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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, 1996 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 isregistered
----------------------------- ------------------------------
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. [ x ]
Based upon the closing price on the New York Stock Exchange on February 28,
1997, the aggregate market value of the voting stock held by nonaffiliates of
the Registrant was: 4% Cumulative Preferred Stock $5,801,263.
As of February 28, 1997, the number of outstanding shares of the
Registrant's common stock, par value $2.50 per share, was 40,373,991 all of
which were held by OGE Energy Corp.
The information statement for the 1997 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
Introduction............................................. 1
General.................................................. 2
Finance and Construction................................. 5
Regulation and Rates..................................... 6
Rate Structure, Load Growth and Related Matters.......... 10
Fuel Supply.............................................. 11
Environmental Matters............................................. 12
Item 2. Properties........................................................ 14
Item 3. Legal Proceedings. ............................................... 15
Item 4. Submission of Matters to a Vote of Security Holders............... 17
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters...................................... 21
Item 6. Selected Financial Data........................................... 22
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition....................... 23
Item 8. Financial Statements and Supplementary Data....................... 31
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure ................................ 57
PART III
Item 10. Directors and Executive Officers of the Registrant................ 57
Item 11. Executive Compensation............................................ 57
Item 12. Security Ownership of Certain Beneficial
Owners and Management.................................... 57
Item 13. Certain Relationships and Related Transactions.................... 57
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K...................................... 57
i
PART I
ITEM 1. BUSINESS.
- - -----------------
THE COMPANY
INTRODUCTION
Oklahoma Gas and Electric Company (the "Company") is a regulated public
utility engaged in the generation, transmission and distribution of electricity
to retail and wholesale customers. The Company is a subsidiary of OGE Energy
Corp. ("Energy Corp.") which is a public utility holding company incorporated in
the State of Oklahoma and located in Oklahoma City, Oklahoma. The Company's
executive offices are located at 101 N. Robinson, P.O. Box 321, Oklahoma City,
Oklahoma 73101-0321: telephone (405) 553-3000.
The Company and its former subsidiary, Enogex, Inc. and Enogex Inc.'s
subsidiaries (collectively, "Enogex") became subsidiaries of Energy Corp. on
December 31, 1996 pursuant to a mandatory share exchange whereby each share of
outstanding common stock of the Company was exchanged on a share-for-share basis
for common stock of Energy Corp. Immediately following this exchange, the
Company transferred its shares of Enogex stock to Energy Corp. and Enogex became
a direct subsidiary of Energy Corp. Energy Corp. now serves as the parent
company to the Company, Enogex and any other companies that may be formed within
the organization in the future. The new holding company structure is intended to
provide greater flexibility to take advantage of opportunities in an
increasingly competitive business environment and to clearly separate the
Company's electric utility business from the non-utility businesses of the other
Energy Corp. subsidiaries for regulatory, capital structure and other purposes.
The Company was incorporated in 1902 under the laws of the Oklahoma
Territory and is the largest electric utility in the State of Oklahoma. The
Company 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. At the end of 1996, the Company had 2,434 members.
On February 11, 1997, the Oklahoma Corporation Commission ("OCC") issued an
order that, among other things, effectively lowered the Company's rates to its
Oklahoma retail customers by $50 million annually (based on a test year ended
December 31, 1995). Of the $50 million rate reduction, approximately $45 million
became effective on March 5, 1997 and the remaining $5 million becomes effective
March 1, 1998. The Order also directed the Company to transition to competitive
bidding of its gas transportation requirements, currently met by Enogex, no
later than April 30, 2000.
On June 18, 1996, the Arkansas Public Service Commission ("APSC") staff and
the Company filed a Joint Stipulation recommending settlement of certain issues
resulting from the APSC review of the amounts that the Company pays Enogex and
recovers through its fuel clause for transporting natural gas to OG&E's
gas-fired generating stations. See "Regulation and Rates - Recent Regulatory
Matters" for a further discussion of the orders.
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 the Company on August 9, 1994, the
OCC issued an order on October 26, 1994, that permitted the Company to: (i)
establish a regulatory asset in connection with the costs associated with the
workforce reduction; (ii) amortize the December 31, 1994, balance of the
regulatory asset over 26 months; and (iii) reduce the Company's electric rates
during such period by approximately $15 million annually, effective January
1995. In 1996, 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 9 of Notes to Consolidated
Financial Statements for a further discussion of the OCC's orders in February
1997 and February and October 1994.
GENERAL
The Company furnishes retail electric service in 274 communities and their
contiguous rural and suburban areas. During 1996, five other communities and two
rural electric cooperatives in Oklahoma and western Arkansas, purchased
electricity from the Company 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, 1996, were derived from sales in Oklahoma and the remainder from
sales in Arkansas.
The Company's system control area peak demand as reported by the system
dispatcher for the year was approximately 5,150 megawatts, and occurred on July
2, 1996. The Company's native load was approximately 4,851 megawatts on July 2,
1996, resulting in a capacity margin of approximately 20.6 percent. As reflected
in the table below and in the operating statistics on page 4, total
kilowatt-hour sales increased 1.5 percent in 1996 as compared to an increase of
7.0 percent in 1995 and a 9.0 percent decrease in 1994. In 1996, kilowatt-hour
sales to the Company's customers ("system sales") increased slightly due to
continued customer growth and a return to more normal weather. Sales to other
utilities ("off-system sales") decreased in 1996. 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 1995 and 1994, factors which resulted
in variations in total kilowatt-hour sales included: (i) continued customer
growth and (ii) the decrease in off-system sales in 1994.
Variations in kilowatt-hour sales for the three years are reflected in the
following table:
SALES (Millions of Kwh)
Inc/ Inc/ Inc/
1996 (Dec) 1995 (Dec) 1994 (Dec)
- - -----------------------------------------------------------------------------
System Sales 21,541 3.4% 20,828 0.9% 20,642 2.2%
Off-System Sales 1,475 (20.4)% 1,852 232.6% 557 (82.1%)
------ ------ ------
Total Sales 23,016 1.5% 22,680 7.0% 21,199 (9.0%)
====== ====== ======
2
The Company 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. See Item 3 "Legal Proceedings" for a further discussion of this
matter. Oklahoma law forbids the granting of an exclusive franchise to a utility
for providing electricity.
Besides competition from other suppliers of electricity, the Company
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. In April 1996, the Federal Energy Regulatory
Commission ("FERC") issued two final rules, Orders 888 and 889, regarding
non-discriminatory open access transmission service. These orders may have a
significant impact on wholesale markets. 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 OCC is seeking to identify, describe
and create a process to implement a comprehensive and integrated restructuring
of the electric utility industry for the State of Oklahoma. The Oklahoma
legislature also is considering legislation to permit increased competition at
the retail level by July 2002. 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 these matters.
Electric and magnetic fields ("EMFs") surround all electric tools and
appliances, internal home wiring and external power lines such as those owned by
the Company. During the last several years considerable attention has focused on
possible health effects from EMFs. While some studies indicate a possible weak
correlation, other similar studies indicate no correlation between EMFs and
health effects. The nation's electric utilities, including the Company, have
participated with the Electric Power Research Institute ("EPRI") in the
sponsorship of more than $75 million in research to determine the possible
health effects of EMFs. In addition, the Edison Electric Institute ("EEI") is
helping fund $65 million for EMF studies over a five-year period, that began in
1994. One-half of this amount is expected to be funded by the federal
government, and two-thirds of the non-federal funding is expected to be provided
by the electric utility industry. Through its participation with the EPRI and
EEI, the Company will continue its support of the research with regard to the
possible health effects of EMFs. The Company 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
1996 1995 1994
---- ---- ----
ELECTRIC ENERGY:(Millions of Kwh)
Generation (exclusive of station use)... 21,253 20,639 18,325
Purchased............................... 3,564 3,578 4,387
----------- ----------- -----------
Total generated and purchased......... 24,817 24,217 22,712
Company use, free service and losses.... (1,801) (1,537) (1,513)
----------- ----------- -----------
Electric energy sold.................. 23,016 22,680 21,199
=========== =========== ===========
ELECTRIC ENERGY SOLD:
(Millions of Kwh)
Residential............................. 7,143 6,848 6,739
Commercial and industrial............... 11,161 10,963 10,886
Public street and highway lighting...... 67 66 66
Other sales to public authorities....... 2,096 2,087 2,018
Sales for resale........................ 2,549 2,716 1,490
----------- ----------- -----------
Total.................................. 23,016 22,680 21,199
=========== =========== ===========
OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential............................ $ 479,574 $ 471,313 $ 476,441
Commercial and industrial.............. 530,213 512,212 549,528
Public street and highway lighting..... 9,367 9,115 9,294
Other sales to public authorities...... 98,209 95,660 99,789
Sales for resale....................... 60,141 63,340 43,001
Provision for rate refund.............. (1,221) (2,437) (3,417)
Miscellaneous.......................... 24,054 19,084 22,262
----------- ----------- -----------
Total Electric Revenues............... $1,200,337 $1,168,287 $1,196,898
=========== =========== ===========
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential............................. 588,778 583,741 578,044
Commercial and industrial............... 84,032 82,577 81,175
Public street and highway lighting...... 249 249 249
Other sales to public authorities....... 10,688 10,340 10,198
Sales for resale........................ 41 43 39
----------- ----------- -----------
Total.................................. 683,788 676,950 669,705
=========== =========== ===========
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (Kwh)................ 12,178 11,786 11,724
Average annual revenue.................. $ 817.62 $ 811.10 $ 828.86
Average price per Kwh (cents)........... 6.71 6.88 7.07
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 1996 and 1995, which enabled the Company to internally
generate the required funds to satisfy construction expenditures during these
years.
Management expects that internally generated funds will be adequate over
the next three years to meet the Company's capital requirements. The primary
capital requirements for 1997 through 1999 are estimated as follows:
(dollars in millions) 1997 1998 1999
- - -------------------------------------------------------------------------------
Construction expenditures
including AFUDC ....................... $ 95.0 $ 94.0 $ 94.0
Maturities of long-term debt and
sinking fund requirement............... 15.0 25.0 12.5
- - -------------------------------------------------------------------------------
Total................................. $ 110.0 $ 119.0 $ 106.5
===============================================================================
The three-year estimate includes expenditures for construction of new
facilities to meet anticipated demand for service, to replace or expand existing
facilities and to some extent, for satisfying maturing debt and sinking fund
obligations. Approximately $400,000 of the Company's construction expenditures
budgeted for 1997 are to comply with environmental laws and regulations. The
Company'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."
The Company intends to meet its customers' increased electricity needs
during the foreseeable future by maintaining the reliability and increasing the
utilization of existing capacity. The Company's current resource strategy
includes the reactivation of existing plants and the addition of peaking
resources. The Company does not anticipate the need for another base-load plant
in the foreseeable future.
The Company'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 the Company'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, 1996, and assuming an annual interest rate of 7.74 percent, the
Company could issue more than $1 billion in principal amount of additional first
mortgage bonds under the earnings test contained in the Company's Trust
Indenture (assuming adequate property additions were available). Under the
earnings test contained in the Company's Restated Certificate of Incorporation
and assuming none of the foregoing first mortgage bonds are issued, more than $1
billion of additional preferred stock at an assumed annual dividend rate of 7.2
percent could be issued as of December 31, 1996.
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 1996 was $142.1 million.
5
The Company'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"), the Company is obligated to purchase 110 megawatts of capacity
annually from Smith Cogeneration, Inc. and 320 megawatts annually from Applied
Energy Services, Inc., another qualified cogeneration facility. 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, the Company 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 the Company 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.
The Company'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.
REGULATION AND RATES
The Company's retail electric tariffs in Oklahoma are regulated by the OCC,
and in Arkansas by the APSC. The issuance of certain securities by the Company
is also regulated by the OCC and the APSC. The Company's wholesale electric
tariffs, short-term borrowing authorization and accounting practices are subject
to the jurisdiction of the FERC. The Secretary of the Department of Energy has
jurisdiction over some of the Company's facilities and operations.
As part of the corporate reorganization whereby the Company became a
subsidiary of Energy Corp., the Company obtained the approval of the OCC. The
order of the OCC authorizing the Company to reorganize into a holding company
structure contains certain provisions which, among other things, ensure the OCC
access to the books and records of Energy Corp. and its affiliates relating to
transactions with the Company; require the Company to employ accounting and
other procedures and controls to protect against subsidization of non-utility
activities by the Company's customers; and prohibit the Company from pledging
its assets or income for affiliate transactions.
For the year ended December 31, 1996, approximately 88 percent of the
Company's electric revenue was subject to the jurisdiction of the OCC, seven
percent to the APSC, and five percent to the FERC.
RECENT REGULATORY MATTERS: On February 11, 1997, the OCC issued an order
---------------------------
that, among other things, effectively lowered the Company's rates to its
Oklahoma retail customers by $50 million annually (based on a test year ended
December 31, 1995). Of the $50 million rate reduction, approximately $45 million
became effective on March 5, 1997 and the remaining $5 million becomes effective
March 1, 1998. The Company had filed an application in June 1996 with the OCC
for an annual electric utility rate reduction of $14.2 million. On October 14,
1996, the staff of the OCC and the Oklahoma
6
Attorney General recommended that the Company lower its annual revenues by $94.5
and $79.8 million, respectively. In a separate recommendation, the Oklahoma
Industrial Energy Consumers proposed a $107.8 million annual Company rate
reduction. On December 18, 1996, the Company and the intervenors proposed a $50
million settlement. The OCC voted to approve the Company's proposed settlement
agreement on January 23, 1997, allowing the Company to lower its electric rates
by $50 million. The order approving the rate reduction also provides for an
incentive program designed to encourage future generation cost savings to be
shared by the Company and its customers. This program gives the Company the
opportunity to lessen the impact of the $50 million reduction, if future cost
savings are achieved. See Note 9 of Notes to Consolidated Financial Statements.
The February 11, 1997 order also directed the Company to transition to
competitive bidding of its gas transportation requirements currently met by
Enogex no later than April 30, 2000 and set annual compensation for the
transportation services provided by Enogex to the Company at $41.3 million until
competitively-bid gas transportation begins. In 1996, approximately $44 million
or 19 percent of Enogex's revenues were attributable to transporting gas for the
Company. Other pipelines seeking to compete with Enogex for the Company's
business will likely have to pay a fee to Enogex for transporting gas on
Enogex's system or incur capital expenditures to develop the necessary
infrastructure to connect with the Company's gas-fired generating stations.
On June 18, 1996, the APSC staff and the Company filed a Joint Stipulation
recommending settlement of certain issues resulting from the APSC review of the
amounts that the Company pays Enogex and recovers through its fuel clause for
transporting natural gas to the Company's gas-fired generating stations. On July
11, 1996, the APSC issued an order that, among other things, required the
Company to refund approximately $4.5 million in 1996 to its Arkansas retail
electric customers. The $4.5 million refund was recorded as a provision for a
potential refund prior to August 1996.
On February 25, 1994, the OCC issued an order that, among other things,
effectively lowered the Company's rates to its Oklahoma retail customers by
approximately $17 million annually and required the Company 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. The entire $41.3 million refund related to the OCC's
disallowance of a portion of the fees paid by the Company to Enogex for prior
transportation and related gas gathering services. Of the $17 million annual
rate reduction, approximately $9.9 million reflects the OCC's reduction of the
amount to be recovered by the Company from its Oklahoma customers for the future
performance of such services by Enogex for the Company. In accordance with the
OCC's rate order and a stipulation approved by the OCC in July 1991, the
Company's electric rates were designed to permit the Company to earn a 12
percent regulatory return on equity and the OCC staff was precluded from
initiating an investigation of the Company's rates for three years from February
25, 1994, unless the Company's regulatory return on equity exceeded 12.75
percent.
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, the Company deferred the
costs associated with the 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 the Company
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 the Company's electric rates during such period by
approximately $15 million annually, effective January 1995. Labor savings from
the VERP and severance package have substantially offset the amortization of the
regulatory asset and annual rate reduction of $15 million. Labor savings in
7
1994, 1995 and 1996 approximated the amortization of the deferred amount and
therefore, did not significantly impact 1994, 1995 and 1996 results. However,
approximately $6.5 million in other restructuring expenses reduced 1994 earnings
by $0.10 per share. At December 31, 1996, the deferred amount was $3.8 million,
which is included on the Balance Sheets as Deferred Charges - Other.
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 (the "Energy Act"), requiring the Company 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, the Company and other
electric utilities serving customers in Arkansas were required to submit a
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 cost-of-service for ratemaking, are charged to substantially
all of the Company's electric customers through automatic fuel adjustment
clauses, which are subject to periodic review by the OCC, the APSC and the FERC.
NATIONAL ENERGY LEGISLATION: The National Energy Act of 1978 imposes
-----------------------------
numerous responsibilities and requirements on the Company. The Public Utility
Regulatory Policies Act of 1978 requires electric utilities, such as the
Company, 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. The Company has entered into agreements with four such cogenerators.
See "Finance and Construction." Electric utilities also must furnish electric
energy to QFs on a non-discriminatory basis at a rate that is just and
reasonable and in the public interest and must provide certain types of service
which may be requested by QFs to supplement or back up those facilities' own
generation.
The Energy 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
8
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."
In April 1996, FERC issued two final rules, Orders 888 and 889, which may
have a significant impact on wholesale markets. These orders were subsequently
amended in orders issued in March 1997. Order 888, which was preceded by a
Notice of Proposed Rulemaking, referred to as the "Mega-NOPR," set forth rules
on non-discriminatory open access transmission service to promote wholesale
competition. Order 888, which was effective on July 9, 1996, requires utilities
and other transmission users to abide by comparable terms, conditions and
pricing in transmitting power. Order 889, which had its effective date extended
to January 3, 1997, requires public utilities to implement Standards of Conduct
and an Open Access Same Time Information System ("OASIS," formerly known as
"Real-Time Information Networks"). These rules require transmission personnel to
provide the same information about the transmission system to all transmission
customers using the OASIS. The Company is complying with these new rules from
the FERC.
Another impact of complying with FERC's Order 888 is a requirement for
utilities to offer a transmission tariff that includes network transmission
service ("NTS") to transmission customers. NTS allows transmission service
customers to fully integrate load and resources on an instantaneous basis, in a
manner similar to how the Company has historically integrated its load and
resources. Under NTS, the Company and participating customers share the total
annual transmission cost, net of related transmission revenues, based upon each
company's share of the total system load. At this time, the Company expects to
incur approximately $1 million in start-up costs beginning in 1997 and a minimal
annual expense increase, as a result of Orders 888 and 889.
In accordance with FERC's direction regarding competition and alternative
regulation of the electric energy utility market on the national scale, the OCC
is seeking to identify, describe and create a process to implement a
comprehensive and integrated restructuring of the electric utility industry for
the State of Oklahoma. On June 6, 1996, the OCC issued a Notice of Inquiry
proposing questions for comment. In response to the Notice of Inquiry, the
Company filed comments with the OCC on September 9, 1996. The comments listed,
among other things, five critical issues that the Company believes must be
addressed to ensure a successful transition to a deregulated environment. These
issues are: (i) retail wheeling should be implemented in Oklahoma at the same
time it is implemented and on the same terms in all surrounding states; (ii)
stranded costs must be recovered; (iii) a level playing field must be
established; (iv) state regulators role must be restructured; and (v) there must
be no exceptions to the new rules. In addition, the Oklahoma State Senate has
passed legislation that would permit increased competition at the retail level
by July 2002. This proposed legislation authorizes the OCC, under the direction
of a special task force comprised of members of the Oklahoma State Senate and
the Oklahoma State House of Representatives, to undertake a series of studies to
set the framework for electric utility industry competition. The proposed
legislation calls for the OCC to report to the task force the results of its
studies beginning in February 1998 with a report regarding independent system
operators. Following a transition period, the proposed legislation would require
the unbundling of generation, transmission and distribution services. Stranded
costs would be recoverable over a 3 to 7 year period. At this time, it is
uncertain whether or when such legislation will be approved by the House of
Representatives. The Company is not opposed to such legislation generally,
provided the five issues noted above are addressed fairly.
The Energy Act, these FERC actions, restructuring proposals in Oklahoma 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
9
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 advocate this position
vigorously.
RATE STRUCTURE, LOAD GROWTH
AND RELATED MATTERS
Two of the Company'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, the Company has reduced and
restructured its rates to its key customers while at the same time implementing
numerous energy efficiency programs and tariff schedules. In 1996, these
programs and schedules included: (i) assistance programs that help residential
customers live in comfortable homes with lower energy costs; (ii) the "Surprise
Free Guarantee" program, which guarantees residential customers comfort and
annual energy consumption for heating, cooling and water heating; (iii) 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; (iv) a load curtailment rate for industrial and
commercial customers who can demonstrate a load curtailment of at least 300
kilowatts; and (v) time-of-use rate schedules for various commercial, industrial
and residential customers designed to shift energy usage from peak demand
periods during the hot summer afternoons to non-peak hours. The February 11,
1997 order issued by the OCC, among other things, eliminated the PEAKS program
and raised the minimum load curtailment per customer from 300 to 500 kilowatts.
The Company implemented a Real Time Pricing pilot program, for selected
industrial customers, 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 control their costs.
The Company's 1996 marketing efforts included geothermal heat pumps,
electrotechnologies, an electric food service promotion and a heat pump
promotion in the residential, commercial and industrial markets. The Company
works closely with individual customers to provide the best information on how
current technologies can be combined with the Company's marketing programs to
maximize the customer's benefit.
The Company currently does not anticipate the need for new base-load
generating plants in the foreseeable future. For further discussion, see
"Finance and Construction."
10
FUEL SUPPLY
During 1996, approximately 79 percent of the Company-generated energy was
produced by coal-fired units and 21 percent by natural gas-fired units. It is
estimated that the fuel mix for 1997 through 2001, based upon expected
generation for these years, will be as follows:
1997 1998 1999 2000 2001
- - -------------------------------------------------------------------------------
Coal......... 82% 80% 80% 79% 79%
Natural Gas.. 18% 20% 20% 21% 21%
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:
1996 1995 1994 1993 1992
- - -------------------------------------------------------------------------------
Coal......... $0.83 $0.83 $0.78 $1.16 $1.18
Natural Gas.. $3.61 $3.19 $3.58 $3.64 $3.48
Weighted Avg. $1.45 $1.41 $1.58 $1.92 $1.88
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."
COAL-FIRED UNITS: All Company coal units, with an aggregate capacity of 2,530
- - -----------------
megawatts, are designed to burn low sulfur western coal. The Company purchases
coal under a mix of long- and short-term contracts. During 1996, the Company
purchased 9.9 million tons of coal from the following Wyoming suppliers: Amax
Coal West, Inc., Caballo Rojo, Inc., Kennecott Energy Company, Thunder Basin
Coal Company and Powder River Coal Company. The combination of all coals has a
weighted average sulfur content of 0.31 percent and can be burned in these units
under existing federal, state and local environmental standards (maximum of 1.2
pounds of sulfur dioxide per million Btu) without the addition of sulfur dioxide
removal systems. Based upon the average sulfur content, the Company units have
an approximate emission rate of 0.63 pounds of sulfur dioxide per million Btu.
In anticipation of the more strict provisions of Phase II of The Clean Air Act
starting in the year 2000, the Company has contracts in place that will allow
for a supply of very low sulfur coal from suppliers in the Powder River Basin to
meet the new sulfur dioxide standards.
Wyoming coal is transported to the Company generating stations, a distance
of approximately 1,000 miles, by either 112 or 135 rail car unit trains. In
1995, the Company 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 20 percent increase in net loading per car over a
conventional steel car. During 1996, the Company used larger unit trains with a
maximum of 135 cars instead of a maximum of 112 cars in unit train service to
the Muskogee generating station. Increasing the unit train size allows for an
increase of delivered tons by approximately 21 percent. The combination of high
volume, aluminum design and increased train size to the Muskogee generating
11
station reduces the number of trips from Wyoming by approximately 29 percent and
reduces rail car maintenance expenses accordingly.
GAS-FIRED UNITS: For calendar year 1997, the Company expects to acquire
- - ----------------
approximately 10 percent of its gas needs from long-term gas purchase contracts.
The remainder of the Company's gas needs during 1997 will be supplied by
contracts with at-market pricing or through day-to-day purchases on the spot
market.
In 1993, the Company began utilizing a natural gas storage facility which
helps lower fuel costs by allowing the Company 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, the Company is
able to use as much coal as possible to generate electricity and utilize the
stored gas to meet the additional demand for electricity. During 1996, the
Company completed a controls upgrade to its Seminole Unit 1. This upgrade will
allow the unit to run efficiently at low loads as well as high loads. This added
flexibility in gas generation compliments the Company's contracted gas storage
facility to allow the gas generating system to meet our customers' changing
electrical needs in a reliable and efficient manner.
ENVIRONMENTAL MATTERS
The Company's management believes all of its operations are in substantial
compliance with present federal, state and local environmental standards. It is
estimated that the Company's total expenditures for capital, operating,
maintenance and other costs to preserve and enhance environmental quality will
be approximately $40 million during 1997, compared to approximately $43 million
utilized in 1996. Approximately $400,000 of the Company's construction
expenditures budgeted for 1997 are to comply with environmental laws and
regulations. The Company continues to evaluate its environmental management
systems to ensure compliance with existing and proposed environmental
legislation and regulations and to better position itself in a competitive
market.
As required by Title IV of the Clean Air Act Amendments of 1990 ("CAAA"),
the Company has completed installation and certification of all required
continuous emissions monitors ("CEMs") at its generating stations. The Company
submits emissions data quarterly to the Environmental Protection Agency ("EPA")
as required by the CAAA. Phase II sulfur dioxide ("SO2") emission requirements
will affect the Company beginning in the year 2000. Based on current information
the Company believes it can meet the SO2 limits without additional capital
expenditures. In 1996 the Company emitted 58,700 tons of SO2.
With respect to the nitrogen oxide ("NOx") regulations of Title IV of the
CAA, the Company has committed to meeting a 0.45 lbs/mm Btu NOx emission level
beginning in 1997. As a result, the Company was eligible to exercise its option
to extend the effective date of the lower emission requirements from the year
2000 until 2008. The Company's average NOx emissions for 1996 was 0.38 lbs/mm
Btu.
The Company has submitted all of its required Title V permit applications.
The first two were submitted on July 10, 1996 while the remaining six were
submitted on March 5, 1997. As a result of the Title V Program the Company paid
approximately $340,000 in fees in 1996.
12
Other air regulated items have emerged that could impact the Company. The
Ozone Transport Assessment Group ("OTAG") is studying long range transport of
ozone and its precursors across a thirty-seven state area. The results of the
study are due by mid 1997. If reductions are required in Oklahoma, the Company
could have to reduce its NOx emissions even further from the limits imposed by
Title IV of the Act.
EPA has proposed revisions to the ambient ozone and particulate standards.
Based on historic data and EPA projections, Tulsa and Oklahoma counties would
fail to meet the proposed standard for ozone. In addition, Muskogee, Kay, Tulsa
and Comanche counties would fail to meet the standard for particulate matter. If
reductions were required in Muskogee, Kay and Oklahoma counties, significant
capital expenditures could be required by the Company.
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 1996, the Company obtained refunds of approximately
$232,600 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.
The Company has made application for renewal of all of its National
Pollutant Discharge Elimination System ("NPDES") permits. The Company received
one of the permits in final form and the remainder of the applications are in
technical review by the regulatory agency. It is anticipated, because of
regulation changes, that the new permits will offer greater operational
flexibility than those in the past. In 1996 responsibility for administration of
the NPDES program was shifted from the U. S. EPA to certain states including
Oklahoma. As a result of the assumption of this program by the Oklahoma
Department of Environmental Quality, annual state wastewater fees are expected
to increase. Annual NPDES fees for 1996 were approximately $34,400 and at this
time, it is anticipated that the cost of these fees will be similar for 1997.
The Company remains a party to two separate actions brought by the EPA
concerning cleanup of disposal sites for hazardous and toxic waste, See "Item 3.
Legal Proceedings."
The Company has and will continue to evaluate the impact of its operations
on the environment. As a result, contamination on Company property will be
discovered from time to time. Three separate sites, which were identified as
having been contaminated by historical operations were addressed during 1996.
The Company completed remediation of two of these while remedial options for the
third are being pursued with appropriate regulatory agencies. The cost of these
actions has not had and are not anticipated to have a material adverse impact on
the Company's financial position or results of operations.
13
ITEM 2. PROPERTIES.
- - ------------------
The Company 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, all of which are located in
Oklahoma:
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
========
14
At December 31, 1996, OG&E's transmission system included: (i) 65
substations with a total capacity of approximately 15.6 million kVA and
approximately 3,989 structure miles of lines in Oklahoma; and (ii) six
substations with a total capacity of approximately 1.9 million kVA and
approximately 241 structure miles of lines in Arkansas. OG&E's distribution
system included: (i) 301 substations with a total capacity of approximately 5.6
million kVA, 19,794 structure miles of overhead lines, 1,562 miles of
underground conduit and 6,386 miles of underground conductors in Oklahoma; and
(ii) 30 substations with a total capacity of approximately 665,000 kVA, 1,617
structure miles of overhead lines, 148 miles of underground conduit and 344
miles of underground conductors in Arkansas.
Substantially all of the Company's electric facilities are subject to a
direct first mortgage lien under the Trust Indenture securing the Company's
first mortgage bonds.
During the three years ended December 31, 1996, the Company's gross
property, plant and equipment additions approximated $308 million and gross
retirements approximated $76 million. Over 95 percent of these additions were
provided by internally generated funds. The additions during this three-year
period amounted to approximately 8.6 percent of total property, plant and
equipment at December 31, 1996.
ITEM 3. LEGAL PROCEEDINGS.
- - -------------------------
1. On July 8, 1994, an employee of the Company filed a lawsuit in state
court against the Company in connection with the Company's VERP. The case was
removed to the U.S. District Court in Tulsa, Oklahoma. On August 23, 1994, the
trial court granted the Company'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 results of operations or financial condition.
2. The Company is also involved, along with numerous other Potentially
Responsible Party's ("PRP"), in an EPA administrative action involving the
facility in Holden, Missouri, of Martha C. Rose Chemicals, Inc. ("Rose").
Beginning in early 1983 through 1986, Rose was engaged in the business of
brokering of polychlorinated biphenyls ("PCBs") and PCB items, processing of PCB
capacitors and transformers for disposal, and decontamination of mineral oil
dielectric fluids containing PCBs. During this time period, various generators
of PCBs ("Generators"), including the Company, shipped materials
15
containing PCBs to the facility. Contrary to its contractual obligation with the
Company and other Generators, it appears that Rose failed to manage, handle and
dispose of the PCBs and the PCB items in accordance with the applicable law.
Rose has been issued citations by both the EPA and the Occupational Safety and
Health Administration. Several Generators, including OG&E, formed a Steering
Committee to investigate and clean up the Rose facility.
The Company's share of the total hazardous wastes at the Rose facility was
less than six percent. The remediation of this site was completed in 1995 by the
Steering Committee and is currently in the final stages of closure with the EPA,
which includes operation and maintenance activities as required in the
Administrative Order on Consent with the EPA. Due to additional funds resulting
from payments by third party companies who were not a part of the Steering
Committee, and also reduced remedy implementation costs, the Company received a
refund in December 1995 under the allocation formula. The Company has reached a
settlement agreement with its insurance carrier, AEGIS Insurance Company, with
respect to costs incurred at this site. The Company considers this insurance
matter to be closed.
Management believes that the Company's ultimate liability for any
additional cleanup costs of this site will not have a material adverse effect on
the Company's financial position or its results of operations. Management's
opinion is based on the following: (i) the present status of the site; (ii) the
cleanup costs already paid by certain parties; (iii) the financial viability of
the other PRPs; (iv) the portion of the total waste disposed at this site
attributable to the Company; and (v) the Company's settlement agreement with its
insurer. Management also believes that costs incurred in connection with this
site, which are not recovered from insurance carriers or other parties, may be
allowable costs for future ratemaking purposes.
3. On January 11, 1993, the Company 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 the Company and 45
others as PRPs. Each PRP could be held jointly and severally liable for
remediation of this site.
On February 15, 1996, the Company elected to participate in the de minimis
settlement of EPA's Administrative Order on Consent. This limits the Company's
financial obligation to less than $50,000 and also eliminates its involvement in
the design and implementation of the site remedy.
4. As previously reported, on September 18, 1996, Trigen - Oklahoma City
Energy Corporation ("Trigen") sued OG&E in the United States District Court,
Western District of Oklahoma, Case No. CIV-96-1595-M. Trigen alleged six causes
of action: (i) monopolization in violation of Section 2 of the Sherman Act; (ii)
attempt to monopolize in violation of Section 2 of the Sherman Act; (iii) acts
in restraint of trade in violation of Oklahoma law, 79 O.S. 1991, ss. 1; (iv)
discriminatory sales in violation of 79 O.S. 1991, ss. 4; (v) tortious
interference with contract; and (vi) tortious interference with a prospective
economic advantage. Trigen seeks actual damages of at least $7 million, trebled,
together with its costs, pre- and post-judgment interest and attorney fees, in
connection with each of the first four counts. It seeks actual damages of at
least $7 million, plus punitive damages together with its costs, pre-and
post-judgment interest and attorney fees, in connection with each of the
remaining counts. Trigen also seeks permanent injunctive relief against the
alleged Sherman Act violations and against the Company's alleged practice of
offering cooling services to customers in Oklahoma City in the form of
RTP-priced electricity "bundled" together with financing, construction, and/or
other consulting services at guaranteed rates.
16
The Company filed an answer and counterclaim on November 7, 1996 asserting
that Trigen made false claims, misrepresented facts, published false statements
and other defamatory conduct which damaged the Company, and asserting violation
of the Oklahoma Deceptive Trade Practices Act. The Company seeks punitive and
actual damages. Due to the early stages of this lawsuit, the Company cannot
predict its outcome at this time.
5. The State of Oklahoma, ex rel., Teresa Harvey (Carroll); Margaret B.
Fent and Jerry R. Fent v. Oklahoma Gas and Electric Company, et al., District
Court, Oklahoma County, Case No. CJ-97-1242-63. On February 24, 1997, the
taxpayers instituted litigation against the Company and Co-Defendants Oklahoma
Corporation Commission, Oklahoma Tax Commission and individual commissioners
seeking judgment in the amount of $970,184.14 and treble penalties of
$2,910,552.42, plus interest and costs, for overcharges refunded by the Company
to its ratepayers in compliance with an Order of the OCC which Plantiffs allege
was illegal. Plantiffs allege the refunds should have been paid into the state
Unclaimed Property Fund. Management believes that the lawsuit is without merit
and will not have a material adverse effect on the Company's financial position
or its results of operations.
6. On March 19, 1997, the City of Enid, Oklahoma ("Enid") through its
City Council, notified the Company of its intent to purchase the Company's
electric distribution facilities for Enid and to terminate the Company's
franchise to provide electricity within Enid as of June 26, 1998. The ability of
Enid to purchase the Company's distribution facilities in Enid is subject to
numerous additional conditions. The Company currently provides electricity to
approximately 25,000 customers in Enid and for the year ended December 31, 1996,
derived less than 3.5 percent of its electric retail revenues from sales of
electricity to such customers. In the event Enid is ultimately successful in its
current efforts, it is expected that the Company would compete with other
companies at the wholesale level to supply electricity to Enid. The Company is
currently evaluating the legality of the City Council's actions and determining
the appropriate actions to take.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
- - ------------------------------------------------------------
None
17
EXECUTIVE OFFICERS OF THE REGISTRANT.
- - ------------------------------------
The following persons were Executive Officers of the Registrant as of March
15, 1997:
Name Age Title
- - -------------------- --- -------------------------------
Steven E. Moore 50 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 53 Senior Vice President - Finance
and Administration
Melvin D. Bowen, Jr. 55 Vice President - Power Delivery
Jack T. Coffman 53 Vice President - Power Supply
Michael G. Davis 47 Vice President - Marketing and
Customer Services
Irma B. Elliott 58 Vice President and
Corporate Secretary
James R. Hatfield 39 Vice President and Treasurer
Donald R. Rowlett 39 Controller Corporate Accounting
Don L. Young 56 Controller Corporate Audits
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
15, 1997.
18
The business experience of each of the Executive Officers of the Registrant
for the past five years is as follows:
Name Business Experience
- - -------------------- -------------------------------------------
Steven E. Moore 1996-Present: Chairman of the Board,
President and Chief
Executive Officer -
Energy Corp.
1996-Present: Chairman of the Board,
President and Chief
Executive Officer
1995-1996: President and Chief
Operating Officer
1992-1995: Vice President - Law
and Public Affairs
Al M. Strecker 1996-Present: Senior Vice President -
Energy Corp.
1994-Present: Senior Vice President -
Finance and
Administration
1992-1994: Vice President and
Treasurer
Melvin D. Bowen, Jr. 1994-Present: Vice President -
Power Delivery
1992-1994: Metro Region
Superintendent
Jack T. Coffman 1994-Present: Vice President -
Power Supply
1992-1994: Manager - Generation
Services
19
Name Business Experience
- - -------------------- -------------------------------------------
Michael G. Davis 1996-Present: Vice President - Energy
Corp.
1994-Present: Vice President -
Marketing and
Customer Services
1992-1994: Director - Marketing
Division
1992: Manager - Industrial
Services
Irma B. Elliott 1996-Present: Vice President and
Corporate Secretary -
Energy Corp.
1996-Present: Vice President and
Corporate Secretary
1992-1996: Secretary
James R. Hatfield Present: Vice President and
Treasurer - Energy
Corp.
Present: Vice President and
Treasurer
1994-1997: Treasurer
1994: Vice President - Investor
Relations & Corporate
Secretary - Aquila Gas
Pipeline Corporation
(an intrastate gas
pipeline subsidiary of
UtiliCorp United Inc.)
1992-1993: Assistant Treasurer -
UtiliCorp United Inc.
(an electric and
natural gas utility
company)
Donald R. Rowlett 1996-Present: Controller Corporate
Accounting
1994-1996: Assistant Controller
1992-1994: Senior Specialist -
Tax Accounting
1992: Specialist - Tax Accounting
Don L. Young 1996-Present: Controller Corporate Audits
1992-1996: Controller
20
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
- - ---------------------------------------------------------
STOCKHOLDER MATTERS.
- - --------------------
Currently, all Company common stock, 40,373,991 shares, is held by Energy
Corp. Therefore, there is no public trading market for the Company's common
stock. 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 Company's common stock prior to the
corporate reorganization.
1996 1995
-------------------------------------------------------------
Dividend Dividend
Paid High Low Paid High Low
-------------------------------------------------------------
First Quarter $0.66 1/2 $43 5/8 $38 7/8 $0.66 1/2 $36 1/4 $32 9/16
Second Quarter 0.66 1/2 40 1/8 36 7/8 0.66 1/2 36 3/8 33 1/4
Third Quarter 0.66 1/2 41 7/8 38 1/8 0.66 1/2 38 33 3/8
Fourth Quarter 0.66 1/2 41 7/8 38 1/8 0.66 1/2 43 5/8 36 7/8
21
ITEM 6. SELECTED FINANCIAL DATA.
- - ---------------------------------
HISTORICAL DATA
As Restated - See Note I
to Consolidated Financial Statements
----------------------------------------------------
1996 1995 1994 1993 1992
------------------------------------------------------------------
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS EXCEPT
FOR PER SHARE DATA)
Operating revenues.................. $1,200,337 $1,168,287 $1,196,898 $1,282,817 $1,193,993
Operating expenses.................. 1,022,988 987,270 1,016,074 1,106,820 1,036,424
----------- ----------- ----------- ----------- -----------
Operating income.................... 177,349 181,017 180,824 175,997 157,569
Other income and deductions......... (914) 2,272 321 (873) (1,656)
Interest charges.................... 59,566 70,745 67,350 70,394 67,620
----------- ----------- ----------- ----------- -----------
Income from continuing operations... 116,869 112,544 113,795 104,730 88,293
Income from operations of Enogex
distributed to OGE Energy Corp..... 16,463 12,712 9,990 9,547 11,419
----------- ----------- ----------- ----------- -----------
Net income.......................... 133,332 125,256 123,785 114,277 99,712
Preferred dividend requirements..... 2,302 2,316 2,317 2,317 2,317
----------- ----------- ----------- ----------- -----------
Earnings available for common....... $ 131,030 $ 122,940 $ 121,468 $ 111,960 $ 97,395
=========== =========== =========== =========== ===========
Long-term debt...................... $ 709,281 $ 723,862 $ 723,667 $ 748,660 $ 748,654
Long-term debt of Enogex............ --- 120,000 6,900 90,000 90,000
Total assets........................ $2,421,241 $2,754,871 $2,782,629 $2,731,424 $2,590,083
Income from continuing operations... $ 2.84 $ 2.73 $ 2.76 $ 2.54 $ 2.13
Income from Enogex operations....... .41 .32 .25 .24 .29
----------- ----------- ----------- ----------- -----------
Earnings per average common share... $ 3.25 $ 3.05 $ 3.01 $ 2.78 $ 2.42
CAPITALIZATION RATIOS *
Common equity....................... 52.57% 54.78% 54.35% 53.17% 53.03%
Cumulative preferred stock.......... 3.09% 2.92% 2.95% 2.93% 2.94%
Long-term debt...................... 44.34% 42.30% 42.70% 43.90% 44.03%
INTEREST COVERAGES *
Before federal income taxes
(including AFUDC).................. 4.09X 3.49X 3.66X 3.36X 2.99X
(excluding AFUDC).................. 4.08X 3.47X 3.64X 3.35X 2.98X
After federal income taxes
(including AFUDC).................. 2.94X 2.56X 2.66X 2.48X 2.29X
(excluding AFUDC).................. 2.93X 2.55X 2.65X 2.47X 2.28X
* These amounts do not include Enogex.
22
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) 1996 1995 1994 1996 1995
- - -------------------------------------------------------------------------------------------------
Operating revenues...................... $1,200,337 $1,168,287 $1,196,898 2.7 (2.4)
Earnings available for common stock..... $ 114,567 $ 110,228 $ 111,478 3.9 (1.1)
Average shares outstanding.............. 40,367 40,356 40,344 --- ---
Earnings per average common share from
continuing operations.................. $ 2.84 $ 2.73 $ 2.76 4.0 (1.1)
Dividends paid per share................ $ 2.66 $ 2.66 $ 2.66 --- ---
=================================================================================================
Oklahoma Gas and Electric Company (the "Company") is an operating public
utility engaged in the generation, transmission, distribution, and sale of
electric energy. OGE Energy Corp. ("Energy Corp.") became the parent company of
the Company and its former subsidiary, Enogex Inc. ("Enogex") on December 31,
1996 in a corporate reorganization whereby all common stock of the Company was
exchanged on a share-for-share basis for common stock of Energy Corp. Under this
corporate structure, the new holding company serves as the parent company to the
Company, Enogex and any other companies that may be formed within the
organization in the future. Also, effective December 31, 1996, the Company
distributed its ownership of Enogex to Energy Corp. Although Enogex continues to
operate as a subsidiary of Energy Corp., for purposes of these consolidated
financial statements, Enogex has been accounted for as discontinued operations
and prior year consolidated financial statements have been restated to reflect
that accounting. This new holding company structure is intended to provide
greater flexibility to take advantage of opportunities in an increasingly
competitive business environment and to clearly separate the Company's electric
utility business from Energy Corp.'s non-utility businesses.
Earnings from continuing operations for 1996 increased 4.0 percent from
$2.73 per share in 1995 to $2.84 per share in 1996. The increase is primarily
the result of continued customer growth in the Company's service area and lower
interest costs. The 1995 decrease resulted primarily from mild weather in the
service area. The 1995 decrease was partially offset by continued customer
growth in the Company's service area and improved operating efficiencies
resulting from the 1994 restructuring of the Company's operations.
On February 11, 1997, the Oklahoma Corporation Commission ("OCC") issued an
order approving the Company's proposed settlement agreement, which reduced the
Company's electric rates on an annual basis by approximately $50 million with
approximately $45 million effective March 5, 1997, and the remaining $5 million
effective March 1, 1998. The Company had filed an application in June 1996 with
the OCC for an annual electric utility rate reduction of $14.2 million. Various
parties proposed significantly higher reductions than the $14.2 million proposed
by the Company and the $50 million approved by the OCC. The approved rate
reduction provides an incentive program designed to encourage future generation
cost savings to be shared by OG&E and its customers. This program also gives the
23
Company the opportunity to lessen the impact of the $50 million reduction, if
future cost savings are achieved. See Note 9 of Notes to Consolidated Financial
Statements.
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, the Company 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 during such period by
approximately $15 million annually. At December 31, 1996, the unamortized
regulatory asset was $3.8 million, which is included on the Consolidated Balance
Sheets as Deferred Charges - Other. In 1996, 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
1996 operating results. The unamortized regulatory asset will be fully amortized
in February 1997, allowing the labor savings associated with the 1994 workforce
reductions to lessen the impact of the most recent OCC order reducing the
Company's electric rates which became effective on March 5, 1997.
In 1996, the Company decided upon an "enterprise software" future for its
businesses. Enterprise software is a corporate software system designed to
handle most of the Company's information processing needs and to improve work
processes throughout the Company. On January 1, 1997, an enterprise software
system was successfully implemented throughout the Company and is expected to
give the Company a strategic advantage in the years ahead.
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. Except for the historical
statements contained herein, the matters discussed in the following discussion
and analysis, are forward-looking statements that are subject to certain risks,
uncertainties and assumptions. Such forward-looking statements are intended to
be identified in this document by the words "anticipate", "estimate",
"objective", "possible", "potential" and similar expressions. Actual results may
vary materially. Factors that could cause actual results to differ materially
include, but are not limited to: general economic conditions, including their
impact on capital expenditures; business conditions in the energy industry;
competitive factors; unusual weather; regulatory decisions and the other risk
factors listed in the reports filed by the Company with the Securities and
Exchange Commission.
24
RESULTS OF OPERATIONS
REVENUES
Percent Change
From Prior Year
---------------
(THOUSANDS) 1996 1995 1994 1996 1995
- - --------------------------------------------------------------------------------------------------
Sales of electricity to OG&E customers... $1,173,961 $1,135,720 $1,188,550 3.4 (4.4)
Provisions for rate refund............... (1,221) (2,437) (3,417) * *
Sales of electricity to other utilities.. 27,597 35,004 11,765 (21.2) 197.5
- - ----------------------------------------------------------------------------------
Total operating revenues............... $1,200,337 $1,168,287 $1,196,898 2.7 (2.4)
==================================================================================================
System kilowatt-hour sales............... 21,540,670 20,828,415 20,642,675 3.4 0.9
Kilowatt-hour sales to other utilities... 1,475,449 1,851,839 556,765 (20.3) 232.6
- - ----------------------------------------------------------------------------------
Total kilowatt-hour sales.............. 23,016,119 22,680,254 21,199,440 1.5 7.0
==================================================================================================
*NOT MEANINGFUL
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. Actions of the
regulatory commissions that set the Company's electric rates will continue to
affect the Company's financial results. The commissions also have the authority
to examine the appropriateness of the Company's recovery from its customers of
fuel costs, which include the transportation fees that the Company pays Enogex
for transporting natural gas to the Company's generating units. See
"Contingencies" and Note 9 of Notes to Consolidated Financial Statements for a
discussion of the impact of the OCC's February 11, 1997 rate order on these
transportation fees.
Operating revenues increased $32.0 million or 2.7 percent during 1996. This
increase was due to continued customer growth and a return to more normal
weather resulting in increased system sales. During 1995, operating revenues
decreased $28.6 million or 2.4 percent, primarily due to 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
Company customers ("system sales") and a significant increase in kilowatt-hour
sales to other utilities.
EXPENSES AND OTHER ITEMS
Percent Change
From Prior Year
---------------
(DOLLARS IN THOUSANDS) 1996 1995 1994 1996 1995
- - ---------------------------------------------------------------------------------------------
Fuel ............................. $ 323,412 $ 304,775 $ 308,139 6.1 (1.1)
Purchased power................... 222,070 216,598 228,701 2.5 (5.3)
Other operation and maintenance... 253,176 249,873 241,850 1.3 3.3
Restructuring .................... --- --- 21,035 * *
Depreciation and Amortization..... 112,233 110,719 107,239 1.4 3.2
Taxes............................. 112,097 105,305 109,110 6.4 (3.5)
- - --------------------------------------------------------------------------
Total operating expenses........ $1,022,988 $ 987,270 $1,016,074 3.6 (2.8)
=============================================================================================
* NOT MEANINGFUL
25
Total operating expenses increased $35.7 million or 3.6 percent in 1996,
primarily due to higher fuel costs for the production of electricity, higher
income taxes and increased purchases of power from other utilities.
The Company'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 1996, fuel costs increased $18.6
million or 6.1 percent due to increased generation of electricity resulting from
continued customer growth and favorable weather conditions in the electric
service area. During 1995, fuel costs decreased $3.4 million or 1.1 percent
because of lower prices and usage of natural gas and a higher volume of
kilowatt-hours generated with lower-priced coal.
Other operation and maintenance increased $3.3 million or 1.3 percent in
1996, due to the new enterprise software information processing system,
increased pension expense, minor overhauls at coal-fired generating plants and
repair of coal handling equipment. Other operation and maintenance increased
$8.0 million in 1995, because of $22.6 million of amortization of the regulatory
asset resulting from the 1994 restructuring of the Company's operations, costs
associated with a major storm in the Company's service area and the write-off of
obsolete inventory, offset by lower costs resulting from the 1994 workforce
reduction and efficiencies gained in the maintenance of the Company's generating
plants.
In 1996, income taxes increased primarily due to higher pre-tax
earnings. Income taxes decreased in 1995 as a result of an increase in tax
credits earned and lower pre-tax earnings.
Purchased power costs were $222.1 million in 1996, up from $216.6 million
in 1995. The $5.5 million increase in 1996 resulted from the availability of
larger quantities of economically - priced energy from 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. 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 8 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 the Company'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 the Company pays Enogex, which the Company
seeks to recover through the fuel adjustment clause or other tariffs. See Note 9
of Notes to Consolidated Financial Statements for a discussion of the February
11, 1997 OCC order setting, among other things, annual compensation for these
transportation services provided by Enogex to the Company at $41.3 million and
directing the Company to transition to competitive bidding of its gas
transportation requirements currently provided by Enogex no later than April 30,
2000; the APSC order in July 1996 requiring, among other things, a $4.5 million
refund; and the OCC order in February 1994 requiring, among other things, a
$41.3 million refund relating to the fees the Company paid Enogex.
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) utilizing a natural gas storage facility; 2) spot market
purchases of coal; 3) renegotiated contracts for coal, gas, railcar maintenance
and
26
coal transportation; and 4) a heat rate awareness program to produce
kilowatt-hours with less fuel. Reducing fuel costs helps the Company remain
competitive, which in turn helps the Company's electric customers remain
competitive in a global economy.
The increases in depreciation and amortization for 1996 and 1995
reflects higher levels of depreciable plant.
The decrease in interest expense for 1996 was primarily attributable to the
successful refinancing activity in 1995. The Company refinanced approximately
$300 million of long-term debt in 1995, resulting in an approximate $10 million
reduction in annual interest expense.
LIQUIDITY, CAPITAL RESOURCES AND CONTINGENCIES
The primary capital requirements for 1996 and as estimated for 1997 through
1999 are as follows:
(DOLLARS IN MILLIONS) 1996 1997 1998 1999
- - -------------------------------------------------------------------------------
Construction expenditures
including AFUDC.................. $ 94.0 $ 95.0 $ 94.0 $ 94.0
Maturities of long-term debt and
sinking fund requirements........ --- 15.0 25.0 12.5
- - -------------------------------------------------------------------------------
Total........................... $ 94.0 $110.0 $119.0 $106.5
===============================================================================
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 its electric 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.
1996 CAPITAL REQUIREMENTS AND FINANCING ACTIVITIES
Construction expenditures were $94 million in 1996. Approximately $1.3
million of the 1996 construction expenditures were to comply with environmental
regulations. This compares to construction expenditures of $110 million in 1995,
of which $1 million were to comply with environmental regulations.
During 1996, the Company's primary source of capital was internally
generated funds from operating cash flows. Operating cash flow remained strong
in 1996 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 1996, accounts receivable and accounts payable were higher due to more
favorable weather in the last quarter of the year as compared to 1995.
27
Short-term borrowings were used during 1996 to meet temporary cash
requirements. At December 31, 1996, the Company had outstanding short-term
borrowings of $41.4 million.
In April 1996, the Company filed a registration statement for the sale of
up to $300 million of senior notes. In February 1997, the Company reduced the
amount of the registration statement for senior notes to $250 million and filed
a new registration statement for up to $50 million of grantor trust preferred
securities. Assuming favorable market conditions, the Company may issue all or
part of these securities to refinance, at lower rates, one or more series of
outstanding first mortgage bonds or preferred stock.
FUTURE CAPITAL REQUIREMENTS
The Company 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 $400,000 of the Company's construction expenditures budgeted for
1997 are to comply with environmental laws and regulations.
Future financing requirements may be dependent, to varying degrees, upon
numerous factors outside the Company's control 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.
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.
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. Remediation of two of these sites has been completed. The Company's
total waste disposed at the remaining site is minimal and on February 15, 1996,
the Company elected to participate in the de minimis settlement offered by the
EPA, which is being contested by one party. This limits the Company's financial
obligation in addition to removing any participation in the site remedy. While
it is not possible to determine the precise outcome of these matters, in the
opinion of management, the Company's ultimate liability for these sites will not
be material.
On February 11, 1997, the OCC issued an order, among other things,
directing the Company to transition to competitive bidding its gas
transportation requirements, currently met by Enogex, no later than April 30,
2000. This order also set annual compensation for the transportation services
provided by Enogex to the Company at $41.3 million until competitively-bid gas
transportation begins. In 1996, approximately $44 million or 19 percent of
Enogex's revenues were attributable to transporting gas for the Company. Other
pipelines seeking to compete with Enogex for the Company's business will likely
have to
28
pay a fee to Enogex for transporting gas on Enogex's system or incur
expenditures to develop the necessary infrastructure to connect with the
Company's gas-fired generating stations.
The Company has contracted for low-sulfur coal to comply with the sulfur
dioxide limitations of the Clean Air Act Amendments of 1990 ("CAAA"). The
Company also has completed installation and certification of all required
continuous emissions monitors at each of its generating units. Phase II sulfur
dioxide emission requirements will affect the Company beginning in the year
2000. The Company believes it can meet these sulfur dioxide limits without
additional capital expenditures. With respect to nitrogen oxide limits, the
Company is meeting the current emission standards and has exercised its option
to extend the effective date of the further reductions from 2000 to 2008.
The Oklahoma Department of Environmental Quality's CAAA Title V air
permitting program was approved by the EPA in March, 1996. The Company submitted
comprehensive site air permit applications on July 10, 1996 for two of its major
source generating stations. Title V permits for the remaining six permit
applications were submitted on March 5, 1997. Air permit fees for generating
stations were approximately $340,000 in 1996 and are estimated to be
approximately $340,000 in 1997.
In October 1992, the National Energy Policy Act of 1992 ("Energy Act") was
enacted. Among many other provisions, the Energy Act is designed to promote
competition in the development of wholesale power generation in the electric
utility industry. It exempts a new class of independent power producers from
regulation under the Public Utility Holding Company Act of 1935 and allows the
FERC to order "wholesale wheeling" by public utilities to provide utility and
non-utility generators access to public utility transmission facilities.
In April 1996, FERC issued two final rules, Orders 888 and 889, which may
have a significant impact on wholesale markets. These orders were amended in
orders issued in March 1997. Order 888, which was preceded by a Notice of
Proposed Rulemaking referred to as the "Mega-NOPR", sets forth rules on
non-discriminatory open access transmission service to promote wholesale
competition. Order 888, which was effective on July 9, 1996, requires utilities
and other transmission users to abide by comparable terms, conditions and
pricing in transmitting power. Order 889, which had its effective date extended
to January 3, 1997, requires public utilities to implement Standards of Conduct
and an Open Access Same Time Information System ("OASIS", formerly known as
"Real-Time Information Networks"). These rules require transmission personnel to
provide the same information about the transmission system to all transmission
customers using the OASIS. The Company is complying with these new rules from
the FERC.
Another impact of complying with FERC's Order 888 is a requirement for
utilities to offer a transmission tariff that includes network transmission
service ("NTS") to transmission customers. NTS allows transmission service
customers to fully integrate load and resources on an instantaneous basis, in a
manner similar to how the Company has historically integrated its load and
resources. Under NTS, the Company and participating customers share the total
annual transmission cost for their combined joint-use systems, net of related
transmission revenues, based upon each company's share of the total system load.
At this time, the Company expects to incur approximately, $1 million in start-up
costs beginning in 1997 and a minimal annual expense increase, as a result of
Orders 888 and 889.
Numerous state legislatures and regulatory commissions are considering
proposals to increase competition at the retail customer level. The OCC is
seeking to identify, describe and create a process to implement a comprehensive
and integrated restructuring of the electric utility industry for the State of
Oklahoma. On June 6, 1996, the OCC issued a Notice of Inquiry proposing
questions for comment. In
29
response to the Notice of Inquiry, the Company filed comments with the OCC on
September 9, 1996. The comments listed, among other things, five critical issues
that the Company believes must be addressed to ensure a successful transition to
a deregulated environment. These issues are: i) retail wheeling should be
implemented in Oklahoma at the same time it is implemented and on the same terms
in all surrounding states; ii) stranded costs must be recovered; iii) a level
playing field must be established; iv) state regulators role must be
restructured; and v) there must be no exceptions to the new rules. In addition,
legislation has been introduced in the Oklahoma Legislature to permit increased
competition at the retail level by July 2002. The Company is not opposed to such
legislation generally, provided the five issues noted above are addressed
fairly.
Besides the existing contingencies described above, and those described in
Note 8 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.
30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
- - -----------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
See Note 1
--------------------------
Year ended December 31 (DOLLARS IN THOUSANDS EXPECT PER SHARE DATA) 1996 1995 1994
===============================================================================================================
OPERATING REVENUES................................................. $1,200,337 $1,168,287 $1,196,898
- - ---------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Fuel............................................................ 323,412 304,775 308,139
Purchased power................................................. 222,070 216,598 228,701
Other operation................................................. 196,008 194,234 176,668
Maintenance..................................................... 57,168 55,639 65,182
Restructuring................................................... --- --- 21,035
Depreciation and amortization................................... 112,233 110,719 107,239
Current income taxes............................................ 73,171 72,800 47,841
Deferred income taxes, net...................................... 2,156 (2,335) 25,312
Deferred investment tax credits, net............................ (5,150) (5,150) (5,150)
Taxes other than income......................................... 41,920 39,990 41,107
- - ---------------------------------------------------------------------------------------------------------------
Total operating expenses..................................... 1,022,988 987,270 1,016,074
- - ---------------------------------------------------------------------------------------------------------------
OPERATING INCOME................................................... 177,349 181,017 180,824
- - ---------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
Interest income................................................. 3,187 6,556 5,204
Other........................................................... (4,101) (4,284) (4,883)
- - ---------------------------------------------------------------------------------------------------------------
Net other income and deductions.............................. (914) 2,272 321
- - ---------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt...................................... 54,141 63,970 61,226
Allowance for borrowed funds used during construction........... (709) (1,224) (1,073)
Other........................................................... 6,134 7,999 7,197
- - ---------------------------------------------------------------------------------------------------------------
Total interest charges, net.................................. 59,566 70,745 67,350
- - ---------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS.................................. 116,869 112,544 113,795
INCOME FROM OPERATIONS OF ENOGEX DISTRIBUTED
TO OGE ENERGY CORP. (less applicable taxes of $8,050,
$3,502 and $4,068 respectively)................................. 16,463 12,712 9,990
- - ---------------------------------------------------------------------------------------------------------------
NET INCOME......................................................... 133,332 125,256 123,785
PREFERRED DIVIDEND REQUIREMENTS.................................... 2,302 2,316 2,317
- - ---------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON...................................... $ 131,030 $ 122,940 $ 121,468
===============================================================================================================
AVERAGE COMMON SHARES OUTSTANDING.................................. 40,367 40,356 40,344
EARNINGS PER AVERAGE COMMON SHARE
Income from continuing operations............................... $ 2.84 $ 2.73 $ 2.76
Income from Enogex operations................................... 0.41 0.32 0.25
- - ---------------------------------------------------------------------------------------------------------------
Earnings per average common share............................... $ 3.25 $ 3.05 $ 3.01
===============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
31
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
See Note 1
--------------------------
Year ended December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
===============================================================================================================
BALANCE AT BEGINNING OF PERIOD..................................... $ 425,545 $ 409,960 $ 395,811
ADD:
Income from continuing operations............................... 116,869 112,544 113,795
Income from operations of Enogex................................ 16,463 12,712 9,990
- - ---------------------------------------------------------------------------------------------------------------
Total........................................................ 558,877 535,216 519,596
DEDUCT:
Cash dividends declared on preferred stock...................... 2,302 2,316 2,317
Cash dividends declared on common stock......................... 107,377 107,355 107,319
- - ---------------------------------------------------------------------------------------------------------------
Total Cash Dividends......................................... 109,679 109,671 109,636
Distribution of Enogex to OGE Energy Corp....................... 120,568 --- ---
- - ---------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD........................................... $ 328,630 $ 425,545 $ 409,960
===============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
32
CONSOLIDATED BALANCE SHEETS
See Note 1
--------------------------
December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
===============================================================================================================
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service...................................................... $3,574,241 $3,523,708 $3,423,430
Construction work in progress................................... 26,807 24,446 42,624
- - ---------------------------------------------------------------------------------------------------------------
Total property, plant and equipment.......................... 3,601,048 3,548,154 3,466,054
Less accumulated depreciation............................. 1,560,546 1,483,899 1,400,584
- - ---------------------------------------------------------------------------------------------------------------
Net property, plant and equipment............................ 2,040,502 2,064,255 2,065,470
- - ---------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost............................ 21,869 21,858 18,879
- - ---------------------------------------------------------------------------------------------------------------
PROPERTY, EQUIPMENT AND OTHER LONG-TERM
ASSETS OF ENOGEX................................................ --- 295,447 278,120
- - ---------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents....................................... 200 397 434
Notes Receivable................................................ --- --- 38,818
Accounts receivable - customers, less reserve of $3,520,
$3,847 and $3,521 respectively............................... 96,067 88,509 84,145
Accrued unbilled revenues....................................... 34,900 43,550 36,800
Accounts receivable - other..................................... 44,699 8,283 7,904
Fuel inventories, at LIFO cost.................................. 60,463 59,277 43,579
Materials and supplies, at average cost......................... 20,387 18,856 26,808
Prepayments and other........................................... 3,094 3,479 3,135
Accumulated deferred tax assets................................. 8,994 10,042 11,713
Current assets of Enogex........................................ --- 36,816 32,607
- - ---------------------------------------------------------------------------------------------------------------
Total current assets......................................... 268,804 269,209 285,943
- - ---------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Advance payments for gas........................................ 9,500 6,500 10,000
Income taxes recoverable - future rates......................... 44,368 41,934 47,246
Other........................................................... 36,198 55,668 76,971
- - ---------------------------------------------------------------------------------------------------------------
Total deferred charges....................................... 90,066 104,102 134,217
- - ---------------------------------------------------------------------------------------------------------------
TOTAL ASSETS....................................................... $2,421,241 $2,754,871 $2,782,629
===============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
33
CONSOLIDATED BALANCE SHEETS (Continued)
See Note 1
--------------------------
December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
===============================================================================================================
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statements):
Common stock and retained earnings.............................. $ 841,035 $ 937,535 $ 921,177
Cumulative preferred stock...................................... 49,379 49,939 49,973
Long-term debt.................................................. 709,281 723,862 723,667
Long-term debt of Enogex........................................ --- 120,000 6,900
- - ---------------------------------------------------------------------------------------------------------------
Total capitalization......................................... 1,599,695 1,831,336 1,701,717
- - ---------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Short-term debt................................................. 41,400 67,600 152,750
Accounts payable ............................................... 63,596 55,275 49,548
Dividends payable............................................... 27,421 27,427 27,415
Customers' deposits............................................. 23,257 21,920 20,903
Accrued taxes................................................... 25,037 26,556 23,782
Accrued interest................................................ 16,386 15,967 23,740
Long-term debt due within one year.............................. 15,000 --- 25,350
Other........................................................... 35,739 32,953 42,537
Current liabilities of Enogex................................... --- 24,458 50,102
- - ---------------------------------------------------------------------------------------------------------------
Total current liabilities.................................... 247,836 272,156 416,127
- - ---------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation.......................... 57,137 63,983 68,433
Accumulated deferred income taxes............................... 429,766 427,178 437,768
Accumulated deferred investment tax credits..................... 78,028 83,178 88,328
Other........................................................... 8,779 12,120 2,151
Deferred credits and other liabilities of Enogex................ --- 64,920 68,105
- - ---------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities................. 573,710 651,379 664,785
- - ---------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 8 and 9)
- - ---------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES............................... $2,421,241 $2,754,871 $2,782,629
===============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
34
CONSOLIDATED STATEMENTS OF CAPITALIZATION
See Note 1
--------------------------
December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
===============================================================================================================
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........................................ 608,544 608,273 608,158
Retained earnings............................................... 328,630 425,545 409,960
Treasury stock - 6,091,871, 6,097,357 and 6,116,229
shares, respectively......................................... (212,316) (212,460) (213,118)
- - ---------------------------------------------------------------------------------------------------------------
Total common stock and retained earnings.................. 841,035 937,535 921,177
- - ---------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK:
Par value $20, authorized 675,000 shares - 4%;
421,963, 421,963 and 423,663 shares, respectively............ 8,439 8,439 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% 49,950.............................................. 4,995 5,000 5,000
4.24% 75,000.............................................. 7,500 7,500 7,500
4.44% 63,500.............................................. 6,350 6,500 6,500
4.80% 70,950.............................................. 7,095 7,500 7,500
5.34% 150,000............................................. 15,000 15,000 15,000
- - ---------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock.......................... 49,379 49,939 49,973
- - ---------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT:
First mortgage bonds-
SERIES DATE DUE
4.500% March 1, 1995....................................... --- --- 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
6.250% Senior Notes Series B, October 15, 2000............. 110,000 110,000 ---
7.125% January 1, 2002..................................... 40,000 40,000 40,000
8.375% January 1, 2004..................................... --- --- 75,000
9.125% January 1, 2005..................................... --- --- 60,000
8.625% January 1, 2006..................................... --- --- 55,000
8.375% January 1, 2007..................................... 75,000 75,000 75,000
8.625% November 1, 2007.................................... 35,000 35,000 35,000
8.250% August 15, 2016..................................... 100,000 100,000 100,000
8.875% December 1, 2020.................................... 75,000 75,000 75,000
7.300% Senior Notes Series A, October 15, 2025............. 110,000 110,000 ---
5.875% Pollution Control Series A, December 1, 2007........ --- --- 47,000
7.000% Pollution Control Series C, March 1, 2017........... 56,000 56,000 56,000
Other bonds-
6.750% Muskogee Industrial Trust Bonds,
March 1, 2006....................................... --- --- 32,050
Var. % Garfield Industrial Authority, January 1, 2025...... 47,000 47,000 ---
Var. % Muskogee Industrial Authority, January 1, 2025...... 32,400 32,400 ---
Unamortized premium and discount, net........................... (8,619) (9,038) (8,533)
- - ---------------------------------------------------------------------------------------------------------------
Total long-term debt...................................... 724,281 723,862 749,017
Less long-term debt due within one year................ 15,000 --- 25,350
- - ---------------------------------------------------------------------------------------------------------------
Total long-term debt (excluding long-term
debt due within one year).............................. 709,281 723,862 723,667
Enogex Inc................................................ --- 120,000 6,900
- - ---------------------------------------------------------------------------------------------------------------
Total Capitalization............................................... $1,599,695 $1,831,336 $1,701,717
===============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
35
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Note 1
--------------------------
Year ended December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
===============================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income...................................................... $ 133,332 $ 125,256 $ 123,785
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation................................................. 136,140 132,135 126,377
Deferred income taxes and investment tax credits, net........ (3,000) (9,078) 21,942
Provision for rate refund.................................... 1,804 3,112 4,200
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers........................... (16,533) (6,462) 11,898
Accrued unbilled revenues................................. 8,650 (6,750) 8,300
Fuel, materials and supplies inventories.................. (4,200) (6,457) (22,955)
Accumulated deferred tax assets........................... 692 1,318 12,011
Other current assets...................................... (2,361) 38,051 (16,821)
Accounts payable.......................................... 13,401 5,887 (35,667)
Accrued taxes............................................. (1,176) 2,784 436
Accrued interest.......................................... 688 (4,729) (2,839)
Accumulated provision for rate refund..................... (2,650) (320) (36,147)
Other current liabilities................................. 7,131 (6,905) (5,789)
Other operating activities................................... 22,753 13,667 15,479
- - ---------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities.............. 294,671 281,509 204,210
- - ---------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures......................................... (161,129) (141,439) (151,012)
- - ---------------------------------------------------------------------------------------------------------------
Net cash used in investing activities.................. (161,129) (141,439) (151,012)
- - ---------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt, net............................ --- 87,750 (83,450)
Short-term debt, net......................................... (26,200) (115,150) 135,750
Redemption of preferred stock................................ (560) (34) ---
Cash dividends declared on preferred stock................... (2,302) (2,316) (2,317)
Cash dividends declared on common stock...................... (107,377) (107,355) (107,319)
- - ---------------------------------------------------------------------------------------------------------------
Net cash used in financing activities.................. (136,439) (137,105) (57,336)
- - ---------------------------------------------------------------------------------------------------------------
NET (DECREASE) INCREASE IN CASH AND CASH
EQUIVALENTS..................................................... (2,897) 2,965 (4,138)
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD:
From continuing operations................................... 397 434 458
From Enogex operations....................................... 5,023 2,021 6,135
- - ---------------------------------------------------------------------------------------------------------------
Total cash and cash equivalents at beginning of period. 5,420 2,455 6,593
- - ---------------------------------------------------------------------------------------------------------------
EFFECT OF REORGANIZATION - ENOGEX CASH............................. (2,323) --- ---
CASH AND CASH EQUIVALENTS AT END OF PERIOD:
From continuing operations................................... 200 397 434
From Enogex operations....................................... --- 5,023 2,021
===============================================================================================================
Total cash and cash equivalents at end of period....... $ 200 $ 5,420 $ 2,455
===============================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)......................... $ 64,482 $ 76,860 $ 74,372
Income taxes ................................................ $ 82,970 $ 77,752 $ 57,416
- - ---------------------------------------------------------------------------------------------------------------
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.
36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
REORGANIZATION
OGE Energy Corp. ("Energy Corp.") became the parent company of Oklahoma Gas
and Electric Company (the "Company") and its former subsidiary, Enogex, Inc.
("Enogex") on December 31, 1996. On that date, all outstanding Company common
stock was exchanged on a share-for-share basis for common stock of Energy Corp.
and the Company distributed its ownership of Enogex to Energy Corp. Although
Enogex continues to operate as a subsidiary of Energy Corp., for purposes of
these consolidated financial statements, Enogex has been accounted for as
discontinued operations. The net income of Enogex prior to December 31, 1996 is
included in the consolidated statements of income as "Income from Operations of
Enogex Distributed to OGE Energy Corp." Prior year consolidated financial
statements have been restated to reflect Enogex being accounted for as
discontinued operations.
ACCOUNTING RECORDS
The accounting records of the Company 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, the Company,
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 9 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." This standard was adopted effective January 1, 1996 and did 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.
37
PROPERTY, PLANT AND EQUIPMENT
All property, plant and equipment is recorded at cost. Electric utility
plant is recorded at its original cost. Newly constructed plant is added to
plant balances at costs which include contracted services, direct labor,
materials, overhead and allowance for funds used during construction.
Replacement of major units of property are capitalized as plant. The replaced
plant is removed from plant balances and the cost of such property together with
the cost of removal less salvage is charged to accumulated depreciation. Repair
and replacement of minor items of property are included in the 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 1996, 1995 and 1994, 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.
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 Statements of
Income and a charge to construction work in progress.
AFUDC rates, compounded semi-annually, were 5.63, 6.30 and 4.58 percent for
the years 1996, 1995 and 1994, respectively.
UNBILLED REVENUE
The Company accrues estimated revenues for services provided but not yet
billed. The cost of providing service is recognized as incurred.
AUTOMATIC FUEL ADJUSTMENT CLAUSES
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are charged to substantially all of 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 $4.6 million, $2.4 million and
$2.5 million for 1996, 1995 and 1994, respectively, based on the average cost of
fuel purchased late in the respective years.
38
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 the Company has
been designated as one of several potentially responsible parties, the amount
accrued represents the Company's estimated share of the cost.
RECLASSIFICATIONS
Certain amounts have been reclassified on the consolidated financial
statements to conform with the 1996 presentation.
2. INCOME TAXES
The items comprising tax expense are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
- - ---------------------------------------------------------------------------------------------------------------
Provision For Current Income Taxes:
Federal......................................................... $ 65,954 $ 61,996 $ 41,029
State........................................................... 7,217 10,804 6,812
- - ---------------------------------------------------------------------------------------------------------------
Total Provision For Current Income Taxes..................... 73,171 72,800 47,841
- - ---------------------------------------------------------------------------------------------------------------
Provisions (Benefit) For Deferred Income Taxes, net:
Federal
Depreciation................................................. 2,297 5,548 6,559
Repair allowance............................................. 2,100 2,101 1,109
Removal costs................................................ 630 700 1,542
Provision for rate refund.................................... 928 (588) 12,406
Company restructuring........................................ (8,250) (8,373) ---
Other........................................................ 219 (1,613) 92
State........................................................... 4,232 (110) 3,604
- - ---------------------------------------------------------------------------------------------------------------
Total Provision (Benefit) For Deferred Income Taxes, net.... 2,156 (2,335) 25,312
- - ---------------------------------------------------------------------------------------------------------------
Deferred Investment Tax Credits, net............................... (5,150) (5,150) (5,150)
Income Taxes Relating to Other Income and Deductions............... (515) 1,436 203
- - ---------------------------------------------------------------------------------------------------------------
Total Income Tax Expense..................................... $ 69,662 $ 66,751 $ 68,206
- - ---------------------------------------------------------------------------------------------------------------
Pretax Income...................................................... $186,531 $179,295 $182,000
===============================================================================================================
39
The following schedule reconciles the statutory federal tax rate to the
effective income tax rate:
Year ended December 31 1996 1995 1994
- - ---------------------------------------------------------------------------------------
Statutory federal tax rate.............................. 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit... 4.0 3.9 3.7
Tax credits, net........................................ (2.8) (2.9) (2.8)
Other, net.............................................. 1.1 1.2 1.6
- - ---------------------------------------------------------------------------------------
Effective income tax rate as reported.............. 37.3% 37.2% 37.5%
=======================================================================================
The Company is a member of an affiliated group that files consolidated
income tax returns. Income taxes are allocated to each company in the affiliated
group based on its separate taxable income or loss.
Investment tax credits on electric utility property have been deferred and
are being amortized to income over the life of the related property.
The Company follows the provisions of SFAS No. 109, "Accounting for Income
Taxes", which uses an asset and liability approach to accounting for income
taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based
on the difference between the financial statement and income tax bases of assets
and liabilities ("temporary differences") using the enacted marginal tax rate.
Deferred income tax expenses or benefits are based on the changes in the asset
or liability from period to period.
The deferred tax provisions, set forth above, are recognized as costs in
the ratemaking process by the commissions having jurisdiction over the rates
charged by the Company.
40
The components of Accumulated Deferred Income Taxes at December 31, 1996,
1995 and 1994 are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
===============================================================================================
Current Deferred Tax Assets:
Accrued vacation ..................................... $ 3,821 $ 3,377 $ 3,057
Postemployment medical and life insurance benefits.... --- --- 3,235
Provision for rate refund............................. --- 1,025 375
Uncollectible accounts................................ 1,383 1,489 1,477
Capitalization of indirect costs...................... 2,583 2,583 2,583
Provision for Worker's Compensation claims............ 1,207 1,568 ---
Other................................................. --- --- 986
- - -----------------------------------------------------------------------------------------------
Accumulated deferred tax assets.................... $ 8,994 $ 10,042 $ 11,713
- - -----------------------------------------------------------------------------------------------
Deferred Tax Liabilities:
Accelerated depreciation and other property-related
differences........................................ $410,094 $401,043 $396,607
Allowance for funds used during construction.......... 46,429 49,572 53,317
Income taxes recoverable through future rates......... 49,466 54,023 58,470
- - -----------------------------------------------------------------------------------------------
Total.............................................. 505,989 504,638 508,394
- - -----------------------------------------------------------------------------------------------
Deferred Tax Assets:
Deferred investment tax credits....................... (25,372) (27,120) (28,868)
Income taxes refundable through future rates.......... (32,296) (37,795) (40,186)
Postemployment medical and life insurance benefits.... (2,301) (2,347) ---
Company pension plan.................................. (14,965) (10,306) (6,052)
Other................................................. (1,289) 108 4,480
- - -----------------------------------------------------------------------------------------------
Total.............................................. (76,223) (77,460) (70,626)
- - -----------------------------------------------------------------------------------------------
Accumulated Deferred Income Tax Liabilities.............. $429,766 $427,178 $437,768
===============================================================================================
41
3. COMMON STOCK AND RETAINED EARNINGS
There were no new shares of common stock issued during 1996, 1995 or 1994.
The $271,000 and $115,000 increase in 1996 and 1995, respectively and $37,000
decrease in 1994 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, and
repurchased preferred stock.
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 16,024, 18,872 and 18,950 shares
of common stock during 1996, 1995 and 1994, respectively. The Company also
reacquired 10,538 and 11,040 shares in 1996 and 1994, respectively. The shares
distributed/reacquired in the reported periods were recorded as treasury stock.
Changes in common stock were:
(thousands) 1996 1995 1994
- - ------------------------------------------------------------------------------------------
Shares outstanding January 1............................. 40,373 40,354 40,346
Issued/reacquired under the Restricted Stock Plan, net... 6 19 8
- - ------------------------------------------------------------------------------------------
Shares outstanding December 31........................... 40,379 40,373 40,354
==========================================================================================
There were 5,250,000 shares of unissued Energy Corp. common stock reserved
for the various employee and Company stock plans at December 31, 1996. 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.
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 1996, there was approximately $5.7 million in
unamortized costs associated with obtaining these amendments.
42
SHAREOWNERS RIGHTS PLAN
In December 1990, the Company adopted a Shareowners Rights Plan designed
to protect shareowners' interests in the event that the Company was ever
confronted with an unfair or inadequate acquisition proposal. In connection with
the corporate restructuring, Energy Corp. adopted a substantially identical
Shareowners Rights Plan in August 1995. Pursuant to the plan, Energy Corp.
declared a dividend distribution of one "right" for each share of Energy Corp.
common stock. Each right entitles the holder to purchase from Energy Corp. one
one-hundredth of a share of new preferred stock of Energy Corp. 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 Energy Corp.'s
common stock. Under certain circumstances, the holders of the rights will be
entitled to purchase either shares of common stock of Energy Corp. or common
stock of the acquirer at a reduced percentage of market value. The rights are
scheduled to expire on December 11, 2000.
4. CUMULATIVE PREFERRED STOCK
Preferred stock is redeemable at the option of the Company 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
The Company's Trust Indenture, as supplemented, relating to the First
Mortgage Bonds, requires the Company 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, 1996,
gross property additions pledged totaled approximately $382 million.
Annual sinking fund requirements for each of the five years subsequent to
December 31, 1996, are as follows:
Year Amount
-------------------------------------------------------------
1997............................................$ 13,302,083
1998............................................$ 12,781,249
1999............................................$ 12,520,833
2000............................................$ 10,229,166
2001............................................$ 10,229,166
-------------------------------------------------------------
As in prior years, the Company expects to meet these requirements by
pledging permanent additions to property.
43
In April 1996, the Company filed a registration statement for the sale of
up to $300 million of senior notes. In February 1997, the Company reduced the
amount of the registration statement for senior notes to $250 million and filed
a new registration statement for up to $50 million of grantor trust preferred
securities. Assuming favorable market conditions, the Company may issue all or
part of these securities to refinance, at lower rates, one or more series of
outstanding first mortgage bonds or preferred stock.
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 $110 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, 1996.
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 1996 were $142.1 million and $72.4
million, respectively, at a weighted average interest rate of 5.63%. The
weighted average interest rates for 1995 and 1994 were 6.39% and 4.76%,
respectively. The Company 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 $41.4
million was outstanding at December 31, 1996.
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 has not been offset by labor savings through December 31, 1994. The
remaining
44
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 and 1996, amortization of the deferred
regulatory asset was $22.6 million each year.
45
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 Statements of Income in Other operation.
In determining the projected benefit obligation, the weighted average
discount rates used were 7.75, 7.25 and 8.25 percent for 1996, 1995 and 1994,
respectively. The assumed rate of increase in future salary levels was 4.5
percent in 1996, 1995 and 1994. 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 1996, 1995 and 1994 included the
following:
(DOLLARS IN THOUSANDS) 1996 1995 1994
======================================================================================
Service costs..................................... $ 5,472 $ 4,174 $ 7,012
Interest cost on projected benefit obligation..... 20,414 19,971 17,465
Return on plan assets ............................ (18,314) (14,742) (17,217)
Net amortization and deferral..................... (1,263) (1,263) (1,263)
Amortization of unrecognized prior service cost... 2,937 2,634 1,489
- - --------------------------------------------------------------------------------------
Net periodic pension costs........................ $ 9,246 $ 10,774 $ 7,486
======================================================================================
46
The following table sets forth the plan's funded status at December 31,
1996, 1995 and 1994:
(DOLLARS IN THOUSANDS) 1996 1995 1994
- - ----------------------------------------------------------------------------------------------------
Projected benefit obligation:
Vested benefits....................................... $(219,222) $(228,231) $(205,311)
Nonvested benefits.................................... (16,869) (17,476) (13,997)
- - ----------------------------------------------------------------------------------------------------
Accumulated benefit obligation........................ (236,091) (245,707) (219,308)
Effect of future compensation levels.................. (41,305) (42,790) (26,753)
- - ----------------------------------------------------------------------------------------------------
Projected benefit obligation............................. (277,396) (288,497) (246,061)
Plan's assets at fair value.............................. 217,208 210,483 173,766
- - ----------------------------------------------------------------------------------------------------
Plan's assets less than projected benefit obligation..... (60,188) (78,014) (72,295)
Unrecognized prior service cost.......................... 42,954 40,616 43,250
Unrecognized net asset from application of SFAS No. 87... (6,316) (7,580) (8,842)
Unrecognized net (gain) loss............................. (15,101) 8,638 (2,494)
- - ----------------------------------------------------------------------------------------------------
Accrued pension liability................................ $ (38,651) $ (36,340) $ (40,381)
====================================================================================================
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.
During 1993, the Company 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 the Company 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, the Company 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 the Company
continues to believe that it could have recovered these costs in future rate
proceedings before the OCC, the Company decided to recognize these expenses
currently, due to its strategy to reduce its cost-structure, which minimizes
future revenue requirements. The Company 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.
47
Net postretirement benefit expense for 1996, 1995 and 1994 included the
following components:
(DOLLARS IN THOUSANDS) 1996 1995 1994
===============================================================================
Service cost................................ $ 2,052 $ 1,721 $ 2,463
Interest cost............................... 6,577 6,989 5,732
Return on plan assets....................... (3,263) (576) ---
Net amortization............................ 3,723 3,197 3,174
Net amount capitalized or deferred.......... (2,157) (2,399) (4,557)
Discontinued deferral of regulatory asset... --- --- 8,359
- - -------------------------------------------------------------------------------
Net postretirement benefit expense....... $ 6,932 $ 8,932 $ 15,171
===============================================================================
The discount rates used in determining the accumulated postretirement
benefit obligation were 7.75, 7.25 and 8.25 percent for December 31, 1996, 1995
and 1994, 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, 1996, 1995 and 1994. A 9 percent annual rate of
increase in the per capita cost of covered health care benefits was assumed for
1996; 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, 1996, by approximately $8.7
million, and the aggregate of the service and interest cost components of net
postretirement health care cost for 1996 by approximately $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, 1996, 1995 and 1994:
(DOLLARS IN THOUSANDS) 1996 1995 1994
- - -----------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees...................................... $(77,118) $(86,317) $(80,778)
Actives eligible to retire.................... (3,116) (2,239) (1,452)
Actives not yet eligible to retire............ (10,449) (10,369) (6,817)
- - -----------------------------------------------------------------------------------------
Total...................................... (90,683) (98,925) (89,047)
- - -----------------------------------------------------------------------------------------
Plan assets at fair value........................ 39,066 23,864 17,279
- - -----------------------------------------------------------------------------------------
Funded status ................................... (51,617) (75,061) (71,768)
Unrecognized transition obligation............... 41,951 44,573 47,195
Unrecognized net actuarial loss (gain)........... (7,293) 4,272 (2,792)
- - -----------------------------------------------------------------------------------------
Accrued postretirement benefit obligation........ $(16,959) $(26,216) $(27,365)
=========================================================================================
48
8. 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 1997 are estimated at $95 million.
The Company acquires natural gas for boiler fuel under 265 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,
1996, 1995 and 1994, outstanding prepayments for gas, including the amounts
classified as current assets, under these contracts were approximately
$9,936,000, $7,402,000, and $10,879,000, 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, 1996, the Company held non-cancelable operating leases
covering 1,495 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)
1997............... $ 5,280 2000............... $ 5,010
1998............... 5,199 2001............... 4,915
1999............... 5,105 2002 and beyond.... 58,781
-------
Total Minimum Lease Payments............................. $84,290
=======
Rental payments under operating leases were approximately $5.4 million in
1996, $6.5 million in 1995, and $5.6 million in 1994.
The Company 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. 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. During 1996, the Company completed
negotiations and contracted with the third-party developer for gas storage
service. Pursuant to the contract, the third-party developer reimbursed the
Company 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. Permanent financing by the
third-party, which should occur around mid-1997, will replace the bridge finance
agreement with the Company 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
49
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 1996, 1995, and 1994, the Company made total payments to
cogenerators of approximately $210.0 million, $210.4 million, and $210.3
million, of which $175.2 million, $174.1 million, and $173.2 million,
respectively, represented capacity payments. All payments for purchased power,
including cogeneration, are included in the Consolidated Statements of Income as
Purchased power. The future minimum capacity payments under the contracts for
the next five years are approximately: 1997 - $176 million, 1998 - $187 million,
1999 - $189 million, 2000 - $190 million and 2001 - $192 million.
Approximately $400,000 of the Company's construction expenditures budgeted
for 1997 are to comply with environmental laws and regulations.
The Company's management believes all of its operations are in substantial
compliance with present federal, state and local environmental standards. It is
estimated that the Company's total expenditures for capital, operating,
maintenance and other costs to preserve and enhance environmental quality will
be approximately $40 million during 1997, compared to approximately $43 million
in 1996. The Company continues to evaluate its environmental management systems
to ensure compliance with existing and proposed environmental legislation and
regulations and to better position itself in a competitive market.
The Company has contracted for low-sulfur coal to comply with the sulfur
dioxide limitations of the Clean Air Act Amendments of 1990 ("CAAA"). The
Company also has completed installation and certification of all required
continuous emissions monitors at each of its generating units. Phase II sulfur
dioxide emission requirements will affect the Company beginning in the year
2000. The Company believes it can meet these sulfur dioxide limits without
additional capital expenditures. With respect to nitrogen oxide limits, the
Company is meeting the current emission standards and has exercised its option
to extend the effective date of the further reductions from 2000 to 2008.
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. Remediation at two of these sites has
been completed. The Company's total waste disposed at the remaining site is
minimal and on February 15, 1996, the Company elected to participate in the de
minimis settlement offered by EPA, which limited the Company's financial
obligation to less than $50,000. One of the other potentially responsible
parties is currently contesting the Company's participation as a de minimis
party. Regardless of the outcome of this issue, the Company believes its
ultimate liability for this site is minimal.
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.
50
9. RATE MATTERS AND REGULATION
On February 11, 1997, the OCC issued an order that, among other things,
effectively lowered the Company's rates to its Oklahoma retail customers by $50
million annually (based on a test year ended December 31, 1995). The OCC order
also directed the Company to transition to competitive bidding of its gas
transportation requirements, currently met by Enogex, no later than April 30,
2000. The order also set annual compensation for the transportation services
provided by Enogex at $41.3 million until competitively-bid gas transportation
begins.
As discussed in Note 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, the
Company 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 the Company 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 the Company's
electric rates during such period by approximately $15 million annually,
effective January 1995. The labor savings from the VERP and severance package
substantially offset the amortization of the regulatory asset and annual rate
reduction of $15 million.
On February 25, 1994, the OCC issued an order that, among other things,
effectively lowered the Company's rates to its Oklahoma retail customers by
approximately $14 million annually (based on a test year ended June 30, 1991)
and required the Company to refund approximately $41.3 million. The $14 million
annual reduction in rates lowered the Company's rates to its Oklahoma customers
by approximately $17 million annually. With respect to the $41.3 million refund,
the entire amount relates to the disallowance of a portion of the fees paid by
the Company to Enogex for transportation services of which $39.1 million was
associated with revenues prior to January 1, 1994, while the remaining $2.2
million related to 1994.
On June 18, 1996, the APSC staff and the Company filed a Joint Stipulation
recommending settlement of certain issues resulting from the APSC review of the
amounts that the Company pays Enogex and recovers through its fuel clause for
transporting natural gas to the Company's gas-fired generating stations. On July
11, 1996, the APSC issued an order that, among other things, required the
Company to refund approximately $4.5 million in 1996 to its Arkansas retail
electric customers. The $4.5 million refund related to the disallowance of a
portion of the fees paid by the Company to Enogex for such transportation
services and was recorded as a provision for a potential refund prior to August
1996.
The components of Deferred Charges - Other, on the Consolidated Balance
Sheets included the following, as of December 31:
(DOLLARS IN THOUSANDS) 1996 1995 1994
- - -----------------------------------------------------------------------------------
Regulatory asset (restructuring)................ $ 3,759 $26,331 $48,903
Unamortized debt expense........................ 10,291 10,919 12,871
Unamortized loss on reacquired debt............. 10,253 11,197 5,487
Insurance claims - Property Damage.............. 6,231 --- ---
Miscellaneous................................... 5,664 7,221 9,710
- - -----------------------------------------------------------------------------------
Total........................................ $36,198 $55,668 $76,971
===================================================================================
51
Regulatory Assets and Liabilities consisted of the following as of December 31:
(DOLLARS IN THOUSANDS) 1996 1995 1994
- - -------------------------------------------------------------------------------------
Regulatory Assets:
Income Taxes Recoverable from Customers..... $127,819 $139,594 $151,086
Workforce Reduction (Restructuring)......... 3,759 26,331 48,903
Miscellaneous............................... 435 455 2,214
- - -------------------------------------------------------------------------------------
Total Regulatory Assets.................. 132,013 166,380 202,203
Regulatory Liabilities:
Income Taxes Refundable to Customers........ (83,451) (97,660) (103,840)
Gain on Disposition of Allowances........... (329) (282) (187)
- - -------------------------------------------------------------------------------------
Net Regulatory Assets.......................... $ 48,233 $ 68,438 $ 98,176
=====================================================================================
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.
10. 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.
52
Indicated below are the carrying amounts and estimated fair values of the
Company's financial instruments as of December 31:
1996 1995 1994
-------------------- -------------------- --------------------
Carrying Fair Carrying Fair Carrying Fair
(DOLLARS IN THOUSANDS) Amount Value Amount Value Amount Value
===========================================================================================================
ASSETS:
CASH AND CASH EQUIVALENTS....... $ 200 $ 200 $ 397 $ 397 $ 434 $ 434
===========================================================================================================
LIABILITIES:
CUSTOMER DEPOSITS $ 23,257 $ 23,257 $ 21,920 $ 21,920 $ 20,903 $ 20,903
===========================================================================================================
CAPITALIZATION:
First Mortgage Bonds............ $644,881 $656,362 $644,462 $671,356 $716,967 $710,523
Industrial Authority Bonds...... 79,400 79,400 79,400 79,400 32,050 32,044
Preferred Stock:
4% - 5.34% Series -- 831,363,
836,963 and 838,663 Shares... 49,379 35,829 49,939 35,541 49,973 27,442
- - -----------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION............ $773,660 $771,591 $773,801 $786,297 $798,990 $770,009
===========================================================================================================
53
Report of Independent Public Accountants
TO THE SHAREOWNER 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, 1996, 1995 and 1994, 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, 1996, 1995 and 1994, and the
results of its operations and its 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 23, 1997
54
Report of Management
- - --------------------
To Our Shareowner:
The management of Oklahoma Gas and Electric Company 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 the 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.
55
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 PER Dec 31 Sep 30 Jun 30 Mar 31
SHARE DATA)
- - ----------------------------------------------------------------------------------------- -----------
Operating revenues......................... 1996 $251,669 $411,765 $303,077 $233,826
1995 241,041 436,846 275,524 214,876
1994 241,739 411,662 304,632 238,865
- - ----------------------------------------------------------------------------------------- -----------
Operating income........................... 1996 $ 18,002 $101,098 $ 47,356 $ 10,893
1995 19,785 110,603 37,717 12,912
1994 18,038 101,081 44,328 17,377
- - -----------------------------------------------------------------------------------------------------
Income from operations of Enogex
distributed to OGE Energy Corp.......... 1996 $ 3,900 $ 3,740 $ 4,322 $ 4,501
1995 3,575 2,844 3,039 3,254
1994 3,529 1,869 3,657 935
- - -----------------------------------------------------------------------------------------------------
Net income (loss).......................... 1996 $ 7,301 $ 90,165 $ 35,328 $ 538
1995 4,890 96,969 24,258 (861)
1994 4,952 86,251 31,082 1,500
- - -----------------------------------------------------------------------------------------------------
Earnings (loss) available for common....... 1996 $ 6,729 $ 89,593 $ 34,749 $ (41)
1995 4,311 96,390 23,679 (1,440)
1994 4,372 85,672 30,503 921
- - -----------------------------------------------------------------------------------------------------
Earnings (loss) per average common share... 1996 $ 0.17 $ 2.22 $ 0.86 $ 0.00
1995 0.11 2.39 0.59 (0.04)
1994 0.11 2.12 0.76 0.02
- - -----------------------------------------------------------------------------------------------------
56
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
- - --------------------------------------------------------------------
AND FINANCIAL DISCLOSURE.
------------------------
Not Applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
- - -----------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION.
- - -------------------------------
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
- - -------------------------------------------------
OWNERS AND MANAGEMENT.
---------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
- - -------------------------------------------------------
Items 10, 11, 12 and 13 are omitted pursuant to General Instruction G of
Form 10-K, since the Company filed copies of a definitive information statement
with the Securities and Exchange Commission on or about April 11, 1997. Such
information 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, 1996, 1995 and 1994
o Consolidated Statements of Income for the years ended December 31, 1996,
1995 and 1994
o Consolidated Statements of Retained Earnings for the years ended
December 31, 1996, 1995 and 1994
o Consolidated Statements of Capitalization at December 31, 1996, 1995
and 1994
o Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994
o Notes to Consolidated Financial Statements
o Report of Independent Public Accountants
o Report of Management
57
SUPPLEMENTARY DATA
------------------
o Interim Consolidated Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE
- - ----------------------------------------------------- ----
Schedule II - Valuation and Qualifying Accounts 66
Report of Independent Public Accountants 67
Financial Data Schedule 78
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
Registration Statement No. 33-59805,
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)
58
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)
59
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)
60
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)
61
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
the Company 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 the Company
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 the Company and
Atlantic Richfield Company. (Filed as Exhibit 5.28 to
Registration Statement No. 2-62208 and incorporated by
reference herein)
62
10.04 Amendment dated June 27, 1990, between the Company and Thunder
Basin Coal Company, to Coal Supply Agreement dated
March 1, 1973, between the Company 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 The First National Bank and Trust Company of
Oklahoma City, Thrall Car Manufacturing Company,
the Company and other parties, including Lease of
Railroad Equipment dated January 1, 1980, between
Mercantile-Safe Deposit and Trust Company and
the Company. (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 the Company.
(Filed as Exhibit 20.01 to the Company's Form 10-Q
for June 30, 1981, File No. 1-1097, and incorporated
by reference herein)
10.07 Form of Change of Control Agreement for Officers of the Company
and Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.'s
Form 10-K Report for the year ended December 31, 1996,
File No. 1-12579 and incorporated by reference herein)
10.08 Amended and Restated Stock Equivalent and
Deferred Compensation Plan for Directors,
as amended. (Filed as Exhibit 10.08 to Energy Corp.'s
Form 10-K Report for the year ended December 31, 1996,
File No. 1-12579, and incorporated by reference herein)
10.09 Restricted Stock Plan of Energy Corp. (Filed as Exhibit 10.09
to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996, File No. 1-12579, and
incorporated by reference herein)
63
10.10 Agreement and Plan of Reorganization, dated May 14, 1986,
between the Company 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
the Company 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 Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996, File
No. 1-12579 and incorporated by reference herein)
10.13 Energy Corp.'s Restoration of Retirement Savings Plan.
(Filed as Exhibit 10.13 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996, File
No. 1-12579 and incorporated by reference herein)
10.14 Gas Service Agreement dated July 23, 1987, between
the Company 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 10.15 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996, File
No. 1-12579 and incorporated by reference herein)
10.16 Energy Corp.'s Annual Incentive Compensation Plan.
(Filed as Exhibit 10.16 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996, File
No. 1-12579 and incorporated by reference herein)
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
27.02 Financial Data Schedule.
27.03 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995
64
Executive Compensation Plans and Arrangements
---------------------------------------------
10.07 Form of Change of Control Agreement for Officers of the Company and
Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.'s
Form 10-K Report for the year ended December 31, 1996,
File No. 1-12579, and incorporated by reference herein)
10.08 Amended and Restated Stock Equivalent and
Deferred Compensation Plan for Directors, as amended.
(Filed as Exhibit 10.08 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1996, File No. 1-12579,
and incorporated by reference herein)
10.09 Restricted Stock Plan of the Company. (Filed as Exhibit 10.09 to
Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996, File No. 1-12579, and incorporated
by reference herein)
10.12 Company's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1996, File No. 1-12579
and incorporated by reference herein)
10.13 Energy Corp.'s Restoration of Retirement Savings Plan.
(Filed as Exhibit 10.13 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1996, File No. 1-12579
and incorporated by reference herein)
10.15 Company's Supplemental Executive Retirement Plan.
(Filed as Exhibit 10.15 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1993, File No. 1-12579
and incorporated by reference herein)
10.16 Energy Corp.'s Annual Incentive Compensation Plan.
(Filed as Exhibit 10.16 to Energy Corp.'s Form 10-K Report
for the year ended December 31, 1996, File No. 1-12579
and incorporated by reference herein)
(B) REPORTS ON FORM 8-K
- - ------------------------
Item 5. Other Events, dated May 17, 1996.
Item 5. Other Events, dated June 3, 1996.
Item 5. Other Events, dated October 16, 1996.
Item 5. Other Events, dated November 14, 1996.
Item 5. Other Events, dated December 20, 1996.
65
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
----------- --------- ---------- ---------- ---------- ----
1996 (THOUSANDS)
Reserve for Uncollectible Accounts $3,847 $6,571 - $6,898 $3,520
1995
Reserve for Uncollectible Accounts $3,521 $7,428 - $7,102 $3,847
1994
Reserve for Uncollectible Accounts $3,895 $6,744 - $7,118 $3,521
66
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 23,
1997. Our audits were made for the purpose of forming an opinion on those
statements taken as a whole. The schedule listed on Page 58, 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 23, 1997
67
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 21st day of March, 1997.
OKLAHOMA GAS AND ELECTRIC COMPANY
(REGISTRANT)
/s/ Steven E. Moore
By Steven E. Moore
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this Report has been signed below by the following persons in the
capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/ s / Steven E. Moore
Steven E. Moore Principal Executive March 21, 1997
Officer and Director;
/ s / A. M. Strecker
A. M. Strecker Principal Financial Officer; and March 21, 1997
/ s / Donald R. Rowlett
Donald R. Rowlett Principal Accounting Officer. March 21, 1997
Herbert H. Champlin Director;
Luke R. Corbett Director;
William E. Durrett Director;
Martha W. Griffin Director;
Hugh L. Hembree, III Director;
Robert Kelley Director;
Bill Swisher Director; and
Ronald H. White, M.D. Director.
/ s / Steven E. Moore
By Steven E. Moore (attorney-in-fact) March 21, 1997
68
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- - ---------- -----------
3.01 Copy of Restated Certificate of Incorporation.
(Filed as Exhibit 4.01 to the Company's
Registration Statement No. 33-59805,
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)
69
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)
70
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)
71
4.20 Copy of Supplemental Trust Indenture, dated
January 1, 1977, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.20
to Registration Statement No. 2-59887 and
incorporated by reference herein)
4.21 Copy of Supplemental Trust Indenture, dated
November 1, 1977, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.21 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.22 Copy of Supplemental Trust Indenture, dated
December 1, 1977, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.22 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.23 Copy of Supplemental Trust Indenture, dated
February 1, 1980, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.23 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.24 Copy of Supplemental Trust Indenture, dated
April 15, 1982, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.24
to the Company's Form 10-K Report, File No. 1-1097,
for the year ended December 31, 1982, and incorporated
by reference herein)
4.25 Copy of Supplemental Trust Indenture, dated
August 15, 1986, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.25
to the Company's Form 10-K Report, File No. 1-1097,
for the year ended December 31, 1986 and incorporated
by reference herein)
4.26 Copy of Supplemental Trust Indenture, dated March 1, 1987,
being a supplemental instrument to Exhibit 4.01 hereto.
(Filed as Exhibit 4.26 to the Company's Form 10-K Report
for the year ended December 31, 1987, File No. 1-1097,
and incorporated by reference herein)
72
4.28 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
the Company 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 the Company
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 the Company and
Atlantic Richfield Company. (Filed as Exhibit 5.28 to
Registration Statement No. 2-62208 and incorporated by
reference herein)
73
10.04 Amendment dated June 27, 1990, between the Company and Thunder
Basin Coal Company, to Coal Supply Agreement dated
March 1, 1973, between the Company 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 The First National Bank and Trust Company of
Oklahoma City, Thrall Car Manufacturing Company,
the Company and other parties, including Lease of
Railroad Equipment dated January 1, 1980, between
Mercantile-Safe Deposit and Trust Company and
the Company. (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 the Company.
(Filed as Exhibit 20.01 to the Company's Form 10-Q
for June 30, 1981, File No. 1-1097, and incorporated
by reference herein)
10.07 Form of Change of Control Agreement for Officers of the Company
and Energy Corp. (Filed as Exhibit 10.07 to Energy Corp.'s
Form 10-K Report for the year ended December 31, 1996,
File No. 1-12579 and incorporated by reference herein)
10.08 Amended and Restated Stock Equivalent and
Deferred Compensation Plan for Directors,
as amended. (Filed as Exhibit 10.08 to Energy Corp.'s
Form 10-K Report for the year ended December 31, 1996,
File No. 1-12579, and incorporated by reference herein)
10.09 Restricted Stock Plan of Energy Corp. (Filed as Exhibit 10.09
to Energy Corp.'s Form 10-K Report for the year ended
December 31, 1996, File No. 1-12579, and
incorporated by reference herein)
74
10.10 Agreement and Plan of Reorganization, dated May 14, 1986,
between the Company 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
the Company 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 Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996, File
No. 1-12579 and incorporated by reference herein)
10.13 Energy Corp.'s Restoration of Retirement Savings Plan.
(Filed as Exhibit 10.13 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996, File
No. 1-12579 and incorporated by reference herein)
10.14 Gas Service Agreement dated July 23, 1987, between
the Company 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 10.15 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996, File
No. 1-12579 and incorporated by reference herein)
10.16 Energy Corp.'s Annual Incentive Compensation Plan.
(Filed as Exhibit 10.16 to Energy Corp.'s Form 10-K
Report for the year ended December 31, 1996, File
No. 1-12579 and incorporated by reference herein)
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
27.02 Financial Data Schedule.
27.03 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995
75