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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 June 30, 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
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There were 40,378,745 Shares of Common Stock, par value $2.50 per share,
outstanding as of July 31, 2000.
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<CAPTION>
OKLAHOMA GAS AND ELECTRIC COMPANY
PART I. FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
STATEMENTS OF INCOME
(Unaudited)
3 Months Ended 6 Months Ended
June 30 June 30
-------------------------------- ---------------------------------
2000 1999 2000 1999
-------------- -------------- -------------- --------------
(THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
OPERATING REVENUES......................................... $ 335,573 $ 314,102 $ 580,905 $ 564,246
-------------- -------------- -------------- --------------
OPERATING EXPENSES:
Fuel..................................................... 106,957 85,698 179,206 153,656
Purchased power.......................................... 62,124 62,267 122,666 121,390
Other operation and maintenance.......................... 69,083 65,012 134,336 120,121
Depreciation and amortization............................ 30,363 29,553 60,514 58,856
Taxes other than income.................................. 11,365 10,875 22,734 22,227
-------------- -------------- -------------- --------------
Total operating expenses............................... 279,892 253,405 519,456 476,250
-------------- -------------- -------------- --------------
OPERATING INCOME........................................... 55,681 60,697 61,449 87,996
-------------- -------------- -------------- --------------
OTHER INCOME (EXPENSES), net............................... (767) 493 (1,401) (34)
-------------- -------------- -------------- --------------
EARNINGS BEFORE INTEREST AND TAXES......................... 54,914 61,190 60,048 87,962
INTEREST INCOME (EXPENSES):
Interest income.......................................... 144 277 289 500
Interest on long-term debt............................... (11,611) (11,213) (22,870) (22,246)
Other interest charges................................... 785 (586) 307 (849)
-------------- -------------- -------------- --------------
Net interest income (expenses)......................... (10,682) (11,522) (22,274) (22,595)
-------------- -------------- -------------- --------------
EARNINGS BEFORE INCOME TAXES............................... 44,232 49,668 37,774 65,367
PROVISION FOR INCOME TAXES................................. 14,671 15,939 11,439 21,449
-------------- -------------- -------------- --------------
NET INCOME................................................. $ 29,561 $ 33,729 $ 26,335 $ 43,918
============== ============== ============== ==============
AVERAGE COMMON SHARES OUTSTANDING.......................... 40,379 40,379 40,379 40,379
EARNINGS PER AVERAGE COMMON SHARE.......................... $ 0.73 $ 0.84 $ 0.65 $ 1.09
============== ============== ============== ==============
DIVIDENDS DECLARED PER SHARE............................... $ 0.641 $ 0.641 $ 1.282 $ 1.282
<FN>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
</TABLE>
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<TABLE>
<CAPTION>
BALANCE SHEETS
(UNAUDITED)
JUNE 30 DECEMBER 31
2000 1999
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(DOLLARS IN THOUSANDS)
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 308 $ 1,779
Accounts receivable - customers, less reserve of $5,222 and
$3,405, respectively........................................ 102,748 96,212
Accrued unbilled revenues..................................... 58,300 40,200
Accounts receivable - other................................... 6,783 8,074
Fuel inventories, at LIFO cost................................ 82,203 75,465
Materials and supplies, at average cost....................... 31,308 30,311
Prepayments and other......................................... 3,697 3,100
Accumulated deferred tax assets............................... 7,309 7,681
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Total current assets........................................ 292,656 262,822
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OTHER PROPERTY AND INVESTMENTS, at cost......................... 15,006 12,731
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PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... 3,770,258 3,747,690
Construction work in progress................................. 66,218 15,575
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Total property, plant and equipment......................... 3,836,476 3,763,265
Less accumulated depreciation............................. 1,853,648 1,810,898
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Net property, plant and equipment............................. 1,982,828 1,952,367
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DEFERRED CHARGES:
Advance payments for gas...................................... 11,800 11,800
Income taxes recoverable through future rates................. 39,173 39,692
Other......................................................... 41,329 41,248
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Total deferred charges...................................... 92,302 92,740
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TOTAL ASSETS.................................................... $ 2,382,792 $ 2,320,660
============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - affiliates................................. $ 173,197 $ 75,674
Accounts payable - other...................................... 33,427 36,231
Customers' deposits........................................... 22,087 22,137
Accrued taxes................................................. 18,947 19,545
Accrued interest.............................................. 14,472 14,573
Other......................................................... 23,585 20,893
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Total current liabilities................................... 285,715 189,053
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LONG-TERM DEBT.................................................. 703,112 703,045
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DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 16,112 14,886
Accumulated deferred income taxes............................. 442,355 450,028
Accumulated deferred investment tax credits................... 60,004 62,578
Other......................................................... 11,802 11,933
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Total deferred credits and other liabilities................ 530,273 539,425
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STOCKHOLDERS' EQUITY:
Common stockholders' equity................................... 512,446 512,446
Retained earnings............................................. 351,246 376,691
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Total stockholders' equity.................................. 863,692 889,137
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TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,382,792 $ 2,320,660
============= ==============
<FN>
THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
</TABLE>
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<TABLE>
<CAPTION>
STATEMENTS OF
CASH FLOWS
(UNAUDITED)
6 MONTHS ENDED
JUNE 30
2000 1999
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(DOLLARS IN THOUSANDS)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income......................................................... $ 26,335 $ 43,918
Adjustments to Reconcile Net Income to Net Cash:
Depreciation and amortization.................................... 60,514 58,856
Deferred income taxes and investment tax credits, net............ (8,949) (12,734)
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers................................ (6,536) 2,499
Accrued unbilled revenues...................................... (18,100) (36,500)
Fuel, materials and supplies inventories....................... (7,735) (21,481)
Accumulated deferred tax assets................................ 372 (636)
Other current assets........................................... 694 14,325
Accounts payable............................................... 64,438 (3,710)
Accrued taxes.................................................. (598) 332
Accrued interest............................................... (101) (485)
Other current liabilities...................................... 2,642 (15,495)
Other operating activities....................................... (28,083) 19,587
-------------- --------------
Net cash provided from operating activities.................. 84,893 48,476
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CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (64,865) (59,683)
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Net cash used in investing activities........................ (64,865) (59,683)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-term debt, net............................................... 30,281 62,810
Cash dividends declared on common stock............................ (51,780) (51,738)
-------------- --------------
Net cash provided by (used in) financing activities.......... (21,499) 11,072
-------------- --------------
NET DECREASE IN CASH AND CASH EQUIVALENTS............................ (1,471) (135)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 1,779 312
-------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 308 $ 177
============== ==============
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)............................. $ 24,760 $ 21,215
Income taxes..................................................... $ 5,115 $ 16,579
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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>
</TABLE>
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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 accounting principles generally
accepted in the United States 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 June 30, 2000, and December 31,
1999, and the results of operations and the changes in cash flows for the
periods ended June 30, 2000, and June 30, 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. In June
2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities", which amends the accounting
and reporting standards of SFAS No. 133 for certain derivative instruments
and hedging activities. 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
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 six months ended June 30, 2000
(respectively, the "current periods"), and the financial position as of June 30,
2000, of the Company. 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 of the 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
Net income decreased $4.2 million or 12.4 percent and $17.6 million or 40.0
percent in the current periods. As explained below, the Company's decrease in
earnings was primarily attributable to increased operating expenses. Earnings
per average common share decreased from $0.84 to $0.73 and from $1.09 to $0.65
in the current periods.
REVENUES
Operating revenues increased $21.5 million or 6.8 percent and $16.7 million
or 3.0 percent in the current periods. These increases resulted primarily from
the recovery of higher priced fuel costs. 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 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 affiliated company, owns and operates a pipeline business that delivers
natural gas to the generating stations of the
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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." Revenue was unfavorably affected in
the current periods by approximately $3.6 million and $7.7 million, due to
modifications of the Generation Efficiency Performance Rider ("GEP Rider") and
by approximately $2.8 million and $3.6 million, due to lower recoveries under
the Acquisition Premium Credit Rider ("APC Rider"). See "Regulation and Rates" -
"Recent Regulatory Matters." Increases in kilowatt-hour sales of 5.4 percent and
4.8 percent to Company customers ("system sales") in the current periods were
primarily attributable to more favorable weather in the Company's service area,
which partially offset the impact of the GEP Rider modifications and the APC
Rider. Kilowatt-hour sales to other utilities and power marketers ("off-system
sales") decreased 44.7 percent in the three months ended June 30, 2000 and
increased 5.2 percent in the six-month period ended June 30, 2000. Off-system
sales generally occur at much lower prices per kilowatt-hour and have less
impact on operating revenues and earnings than system sales.
EXPENSES
Total operating expenses increased $26.5 million or 10.5 percent and $43.2
million or 9.1 percent in the current periods. These increases were primarily
due to increased fuel expense and other operation and maintenance.
Fuel expense increased $21.3 million or 24.8 percent and $25.6 million or
16.6 percent in the current periods primarily due to a significant increase in
the average cost of fuel (particularly natural gas) and slightly higher
generation levels.
Purchased power costs remained relatively constant in the three months
ended June 30, 2000 and increased $1.3 million or 1.1 percent in the six months
ended June 30, 2000, primarily due to an increase in transmission charges
associated with off-system purchases.
Other operation and maintenance increased $4.1 million or 6.3 percent and
$14.2 million or 11.8 percent in the current periods primarily due to increased
labor, employee benefit costs and miscellaneous corporate expenses.
Depreciation and amortization increased $0.8 million or 2.7 percent and
$1.7 million or 2.8 percent during the current periods due to an increase in
depreciable property.
Other income decreased $1.3 million and $1.4 million in the current periods
due to a decrease in margins on contract work.
Interest charges decreased $0.8 million or 7.3 percent and $0.3 million or
1.4 percent in the current periods due to an increase in the allowance for
borrowed funds used during construction.
6
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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 of $64.9 million for the six months ended June 30, 2000, 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 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 $85.7 million and $55.5 million
in short-term debt outstanding at June 30, 2000 and December 31, 1999, which is
classified as accounts payable-affiliates on the accompanying balance sheets.
The Company acquired two gas turbine generators for use at the Company's
Horseshoe Lake Generating station. These two generators were brought on line on
June 14 and July 16, 2000 and will each produce 44 megawatts of additional
peak-load generating capacity. The total cost of this project is expected to be
$47 million. In August 1999, the Company announced the reactivation of two of
its generators at the Mustang Generating Station, which have been idle for
several years. These two Mustang Station generators were both brought on line
July 21, 2000 and together produce approximately 115 megawatts of additional
peak-load generating capacity. The total cost of this reactivation project is
expected to be $7 million. Together, these four generators increased the
Company's 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 six months ended June 30, 2000. The
decrease reflects the Company's cash flow from operations and proceeds from
short-term debt, net of 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.
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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 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 pursuant to the APC Rider 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, 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. On
April 4, 2000, the Staff filed testimony proposing an annual GEP Rider incentive
of $7.07 million for the Company, compared initially to $13.26 million under the
then-current GEP Rider incentive factors. The GEP Rider was designed so that
when the Company's average annual cost of fuel per kwh was 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 was allowed to collect,
through the GEP Rider, one-third of the amount by which the Company's average
annual cost of fuel was below 96.261 percent of the average of the other
specified utilities. If the Company's fuel cost exceeded 103.739 percent of the
stated average, the Company was not 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 continued to support incentive programs
that reward superior performance, but in their view the existing GEP Rider was
not functioning as the Staff had originally envisioned it.
In June 2000, the OCC approved the GEP Rider for $6.6 million annually and
the following four changes: (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; (iii) reducing the Company's share of cost savings as compared
to its new peer group from 33 percent to 30 percent; and (iv) limiting to $10.0
million the amount of any awards paid to the Company or penalties charged to the
Company.
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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. 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 continues to serve
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 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. The Company recently
entered into a stipulation (the "Stipulation") with the Staff, the Office of the
Attorney General and a coalition of industrial customers regarding the
competitive bid process of its gas transportation service. The Stipulation
(which, with one exception, has been signed by all parties to the proceeding)
permits the Company to recover $25.2 million annually for gas transportation
services to be provided by Enogex pursuant to the competitive bid process. The
Stipulation is scheduled to be presented for approval to an Administrative Law
Judge ("ALJ") in September 2000. The decision of the ALJ will then be presented
to the OCC for its approval.
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
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enacted in 1999 and 1998. Additional implementing legislation needs to be
adopted by the Oklahoma legislature, to address many specific issues associated
with the Act and with deregulation. In May 2000, a bill addressing the specific
issues of deregulation was passed in the Oklahoma State Senate and then was
defeated in the Oklahoma House of Representatives. The Company cannot predict
what, if any, legislation will be adopted at the next legislative session.
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 for generation, transmission, distribution and customer service. The
Company filed preliminary business separation plans with the APSC on August 8,
2000. 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.
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PART II. OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
Reference is made to Item 3 of the Company's 1999 Form 10-K and to Part II,
Item 1 of the Company's Form 10-Q for the quarter ended March 31, 2000 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.
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The Company's Annual Meeting of Shareowners was held on May 18, 2000.
(b) Not applicable.
(c) The matters voted upon and the results of the voting at the Annual
Meeting were as follows:
(1) The Shareowners voted to elect the Company's nominees
for election to the Board of Directors as follows:
William E. Durrett - 40,378,745 votes for election and
no votes withheld
H. L. Hembree, III - 40,378,745 votes for election and
no votes withheld
Steven E. Moore - 40,378,745 votes for election and
no votes withheld
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)
August 11, 2000
12
<PAGE>
<TABLE>
EXHIBIT INDEX
<CAPTION>
EXHIBIT NO. DESCRIPTION
----------- -----------
<S> <C>
27.01 Financial Data Schedule
</TABLE>
