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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the fiscal year ended December 31, 1996 Commission File Number 1-12579
OGE Energy Corp.
(Exact name of registrant as specified in its charter)
Oklahoma 73-1481638
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
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 and Pacific Stock Exchange
Rights to Purchase-
Series A Preferred Stock New York Stock Exchange and Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes x No
---
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [x]
As of February 28, 1997, Common Shares outstanding were 40,373,991. Based
upon the closing price on the New York Stock Exchange on February 28, 1997, the
aggregate market value of the voting stock held by nonaffiliates of the Company
was: Common Stock $1,694,877,891.
The proxy statement for the 1997 annual meeting of shareowners is
incorporated by reference into Part III of this Report.
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TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
Item 1. Business......................................................... 1
The Company ..................................................... 1
Electric Operations.............................................. 2
General................................................. 2
Regulation and Rates.................................... 5
Rate Structure, Load Growth and Related Matters......... 8
Fuel Supply............................................. 9
Enogex........................................................... 10
Finance and Construction......................................... 13
Environmental Matters............................................ 15
Employees........................................................ 16
Item 2. Properties....................................................... 17
Item 3. Legal Proceedings. .............................................. 18
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.................................... 25
Item 6. Selected Financial Data......................................... 26
Item 7. Management's Discussion and Analysis of Results of
Operations and Financial Condition..................... 27
Item 8. Financial Statements and Supplementary Data..................... 36
Item 9. Changes in and Disagreements with Accountants
and Financial Disclosure ............................. 63
PART III
Item 10. Directors and Executive Officers of the Registrant.............. 63
Item 11. Executive Compensation.......................................... 63
Item 12. Security Ownership of Certain Beneficial
Owners and Management............................ 63
Item 13. Certain Relationships and Related Transactions.................. 63
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.................................... 63
i
PART I
ITEM 1. BUSINESS.
- ------------------
THE COMPANY
OGE Energy Corp. (the "Company") is a newly-formed public utility holding
company which was incorporated in August 1995 in the State of Oklahoma. The
Company became the parent holding company of Oklahoma Gas and Electric Company
("OG&E") and its former subsidiary, Enogex Inc. on December 31, 1996 pursuant to
a mandatory share exchange whereby each share of outstanding common stock of
OG&E was exchanged on a share-for-share basis for common stock of the Company.
Immediately following this exchange, OG&E transferred its shares of Enogex stock
to the Company and Enogex became a direct subsidiary of the Company.
The Company now serves as the parent company to OG&E, Enogex and any other
companies that may be formed within the organization in the future. The new
holding company structure is intended to provide greater flexibility to take
advantage of opportunities in an increasingly competitive business environment
and to clearly separate the Company's electric utility business from its
non-utility businesses. At December 31, 1996, the Company was not engaged in any
business independent of that conducted through its subsidiaries OG&E and Enogex
Inc. and Enogex Inc.'s subsidiaries (collectively, "Enogex")
The Company's principal subsidiary is OG&E and, accordingly, the Company's
financial results and condition are substantially dependent at this time on the
financial results and conditions of OG&E. OG&E is a regulated public utility
engaged in the generation, transmission and distribution of electricity to
retail and wholesale customers. OG&E was incorporated in 1902 under the laws of
the Oklahoma Territory and is the largest electric utility in the State of
Oklahoma. OG&E sold its retail gas business in 1928 and now owns and operates an
interconnected electric production, transmission and distribution system which
includes eight active generating stations with a total capability of 5,647,300
kilowatts.
Enogex owns and operates over 3,500 miles of natural gas transmission and
gathering pipelines, has interests in six gas processing plants, markets natural
gas and natural gas products and invests in the drilling for and production of
crude oil and natural gas.
On February 11, 1997, the Oklahoma Corporation Commission ("OCC") issued an
order that, among other things, effectively lowered OG&E's rates to its Oklahoma
retail customers by $50 million annually (based on a test year ended December
31, 1995). Of the $50 million rate reduction, approximately $45 million became
effective on March 5, 1997 and the remaining $5 million becomes effective March
1, 1998. The Order also directed OG&E to transition to competitive bidding of
its gas transportation requirements, currently met by Enogex, no later than
April 30, 2000.
On June 18, 1996, the Arkansas Public Service Commission ("APSC") staff and
OG&E filed a Joint Stipulation recommending settlement of certain issues
resulting from the APSC review of the amounts that OG&E pays Enogex and recovers
through its fuel clause for transporting natural gas to OG&E's gas-fired
generating stations. See "Electric Operations - Regulation and Rates - Recent
Regulatory Matters" for a further discussion of the orders.
In 1994, the Company restructured and redesigned its operations to reduce
costs and 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: (i) establish a
regulatory asset in connection with the costs associated with the workforce
reduction; (ii) amortize the December 31, 1994, balance of the regulatory asset
over 26 months; and (iii) reduce OG&E's electric rates during such period by
approximately $15 million annually, effective January 1995. In 1996, the labor
savings substantially offset the amortization of the regulatory asset and the
annual rate reduction of $15 million. See "Electric Operations - 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
1997 and February and October 1994.
The Company's executive offices are located at 101 North Robinson, P. O.
Box 321, Oklahoma City, Oklahoma 73101-0321; telephone (405) 553-3000.
ELECTRIC OPERATIONS
GENERAL
OG&E furnishes retail electric service in 274 communities and their
contiguous rural and suburban areas. During 1996, five other communities and two
rural electric cooperatives in Oklahoma and western Arkansas purchased
electricity from OG&E for resale. The service area, with an estimated population
of 1.7 million, covers approximately 30,000 square miles in Oklahoma and western
Arkansas; including Oklahoma City, the largest city in Oklahoma, and Ft. Smith,
Arkansas, the second largest city in that state. Of the 279 communities served,
248 are located in Oklahoma and 31 in Arkansas. Approximately 91 percent of
total electric operating revenues for the year ended December 31, 1996, 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 5,150 megawatts, and occurred on July 2, 1996.
OG&E's native load was approximately 4,851 megawatts on July 2, 1996, resulting
in a capacity margin of approximately 20.6 percent. As reflected in the table
below and in the operating statistics on page 4, total kilowatt-hour sales
increased 1.5 percent in 1996 as compared to an increase of 7.0 percent in 1995
and a 9.0 percent decrease in 1994. In 1996, kilowatt-hour sales to OG&E
customers ("system sales") increased slightly due to continued customer growth
and a return to more normal weather. Sales to other utilities ("off-system
sales") decreased in 1996. However, off-system sales are at much lower prices
per kilowatt-hour and have less impact on operating revenues and income than
system sales. In 1995 and 1994, factors which resulted in variations in total
kilowatt-hour sales included: (i) continued customer growth and (ii) the
decrease in off-system sales in 1994.
2
Variations in kilowatt-hour sales for the three years are reflected in the
following table:
SALES (Millions of Kwh)
Inc/ Inc/ Inc/
1996 (Dec) 1995 (Dec) 1994 (Dec)
- -------------------------------------------------------------------------
System Sales 21,541 3.4% 20,828 0.9% 20,642 2.2%
Off-System Sales 1,475 (20.4%) 1,852 232.6% 557 (82.1%)
------ ------ ------
Total Sales 23,016 1.5% 22,680 7.0% 21,199 (9.0%)
====== ====== ======
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. In April 1996, the Federal Energy Regulatory Commission ("FERC")
issued two final rules, Orders 888 and 889, regarding non-discriminatory open
access transmission service. These orders may have a significant impact on
wholesale markets. Also, numerous states are considering proposals to require
"retail wheeling" which is the delivery of power generated by a third party to
retail customers. The OCC is seeking to identify, describe and create a process
to implement a comprehensive and integrated restructuring of the electric
utility industry for the State of Oklahoma. The Oklahoma legislature also is
considering legislation to permit increased competition at the retail level by
July 2002. The Energy Act, these proposals and other factors are expected to
significantly increase competition in the electric industry. The Company has
taken steps in the past and intends to take appropriate steps in the future to
remain a competitive supplier of electricity. See "Electric Operations -
Regulation and Rates - Recent Regulatory Matters" for a further discussion of
these matters.
Electric and magnetic fields ("EMFs") surround all electric tools and
appliances, internal home wiring and external power lines such as those owned by
OG&E. During the last several years considerable attention has focused on
possible health effects from EMFs. While some studies indicate a possible weak
correlation, other similar studies indicate no correlation between EMFs and
health effects. The nation's electric utilities, including OG&E, have
participated with the Electric Power Research Institute ("EPRI") in the
sponsorship of more than $75 million in research to determine the possible
health effects of EMFs. In addition, the Edison Electric Institute ("EEI") is
helping fund $65 million for EMF studies over a five-year period, that began in
1994. One-half of this amount is expected to be funded by the federal
government, and two-thirds of the non-federal funding is expected to be provided
by the electric utility industry. Through its participation with the EPRI and
EEI, OG&E will continue its support of the research with regard to the possible
health effects of EMFs. OG&E is dedicated to delivering electric service in a
safe, reliable, environmentally acceptable and economical manner.
3
OKLAHOMA GAS AND ELECTRIC COMPANY
CERTAIN OPERATING STATISTICS
Year Ended December 31
1996 1995 1994
---- ---- ----
ELECTRIC ENERGY:
(Millions of Kwh)
Generation (exclusive of station use) ...... 21,253 20,639 18,325
Purchased .................................. 3,564 3,578 4,387
---------- ---------- ----------
Total generated and purchased........... 24,817 24,217 22,712
Company use, free service and losses........ (1,801) (1,537) (1,513)
---------- ---------- ----------
Electric energy sold.................... 23,016 22,680 21,199
========== ========== ==========
ELECTRIC ENERGY SOLD:
(Millions of Kwh)
Residential................................. 7,143 6,848 6,739
Commercial and industrial................... 11,161 10,963 10,886
Public street and highway lighting.......... 67 66 66
Other sales to public authorities........... 2,096 2,087 2,018
Sales for resale............................ 2,549 2,716 1,490
---------- ---------- ----------
Total.................................... 23,016 22,680 21,199
========== ========== ==========
ELECTRIC OPERATING REVENUES:
(Thousands)
Electric Revenues:
Residential.............................. $ 479,574 $ 471,313 $ 476,441
Commercial and industrial................ 530,213 512,212 549,528
Public street and highway lighting....... 9,367 9,115 9,294
Other sales to public authorities........ 98,209 95,660 99,789
Sales for resale......................... 60,141 63,340 43,001
Provision for rate refund ............... (1,221) (2,437) (3,417)
Miscellaneous............................ 24,054 19,084 22,262
---------- ---------- ----------
Total Electric Revenues................. $1,200,337 $1,168,287 $1,196,898
========== ========== ==========
NUMBER OF ELECTRIC CUSTOMERS:
(At end of period)
Residential................................. 588,778 583,741 578,044
Commercial and industrial................... 84,032 82,577 81,175
Public street and highway lighting.......... 249 249 249
Other sales to public authorities........... 10,688 10,340 10,198
Sales for resale............................ 41 43 39
---------- ---------- ----------
Total................................... 683,788 676,950 669,705
========== ========== ==========
RESIDENTIAL ELECTRIC SERVICE:
Average annual use (Kwh).................... 12,178 11,786 11,724
Average annual revenue...................... $ 817.62 $ 811.10 $ 828.86
Average price per Kwh (cents)............... 6.71 6.88 7.07
4
REGULATION AND RATES
OG&E's retail electric tariffs in Oklahoma are regulated by the OCC, and in
Arkansas by the APSC. The issuance of certain securities by OG&E is also
regulated by the OCC and the APSC. OG&E's wholesale electric tariffs, short-term
borrowing authorization and accounting practices are subject to the jurisdiction
of the FERC. The Secretary of the Department of Energy has jurisdiction over
some of OG&E's facilities and operations.
As part of the corporate reorganization whereby the Company became the
holding company parent of OG&E, OG&E obtained the approval of the OCC. The order
of the OCC authorizing OG&E to reorganize into a holding company structure
contains certain provisions which, among other things, ensure the OCC access to
the books and records of the Company and its affiliates relating to transactions
with OG&E; require the Company and its subsidiaries to employ accounting and
other procedures and controls to protect against subsidization of non-utility
activities by OG&E's customers; and prohibit the Company from pledging OG&E
assets or income for affiliate transactions.
For the year ended December 31, 1996, approximately 88 percent of OG&E's
electric revenue was subject to the jurisdiction of the OCC, seven percent to
the APSC, and five percent to the FERC.
RECENT REGULATORY MATTERS: On February 11, 1997, the OCC issued an order
----------------------------
that, among other things, effectively lowered OG&E's rates to its Oklahoma
retail customers by $50 million annually (based on a test year ended December
31, 1995). Of the $50 million rate reduction, approximately $45 million became
effective on March 5, 1997 and the remaining $5 million becomes effective March
1, 1998. OG&E had filed an application in June 1996 with the OCC for an annual
electric utility rate reduction of $14.2 million. On October 14, 1996, the staff
of the OCC and the Oklahoma Attorney General recommended that OG&E lower its
annual revenues by $94.5 and $79.8 million, respectively. In a separate
recommendation, the Oklahoma Industrial Energy Consumers proposed a $107.8
million annual OG&E rate reduction. On December 18, 1996, OG&E and the
intervenors proposed a $50 million settlement. The OCC voted to approve OG&E's
proposed settlement agreement on January 23, 1997, allowing OG&E to lower its
electric rates by $50 million. The order approving the rate reduction also
provides for an incentive program designed to encourage future generation cost
savings to be shared by OG&E and its customers. This program gives OG&E the
opportunity to lessen the impact of the $50 million reduction, if future cost
savings are achieved. See Note 10 of Notes to Consolidated Financial Statements.
The February 11, 1997 order also directed OG&E to transition to competitive
bidding of its gas transportation requirements currently met by Enogex no later
than April 30, 2000 and set annual compensation for the transportation services
provided by Enogex to OG&E at $41.3 million until competitively-bid gas
transportation begins. In 1996, approximately $44 million or 19 percent of
Enogex's revenues were attributable to transporting gas for OG&E. Other
pipelines seeking to compete with Enogex for OG&E's business will likely have to
pay a fee to Enogex for transporting gas on Enogex's system or incur capital
expenditures to develop the necessary infrastructure to connect with OG&E's
gas-fired generating stations.
On June 18, 1996, the APSC staff and OG&E filed a Joint Stipulation
recommending settlement of certain issues resulting from the APSC review of the
amounts that OG&E pays Enogex and recovers through its fuel clause for
transporting natural gas to OG&E's gas-fired generating stations. On July 11,
1996, the APSC issued an order that, among other things, required OG&E to refund
5
approximately $4.5 million in 1996 to its Arkansas retail electric customers.
The $4.5 million refund was recorded as a provision for a potential refund prior
to August 1996.
On February 25, 1994, the OCC issued an order that, among other things,
effectively lowered 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. 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 prior transportation and related
gas gathering services. Of the $17 million annual rate reduction, approximately
$9.9 million reflects the OCC's reduction of the amount to be recovered by 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 were designed to permit
OG&E to earn a 12 percent regulatory return on equity and the OCC staff was
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 exceeded 12.75
percent.
In 1994, the Company underwent a significant restructuring effort and
redesign of its operations to more favorably position itself for the competitive
electric utility environment. The Company incurred $63.4 million of
restructuring costs in 1994. Pending an OCC order, OG&E deferred the costs
associated with the VERP and severance package in the third quarter of 1994.
Between August 1 and December 31, 1994, the amount deferred was reduced by
approximately $14.5 million. In response to an application filed by 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 during such period by approximately $15
million annually, effective January 1995. Labor savings from the VERP and
severance package have substantially offset the amortization of the regulatory
asset and annual rate reduction of $15 million. Labor savings in 1994, 1995 and
1996 approximated the amortization of the deferred amount and therefore, did not
significantly impact 1994, 1995 and 1996 results. However, approximately $6.5
million in other restructuring expenses reduced 1994 earnings by $0.10 per
share. At December 31, 1996, the deferred amount was $3.8 million, which is
included on the Consolidated Balance Sheets as Deferred Charges - Other.
On October 5, 1994, the OCC issued an order instructing the OCC staff of
the Public Utility Division ("PUD") to move forward with the development of OCC
rules to implement the mandates of Sections 111 and 115 of the National Energy
Policy Act of 1992 (the "Energy Act"), requiring OG&E and other electric
utilities to each submit 20-year Integrated Resource Plans ("IRP"). Following
several technical conferences, in Order No. 398049, Cause No. RM 950000011
issued December 18, 1995, the OCC stated that it encourages Oklahoma electric
and gas utilities to utilize IRP principles, but found it unnecessary to set new
rules dictating requirements for IRP.
Pursuant to an order from the APSC in July 1992, OG&E and other electric
utilities serving customers in Arkansas were required to submit a 20-year IRP
with the APSC. On October 10, 1995, the APSC issued Order No. 9, Docket No.
92-164-U, which recognized the shifting pressures on today's utility industry,
the industry's good planning practices, the increasing competitive markets for
energy services and the need for publicly available information on utility plans
and planning processes. The APSC also recognized that long-term integrated
resource planning under prescriptive regulatory guidelines is no longer the most
appropriate or, more importantly, most effective means to protect the public
interest. Therefore, the APSC is not utilizing the IRP.
6
AUTOMATIC FUEL ADJUSTMENT CLAUSES: Variances in the actual cost of fuel
-------------------------------------
used in electric generation and certain purchased power costs, as compared to
that component in cost-of-service for ratemaking, are charged to substantially
all of the Company's electric customers through automatic fuel adjustment
clauses, which are subject to periodic review by the OCC, the APSC and the FERC.
NATIONAL ENERGY LEGISLATION: The National Energy Act of 1978 imposes
------------------------------
numerous responsibilities and requirements on OG&E. The Public Utility
Regulatory Policies Act of 1978 requires electric utilities, such as OG&E, to
purchase electric power from, and sell electric power to, qualified cogeneration
facilities ("QFs") and small power production facilities. Generally stated,
electric utilities must purchase electric energy and production capacity made
available by QFs and small power producers at a rate reflecting the cost that
the purchasing utility can avoid as a result of obtaining energy and production
capacity from these sources; rather than generating an equivalent amount of
energy itself or purchasing the energy or capacity from other suppliers. OG&E
has entered into agreements with four such cogenerators. See "Finance and
Construction." Electric utilities also must furnish electric energy to QFs on a
non-discriminatory basis at a rate that is just and reasonable and in the public
interest and must provide certain types of service which may be requested by QFs
to supplement or back up those facilities' own generation.
The Energy Act is expected to make some significant changes in the
operations of the electric utility industry and the federal policies governing
the generation and sale of electric power. The Energy Act, among other things,
allows the FERC to order utilities to permit access to their electrical
transmission systems and to transmit power produced by independent power
producers at transmission rates set by the FERC. The Energy Act also provides
funds to study electric vehicle technology, the effects of electric and magnetic
fields, and institutes a tax credit for generating electricity using renewable
energy sources. The Energy Act also is designed to promote competition in the
development of wholesale power generation in the electric industry. It exempts a
new class of independent power producers from regulation under the Public
Utility Holding Company Act of 1935 and allows the FERC to order "wholesale
wheeling" by public utilities to provide utility and non-utility generators
access to public utility transmission facilities. Also, numerous states are
considering proposals to require "retail wheeling."
In April 1996, FERC issued two final rules, Orders 888 and 889, which may
have a significant impact on wholesale markets. These orders were subsequently
amended in orders issued in March 1997. Order 888, which was preceded by a
Notice of Proposed Rulemaking, referred to as the "Mega-NOPR," set forth rules
on non-discriminatory open access transmission service to promote wholesale
competition. Order 888, which was effective on July 9, 1996, requires utilities
and other transmission users to abide by comparable terms, conditions and
pricing in transmitting power. Order 889, which had its effective date extended
to January 3, 1997, requires public utilities to implement Standards of Conduct
and an Open Access Same Time Information System ("OASIS," formerly known as
"Real-Time Information Networks"). These rules require transmission personnel to
provide the same information about the transmission system to all transmission
customers using the OASIS. OG&E is complying with these new rules from the FERC.
Another impact of complying with FERC's Order 888 is a requirement for
utilities to offer a transmission tariff that includes network transmission
service ("NTS") to transmission customers. NTS allows transmission service
customers to fully integrate load and resources on an instantaneous basis, in a
manner similar to how OG&E has historically integrated its load and resources.
Under NTS, OG&E and participating customers share the total annual transmission
cost, net of related transmission revenues, based upon each company's share of
the total system load. At this time, the Company expects to incur
7
approximately $1 million in start-up costs beginning in 1997 and a minimal
annual expense increase, as a result of Orders 888 and 889.
In accordance with FERC's direction regarding competition and alternative
regulation of the electric energy utility market on the national scale, the OCC
is seeking to identify, describe and create a process to implement a
comprehensive and integrated restructuring of the electric utility industry for
the State of Oklahoma. On June 6, 1996, the OCC issued a Notice of Inquiry
proposing questions for comment. In response to the Notice of Inquiry, OG&E
filed comments with the OCC on September 9, 1996. The comments listed, among
other things, five critical issues that OG&E believes must be addressed to
ensure a successful transition to a deregulated environment. These issues are:
(i) retail wheeling should be implemented in Oklahoma at the same time it is
implemented and on the same terms in all surrounding states; (ii) stranded costs
must be recovered; (iii) a level playing field must be established; (iv) state
regulators role must be restructured; and (v) there must be no exceptions to the
new rules. In addition, the Oklahoma State Senate has passed legislation that
would permit increased competition at the retail level by July 2002. This
proposed legislation authorizes the OCC, under the direction of a special task
force comprised of members of the Oklahoma State Senate and the Oklahoma State
House of Representatives, to undertake a series of studies to set the framework
for electric utility industry competition. The proposed legislation calls for
the OCC to report to the task force the results of its studies beginning in
February 1998 with a report regarding independent system operators. Following a
transition period, the proposed legislation would require the unbundling of
generation, transmission and distribution services. Stranded costs would be
recoverable over a 3 to 7 year period. At this time, it is uncertain whether or
when such legislation will be approved by the House of Representatives. OG&E is
not opposed to such legislation generally, provided the five issues noted above
are addressed fairly.
The Energy Act, these FERC actions, restructuring proposals in Oklahoma and
other factors are expected to significantly increase competition in the electric
industry. The Company has taken steps in the past and intends to take
appropriate steps in the future to remain a competitive supplier of electricity.
Past actions include the redesign and restructuring effort in 1994 and
continuing actions to reduce fuel costs, both of which have resulted in lower
retail rates, especially for industrial customers. While the Company is
supportive of competition, it believes that all electric suppliers must be
required to compete on a fair and equitable basis and the Company intends to
advocate this position vigorously.
RATE STRUCTURE, LOAD GROWTH
AND RELATED MATTERS
Two of 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. In 1996, these programs and schedules
included: (i) assistance programs that help residential customers live in
comfortable homes with lower energy costs; (ii) the "Surprise Free Guarantee"
program, which guarantees residential customers comfort and annual energy
consumption for heating, cooling and water heating; (iii) the PEAKS program,
which provides credit on a customer's bill for the installation of a device that
periodically cycles off the customer's central air conditioner during peak
summer periods; (iv) a load curtailment rate for industrial and commercial
customers who can demonstrate a load curtailment of at least 300 kilowatts; and
(v) time-of-use rate schedules for various commercial, industrial and
residential
8
customers designed to shift energy usage from peak demand periods during the hot
summer afternoons to non-peak hours. The February 11, 1997 order issued by the
OCC, among other things, eliminated the PEAKS program and raised the minimum
load curtailment per customer from 300 to 500 kilowatts.
OG&E implemented a Real Time Pricing pilot program, for selected industrial
customers, to keep its electric tariffs attractive and to control peak demand
growth. Real Time Pricing is a service option which prices electricity so that
current price varies hourly with short notice to reflect current expected cost.
The technique will allow a measure of competitive pricing, a broadening of
customer choice, balancing of electricity usage and capacity in the short and
long term, and help customers control their costs.
OG&E's 1996 marketing efforts included geothermal heat pumps,
electrotechnologies, an electric food service promotion and a heat pump
promotion in the residential, commercial and industrial markets. OG&E works
closely with individual customers to provide the best information on how current
technologies can be combined with OG&E's marketing programs to maximize the
customer's benefit.
The Company 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 1996, approximately 79 percent of the OG&E-generated energy was
produced by coal-fired units and 21 percent by natural gas-fired units. It is
estimated that the fuel mix for 1997 through 2001, based upon expected
generation for these years, will be as follows:
1997 1998 1999 2000 2001
- --------------------------------------------------------------------------------
Coal.................. 82% 80% 80% 79% 79%
Natural Gas........... 18% 20% 20% 21% 21%
The decline in the percentage of coal-fired generation relative to total
generation will result from projected increases in natural gas-fired generation,
not a reduction in Kwh of coal-fired generation.
The average cost of fuel used, by type, per million Btu for each of the 5
years was as follows:
1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------
Coal.................. $0.83 $0.83 $0.78 $1.16 $1.18
Natural Gas........... $3.61 $3.19 $3.58 $3.64 $3.48
Weighted Avg.......... $1.45 $1.41 $1.58 $1.92 $1.88
A portion of the fuel cost is included in base rates and differs for each
jurisdiction. The portion of these costs that is not included in base rates is
recovered through automatic fuel adjustment clauses. See "Electric Operations -
Regulation and Rates - Automatic Fuel Adjustment Clauses."
COAL-FIRED UNITS: All OG&E coal units, with an aggregate capacity of 2,530
-----------------
megawatts, are designed to burn low sulfur western coal. OG&E purchases coal
under a mix of long- and short-term contracts. During 1996, OG&E purchased 9.9
million tons of coal from the following Wyoming
9
suppliers: Amax Coal West, Inc., Caballo Rojo, Inc., Kennecott Energy Company,
Thunder Basin Coal Company and Powder River Coal Company. The combination of all
coals has a weighted average sulfur content of 0.31 percent and can be burned in
these units under existing federal, state and local environmental standards
(maximum of 1.2 pounds of sulfur dioxide per million Btu) without the addition
of sulfur dioxide removal systems. Based upon the average sulfur content, OG&E
units have an approximate emission rate of 0.63 pounds of sulfur dioxide per
million Btu. In anticipation of the more strict provisions of Phase II of The
Clean Air Act starting in the year 2000, OG&E has contracts in place that will
allow for a supply of very low sulfur coal from suppliers in the Powder River
Basin to meet the new sulfur dioxide standards.
Wyoming coal is transported to OG&E generating stations, a distance of
approximately 1,000 miles, by either 112 or 135 rail car unit trains. In 1995,
OG&E completed the upgrading of its unit train fleet to high volume aluminum
body rail cars. Currently, the fleet is comprised of 1,495 leased cars. Each
aluminum rail car has a maximum capacity of 120 net tons allowing for the
movement of 13,440 net tons per unit train. High volume and aluminum design
combine to offer a 20 percent increase in net loading per car over a
conventional steel car. During 1996, OG&E used larger unit trains with a maximum
of 135 cars instead of a maximum of 112 cars in unit train service to the
Muskogee generating station. Increasing the unit train size allows for an
increase of delivered tons by approximately 21 percent. The combination of high
volume, aluminum design and increased train size to the Muskogee generating
station reduces the number of trips from Wyoming by approximately 29 percent and
reduces rail car maintenance expenses accordingly.
GAS-FIRED UNITS: For calendar year 1997, OG&E expects to acquire
------------------
approximately 10 percent of its gas needs from long-term gas purchase contracts.
The remainder of OG&E's gas needs during 1997 will be supplied by contracts with
at-market pricing or through day-to-day purchases on the spot market.
In 1993, OG&E began utilizing a natural gas storage facility which helps
lower fuel costs by allowing OG&E to optimize economic dispatch between fuel
types and take advantage of seasonal variations in natural gas prices. By
diverting gas into storage during low demand periods, OG&E is able to use as
much coal as possible to generate electricity and utilize the stored gas to meet
the additional demand for electricity. During 1996, OG&E completed a controls
upgrade to its Seminole Unit 1. This upgrade will allow the unit to run
efficiently at low loads as well as high loads. This added flexibility in gas
generation compliments OG&E's contracted gas storage facility to allow the gas
generating system to meet our customers' changing electrical needs in a reliable
and efficient manner.
ENOGEX
The Company's wholly-owned non-utility subsidiary, Enogex Inc., is the 36th
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 development and production
activities. Enogex Inc. has three wholly-owned subsidiaries, Enogex Products
Corporation ("Products"), Enogex Services Corporation ("Services") and Enogex
Exploration Corporation ("Exploration"). Enogex Inc. also owns an 80 percent
interest in Centoma Gas Systems, Inc. ("Centoma"). Products owns interests in
and operates six natural gas processing plants. Exploration is engaged in
investing in the development and production of oil and natural gas and
10
the purchase of oil and gas reserves. Services is engaged in the marketing
(buying and selling) of natural gas and also markets the natural gas liquids of
Products. Centoma both purchases and gathers gas for subsequent processing at
one of three processing plants, two of which are owned by Products. The residue
gas is then sold under a combination of contract and spot market prices.
For the year ended December 31, 1996, and before elimination of
intercompany items between OG&E and Enogex, Enogex's consolidated revenues and
net income were approximately $231.4 million and $16.5 million, respectively.
Enogex's natural gas transportation business in Oklahoma consists primarily
of gathering and transporting natural gas for OG&E and on an interruptible
basis, for other customers. Enogex's system consists of over 3,500 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. 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 1996, Enogex transported 148 Bcf of
natural gas; of which approximately 45 Bcf, or about 30 percent, was delivered
to OG&E's electric generating stations and storage facility, which resulted in
approximately 67 percent of Enogex Inc.'s revenue of $66.2 million for 1996. On
February 11, 1997, the OCC issued an order directing OG&E to transition to
competitive bidding of its gas transportation requirements no later than April
30, 2000. The order also set annual compensation for the transportation services
provided by Enogex to OG&E at $41.3 million until competitively-bid gas
transportation begins. See "Electric Operations - Regulation and Rates" and
"Management's Discussion and Analysis of Results of Operations and Financial
Condition -- Contingencies."
Enogex's pipeline system also gathers and transports natural gas destined
for interstate markets through interconnections in Oklahoma with other pipeline
companies. Among others, these interconnections include Panhandle Eastern
Pipeline, Williams Natural Gas Pipeline, Natural Gas Pipeline Company of
America, Northern Natural Gas Company, NorAm Gas Transmission Company, ANR
Pipeline Company and Ozark Gas Transmission Company.
The rates charged by Enogex for transporting natural gas on behalf of an
interstate natural gas pipeline company or a local distribution company served
by an interstate natural gas pipeline company are subject to the jurisdiction of
FERC under Section 311 of the Natural Gas Policy Act. The statute entitles
Enogex to charge a "fair and equitable" rate that is subject to review and
approval by the FERC at least once every three years. This rate review may
involve an administrative-type trial and an administrative appellate review. In
addition, Enogex has agreed to open its system to all interstate shippers that
are interested in moving natural gas through the Enogex system. Enogex is
required to conduct this transportation on a non-discriminatory basis, although
this transportation is subordinate to that performed for OG&E. This decision
does not increase appreciably the federal regulatory burden on Enogex, but does
give Enogex the opportunity to utilize any unused capacity on an interruptible
basis and thus increase its transportation revenues.
The fees charged by Enogex for transporting natural gas for OG&E and other
intrastate shippers are not subject to FERC regulation. With respect to state
regulation, the fees charged by Enogex for any intrastate transportation service
have not been subject to direct state regulation by the OCC. Even though the
intrastate pipeline business of Enogex is not directly regulated, the OCC, the
APSC and the FERC have the authority to examine the appropriateness of any
transportation charge or other fees paid by OG&E to
11
Enogex, which OG&E seeks to recover from ratepayers. See "Electric Operations -
Regulation and Rates" for a further discussion of this matter and the OCC's
recent 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 interests in five
other natural gas processing plants in Oklahoma, which have, in the aggregate,
the capacity to process approximately 69 Mmcf of natural gas per day. Products'
natural gas processing plant operations consist of off-lease extraction of
liquids from natural gas that is transported through the Enogex pipeline at four
of the plants, off-lease extraction of liquids from an unaffiliated pipeline at
one plant and extraction of liquids from another plant and associated gathering
system. The raw gas stream is processed and converted into marketable ethane,
propane, butane, and natural gasoline mix. The residue gas remaining after the
liquid products have been extracted consists primarily of methane.
Commercial grade propane is sold on the local market and the marketing of
all other natural gas liquids extracted by Products is handled by Services. The
natural gas liquids are sold to Services at a price equal to the Oil Price
Information Service average monthly price.
In processing and marketing natural gas liquids, the Enogex companies
compete against virtually all other gas processors selling natural gas liquids.
The Enogex companies believe they will be able to continue to compete favorably
against such companies. With respect to factors affecting the natural gas
liquids industry generally, as the price of natural gas liquids fall without a
corresponding decrease in the price of natural gas, it may become uneconomical
to extract certain natural gas liquids. As to factors affecting the Enogex
companies specifically, the volume of natural gas processed at their plants is
dependent upon the volume of natural gas transported through the pipeline system
located "behind the plants." If the volume of natural gas transported by such
pipeline increases "behind the plants," then the volume of liquids extracted by
Products should normally increase.
Services is a natural gas and natural gas liquids marketing company serving
both producers and consumers of natural gas by buying natural gas at the
wellhead and from other sources in Oklahoma and other states, and reselling the
gas to local distribution companies, utilities other than OG&E and industrial
purchasers both within and outside Oklahoma. It also serves Products by
purchasing and marketing the natural gas liquids they produce. The natural gas
liquids are delivered to Conway, Kansas (which is one of the nation's largest
wholesale markets for gas liquids), where they are sold on the spot market,
commonly referred to as Group 140.
Although the margin on gas sales by Services is relatively small,
approximately 82 percent of the natural gas purchased and resold is transported
through the Enogex Inc. pipeline to one or more interstate pipelines that
deliver the gas to markets. Thus, in addition to purchasing and selling natural
gas, Services seeks to use the space available in the Enogex Inc. pipeline and
increase the amount of natural gas available for processing by Products.
Enogex Inc. is committed to continue the activities of Services in order to
increase the amount of natural gas transported through the pipeline and the
amount of natural gas processed by Products.
In its marketing and transportation services for third parties, Enogex Inc.
and Services encounter competition from other natural gas transporters and
marketers and from other available alternative energy sources. The effect of
competition from alternative energy sources is dependent upon the availability
and cost of competing supply sources.
12
Volumes of natural gas transported by Enogex Inc. for third parties and the
revenues derived from such activities increased from 1995. The contributing
factors for the increase were favorable third party volume and price variances.
Services competes with all major suppliers of natural gas and natural gas
liquids in the geographic markets they serve. For natural gas, those geographic
markets are primarily the areas served by pipelines with which Enogex is
interconnected. Although the price of the gas is an important factor to a buyer
of natural gas from Services, the primary factor is the total cost (including
transportation fees) that the buyer must pay. Natural gas transported for
Services by Enogex Inc. is billed at the same rate Enogex Inc. charges for
comparable third-party transportation.
Exploration was formed in 1988 primarily to engage in the development and
production of oil and 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, Utah, Texas and Indiana. As of December 31, 1996,
Exploration had interests in 448 active wells. Exploration's estimated proved
reserves were 86,947 Mmcfe. The standardized measure of discounted future net
cash flow with related Section 29 tax credits of Exploration's proved reserves
was $78.8 million at December 31, 1996.
Centoma was formed in 1994 and is Enogex's gas gatherer within an area of
mutual interest located on Enogex's inner system. All gas gathered by Centoma is
processed at one of three gas plants, two of which are owned by Products.
Centoma derives revenues from gas gathering and also from the resale of residue
gas during the winter under premium price contracts. Subsequent to year-end,
Enogex agreed to sell its 80 percent ownership in Centoma to the minority
interest owner for $3.2 million which approximates the net book value of
Enogex's share of Centoma's assets at December 31, 1996.
FINANCE AND CONSTRUCTION
The Company meets its cash needs through internally generated funds,
short-term borrowings and permanent financing. Cash flows from operations
remained strong in 1996 and 1995, which enabled the Company to internally
generate the required funds to satisfy construction expenditures during these
years.
Management expects that internally generated funds will be adequate over
the next three years to meet the Company's capital requirements. The primary
capital requirements for 1997 through 1999 are estimated as follows:
(DOLLARS IN MILLIONS) 1997 1998 1999
- --------------------------------------------------------------------------------
Electric utility construction
expenditures including AFUDC...... $ 95.0 $ 94.0 $ 94.0
Enogex construction expenditures
and acquisitions.................. 108.0 75.0 69.0
Maturities of long-term debt and
sinking fund requirement.......... 15.0 25.0 12.5
================================================================================
Total.......................... $218.0 $194.0 $175.5
================================================================================
13
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
$400,000 of the Company's construction expenditures budgeted for 1997 are to
comply with environmental laws and regulations. OG&E's construction program was
developed to support an anticipated peak demand growth of one to two percent
annually and to maintain minimum capacity reserve margins as stipulated by the
Southwest Power Pool. See "Electric Operations - Rate Structure, Load Growth and
Related Matters."
OG&E intends to meet its customers' increased electricity needs during the
foreseeable future by maintaining the reliability and increasing the utilization
of existing capacity. OG&E's current resource strategy includes the reactivation
of existing plants and the addition of peaking resources. OG&E does not
anticipate the need for another base-load plant in the foreseeable future.
The ability of the Company and its subsidiaries 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, 1996, and assuming an annual interest rate of
7.74 percent, OG&E could issue more than $1.0 billion in principal amount of
additional first mortgage bonds under the earnings test contained in OG&E's
Trust Indenture (assuming adequate property additions were available). Under the
earnings test contained in OG&E's Restated Certificate of Incorporation and
assuming none of the foregoing first mortgage bonds are issued, more than $1.0
billion of additional preferred stock at an assumed annual dividend rate of 7.2
percent could be issued as of December 31, 1996.
The Company will continue to use short-term borrowings to meet temporary
cash requirements. OG&E has the necessary regulatory approvals to incur up to
$400 million in short-term borrowings at any one time. The maximum amount of
outstanding short-term borrowings during 1996 was $142.1 million.
OG&E's resource strategy for supplying energy through the next decade and
beyond consists of evaluating measures to keep its existing generating plants
operating efficiently well past their traditional retirement dates. As long as
the cost to keep existing plants operating reliably and efficiently is less than
the cost of alternative sources of capacity, existing plants will be operated.
In accordance with the requirements of the Public Utility Regulatory
Policies Act of 1978 ("PURPA") (see "Electric Operations - Regulation and Rates
- - National Energy Legislation"), OG&E is obligated to purchase 110 megawatts of
capacity annually from Smith Cogeneration, Inc. and 320 megawatts annually from
Applied Energy Services, Inc., another qualified cogeneration facility. In 1986,
a contract was signed with Sparks Regional Medical Center to purchase energy not
needed by the hospital from its nominal seven megawatt cogeneration facility. In
1987, OG&E signed a contract to purchase up to 110 megawatts of capacity from
Mid-Continent Power Company, Inc. This purchase of capacity is currently planned
to begin in 1998 and carries no obligation on the part of OG&E to purchase
energy. The purchases under each of these cogeneration contracts were approved
by the appropriate regulatory commissions at rates set in accordance with PURPA.
The Company's financial results depend to a large extent upon the tariffs
OG&E charges customers and the actions of the regulatory bodies that set those
tariffs, the amount of energy used by OG&E's customers, the cost and
availability of external financing and the cost of conforming to government
regulations.
14
ENVIRONMENTAL MATTERS
The Company's management believes all of its operations are in substantial
compliance with present federal, state and local environmental standards. It is
estimated that the Company's total expenditures for capital, operating,
maintenance and other costs to preserve and enhance environmental quality will
be approximately $40 million during 1997, compared to approximately $43 million
in 1996. Approximately $400,000 of the Company's construction expenditures
budgeted for 1997 are to comply with environmental laws and regulations. The
Company continues to evaluate its environmental management systems to ensure
compliance with existing and proposed environmental legislation and regulations
and to better position itself in a competitive market.
As required by Title IV of the Clean Air Act Amendments of 1990 ("CAAA"),
the Company has completed installation and certification of all required
continuous emissions monitors ("CEMs") at OG&E's generating stations. OG&E
submits emissions data quarterly to the Environmental Protection Agency ("EPA")
as required by the CAAA. Phase II sulfur dioxide ("SO2") emission requirements
will affect OG&E beginning in the year 2000. Based on current information the
Company believes it can meet the SO2 limits without additional capital
expenditures. In 1996 the Company emitted 58,700 tons of SO2.
With respect to the nitrogen oxide ("NOx") regulations of Title IV of the
CAA, the Company has committed to meeting a 0.45 lbs/mm Btu NOx emission level
beginning in 1997. As a result, the Company was eligible to exercise its option
to extend the effective date of the lower emission requirements from the year
2000 until 2008. The Company's average NOx emissions for 1996 was 0.38 lbs/mm
Btu.
The Company has submitted all of its required Title V permit applications.
The first two were submitted on July 10, 1996 while the remaining six were
submitted on March 5, 1997. As a result of the Title V Program the Company paid
approximately $340,000 in fees in 1996.
Other air regulated items have emerged that could impact the Company. The
Ozone Transport Assessment Group ("OTAG") is studying long range transport of
ozone and its precursors across a thirty-seven state area. The results of the
study are due by mid 1997. If reductions are required in Oklahoma, the Company
could have to reduce its NOx emissions even further from the limits imposed by
Title IV of the Act.
EPA has proposed revisions to the ambient ozone and particulate standards.
Based on historic data and EPA projections, Tulsa and Oklahoma counties would
fail to meet the proposed standard for ozone. In addition, Muskogee, Kay, Tulsa
and Comanche counties would fail to meet the standard for particulate matter. If
reductions were required in Muskogee, Kay and Oklahoma counties, significant
capital expenditures could be required by the Company.
The Company has and will continue to seek new pollution prevention
opportunities and to evaluate the effectiveness of its waste reduction, reuse
and recycling efforts. In 1996, OG&E obtained refunds of approximately $232,600
from its recycling efforts. This figure does not include the additional savings
gained through the reduction and/or avoidance of disposal costs and the
reduction in material purchases due to reuse of existing materials. Similar
savings are anticipated in future years.
OG&E has made application for renewal of all of its National Pollutant
Discharge Elimination System ("NPDES") permits. OG&E received one of the permits
in final form and the remainder of the applications are in technical review by
the regulatory agency. It is anticipated, because of regulation
15
changes, that the new permits will offer greater operational flexibility than
those in the past. In 1996 responsibility for administration of the NPDES
program was shifted from the U. S. EPA to certain states including Oklahoma. As
a result of the assumption of this program by the Oklahoma Department of
Environmental Quality, annual state wastewater fees are expected to increase.
Annual NPDES fees for 1996 were approximately $34,400 and at this time, it is
anticipated that the cost of these fees will be similar for 1997.
OG&E remains a party to two separate actions brought by the EPA concerning
cleanup of disposal sites for hazardous and toxic waste, See "Item 3. Legal
Proceedings."
The Company has and will continue to evaluate the impact of its operations
on the environment. As a result, contamination on Company property will be
discovered from time to time. Three separate sites, which were identified as
having been contaminated by historical operations were addressed during 1996.
The Company completed remediation of two of these while remedial options for the
third are being pursued with appropriate regulatory agencies. The cost of these
actions has not had and are not anticipated to have a material adverse impact on
the Company's financial position or results of operations.
EMPLOYEES
The Company and its subsidiaries had 2,751 employees at December 31, 1996.
16
ITEM 2. PROPERTIES.
- -------------------
OG&E owns and operates an interconnected electric production, transmission
and distribution system, located in Oklahoma and western Arkansas, which
includes eight active generating stations with an aggregate active capability of
5,647 megawatts. The following table sets forth information with respect to
present electric generating facilities, all of which are located in Oklahoma:
Unit Station
Year Capability Capability
Station & Unit Fuel Installed (Megawatts) (Megawatts)
- ------------------ ---- --------- ----------- -----------
Seminole 1 Gas 1971 549
2 Gas 1973 507
3 Gas 1975 500 1,556
Muskogee 3 Gas 1956 184
4 Coal 1977 500
5 Coal 1978 500
6 Coal 1984 515 1,699
Sooner 1 Coal 1979 505
2 Coal 1980 510 1,015
Horseshoe 6 Gas 1958 178
Lake 7 Gas 1963 238
8 Gas 1969 404 820
Mustang 1 Gas 1950 58 Inactive
2 Gas 1951 57 Inactive
3 Gas 1955 122
4 Gas 1959 260
5 Gas 1971 64 446
Conoco 1 Gas 1991 26
2 Gas 1991 26 52
Arbuckle 1 Gas 1953 74 Inactive
Enid 1 Gas 1965 12
2 Gas 1965 12
3 Gas 1965 12
4 Gas 1965 12 48
Woodward 1 Gas 1963 11 11
--------
Total Active Generating Capability (all stations) 5,647
========
17
At December 31, 1996, OG&E's transmission system included: (i) 65
substations with a total capacity of approximately 15.6 million kVA and
approximately 3,989 structure miles of lines in Oklahoma; and (ii) six
substations with a total capacity of approximately 1.9 million kVA and
approximately 241 structure miles of lines in Arkansas. OG&E's distribution
system included: (i) 301 substations with a total capacity of approximately 5.6
million kVA, 19,794 structure miles of overhead lines, 1,562 miles of
underground conduit and 6,386 miles of underground conductors in Oklahoma; and
(ii) 30 substations with a total capacity of approximately 665,000 kVA, 1,617
structure miles of overhead lines, 148 miles of underground conduit and 344
miles of underground conductors in Arkansas.
Substantially all of 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: (i) over 3,500 miles of natural gas pipeline extending from
the Arkoma Basin in eastern Oklahoma to the Anadarko Basin in western Oklahoma;
(ii) a 50 percent interest in a natural gas processing plant near Calumet,
Oklahoma, which has the capacity to process 250 Mmcf of natural gas per day;
(iii) five other natural gas processing plants in Oklahoma, which have, in the
aggregate, the capacity to process approximately 69 Mmcf of natural gas per day;
and (iv) an 80 percent interest in approximately 110 miles of gas gathering
pipeline owned by Centoma.
During the three years ended December 31, 1996, the Company's gross
property, plant and equipment additions approximated $440 million and gross
retirements approximated $97 million. Over 95 percent of these additions were
provided by internally generated funds. The additions during this three-year
period amounted to approximately 10.9 percent of total property, plant and
equipment at December 31, 1996.
ITEM 3. LEGAL PROCEEDINGS.
- --------------------------
1. On July 8, 1994, an employee of OG&E filed a lawsuit in state court
against OG&E in connection with OG&E's VERP. The case was removed to the U.S.
District Court in Tulsa, Oklahoma. On August 23, 1994, the trial court granted
OG&E's Motion to Dismiss Plaintiff's Complaint in its entirety.
On September 12, 1994, Plaintiff, along with two other Plaintiffs, filed an
Amended Complaint alleging substantially the same allegations which were in the
original complaint. The action was filed as a class action, but no motion to
certify a class was ever filed. Plaintiffs want credit, for retirement purposes,
for years they worked prior to a pre-ERISA (1974) break in service. They allege
violations of ERISA, the Veterans Reemployment Act, Title VII, and the Age
Discrimination in Employment Act. State law claims, including one for
intentional infliction of emotional distress, are also alleged.
On October 10, 1994, Defendants filed a Motion to Dismiss Counts II, IV, V,
VI and VII of Plaintiffs' Amended Complaint. With regard to Counts I and III,
Defendants filed a Motion for Summary Judgment on January 18, 1996. One
Plaintiff was killed in a car accident in January of 1996. The Plaintiff never
retired and Defendants allege the Plaintiff does not have a claim for retirement
benefits. The Plaintiff's beneficiary will receive death benefits.
While the Company cannot predict the precise outcome of the proceeding, the
Company continues to believe that the lawsuit is without merit and will not have
a material adverse effect on its consolidated results of operations or financial
condition.
18
2. OG&E is also involved, along with numerous other Potentially Responsible
Party's ("PRP"), in an EPA administrative action involving the facility in
Holden, Missouri, of Martha C. Rose Chemicals, Inc. ("Rose"). Beginning in early
1983 through 1986, Rose was engaged in the business of brokering of
polychlorinated biphenyls ("PCBs") and PCB items, processing of PCB capacitors
and transformers for disposal, and decontamination of mineral oil dielectric
fluids containing PCBs. During this time period, various generators of PCBs
("Generators"), including OG&E, shipped materials containing PCBs to the
facility. Contrary to its contractual obligation with OG&E and other Generators,
it appears that Rose failed to manage, handle and dispose of the PCBs and the
PCB items in accordance with the applicable law. Rose has been issued citations
by both the EPA and the Occupational Safety and Health Administration. Several
Generators, including OG&E, formed a Steering Committee to investigate and clean
up the Rose facility.
The Company's share of the total hazardous wastes at the Rose facility was
less than six percent. The remediation of this site was completed in 1995 by the
Steering Committee and is currently in the final stages of closure with the EPA,
which includes operation and maintenance activities as required in the
Administrative Order on Consent with the EPA. Due to additional funds resulting
from payments by third party companies who were not a part of the Steering
Committee, and also reduced remedy implementation costs, the Company received a
refund in December 1995 under the allocation formula. OG&E has reached a
settlement agreement with its insurance carrier, AEGIS Insurance Company, with
respect to costs incurred at this site. The Company considers this insurance
matter to be closed.
Management believes that OG&E's ultimate liability for any additional
cleanup costs of this site will not have a material adverse effect on OG&E's
financial position or its results of operations. Management's opinion is based
on the following: (i) the present status of the site; (ii) the cleanup costs
already paid by certain parties; (iii) the financial viability of the other
PRPs; (iv) the portion of the total waste disposed at this site attributable to
OG&E; and (v) the Company's settlement agreement with its insurer. Management
also believes that costs incurred in connection with this site, which are not
recovered from insurance carriers or other parties, may be allowable costs for
future ratemaking purposes.
3. On January 11, 1993, OG&E received a Section 107 (a) Notice Letter from
the EPA, Region VI, as authorized by the CERCLA, 42 USC Section 9607 (a),
concerning the Double Eagle Refinery Superfund Site located at 1900 NE First
Street in Oklahoma City, Oklahoma. The EPA has named OG&E and 45 others as PRPs.
Each PRP could be held jointly and severally liable for remediation of this
site.
On February 15, 1996, OG&E elected to participate in the de minimis
settlement of EPA's Administrative Order on Consent. This limits OG&E's
financial obligation to less than $50,000 and also eliminates its involvement in
the design and implementation of the site remedy.
4. As previously reported, on September 18, 1996, Trigen-Oklahoma City
Energy Corporation ("Trigen") sued OG&E in the United States District Court,
Western District of Oklahoma, Case No. CIV-96-1595-M. Trigen alleged six causes
of action: (i) monopolization in violation of Section 2 of the Sherman Act; (ii)
attempt to monopolize in violation of Section 2 of the Sherman Act; (iii) acts
in restraint of trade in violation of Oklahoma law, 79 O.S. 1991, ss. 1; (iv)
discriminatory sales in violation of 79 O.S. 1991, ss. 4; (v) tortious
interference with contract; and (vi) tortious interference with a prospective
economic advantage. Trigen seeks actual damages of at least $7 million, trebled,
together with its costs, pre- and post-judgment interest and attorney fees, in
connection with each of the first four counts. It seeks actual damages of at
least $7 million, plus punitive damages together with its costs, pre-and
post-judgment interest and attorney fees, in connection with each of the
19
remaining counts. Trigen also seeks permanent injunctive relief against the
alleged Sherman Act violations and against OG&E's alleged practice of offering
cooling services to customers in Oklahoma City in the form of RTP-priced
electricity "bundled" together with financing, construction, and/or other
consulting services at guaranteed rates.
OG&E filed an answer and counterclaim on November 7, 1996 asserting that
Trigen made false claims, misrepresented facts, published false statements and
other defamatory conduct which damaged the Company, and asserting violation of
the Oklahoma Deceptive Trade Practices Act. The Company seeks punitive and
actual damages. Due to the early stages of this lawsuit, OG&E cannot predict its
outcome at this time.
5. The State of Oklahoma, ex rel., Teresa Harvey (Carroll); Margaret B.
Fent and Jerry R. Fent v. Oklahoma Gas and Electric Company, et al., District
Court, Oklahoma County, Case No. CJ-97-1242-63. On February 24, 1997, the
taxpayers instituted litigation against OG&E and Co-Defendants Oklahoma
Corporation Commission, Oklahoma Tax Commission and individual commissioners
seeking judgment in the amount of $970,184.14 and treble penalties of
$2,910,552.42, plus interest and costs, for overcharges refunded by OG&E to its
ratepayers in compliance with an Order of the OCC which Plantiffs allege was
illegal. Plantiffs allege the refunds should have been paid into the state
Unclaimed Property Fund. Management believes that the lawsuit is without merit
and will not have a material adverse effect on the Company's consolidated
financial position or its results of operations.
6. On March 19, 1997, the City of Enid, Oklahoma ("Enid") through its City
Council, notified OG&E of its intent to purchase OG&E's electric distribution
facilities for Enid and to terminate OG&E's franchise to provide electricity
within Enid as of June 26, 1998. The ability of Enid to purchase OG&E's
distribution facilities in Enid is subject to numerous additional conditions.
OG&E currently provides electricity to approximately 25,000 customers in Enid
and for the year ended December 31, 1996, derived less than 3.5 percent of its
electric retail revenues from sales of electricity to such customers. In the
event Enid is ultimately successful in its current efforts, it is expected that
OG&E would compete with other companies at the wholesale level to supply
electricity to Enid. OG&E is currently evaluating the legality of the City
Council's actions and determining the appropriate actions to take.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
- -------------------------------------------------------------
None
20
EXECUTIVE OFFICERS OF THE REGISTRANT.
- -------------------------------------
The following persons were Executive Officers of the Registrant as of March
15, 1997:
Name Age Title
- -------------------- --- --------------------------------------
Steven E. Moore 50 Chairman of the Board, President
and Chief Executive Officer
Al M. Strecker 53 Senior Vice President
Michael G. Davis 47 Vice President
James R. Hatfield 39 Vice President and Treasurer
Irma B. Elliott 58 Vice President and
Corporate Secretary
Melvin D. Bowen, Jr. 55 Vice President - Power Delivery - OG&E
Jack T. Coffman 53 Vice President - Power Supply - OG&E
Donald R. Rowlett 39 Controller Corporate Accounting - OG&E
Don L. Young 56 Controller Corporate Audits - OG&E
No family relationship exists between any of the Executive Officers of the
Registrant. Each Officer is to hold office until the Board of Directors meeting
following the next Annual Meeting of Shareowners, currently scheduled for May
15, 1997.
Messrs. Moore, Strecker, Davis, Hatfield and Ms. Elliott were named to the
position shown above following the corporate reorganization effective December
31, 1996, pursuant to which the Registrant became the holding company parent of
OG&E. Such persons are also officers of OG&E.
21
The business experience of each of the Executive Officers of the Registrant
for the past five years is as follows:
Name Business Experience
- -------------------- ------------------------------------------------------
Steven E. Moore 1996-Present: Chairman of the Board,
President and Chief
Executive Officer
1996-Present: Chairman of the Board,
President and Chief
Executive Officer - OG&E
1995-1996: President and Chief
Operating Officer - OG&E
1992-1995: Vice President - Law
and Public Affairs - OG&E
Al M. Strecker 1996-Present: Senior Vice President
1994-Present: Senior Vice President -
Finance and
Administration - OG&E
1992-1994: Vice President and
Treasurer - OG&E
Michael G. Davis 1996-Present: Vice President
1994-Present: Vice President -
Marketing and Customer
Services - OG&E
1992-1994: Director-Marketing
Division - OG&E
1992: Manager - Industrial
Services - OG&E
22
Name Business Experience
- -------------------- ------------------------------------------------------
James R. Hatfield Present: Vice President and Treasurer
Present: Vice President and
Treasurer - OG&E
1994-1997: Treasurer - OG&E
1994: Vice President - Investor
Relations & Corporate
Secretary - Aquila Gas
Pipeline Corporation
(an intrastate gas
pipeline subsidiary of
UtiliCorp United Inc.)
1992-1993: Assistant Treasurer -
UtiliCorp United Inc.
(an electric and
natural gas utility
company)
Irma B. Elliott 1996-Present: Vice President and
Corporate Secretary
1996-Present: Vice President and
Corporate Secretary -
OG&E
1992-1996: Secretary - OG&E
Melvin D. Bowen, Jr. 1994-Present: Vice President -
Power Delivery - OG&E
1992-1994: Metro Region
Superintendent - OG&E
Jack T. Coffman 1994-Present: Vice President -
Power Supply - OG&E
1992-1994: Manager - Generation
Services - OG&E
23
Name Business Experience
- -------------------- ------------------------------------------------------
Donald R. Rowlett 1996-Present: Controller Corporate
Accounting - OG&E
1994-1996: Assistant Controller - OG&E
1992-1994: Senior Specialist -
Tax Accounting - OG&E
1992: Specialist - Tax Accounting -
OG&E
Don L. Young 1996-Present: Controller Corporate
Audits - OG&E
1992-1996: Controller - OG&E
24
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
- ---------------------------------------------------------
STOCKHOLDER MATTERS.
- --------------------
The Company's Common Stock is listed for trading on the New York and
Pacific Stock Exchanges under the ticker symbol "OGE." Quotes may be obtained in
daily newspapers where the common stock is listed as "OGE Engy" in the New York
Stock Exchange listing table. The following table gives information with respect
to price ranges, as reported in THE WALL STREET JOURNAL as New York Stock
-------------------------
Exchange Composite Transactions, and dividends paid for the periods shown.
1996 1995
----------------------------------------------------------------
Dividend Dividend
Paid High Low Paid High Low
----------------------------------------------------------------
First Quarter $0.66 1/2 $43 5/8 $38 7/8 $0.66 1/2 $36 1/4 $32 9/16
Second Quarter 0.66 1/2 40 1/8 36 7/8 0.66 1/2 36 3/8 33 1/4
Third Quarter 0.66 1/2 41 7/8 38 1/8 0.66 1/2 38 33 3/8
Fourth Quarter 0.66 1/2 41 7/8 38 1/8 0.66 1/2 43 5/8 36 7/8
The number of record holders of Common Stock at December 31, 1996, was
44,544. The book value of the Company's Common Stock at December 31, 1996, was
$23.81.
25
ITEM 6. SELECTED FINANCIAL DATA.
- ---------------------------------
HISTORICAL DATA
1996 1995 1994 1993 1992
------------------------------------------------------------------
SELECTED FINANCIAL DATA
(DOLLARS IN THOUSANDS EXCEPT
FOR PER SHARE DATA)
Operating revenues............ $1,387,435 $1,302,037 $1,355,168 $1,447,252 $1,314,984
Operating expenses............ 1,186,216 1,099,890 1,154,702 1,252,099 1,137,980
---------- ---------- ---------- ---------- ----------
Operating income.............. 201,219 202,147 200,466 195,153 177,004
Other income and deductions... 97 800 (2,167) (1,301) (567)
Interest charges.............. 67,984 77,691 74,514 79,575 76,725
---------- ---------- ---------- ---------- ----------
Net income.................... 133,332 125,256 123,785 114,277 99,712
Preferred dividend
requirements................. 2,302 2,316 2,317 2,317 2,317
Earnings available for
common....................... $ 131,030 $ 122,940 $ 121,468 $ 111,960 $ 97,395
========== ========== ========== ========== ==========
Long-term debt................ $ 829,281 $ 843,862 $ 730,567 $ 838,660 $ 838,654
Total assets.................. $2,762,355 $2,754,871 $2,782,629 $2,731,424 $2,590,083
Earnings per average common
share........................ $ 3.25 $ 3.05 $ 3.01 $ 2.78 $ 2.42
CAPITALIZATION RATIOS
Common equity................. 52.26% 51.19% 54.13% 50.51% 50.36%
Cumulative preferred stock.... 2.68% 2.73% 2.94% 2.78% 2.79%
Long-term debt................ 45.06% 46.08% 42.93% 46.71% 46.85%
INTEREST COVERAGES
Before federal income taxes
(including AFUDC)......... 4.07X 3.48X 3.59X 3.32X 3.05X
(excluding AFUDC)......... 4.06X 3.46X 3.58X 3.32X 3.04X
After federal income taxes
(including AFUDC)......... 2.94X 2.59X 2.64X 2.43X 2.29X
(excluding AFUDC)......... 2.93X 2.57X 2.62X 2.42X 2.28X
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF OPERATIONS
- ----------------------------------------------------------
AND FINANCIAL CONDITION.
- ------------------------
MANAGEMENT'S DISCUSSION AND ANALYSIS.
OVERVIEW
Percent Change
From Prior Year
---------------
(THOUSANDS EXCEPT PER SHARE AMOUNTS) 1996 1995 1994 1996 1995
- ---------------------------------------------------------------------------------------------------
Operating revenues...................... $1,387,435 $1,302,037 $1,355,168 6.6 (3.9)
Earnings available for common stock..... $ 131,030 $ 122,940 $ 121,468 6.6 1.2
Average shares outstanding.............. 40,367 40,356 40,344 --- ---
Earnings per average common share....... $ 3.25 $ 3.05 $ 3.01 6.6 1.3
Dividends paid per share................ $ 2.66 $ 2.66 $ 2.66 --- ---
===================================================================================================
OGE Energy Corp. (the "Company") became the parent company of Oklahoma Gas
and Electric Company ("OG&E") and its former subsidiary, Enogex Inc. ("Enogex")
on December 31, 1996 in a corporate reorganization whereby all common stock of
OG&E was exchanged on a share-for-share basis for common stock of the Company.
Prior to December 31, 1996, the Company had no operations and the financial
results discussed herein essentially represent the consolidated statements of
OG&E and comparisons to prior year results represent comparisons to the
consolidated results of OG&E. Under this corporate structure, the Company serves
as the parent holding company to OG&E, Enogex and any other companies that may
be formed within the organization in the future. This new holding company
structure is intended to provide greater flexibility to take advantage of
opportunities in an increasingly competitive business environment and to clearly
separate the Company's electric utility business from its non-utility
businesses. Because OG&E is the Company's principal subsidiary, the Company's
financial results and condition are substantially dependent at this time on the
financial results and condition of OG&E.
Earnings for 1996 increased 6.6 percent from $3.05 per share in 1995 to
$3.25 per share in 1996. The increase is primarily the result of continued
customer growth in the OG&E service area, lower interest costs and increased
earnings by Enogex. The 1995 increase from $3.01 per share to $3.05 per share
resulted primarily from customer growth in the OG&E service area and improved
operating efficiencies from the 1994 restructuring of the Company's operations.
The dividend payout ratio (expressed as a percentage of earnings available
for common) improved in 1996 to 82 percent as compared to 87 percent for 1995.
The Company's long-term goal is to achieve a dividend payout ratio of 75 percent
based on long-term earnings expectations.
On February 11, 1997, the Oklahoma Corporation Commission ("OCC") issued an
order approving OG&E's proposed settlement agreement, which reduced OG&E's
electric rates on an annual basis by approximately $50 million, approximately
$45 million effective March 5, 1997, and the remaining $5 million effective
March 1, 1998. OG&E had filed an application in June 1996 with the OCC for an
annual electric utility rate reduction of $14.2 million. Various parties
proposed significantly higher reductions than the $14.2 million proposed by OG&E
and the $50 million approved by the OCC. The approved rate reduction provides an
incentive program designed to encourage future generation cost savings to be
shared by OG&E and its customers. This program also gives OG&E the opportunity
to
27
lessen the impact of the $50 million reduction, if future cost savings are
achieved. See Note 10 of Notes to Consolidated Financial Statements.
In 1994, the Company restructured and redesigned its operations to reduce
costs in order to more favorably position itself for the competitive electric
utility environment. As part of this process, the Company implemented a
Voluntary Early Retirement Package ("VERP") and a severance package in 1994.
Those two programs reduced the Company's workforce by more than 900 employees.
In January 1995, OG&E began amortizing a regulatory asset of $48.9 million
consisting of the balance of the deferred costs associated with the VERP and the
severance package, in accordance with an order of the OCC issued on October 26,
1994. The OCC order permitted the Company to amortize the $48.9 million over 26
months and reduced electric rates during such period by approximately $15
million annually. At December 31, 1996, the unamortized regulatory asset was
$3.8 million, which is included on the Consolidated Balance Sheets as Deferred
Charges - Other. In 1996, the labor savings from the VERP and severance package
approximated the amortization of the regulatory asset and the annual rate
reduction of $15 million and therefore, did not significantly impact 1996
operating results. The unamortized regulatory asset will be fully amortized in
February 1997, allowing the labor savings associated with the 1994 workforce
reductions to lessen the impact of the most recent OCC order reducing OG&E's
electric rates which became effective on March 5, 1997.
In 1996, the Company decided upon an "enterprise software" future for its
businesses. Enterprise software is a corporate software system designed to
handle most of the Company's information processing needs and to improve work
processes throughout the Company. On January 1, 1997, an enterprise software
system was successfully implemented throughout the Company and is expected to
give the Company a strategic advantage in the years ahead.
The following discussion and analysis presents factors which had a material
effect on the Company's operations and financial position during the last three
years and should be read in conjunction with the Consolidated Financial
Statements and Notes thereto. Trends and contingencies of a material nature are
discussed to the extent known and considered relevant. Except for the historical
statements contained herein, the matters discussed in the following discussion
and analysis, are forward-looking statements that are subject to certain risks,
uncertainties and assumptions. Such forward-looking statements are intended to
be identified in this document by the words "anticipate", "estimate",
"objective", "possible", "potential" and similar expressions. Actual results may
vary materially. Factors that could cause actual results to differ materially
include, but are not limited to: general economic conditions, including their
impact on capital expenditures; business conditions in the energy industry;
competitive factors; unusual weather; regulatory decisions and the other risk
factors listed in the reports filed by the Company with the Securities and
Exchange Commission.
28
RESULTS OF OPERATIONS
REVENUES
Percent Change
From Prior Year
---------------
(THOUSANDS) 1996 1995 1994 1996 1995
- ---------------------------------------------------------------------------------------------------------
Sales of electricity to OG&E customers..... $1,172,740 $1,133,283 $1,185,133 3.5 (4.4)
Sales of electricity to other utilities.... 27,597 35,004 11,765 (21.2) 197.5
Enogex..................................... 187,098 133,750 158,270 39.9 (15.5)
- -------------------------------------------------------------------------------------
Total operating revenues.............. $1,387,435 $1,302,037 $1,355,168 6.6 (3.9)
=========================================================================================================
System kilowatt-hour sales................. 21,540,670 20,828,415 20,642,675 3.4 0.9
Kilowatt-hour sales to other utilities..... 1,475,449 1,851,839 556,765 (20.3) 232.6
- -------------------------------------------------------------------------------------
Total kilowatt-hour sales............. 23,016,119 22,680,254 21,199,440 1.5 7.0
=========================================================================================================
In 1996, approximately 87 percent of the Company's revenues consisted of
OG&E's regulated sales of electricity as a public utility, while the remaining
13 percent was provided by the non-utility operations of Enogex. Revenues from
sales of electricity are somewhat seasonal, with a large portion of OG&E's
annual electric revenues occurring during the summer months when the electricity
needs of its customers increase. Enogex's primary operations consist of
transporting natural gas through its intra-state pipeline to various customers
(including OG&E), buying and selling natural gas to third parties ("gas
marketing"), selling natural gas liquids extracted by its natural gas processing
plants and investing in natural gas development and production activities.
Actions of the regulatory commissions that set OG&E's electric rates will
continue to affect OG&E's financial results. The commissions also have the
authority to examine the appropriateness of OG&E's recovery from its customers
of fuel costs, which include the transportation fees that OG&E pays Enogex for
transporting natural gas to OG&E's generating units. See "Contingencies" and
Note 10 of Notes to Consolidated Financial Statements for a discussion of the
impact of the OCC's February 11, 1997 rate order on these transportation fees.
Operating revenues increased $85.4 million or 6.6 percent, during 1996,
primarily due to continued growth in kilowatt-hour sales to OG&E customers
("system sales") and a significant increase in revenue from Enogex businesses.
In 1996, Enogex revenues increased 39.9 percent. This increase is primarily
attributable to increased gas marketing sales, increased margins in petroleum
product sales and increased third party gas transportation services.
During 1995, operating revenues decreased $53.1 million or 3.9 percent,
primarily due to lower revenue from Enogex businesses, the $15 million rate
reduction, mild weather and recovery of lower fuel costs. Partially offsetting
the impact of these reductions was continued growth in system sales and a
significant increase in kilowatt-hour sales to other utilities.
Enogex revenues decreased 15.5 percent in 1995. This reduction was
primarily attributable to a reduced emphasis on low margin off-system natural
gas sales and lower natural gas prices on gas purchased for resale.
29
EXPENSES AND OTHER ITEMS
Percent Change
From Prior Year
---------------
(DOLLARS IN THOUSANDS) 1996 1995 1994 1996 1995
- --------------------------------------------------------------------------------------------------
Fuel ................................. $ 279,083 $ 260,443 $ 263,329 7.2 (1.1)
Purchased power....................... 222,070 216,598 228,701 2.5 (5.3)
Gas purchased for resale (Enogex)..... 117,343 87,293 114,044 34.4 (23.5)
Other operation and maintenance....... 307,154 290,824 284,194 5.6 2.3
Restructuring ........................ --- --- 21,035 * *
Depreciation and Amortization......... 136,140 132,135 126,377 3.0 4.6
Taxes................................. 124,426 112,597 117,022 10.5 (3.8)
- --------------------------------------------------------------------------------
Total operating expenses......... $1,186,216 $1,099,890 $1,154,702 7.8 (4.7)
==================================================================================================
* Not meaningful
Total operating expenses increased $86.3 million or 7.8 percent in 1996,
primarily due to increases in quantities and prices of gas purchased for resale
by Enogex, higher fuel costs for the production of electricity, increased other
operation costs and higher income taxes.
Enogex's gas purchased for resale pursuant to its gas marketing operations
increased $30.0 million or 34.4 percent for 1996 compared to a decrease of $26.7
million or 23.5 percent for 1995. The 1996 increase was due to increased sales
volumes and significantly higher purchase prices, while the 1995 decrease
resulted from reduced volumes and lower natural gas prices.
OG&E's generating capability is evenly divided between coal and natural gas
and provides for flexibility to use either fuel to the best economic advantage
for the Company and its customers. In 1996, fuel costs increased $18.6 million
or 7.2 percent primarily due to increased generation of electricity resulting
from continued customer growth and favorable weather conditions in the electric
service area. During 1995, fuel costs decreased $2.9 million or 1.1 percent
because of lower prices and usage of natural gas and a higher volume of
kilowatt-hours generated with lower-priced coal.
Other operation and maintenance increased $16.3 million in 1996, due to the
new enterprise software information processing system, increased pension
expense, increased oil and gas production and the related lease operating
expenses by Enogex, minor overhauls at coal-fired generating plants, repair of
coal handling equipment and increased pipeline maintenance associated with
increased gas gathering and sales by Enogex. Other operation and maintenance
increased $6.6 million in 1995, because of $22.6 million of amortization of the
regulatory asset resulting from the 1994 restructuring of the Company's
operations, costs associated with a major storm in the Company's service area
and the write-off of obsolete inventory, offset by lower costs resulting from
the 1994 workforce reduction and efficiencies gained in the maintenance of the
Company's generating plants.
In 1996, income taxes increased primarily due to a decrease in tax credits
earned and higher pre-tax earnings. Income taxes decreased in 1995 as a result
of an increase in tax credits earned and lower pre-tax earnings.
30
Purchased power costs were $222.1 million in 1996, up from $216.6 million
in 1995. The $5.5 million increase in 1996 resulted from the availability of
larger quantities of economically-priced energy from other utilities. Purchased
power costs decreased $12.1 million or 5.3 percent in 1995, primarily due to the
availability of larger quantities of economically-priced energy in 1994. As
required by the Public Utility Regulatory Policy Act ("PURPA"), OG&E is
currently purchasing power from qualified cogeneration facilities. In 1998,
another qualified cogeneration facility is scheduled to become operational and
OG&E is obligated to purchase up to 100 megawatts of capacity from this facility
as well. See related discussion of purchased power in Note 9 of Notes to
Consolidated Financial Statements.
Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are passed through to OG&E's electric customers through
automatic fuel adjustment clauses. The automatic fuel adjustment clauses are
subject to periodic review by the OCC, the Arkansas Public Service Commission
("APSC") and the Federal Energy Regulatory Commission ("FERC"). The OCC, the
APSC and the FERC have authority to review the appropriateness of gas
transportation charges or other fees OG&E pays Enogex, which OG&E seeks to
recover through the fuel adjustment clause or other tariffs. See Note 10 of
Notes to Consolidated Financial Statements for a discussion of the February 11,
1997 OCC order setting, among other things, annual compensation for these
transportation services provided by Enogex to OG&E at $41.3 million and
directing OG&E to transition to competitive bidding of its gas transportation
requirements currently provided by Enogex no later than April 30, 2000; the APSC
order in July 1996 requiring, among other things, a $4.5 million refund; and the
OCC order in February 1994 requiring, among other things, a $41.3 million refund
relating to the fees OG&E paid Enogex.
OG&E has initiated numerous other ongoing programs that have helped reduce
the cost of generating electricity over the last several years. These programs
include: 1) utilizing a natural gas storage facility; 2) spot market purchases
of coal; 3) renegotiated contracts for coal, gas, railcar maintenance and coal
transportation; and 4) a heat rate awareness program to produce kilowatt-hours
with less fuel. Reducing fuel costs helps OG&E remain competitive, which in turn
helps OG&E's electric customers remain competitive in a global economy.
The increases in depreciation and amortization for 1996 and 1995 reflects
higher levels of depreciable plant and amortization of gas sales contracts by
Enogex.
The decrease in interest expense for 1996 was primarily attributable to the
successful refinancing activity in 1995. The Company refinanced approximately
$396 million of short-term and long-term debt in 1995, resulting in an
approximate $10 million reduction in annual interest expense.
31
LIQUIDITY, CAPITAL RESOURCES AND CONTINGENCIES
The primary capital requirements for 1996 and as estimated for 1997
through 1999 are as follows:
(DOLLARS IN MILLIONS) 1996 1997 1998 1999
- --------------------------------------------------------------------------------
Construction expenditures
including AFUDC................... $150.0 $203.0 $169.0 $163.0
Maturities of long-term debt and
sinking fund requirements......... --- 15.0 25.0 12.5
- --------------------------------------------------------------------------------
Total......................... $150.0 $218.0 $194.0 $175.5
================================================================================
The Company's primary needs for capital are related to construction of new
facilities to meet anticipated demand for utility service, to replace or expand
existing facilities in both its electric and non-utility businesses, and to some
extent, for satisfying maturing debt and sinking fund obligations. The Company
generally meets its cash needs through a combination of internally generated
funds, short-term borrowings and permanent financing. Because of the continuing
trend toward greater environmental awareness and increasingly stringent
regulations, the Company has been experiencing increasing construction
expenditures related to compliance with environmental laws and regulations.
1996 CAPITAL REQUIREMENTS AND FINANCING ACTIVITIES
Construction expenditures were $150 million in 1996. Approximately $1.3
million of the 1996 construction expenditures were to comply with environmental
regulations. This compares to construction expenditures of $154 million in 1995,
of which $1 million was to comply with environmental regulations.
During 1996, the Company's primary source of capital was internally
generated funds from operating cash flows. Operating cash flow remained strong
in 1996 as internally generated funds provided financing for all of the
Company's capital expenditures. Variations in accounts receivable and accounts
payable are not generally significant indicators of the Company's liquidity, as
such variations are primarily attributable to fluctuations in weather in OG&E's
service territory, which has a direct effect on sales of electricity. In 1996,
accounts receivable and accounts payable were higher due to more favorable
weather in the last quarter of the year as compared to 1995.
Short-term borrowings were used during 1996 to meet temporary cash
requirements. At December 31, 1996, the Company had outstanding short-term
borrowings of $41.4 million.
In April 1996, OG&E filed a registration statement for the sale of up to
$300 million of senior notes. In February 1997, OG&E reduced the amount of the
registration statement for senior notes to $250 million and filed a new
registration statement for up to $50 million of grantor trust preferred
securities. Assuming favorable market conditions, OG&E may issue all or part of
these securities to refinance, at lower rates, one or more series of outstanding
first mortgage bonds or preferred stock.
32
FUTURE CAPITAL REQUIREMENTS
The Company's construction program for the next several years does not
include additional base-load generating units. Rather, to meet the increased
electricity needs of OG&E's electric utility customers during the balance of the
century, OG&E will concentrate on maintaining the reliability and increasing the
utilization of existing capacity and increasing demand-side management efforts.
Approximately $400,000 of the Company's construction expenditures budgeted for
1997 are to comply with environmental laws and regulations.
Future financing requirements may be dependent, to varying degrees, upon
numerous factors outside the Company's control such as general economic
conditions, abnormal weather, load growth, inflation, changes in environmental
laws or regulations, rate increases or decreases allowed by regulatory agencies,
new legislation and market entry of competing electric power generators.
FUTURE SOURCES OF FINANCING
Management expects that internally generated funds will be adequate over
the next three years to meet anticipated capital requirements. Short-term
borrowings will continue to be used to meet temporary cash requirements. OG&E
has the necessary regulatory approvals to incur up to $400 million in short-term
borrowings at any one time. OG&E has in place a line of credit for up to $160
million which expires December 6, 2000.
The Company continues to evaluate opportunities to enhance shareowner
returns and achieve long-term financial objectives through acquisitions of
non-utility businesses. Permanent financing could be required for such
acquisitions.
CONTINGENCIES
The Company through its subsidiaries is defending various claims and legal
actions, including environmental actions, which are common to its operations. As
to environmental matters, OG&E has been designated as a "potentially responsible
party" ("PRP") with respect to three waste disposal sites to which OG&E sent
materials. Remediation of two of these sites has been completed. OG&E's total
waste disposed at the remaining site is minimal and on February 15, 1996, the
Company elected to participate in the de minimis settlement offered by the EPA,
which is being contested by one party. This limits the Company's financial
obligation in addition to removing any participation in the site remedy. While
it is not possible to determine the precise outcome of these matters, in the
opinion of management, OG&E's ultimate liability for these sites will not be
material.
On February 11, 1997, the OCC issued an order, among other things,
directing OG&E to transition to competitive bidding its gas transportation
requirements, currently met by Enogex, no later than April 30, 2000. This order
also set annual compensation for the transportation services provided by Enogex
to OG&E at $41.3 million until competitively-bid gas transportation begins. In
1996, approximately $44 million or 19 percent of Enogex's revenues were
attributable to transporting gas for OG&E. Other pipelines seeking to compete
with Enogex for OG&E's business will likely have to pay a fee to Enogex for
transporting gas on Enogex's system or incur capital expenditures to develop the
necessary infrastructure to connect with OG&E's gas-fired generating stations.
Nevertheless, a potential outcome of the competitive bidding process is that the
revenues of Enogex derived from transporting gas for OG&E may be significantly
less after April 30, 2000.
33
The Company has contracted for low-sulfur coal to comply with the sulfur
dioxide limitations of the Clean Air Act Amendments of 1990 ("CAAA"). OG&E also
has completed installation and certification of all required continuous
emissions monitors at each of its generating units. Phase II sulfur dioxide
emission requirements will affect OG&E beginning in the year 2000. OG&E believes
it can meet these sulfur dioxide limits without additional capital expenditures.
With respect to nitrogen oxide limits, OG&E is meeting the current emission
standards and has exercised its option to extend the effective date of the
further reductions from 2000 to 2008.
The Oklahoma Department of Environmental Quality's CAAA Title V air
permitting program was approved by the EPA in March, 1996. OG&E submitted
comprehensive site air permit applications on July 10, 1996 for two of its major
source generating stations. Title V permits for the remaining six permit
applications should be complete by March, 1997. Air permit fees for generating
stations were approximately $340,000 in 1996 and are estimated to be
approximately $340,000 in 1997.
In October 1992, the National Energy Policy Act of 1992 ("Energy Act") was
enacted. Among many other provisions, the Energy Act is designed to promote
competition in the development of wholesale power generation in the electric
utility industry. It exempts a new class of independent power producers from
regulation under the Public Utility Holding Company Act of 1935 and allows the
FERC to order "wholesale wheeling" by public utilities to provide utility and
non-utility generators access to public utility transmission facilities.
In April 1996, FERC issued two final rules, Orders 888 and 889, which may
have a significant impact on wholesale markets. These orders were amended in
orders issued in March 1997. Order 888, which was preceded by a Notice of
Proposed Rulemaking referred to as the "Mega-NOPR", sets forth rules on
non-discriminatory open access transmission service to promote wholesale
competition. Order 888, which was effective on July 9, 1996, requires utilities
and other transmission users to abide by comparable terms, conditions and
pricing in transmitting power. Order 889, which had its effective date extended
to January 3, 1997, requires public utilities to implement Standards of Conduct
and an Open Access Same Time Information System ("OASIS", formerly known as
"Real-Time Information Networks"). These rules require transmission personnel to
provide the same information about the transmission system to all transmission
customers using the OASIS. OG&E is complying with these new rules from the FERC.
Another impact of complying with FERC's Order 888 is a requirement for
utilities to offer a transmission tariff that includes network transmission
service ("NTS") to transmission customers. NTS allows transmission service
customers to fully integrate load and resources on an instantaneous basis, in a
manner similar to how OG&E has historically integrated its load and resources.
Under NTS, OG&E and participating customers share the total annual transmission
cost for their combined joint-use systems, net of related transmission revenues,
based upon each company's share of the total system load. At this time, OG&E
expects to incur approximately $1 million in start-up costs beginning in 1997
and a minimal annual expense increase, as a result of Orders 888 and 889.
Numerous state legislatures and regulatory commissions are considering
proposals to increase competition at the retail customer level. The OCC is
seeking to identify, describe and create a process to implement a comprehensive
and integrated restructuring of the electric utility industry for the State of
Oklahoma. On June 6, 1996, the OCC issued a Notice of Inquiry proposing
questions for comment. In response to the Notice of Inquiry, OG&E filed comments
with the OCC on September 9, 1996. The comments listed, among other things, five
critical issues that OG&E believes must be addressed to ensure a successful
transition to a deregulated environment. These issues are: 1) retail wheeling
should be implemented in Oklahoma at the same time it is implemented and on the
same terms in all surrounding
34
states; 2) stranded costs must be recovered; 3) a level playing field must be
established; 4) state regulators role must be restructured and 5) there must be
no exceptions to the new rules. In addition, legislation has been introduced in
the Oklahoma Legislature to permit increased competition at the retail level by
July 2002. OG&E is not opposed to such legislation generally, provided the five
issues noted above are addressed fairly. OG&E has taken steps such as its 1994
restructuring of its operations and its holding company reorganization, and
intends to take appropriate steps in the future, to remain a competitive
supplier of electricity.
Besides the existing contingencies described above, and those described in
Note 9 of Notes to Consolidated Financial Statements, the Company's ability to
fund its future operational needs and to finance its construction program is
dependent upon numerous other factors beyond its control, such as general
economic conditions, abnormal weather, load growth, inflation, new environmental
laws or regulations, and the cost and availability of external financing.
35
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
- ----------------------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
Year ended December 31 (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1996 1995 1994
==============================================================================================================
OPERATING REVENUES ................................................ $1,387,435 $1,302,037 $1,355,168
- --------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
Fuel ......................................................... 279,083 260,443 263,329
Purchased power .............................................. 222,070 216,598 228,701
Gas purchased for resale ..................................... 117,343 87,293 114,044
Other operation .............................................. 247,331 233,250 216,961
Maintenance .................................................. 59,823 57,574 67,233
Restructuring ................................................ --- --- 21,035
Depreciation ................................................. 136,140 132,135 126,377
Current income taxes ......................................... 81,227 77,895 50,129
Deferred income taxes, net ................................... 2,150 (3,928) 27,092
Deferred investment tax credits, net ......................... (5,150) (5,150) (5,150)
Taxes other than income ...................................... 46,199 43,780 44,951
- --------------------------------------------------------------------------------------------------------------
Total operating expenses ................................. 1,186,216 1,099,890 1,154,702
- --------------------------------------------------------------------------------------------------------------
OPERATING INCOME .................................................. 201,219 202,147 200,466
- --------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
Interest income .............................................. 2,198 4,380 3,409
Other ........................................................ (2,101) (3,580) (5,576)
- --------------------------------------------------------------------------------------------------------------
Net other income and deductions .......................... 97 800 (2,167)
- --------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
Interest on long-term debt ................................... 62,412 67,549 67,680
Allowance for borrowed funds used during construction ........ (709) (1,224) (1,073)
Other ........................................................ 6,281 11,366 7,907
- --------------------------------------------------------------------------------------------------------------
Total interest charges, net .............................. 67,984 77,691 74,514
- --------------------------------------------------------------------------------------------------------------
NET INCOME ........................................................ 133,332 125,256 123,785
PREFERRED DIVIDEND REQUIREMENTS ................................... 2,302 2,316 2,317
- --------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON ..................................... $ 131,030 $ 122,940 $ 121,468
==============================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (thousands) ..................... 40,367 40,356 40,344
EARNINGS PER AVERAGE COMMON SHARE ................................. $ 3.25 $ 3.05 $ 3.01
==============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
36
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year ended December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
==============================================================================================================
BALANCE AT BEGINNING OF PERIOD.................................... $ 425,545 $ 409,960 $ 395,811
ADD - net income.................................................. 133,332 125,256 123,785
Total.................................................... 558,877 535,216 519,596
DEDUCT:
Cash dividends declared on preferred stock................... 2,302 2,316 2,317
Cash dividends declared on common stock...................... 107,377 107,355 107,319
- --------------------------------------------------------------------------------------------------------------
Total.................................................... 109,679 109,671 109,636
- --------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD.......................................... $ 449,198 $ 425,545 $ 409,960
==============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
37
CONSOLIDATED BALANCE SHEETS
December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
==============================================================================================================
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service................................................... $4,005,532 $3,898,829 $3,770,247
Construction work in progress................................ 27,968 29,705 43,943
- --------------------------------------------------------------------------------------------------------------
Total property, plant and equipment...................... 4,033,500 3,928,534 3,814,190
Less accumulated depreciation....................... 1,687,423 1,585,274 1,487,300
- --------------------------------------------------------------------------------------------------------------
Net property, plant and equipment............................ 2,346,077 2,343,260 2,326,890
- --------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost........................... 24,802 23,775 20,207
- --------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
Cash and cash equivalents.................................... 2,523 5,420 2,455
Accounts receivable - customers, less reserve of $4,626,
$4,205 and $3,719, respectively......................... 128,974 112,441 105,979
Accrued unbilled revenues.................................... 34,900 43,550 36,800
Accounts receivable - other.................................. 11,748 9,152 8,601
Fuel inventories, at LIFO cost............................... 62,725 60,356 46,494
Materials and supplies, at average cost...................... 24,827 22,996 30,401
Prepayments and other........................................ 4,300 4,535 43,137
Accumulated deferred tax assets.............................. 10,067 10,759 12,077
- --------------------------------------------------------------------------------------------------------------
Total current assets..................................... 280,064 269,209 285,944
- --------------------------------------------------------------------------------------------------------------
DEFERRED CHARGES:
Advance payments for gas..................................... 9,500 6,500 10,000
Income taxes recoverable through future rates................ 44,368 41,934 47,246
Other........................................................ 57,544 70,193 92,342
- --------------------------------------------------------------------------------------------------------------
Total deferred charges................................... 111,412 118,627 149,588
- --------------------------------------------------------------------------------------------------------------
TOTAL ASSETS...................................................... $2,762,355 $2,754,871 $2,782,629
==============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
38
CONSOLIDATED BALANCE SHEETS (Continued)
December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
==============================================================================================================
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (see statements):
Common stock and retained earnings............................ $ 961,603 $ 937,535 $ 921,177
Cumulative preferred stock.................................... 49,379 49,939 49,973
Long-term debt................................................ 829,281 843,862 730,567
- --------------------------------------------------------------------------------------------------------------
Total capitalization...................................... 1,840,263 1,831,336 1,701,717
- --------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
Short-term debt............................................... 41,400 67,600 182,750
Accounts payable.............................................. 86,856 72,089 66,391
Dividends payable............................................. 27,421 27,427 27,415
Customers' deposits........................................... 23,257 21,920 20,904
Accrued taxes................................................. 26,761 27,937 25,153
Accrued interest.............................................. 19,832 19,144 23,873
Long-term debt due within one year............................ 15,000 --- 25,350
Accumulated provision for rate refund......................... --- 2,650 2,970
Other......................................................... 39,188 33,388 41,321
- --------------------------------------------------------------------------------------------------------------
Total current liabilities................................. 279,715 272,155 416,127
- --------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 61,335 67,350 71,014
Accumulated deferred income taxes............................. 488,016 485,078 497,056
Accumulated deferred investment tax credits................... 78,028 83,178 88,328
Other......................................................... 14,998 15,774 8,387
- --------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities.............. 642,377 651,380 664,785
- --------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 9 and 10)
- --------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION AND LIABILITIES............................... $2,762,355 $2,754,871 $2,782,629
==============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
39
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
================================================================================================================
COMMON STOCK AND RETAINED EARNINGS:
Common stock, par value $0.01, $2.50 and $2.50 per
share, respectively; authorized 125,000,000,
100,000,000 and 100,000,000 shares,
respectively; and issued 46,470,616 shares.................. $ 465 $ 116,177 $ 116,177
Premium on capital stock........................................ 724,256 608,273 608,158
Retained earnings 449,198 425,545 409,960
Treasury stock - 6,091,871, 6,097,357, and 6,116,229
shares, respectively........................................ (212,316) (212,460) (213,118)
- ----------------------------------------------------------------------------------------------------------------
Total common stock and retained earnings............... 961,603 937,535 921,177
- ----------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK:
Par value $20, authorized 675,000 shares - 4%;
421,963, 421,963, and 423,663 shares, respectively.......... 8,439 8,439 8,473
Par value $25, authorized and unissued 4,000,000 shares......... --- --- ---
Par value $0.01, authorized and unissued 5,000,000 shares....... --- --- ---
Par value $100, authorized 1,865,000 shares-
SERIES SHARES OUTSTANDING
4.20% 49,950......................................... 4,995 5,000 5,000
4.24% 75,000......................................... 7,500 7,500 7,500
4.44% 63,500......................................... 6,350 6,500 6,500
4.80% 70,950......................................... 7,095 7,500 7,500
5.34% 150,000........................................ 15,000 15,000 15,000
- ----------------------------------------------------------------------------------------------------------------
Total cumulative preferred stock....................... 49,379 49,939 49,973
- ----------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT:
First mortgage bonds-
SERIES DATE DUE
4.50 % March 1, 1995.................................. --- --- 25,000
5.125% January 1, 1997................................ 15,000 15,000 15,000
6.375% January 1, 1998................................ 25,000 25,000 25,000
7.125% January 1, 1999................................ 12,500 12,500 12,500
8.625% January 1, 2000................................ --- --- 30,000
6.25 % Senior Notes Series B, October 15, 2000........ 110,000 110,000 ---
7.125% January 1, 2002................................ 40,000 40,000 40,000
8.375% January 1, 2004................................ --- --- 75,000
9.125% January 1, 2005................................ --- --- 60,000
8.625% January 1, 2006................................ --- --- 55,000
8.375% January 1, 2007................................ 75,000 75,000 75,000
8.625% November 1, 2007............................... 35,000 35,000 35,000
8.25 % August 15, 2016................................ 100,000 100,000 100,000
8.875% December 1, 2020............................... 75,000 75,000 75,000
7.30 % Senior Notes Series A, October 15, 2025........ 110,000 110,000 ---
5.875% Pollution Control Series A December 1, 2007.... --- --- 47,000
7.00 % Pollution Control Series C, March 1, 2017...... 56,000 56,000 56,000
Other bonds-
6.75 % Muskogee Industrial Trust Bonds,
March 1, 2006.................................. --- --- 32,050
Var. % Garfield Industrial Authority, January 1, 2025. 47,000 47,000 ---
Var. % Muskogee Industrial Authority, January 1, 2025. 32,400 32,400 ---
Unamortized premium and discount, net........................... (8,619) (9,038) (8,533)
Enogex Inc. notes (Note 5)...................................... 120,000 120,000 6,900
- ----------------------------------------------------------------------------------------------------------------
Total long-term debt................................... 844,281 843,862 755,917
Less long-term debt due within one year............ 15,000 --- 25,350
- ----------------------------------------------------------------------------------------------------------------
Total long-term debt (excluding long-term
debt due within one year).......................... 829,281 843,862 730,567
- ----------------------------------------------------------------------------------------------------------------
Total Capitalization ............................................... $1,840,263 $1,831,336 $1,701,717
================================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
40
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
==============================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income....................................................... $ 133,332 $ 125,256 $ 123,785
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation.................................................. 136,140 132,135 126,377
Deferred income taxes and investment tax credits, net......... (3,000) (9,078) 21,942
Provision for rate refund..................................... 1,804 3,112 4,200
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers........................... (16,533) (6,462) 11,898
Accrued unbilled revenues................................. 8,650 (6,750) 8,300
Fuel, materials and supplies inventories.................. (4,200) (6,457) (22,955)
Accumulated deferred tax assets........................... 692 1,318 12,011
Other current assets...................................... (2,361) 38,051 (16,821)
Accounts payable.......................................... 13,401 5,887 (35,667)
Accrued taxes............................................. (1,176) 2,784 436
Accrued interest.......................................... 688 (4,729) (2,839)
Accumulated provision for rate refund..................... (2,650) (320) (36,147)
Other current liabilities................................. 7,131 (6,905) (5,789)
Other operating activities.................................... 22,753 13,667 15,479
- --------------------------------------------------------------------------------------------------------------
Net cash provided from operating activities............... 294,671 281,509 204,210
- --------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures.......................................... (161,129) (141,439) (151,012)
- --------------------------------------------------------------------------------------------------------------
Net cash used in investing activities..................... (161,129) (141,439) (151,012)
- --------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt, net............................. --- 87,750 (83,450)
Short-term debt, net.......................................... (26,200) (115,150) 135,750
Redemption of preferred stock................................. (560) (34) ---
Cash dividends declared on preferred stock.................... (2,302) (2,316) (2,317)
Cash dividends declared on common stock....................... (107,377) (107,355) (107,319)
- --------------------------------------------------------------------------------------------------------------
Net cash used in financing activities..................... (136,439) (137,105) (57,336)
- --------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS..................................................... (2,897) 2,965 (4,138)
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD.......................................................... 5,420 2,455 6,593
CASH AND CASH EQUIVALENTS AT END OF PERIOD......................... $ 2,523 $ 5,420 $ 2,455
==============================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Cash Paid During the Period for:
Interest (net of amount capitalized)...................... $ 64,882 $ 76,860 $ 74,372
Income taxes ............................................. $ 82,970 $ 77,752 $ 57,416
- --------------------------------------------------------------------------------------------------------------
DISCLOSURE OF ACCOUNTING POLICY:
For purposes of these statements, the Company considers all highly liquid
debt instruments purchased with a maturity of three months or less to be cash
equivalents. These investments are carried at cost which approximates market.
==============================================================================================================
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART
HEREOF.
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
REORGANIZATION AND PRINCIPALS OF CONSOLIDATION
OGE Energy Corp. (the "Company") became the parent company of Oklahoma Gas
and Electric Company ("OG&E") and its former subsidiary, Enogex, Inc. ("Enogex")
on December 31, 1996. On that date, all outstanding OG&E common stock was
exchanged on a share-for-share basis for common stock of OGE Energy Corp. and
the common stock of Enogex was distributed to the Company. The financial
information presented represents the consolidated results of OG&E through
December 31, 1996. All significant intercompany transactions have been
eliminated in consolidation.
ACCOUNTING RECORDS
The accounting records of OG&E are maintained in accordance with the
Uniform System of Accounts prescribed by the Federal Energy Regulatory
Commission ("FERC") and adopted by the Oklahoma Corporation Commission ("OCC")
and the Arkansas Public Service Commission ("APSC"). Additionally, OG&E, as a
regulated utility, is subject to the accounting principles prescribed by
Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the
Effects of Certain Types of Regulation". SFAS No. 71 provides that certain costs
that would otherwise be charged to expense can be deferred as regulatory assets,
based on expected recovery from customers in future rates. Likewise, certain
credits that would otherwise be charged to expense are deferred as regulatory
liabilities based on expected flowback to customers in future rates.
Management's expected recovery of deferred costs and flowback of deferred
credits generally results from specific decisions by regulators granting such
ratemaking treatment. Regulatory assets and liabilities are amortized consistent
with ratemaking treatment established by regulators. Management continuously
monitors the future recoverability of regulatory assets. When, in management's
judgment, future recovery becomes impaired, the amount of the regulatory asset
is reduced or written-off, as appropriate. See Notes 7 and 10 of Notes to
Consolidated Financial Statements for related discussion.
In March 1995 the Financial Accounting Standards Board issued SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." This standard was adopted effective January 1, 1996 and did not
have a material impact on the Company's financial position or its results of
operations.
USE OF ESTIMATES
In preparing the consolidated financial statements, management is required
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
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
42
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 percent of the
average depreciable utility plant, for each of the years 1996, 1995 and 1994, is
provided on a straight-line method over the estimated service life of the
property. Depreciation is provided at the unit level for production plant and at
the account or sub-account level for all other plant, and is based on the
average life group procedure.
Enogex's gas pipeline, gathering systems, compressors and gas processing
plants are depreciated on a straight-line method over periods ranging from 15 to
48 years.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
Allowance for funds used during construction ("AFUDC") is calculated
according to FERC pronouncements for the imputed cost of equity and borrowed
funds. AFUDC, a non-cash item, is reflected as a credit on the Consolidated
Statements of Income and a charge to construction work in progress.
AFUDC rates, compounded semi-annually, were 5.63, 6.30 and 4.58 percent for
the years 1996, 1995 and 1994, 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 cost-of-service
for ratemaking, are charged to substantially all of OG&E's electric customers
through automatic fuel adjustment clauses, which are subject to periodic review
by the OCC, the APSC and the FERC.
FUEL INVENTORIES
Fuel inventories for the generation of electricity consist of coal, oil and
natural gas. These inventories are accounted for under the last-in, first-out
("LIFO") cost method. The estimated replacement cost of fuel inventories
exceeded the stated LIFO cost by approximately $4.6 million, $2.4 million and
$2.5 million for 1996, 1995 and 1994, respectively, based on the average cost of
fuel purchased late in the respective years. Natural gas products inventories
are held for sale and accounted for based on the weighted average cost of
production.
ENVIRONMENTAL COSTS
Accruals for environmental costs are recognized when it is probable that a
liability has been incurred and the amount of the liability can be reasonably
estimated. When a single estimate of the liability
43
cannot be determined, the low end of the estimated range is recorded. Costs are
charged to expense or deferred as a regulatory asset based on expected recovery
from customers in future rates, if they relate to the remediation of conditions
caused by past operations or if they are not expected to mitigate or prevent
contamination from future operations. Where environmental expenditures relate to
facilities currently in use, such as pollution control equipment, the costs may
be capitalized and depreciated over the future service periods. Estimated
remediation costs are recorded at undiscounted amounts, independent of any
insurance or rate recovery, based on prior experience, assessments and current
technology. Accrued obligations are regularly adjusted as environmental
assessments and estimates are revised, and remediation efforts proceed. For
sites where OG&E has been designated as one of several potentially responsible
parties, the amount accrued represents OG&E's estimated share of the cost.
RECLASSIFICATIONS
Certain amounts have been reclassified on the consolidated financial
statements to conform with the 1996 presentation.
44
2. INCOME TAXES
The items comprising tax expense are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
- --------------------------------------------------------------------------------------------------------
Provision For Current Income Taxes:
Federal....................................................... $ 72,633 $ 65,173 $ 42,974
State......................................................... 8,594 12,722 7,155
- --------------------------------------------------------------------------------------------------------
Total Provision For Current Income Taxes.................. 81,227 77,895 50,129
- --------------------------------------------------------------------------------------------------------
Provisions (Benefit) For Deferred Income Taxes, net:
Federal
Depreciation.............................................. 2,671 6,084 7,372
Repair allowance.......................................... 2,100 2,101 1,109
Removal costs............................................. 630 700 1,542
Provision for rate refund................................. 928 (588) 12,406
Company restructuring..................................... (8,250) (8,373) ---
Other..................................................... (294) (2,678) 812
State......................................................... 4,365 (1,174) 3,851
- --------------------------------------------------------------------------------------------------------
Total Provision (Benefit) For Deferred Income Taxes, net.. 2,150 (3,928) 27,092
- --------------------------------------------------------------------------------------------------------
Deferred Investment Tax Credits, net............................... (5,150) (5,150) (5,150)
Income Taxes Relating to Other Income and Deductions............... (515) 1,436 203
- --------------------------------------------------------------------------------------------------------
Total Income Tax Expense.................................. $ 77,712 $ 70,253 $ 72,274
- --------------------------------------------------------------------------------------------------------
Pretax Income...................................................... $211,044 $195,509 $196,059
========================================================================================================
The following schedule reconciles the statutory federal tax rate to the
effective income tax rate:
Year ended December 31 1996 1995 1994
- ----------------------------------------------------------------------------------------------
Statutory federal tax rate......................................... 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit.............. 4.0 3.8 3.7
Tax credits, net................................................... (4.1) (4.8) (3.8)
Other, net......................................................... 1.9 1.9 2.0
- ----------------------------------------------------------------------------------------------
Effective income tax rate as reported......................... 36.8% 35.9% 36.9%
==============================================================================================
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.
45
The Company follows the provisions of SFAS No. 109, "Accounting for Income
Taxes", which uses an asset and liability approach to accounting for income
taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based
on the difference between the financial statement and income tax bases of assets
and liabilities ("temporary differences") using the enacted marginal tax rate.
Deferred income tax expenses or benefits are based on the changes in the asset
or liability from period to period.
The deferred tax provisions, set forth above, are recognized as costs in
the ratemaking process by the commissions having jurisdiction over the rates
charged by OG&E. The components of Accumulated Deferred Income Taxes at December
31, 1996, 1995 and 1994 are as follows:
Year ended December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
- ----------------------------------------------------------------------------------------------------
Current Deferred Tax Assets:
Accrued vacation ......................................... $ 4,171 $ 3,666 $ 3,363
Postemployment medical and life insurance benefits........ --- --- 3,235
Provision for rate refund................................. --- 1,025 375
Uncollectible accounts.................................... 1,748 1,782 1,218
Capitalization of indirect costs.......................... 2,583 2,583 2,583
Provision for Worker's Compensation claims................ 1,207 1,568 ---
Other..................................................... 358 135 1,303
- ----------------------------------------------------------------------------------------------------
Accumulated deferred tax assets....................... $ 10,067 $ 10,759 $ 12,077
====================================================================================================
Deferred Tax Liabilities:
Accelerated depreciation and other property-related
differences............................................... $469,949 $460,332 $455,943
Allowance for funds used during construction.............. 46,429 49,572 53,317
Income taxes recoverable through future rates............. 49,466 54,023 58,470
- ----------------------------------------------------------------------------------------------------
Total................................................. 565,844 563,927 567,730
- ----------------------------------------------------------------------------------------------------
Deferred Tax Assets:
Deferred investment tax credits........................... (25,372) (27,120) (28,868)
Income taxes refundable through future rates.............. (32,296) (37,795) (40,186)
Postemployment medical and life insurance benefits........ (2,301) (2,347) ---
Company pension plan...................................... (16,465) (11,612) (6,417)
Other..................................................... (1,394) 25 4,797
- ----------------------------------------------------------------------------------------------------
Total................................................. (77,828) (78,849) (70,674)
- ----------------------------------------------------------------------------------------------------
Accumulated Deferred Income Tax Liabilities.................... $488,016 $485,078 $497,056
====================================================================================================
46
3. COMMON STOCK AND RETAINED EARNINGS
There were no new shares of common stock issued during 1996, 1995 or 1994.
The $271,000 and $115,000 increase in 1996 and 1995, respectively and $37,000
decrease in 1994 in premium on capital stock, as presented on the Consolidated
Statements of Capitalization, represents the gains and losses associated with
the issuance of common stock pursuant to the Restricted Stock Plan, and
repurchased preferred stock.
RESTRICTED STOCK PLAN
The Company has a Restricted Stock Plan whereby certain employees may
periodically receive shares of the Company's common stock at the discretion of
the Board of Directors. The Company distributed 16,024, 18,872 and 18,950 shares
of common stock during 1996, 1995 and 1994, respectively. The Company also
reacquired 10,538 and 11,040 shares in 1996 and 1994, respectively. The shares
distributed/reacquired in the reported periods were recorded as treasury stock.
Changes in common stock were:
(thousands) 1996 1995 1994
- ------------------------------------------------------------------------------------------
Shares outstanding January 1............................... 40,373 40,354 40,346
Issued/reacquired under the Restricted Stock Plan, net..... 6 19 8
- ------------------------------------------------------------------------------------------
Shares outstanding December 31............................. 40,379 40,373 40,354
==========================================================================================
There were 5,250,000 shares of unissued common stock reserved for the
various employee and Company stock plans at December 31, 1996. With the
exception of the Restricted Stock Plan, the common stock requirements, pursuant
to those plans, are currently being satisfied with stock purchased on the open
market.
OG&E's Restated Certificate of Incorporation and its Trust Indenture, as
supplemented, relating to the First Mortgage Bonds, contain 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 the Company, as
common shareowner.
In December 1991, holders of OG&E's First Mortgage Bonds approved a series
of amendments to OG&E'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 common stock, when appropriate, in order to maintain desired
capitalization ratios and to achieve other business needs. OG&E incurred $14
million relating to obtaining such amendments and began amortizing these costs
over the remaining life of the respective bond issues. In November 1995, OG&E
redeemed $220 million principal amount of outstanding First Mortgage Bonds and
expensed approximately $3 million of the costs incurred in obtaining the
amendments. At the end of 1996, there was approximately $5.7 million in
unamortized costs associated with obtaining these amendments.
SHAREOWNERS RIGHTS PLAN
In December 1990, OG&E adopted a Shareowners Rights Plan designed to
protect shareowners' interests in the event that OG&E was ever confronted with
an unfair or inadequate acquisition proposal. In
47
connection with the corporate restructuring, the Company adopted a substantially
identical Shareowners Rights Plan in August 1995. Pursuant to the plan, the
Company declared a dividend distribution of one "right" for each share of
Company common stock. Each right entitles the holder to purchase from the
Company one one-hundredth of a share of new preferred stock of the Company under
certain circumstances. The rights may be exercised if a person or group
announces its intention to acquire, or does acquire, 20 percent or more of the
Company's common stock. Under certain circumstances, the holders of the rights
will be entitled to purchase either shares of common stock of the Company or
common stock of the acquirer at a reduced percentage of market value. The rights
are scheduled to expire on December 11, 2000.
4. CUMULATIVE PREFERRED STOCK OF SUBSIDIARY
Preferred stock of OG&E 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.
OG&E's Restated Certificate of Incorporation permits the issuance of new
series of preferred stock with dividends payable other than quarterly.
5. LONG-TERM DEBT
OG&E's Trust Indenture, as supplemented, relating to the First Mortgage
Bonds, requires OG&E to pay to the trustee annually, an amount sufficient to
redeem, for sinking fund purposes, 1 1/4 percent of the highest amount
outstanding at any time. This requirement has been satisfied by pledging
permanent additions to property to the extent of 166 2/3 percent of principal
amounts of bonds otherwise required to be redeemed. Through December 31, 1996,
gross property additions pledged totaled approximately $382 million.
Annual sinking fund requirements for each of the five years subsequent to
December 31, 1996, are as follows:
Year Amount
===================================================
1997.................................. $ 13,302,083
1998.................................. $ 12,781,249
1999.................................. $ 12,520,833
2000.................................. $ 10,229,166
2001.................................. $ 10,229,166
===================================================
As in prior years, OG&E expects to meet these requirements by pledging
permanent additions to property.
In April 1996, OG&E filed a registration statement for the sale of up to
$300 million of senior notes. In February 1997, OG&E reduced the amount of the
registration statement for senior notes to $250 million and filed a new
registration statement for up to $50 million of grantor trust preferred
48
securities. Assuming favorable market conditions, OG&E may issue all or part of
these securities to refinance, at lower rates, one or more series of outstanding
first mortgage bonds or preferred stock.
As of December 31, 1996, Enogex long-term debt consisted of $120 million of
medium-term notes at a composite rate of 6.89%. The following table itemizes the
Enogex long-term debt at December 31, 1996, 1995 and 1994:
December 31 (DOLLARS IN THOUSANDS) 1996 1995 1994
- --------------------------------------------------------------------------------
Series Due August 7, 2000 -- 6.76% - 6.77%.... $ 27,000 $ 27,000 $ ---
Series Due August 31, 2000 -- 6.68%........... 20,000 20,000 ---
Series Due September 1, 2000 -- 6.70%......... 10,000 10,000 ---
Variable Rate Note Due July 31, 2001.......... --- --- 6,900
Series Due August 7, 2002 -- 7.02% - 7.05%.... 63,000 63,000 ---
- --------------------------------------------------------------------------------
Total.................................... $120,000 $120,000 $ 6,900
================================================================================
Maturities of long-term debt during the next five years consist of $15
million in 1997, $25 million in 1998, $12.5 million in 1999 and $167 million in
2000.
Unamortized debt expense and unamortized premium and discount on long-term
debt are being amortized over the life of the respective debt.
Substantially all electric plant was subject to lien of the Trust Indenture
at December 31, 1996.
6. SHORT-TERM DEBT
The Company borrows on a short-term basis, as necessary, by the issuance of
commercial paper and by obtaining short-term bank loans. The maximum and average
amounts of short-term borrowings during 1996 were $142.1 million and $72.4
million, respectively, at a weighted average interest rate of 5.63%. The
weighted average interest rates for 1995 and 1994 were 6.39% and 4.76%,
respectively. OG&E has an agreement for a flexible line of credit, up to $160
million, through December 6, 2000. The line of credit is maintained on a
variable fee basis on the unused balance. Short-term debt in the amount of $41.4
million was outstanding at December 31, 1996.
7. POSTEMPLOYMENT BENEFIT PLANS
During 1994, the Company restructured its operations, reducing its
workforce by approximately 24 percent. This was accomplished through a Voluntary
Early Retirement Package ("VERP") and an enhanced severance package. The VERP
included enhanced pension benefits as well as postemployment medical and life
insurance benefits.
As a result of the postemployment benefits provided in connection with this
workforce reduction, the Company incurred severance costs and certain one-time
costs computed in accordance with SFAS No. 88, "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits" and SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." In response to an application
filed by the Company, the OCC directed the Company to defer the one-time costs
which had not been offset by labor savings through December 31, 1994. The
remaining
49
balance of the one-time costs is being amortized over 26 months, commencing
January 1, 1995. The components of the severance and VERP costs and the amount
deferred are as follows:
SFAS SFAS
(DOLLARS IN THOUSANDS) No. 88 No. 106 Severance Total
- --------------------------------------------------------------------------------------------
Curtailment Loss............................... $ 1,042 $ 5,457 $ --- $ 6,499
Recognition of Transition Obligation........... --- 17,268 --- 17,268
Special Retirement Benefits.................... 28,198 6,566 --- 34,764
Enhanced Severance............................. --- --- 4,891 4,891
- --------------------------------------------------------------------------------------------
Total VERP and Severance Costs................. $29,240 $29,291 $ 4,891 63,422
- --------------------------------------------------------------------------------------------
Deferred as a Regulatory Asset at December 31, 1994............................. (48,903)
- --------------------------------------------------------------------------------------------
Postemployment Costs Recognized as Restructuring in 1994........................ 14,519
Consulting Fees................................................................. 2,750
Other........................................................................... 3,766
- --------------------------------------------------------------------------------------------
1994 Restructuring Expenses..................................................... $21,035
============================================================================================
The restructuring charges reflected above, include only costs that were
actually incurred in 1994. In 1995 and 1996, amortization of the deferred
regulatory asset was $22.6 million each year.
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 in Other operation.
In determining the projected benefit obligation, the weighted average
discount rates used were 7.75, 7.25 and 8.25 percent for 1996, 1995 and 1994,
respectively. The assumed rate of increase in future salary levels was 4.5
percent in 1996, 1995 and 1994. The expected long-term rate of return on plan
assets used in determining net periodic pension cost was 9 percent for the
reported periods.
The plan's assets consist primarily of U. S. Government securities, listed
common stocks and corporate debt.
50
Net periodic pension costs for 1996, 1995 and 1994 included the following:
(DOLLARS IN THOUSANDS) 1996 1995 1994
- -------------------------------------------------------------------------------------------
Service costs.......................................... $ 6,493 $ 4,714 $ 7,824
Interest cost on projected benefit obligation.......... 20,909 20,392 17,851
Return on plan assets ................................. (18,742) (15,036) (17,510)
Net amortization and deferral.......................... (1,263) (1,263) (1,263)
Amortization of unrecognized prior service cost........ 2,939 2,634 1,489
- -------------------------------------------------------------------------------------------
Net periodic pension costs............................. $10,336 $11,441 $ 8,391
===========================================================================================
The following table sets forth the plan's funded status at December 31,
1996, 1995 and 1994:
(DOLLARS IN THOUSANDS) 1996 1995 1994
- -----------------------------------------------------------------------------------------------------
Projected benefit obligation:
Vested benefits....................................... $(223,116) $(232,457) $(208,438)
Nonvested benefits.................................... (17,599) (18,263) (14,664)
- -----------------------------------------------------------------------------------------------------
Accumulated benefit obligation........................ (240,715) (250,720) (223,102)
Effect of future compensation levels.................. (44,258) (44,853) (29,425)
- -----------------------------------------------------------------------------------------------------
Projected benefit obligation............................... (284,973) (295,573) (252,527)
Plan's assets at fair value................................ 222,912 214,986 177,045
- -----------------------------------------------------------------------------------------------------
Plan's assets less than projected benefit obligation....... (62,061) (80,587) (75,482)
Unrecognized prior service cost............................ 42,986 40,616 43,250
Unrecognized net asset from application of SFAS No. 87..... (6,316) (7,580) (8,842)
Unrecognized net (gain) loss............................... (15,254) 9,489 (900)
- -----------------------------------------------------------------------------------------------------
Accrued pension liability.................................. $ (40,645) $ (38,062) $ (41,974)
=====================================================================================================
POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
In addition to providing pension benefits, the Company provides certain
medical and life insurance benefits for retired members ("postretirement
benefits"). Employees retiring from the Company on or after attaining age 55 who
have met certain length of service requirements are entitled to these benefits.
The benefits are subject to deductibles, co-payment provisions and other
limitations.
During 1993, OG&E expensed pay-as-you-go postretirement benefits and
recorded a deferral for the difference between pay-as-you-go and SFAS No. 106
requirements. The February 25, 1994, OCC rate order directed OG&E to recover
postretirement benefit costs following the pay-as-you-go method and to defer the
incremental cost associated with accrual recognition of SFAS No. 106 related
costs following a "phase-in" plan. Accordingly, OG&E recorded a regulatory asset
for the difference between the amounts using the pay-as-you-go method (adjusted
for the phase-in plan) and those required by SFAS No. 106.
51
A decision was made in the second quarter of 1994 to discontinue deferral
of the differential and to charge to expense $8.4 million of postretirement
benefits that had been recorded as a regulatory asset. Although OG&E continues
to believe that it could have recovered these costs in future rate proceedings
before the OCC, OG&E decided to recognize these expenses currently, due to its
strategy to reduce its cost-structure, which minimizes future revenue
requirements. OG&E expects to continue charging to expense the SFAS No. 106
costs and to include an annual amount as a component of cost-of-service in
future ratemaking proceedings. Net postretirement benefit expense for 1996, 1995
and 1994 included the following components:
(DOLLARS IN THOUSANDS) 1996 1995 1994
======================================================================================
Service cost...................................... $ 2,317 $ 1,932 $ 2,714
Interest cost..................................... 6,824 7,242 5,978
Return on plan assets............................. (3,263) (576) ---
Net amortization.................................. 3,844 3,325 3,549
Net amount capitalized or deferred................ (2,157) (2,399) (4,557)
Discontinued deferral of regulatory asset......... --- --- 8,359
- --------------------------------------------------------------------------------------
Net postretirement benefit expense............ $ 7,565 $ 9,524 $16,043
======================================================================================
The discount rates used in determining the accumulated postretirement
benefit obligation were 7.75, 7.25 and 8.25 percent for December 31, 1996, 1995
and 1994, respectively. The rate of increase in future compensation levels used
in measuring the life insurance accumulated postretirement benefit obligation
was 4.5 percent for December 31, 1996, 1995 and 1994. A 9 percent annual rate of
increase in the per capita cost of covered health care benefits was assumed for
1996; the rate is assumed to decrease gradually to 4.5 percent by the year 2006
and remain at that level thereafter. A one-percentage-point increase in the
assumed health care cost trend rates would increase the accumulated
postretirement benefit obligation as of December 31, 1996, by approximately $9.1
million, and the aggregate of the service and interest cost components of net
postretirement health care cost for 1996 by approximately $1.1 million.
52
The following table sets forth the funded status of the postretirement
benefits and amounts recognized in the Company's Consolidated Balance Sheets as
of December 31, 1996, 1995 and 1994:
(DOLLARS IN THOUSANDS) 1996 1995 1994
==========================================================================================
Accumulated postretirement benefit obligation:
Retirees.................................... $(78,856) $(88,500) $(81,688)
Actives eligible to retire.................. (3,863) (2,420) (2,716)
Actives not yet eligible to retire.......... (11,553) (11,869) (7,870)
- ------------------------------------------------------------------------------------------
Total................................... (94,272) (102,789) (92,274)
Plan assets at fair value........................ 39,066 23,864 17,279
- ------------------------------------------------------------------------------------------
Funded status ................................... (55,206) (78,925) (74,995)
Unrecognized transition obligation............... 43,985 46,734 49,483
Unrecognized net actuarial (gain) loss .......... (7,937) 4,331 (2,930)
- ------------------------------------------------------------------------------------------
Accrued postretirement benefit obligation........ $(19,158) $(27,860) $(28,442)
==========================================================================================
53
8. REPORT OF BUSINESS SEGMENTS
The Company's electric utility operations are conducted through OG&E, an
operating public utility engaged in the generation, transmission, distribution,
and sale of electric energy. The non-utility operations are conducted through
Enogex, which is engaged in the gathering and transmission of natural gas, and
through its subsidiaries, is engaged in the processing of natural gas and the
marketing of natural gas liquids, in the buying and selling of natural gas to
third parties, and in the exploration for and production of natural gas and
related products.
(DOLLARS IN THOUSANDS) 1996 1995 1994
==============================================================================================
Operating Information:
Operating Revenues
Electric utility............................ $1,200,337 $1,168,287 $1,196,898
Non-utility subsidiary...................... 231,427 178,082 203,079
Intersegment revenues (A)................... (44,329) (44,332) (44,809)
- ----------------------------------------------------------------------------------------------
Total................................... $1,387,435 $1,302,037 $1,355,168
==============================================================================================
Pre-tax Operating Income
Electric utility............................ $ 247,527 $ 246,333 $ 248,827
Non-utility subsidiary...................... 31,919 24,631 23,710
- ----------------------------------------------------------------------------------------------
Total................................... $ 279,446 $ 270,964 $ 272,537
==============================================================================================
Net Income
Electric utility............................ $ 116,869 $ 112,545 $ 113,795
Non-utility subsidiary...................... 16,463 12,711 9,990
- ----------------------------------------------------------------------------------------------
Total................................... $ 133,332 $ 125,256 $ 123,785
==============================================================================================
Investment Information:
Identifiable Assets as of December 31
Electric utility (B)........................ $2,388,012 $2,422,609 $2,471,902
Non-utility subsidiary...................... 374,343 332,262 310,727
- ----------------------------------------------------------------------------------------------
Total................................... $2,762,355 $2,754,871 $2,782,629
==============================================================================================
Other Information:
Depreciation
Electric utility............................ $ 112,232 $ 110,719 $ 107,239
Non-utility subsidiary...................... 23,908 21,416 19,138
- ----------------------------------------------------------------------------------------------
Total................................... $ 136,140 $ 132,135 $ 126,377
==============================================================================================
Construction Expenditures
Electric utility............................ $ 94,019 $ 110,276 $ 104,256
Non-utility subsidiary...................... 56,155 43,242 32,084
- ----------------------------------------------------------------------------------------------
Total................................... $ 150,174 $ 153,518 $ 136,340
==============================================================================================
(A) Intersegment revenues are recorded at prices comparable to those of
unaffiliated customers and are affected by regulatory considerations.
(B) Includes OGE Energy Corp. start-up costs of $1,299,528 at December 31,1996.
54
9. COMMITMENTS AND CONTINGENCIES
OG&E has entered into purchase commitments in connection with OG&E's
construction program and the purchase of necessary fuel supplies of coal and
natural gas for OG&E's generating units. The Company's construction expenditures
for 1997 are estimated at $203 million.
OG&E acquires natural gas for boiler fuel under 265 individual contracts,
some of which contain provisions allowing the owners to require prepayments for
gas if certain minimum quantities are not taken. At December 31, 1996, 1995 and
1994, outstanding prepayments for gas, including the amounts classified as
current assets, under these contracts were approximately $9,936,000, $7,402,000,
and $10,879,000, respectively. OG&E may be required to make additional
prepayments in subsequent years. OG&E expects to recover these prepayments as
fuel costs if unable to take the gas prior to the expiration of the contracts.
At December 31, 1996, OG&E held non-cancelable operating leases covering
1,495 coal hopper railcars. Rental payments are charged to fuel expense and
recovered through OG&E's tariffs and automatic fuel adjustment clauses. The
leases have purchase and renewal options. Future minimum lease payments due
under the railcar leases, assuming the leases are renewed under the renewal
option are as follows:
(DOLLARS IN THOUSANDS)
1997..................... $5,280 2000.................... $ 5,010
1998..................... 5,199 2001.................... 4,915
1999..................... 5,105 2002 and beyond......... 58,781
---------
Total Minimum Lease Payments................................ $ 84,290
=========
Rental payments under operating leases were approximately $5.4 million in
1996, $6.5 million in 1995, and $5.6 million in 1994.
OG&E is required to maintain the railcars it has under lease to transport
coal from Wyoming and has entered into an agreement with Railcar Maintenance
Company, a non-affiliated company, to furnish this maintenance.
OG&E had entered into an agreement with an unrelated third-party to develop
a natural gas storage facility. Operation of the gas storage facility proved
beneficial by allowing OG&E to lower fuel costs by base loading coal generation,
a less costly fuel supply. During 1996, OG&E completed negotiations and
contracted with the third-party developer for gas storage service. Pursuant to
the contract, the third-party developer reimbursed OG&E for all outstanding cash
advances and interest amounting to approximately $46.8 million. OG&E also
entered into a bridge financing agreement as guarantor for the third-party.
Permanent financing by the third-party, which should occur around mid 1997, will
replace the bridge finance agreement with OG&E as guarantor.
OG&E has entered into agreements with four qualifying cogeneration
facilities having initial terms of 3 to 32 years. These contracts were entered
into pursuant to the Public Utility Regulatory Policy Act of 1978 ("PURPA").
Stated generally, PURPA and the regulations thereunder promulgated by FERC
require OG&E to purchase power generated in a manufacturing process from a
qualified cogeneration facility ("QF"). The rate for such power to be paid by
OG&E was approved by the OCC. The rate generally consists of two components: one
is a rate for actual electricity purchased from the QF by OG&E; the other is a
capacity charge which OG&E must pay the QF for having the capacity available.
However, if no
55
electrical power is made available to OG&E for a period of time (generally three
months), OG&E's obligation to pay the capacity charge is suspended. The total
cost of cogeneration payments is currently recoverable in rates from Oklahoma
customers.
During 1996, 1995, and 1994, OG&E made total payments to cogenerators of
approximately $210.0 million, $210.4 million, and $210.3 million, of which
$175.2 million, $174.1 million, and $173.2 million, respectively, represented
capacity payments. All payments for purchased power, including cogeneration, are
included in the Consolidated Statements of Income as purchased power. The future
minimum capacity payments under the contracts for the next five years are
approximately: 1997 - $176 million, 1998 - $187 million, 1999 - $189 million,
2000 - $190 million and 2001 - $192 million.
Approximately $400,000 of the Company's construction expenditures budgeted
for 1997 are to comply with environmental laws and regulations.
The Company's management believes all of its operations are in substantial
compliance with present federal, state and local environmental standards. It is
estimated that the Company's total expenditures for capital, operating,
maintenance and other costs to preserve and enhance environmental quality will
be approximately $40 million during 1997, compared to approximately $43 million
in 1996. The Company continues to evaluate its environmental management systems
to ensure compliance with existing and proposed environmental legislation and
regulations and to better position itself in a competitive market.
OG&E has contracted for low-sulfur coal to comply with the sulfur dioxide
limitations of the Clean Air Act Amendments of 1990 ("CAAA"). OG&E also has
completed installation and certification of all required continuous emissions
monitors at each of its generating units. Phase II sulfur dioxide emission
requirements will affect OG&E beginning in the year 2000. OG&E believes it can
meet these sulfur dioxide limits without additional capital expenditures. With
respect to nitrogen oxide limits, OG&E is meeting the current emission standards
and has exercised its option to extend the effective date of the further
reductions from 2000 to 2008.
OG&E is a party to three separate actions brought by the EPA concerning
cleanup of disposal sites for hazardous waste. OG&E was not the owner or
operator of those sites. Rather OG&E along with many others, shipped materials
to the owners or operators of the sites who failed to dispose of the materials
in an appropriate manner. Remediation at two of these sites has been completed.
OG&E's total waste disposed at the remaining site is minimal and on February 15,
1996, OG&E elected to participate in the de minimis settlement offered by EPA,
which limited OG&E's financial obligation to less than $50,000. One of the other
potentially responsible parties is currently contesting OG&E's participation as
a de minimis party. Regardless of the outcome of this issue, OG&E believes its
ultimate liability for this site is minimal.
In the normal course of business, other lawsuits, claims, environmental
actions and other governmental proceedings arise against the Company and its
subsidiaries. Management, after consultation with legal counsel, does not
anticipate that liabilities arising out of other currently pending or threatened
lawsuits and claims will have a material adverse effect on the Company's
consolidated financial position or results of operations.
56
10. RATE MATTERS AND REGULATION
On February 11, 1997, the OCC issued an order that, among other things,
effectively lowered OG&E's rates to its Oklahoma retail customers by $50 million
annually (based on a test year ended December 31, 1995). The OCC order also
directed OG&E to transition to competitive bidding of its gas transportation
requirements currently met by Enogex no later than April 30, 2000. The order
also set annual compensation for the transportation services provided by Enogex
at $41.3 million until competitively-bid gas transportation begins.
As discussed in Note 7 of Notes to Consolidated Financial Statements,
during the third quarter of 1994, the Company incurred $63.4 million of costs
related to the VERP and enhanced severance package. Pending an OCC order, OG&E
deferred these costs; however, between August 1, and December 31, 1994, the
amount deferred was reduced by approximately $14.5 million. In response to an
application filed by OG&E on August 9, 1994, the OCC issued an order on October
26, 1994, that permitted the Company to amortize the December 31, 1994,
regulatory asset of $48.9 million over 26 months and reduced OG&E's electric
rates during such period by approximately $15 million annually, effective
January 1995. The labor savings from the VERP and severance package
substantially offset the amortization of the regulatory asset and annual rate
reduction of $15 million.
On February 25, 1994, the OCC issued an order that, among other things,
effectively lowered 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 lowered OG&E's rates to its Oklahoma customers by
approximately $17 million annually. With respect to the $41.3 million refund,
the entire amount relates to the disallowance of a portion of the fees paid by
OG&E to Enogex for transportation services of which $39.1 million was associated
with revenues prior to January 1, 1994, while the remaining $2.2 million related
to 1994.
On June 18, 1996, the APSC staff and OG&E filed a Joint Stipulation
recommending settlement of certain issues resulting from the APSC review of the
amounts that OG&E pays Enogex and recovers through its fuel clause for
transporting natural gas to OG&E's gas-fired generating stations. On July 11,
1996, the APSC issued an order that, among other things, required OG&E to refund
approximately $4.5 million in 1996 to its Arkansas retail electric customers.
The $4.5 million refund related to the disallowance of a portion of the fees
paid by OG&E to Enogex for such transportation services and was recorded as a
provision for a potential refund prior to August 1996.
57
The components of Deferred Charges - Other, on the Consolidated Balance
Sheets included the following, as of December 31:
(DOLLARS IN THOUSANDS) 1996 1995 1994
- --------------------------------------------------------------------------------
Regulatory asset (restructuring)........... $ 3,759 $ 26,331 $ 48,903
Unamortized debt expense................... 10,291 10,919 12,871
Enogex gas sales contracts................. 15,075 11,294 12,690
Unamortized loss on reacquired debt........ 10,253 11,197 5,487
Insurance Claims - Property Damage......... 6,231 --- ---
Miscellaneous.............................. 11,935 10,452 12,391
- --------------------------------------------------------------------------------
Total............................. $ 57,544 $ 70,193 $ 92,342
================================================================================
Regulatory Assets and Liabilities consisted of the following as of December 31:
(DOLLARS IN THOUSANDS) 1996 1995 1994
- ----------------------------------------------------------------------------------
Regulatory Assets:
Income Taxes Recoverable from Customers.... $127,819 $139,594 $151,086
Workforce Reduction (Restructuring)........ 3,759 26,331 48,903
Miscellaneous.............................. 435 455 2,214
- ----------------------------------------------------------------------------------
Total Regulatory Assets................. 132,013 166,380 202,203
Regulatory Liabilities:
Income Taxes Refundable to Customers....... (83,451) (97,660) (103,840)
Gain on Disposition of Allowances.......... (329) (282) (187)
- ----------------------------------------------------------------------------------
Net Regulatory Assets........................ $ 48,233 $ 68,438 $ 98,176
==================================================================================
While the Company does not expect to cease meeting the criteria for
application of SFAS No. 71 in the foreseeable future, if the Company were
required to discontinue the application of SFAS No. 71 for some or all of its
operations, it would result in writing off the related regulatory assets; the
financial effects of which could be significant.
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.
58
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:
1996 1995 1994
--------------------- --------------------- ---------------------
Carrying Fair Value Carrying Fair Value Carrying Fair Value
(DOLLARS IN THOUSANDS) Amount Amount Amount
================================================================================================================
ASSETS:
CASH AND CASH EQUIVALENTS......... $ 2,523 $ 2,523 $ 5,420 $ 5,420 $ 2,455 $ 2,455
================================================================================================================
LIABILITIES:
CUSTOMER DEPOSITS................. $ 23,257 $ 23,257 $ 21,920 $ 21,920 $ 20,904 $ 20,904
================================================================================================================
CAPITALIZATION:
First Mortgage Bonds.............. $644,881 $656,362 $644,462 $671,356 $716,967 $710,523
Industrial Authority Bonds........ 79,400 79,400 79,400 79,400 32,050 32,044
Enogex Inc. Notes................. 120,000 120,379 120,000 124,853 6,900 6,900
Preferred Stock:
4% - 5.34% Series -- 831,363,
836,963 and 838,663 Shares..... 49,379 35,829 49,939 35,541 49,973 27,442
- ----------------------------------------------------------------------------------------------------------------
TOTAL CAPITALIZATION.............. $893,660 $891,970 $893,801 $911,150 $805,890 $776,909
================================================================================================================
59
Report of Independent Public Accountants
- ----------------------------------------
TO THE SHAREOWNERS OF
OGE ENERGY CORP.:
We have audited the accompanying consolidated balance sheets and statements
of capitalization of OGE Energy Corp. (an Oklahoma corporation), formerly
Oklahoma Gas & Electric Company, and its subsidiaries as of December 31, 1996,
1995 and 1994, and the related consolidated statements of income, retained
earnings and cash flows for the years then ended. These financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of OGE Energy Corp. and its
subsidiaries as of December 31, 1996, 1995 and 1994, and the results of their
operations and their cash flows for the years then ended in conformity with
generally accepted accounting principles.
/s/ Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 23, 1997
60
Report of Management
- --------------------
TO OUR SHAREOWNERS:
The management of OGE Energy Corp. and its subsidiaries has prepared, and
is responsible for the integrity and objectivity of the financial and operating
information contained in this Annual Report. The consolidated financial
statements have been prepared in accordance with generally accepted accounting
principles and include certain amounts that are based on the best estimates and
judgments of management.
To meet its responsibility for the reliability of the consolidated
financial statements and related financial data, the Company's management has
established and maintains an internal control structure. This structure provides
management with reasonable assurance in a cost-effective manner that, among
other things, assets are properly safeguarded and transactions are executed and
recorded in accordance with its authorizations so as to permit preparation of
financial statements in accordance with generally accepted accounting
principles. The Company's internal auditors assess the effectiveness of this
internal control structure and recommend possible improvements thereto on an
ongoing basis.
The Company maintains high standards in selecting, training and developing
its members. This, combined with Company policies and procedures, provides
reasonable assurance that operations are conducted in conformity with applicable
laws and with its commitment to the highest standards of business conduct.
61
Supplementary Data
- ------------------
Interim Consolidated Financial Information (Unaudited)
In the opinion of the Company, the following quarterly information includes
all adjustments, consisting of normal recurring adjustments, necessary for a
fair statement of the results of operations for such periods:
Quarter ended (DOLLARS IN THOUSANDS EXCEPT Dec 31 Sep 30 Jun 30 Mar 31
PER SHARE DATA)
- -------------------------------------------------------------------------------------------------------------
Operating revenues............................. 1996 $ 311,515 $ 449,224 $ 348,644 $ 278,052
1995 283,898 467,510 304,113 246,516
1994 281,388 443,173 346,623 283,984
- -------------------------------------------------------------------------------------------------------------
Operating income............................... 1996 $ 23,227 $ 107,152 $ 53,623 $ 17,217
1995 24,948 115,991 42,800 18,408
1994 23,792 105,563 50,427 20,684
- -------------------------------------------------------------------------------------------------------------
Net income (loss).............................. 1996 $ 7,301 $ 90,165 $ 35,328 $ 538
1995 4,890 96,969 24,258 (861)
1994 4,952 86,251 31,082 1,500
- -------------------------------------------------------------------------------------------------------------
Earnings (loss) available for common........... 1996 $ 6,729 $ 89,593 $ 34,749 $ (41)
1995 4,311 96,390 23,679 (1,440)
1994 4,372 85,672 30,503 921
- -------------------------------------------------------------------------------------------------------------
Earnings (loss) per average common share....... 1996 $ 0.17 $ 2.22 $ 0.86 $ 0.00
1995 0.11 2.39 0.59 (0.04)
1994 0.11 2.12 0.76 0.02
- -------------------------------------------------------------------------------------------------------------
62
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
- --------------------------------------------------------------------
AND FINANCIAL DISCLOSURE.
-------------------------
Not Applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
- ------------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION.
- --------------------------------
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
- -------------------------------------------------
OWNERS AND MANAGEMENT.
----------------------
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
- --------------------------------------------------------
Items 10, 11, 12 and 13 are omitted pursuant to General Instruction G of
Form 10-K, since the Company filed copies of a definitive proxy statement with
the Securities and Exchange Commission on or about March 28, 1997. Such proxy
statement is incorporated herein by reference. In accordance with Instruction G
of Form 10-K, the information required by Item 10 relating to Executive Officers
has been included in Part I, Item 4, of this Form 10-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
- ----------------------------------------------------
REPORTS ON FORM 8-K.
--------------------
(A) 1. FINANCIAL STATEMENTS
- ---------------------------
The following consolidated financial statements and supplementary data are
included in Part II, Item 8 of this Report:
o Consolidated Balance Sheets at December 31, 1996, 1995 and 1994
o Consolidated Statements of Income for the years ended December 31, 1996,
1995 and 1994
o Consolidated Statements of Retained Earnings for the years ended December
31, 1996, 1995 and 1994
o Consolidated Statements of Capitalization at December 31, 1996, 1995 and
1994
o Consolidated Statements of Cash Flows for the years ended December 31,
1996, 1995 and 1994
o Notes to Consolidated Financial Statements
o Report of Independent Public Accountants
o Report of Management
63
SUPPLEMENTARY DATA
------------------
Interim Consolidated Financial Information
2. FINANCIAL STATEMENT SCHEDULE (INCLUDED IN PART IV) PAGE
- ----------------------------------------------------- ----
Schedule II - Valuation and Qualifying Accounts 72
Report of Independent Public Accountants 73
Financial Data Schedule 180
All other schedules have been omitted since the required information is not
applicable or is not material, or because the information required is included
in the respective financial statements or notes thereto.
3. EXHIBITS
- ------------
EXHIBIT NO. DESCRIPTION
- ----------- -----------
3.01 Copy of Restated Certificate of Incorporation.
3.02 By-laws.
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)
64
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)
65
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)
66
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 OG&E'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 OG&E'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 OG&E's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
67
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 OG&E'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
OG&E's Form 10-K Report for the year ended
December 31, 1991, File No. 1-1097, and incorporated
by reference herein)
4.30 Copy of Supplemental Trust Indenture dated
October 1, 1995, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to
OG&E's Form 8-K Report dated October 23, 1995,
File No. 1-1097, and incorporated by reference herein)
4.31 Copy of Supplemental Trust Indenture dated
October 1, 1995, from OG&E to
Boatmen's First National Bank of Oklahoma, Trustee.
(Filed as Exhibit 4.29 to Registration Statement No. 33-61821
and incorporated by reference herein)
4.32 Copy of Supplemental Trust Indenture No. 1 dated
October 16, 1995, being a supplemental instrument
to Exhibit 4.31 hereto. (Filed as Exhibit 4.01 to
OG&E's Form 8-K Report dated October 23, 1995,
File No. 1-1097, and incorporated by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between
OG&E and Atlantic Richfield Company. (Filed as
Exhibit 5.19 to Registration Statement No. 2-59887
and incorporated by reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between OG&E
and Atlantic Richfield Company, together with
related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply
Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company.
(Filed as Exhibit 5.28 to Registration Statement
No. 2-62208 and incorporated by reference herein)
68
10.04 Amendment dated June 27, 1990, between OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between OG&E and Atlantic
Richfield Company. (Filed as Exhibit 10.04 to
OG&E's Form 10-K Report for the year ended
December 31, 1994, File No. 1-1097, and incorporated
by reference herein) [Confidential Treatment has been
requested for certain portions of this exhibit.]
10.05 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 OG&E'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 OG&E's Form 10-Q
for June 30, 1981, File No. 1-1097, and incorporated
by reference herein)
10.07 Form of Change of Control Agreement for Officers of the
Company and OG&E.
10.08 Amended and Restated Stock Equivalent and
Deferred Compensation Plan for Directors,
as amended.
10.09 Amended and Restated Restricted Stock Plan of the Company
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)
69
10.11 Gas Service Agreement dated January 1, 1988, between
OG&E and Oklahoma Natural Gas Company. (Filed as
Exhibit 10.26 to OG&E's Form 10-K Report
for the year ended December 31, 1987, File No. 1-1097,
and incorporated by reference herein)
10.12 OG&E's Restoration of Retirement Income Plan, as amended.
10.13 Company's Restoration of Retirement Savings Plan, as amended.
10.14 Gas Service Agreement dated July 23, 1987, between
OG&E and Arkla Services Company. (Filed as Exhibit
10.29 to OG&E's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
10.15 OG&E's Supplemental Executive Retirement Plan, as amended.
10.16 Company's Annual Incentive Compensation Plan.
21.01 Subsidiaries of the Registrant.
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995.
99.02 Description of Common Stock.
70
Executive Compensation Plans and Arrangements
---------------------------------------------
10.07 Form of Change of Control Agreement for Officers of the Company
and OG&E.
10.08 Amended and Restated Stock Equivalent and
Deferred Compensation Plan for Directors, as amended.
10.09 Amended and Restated Restricted Stock Plan of the Company.
10.12 OG&E's Restoration of Retirement Income Plan, as amended.
10.13 Company's Restoration of Retirement Savings Plan, as amended.
10.15 OG&E's Supplemental Executive Retirement Plan, as amended.
10.16 Company's Annual Incentive Compensation Plan.
(b) REPORTS ON FORM 8-K
Item 5. Other Events, dated December 23, 1996.
71
OGE ENERGY CORP.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
BALANCE CHARGED TO CHARGED TO BALANCE
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS YEAR
----------- --------- ---------- ---------- ---------- --------
1996 (THOUSANDS)
Reserve for Uncollectible Accounts $4,205 $7,720 - $7,299 $4,626
1995
Reserve for Uncollectible Accounts $3,719 $7,673 - $7,187 $4,205
1994
Reserve for Uncollectible Accounts $4,070 $6,942 - $7,293 $3,719
72
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To OGE Energy Corp.:
We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements of OGE Energy Corp. (an Oklahoma
Corporation), formerly Oklahoma Gas & Electric Company, and its subsidiaries
included in this Form 10-K, and have issued our report thereon dated January 23,
1997. Our audits were made for the purpose of forming an opinion on those
statements taken as a whole. The schedule listed on Page 64, Item 14 (a) 2. is
the responsibility of the Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
/ s / Arthur Andersen LLP
Arthur Andersen LLP
Oklahoma City, Oklahoma,
January 23, 1997
73
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, the Registrant has duly caused this Report to be signed on its behalf
by the undersigned, thereunto duly authorized, in the City of Oklahoma City, and
State of Oklahoma on the 21st day of March, 1997.
OGE ENERGY CORP.
(REGISTRANT)
/s/ Steven E. Moore
By Steven E. Moore
Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this Report has been signed below by the following persons in the
capacities and on the dates indicated.
Signature Title Date
- --------------------- ---------------------- --------------
/ s / Steven E. Moore
Steven E. Moore Principal Executive
Officer and Director; March 21, 1997
/ s / A. M. Strecker
A. M. Strecker Principal Financial and
Accounting Officer.
March 21, 1997
Herbert H. Champlin Director;
Luke R. Corbett Director;
William E. Durrett Director;
Martha W. Griffin Director;
Hugh L. Hembree, III Director;
Robert Kelley Director;
Bill Swisher Director; and
Ronald H. White, M.D. Director.
/ s / Steven E. Moore
By Steven E. Moore (attorney-in-fact) March 21, 1997
74
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
3.01 Copy of Restated Certificate of Incorporation.
3.02 By-laws.
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)
75
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)
76
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)
77
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 OG&E'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 OG&E'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 OG&E's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
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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 OG&E'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
OG&E's Form 10-K Report for the year ended
December 31, 1991, File No. 1-1097, and incorporated
by reference herein)
4.30 Copy of Supplemental Trust Indenture dated
October 1, 1995, being a supplemental instrument
to Exhibit 4.01 hereto. (Filed as Exhibit 4.02 to
OG&E's Form 8-K Report dated October 23, 1995,
File No. 1-1097, and incorporated by reference herein)
4.31 Copy of Supplemental Trust Indenture dated
October 1, 1995, from OG&E to
Boatmen's First National Bank of Oklahoma, Trustee.
(Filed as Exhibit 4.29 to Registration Statement No. 33-61821
and incorporated by reference herein)
4.32 Copy of Supplemental Trust Indenture No. 1 dated
October 16, 1995, being a supplemental instrument
to Exhibit 4.31 hereto. (Filed as Exhibit 4.01 to
OG&E's Form 8-K Report dated October 23, 1995,
File No. 1-1097, and incorporated by reference herein)
10.01 Coal Supply Agreement dated March 1, 1973, between
OG&E and Atlantic Richfield Company. (Filed as
Exhibit 5.19 to Registration Statement No. 2-59887
and incorporated by reference herein)
10.02 Amendment dated April 1, 1976, to Coal Supply
Agreement dated March 1, 1973, between OG&E
and Atlantic Richfield Company, together with
related correspondence. (Filed as Exhibit 5.21 to
Registration Statement No. 2-59887 and
incorporated by reference herein)
10.03 Second Amendment dated March 1, 1978, to Coal Supply
Agreement dated March 1, 1973, between OG&E and
Atlantic Richfield Company.
(Filed as Exhibit 5.28 to Registration Statement
No. 2-62208 and incorporated by reference herein)
79
10.04 Amendment dated June 27, 1990, between OG&E and Thunder
Basin Coal Company, to Coal Supply Agreement
dated March 1, 1973, between OG&E and Atlantic
Richfield Company. (Filed as Exhibit 10.04 to
OG&E's Form 10-K Report for the year ended
December 31, 1994, File No. 1-1097, and incorporated
by reference herein) [Confidential Treatment has been
requested for certain portions of this exhibit.]
10.05 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 OG&E'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 OG&E's Form 10-Q
for June 30, 1981, File No. 1-1097, and incorporated
by reference herein)
10.07 Form of Change of Control Agreement for Officers of the
Company and OG&E.
10.08 Amended and Restated Stock Equivalent and
Deferred Compensation Plan for Directors,
as amended.
10.09 Amended and Restated Restricted Stock Plan of the Company
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)
80
10.11 Gas Service Agreement dated January 1, 1988, between
OG&E and Oklahoma Natural Gas Company. (Filed as
Exhibit 10.26 to OG&E's Form 10-K Report
for the year ended December 31, 1987, File No. 1-1097,
and incorporated by reference herein)
10.12 OG&E's Restoration of Retirement Income Plan, as amended.
10.13 Company's Restoration of Retirement Savings Plan, as amended.
10.14 Gas Service Agreement dated July 23, 1987, between
OG&E and Arkla Services Company. (Filed as Exhibit
10.29 to OG&E's Form 10-K Report for the year
ended December 31, 1987, File No. 1-1097, and
incorporated by reference herein)
10.15 OG&E's Supplemental Executive Retirement Plan, as amended.
10.16 Company's Annual Incentive Compensation Plan.
21.01 Subsidiaries of the Registrant.
23.01 Consent of Arthur Andersen LLP.
24.01 Power of Attorney.
27.01 Financial Data Schedule.
99.01 Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation
Reform Act of 1995.
99.02 Description of Common Stock.
81