<PAGE>
================================================================================
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2000
OR
| | TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-1097
Oklahoma Gas and Electric Company meets the conditions set forth in general
instruction H(1) (a) and (b) of Form 10-Q and is therefore filing this form with
the reduced disclosure format permitted by general instruction H (2).
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma 73-0382390
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
321 North Harvey
P. O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
405-553-3000
(Registrant's telephone number, including area code)
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
-------- --------
There were 40,378,745 Shares of Common Stock, par value $2.50 per share,
outstanding as of April 30, 2000.
================================================================================
<PAGE>
<TABLE>
<CAPTION>
OKLAHOMA GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
STATEMENTS OF OPERATIONS
(UNAUDITED)
3 MONTHS ENDED
MARCH 31
2000 1999
-------------- --------------
(THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C>
OPERATING REVENUES:........................................ $ 245,332 $ 250,144
-------------- --------------
OPERATING EXPENSES:
Fuel..................................................... 72,249 67,958
Purchased power.......................................... 60,542 59,124
Other operation and maintenance.......................... 65,253 55,109
Depreciation and amortization............................ 30,151 29,303
Taxes other than income.................................. 11,369 11,351
-------------- --------------
Total operating expenses............................... 239,564 222,845
-------------- --------------
OPERATING INCOME........................................... 5,768 27,299
-------------- --------------
OTHER INCOME (EXPENSES), net............................... (634) (527)
-------------- --------------
EARNINGS BEFORE INTEREST AND TAXES......................... 5,134 26,772
INTEREST INCOME (EXPENSES):
Interest income.......................................... 145 223
Interest on long-term debt............................... (11,259) (11,034)
Other interest charges................................... (478) (262)
-------------- --------------
Net interest income (expenses)......................... (11,592) (11,073)
-------------- --------------
EARNINGS (LOSS) BEFORE INCOME TAXES........................ (6,458) 15,699
PROVISION (BENEFIT) FOR INCOME TAXES....................... (3,232) 5,510
-------------- --------------
NET INCOME (LOSS).......................................... $ (3,226) $ 10,189
============== ==============
AVERAGE COMMON SHARES OUTSTANDING.......................... 40,379 40,379
EARNINGS (LOSS) PER AVERAGE COMMON SHARE................... $ (0.08) $ 0.25
============== ==============
DIVIDENDS DECLARED PER SHARE............................... $ 0.641 $ 0.641
<FN>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
</TABLE>
1
<PAGE>
<TABLE>
<CAPTION>
BALANCE SHEETS
(UNAUDITED)
MARCH 31 DECEMBER 31
2000 1999
------------- --------------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 270 $ 1,779
Accounts receivable - customers, less reserve of $3,419 and
$3,405, respectively........................................ 74,981 96,212
Accrued unbilled revenues..................................... 37,600 40,200
Accounts receivable - other................................... 7,442 8,074
Fuel inventories, at LIFO cost................................ 77,758 75,465
Materials and supplies, at average cost....................... 30,761 30,311
Prepayments and other......................................... 3,100 3,100
Accumulated deferred tax assets............................... 7,289 7,681
------------- --------------
Total current assets........................................ 239,201 262,822
------------- --------------
OTHER PROPERTY AND INVESTMENTS, at cost......................... 13,462 12,731
------------- --------------
PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... 3,755,667 3,747,690
Construction work in progress................................. 18,106 15,575
------------- --------------
Total property, plant and equipment......................... 3,773,773 3,763,265
Less accumulated depreciation............................. 1,828,080 1,810,898
------------- --------------
Net property, plant and equipment............................. 1,945,693 1,952,367
------------- --------------
DEFERRED CHARGES:
Advance payments for gas...................................... 11,800 11,800
Income taxes recoverable through future rates................. 39,433 39,692
Other......................................................... 41,543 41,248
------------- --------------
Total deferred charges...................................... 92,776 92,740
------------- --------------
TOTAL ASSETS.................................................... $ 2,291,132 $ 2,320,660
============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - affiliates................................. $ 62,786 $ 75,674
Accounts payable, other....................................... 45,462 36,231
Customers' deposits........................................... 22,277 22,137
Accrued taxes................................................. 10,474 19,545
Accrued interest.............................................. 15,751 14,573
Other......................................................... 36,065 20,893
------------- --------------
Total current liabilities................................... 192,815 189,053
------------- --------------
LONG-TERM DEBT.................................................. 703,079 703,045
-------------- --------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 16,721 14,886
Accumulated deferred income taxes............................. 445,404 450,028
Accumulated deferred investment tax credits................... 61,291 62,578
Other......................................................... 11,801 11,933
------------- --------------
Total deferred credits and other liabilities................ 535,217 539,425
------------- --------------
STOCKHOLDERS' EQUITY:
Common stockholders' equity................................... 512,446 512,446
Retained earnings............................................. 347,575 376,691
------------- --------------
Total stockholders' equity.................................. 860,021 889,137
------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,291,132 $ 2,320,660
============= ==============
<FN>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
</TABLE>
2
<PAGE>
<TABLE>
<CAPTION>
STATEMENTS OF
CASH FLOWS
(UNAUDITED)
3 MONTHS ENDED
MARCH 31
2000 1999
-------------- --------------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss).................................................. $ (3,226) $ 10,189
Adjustments to Reconcile Net Income (Loss) to Net Cash:
Depreciation and amortization.................................... 30,151 29,303
Deferred income taxes and investment tax credits, net............ (5,056) (6,372)
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers................................ 21,231 13,902
Accrued unbilled revenues...................................... 2,600 (100)
Fuel, materials and supplies inventories....................... (2,743) (8,261)
Accumulated deferred tax assets................................ 392 (210)
Other current assets........................................... 632 15,786
Accounts payable............................................... 36,609 (5,621)
Accrued taxes.................................................. (9,071) (8,090)
Accrued interest............................................... 1,178 372
Other current liabilities...................................... 15,312 (19,362)
Other operating activities....................................... 2,216 15,541
-------------- --------------
Net cash provided from operating activities.................. 90,225 37,077
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (25,578) (24,135)
-------------- --------------
Net cash used in investing activities........................ (25,578) (24,135)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt, net............................................... (40,266) 12,780
Cash dividends declared on common stock............................ (25,890) (25,869)
-------------- --------------
Net cash used in financing activities........................ (66,156) (13,089)
-------------- --------------
NET DECREASE IN CASH AND CASH EQUIVALENTS............................ (1,509) (147)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 1,779 312
-------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 270 $ 165
============== ==============
- --------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)............................. $ 13,590 $ 9,195
Income taxes..................................................... $ 4,900 $ 3,681
- --------------------------------------------------------------------------------------------------------------
<FN>
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 FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
</TABLE>
3
<PAGE>
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
1. The condensed financial statements included herein have been prepared by
Oklahoma Gas and Electric Company (the "Company"), without audit, pursuant
to the rules and regulations of the Securities and Exchange Commission.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted pursuant to such rules and
regulations; however, the Company believes that the disclosures are
adequate to make the information presented not misleading.
In the opinion of management, all adjustments necessary to present fairly
the financial position of the Company as of March 31, 2000, and December
31, 1999, and the results of operations and the changes in cash flows for
the periods ended March 31, 2000, and March 31, 1999, have been included
and are of a normal recurring nature. Certain amounts have been
reclassified on the financial statements to conform with the 2000
presentation.
The results of operations for such interim periods are not necessarily
indicative of the results for the full year. It is suggested that these
condensed financial statements be read in conjunction with the financial
statements and the notes thereto included in the Company's Form 10-K for
the year ended December 31, 1999.
2. The Company is a regulated public utility engaged in the generation,
transmission and distribution of electricity to retail and wholesale
customers. The Company is a wholly-owned subsidiary of OGE Energy Corp.
("Energy Corp.") which is a holding company incorporated in the State of
Oklahoma and located in Oklahoma City, Oklahoma.
3. In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting
for Derivative Instruments and for Hedging Activities", with an effective
date for periods beginning after June 15, 1999. In July 1999, the FASB
issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No. 133". As
a result of SFAS No. 137, adoption of SFAS No. 133 is now required for
financial statements for periods beginning after June 15, 2000. SFAS No.
133 sweeps in a broad population of transactions and changes the previous
accounting definition of a derivative instrument. Under SFAS No. 133, every
derivative instrument is recorded in the balance sheet as either an asset
or liability measured at its fair value. SFAS No. 133 requires that changes
in the derivative's fair value be recognized currently in earnings unless
specific hedge accounting criteria are met. The Company will prospectively
adopt this new standard effective January 1, 2001, and management believes
the adoption of this new standard will not have a material impact on its
financial position or results of operations.
4
<PAGE>
ITEM 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
OVERVIEW
The following discussion and analysis presents factors which affected the
results of operations for the three months ended March 31, 2000 (the "current
period"), and the Company's financial position as of March 31, 2000. Revenues
from sales of electricity are somewhat seasonal, with a large portion of the
Company's annual electric revenues occurring during the summer months when the
electricity needs of its customers increase. Because of seasonal fluctuations
and other factors, the results of one interim period are not necessarily
indicative of results to be expected for the year. Actions of the regulatory
commissions that set the Company's electric rates will continue to affect
financial results. Unless indicated otherwise, all comparisons are with the
corresponding periods of the prior year.
Some matters discussed in this Form 10-Q may contain forward-looking
statements that are subject to certain risks, uncertainties and assumptions.
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
other risk factors listed in the Company's Form 10-K for the year ended December
31, 1999, including Exhibit 99.01 thereto, and other factors described from time
to time in the Company's reports to the Securities and Exchange Commission.
EARNINGS
The current period net loss of $3.2 million represents a decrease of $13.4
million. As explained below, the Company's decrease in earnings was primarily
attributable to lower revenues from sales to its electric customers and higher
operating expenses. The net loss of $0.08 per average common share decreased
from earnings per average common share of $0.25 in the prior period.
REVENUES
Operating revenues decreased $4.8 million or 1.9 percent in the current
period. The decrease in electric sales was primarily attributable to lower
recoveries (approximately $4.1 million) under the Generation Efficiency
Performance Rider ("GEP Rider"), lower recoveries (approximately $0.9 million)
under the Acquisition Premium Credit Rider ("APC Rider") and milder weather in
the Company's service area. See "Regulation and Rates" - "Recent Regulatory
Matters." Kilowatt-hour sales to Company customers ("system sales") increased
4.1 percent in the current period due to growth, which partially offset the
effects of the GEP Rider, APC Rider and milder weather. Kilowatt-hour sales to
other utilities and power marketers ("off-system sales") increased
significantly, however, off-system sales are generally priced at much lower
5
<PAGE>
prices per kilowatt-hour and have less impact on operating revenues and earnings
than system sales.
EXPENSES
Total operating expenses increased $16.7 million or 7.5 percent due to
increased fuel cost and other operation and maintenance expenses.
Fuel expense increased $4.3 million or 6.3 percent in the current period.
This increase was primarily due to an increase in generation levels, resulting
from the increase in system and off-system sales and less favorable prices of
electricity for purchase. In the first quarter of 1999, there was an
availability of electricity for purchase at favorable prices, which the Company
utilized and thereby decreased its generation levels. Variances in the actual
cost of fuel used in electric generation and certain purchased power costs, as
compared to that component in cost-of-service for ratemaking, are passed through
to the Company's electric customers through automatic fuel adjustment clauses.
The automatic fuel adjustment clauses are subject to periodic review by the
Oklahoma Corporation Commission ("OCC"), the Arkansas Public Service Commission
("APSC") and the Federal Energy Regulatory Commission ("FERC"). Enogex Inc., an
affiliate of the Company, owns and operates a pipeline business that delivers
natural gas to the generating stations of the Company. The OCC, the APSC and the
FERC have authority to examine the appropriateness of any gas transportation
charges or other fees the Company pays Enogex, which the Company seeks to
recover through the fuel adjustment clause or other tariffs. See "Regulation and
Rates."
Other operation and maintenance expense increased $10.1 million or 18.4
percent, primarily due to increased labor, employee benefit costs and
miscellaneous corporate expenses.
Purchased power costs increased $1.4 million or 2.4 percent primarily due
to an increase in transmission charges associated with off-system sales.
Interest charges increased $0.4 million or 3.9 percent due to an increase
in variable rate interest and a modest increase in short-term debt.
LIQUIDITY AND CAPITAL REQUIREMENTS
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 and to some extent, for satisfying maturing debt. Capital
expenditures for the current period of $25.6 million were financed with
internally generated funds and short-term borrowings.
The Company meets its cash needs through a combination of internally
generated funds, permanent financing and short-term borrowings. The Company
expects that internally generated funds will be adequate during 2000 to meet
anticipated construction expenditures, while
6
<PAGE>
maturities of long-term debt will require permanent financings, with the amount
and type dependent on market conditions at the time. The Company has long-term
debt of $110 million maturing in October 2000, which it expects to refinance and
accordingly, this debt is reflected as non-current on the accompanying balance
sheets. Short-term borrowings will continue to be used to meet temporary cash
requirements.
The Company will continue to use short-term borrowings from Energy Corp. to
meet its temporary cash requirements. The Company has the necessary regulatory
approvals to incur up to $400 million in short-term borrowings at any one time.
In January 2000, Energy Corp. increased its line of credit from $200 million to
$300 million, with $200 million to expire on January 15, 2001, and $100 million
to expire on January 15, 2004. The Company had $15.2 million and $12.8 million
in short-term debt outstanding at March 31, 2000 and 1999, respectively, which
is classified as accounts payable-affiliates on the accompanying balance sheets.
Energy Corp. has acquired two gas turbine generators for use at the
Company's Horseshoe Lake Generating Station. These two generators will produce
approximately 50 megawatts of additional peak-load each. The total cost of this
project is expected to be approximately $47 million. In August 1999, the Company
announced the reactivation of two of its generators at the Company's Mustang
Generating Station that have been idle for several years. These two generators
together produce approximately 115 megawatts of additional peak-load. The total
cost of this reactivation project is expected to be approximately $9 million.
During the summer of 2000, the Company plans to begin using these four
generators, increasing its electric generating capacity by approximately 4
percent.
The Company's capital structure and cash flow remained strong throughout
the current period. The Company's combined cash and cash equivalents decreased
approximately $1.5 million during the three months ended March 31, 2000. The
decrease reflects the Company's cash flow from operations, net of short-term
debt, construction expenditures and dividend payments.
Like any business, the Company is subject to numerous contingencies, many
of which are beyond its control. For discussion of significant contingencies
that could affect the Company, reference is made to Part II, Item 1 - "Legal
Proceedings" of this Form 10-Q and to "Management's Discussion and Analysis" and
Notes 8 and 9 of Notes to the Financial Statements in the Company's 1999 Form
10-K.
REGULATION AND RATES
The Company's retail electric tariffs in Oklahoma are regulated by the OCC,
and in Arkansas by the APSC. The issuance of certain securities by the Company
is also regulated by the OCC and the APSC. The Company's wholesale electric
tariffs, short-term borrowing authorization and accounting practices are subject
to the jurisdiction of the FERC. The Secretary
7
<PAGE>
of the Department of Energy has jurisdiction over some of the Company's
facilities and operations.
RECENT REGULATORY MATTERS
On January 12, 2000, the OCC Staff (the "Staff") filed three applications
to address various aspects of the Company's electric rates. Two of the
applications were expected, while the third pertains to recoveries under the
Company's fuel adjustment clause. The first application relates to the
completion on March 1, 2000, of the recovery of the amortization premium paid by
the Company when it acquired Enogex in 1986 and the resulting removal of this
$12.8 million ($10.7 million in the Oklahoma Jurisdiction) from the amounts
currently being paid annually by the Company to Enogex and being recovered by
the Company from its ratepayers. The Company consented to this action and in
March 2000, the OCC approved the APC Rider for $10.7 million annually.
The second application relates to a review of the GEP Rider (discussed
below), which, as part of the OCC's 1997 Order, was scheduled for review in
March 2000. The Company collected approximately $20.8 million pursuant to the
GEP Rider during 1999. A hearing on the GEP Rider is scheduled in May 2000 and
the Company intends to support the retention of the GEP Rider with only minor
modifications. The final application relates to a review of 1999 fuel cost
recoveries. The Company assumes that this application also will be used to
address the competitive bid process of its gas transportation service. The
Company cannot predict the precise outcome of these proceedings at this time,
but does not expect that they will have a material effect on its operations.
In February 1997, the OCC issued an order (the "1997 Order") that, among
other things, directed the Company to commence competitively bid gas
transportation service to its gas-fired plants no later than April 30, 2000. The
order also set annual compensation for the transportation services provided by
Enogex to the Company at $41.3 million annually until March 1, 2000, at which
time the rate would drop to $28.5 million (reflecting the completion of the
recovery from ratepayers of the amortization premium paid by the Company when it
acquired Enogex in 1986) and remain at that level until competitively-bid gas
transportation begins. Final firm bids were submitted by Enogex and other
pipelines on April 15, 1999. In July 1999, the Company filed an application with
the OCC requesting approval of a performance-based rate plan for its Oklahoma
retail customers from April 2000 until the introduction of customer choice for
electric power in July 2002. As part of this application, the Company stated
that Enogex had submitted the only viable bid ($33.4 million per year) for gas
transportation to its six gas-fired power plants that were the subject of the
competitive bid. As part of its application to the OCC, the Company offered to
discount Enogex's bid from $33.4 million annually to $25.2 million annually. The
Company has executed a new gas transportation contract with Enogex under which
Enogex would continue serving the needs of the Company's power plants at a price
to be paid by the Company of $33.4 million annually and, if the Company's
proposal had been approved by the OCC, the Company would have recovered a
portion of such amount ($25.2 million) from its ratepayers. The Staff, the
Office of the Oklahoma Attorney General and a coalition of industrial customers
filed testimony questioning various parts of the Company's performance-based
rate
8
<PAGE>
plan, including the result of the competitive bid process, and suggested, among
other things, that the bidding process be repeated or that gas transportation
service to five of the Company's gas-fired plants be awarded to parties other
than Enogex. The Staff also filed testimony stating in substance that the
Company's electric rates as a whole were appropriate and did not warrant a rate
review. The Company negotiated with these parties in an effort to settle all
issues (including the competitive bid process) associated with its application
for a performance-based rate plan. When these negotiations failed, the Company
withdrew its application, which withdrawal was approved by the OCC in December
1999. Based on filed testimony, the Company believes that Enogex properly won
the competitive bid and, unless the Company's decision to award its gas
transportation service to Enogex is abrogated by order of the OCC (which order
is upheld on appeal), that it intends to fulfill its obligations under its new
gas transportation contract with Enogex at a price of $33.4 million annually.
Whether the Company will be able to recover the entire amount from its
ratepayers has not been determined as previously mentioned.
On April 4, 2000, the Staff filed testimony proposing an annual GEP Rider
incentive of $7.07 million for the Company, compared with $13.26 million under
current GEP Rider incentive factors. The current GEP Rider is designed so that
when the Company's average annual cost of fuel per kwh is less than 96.261
percent of the average non-nuclear fuel cost per kwh of certain other
investor-owned utilities in the region, the Company is allowed to collect,
through the GEP Rider, one-third of the amount by which the Company's average
annual cost of fuel comes in below 96.261 percent of the average of the other
specified utilities. If the Company's fuel cost exceeds 103.739 percent of the
stated average, the Company will not be allowed to recover one-third of the fuel
costs above that average from Oklahoma customers. In its April 4, 2000
testimony, the Staff stated that they continue to support incentive programs
that reward superior performance, but in their view the current GEP Rider is not
functioning as the Staff had originally envisioned it.
The Staff proposes three key changes to the GEP Rider: (i) modifying the
Company's peer group to include utilities with a higher coal to gas generation
mix; (ii) reducing the amount of fuel costs that can be recovered if the
Company's costs exceed the new peer group by changing the percentage above which
the Company will not be allowed to recover one-third of the fuel costs from
Oklahoma customers from 103.739 percent to 101.0 percent; and (iii) reducing the
Company's share of cost savings as compared to its new peer group from 33
percent to 25 percent. Other participants in the proceedings, including the
office of the Oklahoma Attorney General, have filed testimony seeking to modify
substantially the GEP Rider. The Company cannot predict the ultimate outcome of
this proceeding at this time but does not expect that it will have a material
effect on its operations.
STATE RESTRUCTURING INITIATIVES
OKLAHOMA: As previously reported, Oklahoma enacted in April 1997 the
Electric Restructuring Act of 1997 (the "Act"), which is designed to provide for
choice by retail customers of their electric supplier by July 1, 2002. Various
amendments to the Act were enacted in 1999 and 1998. The Oklahoma legislature is
in the process of considering additional implementing legislation, which will
address many specific issues associated with the Act and
9
<PAGE>
with deregulation. Separate bills have been passed by the Oklahoma House and
Oklahoma Senate and are currently in conference. The Company cannot predict
what, if any, legislation will be adopted. Nevertheless, the Company expects to
remain a competitive supplier of electricity.
ARKANSAS: In April 1999, Arkansas became the 18th state to pass a law
calling for restructuring of the electric utility industry at the retail level.
The new law targets customer choice of electricity providers by January 1, 2002.
The new law also provides that utilities owning or controlling transmission
assets must transfer control of such transmission assets to an independent
system operator, independent transmission company or regional transmission
group, if any such organization has been approved by the FERC. Other provisions
of the new law permit municipal electric systems to opt in or out, permit
recovery of stranded costs and transition costs and require filing of unbundled
rates by July 1, 2000 for generation, transmission, distribution and customer
service. The APSC has established a timetable to establish rules implementing
the Arkansas restructuring statutes. The new law will significantly affect the
Company's future Arkansas operations. The Company's electric service area
includes parts of western Arkansas, including Ft. Smith, the second-largest
metropolitan market in the state.
NATIONAL ENERGY LEGISLATION
In December 1999, FERC issued Order 2000 to advance the formation of
Regional Transmission Organizations ("RTO"). The rule requires that each public
utility that owns, operates or controls facilities for the transmission of
electric energy in interstate commerce file by October 15, 2000, a proposal with
respect to forming and participating in an RTO. The FERC also codified minimum
characteristics and functions that a transmission entity must satisfy in order
to be considered an RTO. The FERC's goal is to promote efficiency in wholesale
electricity markets and to ensure that electricity consumers pay the lowest
price possible for reliable service. The FERC expects that the RTOs will be
operational by December 15, 2001.
10
<PAGE>
PART II. OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
Reference is made to Item 3 of the Company's 1999 Form 10-K for a
description of certain legal proceedings presently pending. There are no new
significant cases to report against the Company and there have been no notable
changes in the previously reported proceedings, except as set forth below:
Reference is made to paragraph 6 and 7 of Item 3 of the Company's 1999 Form
10-K for a description of: (i) qui tam cases brought by Jack J. Grynberg against
the Company, Enogex, subsidiaries of Enogex and more than 300 other entities
(the "Grynberg matter"), and (ii) the amended class action petition by Quinque
Operating Company, on behalf of itself and others (the "Quinque lawsuit"),
alleging among other things, mismeasurements of gas volume and BTU content by
approximately 200 defendants, including the Company, Enogex and two subsidiaries
of Enogex, including Transok. As previously reported, the Company filed its
notice with the Multi-district Litigation Panel ("MDL Panel") advising the MDL
Panel that the Qunique lawsuit involved the same measurement issues and was a
potential tag-along to the Grynberg matters. On April 10, 2000, the MDL Panel
entered its order transferring and consolidating on pretrial purposes the
Quinque lawsuit with the Grynberg matter. This consolidated case is now before
the United States District Court for the District of Wyoming.
ITEM 5 OTHER INFORMATION
On May 8, 2000, Eric B. Weekes was named Treasurer.
ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
27.01 - Financial Data Schedule.
(b) Reports on Form 8-K
None
11
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
OKLAHOMA GAS AND ELECTRIC COMPANY
(Registrant)
By /s/ Donald R. Rowlett
----------------------------------------
Donald R. Rowlett
Vice President and Controller
(On behalf of the registrant and in
his capacity as Chief Accounting Officer)
May 12, 2000
12
<PAGE>
<TABLE>
EXHIBIT INDEX
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<S> <C>
27.01 Financial Data Schedule
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the Oklahoma
Gas and Electric Company Statements of Income, Balance Sheets, and Statements of
Cash Flows as reported on Form 10-Q as of March 31, 2000 and is qualified in its
entirety by reference to such Form 10-Q.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> MAR-31-2000
<PERIOD-END> MAR-31-2000
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,945,693
<OTHER-PROPERTY-AND-INVEST> 13,462
<TOTAL-CURRENT-ASSETS> 239,201
<TOTAL-DEFERRED-CHARGES> 92,776
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,291,132
<COMMON> 100,947
<CAPITAL-SURPLUS-PAID-IN> 411,499
<RETAINED-EARNINGS> 347,575
<TOTAL-COMMON-STOCKHOLDERS-EQ> 860,021
0
0
<LONG-TERM-DEBT-NET> 703,079
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 1,696
<OTHER-ITEMS-CAPITAL-AND-LIAB> 726,336
<TOT-CAPITALIZATION-AND-LIAB> 2,291,132
<GROSS-OPERATING-REVENUE> 245,332
<INCOME-TAX-EXPENSE> (3,232)
<OTHER-OPERATING-EXPENSES> 239,564
<TOTAL-OPERATING-EXPENSES> 236,332
<OPERATING-INCOME-LOSS> 9,000
<OTHER-INCOME-NET> (489)
<INCOME-BEFORE-INTEREST-EXPEN> 8,511
<TOTAL-INTEREST-EXPENSE> 11,737
<NET-INCOME> (3,226)
0
<EARNINGS-AVAILABLE-FOR-COMM> (3,226)
<COMMON-STOCK-DIVIDENDS> 25,890
<TOTAL-INTEREST-ON-BONDS> 11,259
<CASH-FLOW-OPERATIONS> 90,225
<EPS-BASIC> (0.08)
<EPS-DILUTED> (0.08)
</TABLE>
