<PAGE> 1
________________________________________________________________________________
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, 1994 Commission File Number 1-1097
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma 73-0382390
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
101 North Robinson
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 405-553-3000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which
so registered each class is registered
------------------- ------------------------------
Common Stock New York Stock Exchange
Common Stock Pacific Stock Exchange
Preferred Stock 4% Cumulative New York Stock Exchange
First Mortgage Bonds, Series due 1995 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
As of February 28, 1995, Common Shares outstanding were 40,354,387. Based
upon the closing price on the New York Stock Exchange on February 28, 1995, the
aggregate market value of the voting stock held by nonaffiliates of the Company
was: Common Stock $1,421,022,063 and 4% Cumulative Preferred Stock $4,976,724.
The proxy statement for the 1995 annual meeting of shareowners is
incorporated by reference into Part III of this Report.
________________________________________________________________________________
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<TABLE>
<CAPTION>
TABLE OF CONTENTS
ITEM PAGE
---- ----
<S> <C>
PART I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
The Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Electric Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Finance and Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Regulation and Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Rate Structure, Load Growth and Related Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Environmental Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Enogex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Item 4. Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
PART III
Item 10. Directors and Executive Officers of the Registrant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Item 12. Security Ownership of Certain Beneficial
Owners and Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Item 13. Certain Relationships and Related Transactions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
</TABLE>
<PAGE> 3
PART I
ITEM 1. BUSINESS.
------------------
THE COMPANY
Oklahoma Gas and Electric Company ("OG&E") is a regulated public
utility engaged in the generation, transmission and distribution of electricity
to retail and wholesale customers. Enogex Inc., a wholly-owned subsidiary of
OG&E, and Enogex Inc.'s subsidiaries (collectively, "Enogex") are engaged in
non-utility businesses, consisting of diverse natural gas activities. OG&E and
Enogex are herein referred to collectively as the "Company." Financial
information on the Company's two segments of business is included in Note 8 of
Notes to Consolidated Financial Statements.
OG&E, incorporated in 1902 under the laws of the Oklahoma Territory,
is the largest electric utility in the State of Oklahoma. OG&E sold its retail
gas business in 1928, and now owns and operates an interconnected electric
production, transmission and distribution system which includes eight active
generating stations with a total capability of 5,637,300 kilowatts. Enogex
owns and operates over 3,000 miles of natural gas transmission and gathering
pipelines, has interests in four gas processing plants, markets natural gas and
natural gas products and invests in the exploration and production of natural
gas. At the end of 1994, Enogex had 314 members and OG&E had 2,494 members.
OG&E's executive offices are located at 101 North Robinson, P.O. Box 321,
Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
On February 25, 1994, the Oklahoma Corporation Commission ("OCC")
issued an order that, among other things, effectively lowered OG&E's rates to
its Oklahoma retail customers by approximately $17 million annually and
required OG&E to refund approximately $41.3 million. Of the $41.3 million
refund, $39.1 million was associated with revenues prior to January 1, 1994,
while the remaining $2.2 million related to 1994. See "Regulation and Rates -
Recent Regulatory Matters" for a further discussion of this order.
In 1994, the Company restructured and redesigned its operations to
reduce costs in order to more favorably position itself for the competitive
electric utility environment. As part of this process, the Company implemented
a Voluntary Early Retirement Package ("VERP") and a severance package in 1994.
These two packages reduced the Company's workforce by approximately 900
employees.
In response to an application filed by OG&E on August 9, 1994, the OCC
issued an order on October 26, 1994, that permitted OG&E to: (1) establish a
regulatory asset in connection with the costs associated with the workforce
reduction; (2) amortize the December 31, 1994, balance of the regulatory asset
over 26 months; and (3) reduce OG&E's electric rates by approximately $15
million annually, effective January 1995. In 1995 and 1996, the labor savings
are expected to substantially offset the amortization of the regulatory asset
and the annual rate reduction of $15 million. See "Regulation and Rates -
Recent Regulatory Matters" and Note 10 of Notes to Consolidated Financial
Statements for a further discussion of the OCC's orders in February and October
1994.
<PAGE> 4
ELECTRIC OPERATIONS
GENERAL
OG&E furnishes retail electric service in 270 communities and their
contiguous rural and suburban areas. During 1994, six other communities and
two rural electric cooperatives in Oklahoma and western Arkansas purchased
electricity from OG&E for resale. The service area, with an estimated
population of 1.4 million, covers approximately 30,000 square miles in Oklahoma
and western Arkansas; including Oklahoma City, the largest city in Oklahoma,
and Ft. Smith, Arkansas, the second largest city in that state. Of the 276
communities served, 247 are located in Oklahoma and 29 in Arkansas.
Approximately 91 percent of total electric operating revenues for the year
ended December 31, 1994, were derived from sales in Oklahoma and the remainder
from sales in Arkansas.
OG&E's system control area peak demand as reported by the system
dispatcher for the year was approximately 5,060 megawatts, and occurred on June
27, 1994. Excluding wheeling, the net on system peak demand was about 4,700
megawatts. However, when firm sales were included, total load responsibility
was approximately 4,722 megawatts, resulting in a capacity margin of
approximately 22.56 percent. As reflected in the table below and the operating
statistics on page 4, kilowatt-hour sales to OG&E customers ("system sales")
increased 2.2 percent in 1994 compared to 1993. This increase in system sales
was offset by an 82.1 percent decline in sales to other utilities ("off-system
sales") which caused total kilowatt-hour sales to be down by 9.0 percent for
1994. 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 1993
and 1992, factors which resulted in variations in total kilowatt-hour sales
included: (i) more normal weather in 1993, (ii) continued customer growth; and
(iii) the high level of off-system sales in 1992.
Variations in kilowatt-hour sales for the three years are reflected in
the following table:
<TABLE>
<CAPTION>
KWH SALES (millions)
INC/ Inc/ Inc/
1994 (DEC) 1993 (Dec) 1992 (Dec)
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
System Sales 20,642 2.2% 20,202 5.0% 19,237 (1.5%)
Off-System Sales 557 (82.1%) 3,104 (25.0%) 4,141 62.1%
------ ------ ------
Total Sales 21,199 (9.0%) 23,306 (0.3%) 23,378 5.9%
====== ====== ======
</TABLE>
OG&E is subject to competition in some areas from government-owned
electric systems, municipally-owned electric systems, rural electric
cooperatives and, in certain respects, from other private utilities and
cogenerators. Oklahoma law forbids the granting of an exclusive franchise to a
utility for providing electricity.
Besides competition from other suppliers of electricity, OG&E competes
with suppliers of other forms of energy. The degree of competition between
suppliers may vary depending on relative costs and supplies of other forms of
energy. In October 1992, the National Energy Policy Act of 1992 ("Energy Act")
was enacted. Among many other provisions, the Energy Act is designed to
promote competition in the development of wholesale power generation in the
electric utility industry. Also, numerous states are considering proposals
to require "retail wheeling" which is the delivery of power generated by a
third party to retail customers. The Energy Act, these proposals and other
factors are expected to significantly increase
2
<PAGE> 5
competition in the electric industry. The Company has taken steps in the past
and intends to take appropriate steps in the future to remain a competitive
supplier of electricity. See "Regulation and Rates - Recent Regulatory
Matters" for a further discussion of this matter.
Electric and magnetic fields ("EMFs") surround all electric tools and
appliances, internal home wiring, and external power lines such as those owned
by OG&E. During the last several years considerable attention has focused on
possible health effects from EMFs. While some recent studies indicate a
possible correlation, other similar studies indicate no correlation between
EMFs and health effects. The nation's electric utilities, including OG&E, have
participated with the Electric Power Research Institute in the sponsorship of
more than $75 million in research to determine the possible health effects of
EMFs. Beginning in fiscal year 1994, and in association with the Energy Act,
Edison Electric Institute members will help fund $65 million for EMF studies
over the next five years. One-half of this amount will be funded by the
federal government, and two-thirds of the non-federal funding is expected to be
provided by the electric utility industry. Through its participation with the
Electric Power Research Institute and Edison Electric Institute, OG&E will
continue its support of the research with regard to the possible health effects
of EMFs. OG&E is dedicated to delivering electric service in a safe, reliable,
environmentally acceptable and economical manner.
3
<PAGE> 6
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
<TABLE>
<CAPTION>
Year Ended December 31
1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>
ELECTRIC ENERGY:
(Millions of kWh)
Generation (exclusive of station use) . . . . . . . 18,325 21,789 21,960
Purchased . . . . . . . . . . . . . . . . . . . . . 4,387 3,169 2,724
----------- ----------- -----------
Total generated and purchased . . . . . . . . . 22,712 24,958 24,684
Company use, free service and losses . . . . . . . . (1,513) (1,652) (1,306)
----------- ----------- -----------
Electric energy sold . . . . . . . . . . . . . . 21,199 23,306 23,378
=========== =========== ===========
ELECTRIC ENERGY SOLD:
(Millions of kWh)
Residential . . . . . . . . . . . . . . . . . . . . 6,739 6,631 5,980
Commercial and industrial . . . . . . . . . . . . . 10,886 10,595 10,341
Public street and highway lighting . . . . . . . . . 66 64 63
Other sales to public authorities . . . . . . . . . 2,018 1,966 1,932
Sales for resale . . . . . . . . . . . . . . . . . . 1,490 4,050 5,062
----------- ----------- -----------
Total . . . . . . . . . . . . . . . . . . . . . 21,199 23,306 23,378
=========== =========== ===========
OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential . . . . . . . . . . . . . . . . . . $ 476,441 $ 488,921 $ 436,984
Commercial and industrial . . . . . . . . . . . 549,528 582,733 550,738
Public street and highway lighting . . . . . . . 9,294 9,433 9,134
Other sales to public authorities . . . . . . . 99,789 107,035 101,434
Sales for resale . . . . . . . . . . . . . . . . 43,001 89,945 95,529
Provision for rate refund . . . . . . . . . . . (3,417) (14,963) (18,000)
Miscellaneous . . . . . . . . . . . . . . . . . 22,262 19,712 18,174
----------- ----------- -----------
Total Electric Revenues . . . . . . . . . . . 1,196,898 1,282,816 1,193,993
Non-utility subsidiary . . . . . . . . . . . . . . 158,270 164,436 120,991
----------- ----------- -----------
Total . . . . . . . . . . . . . . . . . . . $ 1,355,168 $ 1,447,252 $ 1,314,984
=========== =========== ===========
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential . . . . . . . . . . . . . . . . . . . . 578,044 568,780 563,261
Commercial and industrial . . . . . . . . . . . . . 81,175 79,572 78,799
Public street and highway lighting . . . . . . . . . 249 248 248
Other sales to public authorities . . . . . . . . . 10,198 10,074 9,842
Sales for resale . . . . . . . . . . . . . . . . . . 39 39 37
----------- ----------- -----------
Total . . . . . . . . . . . . . . . . . . . . . 669,705 658,713 652,187
=========== =========== ===========
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (kWh) . . . . . . . . . . . . . . 11,724 11,688 10,664
Average annual revenue . . . . . . . . . . . . . . . $ 828.86 $ 861.72 $ 779.21
Average price per kWh (cents) . . . . . . . . . . . 7.07 7.37 7.31
</TABLE>
4
<PAGE> 7
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, which enabled the Company to internally generate the required
funds to satisfy construction expenditures during 1994 and 1993.
Management expects that internally generated funds will be adequate
over the next three years to meet OG&E's capital requirements. The primary
capital requirements for 1995 through 1997 are estimated as follows:
<TABLE>
<CAPTION>
(dollars in millions) 1995 1996 1997
-----------------------------------------------------------
<S> <C> <C> <C>
Consolidated construction
expenditures including AFUDC ...... $ 89 $ 89 $ 89
Maturities of long-term debt and
sinking fund requirements ......... 25 - 15
----------------------------------------------------------
Total .......................... $114 $ 89 $104
==========================================================
</TABLE>
The three-year estimate includes expenditures for construction of new
facilities to meet anticipated demand for service, to replace or expand
existing facilities in both its electric and non-utility businesses, and to
some extent, for satisfying maturing debt and sinking fund obligations.
Approximately $7.4 million of the Company's construction expenditures budgeted
for 1995 are to comply with environmental laws and regulations. OG&E's
construction program was developed to support an anticipated peak demand growth
of one to two percent annually and to maintain minimum capacity reserve margins
as stipulated by the Southwest Power Pool. See "Rate Structure, Load Growth
and Related Matters."
OG&E's ability to sell additional securities on satisfactory terms to
meet its capital needs is dependent upon numerous factors, including general
market conditions for utility securities, which will impact OG&E's ability to
meet earnings tests for the issuance of additional first mortgage bonds and
preferred stock. Based on earnings for the twelve months ended December 31,
1994, and assuming an annual interest rate of 8.3 percent, OG&E could issue
approximately $883 million in principal amount of additional first mortgage
bonds under the earnings test contained in OG&E's Trust Indenture (assuming
adequate property additions were available). Under the earnings test contained
in OG&E's Restated Certificate of Incorporation and assuming none of the
foregoing first mortgage bonds are issued, about $864 million of additional
preferred stock at an assumed annual dividend rate of 7.9 percent could be
issued as of December 31, 1994.
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 1994 was $220 million.
OG&E intends to meet its customers' increased electricity needs during
the foreseeable future by maintaining the reliability and increasing the
utilization of existing capacity along with demand-side management. OG&E is not
currently constructing new base-load generation and does not anticipate the
need for another base-load plant in the foreseeable future.
As part of its Integrated Resource Plan ("IRP") for supplying energy
through the next decade and beyond, OG&E is evaluating measures to keep its
existing generating plants operating efficiently well past their traditional
retirement dates. As long as the cost to keep existing plants operating
reliably and efficiently is less than the cost of alternative sources of
capacity, existing plants will be operated.
5
<PAGE> 8
In accordance with the requirements of the Public Utility Regulatory
Policies Act of 1978 ("PURPA") (see "Regulation and Rates, National Energy
Legislation"), OG&E is obligated to purchase 110 megawatts of capacity annually
from Smith Cogeneration, Inc. and 320 megawatts annually from Applied Energy
Services, Inc. AES, another cogenerator. In 1986, a contract was signed with
Sparks Regional Medical Center to purchase energy not needed by the hospital
from its nominal seven megawatt cogeneration facility. In 1987, OG&E signed a
contract to purchase up to 100 megawatts of capacity from Mid-Continent Power
Company, Inc. This purchase of capacity is currently planned to begin in 1998
and carries no obligation on the part of OG&E to purchase energy. The
purchases under each of these cogeneration contracts were approved by the
appropriate regulatory commissions at rates set in accordance with PURPA.
OG&E's financial results depend to a large extent upon the tariffs it
charges customers and the actions of the regulatory bodies that set those
tariffs, the amount of energy used by its customers, the cost and availability
of external financing and the cost of conforming to government regulations.
REGULATION AND RATES
OG&E's retail electric tariffs in Oklahoma are regulated by the OCC,
and in Arkansas are regulated by the Arkansas Public Service Commission
("APSC"). The issuance of certain securities by OG&E is also regulated by the
OCC and the APSC. OG&E's wholesale electric tariffs, short-term borrowing
authorization and accounting practices are subject to the jurisdiction of the
Federal Energy Regulatory Commission ("FERC"). The Secretary of the Department
of Energy has jurisdiction over some of OG&E's facilities and operations.
For the year ended December 31, 1994, approximately 89 percent of
OG&E's electric revenue was subject to the jurisdiction of the OCC, seven
percent to the APSC, and four percent to the FERC.
RECENT REGULATORY MATTERS: On February 25, 1994, the OCC issued an
--------------------------
order that, among other things, effectively lowered OG&E's rates to its
Oklahoma retail customers by approximately $17 million annually and required
OG&E to refund approximately $41.3 million. Of the $41.3 million refund, $39.1
million is associated with revenues prior to January 1, 1994, while the
remaining $2.2 million related to 1994.
Enogex transports natural gas to OG&E for use at its gas-fired
generating units and performs related gas gathering activities for OG&E. The
entire $41.3 million refund related to the OCC's disallowance of a portion of
the fees paid by OG&E to Enogex for such services in the past. Of the
approximately $17 million annual rate reduction, approximately $9.9 million
reflects the OCC's reduction of the amount to be recovered by OG&E from its
Oklahoma customers for the future performance of such services by Enogex for
OG&E. In accordance with the OCC's rate order and a stipulation approved by
the OCC in July 1991, OG&E's electric rates are designed to permit OG&E to earn
a 12 percent regulatory return on equity and the OCC staff is precluded from
initiating an investigation of OG&E's rates for three years from February 25,
1994, unless OG&E's regulatory return on equity exceeds 12.75 percent.
In 1994, the Company underwent a significant restructuring effort and
redesign of its operations to more favorably position itself for the
competitive electric utility environment. The Company incurred $63.4 million
of restructuring costs in 1994. Pending an OCC order, OG&E deferred the costs
associated with a VERP and severance package in the third quarter of 1994.
Between August 1, and December 31, 1994, the
6
<PAGE> 9
amount deferred was reduced by approximately $14.5 million. In response to an
application filed by OG&E on August 9, 1994, the OCC issued an order on October
26, 1994, that permitted OG&E to amortize the December 31, 1994, regulatory
asset of $48.9 million over 26 months and reduced OG&E's electric rates by
approximately $15 million annually, effective January 1995. Management
anticipates that labor savings from the VERP and severance package will
substantially offset the amortization of the regulatory asset and annual rate
reduction of $15 million. Labor savings in 1994 approximated the amortization
of the deferred amount and therefore, did not significantly impact 1994
results. However, approximately $6.5 million in other restructuring expenses
reduced 1994 earnings by $0.10 per share. At December 31, 1994, the deferred
amount was $48.9 million, which is included on the Consolidated Balance Sheets
as Deferred Charges - Other.
Pursuant to an order from the APSC in July 1992, OG&E and other
electric utilities serving customers in Arkansas were required to submit
20-year Integrated Resource Plans with the APSC. The IRP process required the
utilities to document their plans for serving their customers' electric energy
needs, taking into account the full range of alternatives, including new
generating capacity, purchased power, energy conservation and efficiency,
cogeneration and renewable energy sources, in order to provide adequate and
reliable service to their electric customers at the lowest system cost. On
October 5, 1994, the APSC issued an Order initiating a Notice of Inquiry with
respect to integrated resource planning and energy efficiency investments in
power generation and supply for electric utilities, and suspending proceedings
in OG&E's IRP Docket until further notice. In essence, the APSC Order stated
that before the APSC proceeds further with the pending dockets on IRP,
including OG&E's, the ASPC should look more closely at the relationship between
the Federal IRP standard and the "...changes occurring in the electric utility
industry..." particularly with respect to competition. Because of the changing
utility industry, the APSC has determined it should examine more closely
whether IRP is appropriate given the movement of the industry away from
regulation.
On October 5, 1994, the OCC issued an order instructing the OCC staff
of the Public Utility Division ("PUD") to move forward with the development of
OCC rules to implement the mandates of Sections 111 and 115 of the National
Energy Policy Act of 1992, requiring OG&E and other electric utilities to each
submit 20-year IRPs. The order instructs OCC staff to carry out this
development through a collaborative process involving all affected parties.
The completion date is scheduled for mid-to late 1995.
AUTOMATIC FUEL ADJUSTMENT CLAUSES: Variances in the actual cost of
----------------------------------
fuel used in electric generation and certain purchased power costs, as compared
to that component in estimated cost-of-service for ratemaking, are charged to
substantially all of the Company's electric customers through automatic fuel
adjustment clauses, which are subject to periodic review by the OCC, the APSC
and the FERC.
NATIONAL ENERGY LEGISLATION: The National Energy Act of 1978 imposes
----------------------------
numerous responsibilities and requirements on OG&E. PURPA requires electric
utilities, such as OG&E, to purchase electric power from, and sell electric
power to, QFs and small power production facilities. Generally stated,
electric utilities must purchase electric energy and production capacity made
available by QFs and small power producers at a rate reflecting the cost that
the purchasing utility can avoid as a result of obtaining energy and production
capacity from these sources; rather than generating an equivalent amount of
energy itself or purchasing the energy or capacity from other suppliers. OG&E
has entered into agreements with four such cogenerators.
7
<PAGE> 10
See "Finance and Construction." Electric utilities also must furnish electric
energy to QFs on a non-discriminatory basis at a rate that is just and
reasonable and in the public interest and must provide certain types of service
which may be requested by QFs to supplement or back up those facilities' own
generation.
The National Energy Policy Act of 1992 ("Energy Act") is expected to
make some significant changes in the operations of the electric utility
industry and the federal policies governing the generation and sale of electric
power. The Energy Act, among other things, allows the FERC to order utilities
to permit access to their electrical transmission systems and to transmit power
produced by independent power producers at transmission rates set by the FERC.
The Energy Act also provides funds to study electric vehicle technology, the
effects of electric and magnetic fields, and institutes a tax credit for
generating electricity using renewable energy sources. The Energy Act also is
designed to promote competition in the development of wholesale power
generation in the electric industry. It exempts a new class of independent
power producers from regulation under the Public Utility Holding Company Act of
1935 and allows the FERC to order "wholesale wheeling" by public utilities to
provide utility and non-utility generators access to public utility
transmission facilities. Also, numerous states are considering proposals to
require "retail wheeling". The Energy Act, these proposals and other factors
are expected to significantly increase competition in the electric industry.
The Company has taken steps in the past and intends to take appropriate steps
in the future to remain a competitive supplier of electricity. Past actions
include the redesign and restructuring effort in 1994 and the actions to reduce
fuel costs, both of which have resulted in lower retail rates, especially for
industrial customers. In 1995, the Company intends to make a transmission open
access filing before the FERC, in compliance with the Energy Act, and the
Company intends to implement Real Time Pricing for a pilot group of its retail
customers. See "Rate Structure, Load Growth and Related Matters."
RATE STRUCTURE, LOAD GROWTH
AND RELATED MATTERS
Two of OG&E's primary goals in its electric tariff designs are: (i)
to increase electric revenues by attracting and expanding job-producing
businesses and industries; and (ii) to encourage the efficient use of energy by
all of its customers. In order to meet these goals, OG&E has reduced and
restructured its rates to its key customers while at the same time implementing
numerous energy efficiency programs and tariff schedules. These programs and
schedules include: (i) residential energy audits promoting efficient energy
use, and assistance programs that help residential customers live in
comfortable homes with lower energy costs; (ii) the PEAKS program, which
provides credit on a customer's bill for the installation of a device that
periodically cycles off the customer's central air conditioner during peak
summer periods; (iii) a load curtailment rate for industrial and commercial
customers who can demonstrate a load curtailment of at least 300 kilowatts;
(iv) time-of-use rate schedules for various commercial, industrial and
residential customers designed to shift energy usage from peak demand periods
during the hot summer afternoons to non-peak hours; and (v) a thermal energy
storage program that promotes the shifting of cooling loads to off-peak hours.
In 1994, OG&E's marketing efforts included thermal storage,
electrotechnologies, an electric food service promotion and a heat pump
promotion in the residential, commercial and industrial markets. Educating
customers to use available time-of-use rates to lower their energy costs was
also pursued. These rates can make commercial and industrial heating and
cooling especially economical if power is used with thermal storage systems
which chill water at night for cooling the next day.
8
<PAGE> 11
To meet customers' electric power needs for their sensitive electronic
equipment, OG&E began the Power Quality program several years ago. Through
this program, a trained Power Quality team works with the customer by
performing a thorough survey of wiring and grounding, transient surge
protection checks and power monitoring. The customer and the team then develop
solutions and alternatives to power needs at the facility.
OG&E continues studying programs such as Real Time Pricing to keep its
electric tariffs attractive and to control peak demand growth. Real Time
Pricing is a service option which prices electricity so that current price
varies hourly with short notice to reflect current expected cost. The
technique will allow a measure of competitive pricing, a broadening of customer
choice, balancing of electricity usage and capacity in the short and long term,
and help customers to control their costs. OG&E will implement a pilot program
in 1995 with some industrial customers.
Other programs include the use of high efficiency lighting and
ballasts, high efficiency motors, high efficiency air conditioners or chillers,
use of home automation systems, high-tech refrigeration equipment, adjustable
speed drives on electric motors, high-tech electric water heating systems,
heating and cooling demand controls and time scheduling of electric appliances,
such as water heaters. OG&E has also expanded its Positive Energy Home finance
programs for customers to include heat pump water heaters and ground source
heat pumps.
OG&E currently does not anticipate the need for new baseload
generating plants in the foreseeable future. For further discussion, see
"Finance and Construction."
FUEL SUPPLY
During 1994, approximately 28 percent of the OG&E-generated energy was
produced by natural gas-fired units and 72 percent by coal-fired units. It is
estimated that the fuel mix for 1995 through 1999, based upon expected
generation for these years, will be as follows:
<TABLE>
<CAPTION>
1995 1996 1997 1998 1999
-------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Natural Gas 18% 22% 24% 26% 28%
Coal 82% 78% 76% 74% 72%
</TABLE>
The average cost of fuel used, by type, per million Btu for each of
the 5 years was as follows:
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Natural Gas $3.58 $3.64 $3.48 $3.14 $3.06
Coal $0.78 $1.16 $1.18 $1.21 $1.38
Weighted Avg $1.58 $1.92 $1.88 $1.96 $2.08
</TABLE>
A portion of the fuel cost is included in base rates and differs for
each jurisdiction. The portion of these costs that is not included in base
rates is recovered through automatic fuel adjustment clauses. See "Regulation
and Rates, Automatic Fuel Adjustment Clauses."
GAS-FIRED UNITS: OG&E has approximately 740 natural gas purchase
----------------
contracts covering approximately 430 wells and delivery points. These
contracts cover an estimated 153 billion cubic feet of connected reserves.
9
<PAGE> 12
OG&E acquires some natural gas at the wellhead under purchase
contracts which contain provisions allowing the owners to require prepayments
for gas if certain minimum quantities are not taken (see Note 9 of Notes to
Consolidated Financial Statements). At December 31, 1994, outstanding
prepayments for gas, including the amounts classified as current assets, under
these contracts were approximately $10.9 million (including $10 million accrued
but not yet paid). A contract with Oklahoma Natural Gas Company for additional
peaking gas is renewed yearly. The need for this peaking gas contract will be
eliminated as soon as an 8.0 BCF gas storage facility becomes fully
operational.
In 1993, OG&E began utilizing a natural gas storage facility which
helps OG&E lower fuel costs and receive greater value from its remaining
take-or-pay gas contracts. By diverting natural gas into storage, OG&E is able
to use as much coal as possible to generate electricity, and use gas from
storage when needed to meet increases in demand for electricity. In 1995, gas
storage will give OG&E the flexibility to generate about 82 percent of its
electricity with coal, the highest percentage in OG&E's history. This fuel mix
change, along with fuel price reductions will allow OG&E to reduce its fuel
costs in 1995 by an estimated $37 million compared to 1994.
COAL-FIRED UNITS: All of OG&E coal units, with an aggregate capacity
-----------------
of 3,045 megawatts, are designed to burn low-sulfur western coal. OG&E
purchases coal under a mix of long and short-term contracts. OG&E currently has
a long-term, multiple option agreement with Atlantic Richfield Company to
supply coal for these units. The combination of all coal has an average sulfur
content of 0.4 percent and can be burned in these units under existing federal,
state and local environmental standards (maximum of 1.2 pounds of sulfur
dioxide per million Btu) without the addition of sulfur dioxide removal
systems.
During 1994, OG&E burned a total of 8.1 million tons of coal. Based
upon the average sulfur content of Wyoming coal, OG&E's units have an
approximate emission rate of 0.78 pounds of sulfur dioxide per million Btu.
See related discussion in "Environmental Matters." In 1993, OG&E negotiated
new rail transportation contracts for coal beginning in 1994, which resulted in
lower transportation rates.
The Wyoming coal is transported to OG&E's generating stations, a
distance of about 1,000 miles, by unit trains. In 1994, OG&E leased 1,930 coal
cars, of which 1,367 were aluminum, at an approximate annual rental cost of
$5.6 million. The efficiencies related to this newer design of high volume
aluminum body railcar have reduced, by approximately six percent, the number
of trips from Wyoming and reduced railcar maintenance expenses. On July 1,
1994, the lease expired on 426 steel railcars and they were returned to the
lessor.
ENVIRONMENTAL MATTERS
OG&E management believes all of its operations are in substantial
compliance with present federal, state and local environmental standards. It
is estimated that the Company's expenditures for capital, operating,
maintenance and other costs to preserve and enhance environmental quality will
be approximately $46 million during 1995, compared to approximately $47 million
in 1994. OG&E is continually evaluating its environmental programs to ensure
compliance with existing and proposed environmental legislation and regulations
and to position itself in a competitive market.
10
<PAGE> 13
The Company continues to explore options to comply with the Clean Air
Act Amendments of 1990 ("CAAA"). Since all of OG&E's coal-fired generating
units currently burn low-sulfur coal, OG&E will not need to take any steps to
comply with the new sulfur dioxide emission limits until January 1, 2000. In
compliance with Title IV of the CAAA, the Company has completed installation of
continuous emission monitors ("CEMs") on each of its five coal-fired generating
units and three of its 12 gas-fired generating units. Expenditures on CEMs in
1994 totalled approximately $6 million. The Environmental Protection Agency
("EPA") established a time extension for installation of CEMs on gas-fired
units which allowed the Company to defer CEM installation on the remaining nine
units subject to the requirements of Title IV. Completion of this project is
expected to cost approximately $1 million during 1995. The CAAA Title V
operating permits are expected to cost approximately $400,000 in 1995.
The CAAA will also regulate emissions of nitrogen oxides and certain
air toxic compounds. Although final regulations concerning all of these issues
have not been written, additional capital expenditures may be necessary in
future years. The Company will continue to examine all alternatives to comply
with the CAAA as part of its Integrated Resource Planning process. This
planning approach will assure that the Company employs the least cost option to
comply with the CAAA and be in a competitive position to market its services.
During 1992, OG&E disclosed to the EPA discrepancies in the 1991
annual report required by the Toxic Substance Control Act ("TSCA"). These
discrepancies were administrative in nature and presented no harm to the
environment and presented no health problems to our Company members or the
public. However, the Company has instituted specific systems and measures to
correct each of the reported discrepancies. On December 15, 1994, the Company
was notified by the EPA that the EPA had commenced reviewing the matter, and a
response from the EPA may be forthcoming in 1995. No actions were taken by the
EPA on this matter during 1994. See "Item 3. Legal Proceedings" for additional
discussion of this matter.
The Company remains a party to three separate actions brought by the
EPA concerning cleanup of disposal sites for hazardous waste and is involved in
three other matters with the EPA. See "Item 3. Legal Proceedings."
ENOGEX
OG&E's wholly-owned non-utility subsidiary, Enogex Inc., is the 37th
largest pipeline in the nation in terms of miles of pipeline. Enogex Inc.'s
primary operations consist of transporting natural gas through its intra-state
pipeline to various customers (including OG&E), buying and selling natural gas
to third parties, selling natural gas liquids extracted by its natural gas
processing plants and investing in natural gas exploration and production
activities. At December 31, 1994, Enogex Inc. had five wholly-owned
subsidiaries, Enogex Products Corporation ("Products"), Enogex Services
Corporation ("Services"), Enogex Exploration Corporation ("Exploration"), ENGL
Corporation ("ENGL"), and Clinton Gas Transmission, Inc. ("Clinton"). Enogex
also owns an 80% interest in Centoma Gas Systems, Inc. ("Centoma"). Products
owns interests in and operates three natural gas processing plants and marketed
natural gas liquids through the end of 1994. Exploration is engaged in
investing in the exploration and production of oil and natural gas and the
purchase of oil and gas reserves. ENGL owns and operates a natural gas
processing plant and marketed the natural gas liquids through the end of 1994.
Services and Clinton are engaged in the marketing (buying and selling) of
natural gas and beginning in 1995, Services will also market natural gas
liquids of Products and ENGL. Centoma both purchases and gathers gas for
subsequent processing at one of three processing plants, two of which are owned
by Products. The residue gas is then sold under a combination of contract and
spot market prices.
11
<PAGE> 14
For the year ended December 31, 1994, and before elimination of
intercompany items between OG&E and Enogex, Enogex's consolidated revenues and
net income were approximately $203.1 million and $10.0 million, respectively,
as indicated in the following table:
<TABLE>
<CAPTION>
(dollars in millions) 1994 Revenues 1994 Net Income
----------------------------------------------------------------
<S> <C> <C>
Enogex Inc. $ 57.7 $10.0 (a)
Products 18.7 2.8
Services 107.7 0.7
Exploration 5.3 3.2
ENGL 5.7 0.3
Clinton 17.6 0.1
Centoma 3.5 0.0
Eliminations within Enogex (13.1) (b) (7.1)
------ -----
Enogex consolidated amounts $203.1 $10.0
====== =====
</TABLE>
(a) Includes $7.1 million of net income from Products, Services, Exploration,
ENGL, Clinton and Centoma.
(b) Consists of intercompany natural gas transmission fees of $1.8 million and
sales of natural gas products amounting to $11.3 million.
Enogex's natural gas transportation business in Oklahoma consists
primarily of gathering and transporting natural gas for OG&E and on an
interruptible basis, third-party-owned gas. Enogex's system consists of over
3,000 miles of pipeline, which extends from the Arkoma Basin in eastern
Oklahoma to the Anadarko Basin in western Oklahoma. Since 1960, Enogex has had
a gas transmission contract with OG&E under which Enogex transports OG&E's
natural gas supply on a fee basis. Enogex also provides accounting services
and assists in payments to producers and suppliers under the contract. Under
the gas transmission contract, OG&E agrees to tender to Enogex and Enogex
agrees to transport, on a firm, load-following basis, all of OG&E's natural gas
requirements for boiler fuel for its seven gas-fired electric generating
stations. In 1994, Enogex transported 132 Bcf of natural gas; of which
approximately 61 Bcf, or about 46 percent, was delivered to OG&E's electric
generating stations and storage facility, which resulted in approximately 78
percent of Enogex Inc.'s revenue of $57.7 million for 1994. See "Regulation
and Rates."
Enogex's pipeline system also gathers and transports natural gas
destined for interstate markets through interconnections in Oklahoma with other
pipeline companies. Among others, these interconnections include Panhandle
Eastern Pipeline, Williams Natural Gas Pipeline, Natural Gas Pipeline Company
of America, Northern Natural Gas Company, Arkla Energy Resources, Phillips
Seagas Pipeline, ANR Pipeline Company and Ozark Gas Transmission Company.
The rates charged by Enogex for transporting natural gas on behalf of
an interstate natural gas pipeline company or a local distribution company
served by an interstate natural gas pipeline company are subject to the
jurisdiction of FERC under Section 311 of the Natural Gas Policy Act. The
statute entitles Enogex to charge a "fair and equitable" rate that is subject
to review and approval by FERC. This rate review may involve an
administrative-type trial and an administrative appellate review. In addition,
Enogex has agreed to open its system to all interstate shippers that are
interested in moving natural gas through the Enogex system. Enogex is required
to conduct this transportation on a non-discriminatory basis, although this
transportation is subordinate to that performed for OG&E. This decision does
not increase appreciably the federal regulatory burden on Enogex, but does give
Enogex the opportunity to utilize any unused capacity on an interruptible basis
and thus increase its transportation revenues.
12
<PAGE> 15
The fees charged by Enogex for transporting natural gas for OG&E and
other intrastate shippers are not subject to FERC regulation. With respect to
state regulation, the fees charged by Enogex for any intrastate transportation
service have not been subject to direct state regulation by the OCC. Even
though the intrastate pipeline business of Enogex is not directly regulated,
the OCC, the APSC and the FERC have the authority to examine the
appropriateness of any transportation charge or other fees paid by OG&E to
Enogex, which OG&E seeks to recover from ratepayers. See "Regulation and
Rates" for a further discussion of this matter and the OCC's ruling on the fees
paid by OG&E to Enogex.
Products has been active since 1968 in the processing of natural gas
and marketing of natural gas liquids. Products has a 50 percent interest in
and operates a natural gas processing plant near Calumet, Oklahoma, which can
process 250 Mmcf of natural gas per day. Products also owns two other
natural gas processing plants in Oklahoma, which have, in the aggregate, the
capacity to process approximately 23 Mmcf of natural gas per day. ENGL owns
one natural gas processing plant in Oklahoma, which has the capacity to process
approximately 18 Mmcf of natural gas per day. Products' natural gas
processing plant operations consist of off-lease extraction of liquids from
natural gas that is transported through the Enogex pipeline, while ENGL's
natural gas processing operations consists of off-lease extraction of liquids
from an unaffiliated pipeline. The raw gas stream is processed and converted
into marketable ethane, propane, butane, and natural gasoline mix. The residue
gas remaining after the liquid products have been extracted consists primarily
of methane.
Commercial grade propane is sold on the local market and the marketing
of all other natural gas liquids extracted by Products and ENGL was handled
through independent brokers. Beginning in 1995, the natural gas liquids will
be marketed by Services. The natural gas liquids are delivered to Conway,
Kansas (which is one of the nation's largest wholesale markets for gas
liquids), where they are sold on the spot market, commonly referred to as Group
140.
In processing and marketing natural gas liquids, the Enogex companies
compete against virtually all other gas processors selling natural gas liquids.
The Enogex companies believe they will be able to continue to compete favorably
against such companies. With respect to factors affecting the natural gas
liquids industry generally, as the price of natural gas liquids fall without a
corresponding decrease in the price of natural gas, it may become uneconomical
to extract certain natural gas liquids. As to factors affecting the Enogex
companies specifically, the volume of natural gas processed at their plants is
dependent upon the volume of natural gas transported through the pipeline
system located "behind the plants" (i.e. the Enogex pipeline for Products and
an unaffiliated pipeline for ENGL). If the volume of natural gas transported
by such pipeline increases "behind the plants," then the volume of liquids
extracted by Products and ENGL should normally increase.
Services is a natural gas and natural gas liquids marketing company
serving both producers and consumers of natural gas by buying natural gas at
the wellhead and from other sources in Oklahoma and other states, and reselling
the gas to local distribution companies, utilities other than OG&E and
industrial purchasers both within and outside Oklahoma. It also serves
Products and ENGL by purchasing and marketing the natural gas liquids they
produce.
Although the margin on gas sales by Services is relatively small,
approximately 50 percent of the natural gas purchased and resold is transported
through the Enogex Inc. pipeline to one or more interstate pipelines that
deliver the gas to markets. Thus, in addition to purchasing and selling
natural gas, Services seeks to use the space available in the Enogex Inc.
pipeline and increase the amount of natural gas available for processing by
Products. Clinton is engaged in essentially the same business as Services.
13
<PAGE> 16
Enogex Inc. is committed to continue the activities of Services in
order to increase the amount of natural gas transported through the pipeline
and the amount of natural gas processed by Products.
In its marketing and transportation services for third parties, Enogex
Inc., Services and Clinton encounter competition from other natural gas
transporters and marketers and from available alternative energy sources. The
effect of competition from alternative energy sources is dependent upon the
availability and cost of competing supply sources.
Volumes of natural gas transported by Enogex Inc. for third parties
and the revenues derived from such activities increased from 1993. The
contributing factors for the increase were specific projects implemented to
strengthen Enogex's position, with other similar projects under consideration.
Services and Clinton compete with all major suppliers of natural gas
and natural gas liquids in the geographic markets they serve. For natural gas,
those geographic markets are primarily the areas served by pipelines with which
Enogex is interconnected. Although the price of the gas is an important factor
to a buyer of natural gas from Services, the primary factor is the total cost
(including transportation fees) that the buyer must pay. Natural gas
transported for Services by Enogex Inc. is billed at the same rate Enogex Inc.
charges for comparable third-party transportation. Exploration was formed in
1988 primarily to engage in the exploration and production of natural gas.
Exploration has focused its drilling activity in the Antrim Devonian shale
trend in the state of Michigan and also has interests in Oklahoma. As of
December 31, 1994, Exploration had interests in 273 active wells and total
assets, including such interests, of approximately $38 million.
14
<PAGE> 17
ITEM 2. PROPERTIES.
-------------------
OG&E owns and operates an interconnected electric production,
transmission and distribution system, located in Oklahoma and western Arkansas,
which includes eight active generating stations with an aggregate active
capability of 5,637 megawatts. The following table sets forth information with
respect to present electric generating facilities:
<TABLE>
<CAPTION>
Unit Station
Year Capability Capability
Station & Unit Fuel Installed (Megawatts) (Megawatts)
-------------- ---- --------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Seminole 1 Gas 1971 549
2 Gas 1973 507
3 Gas 1975 500 1,556
Muskogee 3 Gas 1956 184
4 Coal 1977 500
5 Coal 1978 500
6 Coal 1984 515 1,699
Sooner 1 Coal 1979 505
2 Coal 1980 510 1,015
Horseshoe 6 Gas 1958 178
Lake 7 Gas 1963 238
8 Gas 1969 394 810
Mustang 1 Gas 1950 58 Inactive
2 Gas 1951 57 Inactive
3 Gas 1955 122
4 Gas 1959 260
5 Gas 1971 64 446
Conoco 1 Gas 1991 26
2 Gas 1991 26 52
Arbuckle 1 Gas 1953 74 Inactive
Enid 1 Gas 1965 12
2 Gas 1965 12
3 Gas 1965 12
4 Gas 1965 12 48
Woodward 1 Gas 1963 11 11
-----
Total Active Generating Capability (all stations) 5,637
=====
</TABLE>
At December 31, 1994, OG&E's transmission system included 71
substations with a total capacity of approximately 17.2 million kVA and
approximately 4,283 structure miles of lines. The distribution system included
338 substations with a total capacity of approximately 6.1 million kVA, 21,113
structure miles of overhead lines, 1,626 miles of underground conduit and 6,394
miles of underground conductor.
15
<PAGE> 18
Substantially all of OG&E's electric facilities are subject to a
direct first mortgage lien under the Trust Indenture securing OG&E's first
mortgage bonds.
Enogex owns: (1) over 3,000 miles of natural gas pipeline extending
from the Arkoma Basin in eastern Oklahoma to the Anadarko Basin in western
Oklahoma; (2) a 50 percent interest in a natural gas processing plant near
Calumet, Oklahoma, which has the capacity to process 250 Mmcf of natural gas
per day; (3) three other natural gas processing plants in Oklahoma, which have,
in the aggregate, the capacity to process approximately 41 Mmcf of natural gas
per day; and (4) an 80 percent interest in approximately 110 miles of gas
gathering pipeline owned by Centoma.
During the three years ended December 31, 1994, the Company's gross
property, plant and equipment additions approximated $405 million and gross
retirements approximated $67 million. Over 95 percent of these additions were
provided by internally generated funds. The additions during this three-year
period amounted to approximately 10.6 percent of total property, plant and
equipment at December 31, 1994.
ITEM 3. LEGAL PROCEEDINGS.
--------------------------
1. Puritan Oil and Gas Corp., and other Plaintiffs, filed an
amendment to a petition on February 19, 1993, to an action previously filed in
the District Court of Oklahoma County, involving an alleged breach of oil and
gas contract by OG&E. This case was removed to the United States District
Court for the Western District of Oklahoma. Enogex Inc. was also joined as a
Defendant in the action. Plaintiffs allege that OG&E and Enogex were in
violation of the Federal Racket Influenced and Corrupt Act ("RICO"). OG&E
filed its Motion to Dismiss the RICO claim on March 26, 1993. Plaintiffs
allege the Defendants refused to honor contractual obligations in certain gas
purchase contracts. The underlying dispute on the gas purchase contracts
arises in the ordinary course of OG&E's business and involves whether OG&E must
purchase gas thereunder, where the contract provides for certain requirements
to be maintained by the well. Actual damages under the RICO claim are sought
in an amount of $2,000,000. RICO provides that these damages be trebled in the
event of an adverse verdict. Punitive damages under the RICO claim are also
sought in the amount of $1,000,000.
On January 4, 1994, the United States District Court for the Western
District of Oklahoma entered its Order and dismissed Plaintiffs' RICO claim as
well as Plaintiffs' claim for punitive damages under RICO. On January 14,
1994, Plaintiffs filed a Motion to Alter or Amend Judgment seeking leave of
Court to file its Amended Complaint asserting different allegations under RICO.
On January 31, 1994, the Court denied Plaintiffs' motion.
Plaintiffs filed their Appeal with the United States Court of Appeals
for the 10th Circuit. In addition, the United States District for the Western
District of Oklahoma remanded the breach of contract claim to the District
Court of Oklahoma County, Oklahoma. By Order filed January 11, 1995, the Court
dismissed the appeal pursuant to a stipulation of the parties. The RICO case
is now dismissed.
Management believes the outcome of this proceeding will not have a
material adverse effect on the Company's consolidated financial position or its
results of operations for numerous reasons, which include that the underlying
dispute between the parties is a contractual dispute under a gas purchase
contract. Management intends to vigorously pursue the defense of this matter.
16
<PAGE> 19
2. On July 8, 1994, an employee of OG&E filed a lawsuit in state
court against OG&E in connection with OG&E's voluntary early retirement
package. The case has been removed to the U.S. District Court in Tulsa,
Oklahoma. The lawsuit purports to be a class action and alleges violation of
Title VII, ERISA, intentional infliction of emotional distress and other
issues.
On August 23, 1994, the trial court sustained OG&E's Motion to Dismiss
Plaintiffs' Complaint, in its entirety. On September 12, 1994, Plaintiffs
filed an Amended Complaint alleging substantially the same allegations which
were in the original Complaint. On October 10, 1994, Defendants filed a Motion
to Dismiss Counts II, IV, V, VI and VII of Plaintiffs Amended Complaint and
filed responsive pleadings to Counts I and III. With regard to those two
Counts, additional investigation will be required to determine whether or not
Plaintiffs can successfully pursue those claims. While the Company cannot
predict the precise outcome of the proceeding, the Company continues to believe
that the lawsuit is without merit and will not have a material adverse effect
on its consolidated results of operations or financial condition.
3. On June 30, l986, the United States government filed suit
against OG&E and 36 other defendants in case number CIV-86-l40l W, in the
United States District Court ("USDC") for the Western District of Oklahoma.
The Complaint generally alleged that a total of l8 million gallons of hazardous
and toxic waste were contained at the Hardage Criner site located approximately
30 miles south of Oklahoma City, and that the government had expended, as of
the date of the filing of the Complaint, $l.44 million related to the site.
The 37 defendants are divided into three classes: 33 "generator" defendants, of
which the Company is one; three "transporter" defendants; and the owner of the
site, Mr. Royal Hardage.
It is estimated that over 200 other entities, not named in the
government's Complaint, also disposed of materials at the site. OG&E disposed
of an estimated 130,000 gallons at the site, or less than 1 percent of the
total volume of waste. OG&E, along with each other Potentially Responsible
Party ("PRP"), could be held jointly and severally liable for the remediation
of the site. In August 1990, the USDC issued its rulings on the appropriate
method for cleanup of the site. The USDC selected the containment remedy
proposed by the Hardage Criner Steering Committee Defendants (the "Committee"),
of which OG&E is a member, with several modifications. The remedy ordered by
the USDC was estimated to cost approximately $60 million.
The design and construction of the remedy is 99% complete. On
December 1, 1994, a tour of the remedy facilities was conducted; present were
representatives of PRPs, EPA and the State agencies.
Settlements have been reached with numerous parties that were not
members of the Committee for their share of costs incurred. The money
collected through these settlements is being used to finance the remedy and to
reimburse the government for response costs.
Even though the settlement funds, plus interest and the United States
contribution will raise a substantial portion of the monies required, any
remaining amounts that OG&E and the other Committee members are likely to pay
may still be substantial due to maintenance of the remedy over time.
The Committee members have reached an Agreement to pay the on-going
maintenance costs based on each company's respective volume of waste sent to
the site. OG&E's share of the total is 2.33 percent, or approximately $1.4
million.
While it is not possible to determine the precise outcome of this
matter, in the opinion of management, OG&E's ultimate liability for the cleanup
costs of this site will not have a material adverse effect on OG&E's financial
position or its results of operations. Management's opinion is based on the
following: (1) the cleanup
17
<PAGE> 20
costs already paid by certain parties; (2) the financial viability of the other
PRPs; (3) the portion of the total waste disposed at this site attributable to
OG&E; and (4) the remedy construction is substantially complete. Management
also believes that costs incurred in connection with this site, which are not
recovered from insurance carriers or other parties, may be allowable costs for
future ratemaking purposes.
4. OG&E is also involved, along with numerous other PRPs, in an
EPA administrative action involving the facility in Holden, Missouri, of Martha
C. Rose Chemicals, Inc. ("Rose"). Beginning in early 1983 through 1986, Rose
was engaged in the business of brokering of polychlorinated biphenyls ("PCBs")
and PCB items, processing of PCB capacitors and transformers for disposal, and
decontamination of mineral oil dielectric fluids containing PCBs. During this
time period, various generators of PCBs ("Generators"), including OG&E, shipped
materials containing PCBs to the facility. Contrary to its contractual
obligation with OG&E and other Generators, it appears that Rose failed to
manage, handle and dispose of the PCBs and the PCB items in accordance with the
applicable law. Rose has been issued citations by both the EPA and the
Occupational Safety and Health Administration. OG&E, along with the other
PRPs, could be held jointly and severally liable for the remediation of the
site.
In March 1986, Rose abandoned its facility in Holden, Missouri, and
subsequently notified certain Generators of its unwillingness and/or inability
to come into compliance with the PCB rules and regulations and to properly
dispose of such PCBs and PCB items at the facility. In addition to PCBs and
PCB items at the Rose facility, the EPA believes that contaminated soils,
sediments and/or sludge may be present off-site.
Several Generators, including OG&E, formed a Steering Committee to
investigate and possibly clean up the Rose facility. Currently, OG&E
management's estimate of the total cost for cleanup of the Rose facility is in
the range of $23 to $31 million, of which $18.5 million has already been
collected from certain parties.
The Company estimates its share of the total hazardous wastes at the
Rose facility to be less than six percent. A Settlement Agreement between
AEGIS Insurance Company and OG&E was reached in 1994. Although the Company
cannot predict the precise outcome of this matter, management believes that
OG&E's ultimate liability for the cleanup costs of this site will not have a
material adverse effect on OG&E's financial position or its results of
operations. Management's opinion is based on the following: (1) the cleanup
costs already paid by certain parties; (2) the financial viability of the other
PRPs; (3) the portion of the total waste disposed at this site attributable to
OG&E and (4) the Company's settlement agreement with its insurer. Management
also believes that costs incurred in connection with this site, which are not
recovered from insurance carriers or other parties, may be allowable costs for
future ratemaking purposes.
5. During the Third Quarter of 1992 OG&E began a voluntary review
of information contained in the 1991 annual report required under the Toxic
Substance Control Act ("TSCA"). The initial result of the review revealed some
discrepancies in operating practices and documentation.
EPA, Region VI, was notified of these initial discrepancies in
December, 1992. Because it suspected that additional discrepancies might be
discovered during the continuing review/audit, OG&E reached an agreement on
January 12, 1993, with the EPA, Region VI, concerning the notification and
reporting requirements of any newly discovered discrepancies.
After further investigation, OG&E reported in September 1993 numerous
additional discrepancies to the EPA, Region VI. Many of the discrepancies
could be deemed violations of the regulations under TSCA. The discrepancies
principally concerned the TSCA regulations relating to PCB handling and record
keeping
18
<PAGE> 21
requirements. However, to the Company's knowledge, none of the activities
involved releases of materials into the environment or caused harm to any
individuals. Under the TSCA regulations, the EPA has the authority to assess a
maximum fine of up to $25,000 per day, and to treat each day of violation as
the basis for a separate fine. OG&E has taken and is taking corrective action
to remedy the discrepancies.
The position of EPA and OG&E is that they are currently in
pre-settlement negotiations. No fines have been assessed as of this date.
Since this matter is currently being negotiated, OG&E does not know the amount
of fines that the EPA may seek. The amount of the fine is dependent upon
numerous interpretative issues under the TSCA regulations and potentially could
be in an amount significant to the Company's results of operations. However,
at the present time, the Company does not expect that the amount of the fine
will have a material adverse effect on its consolidated financial position or
its results of operations based primarily on having voluntarily reported the
discrepancies to the EPA coupled with the Company's efforts to remedy the
discrepancies and the lack of releases into the environment or harm to
individuals. On December 15, 1994, the Company was notified by the EPA that
the EPA had commenced reviewing the matter, and a response from the EPA may be
forthcoming in 1995.
6. On January 11, 1993, OG&E received a Section 107 (a) Notice
Letter from the EPA, Region VI, as authorized by the CERCLA, 42 USC Section
9607 (a), concerning the Double Eagle Refinery Superfund Site located at 1900
NE First Street in Oklahoma City, Oklahoma. The EPA has named OG&E and 45
others as PRPs. Each PRP could be held jointly and severally liable for
remediation of this site.
The Notice of Letter, a formal demand for reimbursement of past and
future incurred costs (past costs are approximately $1.3 million), provided for
a negotiation period of 60 days and encouraged the PRPs to perform or finance
the response activities as set forth in the Record of Decision ("ROD") and the
Draft Statement of Work ("SOW").
The ROD addresses the source of contamination both on and off the site
and is divided into two operable units: 1) Source Control Operable Unit, the
remedy of which is addressed with the SOW and has an estimated cost of $6.4
million; and 2) Groundwater Operable Unit, which is still being evaluated to
assess the extent of contamination in the groundwater and any plumes. The cost
of remediation for this Unit cannot be estimated at this time.
As to the Source Control Operable Unit and as a result of the EPA's
Notice Letter, companies listed as PRPs (including OG&E) held several meetings
to determine whether or not they should form a Steering Committee, whether
additional research into volumetric shares should be conducted and a response,
if any, to be sent to the EPA. Several but not all of the 46 companies have
signed a very limited Participation Agreement, the purpose of which is to
negotiate with the EPA.
On March 31, 1993, OG&E joined with the signatories to the limited
Participation Agreement in making a settlement offer to the EPA.
The EPA met with representatives of the PRPs group on June 11, 1993,
to discuss the current developments taking place. The EPA is currently
considering a modification of the remedy for the Source Control Operable Unit
because the remedy was apparently selected without giving consideration to the
19
<PAGE> 22
presence of listed hazardous waste, although the presence of this waste was
documented in the Record of Decision. The EPA explained at the meeting that it
will likely not make a decision in the near future concerning the remedy for
the Source Control Operable Unit. The EPA informed the participating PRPs that
it would not pursue them through the issuance of a unilateral administrative
order relating to the Special Notice Letters.
As to the Groundwater Operable Unit, OG&E declined to either
participate in conducting or financing any remedial activities. No further
action on the Groundwater Operable Unit has been taken by the EPA.
On February 1, 1994, OG&E received a Section 104 Letter from the EPA,
Region VI, which asked for either participation in or financing of a Removal
Action calling for netting of a 2.5 acre on-site sludge lagoon to preclude
access to wildlife. The PRP Group, for various reasons, declined on
February 10, 1994, to participate or finance the Removal Action.
On December 16, 1994, OG&E received a letter from EPA stating that it
was waiving the Special Notice procedures under Section 122(e) in regard to the
Remedial Design/Remedial Action for the second operable unit. This is based on
the fact that (1) an offer for both operable units is presently being
negotiated and (2) there is a strong indication that the PRPs will not perform
the remedy. EPA hopes to conclude de minimis settlement negotiations and have
a signed settlement document by April 28, 1995. It is believed at this time
that OG&E is a de minimis party, in which case its liability would not be
significant.
Due to the present stage of this matter, the total cost of the cleanup
of the site and the Company's ultimate liability cannot be estimated.
Nevertheless, management believes that OG&E's ultimate liability for the
cleanup costs of this site will not have a material adverse effect on the
Company's consolidated financial position or its results of operations.
Management's opinion is based on the financial viability of the other PRPs and
the portion of the total waste disposed at this site attributable to OG&E.
Management also believes that costs incurred in connection with this site,
which are not recovered from insurance carriers or other parties, may be
allowable costs for future ratemaking purposes.
7. As previously reported, OG&E was aware of an asbestos problem
at its former Osage Plant. During 1994, the Company determined that it had no
material liability with respect to this matter.
8. OG&E has been requested by the EPA to permit the inspection of
two separate properties owned by OG&E for possible hazardous substances,
pollutants or contaminants. These sites were used many years ago by OG&E or
certain companies acquired by OG&E for manufacturing gas from coal. In
connection with manufacturing gas, various by-products were produced (including
coal-tar and other potentially harmful materials), which could remain on the
sites. During 1994, the Company determined that it had no material liability
with respect to these sites.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
-------------------------------------------------------------
Not applicable.
20
<PAGE> 23
EXECUTIVE OFFICERS OF THE REGISTRANT.
-------------------------------------
The following persons were Executive Officers of the Registrant as of
March 15, 1995:
<TABLE>
<CAPTION>
Name Age Title
-------------------- --- ---------------------------------------------
<S> <C> <C>
James G. Harlow Jr. 60 Chairman of the Board, President
and Chief Executive Officer
Patrick J. Ryan 56 Vice Chairman
Al M. Strecker 51 Senior Vice President - Finance and
Administration
Steven E. Moore 48 Senior Vice President - Law and Public Affairs
Melvin D. Bowen Jr. 53 Vice President - Power Delivery
Jack T. Coffman 51 Vice President - Power Supply
Michael G. Davis 45 Vice President - Marketing and
Customer Services
James R. Hatfield 37 Treasurer
Don L. Young 54 Controller
Donald R. Rowlett 37 Assistant Controller
Irma B. Elliott 56 Secretary
</TABLE>
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 18, 1995.
21
<PAGE> 24
The business experience of each of the Executive Officers of the
Registrant for the past five years is as follows:
<TABLE>
<CAPTION>
Name Business Experience
-------------------- ----------------------------------------
<S> <C> <C>
James G. Harlow Jr. 1990-Present: Chairman of the Board,
President and Chief
Executive Officer
Patrick J. Ryan 1994-Present: Vice Chairman
1990-1994: Executive Vice President
and Chief Operating
Officer
Al M. Strecker 1994-Present: Senior Vice President -
Finance and
Administration
1991-1994: Vice President and
Treasurer
1990-1991: Vice President, Secretary
and Treasurer
Steven E. Moore 1994-Present: Senior Vice President-Law
and Public Affairs
1990-1994: Vice President - Law
and Public Affairs
Melvin D. Bowen Jr. 1994-Present: Vice President -
Power Delivery
1990-1994: Metro Region
Superintendent
Jack T. Coffman 1994-Present: Vice President -
Power Supply
1990-1994: Manager - Generation
Services
Michael G. Davis 1994-Present: Vice President -
Marketing and
Customer Services
1992-1994: Director - Marketing
Division
1990-1992: Manager - Industrial
Services
</TABLE>
22
<PAGE> 25
<TABLE>
<CAPTION>
Name Business Experience
-------------------- ------------------------------------------
<S> <C> <C>
James R. Hatfield 1994-Present: Treasurer
1994: Vice President - Investor
Relations & Corporate
Secretary - Aquila Gas
Pipeline Corporation (an
intrastate gas pipeline
subsidiary of UtiliCorp
United Inc.)
1990-1993: Assistant Treasurer -
UtiliCorp United Inc.
(an electric and natural
gas utility company)
Don L. Young 1990-Present: Controller
Donald R. Rowlett 1994-Present: Assistant Controller
1992-1994: Senior Specialist -
Tax Accounting
1990-1992: Specialist - Tax
Accounting
Irma B. Elliott 1991-Present: Secretary
1990-1991: Assistant Secretary
</TABLE>
23
<PAGE> 26
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
---------------------------------------------------------
STOCKHOLDER MATTERS.
--------------------
The Company's Common Stock is listed for trading on the New York and
Pacific Stock Exchanges under the ticker symbol "OGE". Quotes may be obtained
in daily newspapers where the common stock is listed as "OklaGE" in the New
York Stock Exchange listing table. The following table gives information with
respect to price ranges, as reported in The Wall Street Journal as New York
-----------------------
Stock Exchange Composite Transactions, and dividends paid for the periods
shown.
<TABLE>
<CAPTION>
1994 1993
---------------------------------------------------------------------------------------------
Dividend Dividend
Paid High Low Paid High Low
---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
First Quarter $0.66 1/2 $37 1/4 $33 1/2 $0.66 1/2 $35 7/8 $33
Second Quarter 0.66 1/2 36 1/2 29 3/8 0.66 1/2 37 5/8 33 3/4
Third Quarter 0.66 1/2 34 3/8 29 5/8 0.66 1/2 38 5/8 34
Fourth Quarter 0.66 1/2 34 1/4 32 0.66 1/2 38 5/8 32 7/8
</TABLE>
The number of record holders of Common Stock at December 31, 1994, was
44,464. The book value of the Company's Common Stock at December 31, 1994, was
$22.83.
24
<PAGE> 27
ITEM 6. SELECTED FINANCIAL DATA.
--------------------------------
HISTORICAL DATA
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
SELECTED FINANCIAL DATA
(dollars in thousands except for
per share data)
Operating revenue . . . . . . $ 1,355,168 $ 1,447,252 $ 1,314,984 $ 1,314,770 $ 1,230,769
Operating expenses . . . . . . 1,154,702 1,252,099 1,137,980 1,103,683 1,019,510
Operating income . . . . . . . 200,466 195,153 177,004 211,087 211,259
Other income and deductions . (2,167) (1,301) (567) (471) (263)
Interest charges . . . . . . . 74,514 79,575 76,725 76,700 71,798
-------- -------- ------- -------- --------
Net income . . . . . . . . . . 123,785 114,277 99,712 133,916 139,198
Preferred dividend
requirements . . . . . . . . 2,317 2,317 2,317 2,317 2,467
Earnings available for
common . . . . . . . . . . . $ 121,468 $ 111,960 $ 97,395 $ 131,599 $ 136,731
======== ======== ======= ======== ========
Long-term debt . . . . . . . . $ 730,567 $ 838,660 $ 838,654 $ 853,597 $ 853,540
Total assets . . . . . . . . . $ 2,782,629 $ 2,731,424 $ 2,590,083 $ 2,566,089 $ 2,522,907
Earnings per average common
share . . . . . . . . . . . $ 3.01 $ 2.78 $ 2.42 $ 3.27 $ 3.38
CAPITALIZATION RATIOS
Common equity . . . . . . . 54.13% 50.51% 50.36% 50.20% 49.44%
Cumulative preferred stock . 2.94% 2.78% 2.79% 2.75% 2.80%
Long-term debt . . . . . . . 42.93% 46.71% 46.85% 47.05% 47.76%
INTEREST COVERAGES . . . . . .
Before federal income taxes
(including AFUDC) . . . . . . 3.59X 3.32X 3.05X 3.66X 3.91X
(excluding AFUDC) . . . . . . 3.58X 3.32X 3.04X 3.63X 3.87X
After federal income taxes
(including AFUDC) . . . . . . 2.64X 2.43X 2.29X 2.70X 2.84X
(excluding AFUDC) . . . . . . 2.62X 2.42X 2.28X 2.66X 2.79X
</TABLE>
25
<PAGE> 28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
---------------------------------------------------------
OPERATIONS AND FINANCIAL CONDITION.
-----------------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS
OVERVIEW
<TABLE>
<CAPTION>
PERCENT CHANGE
FROM PRIOR YEAR
------------------
(THOUSANDS EXCEPT PER SHARE AMOUNTS) 1994 1993 1992 1994 1993
==================================================================================================================
<S> <C> <C> <C> <C> <C>
Operating revenues . . . . . . . . . $1,355,168 $1,447,252 $1,314,984 (6.4) 10.1
Earnings available for common stock . $ 121,468 $ 111,960 $ 97,395 8.5 15.0
Average shares outstanding . . . . . 40,344 40,328 40,310 -- --
Earnings per average common share . . $ 3.01 $ 2.78 $ 2.42 8.3 14.9
Dividends paid per share . . . . . . $ 2.66 $ 2.66 $ 2.66 -- --
==================================================================================================================
</TABLE>
Earnings for 1994 increased significantly from $2.78 per share in 1993 to
$3.01 per share in 1994. This improvement in earnings occurred despite the
order in February 1994 from the Oklahoma Corporation Commission (the
"Commission"), which effectively reduced OG&E's rates to its Oklahoma customers
by approximately $17 million annually. The Commission's order also required
OG&E to refund $41.3 million to its customers. The refund had only a slight
impact on 1994 results as approximately $39.1 million of the refund had been
recorded in 1993 and 1992.
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 the third quarter of 1994, OG&E deferred the costs associated with the
VERP and severance package, pending a Commission order. Labor savings in 1994
approximated the amortization of the deferred amount and therefore, did not
significantly impact 1994 results. However, approximately $6.5 million in other
restructuring expenses reduced 1994 earnings by $0.10 per share. At December
31, 1994, the deferred amount was $48.9 million, which is included on the
Consolidated Balance Sheets as Deferred Charges - Other. In response to an
application filed by OG&E on August 9, 1994, the Commission issued an order on
October 26, 1994, that permitted the Company to amortize the December 31, 1994,
balance of the regulatory asset over 26 months and reduced OG&E's electric
rates by approximately $15 million annually, effective January 1995. In 1995
and 1996, the labor savings are expected to substantially offset the
amortization of the regulatory asset and the annual rate reduction of $15
million. See Note 10 of Notes to Consolidated Financial Statements for a
further discussion of the Commission's orders in February and October 1994.
The dividend payout ratio (expressed as a percentage of earnings available
for common) improved in 1994 to 88 percent as compared to 96 percent for 1993.
The Company's long-term goal is to achieve a dividend payout ratio of 75
percent based on long-term earnings expectations.
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.
EARNINGS
In 1994, earnings per share increased $0.23, or 8.3 percent from those
reported in 1993. The increase resulted primarily from increased retail
electric kilowatt-hour sales in 1994 and less impact than in 1993 from the
Commission's February 1994 rate order. The 1993 increase in earnings was
attributable almost in its entirety to increased retail electric sales from
more normal weather in the Company's service territory, which more than offset
the provision for rate refund recorded in 1993 ($0.32 per share) related to
the Commission's refund order in February 1994.
26
<PAGE> 29
RESULTS OF OPERATIONS
<TABLE>
<CAPTION>
REVENUES PERCENT CHANGE
FROM PRIOR YEAR
-------------------
(THOUSANDS) 1994 1993 1992 1994 1993
=================================================================================================================
<S> <C> <C> <C> <C> <C>
Sales of electricity to OG&E customers . . $ 1,188,550 $ 1,242,964 $ 1,149,894 (4.4) 8.1
Provision for rate refund . . . . . . . . . (3,417) (14,963) (18,000) * *
Sales of electricity to other utilities . . 11,765 54,815 62,099 (78.5) (11.7)
Enogex . . . . . . . . . . . . . . . . . . 158,270 164,436 120,991 (3.7) 35.9
------------------------------------------------------------------------------------------
Total operating revenues . . . . . . . . $ 1,355,168 $ 1,447,252 $ 1,314,984 (6.4) 10.1
=================================================================================================================
System kilowatt-hour sales . . . . . . . . 20,642,675 20,201,533 19,236,843 2.2 5.0
Kilowatt-hour sales to other utilities 556,765 3,103,977 4,141,084 (82.1) (25.0)
------------------------------------------------------------------------------------------
Total kilowatt-hour sales . . . . . . . 21,199,440 23,305,510 23,377,927 (9.0) (0.3)
=================================================================================================================
</TABLE>
* Not meaningful
In 1994, approximately 88 percent of the Company's revenues consisted of
regulated sales of electricity as a public utility, while the remaining 12
percent was provided by the non-utility operations of the Company's
wholly-owned subsidiary, Enogex Inc. and its subsidiaries (collectively
"Enogex"). Revenues from sales of electricity are somewhat seasonal, with a
large portion of the Company's annual electric revenues being derived during
the summer months when the electricity needs of its customers increase.
Enogex's primary operations consist of transporting natural gas through its
intra-state pipeline to various customers (including OG&E), buying and selling
natural gas to third parties, selling natural gas liquids extracted by its
natural gas processing plants and investing in natural gas exploration and
production activities. Actions of the regulatory commissions that set OG&E's
electric rates will continue to affect the Company's financial results. The
commissions also have the authority to examine the appropriateness of OG&E's
recovery from its customers of fuel costs, which include the transportation
fees that OG&E pays Enogex for transporting natural gas to OG&E's generating
units.
Overall, 1994 operating revenues decreased $92.1 million, or 6.4 percent,
primarily due to recovery of substantially reduced fuel costs, a significant
reduction in kilowatt-hour sales to other utilities, milder weather and lower
revenue from Enogex businesses. Partially offsetting the impact of these
reductions was a 2.2 percent growth in kilowatt-hour sales to OG&E customers
("system sales"). The 1994 rate reduction did not significantly affect 1994
revenues when compared to 1993, due to the increased system sales in 1994, and
since 1993 revenues reflected a $15 million provision for rate refund.
Enogex revenues decreased 3.7 percent in 1994. Primary factors for the
decreases were lower natural gas prices, slightly lower volumes of natural gas
sold by Enogex and lower transportation fees on gas transported for OG&E. These
decreases were only partially offset by increased sales of natural gas liquids.
During 1993, operating revenues increased $132.3 million or 10.1 percent
compared to 1992. Increased system sales, the recovery of higher purchased
power costs and Enogex accounted for the increased revenues. These increases
were only partially offset by the Commission's rate order in February 1994,
which reduced 1993 operating revenues by approximately $15 million.
A return to near normal weather and continued slight customer growth
contributed to the increase in system sales for 1993. This increase in system
sales was partially offset by a 25.0 percent decrease in sales to other
utilities; causing total kilowatt-hour sales to be down by 0.3 percent for
1993. However, sales to other utilities are at much lower prices per
kilowatt-hour and have less impact on operating revenues and income than system
sales.
Enogex's 1993 revenues increased due to higher prices on natural gas sales
and increased sales of petroleum products.
27
<PAGE> 30
<TABLE>
<CAPTION>
EXPENSES AND OTHER ITEMS PERCENT CHANGE
FROM PRIOR YEAR
-------------------
(DOLLARS IN THOUSANDS) 1994 1993 1992 1994 1993
=================================================================================================================
<S> <C> <C> <C> <C> <C>
Fuel . . . . . . . . . . . . . . $ 263,329 $ 383,207 $ 377,575 (31.3) 1.5
Purchased power . . . . . . . . . 228,701 218,689 182,230 4.6 20.0
Gas purchased for resale (Enogex) 114,044 140,311 97,486 (18.7) 43.9
Other operation and maintenance . 284,194 274,988 266,061 3.3 3.4
Restructuring . . . . . . . . . . 21,035 -- -- * *
Depreciation . . . . . . . . . . 126,377 119,543 110,700 5.7 8.0
Taxes . . . . . . . . . . . . . . 117,022 115,361 103,928 1.4 11.0
-------------------------------------------------------------------------------------
Total operating expenses . . . $1,154,702 $1,252,099 $1,137,980 (7.8) 10.0
=================================================================================================================
</TABLE>
* Not meaningful
Total operating expenses decreased $97.4 million, or 7.8 percent in 1994, due
to reduced fuel costs for the production of electricity and decreases in both
quantities and prices of gas purchased for resale by Enogex. These reductions
were partially offset by the cost of restructuring and increases in purchased
power and depreciation.
The Company's generating capability is almost evenly divided between coal and
natural gas and provides the flexibility to use either fuel to the best
economic advantage for the Company and its customers. During 1994, fuel costs
decreased approximately $120.0 million, or 31.3 percent, due to renegotiated
coal and transportation contracts, lower natural gas usage and a 15.9 percent
reduction in the volume of kilowatt-hours generated (due to economic purchases
of power from other utilities and a reduction in sales to other utilities). In
1993, fuel expense increased approximately $5.6 million, or 1.5 percent,
primarily due to increased prices of gas used in the generation of electricity,
which more than offset a 3.5 percent reduction in consumption of natural gas
used to generate electricity.
Purchased power costs amounted to $228.7 million in 1994, up from $218.7
million and $182.2 million, in 1993 and 1992, respectively. The $10.0 million
increase in 1994 resulted from economic purchases of power from other
utilities, while the $36.5 million increase in 1993 resulted from price
escalation provisions contained in certain cogeneration contracts. As required
by the Public Utility Regulatory Policy Act of 1978 ("PURPA"), the Company must
currently purchase power from qualified cogeneration facilities. In 1998,
another qualified cogeneration facility is scheduled to become operational and
the Company is obligated to purchase up to 100 megawatts of capacity from this
facility as well. See related discussion of purchased power in Note 9 of Notes
to Consolidated Financial Statements.
Variances in the actual cost of fuel used in electric generation and certain
purchased power costs, as compared to that component in cost-of-service for
ratemaking, are passed through to OG&E's electric customers through automatic
fuel adjustment clauses. The automatic fuel adjustment clauses are subject to
periodic review by the Commission, the Arkansas Public Service Commission and
the Federal Energy Regulatory Commission ("FERC").
Even though increases and decreases are passed through to customers, in 1993
the Company began utilizing a natural gas storage facility which helps OG&E
lower fuel costs and receive greater value from its remaining take-or-pay gas
contracts. By diverting natural gas into storage, OG&E is able to use as much
coal as possible to generate electricity, and use gas from storage when needed
to meet increases in demand for electricity. The higher level of fuel
inventories at the end of 1994 was attributable to increased usage of the
natural gas storage facility and the relatively low level of fuel inventories at
the end of 1993 was due to significant kilowatt-hour sales to other utilities.
The Company has initiated numerous other ongoing programs that have helped
reduce the cost of generating electricity over the last several years. These
programs include: 1) spot market purchases of coal; 2) renegotiated contracts
for coal, gas, railcar maintenance and coal transportation; and 3) a heat rate
awareness program to produce kilowatt-hours with less fuel. Reducing fuel
costs helps OG&E remain competitive, which in turn helps OG&E's electric
customers remain competitive in a global economy.
Enogex's gas purchased for resale decreased $26.3 million or 18.7 percent for
1994 compared to an increase of $42.8 million or 43.9 percent for 1993. The
1994 decrease was due to reduced volumes and lower natural gas prices, while
the 1993 increase
28
<PAGE> 31
resulted from higher gas prices and increased volumes compared to 1992.
Other operation and maintenance increased by approximately $9.2 million and
$8.9 million in 1994 and 1993, respectively. A $5.4 million decrease in
production maintenance in 1994, net of labor savings, was more than offset by:
(i) expensing $8.4 million of previously deferred costs associated with
Statement of Financial Accounting Standards ("SFAS") No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions;" (ii) current
recognition of SFAS No. 106 costs; and (iii) increased costs of producing
natural gas liquids at Enogex. The 1993 increase in other operation and
maintenance expenses resulted from major overhauls at two generating plants and
increased labor costs.
The Company offered a Voluntary Early Retirement Package ("VERP") and more
than 730 employees elected to retire in July, at a cost of approximately $58.5
million. The Company also incurred approximately $4.9 million of costs related
to a severance package. The costs of the VERP and severance package were
deferred, pending a Commission order. Between August 1, and December 31, 1994,
the amount deferred was reduced by approximately $14.5 million, which is the
approximate amount of labor savings during that same period. In response to an
application filed by the Company, the Commission issued an order in October
1994 approving the Company's proposed accounting treatment of certain
restructuring costs. At December 31, 1994, the unamortized balance of the
regulatory asset was $48.9 million, which is included on the Consolidated
Balance Sheets as Deferred Charges - Other. This regulatory asset will be
amortized over 26 months, as permitted by the Commission's order. Restructuring
expenses, which resulted from a complete review and redesign of the Company's
operations, were approximately $21.0 million in 1994 (including amortization of
the deferred charge). Restructuring expenses included only costs that were
actually incurred in 1994. See Note 7 of Notes to Consolidated Financial
Statements.
The increases in depreciation for 1994 and 1993 reflect higher levels of
depreciable plant. Also, the adoption of SFAS No. 109, "Accounting for Income
Taxes," during 1993 and its effect on Enogex contributed to the increase in
depreciation. See Note 2 of Notes to Consolidated Financial Statements.
In 1994, income taxes increased primarily due to higher pre-tax earnings.
Income taxes during 1993 increased primarily due to higher pre-tax earnings and
a one percent increase in the federal income tax rate to 35 percent.
The variances in interest expense for 1994 and 1993 were primarily
attributable to the approximate $6.2 million of interest in 1993, associated
with the refund ordered by the Commission in February 1994. See Note 10 of
Notes to Consolidated Financial Statements.
LIQUIDITY, CAPITAL RESOURCES AND CONTINGENCIES
The primary capital requirements for 1994 and as estimated for 1995 through
1997 are as follows:
<TABLE>
<CAPTION>
(DOLLARS IN MILLIONS) 1994 1995 1996 1997
==========================================================================================================
<S> <C> <C> <C> <C>
Construction expenditures
including AFUDC . . . . . . . . . . . . . . . . . $ 150 $ 89 $ 89 $ 89
Maturities of long-term
debt and sinking fund
requirements . . . . . . . . . . . . . . . . . . . -- 25 -- 15
----------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . $ 150 $ 114 $ 89 $104
==========================================================================================================
</TABLE>
CONSTRUCTION
The Company's primary needs for capital are related to construction of new
facilities to meet anticipated demand for service, to replace or expand
existing facilities in both its electric and non-utility businesses, and to
some extent, for satisfying maturing debt and sinking fund obligations.
Approximately $7.4 million of the Company's construction expenditures budgeted
for 1995 are to comply with environmental laws and regulations. Because of the
continuing trend toward greater environmental awareness and increasingly
stringent regulation, the Company has been experiencing a trend towards
increasing environmental costs. This trend has caused and may continue to cause
slightly higher operating expenditures and capital expenditures for
environmental matters.
The construction program for the next several years does not include any
additional base-load generating units. Rather, to meet the increased
electricity needs of its customers during the balance of this century, the
Company will concentrate on
29
<PAGE> 32
maintaining the reliability and increasing the utilization of existing capacity
and increasing demand-side management efforts.
FINANCE
The Company meets its cash needs through internally generated funds,
short-term borrowings and permanent financing. Cash flows from operations
remained strong, which enabled the Company to internally generate the required
funds to satisfy construction expenditures during 1994 and 1993. 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 maximum amount of
outstanding short-term borrowings during 1994 was $220 million. The Company has
the necessary regulatory approvals to incur up to $400 million in short-term
borrowings at any one time.
The Company continues to evaluate opportunities to enhance shareowner returns
and achieve long-term financial objectives through acquisitions of non-utility
businesses. Permanent financing could be required for such acquisitions.
In August 1994, Enogex redeemed its $90 million of outstanding medium-term
notes, with interest rates ranging from 9.88% to 10.11%. Enogex anticipates
issuing long-term debt in 1995 to replace short-term borrowings in connection
with such redemption.
In January 1995, OG&E refinanced its obligations with respect to $47,000,000
of 5 7/8% Pollution Control Revenue Bonds due December 1, 2007 and $32,050,000
of 6 3/4% Pollution Control Revenue Bonds due March 1, 2006 through the
issuance of two new series of pollution control bonds bearing interest at
variable, tax-exempt rates. These refinancings are expected to result in lower
long-term interest rates during 1995.
CONTINGENCIES
The Company is defending various claims and legal actions, including
environmental actions, which are common to its operations. As to environmental
matters, the Company has been designated as a "potentially responsible party"
("PRP") with respect to three waste disposal sites to which the Company sent
materials. Under applicable law, the Company and each PRP could be held jointly
and severally liable for site remediation. Neither the amount of cleanup costs
nor the final method of their allocation among all designated PRPs at any of
these sites has been determined. While it is not possible to determine the
precise outcome of these matters, in the opinion of management, the Company's
ultimate liability for the clean-up costs of these sites will not have a
material adverse effect on the Company's consolidated financial position or
results of operations. Management's opinion is based on the following: 1) the
clean-up costs already paid by certain parties, 2) the financial viability of
the other PRPs, and 3) the portion of the total wastes disposed at the sites
attributable to the Company. Management also believes that costs incurred in
connection with the sites, which are not recovered from insurance carriers or
other parties, may be allowable costs for future ratemaking purposes.
The Company continues to explore options to comply with the Clean Air Act
Amendments of 1990 ("CAAA"). Since all of OG&E's coal-fired generating units
currently burn low-sulfur coal, OG&E will not need to take any steps to comply
with the new sulfur dioxide emission limits until January 1, 2000. In
compliance with Title IV of the CAAA, the Company has completed installation of
continuous emission monitors ("CEMs") on each of its five coal-fired generating
units and three of its 12 gas-fired generating units. Expenditures on CEMs in
1994 totalled approximately $6 million. The Environmental Protection Agency
("EPA") established a time extension for installation of CEMs on gas-fired
units which allowed the Company to defer CEM installation on the remaining nine
units subject to the requirements of Title IV. Completion of this project is
expected to cost approximately $1 million during 1995. The CAAA Title V
operating permits are expected to cost approximately $400,000 in 1995.
30
<PAGE> 33
The CAAA will also regulate emissions of nitrogen oxides and certain air
toxic compounds. Although final regulations concerning all of these issues have
not been written, additional capital expenditures may be necessary in future
years. The Company will continue to examine all alternatives to comply with
the CAAA as part of its Integrated Resource Planning process. This planning
approach will assure the Company employs the least cost option to comply with
the CAAA and be in a competitive position to market its services.
During 1992, OG&E disclosed to the EPA discrepancies in the 1991 annual
report required by the Toxic Substance Control Act ("TSCA"). These
discrepancies were administrative in nature and presented no harm to the
environment and presented no health problems to our Company members or the
public. However, the Company has instituted specific systems and measures to
correct each of the reported discrepancies. No actions were taken by the EPA on
this matter during 1994. See Note 9 of Notes to Consolidated Financial
Statements for a further discussion of this matter.
In October 1992, the National Energy Policy Act of 1992 ("Energy Act") was
enacted. Among many other provisions, the Energy Act is designed to promote
competition in the development of wholesale power generation in the electric
utility industry. It exempts a new class of independent power producers from
regulation under the Public Utility Holding Company Act of 1935 and allows the
FERC to order "wholesale wheeling" by public utilities to provide utility and
non-utility generators access to public utility transmission facilities. Also,
numerous states are considering proposals to require "retail wheeling" which is
the delivery of power generated by a third party to retail customers. In 1995,
the Company intends to make a transmission open access filing before the FERC,
in compliance with the Energy Act, and the Company intends to implement Real
Time Pricing for a pilot group of its retail customers. The Energy Act, these
proposals and other factors are expected to significantly increase competition
in the electric industry. The Company has taken steps in the past and intends
to take appropriate steps in the future to remain a competitive supplier of
electricity. Past actions include the redesign and restructuring effort in 1994
and the actions to reduce fuel costs, both of which have resulted in lower
retail rates, especially for industrial customers.
Besides the existing contingencies described above and those described in
Note 9 of Notes to Consolidated Financial Statements, the Company's ability to
fund its future operational needs and to finance its construction program is
dependent upon numerous other factors beyond its control, such as general
economic conditions, abnormal weather, load growth, inflation, new
environmental laws or regulations and the cost and availability of external
financing.
31
<PAGE> 34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
---------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31 (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . $ 1,355,168 $ 1,447,252 $ 1,314,984
----------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . 263,329 383,207 377,575
Purchased power . . . . . . . . . . . . . . . . . . . . . . . 228,701 218,689 182,230
Gas purchased for resale . . . . . . . . . . . . . . . . . . . 114,044 140,311 97,486
Other operation . . . . . . . . . . . . . . . . . . . . . . . 216,961 196,323 193,622
Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . 67,233 78,665 72,439
Restructuring . . . . . . . . . . . . . . . . . . . . . . . . 21,035 -- --
Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . 126,377 119,543 110,700
Current income taxes . . . . . . . . . . . . . . . . . . . . . 50,129 72,003 61,325
Deferred income taxes, net . . . . . . . . . . . . . . . . . . 27,092 5,286 4,346
Deferred investment tax credits, net . . . . . . . . . . . . (5,150) (5,150) (5,465)
Taxes other than income . . . . . . . . . . . . . . . . . . . 44,951 43,222 43,722
----------------------------------------------------------------------------------------------------------------------
Total operating expenses . . . . . . . . . . . . . . . . . . 1,154,702 1,252,099 1,137,980
----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . . 200,466 195,153 177,004
----------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
Interest income . . . . . . . . . . . . . . . . . . . . . . . 3,409 1,431 629
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,576) (2,732) (1,196)
----------------------------------------------------------------------------------------------------------------------
Net other income and deductions . . . . . . . . . . . . . . (2,167) (1,301) (567)
----------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt . . . . . . . . . . . . . . . . . . 67,680 70,490 71,230
Allowance for borrowed funds used during construction (1,073) (433) (809)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,907 9,518 6,304
----------------------------------------------------------------------------------------------------------------------
Total interest charges, net . . . . . . . . . . . . . . . . 74,514 79,575 76,725
----------------------------------------------------------------------------------------------------------------------
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . 123,785 114,277 99,712
PREFERRED DIVIDEND REQUIREMENTS . . . . . . . . . . . . . . . . . 2,317 2,317 2,317
----------------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON . . . . . . . . . . . . . . . . . . $ 121,468 $ 111,960 $ 97,395
======================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (thousands) . . . . . . . . . . 40,344 40,328 40,310
EARNINGS PER AVERAGE COMMON SHARE . . . . . . . . . . . . . . . . $ 3.01 $ 2.78 $ 2.42
======================================================================================================================
</TABLE>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31 (DOLLARS IN THOUSANDS) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . . . $ 395,811 $ 391,135 $ 400,976
ADD--net income . . . . . . . . . . . . . . . . . . . . . . . . . 123,785 114,277 99,712
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . 519,596 505,412 500,688
----------------------------------------------------------------------------------------------------------------------
DEDUCT:
Cash dividends declared on preferred stock . . . . . . . . . . 2,317 2,317 2,317
Cash dividends declared on common stock . . . . . . . . . . . 107,319 107,284 107,236
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . 109,636 109,601 109,553
----------------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . . . $ 409,960 $ 395,811 $ 391,135
======================================================================================================================
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part hereof.
32
<PAGE> 35
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31 (DOLLARS IN THOUSANDS) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,770,247 $ 3,656,113 $ 3,471,588
Construction work in progress . . . . . . . . . . . . . . . . 43,943 33,970 37,147
----------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment . . . . . . . . . . . . 3,814,190 3,690,083 3,508,735
Less accumulated depreciation . . . . . . . . . . . . . . 1,487,300 1,370,227 1,267,472
----------------------------------------------------------------------------------------------------------------------
Net property, plant and equipment . . . . . . . . . . . . . . 2,326,890 2,319,856 2,241,263
----------------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost . . . . . . . . . . . . . 7,868 6,920 6,269
----------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . 2,455 6,593 11,316
Accounts receivable--customers, less reserve of $3,719,
$4,070 and $4,039, respectively . . . . . . . . . . . . . . 118,318 126,997 107,805
Accrued unbilled revenues . . . . . . . . . . . . . . . . . . 36,800 45,100 45,300
Accounts receivable--other . . . . . . . . . . . . . . . . . . 8,601 6,269 6,378
Fuel inventories, at LIFO cost . . . . . . . . . . . . . . . . 46,494 27,127 37,066
Materials and supplies, at average cost . . . . . . . . . . . 30,401 26,813 24,614
Prepayments and other . . . . . . . . . . . . . . . . . . . . 43,137 28,648 5,215
Accumulated deferred tax asset . . . . . . . . . . . . . . . . 12,077 24,088 --
----------------------------------------------------------------------------------------------------------------------
Total current assets . . . . . . . . . . . . . . . . . . . . 298,283 291,635 237,694
----------------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Advance payments for gas . . . . . . . . . . . . . . . . . . . 10,000 21,165 22,743
Income taxes recoverable through future rates . . . . . . . . 47,246 47,593 44,387
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92,342 44,255 37,727
----------------------------------------------------------------------------------------------------------------------
Total deferred charges . . . . . . . . . . . . . . . . . . . 149,588 113,013 104,857
----------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,782,629 $ 2,731,424 $ 2,590,083
======================================================================================================================
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part hereof.
33
<PAGE> 36
<TABLE>
<CAPTION>
DECEMBER 31 (DOLLARS IN THOUSANDS) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statements):
Common stock and retained earnings . . . . . . . . . . . . . . $ 921,177 $ 906,804 $ 901,503
Cumulative preferred stock . . . . . . . . . . . . . . . . . . 49,973 49,973 49,973
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . 730,567 838,660 838,654
----------------------------------------------------------------------------------------------------------------------
Total capitalization . . . . . . . . . . . . . . . . . . . . 1,701,717 1,795,437 1,790,130
----------------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Short-term debt . . . . . . . . . . . . . . . . . . . . . . . 182,750 47,000 26,000
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . 66,391 100,285 94,549
Dividends payable . . . . . . . . . . . . . . . . . . . . . . 27,415 27,410 27,397
Customers' deposits . . . . . . . . . . . . . . . . . . . . . 20,904 19,353 17,891
Accrued taxes . . . . . . . . . . . . . . . . . . . . . . . . 25,153 24,717 27,169
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . 23,873 26,712 29,961
Long-term debt due within one year . . . . . . . . . . . . . . 25,350 350 15,300
Accumulated provision for rate refund . . . . . . . . . . . . 2,970 39,117 --
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,321 48,666 45,541
----------------------------------------------------------------------------------------------------------------------
Total current liabilities . . . . . . . . . . . . . . . . . 416,127 333,610 283,808
----------------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation . . . . . . . . . . . . 71,014 16,210 5,620
Accumulated provision for rate refund . . . . . . . . . . . . -- -- 18,000
Accumulated deferred income taxes . . . . . . . . . . . . . . 497,056 484,003 384,114
Accumulated deferred investment tax credits . . . . . . . . . 88,328 93,478 98,627
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,387 8,686 9,784
----------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities . . . . . . . . 664,785 602,377 516,145
----------------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (NOTES 9 AND 10)
----------------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES . . . . . . . . . . . . . . $ 2,782,629 $ 2,731,424 $ 2,590,083
======================================================================================================================
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part hereof.
34
<PAGE> 37
CONSOLIDATED STATEMENTS OF CAPITALIZATION
<TABLE>
<CAPTION>
DECEMBER 31 (DOLLARS IN THOUSANDS) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
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 . . . . . . . . . . . . . . . . . . . 608,158 608,195 608,174
Retained earnings . . . . . . . . . . . . . . . . . . . . . . 409,960 395,811 391,135
Treasury stock--6,116,229, 6,124,139 and
6,141,591 shares, respectively . . . . . . . . . . . . . . . (213,118) (213,379) (213,983)
----------------------------------------------------------------------------------------------------------------------
Total common stock and retained earnings . . . . . . . . . . 921,177 906,804 901,503
----------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK:
Par value $20, authorized 675,000 shares--4%;
outstanding 423,663 shares . . . . . . . . . . . . . . . . . 8,473 8,473 8,473
Par value $25, authorized and unissued 4,000,000 shares . . . -- -- --
Par value $100, authorized 1,865,000 shares--
SERIES SHARES OUTSTANDING
4.20% 50,000 . . . . . . . . . . . . . . . . . . . . . 5,000 5,000 5,000
4.24% 75,000 . . . . . . . . . . . . . . . . . . . . . 7,500 7,500 7,500
4.44% 65,000 . . . . . . . . . . . . . . . . . . . . . 6,500 6,500 6,500
4.80% 75,000 . . . . . . . . . . . . . . . . . . . . . 7,500 7,500 7,500
5.34% 150,000 . . . . . . . . . . . . . . . . . . . . . 15,000 15,000 15,000
----------------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock . . . . . . . . . . . . . . . . 49,973 49,973 49,973
----------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT:
First mortgage bonds--
SERIES DATE DUE
4 1/4% March 1, 1993 . . . . . . . . . . . . . . . . . . -- -- 15,000
4 1/2% March 1, 1995 . . . . . . . . . . . . . . . . . . 25,000 25,000 25,000
5 1/8% January 1, 1997 . . . . . . . . . . . . . . . . . 15,000 15,000 15,000
6 3/8% January 1, 1998 . . . . . . . . . . . . . . . . . 25,000 25,000 25,000
7 1/8% January 1, 1999 . . . . . . . . . . . . . . . . . 12,500 12,500 12,500
8 5/8% January 1, 2000 . . . . . . . . . . . . . . . . . 30,000 30,000 30,000
7 1/8% January 1, 2002 . . . . . . . . . . . . . . . . . 40,000 40,000 40,000
8 3/8% January 1, 2004 . . . . . . . . . . . . . . . . . 75,000 75,000 75,000
9 1/8% January 1, 2005 . . . . . . . . . . . . . . . . . 60,000 60,000 60,000
8 5/8% January 1, 2006 . . . . . . . . . . . . . . . . . 55,000 55,000 55,000
8 3/8% January 1, 2007 . . . . . . . . . . . . . . . . . 75,000 75,000 75,000
8 5/8% November 1, 2007 . . . . . . . . . . . . . . . . 35,000 35,000 35,000
8 1/4% August 15, 2016 . . . . . . . . . . . . . . . . . 100,000 100,000 100,000
8 7/8% December 1, 2020 . . . . . . . . . . . . . . . . 75,000 75,000 75,000
5 7/8% Pollution Control Series A, December 1, 2007 . . 47,000 47,000 47,000
7% Pollution Control Series C, March 1, 2017 . . . . 56,000 56,000 56,000
Other bonds--
6 3/4% Muskogee Industrial Trust Bonds, March 1, 2006 . 32,050 32,400 32,700
Unamortized premium and discount, net . . . . . . . . . . . . (8,533) (8,890) (9,246)
Enogex Inc. notes . . . . . . . . . . . . . . . . . . . . . . 6,900 90,000 90,000
----------------------------------------------------------------------------------------------------------------------
Total long-term debt . . . . . . . . . . . . . . . . . . . . 755,917 839,010 853,954
Less long-term debt due within one year . . . . . . . . . . 25,350 350 15,300
----------------------------------------------------------------------------------------------------------------------
Total long-term debt (excluding long-term
debt due within one year) . . . . . . . . . . . . . . . . . 730,567 838,660 838,654
----------------------------------------------------------------------------------------------------------------------
Total Capitalization . . . . . . . . . . . . . . . . . . . . . . $ 1,701,717 $ 1,795,437 $ 1,790,130
======================================================================================================================
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part hereof.
35
<PAGE> 38
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31 (DOLLARS IN THOUSANDS) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 123,785 $ 114,277 $ 99,712
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation . . . . . . . . . . . . . . . . . . . . . . . 126,377 119,543 110,700
Deferred income taxes and investment tax credits, net . . 21,942 136 (1,119)
Provision for rate refund . . . . . . . . . . . . . . . . 4,200 21,117 18,000
Change in Certain Current Assets and Liabilities:
Accounts receivable--customers . . . . . . . . . . . . . 8,679 (19,192) 1,803
Accrued unbilled revenues . . . . . . . . . . . . . . . 8,300 200 (12,500)
Fuel, materials and supplies inventories . . . . . . . . (22,955) 7,740 5,473
Accumulated deferred tax assets . . . . . . . . . . . . 12,011 (24,088) --
Other current assets . . . . . . . . . . . . . . . . . . (16,821) (23,324) (762)
Accounts payable . . . . . . . . . . . . . . . . . . . . (35,667) 5,268 6,220
Accrued taxes . . . . . . . . . . . . . . . . . . . . . 436 (2,452) (7,331)
Accrued interest . . . . . . . . . . . . . . . . . . . . (2,839) (3,249) 4,537
Accumulated provision for rate refund . . . . . . . . . (36,147) 39,117 --
Other current liabilities . . . . . . . . . . . . . . . (5,789) 4,600 4,433
Other operating activities . . . . . . . . . . . . . . . . 18,698 (12,841) 12,863
----------------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities . . . . . . 204,210 226,852 242,029
----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . . . . . (151,012) (127,674) (141,936)
----------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities . . . . . . . . . (151,012) (127,674) (141,936)
----------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt . . . . . . . . . . . . . . . (83,450) (15,300) (300)
Short-term debt . . . . . . . . . . . . . . . . . . . . . 135,750 21,000 13,500
Cash dividends declared on preferred stock . . . . . . . . (2,317) (2,317) (2,317)
Cash dividends declared on common stock . . . . . . . . . (107,319) (107,284) (107,236)
----------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities . . . . . . . . . (57,336) (103,901) (96,353)
----------------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . . . (4,138) (4,723) 3,740
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . . . . . . . 6,593 11,316 7,576
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . . . . . . . $ 2,455 $ 6,593 $ 11,316
======================================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash Paid During the Period for:
Interest (net of amount capitalized) . . . . . . . . . . . . $ 74,372 $ 71,401 $ 73,691
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . $ 57,416 $ 79,953 $ 60,229
----------------------------------------------------------------------------------------------------------------------
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.
----------------------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying Notes to Consolidated Financial Statements are an integral
part hereof.
36
<PAGE> 39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
--------------------------------------------------------------------------------
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Oklahoma Gas
and Electric Company ("OG&E"), its wholly-owned non-utility subsidiary Enogex
Inc. and its subsidiaries ("Enogex") (collectively, the "Company"). All
significant intercompany transactions have been eliminated in consolidation.
ACCOUNTING RECORDS
The accounting records of OG&E are maintained in accordance with the Uniform
System of Accounts prescribed by the Federal Energy Regulatory Commission
("FERC") and adopted by the Oklahoma Corporation Commission (the "Oklahoma
Commission") and the Arkansas Public Service Commission (the "Arkansas
Commission"). Additionally, OG&E is subject to the accounting principles
prescribed by Statement of Financial Accounting Standards ("SFAS") No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
provides that, based upon the expectation to recover from, or flowback to,
future customers, certain costs can be deferred as regulatory assets, rather
than expensed and certain credits can be recognized as regulatory liabilities,
rather than treated as income. Management's expected recovery of deferred costs
and flowback of deferred credits generally results from specific decisions by
regulators granting such ratemaking treatment. Management continuously monitors
the future recoverability of regulatory assets. When, in management's judgment,
future recovery becomes impaired, the amount of the regulatory asset is reduced
or written-off, as appropriate. See Notes 7 and 10 of Notes to Consolidated
Financial Statements for related discussion.
PROPERTY, PLANT AND EQUIPMENT
All property, plant and equipment is recorded at cost. Electric utility
plant is recorded at its original cost. Newly constructed plant is added to
plant balances at costs which include contracted services, direct labor,
materials, overhead and allowance for funds used during construction.
Replacement of major units of property are capitalized as plant. The replaced
plant is removed from plant balances and the cost of such property together
with the cost of removal less salvage is charged to accumulated depreciation.
Repair and replacement of minor items of property are included in the
Consolidated Statements of Income as maintenance expense.
DEPRECIATION
The provision for depreciation, which was approximately 3.2% of the average
depreciable utility plant, for each of the years 1994, 1993 and 1992, is
provided on a straight-line method over the estimated service life of the
property. Depreciation is provided at the unit level for production plant and
at the account or sub-account level for all other plant, and is based on the
average life group procedure.
Enogex's gas pipeline and gas processing plants are depreciated on a
straight-line method over a period of 20 to 48 years.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction ("AFUDC") is calculated
according to FERC pronouncements for the imputed cost of equity and borrowed
funds. AFUDC, a non-cash item, is reflected as a credit on the Consolidated
Statements of Income and a charge to construction work in progress.
AFUDC rates, compounded semi-annually, were 4.58%, 3.60% and 4.30% for the
years 1994, 1993 and 1992, respectively.
UNBILLED REVENUE
OG&E accrues estimated revenues for services provided but not yet billed.
The cost of providing service is recognized as incurred.
AUTOMATIC FUEL ADJUSTMENT CLAUSES
Variances in the actual cost of fuel used in electric generation and certain
purchased power costs, as compared to that component in estimated
cost-of-service for ratemaking, are charged to substantially all of the
Company's electric customers through automatic fuel adjustment clauses, which
are subject to periodic review by the Oklahoma Commission, the Arkansas
Commission and the FERC.
FUEL INVENTORIES
Fuel inventories for the generation of electricity consist of coal, oil and
natural gas. These inventories are accounted for under the last-in, first-out
("LIFO") cost method. The estimated replacement cost of fuel inventories
exceeded the stated LIFO cost by approximately $2.5 million, $2.3 million and
$4.8 million for 1994, 1993 and 1992, respectively, based on the average cost
of fuel purchased late in the respective years. LIFO liquidation gains and
losses (no gains or losses in 1994, approximately $0.5 million gain in 1993 and
approximately $1.3 million loss in 1992) reduced or increased the Company's
recovery under its automatic fuel adjustment clauses, with no impact on net
income. Natural gas products inventories are held for sale and accounted for
based on the weighted average cost of production.
37
<PAGE> 40
--------------------------------------------------------------------------------
2. INCOME TAXES
The items comprising tax expense are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31 (DOLLARS IN THOUSANDS) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
Current Income Taxes
Provision for current taxes:
Federal . . . . . . . . . . . . . . . . . . . . . . . . $ 42,974 $ 61,406 $ 52,191
State . . . . . . . . . . . . . . . . . . . . . . . . . 7,155 10,597 9,134
----------------------------------------------------------------------------------------------------------------------
Total Current Income Taxes . . . . . . . . . . . . . . 50,129 72,003 61,325
----------------------------------------------------------------------------------------------------------------------
Deferred Income Taxes, net
Provision (benefit) for deferred taxes:
Federal
Depreciation . . . . . . . . . . . . . . . . . . . . . 7,372 9,673 6,185
Repair allowance . . . . . . . . . . . . . . . . . . . 1,109 1,360 1,908
Removal costs . . . . . . . . . . . . . . . . . . . . . 1,542 1,026 635
Provision for rate refund . . . . . . . . . . . . . . . 12,406 (6,972) (5,774)
Other . . . . . . . . . . . . . . . . . . . . . . . . . 812 (225) 1,059
State . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,851 424 333
----------------------------------------------------------------------------------------------------------------------
Total Deferred Income Taxes, net . . . . . . . . . . . 27,092 5,286 4,346
----------------------------------------------------------------------------------------------------------------------
Deferred Investment Tax Credits, net . . . . . . . . . . . . (5,150) (5,150) (5,465)
Income Taxes Relating to Other Income and Deductions . . . . 203 (538) (1,006)
----------------------------------------------------------------------------------------------------------------------
Total Income Tax Expense . . . . . . . . . . . . . . . $ 72,274 $ 71,601 $ 59,200
======================================================================================================================
Pretax Income . . . . . . . . . . . . . . . . . . . . . . . . $ 196,059 $ 185,878 $ 158,912
======================================================================================================================
</TABLE>
The following schedule reconciles the statutory federal tax rate to the
effective income tax rate:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
Statutory federal tax rate . . . . . . . . . . . . . . . . . . . 35.0% 35.0% 34.0%
State income taxes, net of federal income tax benefit . . . . . . 3.7 3.9 3.9
Investment tax credits, net . . . . . . . . . . . . . . . . . . . (2.6) (2.8) (3.4)
Change in federal tax rate . . . . . . . . . . . . . . . . . . . -- 0.9 --
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.8 1.5 2.8
----------------------------------------------------------------------------------------------------------------------
Effective income tax rate as reported . . . . . . . . . . . . 36.9% 38.5% 37.3%
======================================================================================================================
</TABLE>
The Company files consolidated income tax returns. Income taxes are
allocated to each company based on its separate taxable income or loss.
Investment tax credits on electric utility property have been deferred and
are being amortized to income over the life of the related property.
Payment of the rate refund in 1994 resulted in lower current income tax
expense. The provisions for rate refund accrued in 1992 and 1993 were not
deductible for income tax purposes until the refund was paid in 1994, resulting
in higher current income tax expense in 1992 and 1993.
The Company follows the provisions of SFAS No. 109, "Accounting for Income
Taxes," which it adopted effective January 1, 1993. SFAS No. 109 requires an
asset and liability approach to accounting for income taxes. Under SFAS No.
109, deferred tax assets or liabilities are computed based on the difference
between the financial statement and income tax bases of assets and liabilities
("temporary differences") using the enacted marginal tax rate. Deferred income
tax expenses or benefits are based on the changes in the asset or liability
from period to period. The Company elected not to restate the financial
statements for years ending before January 1, 1993. When adopted, SFAS No. 109
had no effect on net income.
38
<PAGE> 41
The deferred tax provisions, set forth above, are recognized as costs in the
ratemaking process by the commissions having jurisdiction over the rates
charged by OG&E.
The components of Accumulated Deferred Income Taxes are as follows:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) DEC 31, 1994 DEC 31, 1993 JAN 1, 1993
======================================================================================================================
<S> <C> <C> <C>
Current Deferred Tax Assets:
Accrued vacation . . . . . . . . . . . . . . . . . . . . . . . . $ 3,363 $ 4,177 $ 3,359
Postemployment medical and life insurance benefits . . . . . . . 3,235 -- --
Provision for rate refund . . . . . . . . . . . . . . . . . . . 375 14,965 --
Uncollectible accounts . . . . . . . . . . . . . . . . . . . . . 3,801 4,946 3,669
Customer deposits . . . . . . . . . . . . . . . . . . . . . . . -- -- 1,102
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,303 -- --
----------------------------------------------------------------------------------------------------------------------
Accumulated deferred tax assets . . . . . . . . . . . . . . . $ 12,077 $ 24,088 $ 8,130
======================================================================================================================
Deferred Tax Liabilities:
Accelerated depreciation and other property-related differences $ 455,943 $ 439,253 $ 438,419
Allowance for funds used during construction . . . . . . . . . . 53,317 57,074 61,346
Income taxes recoverable through future rates . . . . . . . . . 58,470 62,441 61,829
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . 567,730 558,768 561,594
----------------------------------------------------------------------------------------------------------------------
Deferred Tax Assets:
Deferred investment tax credits . . . . . . . . . . . . . . . . (28,868) (30,616) (32,850)
Income taxes refundable through future rates . . . . . . . . . . (40,186) (44,022) (49,100)
Provision for rate refund . . . . . . . . . . . . . . . . . . . -- -- (7,074)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,620) (127) (411)
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . (70,674) (74,765) (89,435)
----------------------------------------------------------------------------------------------------------------------
Accumulated Deferred Income Tax Liabilities . . . . . . . . . . . . $ 497,056 $ 484,003 $ 472,159
======================================================================================================================
</TABLE>
The effect of adopting SFAS No. 109 at January 1, 1993, before adjusting for
the new tax rate, resulted in a net increase in property, plant and equipment
of approximately $73.9 million, a net decrease in income taxes recoverable
through future rates of approximately $12.0 million and a net increase in
accumulated deferred income taxes of approximately $61.9 million. Also at
January 1, 1993, approximately $8.1 million of deferred tax assets which were
previously netted with accumulated deferred income taxes, were reclassified as
current assets as a result of adopting SFAS No. 109.
At December 31, 1992, the Company had recorded $44.4 million as unfunded
deferred income taxes recoverable from customers. A corresponding amount was
reflected as a component of accumulated deferred income taxes which represented
amounts refundable to customers. As a result of the adoption of SFAS No. 109,
the $44.4 million amount that was recorded as a component of accumulated
deferred income taxes at December 31, 1992, was reclassified January 1, 1993,
as a regulatory liability and netted against the regulatory asset. This
reclassification combined with the $12.0 million net decrease in income taxes
recoverable through future rates discussed above, resulted in a $32.4 million
net increase in the amount recognized as income taxes to be recovered through
future rates.
The Omnibus Reconciliation Act of 1993, signed into law on August 10, 1993,
increased the top federal corporate tax rate from 34 to 35 percent. The 35
percent rate was retroactively made effective January 1, 1993.
For the temporary differences that existed at January 1, 1993, the change in
the federal income tax rate increased the provision for income taxes and
accumulated deferred income taxes approximately $1.6 and $18.0 million,
respectively. Approximately $16.4 million of the increase which was applicable
to utility operations was recorded as income taxes recoverable from customers
through future rates and therefore had no impact on results of operations for
the year ended December 31, 1993.
For 1992, the provision for deferred income taxes was recorded primarily as
a result of the use of income tax law provisions which allowed for the
deduction or addition of items to taxable income in the tax return prior to or
after their being recorded on the books of the Company.
39
<PAGE> 42
--------------------------------------------------------------------------------
3. COMMON STOCK AND RETAINED EARNINGS
There were no new shares of common stock issued during 1994, 1993 or 1992.
The $37,000 decrease in 1994 and $21,000 increase in 1993 in premium on capital
stock, as presented on the Consolidated Statements of Capitalization,
represents the gains and losses associated with the issuance of common stock
pursuant to the Restricted Stock Plan.
RESTRICTED STOCK PLAN
The Company has a Restricted Stock Plan whereby certain employees may
periodically receive shares of the Company's common stock at the discretion of
the Board of Directors. The Company distributed 18,950, 18,687 and 18,631
shares of common stock during 1994, 1993 and 1992, respectively. The Company
also reacquired 11,040 and 1,235 shares in 1994 and 1993, respectively. The
shares distributed/reacquired in the reported periods were recorded as treasury
stock.
Changes in common stock were:
<TABLE>
<CAPTION>
(THOUSANDS) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
Shares outstanding January 1 . . . . . . . . . . . . . . . . . . . 40,346 40,329 40,310
Issued/reacquired under the Restricted Stock Plan, net . . . . . . 8 17 19
----------------------------------------------------------------------------------------------------------------------
Shares outstanding December 31 . . . . . . . . . . . . . . . . . . 40,354 40,346 40,329
======================================================================================================================
</TABLE>
There were 4,009,021 shares of unissued common stock reserved for the
various employee and Company stock plans at December 31, 1994. 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 is amortizing approximately $14.0 million of costs relating to
obtaining such amendments over the remaining life of the respective bond
issues. At the end of 1994, there was approximately $10.4 million in
unamortized costs associated with obtaining these amendments.
SHAREOWNERS RIGHTS PLAN
In December 1990, the Company adopted a Shareowners Rights Plan designed to
protect shareowners' interests in the event that the Company is ever confronted
with an unfair or inadequate acquisition proposal. Pursuant to the plan, the
Company declared a dividend distribution of one "right" for each share of
Company common stock. Each right entitles the holder to purchase from the
Company one one-hundredth of a share of new preferred stock of the Company
under certain circumstances. The rights may be exercised if a person or group
announces its intention to acquire, or does acquire, 20 percent or more of the
Company's common stock. Under certain circumstances, the holders of the rights
will be entitled to purchase either shares of common stock of the Company or
common stock of the acquirer at a reduced percentage of market value. The
rights will expire on December 11, 2000.
--------------------------------------------------------------------------------
4. CUMULATIVE PREFERRED STOCK
Preferred stock is redeemable at the option of OG&E at the following amounts
per share plus accrued dividends: the 4% Cumulative Preferred Stock at the par
value of $20 per share; the Cumulative Preferred Stock, par value $100 per
share, as follows: 4.20% series-$102; 4.24% series-$102.875; 4.44% series-$102;
4.80% series-$102; and 5.34% series-$101.
As approved by shareowners on May 16, 1991, the Restated Certificate of
Incorporation was amended to permit the issuance of new series of preferred
stock with dividends payable other than quarterly.
40
<PAGE> 43
--------------------------------------------------------------------------------
5. LONG-TERM DEBT
OG&E's Trust Indenture, as supplemented, relating to the First Mortgage
Bonds, requires OG&E to pay to the trustee annually, an amount sufficient to
redeem, for sinking fund purposes, 1 1/4% of the highest amount outstanding at
any time. This requirement has been satisfied by pledging permanent additions
to property to the extent of 166 2/3% of principal amounts of bonds otherwise
required to be redeemed. Through December 31, 1994, gross property additions
pledged totaled approximately $355 million.
Annual sinking fund requirements for each of the five years subsequent to
December 31, 1994, are as follows:
<TABLE>
<CAPTION>
Year Amount
===========================================================================================
<S> <C>
1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 14,593,750
1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 14,593,750
1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 14,281,250
1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 13,760,417
1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 13,500,000
===========================================================================================
</TABLE>
As in prior years, OG&E expects to meet these requirements by pledging
permanent additions to property.
In January 1995, OG&E refinanced its obligations with respect to $47,000,000
of 5 7/8% Pollution Control Revenue Bonds due December 1, 2007 and $32,050,000
of 6 3/4% Pollution Control Revenue Bonds due March 1, 2006 through the
issuance of two new series of pollution control bonds bearing interest at
variable, tax-exempt rates and are due January 1, 2025. The 5 7/8% Series and
the 6 3/4% Series Bonds will be called March 1, 1995.
In August 1994, Enogex redeemed its $90 million of outstanding medium-term
notes, with interest rates ranging from 9.88% to 10.11%. As of December 31,
1994, Enogex long-term debt consisted of a $6.9 million, variable interest rate
note, maturing July 31, 2001. At December 31, 1994, the interest rate was 8
1/4%.
Maturities of First Mortgage Bonds during the next five years consist of $25
million in 1995, $15 million in 1997, $25 million in 1998 and $12.5 million in
1999.
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, 1994.
--------------------------------------------------------------------------------
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 1994 were $220.0 million and
$130.6 million, respectively, at a weighted average interest rate of 4.76%. The
weighted average interest rates for 1993 and 1992 were 3.60% and 4.30%,
respectively. OG&E has an agreement for a flexible line of credit, up to $200
million, through December 31, 1997. The line of credit which was nominated by
OG&E at $160 million at year-end is maintained on a fee basis of 1/8 of 1%, per
year, on the unused balance. Enogex has a line of credit, up to $90 million,
through July 31, 1995. The Enogex line of credit is maintained on a fee basis
of LIBOR plus 1/2 of 1%, and a facility fee of 1/8 of 1% per year. Short-term
debt in the amount of $182.8 million was outstanding at December 31, 1994, of
which approximately $90 million pertained to debt incurred in connection with
Enogex's refinancing of its medium-term notes.
--------------------------------------------------------------------------------
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 Oklahoma Commission directed the Company to defer the
one-time costs which had not been offset by labor savings through December 31,
1994. The remaining balance of the one-time costs will be amortized over 26
months. The components of the severance and VERP costs and the amount deferred
are as follows:
41
<PAGE> 44
<TABLE>
<CAPTION>
SFAS SFAS
(DOLLARS IN THOUSANDS) NO. 88 NO. 106 SEVERANCE TOTAL
========================================================================================================
<S> <C> <C> <C> <C>
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (48,903)
--------------------------------------------------------------------------------------------------------
Postemployment Costs
Recognized as Restructuring in 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . 14,519
Consulting Fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,750
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,766
--------------------------------------------------------------------------------------------------------
1994 Restructuring Expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 21,035
========================================================================================================
</TABLE>
The restructuring charges reflected above, include only costs that were
actually incurred in 1994.
PENSION PLAN
All eligible employees of the Company are covered by a non-contributory
defined benefit pension plan. Under the plan, retirement benefits are primarily
a function of both the years of service and the highest average monthly
compensation for 60 consecutive months out of the last 120 months of service.
It is the Company's policy to fund the plan on a current basis to comply
with the minimum required contributions under existing tax regulations. Such
contributions are intended to provide not only for benefits attributed to
service to date, but also for those expected to be earned in the future.
Net periodic pension cost is computed in accordance with provisions of SFAS
No. 87, "Employers' Accounting for Pensions," and is recorded in the
accompanying Consolidated Statements of Income as Other operation.
In determining the projected benefit obligation, the weighted average
discount rate used was 8.25%, 7.25% and 8.5% for 1994, 1993 and 1992,
respectively. The assumed rate of increase in future salary levels was 4.5% in
1994 and 1993 and 5.5% in 1992. The expected long-term rate of return on assets
used in determining net periodic pension cost was 9.0% for the reported
periods.
The plan's assets consist primarily of U. S. Government securities, listed
common stocks and corporate debt.
Net periodic pension costs for 1994, 1993 and 1992 included the following:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1994 1993 1992
================================================================================================================
<S> <C> <C> <C>
Service costs-benefits earned during year . . . . . . . . $ 7,824 $ 7,630 $ 7,266
Interest cost on projected benefit obligation . . . . . . 17,851 14,557 13,657
Return on plan assets . . . . . . . . . . . . . . . . . . (17,510) (15,697) (14,761)
Net amortization and deferral . . . . . . . . . . . . . . (1,263) (1,263) (1,263)
Amortization of unrecognized prior service cost . . . . . 1,489 671 671
----------------------------------------------------------------------------------------------------------------
Net periodic pension cost . . . . . . . . . . . . . . $ 8,391 $ 5,898 $ 5,570
================================================================================================================
</TABLE>
The following table sets forth the plan's funded status at December 31, 1994,
1993 and 1992:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1994 1993 1992
================================================================================================================
<S> <C> <C> <C>
Projected benefit obligation:
Vested benefits . . . . . . . . . . . . . . . . . . . $(208,438) $(140,958) $(113,072)
Nonvested benefits . . . . . . . . . . . . . . . . . . (14,664) (21,435) (17,709)
----------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation . . . . . . . . . . . . (223,102) (162,393) (130,781)
Effect of future compensation levels . . . . . . . . . (29,425) (51,196) (47,632)
----------------------------------------------------------------------------------------------------------------
Projected benefit obligation . . . . . . . . . . . . . . (252,527) (213,589) (178,413)
Plan's assets at fair value . . . . . . . . . . . . . . . 177,045 194,501 176,891
----------------------------------------------------------------------------------------------------------------
Plan's assets less than projected benefit obligation . . (75,482) (19,088) (1,522)
Unrecognized prior service cost . . . . . . . . . . . . . 43,250 7,942 8,613
Unrecognized net asset from application of SFAS No. 87 . (8,842) (10,106) (11,369)
Unrecognized net (gain) loss . . . . . . . . . . . . . . (900) 14,448 281
----------------------------------------------------------------------------------------------------------------
Accrued pension liability . . . . . . . . . . . . . . . . $ (41,974) $ (6,804) $ (3,997)
================================================================================================================
</TABLE>
42
<PAGE> 45
POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
In addition to providing pension benefits, the Company provides certain
medical and life insurance benefits for retired members ("postretirement
benefits"). Employees retiring from the Company on or after attaining age 55
who have met certain length of service requirements are entitled to these
benefits. The benefits are subject to deductibles, co-payment provisions and
other limitations. Prior to January 1, 1993, the costs of retiree medical and
life insurance benefits were recognized as expense when claims were paid
("pay-as-you-go"). Pay-as-you-go costs totaled approximately $4,621,000,
$3,804,000 and $3,443,000 for 1994, 1993 and 1992, respectively.
The Company adopted the provisions of SFAS No. 106 beginning January 1, 1993.
This standard requires that employers accrue the cost of postretirement
benefits during the active service periods of employees until the date they
attain full eligibility for the benefits.
During 1993, OG&E expensed "pay-as-you-go" postretirement benefits and
recorded a deferral for the difference between pay-as-you-go and SFAS No. 106
requirements. The February 25, 1994, Oklahoma Commission rate order directed
OG&E to recover postretirement benefit costs following the pay-as-you-go method
and to defer the incremental cost associated with accrual recognition of SFAS
No. 106 related costs following a "phase-in" plan. Accordingly, OG&E recorded a
regulatory asset for the difference between the amounts using the pay-as-you-go
method (adjusted for the phase-in plan) and those required by SFAS No. 106.
A decision was made in the second quarter of 1994 to discontinue deferral of
the differential and to charge to expense $8.4 million of postretirement
benefits that had been recorded as a regulatory asset. Although OG&E continues
to believe that it could have recovered these costs in future rate proceedings
before the Oklahoma Commission, OG&E decided to recognize these expenses
currently, due to its strategy to reduce its cost-structure, which minimizes
future revenue requirements. OG&E expects to continue charging to expense the
SFAS No. 106 costs and to include an annual amount as a component of
cost-of-service in future ratemaking proceedings.
Net postretirement benefit expense for the years ended December 31, 1994 and
December 31, 1993, included the following components:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1994 1993
==============================================================================================
<S> <C> <C>
Service cost. . . . . . . . . . . . . . . . . . . . . . . . . $ 2,714 $ 2,812
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . 5,978 6,158
Net amortization . . . . . . . . . . . . . . . . . . . . . . 3,549 3,687
Net amount capitalized or deferred . . . . . . . . . . . . . (4,557) (8,853)
Discontinued deferral of regulatory asset . . . . . . . . . . 8,359 --
----------------------------------------------------------------------------------------------
Net postretirement benefit expense . . . . . . . . . . . . . $ 16,043 $ 3,804
==============================================================================================
</TABLE>
The discount rate used in determining the accumulated postretirement benefit
obligation was 8.25%, 7.25% and 8.5% for December 31, 1994, December 31, 1993
and January 1, 1993, respectively. The rate of increase in future compensation
levels used in measuring the life insurance accumulated postretirement benefit
obligation was 4.5% for December 31, 1994 and December 31, 1993 and 5.5% for
January 1, 1993. A 12.0 percent annual rate of increase in the per capita cost
of covered health care benefits was assumed for 1994; the rate is assumed to
decrease gradually to 4.5% 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, 1994 by approximately $7.3 million, and the aggregate of the
service and interest cost components of net postretirement health care cost for
1994 by approximately $1.0 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, 1994 and December 31, 1993:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) DEC 31, 1994 DEC 31, 1993 JAN 1, 1993
================================================================================================================
<S> <C> <C> <C>
Accumulated postretirement benefit obligation:
Retirees . . . . . . . . . . . . . . . . . . . . . . . . $ (81,688) $ (42,891) $ (45,152)
Actives eligible to retire . . . . . . . . . . . . . . . (2,716) (17,479) (15,341)
Actives not yet eligible to retire . . . . . . . . . . . (7,870) (15,622) (13,241)
----------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . (92,274) (75,992) (73,734)
Plan assets at fair value . . . . . . . . . . . . . . . . 17,279 -- --
----------------------------------------------------------------------------------------------------------------
Funded status . . . . . . . . . . . . . . . . . . . . . . (74,995) (75,992) (73,734)
Unrecognized transition obligation . . . . . . . . . . . . 49,483 70,047 73,734
Unrecognized net actuarial gain . . . . . . . . . . . . . (2,930) (2,908) --
----------------------------------------------------------------------------------------------------------------
Accrued postretirement benefit obligation . . . . . . . . $ (28,442) $ (8,853) $ --
================================================================================================================
</TABLE>
43
<PAGE> 46
POSTEMPLOYMENT BENEFITS
In November 1992, the FASB issued SFAS No. 112, "Employers' Accounting for
Postemployment Benefits," which requires the accrual of the estimated cost of
benefits provided to former or inactive employees after employment but before
retirement. The Company adopted this new standard effective January 1, 1994,
recording $4.7 million of postemployment benefits cost for the year.
--------------------------------------------------------------------------------
8. REPORT OF BUSINESS SEGMENTS
The Company's electric utility segment is an operating public utility
engaged in the generation, transmission, distribution and sale of electric
energy. The non-utility subsidiary segment is engaged in the gathering and
transmission of natural gas, and through its subsidiaries, is engaged in the
processing of natural gas and the marketing of natural gas liquids, in the
buying and selling of natural gas to third parties, and in the exploration for
and production of natural gas and related products.
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
Operating Information:
Operating Revenues
Electric utility . . . . . . . . . . . . . . . . . . . . . . . $ 1,196,898 $ 1,282,816 $1,193,993
Non-utility subsidiary . . . . . . . . . . . . . . . . . . . . 203,079 219,376 189,574
Intersegment revenues (A) . . . . . . . . . . . . . . . . . . . (44,809) (54,940) (68,583)
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,355,168 $ 1,447,252 $1,314,984
======================================================================================================================
Pre-tax Operating Income
Electric utility . . . . . . . . . . . . . . . . . . . . . . . $ 248,827 $ 238,761 $ 206,350
Non-utility subsidiary. . . . . . . . . . . . . . . . . . . . . 23,710 28,531 30,860
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 272,537 $ 267,292 $ 237,210
======================================================================================================================
Net Income
Electric utility . . . . . . . . . . . . . . . . . . . . . . . $ 113,795 $ 104,730 $ 88,293
Non-utility subsidiary . . . . . . . . . . . . . . . . . . . . 9,990 9,547 11,419
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 123,785 $ 114,277 $ 99,712
======================================================================================================================
Investment Information:
Identifiable Assets as of December 31
Electric utility . . . . . . . . . . . . . . . . . . . . . . . $ 2,471,902 $ 2,443,651 $2,358,661
Non-utility subsidiary . . . . . . . . . . . . . . . . . . . . 310,727 287,773 231,422
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,782,629 $ 2,731,424 $2,590,083
======================================================================================================================
Other Information:
Depreciation
Electric utility . . . . . . . . . . . . . . . . . . . . . . . $ 107,239 $ 104,343 $ 100,531
Non-utility subsidiary . . . . . . . . . . . . . . . . . . . . 19,138 15,200 10,169
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 126,377 $ 119,543 $ 110,700
======================================================================================================================
Construction Expenditures
Electric utility . . . . . . . . . . . . . . . . . . . . . . . $ 104,256 $ 105,746 $ 109,650
Non-utility subsidiary . . . . . . . . . . . . . . . . . . . . 45,634 22,396 30,601
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 149,890 $ 128,142 $ 140,251
======================================================================================================================
</TABLE>
(A) Intersegment revenues are recorded at prices comparable to those of
unaffiliated customers and are affected by regulatory considerations.
44
<PAGE> 47
--------------------------------------------------------------------------------
9. COMMITMENTS AND CONTINGENCIES
The Company has entered into purchase commitments in connection with its
construction program and the purchase of necessary fuel supplies of coal and
natural gas for its generating units. The Company's construction expenditures
for 1995 are estimated at $89 million.
The Company acquires natural gas for boiler fuel under 738 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, 1994, 1993 and 1992, outstanding prepayments for gas, including the amounts
classified as current assets, under these contracts were approximately
$10,879,000, $22,165,000 and $24,543,000, 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, 1994, the Company held non-cancelable operating leases
covering approximately 1,500 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:
<TABLE>
<CAPTION>
(dollars in thousands)
<S> <C> <C> <C>
1995 . . . . . . . . $ 5,530 1998 . . . . . . . . . . $ 5,214
1996 . . . . . . . . 5,425 1999 . . . . . . . . . . 5,108
1997 . . . . . . . . 5,319 2000 and beyond . . . . . 110,012
---------
Total Minimum Lease Payments . . . . . . . . . . . . . . . . . . . . $ 136,608
=========
</TABLE>
Rental payments under operating leases were approximately $5.6 million in
1994, $4.9 million in 1993 and $3.6 million in 1992.
OG&E is required to maintain the railcars it has under lease to transport
coal from Wyoming and has entered into an agreement with Railcar Maintenance
Company, a non-affiliated company, to furnish this maintenance.
The Company has entered into an agreement with an unrelated third party to
develop a natural gas storage facility. Pursuant to that agreement, the
Company made cash advances to the developer amounting to approximately $38.8
million, as of December 31, 1994, which is included in Prepayments and other on
the accompanying Consolidated Balance Sheets. Upon completion of the storage
facility, it is anticipated that the developer will obtain alternative
financing for the project and repay the cash advances. OG&E will utilize the
facility on a fee basis.
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 Oklahoma Commission. The rate generally
consists of two components: one is a rate for actual electricity purchased from
the QF by the Company; the other is a capacity charge which the Company must
pay the QF for having the capacity available. However, if no electrical power
is made available to the Company for a period of time (generally three months),
the Company's obligation to pay the capacity charge is suspended. The total
cost of cogeneration payments is currently recoverable in rates from Oklahoma
customers.
During 1994, 1993 and 1992, OG&E made total payments to cogenerators of
approximately $210.3 million, $213.0 million and $179.4 million, of which
$173.2 million, $165.5 million and $101.6 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: 1995 - $174 million, 1996 - $175 million, 1997 - $176
million, 1998 - $184 million and 1999 - $189 million.
Approximately $7.4 million of the Company's construction expenditures
budgeted for 1995 are to comply with environmental laws and regulations.
The Company continues to explore options to comply with the Clean Air Act
Amendments of 1990 ("CAAA"). Since all of OG&E's coal-fired generating units
currently burn low-sulfur coal, OG&E will not need to take any steps to comply
with the new sulfur dioxide emission limits until January 1, 2000. In
compliance with Title IV of the CAAA, the Company has completed installation of
continuous emission monitors ("CEMs") on each of its five coal-fired generating
units and three of its 12 gas-fired generating units. Expenditures on CEMs in
1994 totaled approximately $6 million. The Environmental Protection Agency
("EPA") established a time extension for installation of CEMs on gas-fired
45
<PAGE> 48
units which allowed the Company to defer CEM installation on the remaining nine
units subject to the requirements of Title IV. Completion of this project is
expected to cost approximately $1million during 1995. The CAAA Title V
operating permits are expected to cost approximately $400,000 in 1995.
The CAAA will also regulate emissions of nitrogen oxides and certain air
toxic compounds. Although final regulations concerning all of these issues have
not been written, additional capital expenditures may be necessary in future
years. The Company will continue to examine all alternatives to comply with
the CAAA as part of its Integrated Resource Planning process. This planning
approach will assure the Company employs the least cost option to comply with
the CAAA and be in a competitive position to market its services.
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. The Company has calculated
that its portion of total waste disposed at the sites is relatively minor. The
cost of complying with the EPA sanctions at these sites is difficult to
estimate. However, based on the relative percentage attributed to the Company
and other considerations, management believes the ultimate outcome of these
matters will not have a material adverse effect on the Company's consolidated
financial position or results of operations.
In 1992, OG&E began a voluntary review of information contained in the
annual report required under the Toxic Substance Control Act ("TSCA") for 1991.
The initial result of the review revealed some discrepancies in operating
practices and documentation. The EPA was notified of these initial
discrepancies in December 1992. Because it was suspected that additional
discrepancies might be discovered during the continuing review/audit, OG&E
reached an agreement on January 12, 1993, with the EPA, Region VI, concerning
the notification and reporting requirements of any newly discovered
discrepancies.
After further investigation, OG&E reported in September 1993 numerous
additional discrepancies to the EPA, Region VI. Many of the discrepancies
could be deemed violations of the regulations under TSCA. Under the TSCA
regulations, the EPA has the authority to assess a maximum fine of up to
$25,000 per day, and to treat each day of violation as the basis for a separate
fine. OG&E has taken and is taking corrective action to remedy the
discrepancies.
The position of the EPA and OG&E is that they are currently in
pre-settlement negotiations. Since this matter is currently being negotiated,
OG&E does not know the amount of fines that the EPA may seek. The amount of the
fine is dependent upon numerous interpretative issues under the TSCA
regulations and potentially could be significant to the Company's results of
operations. However, at the present time, the Company does not expect that the
amount of the fine will have a material effect on its results of operations
based primarily on having voluntarily reported the discrepancies to the EPA
coupled with the Company's efforts to remedy the discrepancies and the lack of
releases into the environment or harm to individuals.
In the normal course of business, other lawsuits, claims, environmental
actions, and other governmental proceedings arise against the Company.
Management, after consultation with legal counsel, does not anticipate that
liabilities arising out of other currently pending or threatened lawsuits and
claims will have a material adverse effect on the Company's consolidated
financial position or results of operations.
--------------------------------------------------------------------------------
10. RATE MATTERS AND REGULATION
On February 25, 1994, the Oklahoma Commission issued an order that, among
other things, lowered OG&E's rates to its Oklahoma retail customers by
approximately $14 million annually (based on a test year ended June 30, 1991)
and required OG&E to refund approximately $41.3 million. The $14 million annual
reduction in rates was expected to lower OG&E's rates to its Oklahoma customers
by approximately $17 million annually. With respect to the $41.3 million
refund, $39.1 million was associated with revenues prior to January 1, 1994,
while the remaining $2.2 million related to 1994.
During the first half of 1992 the Company participated in settlement
negotiations and offered a proposed refund and a reduction in rates in an
effort to reach settlement and conclude the proceedings. As a result, the
Company recorded an $18 million provision for a potential refund in 1992. After
receiving the February 25, 1994 order, the Company recorded an additional
provision for rate refund of approximately $21.1 million in 1993, (consisting of
a $14.9 million reduction in
46
<PAGE> 49
revenue and $6.2 million in interest) which reduced net income by some $13
million or $0.32 per share.
Enogex transports natural gas to OG&E for use at its gas-fired generating
units and performs related gas gathering activities for OG&E. The entire $41.3
million refund relates to the Oklahoma Commission's disallowance of a portion
of the fees paid by OG&E to Enogex for such services in the past. Of the
approximately $17 million annual rate reduction, approximately $9.9 million
reflects the Oklahoma Commission's reduction of the amount to be recovered by
OG&E from its Oklahoma customers for the future performance of such services by
Enogex.
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 Voluntary Early Retirement Package ("VERP") and enhanced severance
package. Pending an Oklahoma Commission order, OG&E deferred these costs;
however, between August 1, and December 31, 1994, the amount deferred was
reduced by approximately $14.5 million. In response to an application filed by
OG&E on August 9, 1994, the Oklahoma Commission issued an order on October 26,
1994, that permitted the Company to amortize the December 31, 1994, regulatory
asset of $48.9 million over 26 months and reduced OG&E's electric rates by
approximately $15 million annually, effective January 1995. The Company
anticipates that labor savings from the VERP and severance package will
substantially offset the amortization of the regulatory asset and annual rate
reduction of $15 million.
The components of Deferred Charges - Other, on the Consolidated Balance
Sheets included the following, as of December 31:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
Regulatory asset (restructuring) . . . . . . . . . . . . . . . . . $ 48,903 $ -- $ --
Unamortized debt expense . . . . . . . . . . . . . . . . . . . . . 12,871 14,146 15,462
Enogex gas sales contracts . . . . . . . . . . . . . . . . . . . . 12,690 -- --
Unamortized loss on reacquired debt . . . . . . . . . . . . . . . . 5,487 5,711 5,935
Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,391 24,398 16,330
----------------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 92,342 $ 44,255 $ 37,727
======================================================================================================================
</TABLE>
Regulatory Assets and Liabilities consisted of the following as of
December 31:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1994 1993 1992
======================================================================================================================
<S> <C> <C> <C>
Regulatory Assets:
Income Taxes Recoverable from Customers . . . . . . . . . . . . $ 151,086 $ 161,346 $ 44,387
Workforce Reduction . . . . . . . . . . . . . . . . . . . . . . 48,903 -- --
Miscellaneous. . . . . . . . . . . . . . . . . . . . . . . . . . 2,214 12,090 5,453
----------------------------------------------------------------------------------------------------------------------
Total Regulatory Assets . . . . . . . . . . . . . . . . . . . 202,203 173,436 49,840
Regulatory Liabilities:
Income Taxes Refundable to Customers . . . . . . . . . . . . . . (103,840) (113,753) (44,387)
Gain on Disposition of Allowances . . . . . . . . . . . . . . . (187) (79) --
----------------------------------------------------------------------------------------------------------------------
Net Regulatory Assets . . . . . . . . . . . . . . . . . . . . . . . $ 98,176 $ 59,604 $ 5,453
======================================================================================================================
</TABLE>
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.
47
<PAGE> 50
--------------------------------------------------------------------------------
11. DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments:
CASH AND CASH EQUIVALENTS AND CUSTOMER DEPOSITS
The fair value of cash and cash equivalents and customer deposits
approximate the carrying amount due to their short maturity.
CAPITALIZATION
The fair value of Long-term Debt and Preferred Stocks is estimated based on
quoted market prices and management's estimate of current rates available for
similar issues. The fair value of the Enogex Notes is based on management's
estimate of current rates available for similar issues with the same remaining
maturities.
Indicated below are the carrying amounts and estimated fair values of the
Company's financial instruments as of December 31:
<TABLE>
<CAPTION>
1994 1993 1992
------------------ -------------------- -------------------
CARRYING FAIR CARRYING FAIR CARRYING FAIR
(DOLLARS IN THOUSANDS) AMOUNT VALUE AMOUNT VALUE AMOUNT VALUE
=================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
ASSETS:
CASH AND CASH EQUIVALENTS . . . . . $ 2,455 $ 2,455 $ 6,593 $ 6,593 $ 11,316 $ 11,316
=================================================================================================================
LIABILITIES:
CUSTOMER DEPOSITS . . . . . . . . . . $ 20,904 $ 20,904 $ 19,353 $ 19,353 $ 17,891 $ 17,891
=================================================================================================================
CAPITALIZATION:
First Mortgage Bonds . . . . . . . . $ 716,967 $ 710,523 $ 716,610 $ 749,684 $ 731,254 $ 740,755
Industrial Trust Bonds . . . . . . . 32,050 32,044 32,400 32,604 32,700 32,746
Enogex Inc. Notes . . . . . . . . . 6,900 6,900 90,000 100,486 90,000 95,715
Preferred Stock:
4% Series through 5.34% Series--
838,663 Shares outstanding . . . . 49,973 27,442 49,973 34,523 49,973 31,332
-----------------------------------------------------------------------------------------------------------------
Total . . . . . . . . . . . . . . . $ 805,890 $ 776,909 $ 888,983 $ 917,297 $ 903,927 $ 900,548
=================================================================================================================
</TABLE>
On January 1, 1994, SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities," became effective. This did not have a material
adverse impact on the Company's consolidated financial position or results of
operations.
48
<PAGE> 51
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE SHAREOWNERS OF
OKLAHOMA GAS AND ELECTRIC COMPANY:
We have audited the accompanying consolidated balance sheets and statements
of capitalization of Oklahoma Gas and Electric Company (an Oklahoma corporation)
and its subsidiaries as of December 31, 1994, 1993 and 1992, 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, 1994, 1993 and 1992, and the
results of their operations and their cash flows for the years then ended in
conformity with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma,
January 26, 1995
REPORT OF MANAGEMENT
TO OUR SHAREOWNERS:
The management of Oklahoma Gas and Electric Company and its subsidiaries has
prepared, and is responsible for the integrity and objectivity of the financial
and operating information contained in this Annual Report. The consolidated
financial statements have been prepared in accordance with generally accepted
accounting principles and include certain amounts that are based on the best
estimates and judgments of management.
To meet its responsibility for the reliability of the consolidated financial
statements and related financial data, the Company's management has established
and maintains an internal control structure. This structure provides management
with reasonable assurance in a cost-effective manner that, among other things,
assets are properly safeguarded and transactions are executed and recorded in
accordance with its authorizations so as to permit preparation of financial
statements in accordance with generally accepted accounting principles. The
Company's internal auditors assess the effectiveness of this internal control
structure and recommend possible improvements thereto on an ongoing basis.
The Company maintains high standards in selecting, training and developing
its members. This, combined with Company policies and procedures, provides
reasonable assurance that operations are conducted in conformity with
applicable laws and with its commitment to the highest standards of business
conduct.
49
<PAGE> 52
SUPPLEMENTARY DATA
Interim Consolidated Financial Information (Unaudited)
In the opinion of the Company, the following quarterly information
includes all adjustments, consisting of normal recurring adjustments, necessary
for a fair statement of the results of operations for such periods:
<TABLE>
<CAPTION>
Quarter ended (dollars in thousands except Dec 31 Sep 30 Jun 30 Mar 31
per share data)
------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues ........................ 1994 $281,388 $443,173 $346,623 $283,984
1993 301,392 500,639 341,799 303,422
1992 304,093 443,327 306,341 261,223
------------------------------------------------------------------------------------------------------------
Operating income ......................... 1994 $ 23,792 $105,563 $ 50,427 $ 20,684
1993 18,899 111,576 39,457 25,221
1992 32,043 94,319 36,072 14,570
------------------------------------------------------------------------------------------------------------
Net income (loss) .......................... 1994 $ 4,952 $ 86,251 $ 31,082 $ 1,500
1993 (3,619) 90,810 20,396 6,690
1992 10,629 76,035 17,015 (3,967)
------------------------------------------------------------------------------------------------------------
Earnings (loss) available for common ....... 1994 $ 4,372 $ 85,672 $ 30,503 $ 921
1993 (4,199) 90,231 19,817 6,111
1992 10,050 75,456 16,436 (4,547)
------------------------------------------------------------------------------------------------------------
Earnings (loss) per average common share ... 1994 $ 0.11 $ 2.12 $ 0.76 $ 0.02
1993 (0.10) 2.24 0.49 0.15
1992 0.25 1.87 0.41 (0.11)
------------------------------------------------------------------------------------------------------------
</TABLE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.
Not Applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
ITEM 11. EXECUTIVE COMPENSATION.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Items 10, 11, 12 and 13 are omitted pursuant to General Instruction G
of Form 10-K, since OG&E filed copies of a definitive proxy statement with the
Securities and Exchange Commission on or about March 29, 1995. Such proxy
statement is incorporated herein by reference. In accordance with Instruction
G of
50
<PAGE> 53
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, 1994, 1993 and 1992
o Consolidated Statements of Income for the years ended December 31, 1994,
1993 and 1992
o Consolidated Statements of Retained Earnings for the years ended December
31, 1994, 1993 and 1992
o Consolidated Statements of Capitalization at December 31, 1994, 1993 and
1992
o Consolidated Statements of Cash Flows for the years ended December 31,
1994, 1993 and 1992
o Notes to Consolidated Financial Statements
o Report of Independent Public Accountants
o Report of Management
SUPPLEMENTARY DATA
o Interim Consolidated Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE
----
Schedule II - Valuation and qualifying accounts 59
Report of Independent Public Accountants 60
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.
51
<PAGE> 54
3. EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
----------- -----------
<S> <C>
3.01 Copy of Restated Certificate of Incorporation.
(Filed as Exhibit 4.01 to the Company's Post-
Effective Amendment No. Three to Registration
Statement No. 2-94973, and incorporated by
reference herein)
3.02 By-laws. (Filed as Exhibit 4.02 to Post-Effective
Amendment No. Three to Registration Statement No.
2-94973 and incorporated by reference herein)
4.01 Copy of Trust Indenture, dated February 1, 1945,
from OG&E to The First National Bank and Trust Company
of Oklahoma City, Trustee. (Filed as Exhibit 7-A to
Registration Statement No. 2-5566 and incorporated by
reference herein)
4.02 Copy of Supplemental Trust Indenture, dated
December 1, 1948, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 7.03 to Registration Statement No.
2-7744 and incorporated by reference herein)
4.03 Copy of Supplemental Trust Indenture, dated
June 1, 1949, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.03
to Registration Statement No. 2-7964 and
incorporated by reference herein)
4.04 Copy of Supplemental Trust Indenture, dated
May 1, 1950, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.04
to Registration Statement No. 2-8421 and
incorporated by reference herein)
4.05 Copy of Supplemental Trust Indenture, dated
March 1, 1952, a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to
Registration Statement No. 2-9415 and
incorporated by reference herein)
</TABLE>
52
<PAGE> 55
<TABLE>
<S> <C>
4.06 Copy of Supplemental Trust Indenture, dated
June 1, 1955, being a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.07 to
Registration Statement No. 2-12274 and
incorporated by reference herein)
4.07 Copy of Supplemental Trust Indenture, dated
January 1, 1957, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.07
to Registration Statement No. 2-14115 and
incorporated by reference herein)
4.08 Copy of Supplemental Trust Indenture, dated
June 1, 1958, being a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.09 to
Registration Statement No. 2-19757 and
incorporated by reference herein)
4.09 Copy of Supplemental Trust Indenture, dated
March 1, 1963, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.09
to Registration Statement No. 2-23127 and
incorporated by reference herein)
4.10 Copy of Supplemental Trust Indenture, dated
March 1, 1965, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.10
to Registration Statement No. 2-25808 and
incorporated by reference herein)
4.11 Copy of Supplemental Trust Indenture, dated
January 1, 1967, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.11
to Registration Statement No. 2-27854 and
incorporated by reference herein)
4.12 Copy of Supplemental Trust Indenture, dated
January 1, 1968, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.12
to Registration Statement No. 2-31010 and
incorporated by reference herein)
4.13 Copy of Supplemental Trust Indenture, dated
January 1, 1969, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.13
to Registration Statement No. 2-35419 and
incorporated by reference herein)
</TABLE>
53
<PAGE> 56
<TABLE>
<S> <C>
4.14 Copy of Supplemental Trust Indenture, dated
January 1, 1970, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.14
to Registration Statement No. 2-42393 and
incorporated by reference herein)
4.15 Copy of Supplemental Trust Indenture, dated
January 1, 1972, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.15
to Registration Statement No. 2-49612 and
incorporated by reference herein)
4.16 Copy of Supplemental Trust Indenture, dated
January 1, 1974, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.16
to Registration Statement No. 2-52417 and
incorporated by reference herein)
4.17 Copy of Supplemental Trust Indenture, dated
January 1, 1975, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.17
to Registration Statement No. 2-55085 and
incorporated by reference herein)
4.18 Copy of Supplemental Trust Indenture, dated
January 1, 1976, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.18
to Registration Statement No. 2-57730 and
incorporated by reference herein)
4.19 Copy of Supplemental Trust Indenture, dated
September 14, 1976, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 2.19 to Registration Statement No.
2-59887 and incorporated by reference herein)
4.20 Copy of Supplemental Trust Indenture, dated
January 1, 1977, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.20
to Registration Statement No. 2-59887 and
incorporated by reference herein)
4.21 Copy of Supplemental Trust Indenture, dated
November 1, 1977, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.21 to Registration Statement No.
2-70539 and incorporated by reference herein)
</TABLE>
54
<PAGE> 57
<TABLE>
<S> <C>
4.22 Copy of Supplemental Trust Indenture, dated
December 1, 1977, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.22 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.23 Copy of Supplemental Trust Indenture, dated
February 1, 1980, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.23 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.24 Copy of Supplemental Trust Indenture, dated
April 15, 1982, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.24
to the Company's Form 10-K Report, File No. 1-1097,
for the year ended December 31, 1982, and incorporated
by reference herein)
4.25 Copy of Supplemental Trust Indenture, dated
August 15, 1986, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.25
to the Company's Form 10-K Report, File No. 1-1097,
for the year ended December 31, 1986 and incorporated
by reference herein)
4.26 Copy of Supplemental Trust Indenture, dated
March 1, 1987, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.26
to the Company's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
4.28 Copy of Supplemental Trust Indenture, dated
November 15, 1990, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.28
to the Company's Form 10-K Report for the year
ended December 31, 1990, File No. 1-1097, and
incorporated by reference herein)
4.29 Copy of Supplemental Trust Indenture, dated
December 9, 1991, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.29 to
the Company's Form 10-K Report for the year ended
December 31, 1991, File No. 1-1097, and incorporated
by reference herein)
</TABLE>
55
<PAGE> 58
<TABLE>
<S> <C>
10.01 Coal Supply Agreement dated March 1, 1973, between
OG&E and Atlantic Richfield Company. (Filed as
Exhibit 5.19 to Registration Statement No. 2-59887
and incorporated by reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between OG&E
and Atlantic Richfield Company, together with
related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply
Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company. (Filed as Exhibit
5.28 to Registration Statement No. 2-62208 and
incorporated by reference herein)
10.04 Amendment dated June 27, 1990, between OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between OG&E and Atlantic
Richfield Company.
10.05 Participation Agreement dated as of January 1, 1980,
among First National Bank and Trust Company of
Oklahoma City, Thrall Car Manufacturing Company,
OG&E and other parties, including Lease of Railroad
Equipment dated January 1, 1980, between
Mercantile-Safe Deposit and Trust Company and
OG&E. (Filed as Exhibit 10.32 to the Company's
Form 10-K Report for the year ended December 31,
1980, File No. 1-1097, and incorporated by reference
herein)
10.06 Participation Agreement dated January 1, 1981,
among The First National Bank and Trust Company
of Oklahoma City, Thrall Car Manufacturing Company,
OG&E and other parties, including Lease for
Railroad Equipment dated January 1, 1981, between
Wells Fargo Equipment Leasing Corporation and OG&E.
(Filed as Exhibit 20.01 to the Company's Form 10-Q
for June 30, 1981, File No. 1-1097, and incorporated
by reference herein)
10.08 Form of Amended and Restated Stock Equivalent and
Deferred Compensation Agreement for Directors, as amended.
</TABLE>
56
<PAGE> 59
<TABLE>
<S> <C>
10.09 Restricted Stock Plan of the Company. (Filed as Exhibit 10.36
to the Company's Form 10-K Report for the year ended
December 31, 1986, File No. 1-1097, and
incorporated by reference herein)
10.10 Agreement and Plan of Reorganization, dated May 14, 1986,
between OG&E and Mustang Fuel Corporation.
(Attached as Appendix A to Registration Statement
No. 33-7472 and incorporated by reference herein)
10.11 Gas Service Agreement dated January 1, 1988, between
OG&E and Oklahoma Natural Gas Company. (Filed as
Exhibit 10.26 to the Company's Form 10-K Report
for the year ended December 31, 1987, File No. 1-1097,
and incorporated by reference herein)
10.12 Company's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
10.13 Company's Restoration of Retirement Savings Plan.
(Filed as Exhibit 10.13 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
10.14 Gas Service Agreement dated July 23, 1987, between
OG&E and Arkla Services Company. (Filed as Exhibit
10.29 to the Company's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
10.15 Company's Supplemental Executive Retirement Plan.
(Filed as Exhibit 10.1 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
10.16 Company's Annual Incentive Compensation Plan.
(Filed as Exhibit 10.16 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097, and incorporated by reference herein)
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
</TABLE>
57
<PAGE> 60
<TABLE>
<S> <C>
99.01 1994 Form 11-K Annual Report for Oklahoma Gas
and Electric Company Employees' Retirement Savings Plan.
99.02 Description of Common Stock.
Executive Compensation Plans and Arrangements
10.08 Form of Amended and Restated Stock Equivalent and
Deferred Compensation Agreement for Directors, as amended.
10.09 Restricted Stock Plan of the Company. (Filed as Exhibit 10.36 to the
Company's Form 10-K Report for the year ended December 31,
1986, File No. 1-1097, and incorporated by reference herein)
10.12 Company's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to the Company's Form 10-K Report
for the year ended December 31, 1993, File No. 1-1097
and incorporated by reference herein)
10.13 Company's Restoration of Retirement Savings Plan.
(Filed as Exhibit 10.13 to the Company's Form 10-K Report
for the year ended December 31, 1993, File No. 1-1097
and incorporated by reference herein)
10.15 Company's Supplemental Executive Retirement Plan.
(Filed as Exhibit 10.15 to the Company's Form 10-K Report
for the year ended December 31, 1993, File No. 1-1097
and incorporated by reference herein)
10.16 Company's Annual Incentive Compensation Plan.
(Filed as Exhibit 10.16 to the Company's Form 10-K Report
for the year ended December 31, 1993, File No. 1-1097
and incorporated by reference herein)
</TABLE>
(B) REPORTS ON FORM 8-K
Item 5. Other Events, dated February 28, 1994.
Item 5. Other Events, dated April 29, 1994.
Item 5. Other Events, dated October 28, 1994.
58
<PAGE> 61
OKLAHOMA GAS AND ELECTRIC COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
BALANCE CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS YEAR
----------- ------------ --------------------------- ---------- --------
<S> <C> <C> <C> <C> <C>
(THOUSANDS)
1994
Reserve for Uncollectible Accounts $4,070 $6,767 - $7,118 $3,719
1993
Reserve for Uncollectible Accounts $4,039 $6,669 - $6,638 $4,070
1992
Reserve for Uncollectible Accounts $3,775 $7,549 - $7,285 $4,039
</TABLE>
59
<PAGE> 62
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 26, 1995. Our audits were made for the purpose of forming an opinion
on those statements taken as a whole. The schedule listed on Page 51, 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 26, 1995
60
<PAGE> 63
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 29th day of March, 1995.
OKLAHOMA GAS AND ELECTRIC COMPANY
(REGISTRANT)
/s/ J. G. Harlow Jr.
By J. G. Harlow Jr.
Chairman of the Board
and President
Pursuant to the requirements of the Securities Exchange Act of 1934,
as amended, this Report has been signed below by the following persons in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
---------------- --------------------- --------------
<S> <C>
/s/ J. G. Harlow Jr.
J. G. Harlow Jr. Principal Executive
Officer and Director; March 29, 1995
/s/ A. M. Strecker
A. M. Strecker Principal Financial
Officer; and March 29, 1995
/s/ D. L. Young
D. L. Young Principal Accounting
Officer. March 29, 1995
Herbert H. Champlin Director;
William E. Durrett Director;
Martha W. Griffin Director;
Hugh L. Hembree, III Director;
John F. Snodgrass Director;
Bill Swisher Director;
John A. Taylor Director; and
Ronald H. White, M.D. Director.
By J. G. Harlow Jr. (attorney-in-fact) March 29, 1995
/s/ J. G. Harlow Jr.
</TABLE>
61
<PAGE> 64
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
----------- -----------
<S> <C>
3.01 Copy of Restated Certificate of Incorporation.
(Filed as Exhibit 4.01 to the Company's Post-
Effective Amendment No. Three to Registration
Statement No. 2-94973, and incorporated by
reference herein)
3.02 By-laws. (Filed as Exhibit 4.02 to Post-Effective
Amendment No. Three to Registration Statement No.
2-94973 and incorporated by reference herein)
4.01 Copy of Trust Indenture, dated February 1, 1945,
from OG&E to The First National Bank and Trust Company
of Oklahoma City, Trustee. (Filed as Exhibit 7-A to
Registration Statement No. 2-5566 and incorporated by
reference herein)
4.02 Copy of Supplemental Trust Indenture, dated
December 1, 1948, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 7.03 to Registration Statement No.
2-7744 and incorporated by reference herein)
4.03 Copy of Supplemental Trust Indenture, dated
June 1, 1949, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.03
to Registration Statement No. 2-7964 and
incorporated by reference herein)
4.04 Copy of Supplemental Trust Indenture, dated
May 1, 1950, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 7.04
to Registration Statement No. 2-8421 and
incorporated by reference herein)
4.05 Copy of Supplemental Trust Indenture, dated
March 1, 1952, a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.08 to
Registration Statement No. 2-9415 and
incorporated by reference herein)
4.06 Copy of Supplemental Trust Indenture, dated
June 1, 1955, being a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.07 to
Registration Statement No. 2-12274 and
incorporated by reference herein)
4.07 Copy of Supplemental Trust Indenture, dated
January 1, 1957, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.07
to Registration Statement No. 2-14115 and
incorporated by reference herein)
4.08 Copy of Supplemental Trust Indenture, dated
June 1, 1958, being a supplemental instrument to
Exhibit 4.01 hereto. (Filed as Exhibit 4.09 to
Registration Statement No. 2-19757 and
incorporated by reference herein)
4.09 Copy of Supplemental Trust Indenture, dated
March 1, 1963, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.09
to Registration Statement No. 2-23127 and
incorporated by reference herein)
4.10 Copy of Supplemental Trust Indenture, dated
March 1, 1965, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.10
to Registration Statement No. 2-25808 and
incorporated by reference herein)
4.11 Copy of Supplemental Trust Indenture, dated
January 1, 1967, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.11
to Registration Statement No. 2-27854 and
incorporated by reference herein)
4.12 Copy of Supplemental Trust Indenture, dated
January 1, 1968, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.12
to Registration Statement No. 2-31010 and
incorporated by reference herein)
4.13 Copy of Supplemental Trust Indenture, dated
January 1, 1969, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.13
to Registration Statement No. 2-35419 and
incorporated by reference herein)
4.14 Copy of Supplemental Trust Indenture, dated
January 1, 1970, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.14
to Registration Statement No. 2-42393 and
incorporated by reference herein)
4.15 Copy of Supplemental Trust Indenture, dated
January 1, 1972, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.15
to Registration Statement No. 2-49612 and
incorporated by reference herein)
4.16 Copy of Supplemental Trust Indenture, dated
January 1, 1974, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.16
to Registration Statement No. 2-52417 and
incorporated by reference herein)
4.17 Copy of Supplemental Trust Indenture, dated
January 1, 1975, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.17
to Registration Statement No. 2-55085 and
incorporated by reference herein)
4.18 Copy of Supplemental Trust Indenture, dated
January 1, 1976, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.18
to Registration Statement No. 2-57730 and
incorporated by reference herein)
4.19 Copy of Supplemental Trust Indenture, dated
September 14, 1976, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 2.19 to Registration Statement No.
2-59887 and incorporated by reference herein)
4.20 Copy of Supplemental Trust Indenture, dated
January 1, 1977, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 2.20
to Registration Statement No. 2-59887 and
incorporated by reference herein)
4.21 Copy of Supplemental Trust Indenture, dated
November 1, 1977, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.21 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.22 Copy of Supplemental Trust Indenture, dated
December 1, 1977, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.22 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.23 Copy of Supplemental Trust Indenture, dated
February 1, 1980, being a supplemental
instrument to Exhibit 4.01 hereto. (Filed as
Exhibit 4.23 to Registration Statement No.
2-70539 and incorporated by reference herein)
4.24 Copy of Supplemental Trust Indenture, dated
April 15, 1982, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.24
to the Company's Form 10-K Report, File No. 1-1097,
for the year ended December 31, 1982, and incorporated
by reference herein)
4.25 Copy of Supplemental Trust Indenture, dated
August 15, 1986, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.25
to the Company's Form 10-K Report, File No. 1-1097,
for the year ended December 31, 1986 and incorporated
by reference herein)
4.26 Copy of Supplemental Trust Indenture, dated
March 1, 1987, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.26
to the Company's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
4.28 Copy of Supplemental Trust Indenture, dated
November 15, 1990, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.28
to the Company's Form 10-K Report for the year
ended December 31, 1990, File No. 1-1097, and
incorporated by reference herein)
4.29 Copy of Supplemental Trust Indenture, dated
December 9, 1991, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.29 to
the Company's Form 10-K Report for the year ended
December 31, 1991, File No. 1-1097, and incorporated
by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between
OG&E and Atlantic Richfield Company. (Filed as
Exhibit 5.19 to Registration Statement No. 2-59887
and incorporated by reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between OG&E
and Atlantic Richfield Company, together with
related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply
Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company. (Filed as Exhibit
5.28 to Registration Statement No. 2-62208 and
incorporated by reference herein)
10.04 Amendment dated June 27, 1990, between OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between OG&E and Atlantic
Richfield Company.
10.05 Participation Agreement dated as of January 1, 1980,
among First National Bank and Trust Company of
Oklahoma City, Thrall Car Manufacturing Company,
OG&E and other parties, including Lease of Railroad
Equipment dated January 1, 1980, between
Mercantile-Safe Deposit and Trust Company and
OG&E. (Filed as Exhibit 10.32 to the Company's
Form 10-K Report for the year ended December 31,
1980, File No. 1-1097, and incorporated by reference
herein)
10.06 Participation Agreement dated January 1, 1981,
among The First National Bank and Trust Company
of Oklahoma City, Thrall Car Manufacturing Company,
OG&E and other parties, including Lease for
Railroad Equipment dated January 1, 1981, between
Wells Fargo Equipment Leasing Corporation and OG&E.
(Filed as Exhibit 20.01 to the Company's Form 10-Q
for June 30, 1981, File No. 1-1097, and incorporated
by reference herein)
10.08 Form of Amended and Restated Stock Equivalent and
Deferred Compensation Agreement for Directors, as amended.
10.09 Restricted Stock Plan of the Company. (Filed as Exhibit 10.36
to the Company's Form 10-K Report for the year ended
December 31, 1986, File No. 1-1097, and
incorporated by reference herein)
10.10 Agreement and Plan of Reorganization, dated May 14, 1986,
between OG&E and Mustang Fuel Corporation.
(Attached as Appendix A to Registration Statement
No. 33-7472 and incorporated by reference herein)
10.11 Gas Service Agreement dated January 1, 1988, between
OG&E and Oklahoma Natural Gas Company. (Filed as
Exhibit 10.26 to the Company's Form 10-K Report
for the year ended December 31, 1987, File No. 1-1097,
and incorporated by reference herein)
10.12 Company's Restoration of Retirement Income Plan, as amended.
(Filed as Exhibit 10.12 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
10.13 Company's Restoration of Retirement Savings Plan.
(Filed as Exhibit 10.13 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
10.14 Gas Service Agreement dated July 23, 1987, between
OG&E and Arkla Services Company. (Filed as Exhibit
10.29 to the Company's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
10.15 Company's Supplemental Executive Retirement Plan.
(Filed as Exhibit 10.1 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097 and incorporated by reference herein)
10.16 Company's Annual Incentive Compensation Plan.
(Filed as Exhibit 10.16 to the Company's Form 10-K
Report for the year ended December 31, 1993, File
No. 1-1097, and incorporated by reference herein)
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 1994 Form 11-K Annual Report for Oklahoma Gas
and Electric Company Employees' Retirement Savings Plan.
99.02 Description of Common Stock.
</TABLE>
<PAGE> 1
================================================================================
Exhibit 10.04
1990 AMENDMENT
TO THE
COAL SUPPLY AGREEMENT
BETWEEN
THUNDER BASIN COAL COMPANY
AND
OKLAHOMA GAS AND ELECTRIC COMPANY
<PAGE> 2
1990 AMENDMENT
TO THE
COAL SUPPLY AGREEMENT
This 1990 Amendment is effective June 27, 1990 between Thunder Basin Coal
Company ("Seller") and Oklahoma Gas & Electric Company ("Buyer").
Seller and Buyer are parties to a Coal Supply Agreement dated March 1, 1973, as
previously amended, (the "Agreement"). The purpose of this 1990 Amendment is
to further amend the Agreement as follows:
1. Section 1, "Purchase and Sale", is amended in its entirety to read as
follows:
"SECTION 1 - Purchase and Sale
(a) Historical Coal Quantity
During the period January 1, 1977 through June 27, 1990 (the
"Historical Period"), Seller sold to Buyer and Buyer purchased from Seller
59,426,010 tons of coal (the "Historical Coal Quantity"). Regardless of the
quantity of coal Seller was obligated to sell and Buyer was obligated to
purchase under the Agreement during the Historical Period, Seller and Buyer
agree to accept the Historical Coal Quantity in full satisfaction of the
quantity obligations of both Buyer and Seller under the Agreement during the
Historical Period.
(b) Annual Quantities
Each year during the fourteen year period 1990 through 2003,
Seller shall sell and Buyer shall purchase as applicable (1) the annual
quantity of coal listed below ("Annual Base Quantity") or (2) the Annual Base
Quantity as may be increased by Buyer under Subsection 2(b), or (3) the annual
quantities Seller elects to supply under Subsection 9(i)(2)(d)(2). If the
Agreement is extended under Subsection 2(c), then Seller shall sell and Buyer
shall purchase the annual quantity of coal determined under Subsection 2(c).
<PAGE> 3
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<TABLE>
<CAPTION>
Period Annual Base Quantity
------ --------------------
<S> <C>
1990
1991-1998 100.32 trillion Btus
1999-2003 50.16 trillion Btus
</TABLE>
The Annual Base Quantity for 1990 shall be the quantity of coal that equals
the first 2,850,000 tons of coal purchased by Buyer during 1990 plus 50.16
trillion Btus of coal.
(c) Requirements Coal
Between June 26, 1990 and January 1, 1991 and for each
calendar year during the period January 1, 1991 through December 31, 1993,
Seller shall sell and Buyer shall purchase from Seller all of the coal Buyer
requires for use in Units 1 and 2 at Buyer's Sooner Generating Station and
Units 4, 5 and 6 at Buyer's Muskogee Generating Station up to an additional
annual quantity of 31.68 trillion Btus of coal ("Requirements Coal") in excess
of (1) the Annual Base Quantity plus (2) any coal which Buyer is then or is
required by Oklahoma State law, regulation, or judicial or administrative order
to purchase, including coal supply contracts in effect as of January 1, 1990
for coal purchased pursuant to any such law, regulation or order. Buyer
represents that its commitment to purchase coal under the existing coal supply
contracts with Oklahoma coal producers is 645,487 tons for the period July 1,
1990 through the expiration of the term of the last of the coal supply
contracts, December 31, 1991.
Any coal delivered under the October 19, 1990 Letter Agreement
between Buyer and Seller shall be deemed Requirements Coal upon execution of
this 1990 Amendment and the October 19, 1990 Letter Agreement shall thereafter
be void and of no effect, and neither party shall have any further obligation
to the other except for any then outstanding obligation to pay for any such
coal delivered under the October 19, 1990 Letter Agreement. Promptly after
execution of this 1990 Amendment the price of all Requirements Coal delivered
prior to the execution of the 1990 Agreement shall be retroactively adjusted to
the price of Requirements Coal under this Agreement.
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(d) Matching Coal Quantities and Price
(1) During the period January 1, 1994 through December
31, 1998 and the period January 1, 1999 through December 31, 2003 Seller shall
have the right but not the obligation to supply, and Buyer shall purchase, the
Subsection 1(d)(2) and 1 (d)(3) quantities of Matching Coal, defined below.
(A) For the purposes of this Agreement, the
following definitions shall apply:
(i) "Matching Coal" shall be that
quantity of Suitable Coal, in excess of the Annual Base Quantity, which is
required to be purchased by Buyer pursuant to the procedures set forth in this
Subsection 1(d). Buyer shall purchase Matching Coal from Seller pursuant to
Seller's option to supply Matching Coal. In addition, Matching Coal may be
purchased from the producer of Suitable Coal, who made the bid that yielded the
corresponding Matching Coal Price under Subsection 1(d)(4), if Seller elects
not to supply the corresponding quantity of Matching Coal to Buyer.
(ii) "Suitable Coal" shall mean
subbituminous coal from any mine(s) located in Campbell County or Converse
County, Wyoming which is producing coal at the time Buyer requests bids for
Matching Coal under Subsection 1(d)(4) or requests bids for Suitable Coal under
Subsection 9(i)(2)(a), as the case may be, and which is not Unacceptable Coal
for any of the quality characteristics shown in Exhibit L.
(iii) "Third Party Coal" shall be coal
which Buyer purchases from any producer of coal other than Seller under
Subsection 1(e), during the period January 1, 1994 through December 31, 1998,
which is not purchased pursuant to the procedure for the purchase of Matching
Coal set forth in Subsection 1(d).
(2) During each calendar year of the period January 1,
1994 through December 31, 1998 Seller shall have the right, but not the
obligation, to supply and Buyer shall purchase a quantity of Matching Coal,
which Buyer requires for use in the Units (defined below) in excess of the
Annual Base Quantity up to a maximum annual additional quantity of 31.68
trillion Btus of coal, except as such quantity of Matching Coal may be reduced
pursuant to Subsection 1(e) "Third Party Coal." The terms "Unit" or "Units" in
this Agreement shall mean as applicable: Units 1 and 2 at Buyer's Sooner
Station (also known as Additional Unit 1 and Additional Unit 2 or Additional
Units) and Units 4, 5, and 6 at Buyer's Muskogee Station. If Seller chooses
not to supply a quantity of Matching Coal at the corresponding Matching Coal
Price, then Seller's right to supply up to 31.68 trillion Btus of Matching Coal
in the calendar year during which delivery is
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intended by Buyer to be made (as such intent is stated in Buyer's notice to
Seller under Subsection 1(d)(4) below) shall be reduced for that calendar year
only by the quantity of Matching Coal Seller elected not to supply in said
calendar year unless Buyer fails to purchase all or part of such quantity of
Matching Coal at the corresponding Matching Coal Price in which event Seller
shall again have the right to supply such unpurchased quantity of Matching Coal
under the procedures of this Subsection 1(d).
(3) If Buyer purchases any Third Party Coal under
Subsection 1(e), then during the period January 1, 1999 through December 31,
2003, Seller shall have the right, but not the obligation, to supply and Buyer
shall purchase a quantity of Matching Coal that equals the quantity, expressed
in Btus, of Third Party Coal Buyer purchased. Each time during the period
January 1, 1999 through December 31, 2003 Buyer requires Suitable Coal in
excess of the Annual Base Quantity, the procedures of Subsection 1(d)(4) shall
be followed until Buyer has provided Seller with the right to supply the
quantity of Matching Coal equal to the Third Party Coal Buyer purchased under
Subsection 1(e).
(4) Each time Buyer requires Matching Coal, it shall
notify Seller in writing of the quantity of such Matching Coal in Btus and the
calendar year during which delivery is intended by Buyer. Buyer shall also
notify Seller in writing of the Matching Coal Price(s), defined below, for the
corresponding quantity of Matching Coal after Buyer establishes the Matching
Coal Price(s). Buyer shall begin the process of establishing the Matching Coal
Price(s) by requesting bids from producers of Suitable Coal ("Matching Coal
Bids"). Buyer may establish more than one Matching Coal Price from the
Matching Coal Bids and each Matching Coal Price shall correspond to the
quantity of coal offered in the applicable Matching Coal Bid. In the case of a
range of quantities offered in a Matching Coal Bid by the producer, Buyer shall
choose the quantity of Suitable Coal at the applicable price in the Matching
Coal Bid it intends to purchase from the producer submitting that Matching Coal
Bid as the basis for determining a corresponding Matching Coal Price. Seller
may match any one or more of the Matching Coal Prices and supply each
corresponding quantity of Matching Coal. Each time Buyer requests Matching
Coal Bids, Buyer shall provide a copy of the request for Matching Coal Bids to
Seller. The request for Matching Coal Bids shall require each Matching Coal
Bid to (1) be for a term of supply of Suitable Coal for twelve months or less,
(2) provide for a fixed per ton price (except for quality adjustments) for the
corresponding quantity of Suitable Coal to be supplied and a Btu content for
the Suitable Coal specified by the producer, FOB loaded in Buyer's railcars at
the applicable producer's mine ("Matching Coal Bid Price"), (3) provide the
same quality data as listed in Subsection 9(i)(2)(a)B and agree to the same
sulfur dioxide restriction listed in Subsection 9(i)(2)(a)C, (4) be returned to
<PAGE> 6
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Buyer no later than the due date of the Matching Coal Bids specified by Buyer,
and (5) provide for a delivery period substantially the same as intended by
Buyer as stated in the request for Matching Coal Bids. Buyer shall not divulge
the standards for Low Quality Suitable Coal in the requests for Matching Coal
Bids. All Matching Coal Bids from producers of Suitable Coal meeting the above
requirements shall be considered "Acceptable Matching Coal Bids." Buyer shall
determine whether the Suitable Coal in a Matching Coal Bid is Low Quality
Suitable Coal or Unacceptable Coal by following the same procedure contained in
Exhibit N. Seller shall submit to Buyer the same quality data listed in
Subsection 9(i)(2)(a)B by the applicable due date of the Matching Coal Bids to
permit the determination of the lower heating value of Black Thunder Coal for
use in determining the Matching Coal Price for any Acceptable Matching Coal
Bid. Seller may also submit a Matching Coal Bid to Buyer. Buyer shall not
redesignate Matching Coal as Third Party Coal after Buyer requests Matching
Coal Bids.
The Matching Coal Bid Price in an Acceptable Matching Coal Bid shall
be adjusted by Buyer to yield the "Matching Coal Price" following the
calculation procedures provided in Exhibit N. The values for RCsc and RCbt in
Exhibit N shall be equal to the following values:
RCsc = The weighted average per ton rail rate for
transporting Suitable Coal from the applicable
producer's mine to the Units in effect on the
applicable due date of the Matching Coal Bids, plus
the per ton railcar ownership cost (based on Buyer's
best professional estimate of the cost during the
period of time for which the Matching Coal Price will
apply) of one (1) 112 car train set if the as
received heating value of the Suitable Coal is less
than 8000 Btu/lb per ton .
RCbt = The weighted average per ton rail rate for
transporting Black Thunder Coal from Seller's Mine to
the Units in effect on the applicable due date of the
Matching Coal Bids.
3RCsc and RCbt shall be calculated by weighting the rail rates to the
Muskogee and Sooner Stations, excluding any one-time lump sum charges
or credits, by a 60%/40% proportion, respectively.
Upon receipt of the Matching Coal Price(s) and the corresponding
Matching Coal quantities from Buyer, Seller shall notify Buyer within seven (7)
days of receipt of the Matching Coal Price(s) whether Seller chooses to supply
any one or more of the quantities of Matching Coal at the corresponding
Matching Coal Price(s) or request Buyer to submit a copy of any one or more of
the Acceptable Matching Coal Bid(s) and
<PAGE> 7
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calculations Buyer used for the determination of the Matching Coal Price(s) to
the most recent Independent Party selected under Subsection 9(i)(3) to perform
the scope of work in Exhibit N (the "Verification").
If Seller has requested Verification of the Matching Coal Price(s),
then Buyer and Seller shall by a joint contract with the Independent Party
substantially similar to Exhibit P, which includes the scope of work in Exhibit
N, cause the Independent Party to (1) complete the Verification within 20 days,
(2) provide Buyer and Seller with the results of the Verification including any
reasons why the Independent Party was unable to verify any Matching Coal Price,
if it was unable to verify, and (3) provide it's own determination of any
Matching Coal Price the Independent Party was unable to verify to Seller and
Buyer. Buyer will notify Seller when the supporting documents in Section 2 of
Exhibit N have been submitted to the Independent Party and of the values of
RCsc and RCbt provided to the Independent Party. If the Independent Party
provides its own determination of any Matching Coal Price and both Seller and
Buyer do not agree with such determination, then Seller and Buyer shall then
meet and endeavor in good faith to agree upon a Matching Coal Price for the
corresponding quantity of Matching Coal with due regard to such determination
by the Independent Party. If both Seller and Buyer do not agree upon a
Matching Coal Price within seven (7) days after receipt of such Independent
Party's determination of the applicable Matching Coal Price, then Buyer within
four (4) days after the end of such seven (7) day period shall notify Seller
either that the Matching Coal Price for the applicable quantity of Matching
Coal shall be the Matching Coal Price determined by the Independent Party for
that Acceptable Matching Coal Bid and the corresponding quantity of Matching
Coal or that Buyer has rejected that Acceptable Matching Coal Bid. If Buyer
notifies Seller that the Matching Coal Price for a quantity of Matching Coal
shall be the Matching Coal Price determined by the Independent Party then
Seller shall notify Buyer within four (4) days after receipt of such notice
whether Seller chooses to supply the corresponding quantity of Matching Coal at
that Matching Coal Price. If Buyer and Seller agree upon a Matching Coal Price
during the seven (7) day period above, or if the Independent Party verified
Buyer's determination of the Matching Coal Price or both Seller and Buyer agree
with the Independent Party's determination of the Matching Coal Price then
Seller shall notify Buyer within four (4) days after Seller's and Buyer's
agreement or within four (4) days after receipt by Seller of the results of the
Verification, as the case may be, whether Seller chooses to supply any of the
corresponding quantities of Matching Coal at the applicable Matching Coal
Price(s).
Buyer and Seller acknowledge and agree that the Matching Coal
Price(s), once so determined shall be fixed for the corresponding Matching Coal
quantity except for adjustments under Section 6 and Section 10.
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Matching Coal supplied by Seller shall be delivered under the terms of this
Agreement. Buyer shall be free to purchase from others any quantity of
Matching Coal Seller declines to supply without such quantity counting as Third
Party Coal.
(e) Third Party Coal
Notwithstanding Subsection 1(d) "Matching Coal Quantities and
Price" Buyer may purchase up to a total quantity of 31.68 trillion Btus of coal
during the period January 1, 1994 through December 31, 1998, from one or more
third parties ("Third Party Coal"). If Buyer purchases Third Party Coal as
provided in this Subsection 1(e) Seller shall have no right to supply Matching
Coal to the extent that Third Party Coal is purchased by Buyer in any calendar
year. Each time Buyer places an order for the purchase of Third Party Coal,
Buyer shall inform Seller in writing promptly of such purchase, the quantity
(in Btus) of Third Party Coal Buyer is purchasing and the calendar year(s)
Buyer intends the Third Party Coal to be delivered.
(f) Calculation of Quantity Obligation where Third Party Coal or
Matching Coal is Supplied
For purposes of determining the applicable calendar year for
the supply of quantities for Third Party Coal and/or Matching Coal, the
calendar year in which such Third Party Coal and/or Matching Coal is intended
by Buyer to be delivered (as stated in Buyer's notice to Seller under
Subsection 1(d)(4) for Matching Coal or Buyer's notice to Seller under
Subsection 1(e) for Third Party Coal) shall control."
2. Section 2, "Term of Agreement and Options to Extend", shall be amended
in its entirety to read as follows:
"SECTION 2 - Term of Agreement and Buyer's and Seller's Options
(a) Term
This Agreement became effective March 1, 1973 and
shall continue to 11:59 pm, December 31, 2003 unless otherwise extended under
Subsection 2(c)."
(b) Buyer's Option
Buyer shall have an option to increase the Annual
Base Quantity for all the calendar years during the period January 1, 1999
through December 31, 2003 by the same quantity each calendar year from 50.16
trillion Btus up to a total annual quantity of 100.32 trillion Btus each
calendar year by notifying
<PAGE> 9
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1990 Amendment to the Coal Supply Agreement Page 8
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Seller in writing anytime prior to January 1, 1997. If Buyer so notifies
Seller then the Annual Base Quantity shall be the annual quantity designated by
Buyer which shall be greater than 50.16 trillion Btus and no more than 100.32
trillion Btus each calendar year.
(c) Seller's Option
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
<PAGE> 10
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3. Section 4, "Increase or Decrease in Base Quantity", shall be amended
in its entirety to read as follows:
"SECTION 4 - Requirements Coal Notices
By October 1 of 1991 and 1992 Buyer shall notify Seller in writing of
Buyer's good faith estimate of the quantity of Requirements Coal that Buyer
will require during the following year at the Units . Buyer shall notify
Seller in writing within five days of the execution of the 1990 Amendment to
the Coal Supply Agreement of Buyer's good faith estimate of the quantity of
Requirements Coal that Buyer will require during the remainder of 1990 and for
1991. Buyer shall also notify Seller in writing by the beginning of each
quarter, January 1, April 1, July 1, October 1, during the years 1991 through
1993 of Buyer's most recent, good faith estimate of the Requirements Coal Buyer
will require at the Units during the remainder of that year. The actual
quantity of Requirements Coal Buyer is obligated to purchase from Seller and
Seller is obligated to sell is defined in Subsection 1(c) and not by Buyer's
notice in this Section 4."
4. Section 5, "Delivery Schedules" shall be amended in its entirety to
read as follows:
"SECTION 5 - Delivery Schedules
Deliveries of coal under this Agreement shall be made and taken each
year in approximately equal monthly amounts."
5. The first three sentences of Subsection 7(a) "Source of Coal" shall be
amended in their entirety to read as follows:
"The source of coal to be sold by Seller and purchased by Buyer under
the Agreement shall be Seller's Black Thunder Mine ("Seller's Mine") as it
presently exists or as it may be expanded to immediately adjacent lands in
Campbell County, Wyoming. Seller's Mine, as presently configured, is located
within the area shown on Exhibit A. Seller warrants that at all times during
the term of the Agreement it will maintain and set aside such quantity of coal
reserves located within the area shown on Exhibit A (or immediately adjacent
thereto if Seller's mine is expanded) as is required for the full performance
of Seller's obligations hereunder (including a quantity sufficient to fulfill
Seller's obligation if Buyer's option under Subsection 2(b) is exercised) and
that
<PAGE> 11
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1990 Amendment to the Coal Supply Agreement Page 10
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it will not sell nor contract to sell to others coal from said reserves in such
quantity as to jeopardize Seller's ability to deliver the total quantity of
coal required by this Agreement."
6. The second and third paragraphs of Section 8 "Base Price for Coal"
shall be deleted and the following substituted in their place:
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
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7. Section 9 "Base Price Adjustments" shall be deleted through and
including Subsection 9(f) and replaced with the following:
"SECTION 9 - Adjusted Base Price and Adjusted Requirements Base Price
The terms "Adjusted Base Price" and "Adjusted Requirements Base Price"
as used in this Agreement shall mean, at any time, the price per ton of Annual
Base Quantity coal or Requirements Coal, respectively, as most recently
determined in accordance with all provisions of Subsections 9(a) through 9(d)
and, if applicable, 9(f) and 9(g). Each of the adjustments to the components
of the Base Price and Requirements Base Price under Subsections 9(a) through
9(c) and, if applicable, 9(d) and 9(g) shall be calculated separately.
Each of the adjusted components for the applicable Base Price under
Subsections 9(a) through 9(c) shall be added together with (1) any adjustment
under Subsection 9(d), plus (2), if applicable, the amount of the Fixed
Component under Subsection 9(f), to equal the Adjusted Base Price. Prior to
any adjustments under
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1990 Amendment to the Coal Supply Agreement Page 12
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Section 6 and Section 10, the Adjusted Base Price during the period June 27,
1990 through December 31, 1993 shall be reduced by the amount of any applicable
Price Discount under Subsection 9(g).
The Adjusted Requirements Base Price shall be the sum of each of the
adjusted components for the Requirements Base Price under Subsection 9(a)
through 9(c) plus any adjustment under Subsection 9(d).
Exhibits F-2 and F-3 show the 1990 Base Price and the Requirements
Base Price Components and the calculation of the Royalty and Tax Components for
each Base Price as of the Base Date.
(a) Adjustments to the Base Adjustable Component
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
<PAGE> 14
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(b) Adjustments to the (Federal and/or State) Royalty Component
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
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(c) Adjustments to the Tax Component (Excluding Federal Income Taxes)
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
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8. Subsection 9(d) "Adjustments to Compensate for Increases or Decreases
Caused by Federal, State or Local Regulations"
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
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9. Subsection 9(e) "Buyer's Right of Rejection"
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
10. A new Subsection 9(f) "Fixed Component" shall be added to Section 9.
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
11. A new Subsection 9(g) "Price Discounts" shall be added to Section 9.
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
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12. A new Subsection 9(h) "Index or Index Publication Changes" shall be
added to Section 9.
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
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1990 Amendment to the Coal Supply Agreement Page 18
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13. A new Subsection 9(i) "Base Price Redetermination" shall be added to
Section 9.
"(i) Base Price Redetermination
The Base Price of coal shall be redetermined ("Redetermined
Base Price" )as provided in this Subsection 9(i) effective as of January 1,
1994 and January 1, 1999 (each an "Effective Date") and, if the Agreement is
extended by Seller under Subsection 2(c), also January 1, 2004 (also an
"Effective Date"). In addition, the Base Price of coal may be redetermined
("Additional Base Price Redetermination") at Seller's or Buyer's option, as the
case may be, under the provisions of Subsection 9(i)(2)(e), effective July 1,
1996 and July 1, 2001 respectively (each an "Effective Date") and, if the
Agreement is extended by Seller under Subsection 2(c), also July 1, 2006 (also
an "Effective Date"). If, despite the good faith endeavors of Buyer and
Seller, the Redetermined Base Price is not available on the Effective Date, the
Base Price as adjusted under this Agreement, will continue until the
Redetermined Price is available and at such time a retroactive price adjustment
back to the Effective Date will be made.
(1) Initial Negotiations to Establish Redetermined Base Price
During the first two weeks of that month which is nine months prior
to each Effective Date, the parties shall cause their representatives to meet
during normal business hours at a mutually agreeable location. The parties
shall commence negotiations in good faith to attempt to agree upon a
Redetermined Base Price to be effective on the Effective Date.
(2) Bids to Establish Redetermined Base Price
(a) Request for Bids for Suitable Coal
If Buyer and Seller fail to agree upon a Redetermined
Base Price during the negotiations under Subsection 9(i)(1) by a date which is
180 days prior to the Effective Date, then not later than 173 days prior to the
Effective Date, Buyer shall prepare and forward a Request for Bids for coal
supply to those producers, including Seller, of Suitable Coal, as the term
"Suitable Coal" is defined in Subsection 1(d)(1)(A)(ii). Buyer shall not
divulge the standards for Low Quality Suitable Coal applicable to the Requests
for Bids. The Request for Bids shall require each respondent to supply (1)
Suitable Coal on the following offer basis, (2) supply the following quality
data, and (3) agree to the following sulfur dioxide restriction (collectively
"Bid Requirements"):
A. Offer Basis
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1. Each Bid must be for a minimum quantity of
17.6 trillion Btus.
2. Each Bid must provide for a term of supply of
twelve months commencing on the Effective Date.
3. Each Bid must provide for a fixed price per
ton (except for quality adjustments) at a specified Btu/lb basis FOB loaded in
Buyer's railcars at the applicable producer's mine (the "Bid Price").
B. Quality Data
All Quality Data shall be supplied on an "as
received" basis unless otherwise stated.
1. Each Bid must include the average percent
moisture, ("Bid Moisture Content"), average percent ash ("Bid Ash Content"),
average percent sulfur ("Bid Sulfur Content") and average heat content
expressed in Btus per pound ("Bid Btu Content") for all coal shipped from the
applicable producer's mine during the last twelve months prior to the date of
the Request for Bids;
2. Each Bid must include one ultimate analysis
performed by an independent commercial laboratory for one unit train of coal
shipped from the applicable producer's mine during the twelve month period
prior to the date of the Bid Due Date [defined in Subsection 9(i)(2)(b)]. Each
bid must include an indication from the independent commercial laboratory
whether or not the hydrogen content in the ultimate analyses includes the
hydrogen content in the moisture. If the hydrogen content in the ultimate
analysis includes the hydrogen content in the moisture, then the value for the
hydrogen content in the ultimate analysis shall be adjusted to exclude the
hydrogen content in the moisture as shown in Exhibit J.
3. Each Bid must include the producer's
representation of the average quality of the coal to be supplied from the
producer's mine during the Subsection 9(i)(2)(a)A.2 term of supply for (a)
volatile matter (weight percent) (b) fixed carbon (weight percent) (c)
hardgrove grindability Index (d) percent alkalies as Na2O- dry coal basis (e)
fusion temperatures of ash -oF - (degrees Farenheit) reducing.
C. Sulfur Dioxide Restriction
The producer shall not take exception or otherwise
disclaim that the following statements, listed in the Request for Bids by
Buyer, will apply to coal to be supplied by the producer to Buyer: "In the
event the producer delivers to Buyer a trainload of coal exceeding 1.2 pounds
sulfur dioxide per million Btus burned, Buyer shall have the option to reject
such coal or pay for all such coal at a price mutually agreed
<PAGE> 21
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to by the producer and Buyer. If Buyer rejects the coal, the producer shall
dispose of the coal at its sole cost and expense."
(b) Bid Response
Each Bid shall be due to Buyer not later than 128 days prior
to the Effective Date (the "Bid Due Date") and no Bid received after the Bid
Due Date shall be considered. Seller shall have the right but not the
obligation to provide a Bid to Buyer. If Seller elects not to provide a Bid to
Buyer, Seller shall nonetheless submit the quality data specified in Subsection
9(i)(2)(a)B.1., 2. and 3 by the Bid Due Date to permit the determination of the
lower heating value of Black Thunder Coal under Subsection 9(i)(2)(d)(1) and
the procedures of Exhibit J.
The Applicable Quality Information contained in the immediately
succeeding paragraph, derived from the sources listed therein, must be used by
Buyer to determine whether any Suitable Coal in a Bid is Low Quality Suitable
Coal or Unacceptable Coal. Buyer shall determine whether any Suitable Coal in
a Bid is Low Quality Suitable Coal or Unacceptable Coal as follows: (1) if any
Applicable Quality Information for any Suitable Coal in a Bid falls within the
quality characteristic ranges shown in Exhibit K, then that Suitable Coal must
be classified as Low Quality Suitable Coal, and the "Low Quality Coal Factor"
for the formula shown in Subsection 9(i)(2)(d)(1) shall equal 1.11, (2) if any
Applicable Quality Information for any coal in a Bid, exceeds any one or more
of the quality characteristic levels in Exhibit L then the coal in that Bid
must be classified as Unacceptable Coal and the Bid shall be disqualified from
further consideration.
Applicable Quality Information
1. The Bid Moisture Content supplied by the producer under
9(i)(2)(a)B.1. above.
2. The average quality data supplied by the producer under
9(i)(2)(a)B.3.
3. The weighted average as received heat content (Btus/lb.), the
weighted average as received ash content (weight percent) and the weighted
average as received sulfur content (weight percent) for all coal shipments
reported for the respective producer's mine during the twelve (12) month period
ending six (6) months prior to the month of the Bid Due Date as based on data
contained in Federal Energy Regulatory Commission data, presently shown in FERC
Form 423, (FERC Btu Content, FERC Ash Content, and FERC Sulfur Content,
respectively). The FERC data shall be weighted on a tonnage basis. A
compilation of such FERC data by a third party may be used by Buyer at Buyer's
expense. If Buyer elects to use a third party to
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compile such FERC data, Buyer shall inform Seller of the third party compiling
the FERC data at the time Buyer selects the third party.
(c) Acceptable Bids.
An "Acceptable Bid" shall be a Bid received by Buyer from a
producer of Suitable Coal that (1) meets all of the Bid Requirements, (2) is
received by Buyer by the Bid Due Date and (3) covers the supply of Suitable
Coal which is not Unacceptable Coal.
(d) Adjusted Bid Price, Half Volume Adjusted Bid Price and Full
Volume Adjusted Bid Price
(1)
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
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(2) Within 98 days prior to the Effective Date Buyer shall
determine and inform Seller of the Full Volume Adjusted Bid Price and the Half
Volume Adjusted Bid Price. The Full Volume Adjusted Bid Price shall be the
Adjusted Bid Price for the Annual Base Quantity and the Half Volume Adjusted
Bid Price shall be the Adjusted Bid Price for one-half of the Annual Base
Quantity. In the case of Bids received by Buyer from multiple producers, the
Full Volume Adjusted Bid Price and the Half Volume Adjusted Bid Price shall be
determined by weighting the Full Volume Adjusted Bid Price and the Half Volume
Adjusted Bid Price, as the case may be, by the proportion of the Btus of coal
which would be supplied by each producer up to the quantity contained in each
producer's Bid. Any of the Acceptable Bids may be used by Buyer in determining
the Full Volume Adjusted Bid Price and the Half Volume Adjusted Bid Price. If
no Acceptable Bids are received or if Buyer does not receive Acceptable Bids
with sufficient quantities of Suitable Coal to equal either the Annual Base
Quantity or one-half of the Annual Base Quantity for the year beginning with
the Effective Date, then all or, as applicable, the remaining portion of the
Full Volume Adjusted Bid Price and/or the Half Volume Adjusted Bid Price, as
the case may be, shall be weighted with the remaining proportion of Btus
necessary to make up the respective Full Volume Adjusted Bid Price and/or Half
Volume Adjusted Bid Price at the Adjusted Base Price of coal in effect under
the Agreement as of the Bid Due Date.
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If Seller fails to request an Independent Party Review under
Subsection 9(i)(3) "Independent Party Selection and Review" of the Full Volume
Adjusted Bid Price and the Half Volume Adjusted Bid Price provided to Seller by
Buyer, then by 77 days prior to the Effective Date, Seller shall inform Buyer
whether Seller chooses to supply either the Annual Base Quantity at the Full
Volume Adjusted Bid Price or one half of the Annual Base Quantity at the Half
Volume Adjusted Bid Price ("Seller's Price Decision"). If Seller elects an
Independent Party Review under Subsection 9(i)(3) "Independent Party Selection
and Review", then Seller shall inform Buyer of Seller's Price Decision within
seven (7) days after Seller receives the report issued by the Independent Party
under Subsection 9(i)(3). The Full Volume Adjusted Bid Price or Half Volume
Adjusted Bid Price, as applicable, for the quantity selected by Seller shall
become the Redetermined Base Price.
If Seller's Price Decision is based on a Provisional Adjusted Bid
Price(s), Buyer shall promptly inform Seller of the recalculated Full Volume
Adjusted Bid Price and the Half Volume Adjusted Bid Price when and if the New
Quarter Rate becomes available. However, if Seller's Price Decision was to
supply one-half of the Annual Base Quantity at the Half Volume Adjusted Bid
Price based on the Provisional Adjusted Bid Price(s), then Buyer shall only
inform Seller of the recalculated Half Volume Adjusted Bid Price, which shall
become the Redetermined Base Price, and Seller shall not have the right to
choose to supply the Annual Base Quantity Coal at the Full Volume Adjusted Bid
Price. If Seller's Price Decision was to supply the Annual Base Quantity at
the Full Volume Adjusted Bid Price based on Provisional Adjusted Bid Price(s),
then within seven (7) days after receiving Buyer's notification of the Full
Volume Adjusted Bid Price and the Half Volume Adjusted Bid Price based on the
New Quarter Rate or within seven (7) days after receiving the revised report
reflecting the use of the New Quarter Rate from the Independent Party under the
procedures of Subsection 9(i)(3), if Seller previously elected an Independent
Party Review, Seller will inform Buyer of Seller's Price Decision.
If Seller previously informed Buyer that Seller would supply the
Annual Base Quantity at the Full Volume Adjusted Bid Price based on Provisional
Adjusted Bid Price(s) and Seller subsequently informs Buyer that Seller will
supply one-half of the Annual Base Quantity at the Half Volume Adjusted Bid
Price, then Buyer may notify Seller in writing, and on receipt Seller shall be
obligated to supply coal at the monthly prorated Annual Base Quantity level at
the Full Volume Adjusted Bid Price as previously calculated on the Provisional
Adjusted Bid Price(s) for up to three months commencing on the Effective Date
in order to permit Buyer to
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secure an alternate supplier for the volume of coal Seller declined to supply.
Buyer shall inform Seller in writing of such request within seven (7) days
after Seller's Price Decision.
(e) Additional Base Price Redeterminations
If during any Redetermination of the Base Price,
Seller elects to supply the Annual Base Quantity at the Full Volume Adjusted
Bid Price, then Buyer may request, at Buyer's option, an Additional Base Price
Redetermination by notifying Seller at least twelve (12) months prior to the
next applicable Effective Date for an Additional Base Price Redetermination.
However, the Base Price shall not be redetermined if the Full Volume Adjusted
Bid Price determined under such Additional Base Price Redetermination is not
more than 10% higher or lower than the Adjusted Base Price in effect as of the
Bid Due Date.
If during any Redetermination of the Base Price, Seller elects to
supply one-half of the Annual Base Quantity at the Half Volume Base Price, then
Seller may request, at Seller's option, an Additional Base Price
Redetermination by notifying Buyer at least twelve (12) months prior to the
next applicable Effective Date for an Additional Base Price Redetermination.
After notification from either Buyer or Seller of a request for an
Additional Base Price Redetermination the procedures of Subsection 9(i) and
Exhibit J shall be followed to redetermine the Base Price, except as modified
by this Subsection 9(i)(2)(e).
(3) Independent Party Selection and Review
Eleven (11) months prior to each applicable Effective Date,
Buyer shall provide Seller with a list of three of the ten (10) largest U.S.
accounting firms shown on the most recent revision of Exhibit M. The ten
largest U.S. accounting firms shall be determined based on the total billings
for each firm for the most recent calendar year in which billing data is
available. Exhibit M lists the ten largest U.S. Accounting firms based on 1989
billings. Exhibit M shall be revised by Seller and provided to Buyer by May 15
of each year beginning May 15, 1991. Within seven days after receipt of
Buyer's list, Seller shall notify Buyer of the accounting firm Seller has
selected from Buyer's list to be the Independent Party to conduct any
Independent Party Review under this Subsection 9(i)(3). Buyer and Seller shall
then endeavor to contract with the Independent Party by nine (9) months prior
to the Effective Date using a contract substantially similar to
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Exhibit P to conduct an Independent Party Review (defined below) which shall be
performed in accordance with a scope of work mutually agreed to by Buyer and
Seller. However, any Independent Party Review shall not commence until receipt
of the Notification (defined below) by the Independent Party from Seller. If
Seller and Buyer are unable to agree upon the scope of work by ten (10) months
prior to the Effective Date, then the scope of work outlined in Exhibit O shall
apply. If, for any reason, the Independent Party is unwilling or unable to
contract with Buyer and Seller to perform an Independent Party Review, then,
Seller may choose another accounting firm from Buyer's list. If the next
accounting firm from Buyer's list is unwilling to perform, then Buyer shall
provide Seller with a list of another three accounting firms from Exhibit M and
the process shall be repeated until a contract is signed with an Independent
Party.
On or before 91 days prior to the Effective Date Seller may notify
Buyer in writing that Seller is electing an Independent Party Review, as
defined below. If Seller notifies Buyer of such an election, Seller on behalf
of both Seller and Buyer shall at the time of such election also notify the
Independent Party to commence to perform the Independent Party Review pursuant
to the contract signed between the Independent Party, Buyer and Seller (the
"Notification"). If Buyer has elected to use a third party to compile the FERC
data under Subsection 9(i)(2)(b), the Notification shall indicate whether the
Independent Party shall use a third party selected by Seller to compile the
FERC data. The Independent Party's cost of using such a third party shall be
borne by Seller. The Notification shall also indicate to the Independent Party
whether the Independent Party Review is being performed on Provisional Adjusted
Bid Prices, the value of the Adjusted Base Price as of the Bid Due Date and the
Annual Base Quantity for the year the Redetermined Base Price is effective.
Seller shall concurrently provide Buyer with a copy of the Notification.
The Independent Party Review shall verify (1) that the Bids that are
the basis of the Full Volume and Half Volume Adjusted Bid Prices are Acceptable
Bids and (2) that the Full Volume Adjusted Bid Price and the Half Volume
Adjusted Bid Price have been correctly determined in accordance with the
formula in Subsection 9(i)(2)(d)(1) and the procedures of Exhibit J
("Independent Party Review"). Within seven (7) working days after receipt of
Seller's notice that Seller is electing an Independent Party Review, Buyer
shall submit copies of the Bids, Buyer's calculations of the Full Volume and
Half Volume Adjusted Bid Prices and all supporting data, including all quality
data used in such calculations, to the Independent Party to enable the
Independent Party to conduct the Independent Party Review. The supporting data
provided to the Independent Party by Buyer shall include but not be limited to
the number of Acceptable Bids used by Buyer in the
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calculation of the Full Volume and Half Volume Adjusted Bid Prices, the
quantities in trillion Btus corresponding to each Acceptable Bid, the values of
RCsc and RCbt, whether Buyer used a third party in compiling the FERC data, and
whether the Adjusted Base Price under the Agreement, along with the
corresponding quantity in trillion Btus, was used in the calculation of such
prices. Buyer will notify Seller when the supporting data has been submitted
to the Independent Party and of the values of RCsc and RCbt provided to the
Independent Party. Upon request by the Independent Party, Buyer shall allow
the Independent Party to review the original Bids at Buyer's offices.
If the Independent Party in its sole judgment is unable to verify that
either the Bids are Acceptable Bids or that Buyer's determination of the Full
Volume Adjusted Bid Price and the Half Volume Adjusted Bid Price are correct,
then the contract with the Independent Party shall provide that (1) the
Independent Party notify Buyer and Seller in writing that it was unable to
verify and (2) the Independent Party shall obtain such additional information
which in its sole judgement is necessary for it to correctly establish the Full
Volume Adjusted Bid Price and the Half Volume Adjusted Bid Price in accordance
with Subsection 9(i)(2) and Exhibit J. After so notifying both Buyer and
Seller, the Independent Party may consult with only Buyer to assist it in
obtaining such additional information needed in respect of any Bid but the
Independent Party may consult with Seller, Buyer or any third party (except a
third party who provided a Bid or any other coal producer or the independent
lab for any coal producer) for any other additional information. The contract
with the Independent Party shall provide that the Independent Party shall not
consult with Seller or Buyer concerning the meaning or intent of this
Agreement.
Buyer and Seller's contract with the Independent Party shall provide
that the Independent Party issue a report to Seller and Buyer covering the
results of the Independent Party's work by 60 days prior to the Effective Date.
The report shall include only whether the Independent Party was able to make
the verification in the Independent Review and, if not, the Independent Party's
own determination of the Full Volume and/or Half Volume Adjusted Bid Prices in
accordance with the formula in Subsection 9(i)(2)(d)(1) and the procedures of
Exhibit J. If the Independent Party provides its own determination of the Full
Volume and Half Volume Adjusted Bid Price, such determination shall be final
(subject to revision if the Independent Party Review was conducted on
Provisional Adjusted Bid Prices) and not subject to challenge by either Buyer
or Seller. If Seller previously elected an Independent Party Review based on
Provisional Adjusted Bid Prices, the contract with the Independent Party shall
provide that the Independent Party shall issue a revised report
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reflecting the use of the New Quarter Rate within seven days of receipt of the
New Quarter Rate from Buyer. The expense of the Independent Party Review shall
be shared equally by Seller and Buyer.
(4) Redetermined Base Price Components, Base Date, Base Indexes
When any Redetermined Base Price is established, then (1) new
values shall be established for the components of the Redetermined Base Price
as described below (2) the Base Date shall be changed to the applicable
Effective Date for purposes of applying the Base Price adjustment procedures
set forth in Subsections 9(a) through 9(d) to the Redetermined Base Price and
(3) the Base Index values for A, B and C shown in Table 1 of Subsection 9(a)
shall be changed to the appropriate values as specified in Table 1 of
Subsection 9(a) to correspond to the new Base Date.
The values of the Redetermined Base Price components shall be determined as
follows:
(a) The values of the Royalty and Tax Components covered
by Subsections 9(b) and 9(c) shall be calculated upon the Redetermined Base
Price, using Seller's good faith estimates of the royalty and tax amounts
applicable during the year in which the Redetermined Base Price is effective.
When all final values of the Royalty and Tax Components are known, (subject to
audit by Buyer under Section 14 and/or governmental authorities) for the year
in which the Redetermined Base Price becomes effective, the estimated values
shall be replaced with the final values effective as of the Effective Date of
the Redetermined Base Price. The value of the Base Adjustable Component shall
then be recalculated in (c) below, the value of which shall also be effective
as of the Effective Date of the Redetermined Base Price. The Current
Adjustable Components calculated during the periods in which estimated values
were used shall then be recalculated using the recalculated Base Adjustable
Component, as provided in Subsection 9(a). Any amounts due Seller or Buyer
after all final values for the Royalty and Tax Components are known, (subject
to audit by Buyer under Section 14 and/or governmental authorities) and the
Base Adjustable Component is recalculated and adjusted under Subsection 9(a)
shall be paid by one party to the other within 15 days of receipt of Seller's
invoice or credit showing the revised calculation.
(b) The sum of the values of the Royalty and Tax
components determined in (a) above, shall be subtracted from the Redetermined
Base Price.
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(c) The remainder of the Redetermined Base Price shall
become the Base Adjustable Component.
(5) Limitation on Other Changes
Neither Buyer or Seller shall demand or request that any other
terms or conditions under this Agreement be altered as part of any
redetermination of the Base Price."
14. Section 10 "Adjustments for Btu Value" shall be amended in its
entirety to read as follows:
"SECTION 10 - Adjustments for Btu Value
The Base Price in effect from June 27, 1990 through December 31, 1993
and the Requirements Base Price per ton of coal are based upon coal having an
assumed heating value of 8,800 Btu's per pound, on an "as received" basis at
the Point of Delivery. Each time the Base Price is redetermined under
Subsection 9(i), and each time a Matching Coal Price is determined under
Subsection 1(d)(4) the Redetermined Base Price or the Matching Coal Price, as
the case may be, per ton of coal will be based upon coal having an assumed
heating value equal to the FERC Btu Content for Black Thunder Coal used to
perform the calculation for the Full Volume Adjusted Bid Price and/or Half
Volume Bid Price under Subsection 9(i)(2)(d) and Exhibit J or the Matching Coal
Bid Price under the calculation procedures of Exhibit N, as the case may be
("Redetermined Heating Value").
The Adjusted Base Price, the Adjusted Requirements Base Price and the
Matching Coal Price, as the case may be, shall each be further adjusted each
month in order to compensate for any variations in the assumed heating value of
the coal delivered hereunder during that month pursuant to the formula listed
below. The following formula shall be applied separately to coal delivered to
the Muskogee Units and the Sooner Units.
CV = AP + [ C - B x (AP + TC) ]
B
Where:
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CV = The price adjustment for Btu value of Annual Base
Quantity Coal, Requirements Coal, or Matching Coal,
as the case may be, delivered to Buyer.
AP = Adjusted Base Price or the Adjusted Requirements Base
Price, as the case may be, in dollars per ton
computed as provided in Section 9 or the Matching
Coal Price, as the case may be.
C = Monthly weighted average Btu's per pound of Annual
Base Quantity Coal, or Requirements Coal, or Matching
Coal, as the case may be, on an "as received" basis
for coal delivered to the Muskogee Units or the
Sooner Units, as the case may be, as determined under
Section 12.
B = 8,800 Btus per pound during the period June 27, 1990
through 1993 beginning with ton number 2,850,001 on
train 124BTFGC. After 1993, B shall equal the
Redetermined Heating Value for Annual Base Quantity
Coal or Matching Coal, as the case may be.
TC = The then current transportation rail rate (exclusive
of any additional transportation- related cost) in
dollars per ton from Seller's Mine to the Muskogee
Units or the Sooner Units, as the case may be.
15. Subsection 13(a) shall be deleted and replaced by the following:
"On or before the fifth day after the fifteenth and the end of each calendar
month, Seller shall invoice Buyer for coal delivered by Seller to Buyer during
the preceding semi-monthly period. Buyer shall pay Seller within 15 days after
receipt of such invoice the amount of such invoice, subject however to
adjustment as provided in Subsection 13(b) below. Such invoice shall show the
actual amounts of coal delivered to Buyer, as determined by Section 11 hereof,
times the current Adjusted Base Price or the Adjusted Requirements Base Price
or the Matching Coal Price, as the case may be, then in effect for Annual Base
Quantity Coal or Requirements Coal, or Matching Coal, respectively. Both
parties agree that any adjustments to prior invoices of coal affected by this
1990 Amendment shall be invoiced or credited promptly upon execution of this
1990 Amendment and payment shall be due to Seller or credit due to Buyer within
15 days of receipt of invoice.
During each calendar year of the period January 1, 1991 through
December 31, 1993 Seller shall: 1) apply the Adjusted Base Price, to the first
8.36 trillion Btu's of coal delivered each month; and 2) apply the
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Adjusted Requirements Base Price to all quantities of coal delivered each month
in excess of 8.36 trillion Btu's, unless Buyer has given notice to Seller under
Section 4 that Buyer estimates it will not purchase any Requirements Coal.
However, if Buyer fails for any reason, to take at least 8.36 trillion Btu's of
Annual Base Coal Quantity in any month, then the shortfall from that month
shall be added to the following month's quantity to be purchased and sold at
the Adjusted Base Price then in effect. For 1990 only, Seller shall apply the
Adjusted Requirements Base Price to all quantities of coal delivered to Buyer
after the Annual Base Quantity for 1990 has been delivered to Buyer.
Notwithstanding the provisions of the second paragraph of this
Subsection 13(a), if, by July 1 of any calendar year during the period January
1, 1991 through December 31, 1993 Buyer has failed for any reason to take
delivery of 50.16 trillion Btus of Annual Base Quantity Coal and Requirements
Coal has been delivered during such six-month period, then all or part of such
Requirements Coal shall be redesignated as Annual Base Quantity Coal until a
maximum quantity of 50.16 trillion Btus has been redesignated as Annual Base
Quantity Coal for such six- month period. Seller shall retroactively revise
the pricing of such redesignated coal to reflect the application to such
redesignated coal of the Adjusted Base Price which is in effect at the time of
such redesignation. Any coal redesignated shall begin with the first
Requirements Coal delivered during the six-month period. Buyer will pay Seller
the increased amount due for all such redesignated coal within fifteen (15)
days of receipt of Seller's invoice.
After the end of each calendar year during the period January 1, 1990
through December 31, 1993 if, for any reason, other than Seller's failure to
deliver due to Seller's force majeure or Seller's default, Buyer has not taken
delivery of the Annual Base Quantity during the previous calendar year, then
Seller shall retroactively change the price of all Annual Base Quantity coal
purchased in that year (which shall include any Requirements Coal redesignated
under the immediately preceding paragraph) from the 1990, 1991, 1992, or 1993
Base Price, as the case may be, as adjusted under Sections 9 and 10, to the
Alternative Base Price in effect for the year in which the Annual Base Quantity
was not taken, as adjusted under Sections 9 and 10. However, for 1990, the
Alternative Base Price will only apply to all coal purchased by Buyer beginning
with the first ton of coal delivered after 2,850,000 tons of coal are delivered
during 1990. Buyer will pay Seller the increased amount due for all such coal
within fifteen (15) days of receipt of Seller's invoice. However, if Buyer has
failed to take delivery of the Annual Base Quantity by one unit trainload or
less, then the Base
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Price shall not be retroactively changed for that year and the quantity not
taken for that year shall be added to the Annual Base Quantity for the
following year.
After the end of each calendar year during the period January 1, 1990
through December 31, 1993, if for any reason, the quantity of Requirements Coal
taken by Buyer is different than the quantity of Requirements Coal estimated to
be purchased by Buyer under Section 4 then Seller shall retroactively revise
the Adjusted Base Price of Annual Base Quantity Coal to either (1) exclude the
applicable Price Discounts to the extent Buyer has not taken the corresponding
quantity of Requirements Coal or (2) Seller shall apply any additional
applicable Price Discounts if Buyer has taken delivery of more than the
estimated quantity of Requirements Coal. Any invoices for increased amounts
due from Buyer or for credits due Buyer shall be issued by Seller to Buyer by
January 15 after the end of each calendar year. Buyer will pay Seller any
increased amount due within fifteen (15) days of receipt of Seller's invoice."
16. The fourth sentence of Subsection 15(b) "Force Majeure" beginning with
"Any deficiencies..." shall be amended in its entirety to read as follows:
"Any deficiencies in deliveries of coal under this Agreement which are
caused by Force Majeure shall be made up by Seller as soon as practical after
determination of the effects of such Force Majeure, except to the extent, if
any, (1) that Buyer was required to and did purchase other coal in order to
maintain its Units in operation during such period, or cannot reasonably use
any part of such deficiencies in the ordinary course of business after such
determination; provided, however, that Seller shall not be required to add to
or increase the capacity of its mining facilities to make up such deficiencies,
or (2) that, if as a result of an event of Force Majeure, a Unit is unable to
generate any electricity (Downed Unit) for a continuous period of greater than
30 days, then any deficiency in deliveries of coal so caused which remain at
the end of the calendar year in which the Force Majeure event occurred shall
not be made up except by mutual consent."
17. Exhibit A "Gillette Area", Exhibit B "ARCO Coal Reserve Area" and
Exhibit F "Appendix A-1971 Bituminous Coal Wage Agreement" shall be deleted;
the following Exhibits are incorporated: (1) Exhibit A "Black Thunder Mine
Reserve Area", (2) Exhibit B "Black Thunder Royalty Provisions", (3) Exhibit
F-1 "Base Prices for the Period June 27, 1990 through December 31, 1993", (4)
Exhibit F-2, "1990 Base Price
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Components" (5) Exhibit F-3 "Requirements Base Price Components". (6) Exhibit
H "An Illustration of the Application of the Price Discounts" (7) Exhibit I "An
Illustration of a Determination of a Current Adjustable Component" (8) Exhibit
J "The Determination of the Full Volume Adjusted Bid Price and the Half Volume
Adjusted Bid Price" (9) Exhibit K "Low Quality Suitable Coal" (10) Exhibit L
"Unacceptable Coal" (11) Exhibit M "Ten Largest U.S. Accounting Firms for 1989"
(12) Exhibit N "Independent Party Scope of Work Matching Coal Price" (13)
Exhibit O "Independent Party Scope of Work Full Volume and Half Volume Adjusted
Bid Prices" and (14) Exhibit P "Services Agreement".
18. This 1990 Amendment and the Agreement as previously amended contain
the entire Agreement between the parties with respect to the subject matter
herein and supersedes all previous writings, understandings, representations or
agreements with respect thereto.
19. The provisions of Subsections 9(b) and 9(c) shall survive termination
or expiration of this Agreement for a period of two years.
20. Calculations performed under this Agreement shall be performed to the
same decimal place as shown in the examples or illustrations shown in the
Agreement. If no example or illustration is shown or unless otherwise
specified, calculations shall be rounded to the fourth decimal place (0.0000).
Upward rounding shall occur when the digit in the next decimal place is 5 or
above. Downward rounding shall occur when the digit in the next decimal place
is 4 or below.
21. Nondisclosure
Buyer and Seller agree that the following ("Confidential Information")
shall be kept confidential and not disclosed to third parties:
1. The following provisions of this 1990 Amendment: Sections
2(c), 8, 9(a), through 9(h), the Exhibits F-1, F-2, F-3, H, I,
J, K, and Exhibit N except Appendix 2 and Exhibit O except
Appendix 2;
2. The formula contained in Section 9(i)(2)(d)(1) and the data to
be used therein except for the rail rates.
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3.
[CONFIDENTIAL TREATMENT HAS BEEN REQUESTED. ACCORDINGLY,
THIS SECTION HAS BEEN OMITTED AND FILED SEPARATELY WITH
THE SECURITIES AND EXCHANGE COMMISSION.]
Disclosure of the Confidential Information may be made to the parent
company, employees, directors, officers and agents of either party subject to
the above confidentiality restriction.
Except as limited by the foregoing, nothing in this Section 21 shall
prevent Buyer from discussing any portion of this 1990 Amendment with third
parties; nothing in the foregoing shall prevent disclosure of Exhibits N and O
to the firms listed on Exhibit M.
If disclosure of Confidential Information is required by law or by
regulation or orders of any administrative or judicial body having jurisdiction
over Buyer or Seller, as the case may be, or as required for evidentiary
purposes in any legal proceeding, the same may be disclosed provided notice
thereof is given by one party to the other in advance of any required
disclosure to give the other time to oppose such disclosure. The obligations
of confidentiality and nondisclosure contained herein shall not apply to this
1990 Amendment or the contents of this 1990 Amendment which through no fault of
either party becomes part of the public knowledge. Buyer and Seller's
obligation of nondisclosure shall terminate on December 31, 2008 unless this
Agreement is earlier terminated in which case such obligation shall terminate
upon the expiration of this Agreement.
Buyer and Seller further agree that, as amended by this 1990 Amendment, the
Agreement shall remain in full force and effect.
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Buyer and Seller have caused this 1990 Amendment to the Agreement to be
executed, each by its authorized representative.
THUNDER BASIN COAL COMPANY
By___________________________
Its__________________________
Date:________________________
Attest:______________________________
OKLAHOMA GAS & ELECTRIC COMPANY
By___________________________
Its__________________________
Date:________________________
Attest:______________________________
<PAGE> 1
EXHIBIT 10.08
AMENDED AND RESTATED
STOCK EQUIVALENT AND DEFERRED COMPENSATION PLAN
FOR DIRECTORS OF OKLAHOMA GAS AND ELECTRIC COMPANY
ARTICLE I.
PURPOSES, DEFINITIONS AND GENERAL PROVISIONS
1.1. Purposes.
The purposes of this Plan are: (i) to cause a portion of the
compensation of each non-employee director of Oklahoma Gas and Electric Company
to be paid in equivalents of common stock of the Company and (ii) to offer such
non-employee members the opportunity to defer receipt of the balance of their
directors' compensation, under terms advantageous to both the director and the
Company, until termination of the director's service with the Company.
1.2. Definitions.
(a) "Award" shall mean the amount, expressed either in
dollars of Compensation or in Stock Equivalents, that the Board determines
pursuant to Section 1.4 hereof will be paid to a Participant on an Award Date.
(b) "Award Date" shall mean the date an Award is to be
received by a Participant.
(c) "Board" shall mean the Board of Directors of the
Company.
(d) "Beneficiary" shall mean the person or persons
(including, without limitation, the trustees of any testamentary or inter vivos
trust) designated from time to time in writing by a Participant to receive
payments under the Plan after the death of such Participant, or, in the absence
of any such designation or in the event that such designated persons or person
shall predecease such Participant, or shall not be in existence or shall
otherwise be unable to receive such payments, the person or persons designated
under such Director's last will and testament or, in the absence of such
designation, to the Participant's estate; provided, that the term "Beneficiary"
shall mean the person or persons designated under the rules of the insurance
company in the case of an insurance policy acquired pursuant to Article III
hereof.
(e) "Committee" shall mean those management members of
the Company, namely the Chairman of the Board, President, Chief Financial
Officer and Corporate Secretary, who administer the Plan, provided all such
persons are not eligible to participate in the Plan. All decisions by the
Committee shall be by simple majority and the decisions will be final.
(f) "Company" shall mean Oklahoma Gas and Electric
Company, an Oklahoma corporation, and any successor thereof.
(g) "Compensation" shall mean payments which the Director
receives from the Company for services as a member of its Board of Directors.
Such payments may include directors' retainers, board meeting fees and
committee meeting fees, but shall exclude direct reimbursement of expenses.
(h) "Deferred Amount" shall mean an amount of
Compensation deferred at the election of the Participant under this Plan.
(i) "Director" shall mean any member of the Board of
Directors of the Company who is not an employee of the Company.
<PAGE> 2
(j) "Dollar Account" shall mean the bookkeeping account
to which a Participant has Deferred Amounts credited under Section 2.2 of this
Plan to earn interest as provided therein.
(k) "OG&E Stock" shall mean the common stock of the
Company, par value $2.50 per share.
(l) "Participant" shall mean any Director who receives an
Award or who elects to defer Compensation pursuant to this Plan.
(m) "Plan" shall mean the Amended and Restated Stock
Equivalent and Deferred Compensation Plan for Directors of the Company, as from
time to time amended and in effect.
(n) "Stock Account" shall mean the bookkeeping account to
which a Participant has Awards and Deferred Amounts credited under Section 2.2
of this Plan with Stock Equivalents as provided therein.
(o) "Stock Equivalents" shall mean the units,
representing a like number of shares of OG&E stock, that are credited to a
Director's Stock Account under Section 2.2 of this Plan.
(p) "Termination of Service" shall mean the termination
(by death, retirement or otherwise) of a Participant's service as a Director of
the Company.
2
<PAGE> 3
1.3. Deferral Of Compensation.
Each Director may elect to have all or a portion of his
Compensation for any calendar year deferred under this Plan. Such election
shall be executed in writing by the Director and filed with the Secretary of
the Company, prior to the beginning of the calendar year during which such
Compensation is earned, on a form prescribed by the Company. The election may
specify that the Participant desires to have all or a specified percentage of
his Compensation (other than any portion subject to an Award) for the year
deferred under the Plan. The election shall specify which portion or portions
of such Deferred Amount shall be allocated between Article II and Article III
hereof, subject to the following:
(a) An election to treat all or any portion of a Deferred
Amount as being governed under Article II hereof shall designate the portion or
portions to be credited to the Participant's Dollar Account and/or Stock
Account governed under that Article, and shall be irrevocable for the first
calendar year to which such election relates, and it shall continue in effect
for subsequent calendar years until changed prospectively by the Participant
before the beginning of the calendar year for which the change is effective;
subject, however, in each instance to the provisions in the last paragraph of
Section 2.2 and provided, further, that a Participant subsequently may elect in
accordance with Section 2.3 to transfer all or part of his Dollar Account
Balance to a Stock Account.
(b) An election to treat all or any portion of a Deferred
Amount as being governed under Article III hereof shall be irrevocable at all
times until the Director's Termination of Service.
1.4. Awards.
The amount and number of Awards that may be granted under this
Plan is subject to the sole discretion of the Board and shall be determined in
the sole discretion of the Board. Each Award shall contain such terms,
restrictions and conditions as the Board may determine that are not
inconsistent with this Plan, provided that Awards shall be payable to a
Participant only in cash and, subject to Section 2.5 hereof, only upon a
Participant's Termination of Service. Awards shall be made either in Stock
Equivalents or as a dollar amount of Compensation, as determined in the sole
discretion of the Board.
3
<PAGE> 4
ARTICLE II.
AWARDS AND STRAIGHT CASH DEFERRED COMPENSATION
2.1. General.
To the extent a Director receives an Award pursuant to Section
1.4 hereof, such Award shall be subject to the following provisions of this
Article. To the extent that a Director elects to treat any portion of his
Deferred Amount as being governed under this Article II, then the following
provisions under this Article also shall be applicable with respect to such
portion of his Deferred Amount. References to "Deferred Amount" under this
Article II shall mean that portion of the Deferred Amount which the Director
elects to be governed under this Article.
2.2. Treatment Of Deferred Amounts and Awards.
The Company shall establish on its books the necessary
bookkeeping accounts to accurately reflect the Company's liability to each
Participant who has deferred Compensation under this Article or who has
received an Award pursuant to Section 1.4. To these accounts shall be credited
Awards and Deferred Amounts, plus increments as described hereafter. Payments
to the Participant or his Beneficiary following Termination of Service shall be
debited to the accounts. In addition, debits and credits to the accounts shall
be made in the manner provided in Section 2.3 and in the last paragraph of this
Section 2.2 in the event of a transfer pursuant to Section 2.3 or pursuant to
the last paragraph of this Section 2.2. The standing balance in each account
is hereafter referred to as the "Account Balance." Despite the maintenance of
such bookkeeping accounts, the Company's obligation to make payments under the
Plan shall be made from the Company's general assets and property. The Company
may, in its sole discretion, establish a separate fund or account to make
payment of benefits to a Participant or his Beneficiary or Beneficiaries
hereunder. Whether or not the Company, in its sole discretion, does establish
such a fund or account, no Participant, his Beneficiary or Beneficiaries or any
person shall have, under any circumstances, any interest whatever in any
particular property or assets of the Company by virtue of this Plan.
A Participant who has elected to defer Compensation under this Article shall
direct on the deferral election made pursuant to Section 1.3 that the Deferred
Amount be credited to a Dollar Account or a Stock Account, or partially to one
Account and partially to the other Account, on the same date that it would
otherwise be payable to him. Such Deferred Amounts and any Awards shall also
be subject to the following terms and conditions:
(a) Dollar Account. Deferred Amounts credited to this
Account shall accrue interest from the date of credit to the date of transfer
in accordance with Section 2.3, or to the date of payment in accordance with
Section 2.4 or Section 2.5, at a variable rate of interest determined quarterly
on a prospective basis. Interest shall be credited as of the end of each
calendar quarter and, in the event of a transfer in accordance with Section 2.3
or a payment in accordance with Section 2.4 or Section 2.5, as of the close of
business on the day immediately preceding the date of such transfer or payment.
The interest rate for each quarter shall be equivalent to the one month
commercial paper rate quoted by Salomon Brothers in its Bond Market Roundup, or
by such other recognized source as the Company may designate, for the week in
which the preceding calendar quarter ends.
(b) Stock Account. Awards in the form of Stock
Equivalents shall be credited to this Account. Awards expessed in dollars of
Compensation also shall be credited to this Account and shall be converted into
Stock Equivalents equal to the number of shares of OG&E stock, to three decimal
places, that could be purchased on the Award
4
<PAGE> 5
Date with the dollar amount of such Award, at a price per share equal to the
arithmetical mean of the highest and lowest quoted selling prices on the New
York Stock Exchange Composite Tape for such day. If there are no sales on that
day, then such mean on the next preceding day on which there are such sales
shall be used.
Deferred Amounts credited to this Account shall be converted into
Stock Equivalents equal to that portion of the Deferred Amount which the
Participant elected to have so credited. The Stock Equivalents shall be equal
to the number of shares of OG&E stock, to three decimal places, that could be
purchased on the day that such portion of the Participant's Deferred Amount
would otherwise be paid, at a per share price equal to the arithmetical mean of
the highest and lowest quoted selling prices on the New York Stock Exchange
Composite Tape for such day. If there are no sales on that day, then such mean
on the next preceding day on which there are such sales shall be used.
A Participant who has a Deferred Amount governed by the terms
of Article II of this Plan, as in effect prior to its amendment and restatement
as of December 1, 1989, shall have his Account Balance as of December 1, 1989,
transferred to a Dollar Account; provided, however, that the Participant may
file a written election with the Secretary of the Company on or before December
31, 1989, to have part or all of his Dollar Account Balance as of January 31,
1990, transferred to a Stock Account. The transfer shall be on the basis
described in Section 2.3. Either or both of such accounts shall thereafter be
governed by the terms of this Plan.
On each date on which a dividend in cash or property is
distributed on shares of issued and outstanding OG&E stock, the Stock Account
of a Participant shall be credited with a number of Stock Equivalents based
upon the amount of cash or the fair market value of any property (the "base
amount") distributed with respect to a number of shares of issued and
outstanding OG&E stock equal to the number of Stock Equivalents (including
fractions) standing to the Participant's credit in his Stock Account on the
record date for such distribution (assuming that fractional shares could be
held of record and that distributions were made with respect thereto). The
number of Stock Equivalents to be so credited shall be equal to the number of
shares of OG&E stock, to three decimal places, that could be purchased on such
dividend distribution date with the base amount at a per share price equal to
the mean between the highest and lowest selling prices on the New York Stock
Exchange Composite Tape for that day. If there are no sales on that day, then
such mean on the next preceding day on which there are such sales shall be
used.
On each date on which a stock dividend or stock split is
distributed on shares of OG&E stock, a Participant's Stock Account shall be
credited with a number of Stock Equivalents equal to the number of shares which
would have been distributed with respect to a number of shares of issued and
outstanding OG&E stock equal to the number of Stock Equivalents (including
fractions) standing to the Participant's credit in his Stock Account on the
record date for such distribution (assuming that fractional shares could be
held of record and that fractional shares would be distributed).
In the event that the Company shall be a party to any
consolidation or merger or share exchange and, in connection with such
transaction, all or part of the outstanding shares of OG&E stock shall be
changed into or exchanged for stock or other securities of any other entity or
of the Company or cash or any other property, then the Account Balance in a
Participant's Stock Account shall be transferred on the day immediately
preceding the effective date of such transaction to a Dollar Account for the
Participant, with the Participant's Stock Account being debited with the number
of Stock Equivalents in the Stock Account immediately prior to the transfer and
the Participant's Dollar Account being credited with an amount equal to the
number of Stock Equivalents in the Participant's Stock Account immediately
prior to such transfer multiplied by the mean between the highest and lowest
selling prices for OG&E stock on the New York Stock Exchange Composite Tape on
the date of such transfer or, if there are no sales on such day, such mean on
the next preceding date on
5
<PAGE> 6
which there are such sales. Following such event, no additional amounts shall
be credited to the Stock Account and all future Deferred Amounts that were to
be credited to a Stock Account shall be credited to a Dollar Account, until
changed by the Participant pursuant to Section 1.3.
2.3. Transfers From Dollar Accounts To Stock Accounts.
Each Participant may elect, on an annual basis, to have all or
a portion of his Dollar Account transferred to a Stock Account. Such election
shall be executed in writing by the Participant and filed with the Secretary of
the Company prior to December 31 of a calendar year to be effective as of the
close of business on January 31 of the succeeding calendar year. The
Participant's Dollar Account shall be debited with the amount so transferred
from such account to the Participant's Stock Account. The number of Stock
Equivalents to be credited to the Participant's Stock Account shall be
determined by dividing the amount to be transferred from the Participant's
Dollar Account by a per share price equal to the mean of highest and lowest
quoted selling prices of OG&E stock on the New York Stock Exchange Composite
Tape for the January 31 date of transfer. If there are no sales on that day,
then such mean on the next preceding day on which there are such sales shall be
used. Transfers from a Participant's Stock Account to a Dollar Account shall
not be permitted, except as provided in the last paragraph of Section 2.2
hereof.
2.4. Payment Of Awards and Deferred Amounts.
Upon Termination of Service, a Participant's aggregate Account
Balances in his Dollar Account and Stock Account under this Article shall be
paid to the Participant (or, in the event of Particpant's death, his
Beneficiary) in such number of annual installments (not exceeding 5), as shall
be determined by the Committee in its sole discretion. The Committee may
consult with the Participant prior to such determination, but the Committee
will not be obligated by the desires of the Participant. Such payments shall
commence not later than one year after Termination of Service and shall be made
in cash out of the general assets and property of the Company. Regardless of
when Termination of Service occurs, however, no payment of a Participant's
Dollar Account and Stock Account Balances may commence until the Participant
has attained age 50. In converting a Participant's Stock Equivalents in his
Stock Account into cash for payment purposes, such conversion shall be made on
each payment date to such Participant based on the then current value of the
shares of OG&E stock reflected in his Stock Account. For purposes of the
preceding sentence, value shall be determined based upon the mean between the
highest and lowest selling prices for OG&E stock on the New York Stock Exchange
Composite Tape on the date immediately preceding the payment date. If there
are no sales on that day, then such mean on the next preceding day on which
there are such sales shall be used.
2.5. Acceleration Of Payments.
The Committee, within its sole discretion, is empowered to
accelerate the payment of a Participant's Dollar Account Balance or Stock
Account Balance to such Participant or his Beneficiary, whether before or after
the Participant's Termination of Service, for good and substantial reasons,
such as the Participant's death, disability, hardship or other adverse need,
changes in the tax laws or accounting principles adversely affecting the Plan
and its effect on the Company, the Participants or their Beneficiaries, or
other similar reasons acceptable to the Committee; except that, prior to a
Participant's Termination of Service, the Committee may accelerate the payment
of all or part of a Participant's Stock Account Balance only upon the
Participant's disability.
6
<PAGE> 7
ARTICLE III.
CASH DEFERRED COMPENSATION/SPLIT DOLLAR INSURANCE
3.1. General.
To the extent that a Director elects to treat any portion of
his Deferred Amount as being governed under this Article III, then the
following provisions under this Article shall be applicable with respect to
such Deferred Amount. References to "Deferred Amount" under this Article III
shall mean that portion of the Deferred Amount which the Director elects to be
governed under this Article.
3.2. Insurance Policy.
After consulting with a Participant, the Committee, on behalf
of the Company, shall obtain a premium policy or policies of insurance on the
life of the Participant (the "Policy"), and enter into an appropriate agreement
with the insurance company, the terms of which Policy and agreement shall be
based upon those the Committee deems advisable, within its sole discretion,
subject, however, to the following provisions prior to the time the Participant
has a Termination of Service.
(a) All premiums due on the Policy shall be paid by the
Company from the Deferred Amount, but shall in no event exceed the
Participant's Deferred Amount.
(b) In the event of the death of the Participant, the
Company, its successors or assigns, shall be entitled to receive from the life
insurance proceeds under the Policy an amount equal to the premiums, without
interest thereon, the Company has paid.
(c) Any portion of the death proceeds which is in excess
of the amount payable to the Company, its successors or assigns, shall be
payable to the person or persons entitled thereto under the Policy.
3.3. Ownership Of Policy.
The Policy may reserve to the Participant, or his assignee,
the sole right to change the Beneficiaries for any amount payable thereunder in
the event of the Participant's death, but, notwithstanding anything herein to
the contrary, each and every other right of ownership of such Policy shall be
reserved solely to, and be absolutely vested in, the Company.
3.4. Possession Of Policy.
The Company shall keep possession of the Policy.
3.5. Deferred Compensation At Death.
In the event that the Participant dies before a Termination of
Service, the Company agrees to pay, out of the general assets of the Company,
to the deceased Participant's Beneficiary an amount of deferred compensation
equal to the amount received by the Company under subparagraph (b) of Section
3.2 hereof. Such amount may be paid in the manner
7
<PAGE> 8
set forth in Sections 2.4 and 2.5 hereof; provided, the Committee may pay such
amount in a lump sum without the consent of the Participant.
3.6. Deferred Compensation At Termination Of Service.
Upon the Participant's Termination of Service for any reason
other than his death, the Company agrees to pay, out of the general assets of
the Company, to the Participant an amount of deferred compensation equal to the
then cash value of the Policy on his life. Such amounts may be paid in the
manner set forth in Sections 2.4 and 2.5 hereof; provided, the Committee may
pay such amount in a lump sum without the consent of the Participant. Provided
further, the Committee may, without the consent of the Participant, assign and
distribute such Policy to the Participant in full satisfaction of the Company's
liability under this Article III.
ARTICLE IV.
OTHER PROVISIONS
4.1. Amendment Or Termination.
The Board of Directors may amend or terminate this Plan at any
time; provided, however, that no amendment or termination shall adversely
affect any prior Awards or then existing Deferred Amounts or rights under this
Plan, and provided further that no amendment may be made to the last sentence
of Section 4.5 hereof.
4.2. Expenses.
The expenses of administering the Plan shall be borne by the
Company, and shall not be charged against any Participant's Awards or Deferred
Amounts; provided, however, that any commissions on premium payments under any
Policy issued pursuant to Article III hereof shall not be considered an expense
to be borne by the Company.
4.3. Applicable Law.
The provisions of the Plan shall be construed, administered
and enforced according to the laws of the State of Oklahoma.
4.4. No Trust.
No action by the Company or its Board of Directors under this
Plan shall be construed as creating a trust, escrow or other secured or
segregated fund or other fiduciary relationship of any kind in favor of any
Participant, his Beneficiary, or any other persons otherwise entitled to his
Awards or Deferred Amounts nor, shall any of said persons have rights under any
agreement or Policy in connection therewith between the Company and the
insurance company, except the right to designate a Beneficiary of the proceeds
of a Policy upon the death of the Participant as provided herein. The status
of the Participant and his Beneficiary with respect to any liabilities assumed
by the Company hereunder shall be solely those of unsecured creditors of the
Company. Any Policy or any other asset acquired or held by the Company in
connection with liabilities assumed by it hereunder, shall not be deemed to be
held under any trust, escrow or other secured or segregated
8
<PAGE> 9
fund or other fiduciary relationship of any kind for the benefit of the
Participant or his Beneficiaries or to be security for the performance of the
obligations of the Company, but shall be, and remain, a general, unpledged,
unrestricted asset of the Company at all times subject to the claims of general
creditors of the Company.
4.5. No Assignability And Successors.
Neither the Participant nor any other person shall acquire any
right to or interest in any amount awarded to the Participant, otherwise than
by actual payment in accordance with the provisions of this Plan, or have any
power, voluntarily or involuntarily, to transfer, assign, anticipate, pledge,
mortgage or otherwise encumber, alienate or transfer any rights hereunder in
advance of any of the payments to be made pursuant to this Plan or any portion
thereof. With respect to a Policy issued pursuant to Article III hereof,
neither the Participant nor his spouse nor any Beneficiary, shall have any
rights to transfer, assign, anticipate, pledge, mortgage or otherwise encumber,
alienate or transfer any rights hereunder in advance of any right to receive
any payments under the Policy, which payments and the rights thereto are hereby
expressly declared to be non-assignable and non-transferable. The obligations
of the Company hereunder shall be binding upon any and all successors and
assigns to the Company.
9
<PAGE> 10
4.6. Withholding.
The Company shall comply with all federal and state laws and
regulations respecting the withholding, deposit and payment of any income or
employment taxes relating to the payment of Awards or Deferred Amounts under
this Plan.
4.7. No Impact On Directorship.
This Plan shall not be construed to confer any right on the part of a
Participant to be or remain a Director or to receive any, or any particular
rate of, Compensation.
4.8. Interpretations.
Interpretations of, and determinations related to, this Plan
made by the Company in good faith, including any determinations or calculations
of Awards, Deferred Amounts or Account Balances, shall be conclusive and
binding upon all parties; and the Company and the members of the Committee
shall not incur any liability to a Participant for any such interpretation or
determination so made or for any other action taken by it in connection with
this Plan.
4.9. Effective Date.
This Plan, as amended and restated, shall be effective from
and after November 30, 1994.
OKLAHOMA GAS AND ELECTRIC COMPANY
By: __________________________
J. G. Harlow, Jr.
Chairman of the Board and
President
10
<PAGE> 1
Exhibit 23.01
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our reports dated January 26, 1995 included in the Oklahoma Gas and Electric
Company Form 10-K for the year ended December 31, 1994, into the previously
filed Post-Effective Amendment No. One to Form S-3 Registration Statement No.
33-32870, Form S-8 Registration Statement No. 33-35833, Post-Effective
Amendment No. Three to Form S-3 Registration Statement No. 2-94973, and Form
S-8 Registration Statement No. 33-52169.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma,
March 28, 1995
<PAGE> 1
EXHIBIT 24.01
POWER OF ATTORNEY
WHEREAS, OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation
(herein referred to as the "Company"), is about to file with the Securities and
Exchange Commission, under the provisions of the Securities Exchange Act of
1934, as amended, its annual report on Form 10-K for the year ended December
31, 1994; and
WHEREAS, each of the undersigned holds the office or offices in the
Company herein-below set opposite his or her name, respectively;
NOW, THEREFORE, each of the undersigned hereby constitutes and appoints
J. G. HARLOW, JR., A. M. STRECKER and D. L. YOUNG, and each of them
individually, his or her attorney with full power to act for him or her and in
his or her name, place and stead, to sign his name in the capacity or
capacities set forth below to said Form 10-K and to any and all amendments
thereto, and hereby ratifies and confirms all that said attorney may or shall
lawfully do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned have hereunto set their hands this
18th day of January, 1995.
J. G. Harlow, Jr., Chairman and President,
Principal Executive Officer and
Director /s/ J. G. Harlow, Jr.
Herbert H. Champlin, Director /s/ Herbert H. Champlin
William E. Durrett, Director /s/ William E. Durrett
Martha W. Griffin, Director /s/ Martha W. Griffin
Hugh L. Hembree, III, Director /s/ Hugh L. Hembree, III
John F. Snodgrass, Director /s/ John F. Snodgrass
Bill Swisher, Director /s/ Bill Swisher
John A. Taylor, Director /s/ John A. Taylor
Ronald H. White, M.D., Director /s/ Ronald H. White, M.D.
A. M. Strecker, Principal Financial Officer /s/ A. M. Strecker
D. L. Young, Principal Accounting Officer /s/ D. L. Young
STATE OF OKLAHOMA )
)SS
COUNTY OF OKLAHOMA )
On the date indicated above, before me, Lisa Thompson, Notary Public in
and for said County and State, personally appeared the above named directors
and officers of OKLAHOMA GAS AND ELECTRIC COMPANY, an Oklahoma corporation, and
known to me to be the persons whose names are subscribed to the foregoing
instrument, and they severally acknowledged to me that they executed the same
as their own free act and deed.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed my official
seal on the 18th day of January, 1995.
/s/ LISA THOMPSON
Lisa Thompson
Notary Public in and for the County
of Oklahoma, State of Oklahoma
My Commission Expires:
January 16, 1996
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
Oklahoma Gas and Electric Company Consolidated Statements of Income, Balance
sheets, and Statements of Cash Flow as, reported on Form 10-K as of December
31, 1994 and is qualified in its entirety by reference to such Form 10-K.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,326,890
<OTHER-PROPERTY-AND-INVEST> 7,868
<TOTAL-CURRENT-ASSETS> 298,283
<TOTAL-DEFERRED-CHARGES> 149,588
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,782,629
<COMMON> 116,177
<CAPITAL-SURPLUS-PAID-IN> 395,040
<RETAINED-EARNINGS> 409,960
<TOTAL-COMMON-STOCKHOLDERS-EQ> 921,177
0
49,973
<LONG-TERM-DEBT-NET> 730,567
<SHORT-TERM-NOTES> 30,350
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 152,400
<LONG-TERM-DEBT-CURRENT-PORT> 25,350
0
<CAPITAL-LEASE-OBLIGATIONS> 1,157
<LEASES-CURRENT> 1,166
<OTHER-ITEMS-CAPITAL-AND-LIAB> 870,489
<TOT-CAPITALIZATION-AND-LIAB> 2,782,629
<GROSS-OPERATING-REVENUE> 1,355,168
<INCOME-TAX-EXPENSE> 72,071
<OTHER-OPERATING-EXPENSES> 1,082,631
<TOTAL-OPERATING-EXPENSES> 1,154,702
<OPERATING-INCOME-LOSS> 200,466
<OTHER-INCOME-NET> (2,167)
<INCOME-BEFORE-INTEREST-EXPEN> 198,299
<TOTAL-INTEREST-EXPENSE> 74,514
<NET-INCOME> 123,785
2,317
<EARNINGS-AVAILABLE-FOR-COMM> 121,468
<COMMON-STOCK-DIVIDENDS> 107,319
<TOTAL-INTEREST-ON-BONDS> 67,680
<CASH-FLOW-OPERATIONS> 204,210
<EPS-PRIMARY> 3.01
<EPS-DILUTED> 3.01
</TABLE>
<PAGE> 1
Exhibit 99.01
--------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 11-K
ANNUAL REPORT
[X]
ANNUAL REPORT PURSUANT TO SECTION 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 (FEE REQUIRED)
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934 (NO FEE REQUIRED)
For the fiscal year ended december 31, 1994 Commission File Number 1-1097
OKLAHOMA GAS AND ELECTRIC COMPANY
EMPLOYEES' RETIREMENT SAVINGS PLAN
(Full Title of the Plan)
OKLAHOMA GAS AND ELECTRIC COMPANY
101 North Robinson
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Name of issuer of the securities held pursuant to the Plan and the Address of
its principal executive office)
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SIGNATURES
The undersigned consist of the members of the Committee having the
responsibility for the administration of the Oklahoma Gas and Electric Company
Employees' Retirement Savings Plan. Pursuant to the requirements of the
Securities Exchange Act of 1934, the Plan has duly caused this Annual Report on
Form 11-k to be signed on its behalf by the undersigned, thereunto duly
authorized, in the City of Oklahoma City and State of Oklahoma on the 29th day
of March 1995.
OKLAHOMA GAS AND ELECTRIC COMPANY
EMPLOYEES' RETIREMENT SAVINGS PLAN
By /s/ IRMA B. ELLIOTT
-------------------------
Irma B. Elliott
Chairperson
By /s/ DONALD R. ROWLETT
-------------------------
Donald R. Rowlett
Member
By /s/ R. P. SCHMID
-------------------------
R.P. Schmid
Member
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Exhibit 99.02
OKLAHOMA GAS AND ELECTRIC COMPANY
DESCRIPTION OF COMMON STOCK
The following statements are summaries of certain provisions of the
Restated Certificate of Incorporation of Oklahoma Gas and Electric Company (the
"Company") and are subject to the detailed provisions thereof. Such summaries
do not purport to be complete, and reference is made to the Company's Restated
Certificate of Incorporation (which is filed as Exhibit 4.01 to the Company's
Post-Effective Amendment No. Three to Registration Statement No. 2-94973) for a
full and complete statement of such provisions. The term "preferred stock" as
used herein means the Company's authorized shares of 4% Cumulative Preferred
Stock, par value $20 per share, its Cumulative Preferred Stock, par value $100
per share, and its Cumulative Preferred Stock, par value $25 per share.
DIVIDEND RIGHTS
After dividends on all classes and series of preferred stock have been
paid (or declared and set apart for payment) for all past dividend periods and
declared for the current dividend period, at the full rates fixed therefor,
dividends may be declared and paid on the Common Stock subject to the
restrictions set forth under the following subcaption.
LIMITATIONS ON PAYMENT OF DIVIDENDS ON COMMON STOCK
Unless the capital represented by the Common Stock (including premiums
on capital stock and retained earnings accounts) is 25% or more of total
capital (which also includes debt maturing more than one year after date of
issue), dividends (other than dividends payable in Common Stock) or
distributions on, or acquisitions for value of, Common Stock may not exceed 75%
of net income for the preceding twelve-month period after deducting dividends
accruing on preferred stock during the period; and if less than 20%, may not
exceed 50% of such net income. No portion of the retained earnings of the
Company is presently restricted by this provision. The Restated Certificate of
Incorporation further provides that no dividend may be declared or paid on the
Common Stock until all amounts required to be paid or set aside for any sinking
fund for the redemption or purchase of Cumulative Preferred Stock, par value
$25 per share, have been paid or set aside. Currently, no shares of Cumulative
Preferred Stock, par value $25 per share, are outstanding.
The Indenture, as supplemented, which secures the First Mortgage Bonds
of the Company, contains provisions providing that, so long as any Bonds are
outstanding, earned surplus (i.e., retained earnings) equal to the sum of (1)
the amount by which the aggregate of (a) provisions for retirement and
depreciation and (b) expenditures for maintenance, during the period from June
1, 1955, to the last date for which a statement of income is available, is less
than 15% of gross operating revenues (after deducting cost of electricity
purchased for resale, rentals paid for utility property and the portion of
gross operating revenues attributable to increases since January 6, 1975, in
the Company's cost of fuel used in electric generation) for that period and (2)
the amount, if any, by which all of the consideration paid by the Company in
acquiring shares of its Common Stock during the above period exceeds
$217,301,128 plus any consideration received by the Company from the sale after
September 30, 1991 of its Common Stock, shall not be available for the payment
of cash dividends on Common Stock; and that the Company shall not acquire
shares of its Common Stock for a valuable consideration if after such
acquisition the sum of (1) and (2) above would exceed its then earned surplus
(retained earnings). These provisions are not expected to affect adversely the
Company's ability to pay dividends during the foreseeable future.
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VOTING RIGHTS
Each holder of Common Stock and each holder of 4% Cumulative Preferred
Stock is entitled at all meetings of shareowners to one vote for each $2.50 of
par value of such stock held. The holders of Cumulative Preferred Stock, par
value $100 per share, and Cumulative Preferred Stock, par value $25 per share,
are not entitled to any voting rights whatsoever, except as set forth below and
as expressly provided by law.
If and when dividends payable on the 4% Cumulative Preferred Stock
shall be in default in an amount equivalent to four full quarter-yearly
dividends and thereafter until all defaults shall have been paid, the holders
of the 4% Cumulative Preferred Stock, voting separately as one class, will be
entitled to elect the smallest number of directors necessary to constitute a
majority of the Board of Directors, and the holders of the Common Stock, voting
separately as a class, will be entitled to elect the remaining directors of the
Company. This special voting right shall become vested in the holders of all
classes and series of preferred stock, as one class, if at any time there shall
be no shares of 4% Cumulative Preferred Stock outstanding.
The consent or affirmative vote of the holders of at least two-thirds
of the outstanding shares of 4% Cumulative Preferred Stock is required to: (a)
authorize or issue stock ranking prior thereto; (b) adversely change the terms
and provisions of the 4% Cumulative Preferred Stock; (c) issue shares of 4%
Cumulative Preferred Stock or of stock ranking pari passu with it as to
dividends or liquidation rights unless in exchange for or to retire an equal
number of shares of such stocks or unless specified income and capital ratio
requirements are met. Similar provisions applicable to each class of the
Cumulative Preferred Stock are also contained in the Restated Certificate of
Incorporation. The vote or consent of the holders of at least a majority of
the Common Stock is required to amend Article VII of the Restated Certificate
of Incorporation, which sets forth the classes, authorized amounts, and certain
of the terms and provisions of the stocks of the Company.
The consent or affirmative vote of the holders of at least a majority
of the outstanding shares of the 4% Cumulative Preferred Stock and of each
class of the Cumulative Preferred Stock is required under specified conditions
for the issuance of securities representing unsecured indebtedness or in case
of merger or consolidation. The Company's Restated Certificate of
Incorporation also contains "fair price" provisions, which require the approval
by the holders of at least 80% of the voting power of the Company's outstanding
Voting Stock (as defined below) as a condition for mergers, consolidations,
sales of substantial assets, issuances of capital stock and certain other
business combinations and transactions involving the Company and any
substantial (10% or more) holder of the Company's Voting Stock unless the
transaction is either approved by a majority of the members of the Company's
Board of Directors who are unaffiliated with the substantial holder or certain
minimum price and procedural requirements are met. The provisions summarized
in the foregoing sentence may be amended only by the approval of the holders of
at least 80% of the voting power of the Company's outstanding Voting Stock.
The Company's Voting Stock consists of all outstanding shares of the Company
entitled to vote generally in the election of directors and currently consists
of the Common Stock and 4% Cumulative Preferred Stock.
The Voting Stock of the Company does not have cumulative voting rights
for the election of directors. Subject to the rights described above of the
holders of the 4% Cumulative Preferred Stock to elect directors under certain
circumstances, the Company's Restated Certificate of Incorporation and By-Laws
contain provisions stating that: (1) the Board of Directors shall be divided
into three classes as nearly equal in number as possible with staggered terms
of office so that only approximately one-third of the directors are elected at
each annual meeting of shareowners; (2) directors may be removed only with the
approval of the holders of at least 80% of the voting power of the shares of
the Company generally entitled to vote; (3) any vacancy on the Board of
Directors shall be filled only by the remaining directors then in office,
though less than a quorum; (4) advance notice of introduction by shareowners of
business at annual shareowner meetings and of
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shareowner nominations for the election of directors shall be given and that
certain information be provided with respect to such matters; (5) shareowner
action may be taken only at an annual meeting of shareowners or a special
meeting of shareowners called by the President or the Board of Directors; and
(6) the foregoing provisions may be amended only by the approval of the holders
of at least 80% of the voting power of the shares generally entitled to vote.
These provisions, along with the "fair price" provisions discussed above, would
make more difficult a change in control of the Company that is opposed by the
Company's Board of Directors.
LIQUIDATION RIGHTS
In case of voluntary liquidation, dissolution or winding up of the
Company, the holders of the preferred stock are entitled, respectively, to be
paid the amounts which they would be entitled to receive if, on the date of
such action, the respective shares of the preferred stock held by them had been
redeemed by the Company. In case of an involuntary liquidation, dissolution or
winding up of the Company, the holders of the preferred stock are entitled to
be paid an amount equal to the par value of their respective shares plus the
accrued dividends thereon to the date of payment. Thereafter, the holders of
the Common Stock are entitled to receive the remaining assets and funds pro
rata, according to the number of shares of Common Stock held.
OTHER PROVISIONS
The Board of Directors may allot and issue shares of Common Stock for
such consideration, not less than the par value thereof, as it may from time to
time determine. In addition, subject to certain limitations in the Restated
Certificate of Incorporation, the Board of Directors may issue additional
series of each class of Cumulative Preferred Stock with such dividend rates and
redemption provisions (including, in the case of the Cumulative Preferred
Stock, par value $25 per share, sinking funds) as the Board of Directors may
determine. No holder of Common Stock has the preemptive right to subscribe for
or purchase any part of any new or additional issue of stock or securities
convertible into stock. The Common Stock of the Company is not subject to
further calls or to assessment by the Company.
RIGHTS TO PURCHASE SERIES A CUMULATIVE PREFERRED STOCK
On December 11, 1990, the Board of Directors of the Company declared a
dividend of one preferred stock purchase right (a "Right" or "Rights") for each
outstanding share of Common Stock of the Company. The dividend was paid on
December 31, 1990 (the "Record Date"), to shareowners of record as of such
Record Date. If and when the Rights become exercisable, each Right will
entitle the holder of record to purchase from the Company one one-hundredth of
a share of Series A Cumulative Preferred Stock, par value $25 per share
("Series A Preferred Stock") of the Company, at a price of $95 per one
one-hundredth of a share (the "Purchase Price"), although the price may be
adjusted as described below. The description and terms of the Rights are set
forth in a Rights Agreement (the "Rights Agreement") between the Company and
The Liberty National Bank and Trust Company of Oklahoma City, as Rights Agent
(the "Rights Agent").
Initially, (i) the Rights will not be exercisable, (ii) certificates
will not be sent to shareowners, (iii) the Rights will be evidenced by the
Common Stock certificates, (iv) the Rights will automatically trade with the
Common Stock, (v) the Rights and will be transferred with and only with such
Common Stock certificates, (vi) new Common Stock certificates will contain a
notation incorporating the Rights Agreement by reference and (vii) the
surrender for transfer of any certificates for Common Stock outstanding will
also constitute the transfer of the Rights associated with the Common Stock
represented by such certificate.
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Separate certificates representing the Rights will be distributed as
soon as practicable after the "Distribution Date," which is the close of
business on the earlier to occur on the tenth day following:
(i) a public announcement (or, if earlier, the date a majority of
the Board of Directors of the Company becomes aware) that a
person or group of affiliated or associated persons acquired,
or obtained the right to acquire, beneficial ownership of
Common Stock or other securities of the Company representing
20% or more of the voting power of all securities of the
Company then outstanding generally entitled to vote for the
election of directors ("Voting Power") (such person or group
being called an "Acquiring Person" and such date of first
public announcement being called the "Stock Acquisition
Date"), or
(ii) the commencement of, or public announcement of an intention to
commence, a tender or exchange offer the consummation of which
would result in the ownership of 20% or more of the
outstanding Voting Power (the earlier of the dates in clause
(i) or (ii) being called the "Distribution Date").
As soon as practicable following the Distribution Date, separate
certificates evidencing the Rights ("Right Certificates") will be mailed to
holders of record of the Company's Common Stock as of the close of business on
the Distribution Date, and such separate certificates alone will evidence the
Rights from and after the Distribution Date.
Even if they have acquired, or obtained the right to acquire,
beneficial ownership of 20% or more of the Voting Power of the Company, each of
the following persons (an "Exempt Person") will not be deemed to be an
Acquiring Person: (i) the Company, any subsidiary of the Company, any employee
benefit plan or employee stock plan of the Company or of any subsidiary of the
Company; and (ii) any person who becomes an Acquiring Person solely by virtue
of a reduction in the number of outstanding shares of Common Stock, unless and
until such person shall become the beneficial owner of, or make a tender offer
for any additional shares of Common Stock.
The holders of the Rights are not required to take any action until
the Rights become exercisable. The Rights are not exercisable until the
Distribution Date. The Rights will expire at the close of business on December
11, 2000, unless earlier redeemed or exchanged by the Company as described
below.
In order to protect the value of the Rights to the holders, the
Purchase Price and the number of shares of Series A Preferred Stock (or other
securities or property) issuable upon exercise of the Rights are subject to
adjustment from time to time (i) in the event of a stock dividend on, or a
subdivision, combination or reclassification of, the Company's Common Stock or
Series A Preferred Stock, (ii) upon the grant to holders of the Series A
Preferred Stock of certain rights or warrants to subscribe for Series A
Preferred Stock or convertible securities at less than the current market price
of the Series A Preferred Stock or (iii) upon the distribution to holders of
the Series A Preferred Stock of evidences of indebtedness or assets (excluding
dividends payable in Series A Preferred Stock) or of subscription rights or
warrants (other than those referred to above).
These adjustments are called anti-dilution provisions and are intended
to ensure that a holder of Rights will not be adversely affected by the
occurrence of such events. With certain exceptions, the Company is not
required to adjust the Purchase Price until cumulative adjustments require a
change of at least 1% in the Purchase Price.
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In the event (i) any Person (other than an Exempt Person) becomes an
Acquiring Person (except pursuant to an offer for all outstanding shares of
Common Stock that the independent directors determine prior to the time such
offer is made to be fair to and otherwise in the best interest of the Company
and its shareowners) or (ii) any Exempt Person who is the beneficial owner of
20% or more of the outstanding Voting Power of the Company fails to continue to
qualify as an Exempt Person, then each holder of record of a Right, other than
the Acquiring Person, will thereafter have the right to receive, upon payment
of the Purchase Price, Common Stock (or, in certain circumstance, cash,
property or other securities of the Company) having a market value at the time
of the transaction equal to twice the Purchase Price. Rights are not
exercisable following such event, however, until such time as the Rights are no
longer redeemable by the Company as set forth below. Any Rights that are or
were at any time, on or after the Distribution Date, beneficially owned by an
Acquiring Person shall become null and void.
For example, at an exercise price of $95 per Right, each Right not
owned by an Acquiring Person (or by certain related parties) following an event
set forth in the preceding paragraph would entitle its holder to purchase $190
worth of Common Stock (or other consideration, as noted above) for $95.
Assuming that the Common Stock had a per share value of $40 at such time, the
holder of each valid Right would be entitled to purchase 4.75 shares of Common
Stock for $95.
After the Rights have become exercisable, if (i) the Company is
acquired in a merger or other business combination (in which any shares of the
Company's Common Stock are changed into or exchanged for other securities or
assets) or (ii) more than 50% of the assets or earning power of the Company and
its subsidiaries (taken as a whole) are sold or transferred in one or a series
of related transactions, the Rights Agreement provides that proper provision
shall be made so that each holder of record of a Right will have the right to
receive, upon payment of the Purchase Price, that number of shares of common
stock of the acquiring company having a market value at the time of such
transaction equal to two times the Purchase Price.
To the extent that insufficient shares of Common Stock are available
for the exercise in full of the Rights, holders of Rights will receive upon
exercise shares of Common Stock to the extent available and then other
securities of the Company, including units of shares of Series A Preferred
Stock with rights substantially comparable to those of the Common Stock,
property, or cash, in proportions determined by the Company, so that the
aggregate value received is equal to twice the Purchase Price. The Company,
however, shall not be required to issue any cash, property or debt securities
upon exercise of the Rights to the extent their aggregate value would exceed
the amount of cash the Company would otherwise be entitled to receive upon
exercise in full of the then exercisable Rights.
No fractional shares of Series A Preferred Stock or Common Stock will
be required to be issued upon exercise of the Rights and, in lieu thereof, a
payment in cash may be made to the holder of such Rights equal to the same
fraction of the current market value of a share of Series A Preferred Stock or,
if applicable, Common Stock.
At any time until the earlier of (i) ten days after the Stock
Acquisition Date (subject to extension by the Board of Directors) or (ii) the
date the Rights are exchanged pursuant to the Rights Agreement, the Company may
redeem the Rights in whole, but not in part, at a price of $0.01 per Right (the
"Redemption Price"). Immediately upon the action of the Board of Directors of
the Company authorizing redemption of the Rights, the right to exercise the
Rights will terminate, and the only right of the holders of Rights will be to
receive the Redemption Price without any interest thereon.
At any time after any Person becomes an Acquiring Person, the Board of
Directors may, at its option, exchange all or part of the outstanding Rights
(other than Rights held by the Acquiring Person and certain related parties)
for shares of Common Stock at an exchange ratio of one share of Common Stock
per Right
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(subject to certain anti-dilution adjustments). The Board may not effect such
an exchange, however, at any time any Person or group owns 50% or more of the
Voting Power of the Company. Immediately after the Board orders such an
exchange, the right to exercise the Rights shall terminate and the holders of
Rights shall thereafter only be entitled to receive shares of Common Stock at
the applicable exchange ratio.
Under presently existing federal income tax law, the issuance of the
Rights is not taxable to the Company or to shareowners and will not change the
way in which shareowners can presently trade the Company's shares of Common
Stock. If the Rights should become exercisable, shareowners, depending on then
existing circumstances, may recognize taxable income.
The Rights Agreement may be amended by the Board of Directors of the
Company. After the Distribution Date, however, the provisions of the Rights
Agreement may be amended by the Board only to cure any ambiguity, to make
changes which do not adversely affect the interests of holders of Rights
(excluding the interests of any Acquiring Person or an affiliate or associate
of an Acquiring Person), or to shorten or lengthen any time period under the
Rights Agreement; provided, however, that no amendment to adjust the time
period governing redemption shall be made at such time as the Rights are not
redeemable. In addition, no supplement or amendment may be made which changes
the Redemption Price, the final expiration date, the Purchase Price or the
number of one one-hundredths of a share of Series A Preferred Stock for which a
Right is exercisable, unless at the time of such supplement or amendment there
has been no occurrence of a Stock Acquisition Date and such supplement or
amendment does not adversely affect the interests of the holders of Right
Certificates (other than an Acquiring Person or an associate or affiliate of an
Acquiring Person).
Until a right is exercised, the holder, as such, will have no rights
as a shareowner of the Company, including, without limitation, the right to
vote or to receive dividends.
The Rights may have certain anti-takeover effects. The Rights will
cause substantial dilution to a person or group that attempts to acquire the
Company on terms not approved by the Board of Directors and, accordingly, will
make more difficult a change of control that is opposed by the Company's Board
of Directors. However, the Rights should not interfere with a proposed change
of control (including a merger or other business combination) approved by a
majority of the Board of Directors since the Rights may be redeemed by the
Company at $.01 per Right at any time until ten days after the Stock
Acquisition Date (subject to extension by the Board of Directors). Thus, the
Rights are intended to encourage persons who may seek to acquire control of the
Company to initiate such an acquisition through negotiations with the Board of
Directors. Nevertheless, the Rights also may discourage a third party from
making a partial tender offer or otherwise attempting to obtain a substantial
equity position in, or seeking to obtain control of, the Company. To the
extent any potential acquirors are deterred by the Rights, the Rights may have
the effect of preserving incumbent management in office.
This summary description of the Rights does not purport to be complete
and is qualified in its entirety by reference to the Rights Agreement, which is
filed as an Exhibit to the Company's Registration Statement on Form 8-B and is
incorporated herein by reference.
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