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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 March 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-12579
OGE Energy Corp.
(Exact name of registrant as specified in its charter)
Oklahoma 73-1481638
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
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 77,863,370 Shares of Common Stock, par value $0.01 per share,
outstanding as of April 30, 2000.
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OGE ENERGY CORP.
PART I. FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
3 MONTHS ENDED
MARCH 31
2000 1999
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(THOUSANDS EXCEPT PER SHARE DATA)
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OPERATING REVENUES:
Electric utility......................................... $ 245,332 $ 250,144
Non-utility subsidiaries................................. 336,249 128,061
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Total operating revenues............................... 581,581 378,205
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OPERATING EXPENSES:
Fuel..................................................... 62,000 57,681
Purchased power.......................................... 60,542 59,124
Gas and electricity purchased for resale................. 249,541 101,457
Other operation and maintenance.......................... 116,275 74,344
Depreciation and amortization............................ 44,919 38,263
Taxes other than income.................................. 16,108 13,261
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Total operating expenses............................... 549,385 344,130
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OPERATING INCOME........................................... 32,196 34,075
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OTHER INCOME (EXPENSES), net............................... (201) 317
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EARNINGS BEFORE INTEREST AND TAXES......................... 31,995 34,392
INTEREST INCOME (EXPENSES):
Interest income.......................................... 1,609 493
Interest on long-term debt............................... (25,387) (15,022)
Interest on trust preferred securities................... (4,317) ---
Other interest charges................................... (5,466) (3,278)
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Net interest income (expenses)......................... (33,561) (17,807)
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EARNINGS (LOSS) BEFORE INCOME TAXES........................ (1,566) 16,585
PROVISION (BENEFIT) FOR INCOME TAXES....................... (2,342) 5,453
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NET INCOME................................................. $ 776 $ 11,132
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AVERAGE COMMON SHARES OUTSTANDING.......................... 77,863 78,267
EARNINGS (LOSS) PER AVERAGE COMMON SHARE................... $ 0.01 $ 0.14
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EARNINGS PER AVERAGE COMMON SHARE - ASSUMING DILUTION...... $ 0.01 $ 0.14
============== ==============
DIVIDENDS DECLARED PER SHARE............................... $ 0.3325 $ 0.3325
<FN>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
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CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
MARCH 31 DECEMBER 31
2000 1999
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(DOLLARS IN THOUSANDS)
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ASSETS
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 3,474 $ 7,271
Accounts receivable - customers, less reserve of $4,783 and
$5,270, respectively........................................ 205,994 263,708
Accrued unbilled revenues..................................... 37,600 40,200
Accounts receivable - other................................... 36,762 10,462
Fuel inventories, at LIFO cost................................ 133,627 117,185
Materials and supplies, at average cost....................... 36,711 39,194
Prepayments and other......................................... 16,964 16,911
Accumulated deferred tax assets............................... 8,016 8,729
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Total current assets........................................ 479,148 503,660
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OTHER PROPERTY AND INVESTMENTS, at cost......................... 32,048 31,012
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PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... 5,218,012 5,209,783
Construction work in progress................................. 75,123 56,553
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Total property, plant and equipment......................... 5,293,135 5,266,336
Less accumulated depreciation............................. 2,055,631 2,024,349
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Net property, plant and equipment........................... 3,237,504 3,241,987
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DEFERRED CHARGES:
Advance payments for gas...................................... 11,800 11,800
Income taxes recoverable through future rates................. 39,432 39,692
Other......................................................... 105,849 93,183
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Total deferred charges...................................... 157,081 144,675
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TOTAL ASSETS.................................................... $ 3,905,781 $ 3,921,334
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LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt............................................... $ 153,700 $ 589,100
Accounts payable.............................................. 187,787 161,183
Dividends payable............................................. 25,889 25,889
Customers' deposits........................................... 22,278 22,138
Accrued taxes................................................. 15,538 41,215
Accrued interest.............................................. 31,043 28,191
Long-term debt due within one year............................ 59,000 59,000
Other......................................................... 56,507 40,145
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Total current liabilities................................... 551,742 966,861
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LONG-TERM DEBT.................................................. 1,650,675 1,250,532
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DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 19,810 16,686
Accumulated deferred income taxes............................. 574,709 566,137
Accumulated deferred investment tax credits................... 61,291 62,578
Other......................................................... 53,288 39,161
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Total deferred credits and other liabilities................ 709,098 684,562
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STOCKHOLDERS' EQUITY:
Common stockholders' equity................................... 441,847 441,847
Retained earnings............................................. 552,419 577,532
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Total stockholders' equity.................................. 994,266 1,019,379
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TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 3,905,781 $ 3,921,334
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<FN>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
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CONSOLIDATED STATEMENTS OF
CASH FLOWS
(UNAUDITED)
3 MONTHS ENDED
MARCH 31
2000 1999
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(DOLLARS IN THOUSANDS)
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CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income......................................................... $ 776 $ 11,132
Adjustments to Reconcile Net Income to Net Cash:
Depreciation and amortization.................................... 44,919 38,263
Deferred income taxes and investment tax credits, net............ 8,197 (4,884)
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers................................ 57,714 6,279
Accrued unbilled revenues...................................... 2,600 (100)
Fuel, materials and supplies inventories....................... (13,959) (7,580)
Accumulated deferred tax assets................................ 713 56
Other current assets........................................... (26,353) 12,593
Accounts payable............................................... 26,604 (2,134)
Accrued taxes.................................................. (25,677) (3,218)
Accrued interest............................................... 2,852 145
Other current liabilities...................................... 16,502 (21,709)
Other operating activities....................................... 5,860 12,897
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Net cash provided from operating activities.................. 100,748 41,740
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CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (43,422) (40,838)
Other investing activities......................................... 166 ---
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Net cash used in investing activities........................ (43,256) (40,838)
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CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt....................................... 400 000 ---
Short-term debt, net............................................... (435,400) 107,700
Redemption of preferred stock...................................... --- (80,330)
Cash dividends declared on common stock............................ (25,889) (25,868)
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Net cash provided from (used in) financing activities........ (61,289) 1,502
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NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. (3,797) 2,404
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 7,271 378
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CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 3,474 $ 2,782
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)............................. $ 29,904 $ 15,385
Income taxes..................................................... $ 4,900 $ 4,150
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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 CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. The condensed consolidated financial statements included herein have been
prepared by OGE Energy Corp. (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 and its subsidiaries as of March 31,
2000, and December 31, 1999, and the results of operations and the changes
in cash flows for the periods ended March 31, 2000, and March 31, 1999,
have been included and are of a normal recurring nature. Certain amounts
have been reclassified on the financial statements to conform with the 2000
presentation.
The results of operations for such interim periods are not necessarily
indicative of the results for the full year. It is suggested that these
condensed consolidated financial statements be read in conjunction with the
consolidated 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 holding company, which was incorporated in August 1995 in
the State of Oklahoma. The Company is not engaged in any business
independent of that conducted through its subsidiaries, Oklahoma Gas and
Electric Company ("OG&E"), Enogex Inc. and Enogex Inc.'s subsidiaries
("Enogex"), and OGE Energy Capital Trust I, a financing trust established
in 1999.
OG&E is a regulated public utility that owns and operates an interconnected
electric production, transmission and distribution system.
Enogex is an Oklahoma intrastate natural gas pipeline company that also
conducts related operations, through its subsidiaries, in interstate and
intrastate gas transmission, natural gas gathering, natural gas processing,
natural gas and electricity marketing, and oil and gas development and
production.
3. In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting
for Derivative Instruments and for Hedging Activities", with an effective
date for periods beginning after June 15, 1999. In July 1999, the FASB
issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No. 133". As
a result of SFAS No. 137, adoption of SFAS No. 133 is now required for
financial statements for periods beginning after June 15, 2000. SFAS No.
133 sweeps in a
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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
consolidated financial position or results of operation.
4. Enogex, in the normal course of business, enters into fixed price contracts
for either the purchase or sale of natural gas and electricity at future
dates. Due to fluctuations in the natural gas and electricity markets, the
Company buys or sells natural gas and electricity futures contracts, swaps
or options to hedge the price and basis risk associated with the
specifically identified purchase or sales contracts. Additionally, the
Company may use these contracts as an enhancement or speculative trade,
subject to the Company's policies on risk management. For qualifying
hedges, the Company accounts for changes in the market value of futures
contracts as a deferred gain or loss until the production month for hedged
transactions, at which time the gain or loss on the natural gas or
electricity futures contract, swap or option is recognized in the results
of operations. As market values change, the Company recognizes the gain or
loss on enhancement or speculative contracts in the results of operations.
ITEM 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
OVERVIEW
The following discussion and analysis presents factors which affected the
results of operations for the three months ended March 31, 2000 (the "current
period"), and the financial position as of March 31, 2000, of the Company and
its subsidiaries: OG&E and Enogex. Unless indicated otherwise, all comparisons
are with the corresponding period of the prior year. For the three months ended
March 31, 2000, approximately 58 percent of the Company's revenues consisted of
the non-utility operations of Enogex, while the remaining 42 percent was
provided by the regulated sales of electricity by OG&E, a public utility.
Revenues from sales of electricity are somewhat seasonal, with a large portion
of OG&E's annual electric revenues occurring during the summer months when the
electricity needs of its customers increase. Actions of the regulatory
commissions that set OG&E's electric rates will continue to affect the Company's
financial results.
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
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and Texas. Enogex purchased Transok from Tejas Energy LLC, an affiliate of Shell
Oil Company, for $710.3 million, which includes assumption of $173 million of
long-term debt.
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
The current period net income of $0.8 million represents a decrease of
$10.4 million. OG&E's earnings decreased approximately $13.4 million while
Enogex had an increase in net income of $4.4 million. A decrease of $1.4 million
was attributable to increased expenses at the corporate level. As explained
below, OG&E's decrease in earnings was primarily attributable to lower revenues
from sales to OG&E customers and higher operating expenses. Enogex's earnings
increased due to the positive effects from its acquisition of Transok and from
increased sales volumes and prices in natural gas gathering and transportation;
gas processing and natural gas liquids marketing and marketing of natural gas.
Earnings per average common share decreased to $0.01 from $0.14 in the prior
period.
REVENUES
Total operating revenues increased $203.4 million or 53.8 percent. The
increase was attributable to significantly increased Enogex revenues reflecting
in large part its acquisition of Transok in July 1999. The increased revenues at
Enogex were partially offset by a small decrease at OG&E. Decreased electric
sales by OG&E were primarily attributable to lower recoveries (approximately
$4.1 million) under the Generation Efficiency Performance Rider ("GEP Rider"),
lower recoveries (approximately $0.9 million) under the Acquisition Premium
Credit Rider ("APC Rider") and milder weather in the Company's service area (see
"Regulation and Rates" - "Recent Regulatory Matters"). Growth in the electric
service area resulted in a 4.1 percent increase in electric utility
kilowatt-hour sales to OG&E customers (system sales). The increase in system
sales partially offset the effects of the GEP Rider, the APC Rider and the
milder weather. Kilowatt-hour sales to other utilities and power marketers
("off-system sales") increased significantly, however, off-system sales are
generally priced at much lower prices per kilowatt-hour and have less impact on
operating revenues and earnings than system sales.
Enogex revenues increased $208.2 million or 162.6 percent in the current
period, largely due to the inclusion of the revenues from Transok's operations
and increased sales activity pursuant to its trading and energy services unit.
The integration of Transok's pipeline with those of Enogex has increased gas
transportation revenue and provided Enogex's gas marketing unit with a better
platform to market natural gas.
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EXPENSES
Total operating expenses increased $205.3 million or 59.6 percent in the
current period. This increase was primarily due to increased fuel, gas and
electricity purchased for resale, other operation and maintenance, and
depreciation. With the exception of fuel and purchased power, these expense
items were attributable in large part to the inclusion of Transok's operations.
Enogex's gas and electricity purchased for resale pursuant to its gas and
electricity marketing operations increased $148.1 million or 146.0 percent in
the current period due to increased volume and prices of natural gas purchased
for resale to third parties.
OG&E's purchased power costs increased $1.4 million or 2.4 percent due to
an increase in transmission charges associated with off-system sales.
Depreciation and amortization increased $6.7 million or 17.4 percent due to
an increase in depreciable property and higher oil and gas production volumes
(based on units of production depreciation method) and the acquisition of
Transok in July 1999.
Fuel expense increased $4.3 million or 7.5 percent primarily due to an
increase in generation levels, resulting from the increase in system and
off-system sales and less favorable prices of electricity for purchase. In the
first quarter of 1999, there was an availability of electricity for purchase at
favorable prices, which OG&E utilized and thereby decreased its generation
levels. Variances in the actual cost of fuel used in electric generation and
certain purchased power costs, as compared to that component in cost-of-service
for ratemaking, are passed through to OG&E'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. owns and operates a pipeline business that
delivers natural gas to the generating stations of OG&E. The OCC, the APSC and
the FERC have authority to examine the appropriateness of any gas transportation
charges or other fees OG&E pays Enogex, which OG&E seeks to recover through the
fuel adjustment clause or other tariffs. See "Regulation and Rates."
Other operation and maintenance increased $41.9 million or 56.4 percent,
primarily due to the acquisition of Transok in July 1999, increased natural gas
purchases, increased employee benefit costs and miscellaneous corporate
expenses.
Interest charges increased $16.9 million or 92.2 percent primarily due to
increased long-term debt at Enogex and due to interest on the trust preferred
securities. The proceeds from those securities were used to repay short-term
debt incurred to finance the acquisition of Transok. See "Liquidity and Capital
Requirements."
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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 OG&E's utility service, to replace or
expand existing facilities in OG&E's electric utility business, to replace or
expand existing facilities in its non-utility businesses, to acquire new
non-utility facilities or businesses and to some extent, for satisfying maturing
debt. The Company's capital expenditures for the current period of $43.4 million
were financed with internally generated funds and short-term borrowings.
The Company meets its cash needs through a combination of internally
generated funds, permanent financing and short-term borrowings. The Company
expects that internally generated funds will be adequate during 2000 to meet
anticipated construction expenditures, while maturities of long-term debt at
OG&E will require permanent financings, with the amount and type dependent on
market conditions at the time. OG&E 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. Enogex has
long-term debt of $58 million and $1 million maturing in the third and fourth
quarters of 2000, respectively. Management anticipates that cash flows from
operations and short-term debt will be sufficient to retire the $59 million in
long-term debt at Enogex. Short-term borrowings will continue to be used to meet
temporary cash requirements. In January 2000, the Company 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 has acquired two gas turbine generators for use at OG&E's
Horseshoe Lake Generating Station. These two generators will produce
approximately 50 megawatts of additional peak-load each. The total cost of this
project is expected to be approximately $47 million. In August 1999, OG&E
announced the reactivation of two of its generators at its Mustang Generating
Station that have been idle for several years. These two generators together
produce approximately 115 megawatts of additional peak-load. The total cost of
this reactivation project is expected to be approximately $9 million. During the
summer of 2000, OG&E plans to begin using these four generators, increasing its
electric generating capacity by approximately 4 percent.
The Company's capital structure and cash flow remained strong throughout
the current period. The Company's combined cash and cash equivalents decreased
approximately $3.8 million during the three months ended March 31, 2000. The
decrease reflects the Company's cash flow from operations, net of construction
expenditures, proceeds from long-term debt, short-term debt and dividend
payments.
As discussed previously, on July 1, 1999, Enogex completed its acquisition
of Transok for approximately $710.3 million, which includes assumption of $173
million of long-term debt. The purchase of Transok was temporarily funded
through a $560 million revolving credit agreement with a consortium of banks
with Bank One, N.A. serving as agent. On October 21,
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1999, the financing trust subsidiary of the Company issued $200 million of 8.375
percent trust preferred securities and all of the proceeds were used to repay a
portion of outstanding borrowings under the revolving credit agreement
implemented in connection with the acquisition of Transok.
On January 14, 2000, Enogex sold $400 million of 8.125 percent senior
unsecured notes due January 15, 2010. Enogex entered into a series of interest
rate swap agreements to manage interest costs associated with this $400 million
issue. The effect of these swap agreements reduces the overall effective
interest rate from 8.125 percent to 6.6875 percent during the first year. The
proceeds from the sale of this new debt were used to repay the remaining balance
of the temporary short-term debt Enogex owed the Company associated with the
Transok acquisition and for general corporate purposes.
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" and Item 5 - "Other Information" of this Form 10-Q and to
"Management's Discussion and Analysis" and Notes 10 and 11 of Notes to the
Consolidated Financial Statements in the Company's 1999 Form 10-K.
REGULATION AND RATES
OG&E's retail electric tariffs in Oklahoma are regulated by the OCC, and in
Arkansas by the APSC. The issuance of certain securities by OG&E is also
regulated by the OCC and the APSC. OG&E's wholesale electric tariffs, short-term
borrowing authorization and accounting practices are subject to the jurisdiction
of the FERC. The Secretary of the Department of Energy has jurisdiction over
some of OG&E's facilities and operations.
RECENT REGULATORY MATTERS
On January 12, 2000, the OCC Staff (the "Staff") filed three applications
to address various aspects of OG&E's electric rates. Two of the applications
were expected, while the third pertains to recoveries under OG&E's fuel
adjustment clause. The first application relates to the completion on March 1,
2000, of the recovery of the amortization premium paid by OG&E 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
OG&E to Enogex and being recovered by OG&E from its ratepayers. OG&E consented
to this action and in March 2000, the OCC approved the APC Rider for $10.7
million annually.
The second application relates to a review of the GEP Rider (discussed
below), which, as part of the OCC's 1997 Order, was scheduled for review in
March 2000. OG&E collected approximately $20.8 million pursuant to the GEP Rider
during 1999. A hearing on the GEP Rider is scheduled in May 2000 and OG&E
intends to support the retention of the GEP Rider with only minor modifications.
The final application relates to a review of 1999 fuel cost
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recoveries. OG&E assumes that this application also will be used to address the
competitive bid process of its gas transportation service. The Company cannot
predict the precise outcome of these proceedings at this time, but does not
expect that they will have a material effect on its operations.
In February 1997, the OCC issued an order (the "1997 Order") that, among
other things, directed OG&E 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 OG&E
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 OG&E 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, OG&E 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, OG&E 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, OG&E offered to discount Enogex's bid from $33.4 million annually to
$25.2 million annually. OG&E has executed a new gas transportation contract with
Enogex under which Enogex would continue serving the needs of OG&E's power
plants at a price to be paid by OG&E of $33.4 million annually and, if OG&E's
proposal had been approved by the OCC, OG&E 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 OG&E'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 OG&E's gas-fired plants be awarded to parties other than Enogex. The
Staff also filed testimony stating in substance that OG&E's electric rates as a
whole were appropriate and did not warrant a rate review. OG&E 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, OG&E withdrew its application, which withdrawal was
approved by the OCC in December 1999. Based on filed testimony, OG&E believes
that Enogex properly won the competitive bid and, unless OG&E's decision to
award its gas transportation service to Enogex is abrogated by order of the OCC
(which order is upheld on appeal), that it intends to fulfill its obligations
under its new gas transportation contract with Enogex at a price of $33.4
million annually. Whether OG&E will be able to recover the entire amount from
its ratepayers has not been determined as previously mentioned.
On April 4, 2000, the Staff filed testimony proposing an annual GEP Rider
incentive of $7.07 million for OG&E, compared with $13.26 million under current
GEP Rider incentive factors. The current GEP Rider is designed so that when
OG&E'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, OG&E is allowed to collect, through the GEP Rider, one-third of
the amount by which OG&E's average annual cost of fuel comes in below 96.261
percent of the average of the other specified utilities. If OG&E's fuel cost
exceeds 103.739 percent of the
10
<PAGE>
stated average, the Company will not be allowed to recover one-third of the fuel
costs above that average from Oklahoma customers. In its April 4, 2000
testimony, the Staff stated that they continue to support incentive programs
that reward superior performance, but in their view the current GEP Rider is not
functioning as the Staff had originally envisioned it.
The Staff proposes three key changes to the GEP Rider: (i) modifying OG&E'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 OG&E's costs exceed
the new peer group by changing the percentage above which OG&E will not be
allowed to recover one-third of the fuel costs from Oklahoma customers from
103.739 percent to 101.0 percent; and (iii) reducing OG&E's share of cost
savings as compared to its new peer group from 33 percent to 25 percent. Other
participants in the proceedings, including the office of the Oklahoma Attorney
General, have filed testimony seeking to modify substantially the GEP Rider. The
Company cannot predict the ultimate outcome of this proceeding at this time, but
does not expect that it will have a material effect on its operations.
STATE RESTRUCTURING INITIATIVES
OKLAHOMA: As previously reported, Oklahoma enacted in April 1997 the
Electric Restructuring Act of 1997 (the "Act"), which is designed to provide for
choice by retail customers of their electric supplier by July 1, 2002. Various
amendments to the Act were enacted in 1999 and 1998. The Oklahoma legislature is
in the process of considering additional implementing legislation, which will
address many specific issues associated with the Act and with deregulation.
Separate bills have been passed by the Oklahoma House and Oklahoma Senate and
are currently in conference. The Company cannot predict what, if any,
legislation will be adopted. Nevertheless, the Company expects to remain a
competitive supplier of electricity.
ARKANSAS: In April 1999, Arkansas became the 18th state to pass a law
calling for restructuring of the electric utility industry at the retail level.
The new law targets customer choice of electricity providers by January 1, 2002.
The new law also provides that utilities owning or controlling transmission
assets must transfer control of such transmission assets to an independent
system operator, independent transmission company or regional transmission
group, if any such organization has been approved by the FERC. Other provisions
of the new law permit municipal electric systems to opt in or out, permit
recovery of stranded costs and transition costs and require filing of unbundled
rates by July 1, 2000 for generation, transmission, distribution and customer
service. The APSC has established a timetable to establish rules implementing
the Arkansas restructuring statutes. The new law will significantly affect
OG&E's future Arkansas operations. OG&E'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, the FERC issued Order 2000 to advance the formation of
Regional Transmission Organizations ("RTOs"). The rule requires that each public
utility that owns,
11
<PAGE>
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.
REPORT OF BUSINESS SEGMENTS
The Company's electric utility operations are conducted through OG&E, an
operating public utility engaged in the generation, transmission, distribution
and sale of electric energy. The non-utility operations are conducted through
Enogex. Enogex is engaged in gathering and processing natural gas, producing
natural gas liquids, transporting natural gas through its pipelines in Oklahoma
and Arkansas for various customers (including OG&E), marketing electricity,
natural gas and natural gas liquids and investing in the drilling for and
production of crude oil and natural gas. The following is the Company's business
segment results for the current period.
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 2000 1999
================================================================================
<S> <C> <C>
Operating Information:
Operating Revenues
Electric utility............................. $ 245,332 $ 250,144
Non-utility.................................. 365,114 154,350
Intersegment revenues (A).................. (28,865) (26,289)
- --------------------------------------------------------------------------------
Total.................................... $ 581,581 $ 378,205
================================================================================
Net Income
Electric utility............................. $ (3,226) $ 10,189
Non-utility.................................. 4,002 943
- --------------------------------------------------------------------------------
Total.................................... $ 776 $ 11,132
================================================================================
</TABLE>
(A) Intersegment revenues are recorded at prices comparable to those of
unaffiliated customers and are affected by regulatory considerations.
12
<PAGE>
PART II. OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
Reference is made to Item 3 of the Company's 1999 Form 10-K for a
description of certain legal proceedings presently pending. There are no new
significant cases to report against the Company or its subsidiaries and there
have been no notable changes in the previously reported proceedings, except as
set forth below:
Reference is made to paragraph 6 and 7 of Item 3 of the Company's 1999 Form
10-K for a description of: (i) qui tam cases brought by Jack J. Grynberg against
OG&E, Enogex, subsidiaries of Enogex and more than 300 other entities (the
"Grynberg matter"), and (ii) the amended class action petition by Quinque
Operating Company, on behalf of itself and others (the "Quinque lawsuit"),
alleging among other things, mismeasurements of gas volume and BTU content by
approximately 200 defendants, including OG&E, Enogex and two subsidiaries of
Enogex, including Transok. As previously reported, the Company filed its notice
with the Multi-district Litigation Panel ("MDL Panel") advising the MDL Panel
that the Qunique lawsuit involved the same measurement issues and was a
potential tag-along to the Grynberg matters. On April 10, 2000, the MDL Panel
entered its order transferring and consolidating on pretrial purposes the
Quinque lawsuit with the Grynberg matter. This consolidated case is now before
the United States District Court for the District of Wyoming.
ITEM 5 OTHER INFORMATION
On May 8, 2000, Eric B. Weekes was named Treasurer.
ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
27.01 - Financial Data Schedule.
(b) Reports on Form 8-K
None
13
<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.
OGE ENERGY CORP.
(Registrant)
By /s/ Donald R. Rowlett
----------------------------------------------
Donald R. Rowlett
Vice President and Controller
(On behalf of the registrant and in his capacity
as Controller Corporate Accounting)
May 12, 2000
14
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the OGE
Energy Corp. Consolidated Statements of Income, Balance Sheets, and Statements
of Cash Flows as reported on Form 10-Q as of March 31, 2000 and is qualified in
its entirety by reference to such Form 10-Q.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> MAR-31-2000
<PERIOD-END> MAR-31-2000
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,237,504
<OTHER-PROPERTY-AND-INVEST> 32,048
<TOTAL-CURRENT-ASSETS> 479,148
<TOTAL-DEFERRED-CHARGES> 157,081
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,905,781
<COMMON> 778
<CAPITAL-SURPLUS-PAID-IN> 441,069
<RETAINED-EARNINGS> 552,419
<TOTAL-COMMON-STOCKHOLDERS-EQ> 994,266
0
0
<LONG-TERM-DEBT-NET> 1,650,675
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 153,700
<LONG-TERM-DEBT-CURRENT-PORT> 59,000
0
<CAPITAL-LEASE-OBLIGATIONS> 9,607
<LEASES-CURRENT> 2,058
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,036,475
<TOT-CAPITALIZATION-AND-LIAB> 3,905,781
<GROSS-OPERATING-REVENUE> 581,581
<INCOME-TAX-EXPENSE> (2,342)
<OTHER-OPERATING-EXPENSES> 549,385
<TOTAL-OPERATING-EXPENSES> 547,043
<OPERATING-INCOME-LOSS> 34,538
<OTHER-INCOME-NET> 1,408
<INCOME-BEFORE-INTEREST-EXPEN> 35,946
<TOTAL-INTEREST-EXPENSE> 35,170
<NET-INCOME> 776
0
<EARNINGS-AVAILABLE-FOR-COMM> 776
<COMMON-STOCK-DIVIDENDS> 25,889
<TOTAL-INTEREST-ON-BONDS> 25,387
<CASH-FLOW-OPERATIONS> 100,748
<EPS-BASIC> 0.01
<EPS-DILUTED> 0.01
</TABLE>
