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply
Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company.
(Filed as Exhibit 5.28 to Registration Statement
No. 2-62208 and incorporated by reference herein)
10.04 Amendment dated June 27, 1990, between OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement dated March 1,
1973, between OG&E and Atlantic Richfield Company. (Filed as
Exhibit 10.04 to the Company's Form 10-K Report for the year
ended December 31, 1994, File No. 1-1097, and incorporated by
reference herein) [Confidential Treatment has been requested
for certain portions of this exhibit.]
10.05 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)
10.08 Form of Amended and Restated Stock Equivalent and
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, 1994,
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.
(Filed as Exhibit 10.12 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
10.13 Company's Restoration of Retirement Savings Plan.
(Filed as Exhibit 10.13 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
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.
(Filed as Exhibit 10.1 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
10.16 Company's Annual Incentive Compensation Plan.
(Filed as Exhibit 10.16 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097, and incorporated by reference herein)
21.01 Subsidiaries of the Registrant.
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.02 Description of Common Stock. (Filed as Exhibit 99.02
to the Company's Form 10-K Report for the year
ended December 31, 1994, File No. 1-1097, and
incorporated by reference herein)