<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, 1999
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
(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, 1999, all of which were held by OGE Energy Corp.
================================================================================
<PAGE>
<TABLE>
<CAPTION>
OKLAHOMA GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
STATEMENTS OF INCOME
(Unaudited)
3 MONTHS ENDED
MARCH 31
1999 1998
-------------- --------------
(THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C>
OPERATING REVENUES:........................................ $ 250,144 $ 236,645
-------------- --------------
OPERATING EXPENSES:
Fuel..................................................... 67,958 69,868
Purchased power.......................................... 59,124 56,325
Other operation and maintenance.......................... 55,109 62,165
Depreciation............................................. 29,303 29,607
Taxes other than income.................................. 11,351 11,800
-------------- --------------
Total operating expenses............................... 222,845 229,765
-------------- --------------
OPERATING INCOME........................................... 27,299 6,880
-------------- --------------
OTHER INCOME (EXPENSES):
Interest charges......................................... (11,296) (11,978)
Other, net............................................... (304) 183
-------------- --------------
Total other income (expenses).......................... (11,600) (11,795)
-------------- --------------
EARNINGS BEFORE INCOME TAXES............................... 15,699 (4,915)
PROVISION FOR INCOME TAXES................................. 5,510 (2,836)
-------------- --------------
NET INCOME (LOSS).......................................... 10,189 (2,079)
PREFERRED DIVIDEND REQUIREMENTS............................ --- 733
-------------- --------------
EARNINGS (LOSS) AVAILABLE FOR COMMON....................... $ 10,189 $ (2,812)
============== ==============
AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS).............. 40,379 40,379
EARNINGS (LOSS) PER AVERAGE COMMON SHARE................... $ 0.25 $ (0.07)
============== ==============
DIVIDENDS DECLARED PER SHARE............................... $ 0.641 $ 0.640
<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
1999 1998
------------- --------------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 165 $ 312
Accounts receivable - customers, less reserve of $1,836 and
$2,441, respectively........................................ 77,532 91,434
Accrued unbilled revenues..................................... 22,600 22,500
Accounts receivable - other................................... 5,389 7,723
Fuel inventories, at LIFO cost................................ 54,565 47,081
Materials and supplies, at average cost....................... 26,671 25,894
Prepayments and other......................................... 15,189 28,641
Accumulated deferred tax assets............................... 7,099 6,889
------------- --------------
Total current assets........................................ 209,210 230,474
------------- --------------
OTHER PROPERTY AND INVESTMENTS, at cost......................... 19,875 17,454
------------- --------------
PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... 3,690,518 3,674,732
Construction work in progress................................. 34,250 28,439
------------- --------------
Total property, plant and equipment......................... 3,724,768 3,703,171
Less accumulated depreciation............................. 1,756,503 1,727,472
------------- --------------
Net property, plant and equipment............................. 1,968,265 1,975,699
------------- --------------
DEFERRED CHARGES:
Advance payments for gas...................................... 14,900 15,000
Income taxes recoverable - future rates....................... 40,471 40,731
Other......................................................... 40,818 40,739
------------- --------------
Total deferred charges...................................... 96,189 96,470
------------- --------------
TOTAL ASSETS.................................................... $ 2,293,539 $ 2,320,097
============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - affiliates................................. $ 76,000 $ 67,045
Accounts payable.............................................. 43,740 45,536
Customers' deposits........................................... 24,126 23,984
Accrued taxes................................................. 10,842 18,932
Accrued interest.............................................. 16,303 15,931
Other......................................................... 19,138 38,642
------------- --------------
Total current liabilities................................... 190,149 210,070
------------- --------------
LONG-TERM DEBT.................................................. 702,945 702,912
-------------- --------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 19,364 18,162
Accumulated deferred income taxes............................. 457,549 462,886
Accumulated deferred investment tax credits................... 66,441 67,728
Other......................................................... 19,199 4,768
------------- --------------
Total deferred credits and other liabilities................ 562,553 553,544
------------- --------------
STOCKHOLDERS' EQUITY:
Common stockholders' equity................................... 512,446 512,446
Retained earnings............................................. 325,446 341,125
------------- --------------
Total stockholders' equity.................................. 837,892 853,571
------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,293,539 $ 2,320,097
============= ==============
<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
1999 1998
-------------- --------------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss).................................................. $ 10,189 $ (2,079)
Adjustments to Reconcile Net Income (Loss) to Net Cash:
Depreciation..................................................... 29,303 29,607
Deferred income taxes and investment tax credits, net............ (6,372) (1,262)
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers................................ 13,902 15,109
Accrued unbilled revenues...................................... (100) 7,700
Fuel, materials and supplies inventories....................... (8,261) (1,930)
Accumulated deferred tax assets................................ (210) 251
Other current assets........................................... 15,786 1,228
Accounts payable............................................... (5,621) 44,888
Accrued taxes.................................................. (8,090) (8,164)
Accrued interest............................................... 372 (2,006)
Other current liabilities...................................... (19,362) (2,434)
Other operating activities....................................... 15,541 41
-------------- --------------
Net cash provided from operating activities.................. 37,077 80,949
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (24,135) (22,202)
-------------- --------------
Net cash used in investing activities........................ (24,135) (22,202)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt....................................... --- (25,000)
Short-term debt, net............................................... 12,780 42,055
Redemption of preferred stock...................................... --- (49,266)
Cash dividends declared on preferred stock......................... --- (733)
Cash dividends declared on common stock............................ (25,869) (25,856)
-------------- --------------
Net cash used in financing activities........................ (13,089) (58,800)
-------------- --------------
NET DECREASE IN CASH AND CASH EQUIVALENTS............................ (147) (53)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 312 228
-------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 165 $ 175
============== ==============
- --------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)............................. $ 9,195 $ 13,283
Income taxes..................................................... $ 3,681 $ 9,908
- --------------------------------------------------------------------------------------------------------------
<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, 1999, and December
31, 1998, and the results of operations and the changes in cash flows for
the periods ended March 31, 1999, and March 31, 1998, have been included
and are of a normal recurring nature.
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, 1998.
2. In March 1998, the American Institute of Certified Public Accountants
("AICPA") issued Statement of Position ("SOP") 98-1, "Accounting for the
Costs of Computer Software Developed or Obtained for Internal Use".
Adoption of SOP 98-1 is required for fiscal years beginning after December
15, 1998. The Company adopted this new standard effective January 1, 1999.
Adoption of this new standard did not have a material impact on financial
position or results of operations.
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". Adoption of SFAS
No. 133 is required for financial statements for periods beginning after
June 15, 1999. The Company will adopt this new standard effective January
1, 2000, and management believes the adoption of this new standard will not
have a material impact on its financial position or results of operations.
4. In December 1998, the FASB Emerging Issues Task Force reached consensus on
Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities ("EITF Issue 98-10"). EITF Issue 98-10 is
effective for fiscal years beginning after December 15, 1998. EITF Issue
98-10 requires energy trading contracts to be recorded at fair value on the
balance sheet, with changes in fair value included in earnings. The Company
adopted this new Issue effective January 1, 1999. Adoption of this new
Issue did not have a material impact on 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, 1999 (the "current
period"), and the Company's financial position as of March 31, 1999. 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; failure of companies that
the Company does business with to be Year 2000 ready; regulatory decisions and
other risk factors listed in the Company's Form 10-K for the year ended December
31, 1998, including Exhibit 99.01 thereto, and other factors described from time
to time in the Company's reports to the Securities and Exchange Commission.
On Monday, May 3, 1999, tornadoes and severe thunderstorms inflicted heavy
damage to the power delivery system of the Company. At the peak of the storms
that started Monday afternoon, 116,000 customers were estimated to have lost
electricity. Authorities have estimated that as many as 10,000 homes and
businesses were damaged by these storms. Although the Company is still assessing
the damage, current estimates place the storm damage cost at approximately $12
million to $15 million, of which approximately 75 percent will be capitalized
and 25 percent expensed.
The damage sustained by the Company's power delivery system included
numerous distribution poles and lines. The Company's power transmission system
was also hard-hit. The storms knocked out more than 40 of the towers and high
line systems that transmit electricity from the Company's power plants to the
communities they serve. Despite this damage, the Company was quickly able to
deliver power to all of its substations, some of which were also damaged.
5
<PAGE>
EARNINGS
The current period net income of $10.2 million represents an increase of
$12.3 million. As explained below, the Company's increase in earnings was
primarily attributable to higher revenues from increased sales to its electric
customers ("system sales") and lower operating expenses. Earnings per average
common share increased to $0.25 from a net loss per average common share of
$0.07 in the prior period.
REVENUES
Operating revenues increased $13.5 million or 5.7 percent. The increase in
electric sales was primarily attributable to continued growth in the Company's
electric service area. Kilowatt-hour system sales increased 4.0 percent in the
current period. The increase in system sales was more than offset by a
significant reduction in sales to other utilities and power marketers
("off-system sales"). However, off-system sales are generally priced at much
lower prices per kilowatt-hour and have less impact on operating revenues and
earnings than system sales.
EXPENSES
Total operating expenses decreased $6.9 million or 3.0 percent due to
decreased fuel cost and other operation and maintenance expenses.
Fuel expense decreased $1.9 million or 2.7 percent in the current period.
This decrease was primarily due to the availability of electricity for purchase
at favorable prices and decreased generation levels, resulting from the
significant reduction in off-system sales. 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.
Other operation and maintenance expense decreased $7.1 million or 11.4
percent, primarily due to reduced contract labor, employee benefit costs and
miscellaneous corporate expenses.
Purchased power costs increased $2.8 million or 5.0 percent primarily due
to the availability of electricity at favorable prices.
Interest charges decreased $0.7 million or 5.7 percent due to the
redemption on April 21, 1998 of $87.5 million of long-term debt, refinanced at
lower interest cost.
6
<PAGE>
LIQUIDITY AND CAPITAL REQUIREMENTS
The Company meets its cash needs through internally generated funds,
permanent financing and short-term borrowings. Internally generated funds and
short-term borrowings are expected to meet virtually all of the Company's
capital requirements through the remainder of 1999. Short-term borrowings will
continue to be used to meet temporary cash 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 $24.1 million were financed with
internally generated funds and short-term borrowings.
The Company's capital structure and cash flow remained strong throughout
the current period. The Company's combined cash and cash equivalents decreased
approximately $147,000 during the three months ended March 31, 1999. 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 1998 Form
10-K.
THE YEAR 2000 ISSUE
There has been a great deal of publicity about the Year 2000 (Y2K) and the
possible problems that information technology systems may suffer as a result.
The Y2K problem originated with the early development of computerized business
applications. To save then-expensive storage space, reduce the complexity of
calculations and yield better system performance, programmers and developers
used a two-digit date scheme to represent the year (i.e., "72" for "1972"). This
two-digit date scheme was used well into the 1980s and 1990s in traditional
computer hardware such as mainframe systems, desktop personal computers and
network servers, in customized software systems, off-the-shelf applications and
operating systems, as well as in embedded systems ("chips") in everything from
elevators to industrial plants to consumer products. As the Year 2000
approaches, date-sensitive systems may recognize the Year 2000 as 1900, or not
at all. This inability to recognize or properly treat the Year 2000 may cause
systems, including those of the Company, its customers, suppliers, business
partners and neighboring utilities to process critical financial and operational
information incorrectly, if they are not Year 2000 ready. A failure to identify
and correct any such processing problems prior to January 1, 2000 could result
in material operational and financial risks if the affected systems either cease
to function or produce erroneous data. Such risks are described in more detail
below, but could include an inability to operate the Company's
7
<PAGE>
generating plants, disruptions in the operation of its transmission and
distribution system and an inability to access interconnections with the systems
of neighboring utilities.
After the Company's mainframe conversion in 1994, some 300 programs were
identified as having date sensitive code. All of these programs have since been
corrected or will be replaced by Y2K ready packaged applications.
The Company continues to address the Y2K issues in an aggressive manner.
This is reflected by the January 1, 1997 implementation throughout the Company
of SAP Enterprise Software, which is Y2K ready, for the financial systems. The
SAP installation significantly reduced the potential risks in our older computer
systems. The Company is making significant progress towards the implementation
of the enterprise-wide software system for customer systems. In addition to
significantly reducing the potential risks of its current customer systems, the
Company is set to streamline work processes in customer service and power
delivery by integrating separate systems into a single system using the
enterprise-wide software system. This new single system will also provide for a
more flexible automated billing system and enhancements in handling customer
service orders, energy outage incidents and customer services.
In October of 1997, the Company formed a multi-functional Y2K Project Team
of experienced and knowledgeable members from each business unit to review and
test its operational systems in an effort to further eliminate any potential
problems, should they exist. The team provides regular monthly reports on its
progress to the Y2K Executive Steering Committee and senior management as well
as helping prepare presentations to the Board of Directors.
The Company's Year 2000 effort generally follows a three-phase process:
Phase I - Inventory and Assess Y2K Issues
Phase II - Determine Y2K Readiness of Vendors, Suppliers & Customers
Phase III - Correct, Test, Implement Solutions and Contingency Planning
STATE OF READINESS
The Company has substantially completed the internal inventory and
assessment (Phase 1) of the Year 2000 plan. Follow-up vendor surveys are being
sent to vendors that have not responded to our original requests for information
(Phase II). Remediation efforts are ongoing and even though contingency planning
is a normal part of our business, plans have been prepared to include specific
activities with regard to Y2K issues (Phase III).
In addition, as a part of the Company's three-year lease agreement for
personal computers, all new personal computers are being issued with operating
systems and application software that are Y2K ready. All existing personal
computers will be upgraded with Y2K ready operating systems before the turn of
the century. For embedded and plant operational systems, the Company has
generally completed the evaluative process and is commencing corrective
8
<PAGE>
plans. In particular, the Company's Energy Management System ("EMS") that
monitors transmission interconnections and automatically signals generation
output changes, has been contracted for replacement in 1999. Equipment has been
ordered and software is currently being configured.
The Company is also participating in an "Electric System Readiness
Assessment" program, which provides monthly reports to the Southwest Power Pool
("SPP") and the North American Electric Reliability Council ("NERC"). In April
1999, the Company also participated in a nationwide communication test as a part
of the electric utility industry's Y2K readiness preparation. The purpose of the
test was to determine how electric utilities would communicate with one another
in the event of an interruption of standard communication systems. The ability
to communicate would be important to coordinate the flow of electricity over the
nation's electric grid. The overall success of the test is not yet known,
however, communications in the SPP went smoothly with only minor problems noted.
The responses from all participating companies are being compiled for an
industry-wide status report to the Department of Energy ("DOE"). Also, in
February 1999, the Company submitted contingency plans to the NERC and the SPP
which will be used along with those of other participating companies to
formulate a regional contingency plan.
COSTS OF YEAR 2000 ISSUES
As described above, with the mainframe conversion, the enterprise software
installations and the EMS replacement, a number of Y2K issues were addressed as
part of the Company's normal course upgrades to the information technology
systems. These upgrades were already contemplated and provided additional
benefits or efficiencies beyond the Year 2000 aspect. In addition to the $1
million spent to date for Y2K issues, since 1995 the Company has spent in excess
of $29 million on the mainframe conversion, the enterprise software
installations and the EMS replacement. The Company expects to spend slightly
less than $5 million in 1999. These costs represent estimates, however, and
there can be no assurance that actual costs associated with the Company's Y2K
issues will not be higher.
RISKS OF YEAR 2000 ISSUES
As described above, the Company has made significant progress in the
implementation of its Year 2000 plan. Based upon the information currently known
regarding its internal operations and assuming successful and timely completion
of its remediation plan, the Company does not anticipate significant business
disruptions from its internal systems due to the Y2K issue. However, the Company
may possibly experience limited interruptions to some aspects of its activities,
whether information technology, operational, administrative or otherwise, and
the Company is considering such potential occurrences in planning for its most
reasonably likely worst case scenarios.
Additionally, risk exists regarding the non-readiness of third parties with
key business or operational importance to the Company. Year 2000 problems
affecting key customers, interconnected utilities, fuel suppliers and
transporters, telecommunications providers or
9
<PAGE>
financial institutions could result in lost power or gas sales, reductions in
power production or transmission or internal functional and administrative
difficulties on the part of the Company. Although the Company is not presently
aware of any such situations, occurrences of this type, if severe, could have
material adverse impacts upon the business, operating results or financial
condition of the Company. There can be no assurance that the Company will be
able to identify and correct all aspects of the Year 2000 problem that affect it
in sufficient time, that it will develop adequate contingency plans or that the
costs of achieving Y2K readiness will not be material.
RECENT REGULATORY MATTERS
As previously reported, on February 13, 1998, The APSC Staff filed a motion
for a show cause order to review the Company's electric rates in the State of
Arkansas. The Staff recommended a $3.1 million annual rate reduction (based on a
test year ended December 31, 1996). The Staff and the Company have reached a
settlement for a $2.3 million annual rate reduction. The settlement is scheduled
to be presented to the APSC on May 18, 1999. An order is anticipated in the near
future.
On April 8, 1999, lawmakers in Arkansas reached consensus on deregulation
of the state's electric industry. On April 15, 1999, Senate Bill 791 was signed
by the governor of Arkansas. Arkansas is the 18th state to pass a law calling
for restructuring of the electric utility industry. 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 unbundled rates by July 1, 2000 for generation,
transmission, distribution and customer service. If implemented as proposed, the
new law will significantly affect the Company's future Arkansas operations. The
Company's electric service area includes parts of western Arkansas, including
Fort Smith, the second-largest metropolitan market in the state.
As previously reported, Oklahoma enacted in April 1997 the Electric
Restructuring Act of 1997. Various amendments to the Act were enacted in 1998.
The Company remains involved in the rulemaking process that will provide for
customer choice in Oklahoma by July 1, 2002.
10
<PAGE>
PART II. OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
Reference is made to Item 3 of the Company's 1998 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
significant changes in the previously reported proceedings.
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
Controller Corporate Accounting
(On behalf of the registrant and in
his capacity as Chief Accounting Officer)
May 14, 1999
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, 1999 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-31-1999
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,968,265
<OTHER-PROPERTY-AND-INVEST> 19,875
<TOTAL-CURRENT-ASSETS> 209,210
<TOTAL-DEFERRED-CHARGES> 96,189
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,293,539
<COMMON> 100,947
<CAPITAL-SURPLUS-PAID-IN> 411,499
<RETAINED-EARNINGS> 325,446
<TOTAL-COMMON-STOCKHOLDERS-EQ> 837,892
0
0
<LONG-TERM-DEBT-NET> 702,945
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 1,827
<LEASES-CURRENT> 2,115
<OTHER-ITEMS-CAPITAL-AND-LIAB> 748,760
<TOT-CAPITALIZATION-AND-LIAB> 2,293,539
<GROSS-OPERATING-REVENUE> 250,144
<INCOME-TAX-EXPENSE> 5,510
<OTHER-OPERATING-EXPENSES> 222,845
<TOTAL-OPERATING-EXPENSES> 222,845
<OPERATING-INCOME-LOSS> 27,299
<OTHER-INCOME-NET> (304)
<INCOME-BEFORE-INTEREST-EXPEN> 26,995
<TOTAL-INTEREST-EXPENSE> 11,296
<NET-INCOME> 10,189
0
<EARNINGS-AVAILABLE-FOR-COMM> 10,189
<COMMON-STOCK-DIVIDENDS> 25,869
<TOTAL-INTEREST-ON-BONDS> 11,033
<CASH-FLOW-OPERATIONS> 37,077
<EPS-PRIMARY> 0.25
<EPS-DILUTED> 0.25
</TABLE>
