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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 September 30, 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
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There were 40,378,745 Shares of Common Stock, par value $2.50 per share,
outstanding as of October 31, 1999.
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OKLAHOMA GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
STATEMENTS OF INCOME
(UNAUDITED)
3 MONTHS ENDED 9 MONTHS ENDED
SEPTEMBER 30 SEPTEMBER 30
------------------------------- ----------------------------------
1999 1998 1999 1998
------------- -------------- ---------------- ---------------
(THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
OPERATING REVENUES......................................... $ 464,982 $ 474,209 $ 1,029,228 $ 1,046,871
------------- ------------- ---------------- ---------------
OPERATING EXPENSES:
Fuel..................................................... 125,886 120,188 279,542 278,978
Purchased power.......................................... 69,117 65,107 190,507 179,189
Other operation and maintenance.......................... 65,101 56,688 185,222 182,058
Depreciation............................................. 30,118 28,390 88,974 87,317
Taxes other than income.................................. 11,492 10,141 33,719 32,866
------------- ------------- ---------------- ---------------
Total operating expenses............................... 301,714 280,514 777,964 760,408
------------- ------------- ---------------- ---------------
OPERATING INCOME........................................... 163,268 193,695 251,264 286,463
------------- ------------- ---------------- ---------------
OTHER INCOME (EXPENSES):
Interest charges......................................... (11,253) (11,633) (34,347) (35,644)
Other, net............................................... (290) (868) 176 18
------------- ------------- ---------------- ---------------
Net other income (expenses)............................ (11,543) (12,501) (34,171) (35,626)
------------- ------------- ---------------- ---------------
EARNINGS BEFORE INCOME TAXES............................... 151,725 181,194 217,093 250,837
PROVISION FOR INCOME TAXES................................. 63,972 75,263 85,421 101,106
------------- ------------- ---------------- ---------------
NET INCOME ................................................ 87,753 105,931 131,672 149,731
PREFERRED DIVIDEND REQUIREMENTS............................ - - - 733
------------- ------------- ---------------- ---------------
EARNINGS AVAILABLE FOR COMMON.............................. $ 87,753 $ 105,931 $ 131,672 $ 148,998
============= ============= ================ ===============
AVERAGE COMMON SHARES OUTSTANDING (thousands).............. 40,379 40,379 40,379 40,379
EARNINGS PER AVERAGE COMMON SHARE.......................... $ 2.17 $ 2.62 $ 3.26 $ 3.69
============= ============= ================ ================
DIVIDENDS DECLARED PER SHARE............................... $ 0.641 $ 1.953 $ 1.922 $ 3.258
<FN>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
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<CAPTION>
BALANCE SHEETS
(UNAUDITED)
SEPTEMBER 30 DECEMBER 31
1999 1998
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(DOLLARS IN THOUSANDS)
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ASSETS
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 252 $ 312
Accounts receivable - customers, less reserve of $3,393 and
$2,441, respectively........................................ 152,141 91,434
Accrued unbilled revenues..................................... 47,100 22,500
Accounts receivable - other................................... 8,864 7,723
Fuel inventories, at LIFO cost................................ 64,312 47,081
Materials and supplies, at average cost....................... 29,535 25,894
Prepayments and other......................................... 15,323 28,641
Accumulated deferred tax assets............................... 7,454 6,889
------------- --------------
Total current assets........................................ 324,981 230,474
------------- --------------
OTHER PROPERTY AND INVESTMENTS, at cost......................... 19,721 17,454
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PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... 3,737,861 3,674,732
Construction work in progress................................. 15,077 28,439
------------- --------------
Total property, plant and equipment......................... 3,752,938 3,703,171
Less accumulated depreciation............................. 1,786,859 1,727,472
------------- --------------
Net property, plant and equipment............................. 1,966,079 1,975,699
------------- --------------
DEFERRED CHARGES:
Advance payments for gas...................................... 14,900 15,000
Income taxes recoverable - future rates....................... 39,952 40,731
Other......................................................... 38,013 40,739
------------- --------------
Total deferred charges...................................... 92,865 96,470
------------- --------------
TOTAL ASSETS.................................................... $ 2,403,646 $ 2,320,097
============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - affiliates................................. $ 124,177 $ 67,045
Accounts payable.............................................. 32,498 45,536
Customers' deposits........................................... 22,130 23,984
Accrued taxes................................................. 28,462 18,932
Accrued interest.............................................. 15,720 15,931
Other......................................................... 21,388 38,642
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Total current liabilities................................... 244,375 210,070
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LONG-TERM DEBT.................................................. 703,012 702,912
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DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 15,612 18,162
Accumulated deferred income taxes............................. 453,541 462,886
Accumulated deferred investment tax credits................... 63,866 67,728
Other......................................................... 15,603 4,768
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Total deferred credits and other liabilities................ 548,622 553,544
------------- --------------
STOCKHOLDERS' EQUITY:
Common stockholders' equity................................... 512,446 512,446
Retained earnings............................................. 395,191 341,125
------------- --------------
Total stockholders' equity.................................. 907,637 853,571
------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,403,646 $ 2,320,097
============= ==============
<FN>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
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<CAPTION>
STATEMENTS OF
CASH FLOWS
(UNAUDITED)
9 MONTHS ENDED
SEPTEMBER 30
1999 1998
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(DOLLARS IN THOUSANDS)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income......................................................... $ 131,672 $ 149,731
Adjustments to Reconcile Net Income to Net Cash:
Depreciation and amortization.................................... 88,974 87,317
Deferred income taxes and investment tax credits, net............ (12,382) 6,442
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers.................................. (60,707) (63,798)
Accrued unbilled revenues........................................ (24,600) (9,700)
Fuel, materials and supplies inventories......................... (20,872) 8,261
Accumulated deferred tax assets.................................. (565) (260)
Other current assets............................................. 12,177 (3,136)
Accounts payable................................................. 43,853 99,401
Accrued taxes.................................................... 9,530 9,184
Accrued interest................................................. (211) (844)
Other current liabilities........................................ (19,108) (238)
Other operating activities....................................... 12,206 (13,744)
-------------- --------------
Net cash provided by operating activities...................... 159,967 268,616
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (82,661) (74,508)
-------------- --------------
Net cash used in investing activities.......................... (82,661) (74,508)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt....................................... - (112,500)
Proceeds from long-term debt....................................... - 100,000
Short-term debt, net............................................... 241 -
Redemption of preferred stock...................................... - (49,266)
Cash dividends declared on preferred stock......................... - (733)
Cash dividends declared on common stock............................ (77,607) (131,569)
-------------- --------------
Net cash used in financing activities.......................... (77,366) (194,068)
-------------- --------------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS................. (60) 40
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 312 228
-------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 252 $ 268
============== ==============
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)............................. $ 30,716 $ 32,871
Income taxes..................................................... $ 36,557 $ 42,876
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<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>
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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 September 30, 1999, and
December 31, 1998, and the results of operations and the changes in cash
flows for the periods ended September 30, 1999, and September 30, 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 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".
Adoption of SFAS No. 133 is now required for financial statements for
periods beginning after June 15, 2000. The Company will 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 operation.
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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 and nine months ended September 30, 1999
(respectively, the "current periods"), and the Company's financial position as
of September 30, 1999. Unless indicated otherwise, all comparisons are with the
corresponding periods of the prior year. 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.
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.
EARNINGS
Net income decreased $18.2 million or 17.2 percent and $18.1 million or
12.1 percent in the current periods. As explained below, the Company's decrease
in earnings for the three months ending September 30, 1999, was primarily
attributable to lower revenues from sales to Company customers ("system sales")
due to cooler weather in the Company electric service area, lower other electric
revenues and lower recoveries under the Generation Efficiency Performance Rider
("GEP Rider"). This decrease was partially offset by higher margin sales to
other utilities and power marketers ("off-system sales"). For the nine months
ending September 30, 1999, the Company's decrease in earnings reflect lower
revenues from both system sales and off-system sales and lower recoveries under
the GEP Rider.
REVENUES
Operating revenues decreased $9.2 million or 2.0 percent and $17.6 million
or 1.7 percent in the current periods. Cooler weather in the Company's electric
service area, lower other electric revenues and lower recoveries under the GEP
Rider resulted in reduced revenues for the three
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months ending September 30, 1999. The cooler weather resulted in a 2.4 percent
reduction in kilowatt-hour system sales. The Company's off-system kilowatt-hour
sales also decreased 3.0 percent. However, significantly higher margin sales
resulted in increased revenues of $10.3 million from off-system sales, which
only partially offset the other reductions in electric operating revenues. For
the nine months ending September 30, 1999, cooler weather, decreased system and
off-system sales and lower recoveries under the GEP Rider resulted in reduced
revenues of $17.6 million or 1.7 percent. The cooler weather resulted in a 1.5
percent reduction in kilowatt-hour system sales and a 54.4 percent reduction in
off-system kilowatt-hour sales. See "Recent Regulatory Matters" for a discussion
of the GEP Rider.
EXPENSES
Total operating expenses increased $21.2 million or 7.6 percent and $17.6
million or 2.3 percent in the current periods due to increased other operation
and maintenance costs, purchased power and fuel expense.
Other operation and maintenance increased $8.4 million or 14.8 percent and
$3.2 million or 1.7 percent in the current periods primarily due to expenses
associated with tornadoes and severe thunderstorms that inflicted heavy damage
to the Company's power supply, transmission and delivery systems on May 3, 1999.
Purchased power costs increased $4.0 million or 6.2 percent and $11.3
million or 6.3 percent primarily due to the availability of electricity at
favorable prices.
Fuel expense increased $5.7 million or 4.7 percent and $0.5 million or 0.2
percent in the current periods due to higher costs associated with the increased
use of natural gas in the production of electricity. 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.
("Enogex"), an affiliate of the Company, owns and operates a pipeline business
that delivers natural gas to the Company's electric generating stations. 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 "Recent Regulatory Matters."
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.
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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, to satisfy maturing debt. Capital
expenditures of $82.7 million for the nine months ended September 30, 1999, were
financed with internally generated funds.
The Company's capital structure and cash flow remained strong throughout
the current period. The Company's combined cash and cash equivalents position
remained constant during the nine months ended September 30, 1999, reflecting
the Company's cash flow from operations and short-term debt, offset by the
construction expenditures and dividend payments.
On July 1, 1999, Enogex completed its previously announced acquisition of
Transok LLC and its subsidiaries ("Transok"), a gatherer, processor and
transporter of natural gas in Oklahoma and Texas. Enogex purchased Transok from
Tejas Energy LLC of Houston, an affiliate of Shell Oil Company, for $710.3
million, which includes assumption of $173 million of long-term debt. Certain
security ratings of the Company were lowered by rating agencies primarily due to
Enogex's debt incurred to finance the acquisition of Transok. In August 1999,
Standard & Poor's ("S&P") and Moody's Investors Service ("Moody's") downgraded
the debt ratings of the Company. S&P changed the Company's corporate credit
rating and senior unsecured debt ratings from "AA-" to "A+". Moody's changed the
Company's senior unsecured debt ratings from "Aa3" to "A1". These ratings
reflect the views of S&P and Moody's, and an explanation of the significance of
these ratings may be obtained from S&P and Moody's. A security rating is not a
recommendation to buy, sell or hold securities and is subject to revision or
withdrawal at any time by the rating agency.
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, to Part II, Item 1 - "Legal Proceedings" in the
Company's Form 10-Q for the quarters ended March 31, 1999 and June 30, 1999, to
Item 5 - "Other Information" in the Company's Form 10-Q for the quarter ended
March 31, 1999 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
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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 OG&E's 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 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. In June 1999, the Company also completed the full implementation of the
enterprise-wide software system for customer systems. A portion of our customer
base began to be phased in to the new system in June of 1999. 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 completed the internal inventory and assessment (Phase I)
of the Year 2000 plan. Follow-up vendor requests for information on their status
has been received, documented and filed (Phase II). Remediation is complete for
systems essential to generate and
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deliver electricity to our customers. Even though contingency planning is a
normal part of our business, plans are being updated and finalized 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 have been upgraded with Y2K ready operating systems. For embedded and
plant operational systems, the Company has completed the corrective process. The
Company's Energy Management System ("EMS") that monitors transmission
interconnections and automatically signals generation output changes was
replaced in 1999. Software has been configured and new equipment is installed
and operational.
The Company participated in the "Y2K Electric System Readiness Assessment"
program, which provides monthly reports to the Southwest Power Pool ("SPP") and
the North American Electric Reliability Council ("NERC"). 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. In April 1999, the Company also participated in a nationwide
communications drill as a part of the electric utility industry's Y2K readiness
preparation. The purpose of the drill 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 drill
was successful overall and communications in the SPP went smoothly with only
minor problems noted. On June 28, 1999, the Company reported to the NERC that
its essential systems used to produce and deliver electricity were ready for the
year 2000. The responses from all participating companies are being compiled for
an industry-wide status report to the Department of Energy ("DOE"). Also, the
Company participated in the NERC tests on September 8, 1999, and September 9,
1999, which simulated the exercise of operating, communications, administrative
and contingency plans for the Y2K transition. The drill was successful with
respect to the Company's operations.
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. Since 1995, the Company
has spent in excess of $36 million on the mainframe conversion, the initial
financial enterprise software systems, the customer care enterprise software
installations to-date and the EMS replacement. The Company expects to spend
slightly less than $5 million in 1999. These costs represent estimates, however,
there can be no assurance that actual costs associated with the Company's Y2K
issues will not be higher.
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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 financial institutions could
result in lost power 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
On July 15, 1999, the Company filed with the OCC for approval of a
performance-based ratemaking plan that could lower rates for the Company's
Oklahoma customers by $83 million during the transition to deregulated customer
choice in mid-2002. The Company is the first utility in Oklahoma and among the
first in the nation to seek approval of such a plan.
Under the proposed performance-based ratemaking plan, the Company's rates
would be initially lowered by an estimated $29 million a year compared to June
1999 rates, and then would remain fixed at such rate during the 30-month
period ending July 1, 2002. This would be accomplished, in part, through the
elimination of the Company's GEP Rider and current fuel adjustment clause
through which increases and decreases in fuel costs are passed on to customers.
The risk of higher prices for the coal and natural gas used in generating
electricity would then shift from the customer to the Company.
Another key component of the proposed performance-based ratemaking plan is
a service quality incentive mechanism, pursuant to which the Company's
performance will be measured against its own benchmarks and recognized utility
industry standards. These measurements will then be used in a financial
reward/penalty program to promote continued reliability in the Company's
electric system, high levels of customer satisfaction and employee safety.
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The Company believes that the lower electric rates would be made possible
in part, by a reduction in the cost of transporting natural gas to its power
plants. Under the proposal, Enogex would remain the Company's natural gas
transporter at an annual rate of $25 million, down from the current $41 million
rate. Other provisions of the proposed performance-based ratemaking plan include
termination of the GEP Rider and the termination of the Company's rider for
off-system electricity sales. In Oklahoma, profits from off-system sales are
shared equally between customers and shareowners. The Company believes
termination of this rider is consistent with providing customers fixed rates and
would allow the Company to benefit from effectively managing its business.
On October 13, 1999, the OCC approved a procedural scheduling order for
consideration by year-end of the Company's proposed performance-based ratemaking
plan. Under the order approved by the OCC, testimony and discovery deadlines are
scheduled to conclude in November, with the case to be submitted to an
administrative law judge in early December, followed by a hearing before the OCC
on December 17, 1999. If approved by the OCC, the key provisions of the proposed
performance-based ratemaking plan will go into effect on January 1, 2000.
As previously reported, the OCC's order on February 11, 1997 established
the GEP Rider. The 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 is less than
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 amount from Oklahoma
customers.
The GEP Rider is revised effective July 1 of each year to reflect any
changes in the relative annual cost of fuel reported for the preceding calendar
year. For the twelve months ended June 30, 1999, the GEP Rider positively
impacted revenues by $30 million or approximately $0.45 per share. The GEP Rider
was revised July 1, 1999, by lowering the anticipated amount to be recovered
under the rider during 1999 by approximately $10 million (or approximately $0.15
per share) from 1998. The new GEP Rider is estimated to positively impact
revenue by $20 million or approximately $0.30 per share in 1999.
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 was
presented to the APSC on May 18, 1999. The APSC issued an order approving the
settlement on August 6, 1999.
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.
11
<PAGE>
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 legislative and rulemaking process that is
scheduled to provide for customer choice in Oklahoma by July 1, 2002.
12
<PAGE>
PART II. OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
Reference is made to Item 3 of the Company's 1998 Form 10-K and to Part II,
Item 1 of the Company's Form 10-Q for the quarters ended March 31, 1999 and June
30, 1999 for a description of certain legal proceedings presently pending.
Except as described below, there are no new significant cases to report against
the Company and there have been no significant changes in the previously
reported proceedings.
1. As previously reported in the Company's 1998 Form 10-K, an employee of
the Company filed a lawsuit in the state court on July 8, 1994, against the
Company in connection with the Company's 1994 voluntary early retirement
program. The case was removed to the U.S. District Court in Tulsa, Oklahoma. On
August 23, 1994, the trial court granted the Company's Motion to Dismiss
Plaintiff's Complaint in its entirety. On September 12, 1994, Plaintiff, along
with two other Plaintiffs, filed an Amended Complaint alleging substantially the
same allegations, which were in the original complaint. The action was filed as
a class action, but no motion to certify a class was ever filed. Plaintiff's
wanted credit, for retirement purposes, for years they worked prior to a
pre-ERISA (1974) break in service. They alleged 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, were 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 Judgement on January 18, 1996. On
September 8, 1997, the United States Magistrate Judge recommended that the
Defendant's motions to dismiss and for summary judgement should be granted and
that the case be dismissed in its entirety and judgement entered for the
Company. The United States District Judge accepted the recommendation of the
Magistrate and entered judgement for the Company. Plaintiffs filed an appeal
with the Tenth Circuit Court of Appeals. In August 1999, the Tenth Circuit
affirmed in all respects the District Courts' decision dismissing Plaintiff's
case and entering judgement for the Company. Since the Plaintiffs have failed to
file a timely writ of certiorari to the U.S. Supreme Court, the Company
considers this case closed.
2. Reference is made to "Item 1. Legal Proceedings" of Part II of the
Company's Form 10-Q for the quarter ended June 30, 1999, for a description of
the qui tam cases brought by Jack J. Gynberg against the Company, Enogex,
subsidiaries of Enogex and more than 300 other entities. On October 20, 1999,
the Multi District Litigation Panel (MDL Panel) entered its order consolidating
all the listed Gynberg qui tam cases in the United States District Court of
Wyoming before the Honorable Judge William Downes. On November 4, 1999, the same
MDL Panel entered its Order indicating the listed Gynberg qui tam tag-along
cases would also be considered in the United States District Court of Wyoming
before Judge Downes.
13
<PAGE>
On September 23, 1999, Quinque Operating Company, on behalf of itself and
others, filed an amended class action petition alleging, among other things,
mismeasurement of gas volume and BTU content by approximately 200 defendants,
including the Company, Enogex and two subsidiaries of Enogex, including Transok.
Specifically, Plaintiffs are seeking to certify the action as a class action and
allege breach of contract, negligent or intentional misrepresentation, civil
conspiracy and fraud. Plaintiffs seek actual and treble damages, punitive
damages, and an injunction to prevent mismeasurement in the future. Their prayer
for actual damages is in excess of $75,000 and includes punitive damages. On
October 5, 1999, notice was filed with the MDL Panel that this matter involved
the same measurement issues and was a potential tag-along to the Gynberg matter.
Plaintiffs opposed the MDL Panel transfer on October 15. The MDL Panel has not
yet entered an order concerning whether this will be treated as a tag-along case
to the Gynberg lawsuit.
Due to early stages of these lawsuits, the Company cannot predict the
ultimate outcome of either the Gynberg or Quinque actions, but at the present
time, the Company believes that neither lawsuit will have a material adverse
impact on the Company's consolidated financial position or results of
operations.
ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
27.01 - Financial Data Schedule.
(b) Reports on Form 8-K
(1) Item 5. Other Events, dated July 8, 1999.
(2) Item 5. Other Events, dated July 16, 1999.
14
<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)
November 15, 1999
15
<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 September 30, 1999 and is qualified in
its entirety by reference to such Form 10-Q.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,966,079
<OTHER-PROPERTY-AND-INVEST> 19,721
<TOTAL-CURRENT-ASSETS> 324,981
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<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,403,646
<COMMON> 100,947
<CAPITAL-SURPLUS-PAID-IN> 411,499
<RETAINED-EARNINGS> 395,191
<TOTAL-COMMON-STOCKHOLDERS-EQ> 907,637
0
0
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<CAPITAL-LEASE-OBLIGATIONS> 702
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<OTHER-ITEMS-CAPITAL-AND-LIAB> 790,197
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<GROSS-OPERATING-REVENUE> 1,029,228
<INCOME-TAX-EXPENSE> 85,421
<OTHER-OPERATING-EXPENSES> 777,964
<TOTAL-OPERATING-EXPENSES> 777,964
<OPERATING-INCOME-LOSS> 251,264
<OTHER-INCOME-NET> 176
<INCOME-BEFORE-INTEREST-EXPEN> 251,440
<TOTAL-INTEREST-EXPENSE> 34,347
<NET-INCOME> 131,672
0
<EARNINGS-AVAILABLE-FOR-COMM> 131,672
<COMMON-STOCK-DIVIDENDS> 77,607
<TOTAL-INTEREST-ON-BONDS> 33,428
<CASH-FLOW-OPERATIONS> 159,967
<EPS-BASIC> 3.26
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</TABLE>
