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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, 1998
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 80,771,834 Shares of Common Stock, par value $0.01 per share,
outstanding as of October 31, 1998.
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OGE ENERGY CORP.
PART I. FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
3 Months Ended 9 Months Ended
September 30 September 30
-------------------------------- ---------------------------------
1998 1997 1998 1997
-------------- -------------- -------------- --------------
(THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Electric utility......................................... $ 474,209 $ 417,612 $ 1,046,871 $ 927,637
Non-utility.............................................. 143,089 56,975 325,412 171,393
-------------- -------------- -------------- --------------
Total operating revenues............................... 617,298 474,587 1,372,283 1,099,030
-------------- -------------- -------------- --------------
OPERATING EXPENSES:
Fuel..................................................... 109,655 94,820 247,824 211,783
Purchased power.......................................... 65,107 55,081 179,189 165,931
Gas and electricity purchased for resale................. 114,679 38,855 255,183 114,314
Other operation and maintenance.......................... 68,587 79,440 227,429 226,008
Depreciation and amortization............................ 40,293 35,880 113,500 106,100
Current income taxes..................................... 65,590 43,344 92,896 61,182
Deferred income taxes, net............................... 12,038 12,617 13,061 12,566
Deferred investment tax credits, net..................... (1,287) (1,287) (3,862) (3,862)
Taxes other than income.................................. 13,316 12,569 38,925 37,690
-------------- -------------- -------------- --------------
Total operating expenses............................... 487,978 371,319 1,164,145 931,712
-------------- -------------- -------------- --------------
OPERATING INCOME........................................... 129,320 103,268 208,138 167,318
-------------- -------------- -------------- --------------
OTHER INCOME (DEDUCTIONS):
Interest income.......................................... 860 1,362 3,841 2,733
Other.................................................... (1,849) 2,012 (4,148) 1,594
-------------- -------------- -------------- --------------
Net other income (deductions).......................... (989) 3,374 (307) 4,327
-------------- -------------- -------------- --------------
INTEREST CHARGES:
Interest on long-term debt............................... 18,346 16,687 45,672 47,665
Allowance for borrowed funds used during construction.... (280) (249) (740) (473)
Other.................................................... 2,147 684 7,256 4,109
-------------- -------------- -------------- --------------
Total interest charges, net............................ 20,213 17,122 52,188 51,301
-------------- -------------- -------------- --------------
NET INCOME................................................. 108,118 89,520 155,643 120,344
PREFERRED DIVIDEND REQUIREMENTS............................ - 571 733 1,714
-------------- -------------- -------------- --------------
EARNINGS AVAILABLE FOR COMMON.............................. $ 108,118 $ 88,949 $ 154,910 $ 118,630
============== ============== ============== ==============
AVERAGE COMMON SHARES OUTSTANDING.......................... 80,772 80,743 80,772 80,746
EARNINGS PER AVERAGE COMMON SHARE.......................... $ 1.34 $ 1.10 $ 1.92 $ 1.47
EARNINGS PER AVERAGE COMMON SHARE -
ASSUMING DILUTION........................................ $ 1.33 $ 1.10 $ 1.91 $ 1.47
============== ============== ============== ==============
DIVIDENDS DECLARED PER SHARE............................... $ 0.3325 $ 0.3325 $ 0.9975 $ 0.9975
<FN>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
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CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30 December 31
1998 1997
------------- --------------
(DOLLARS IN THOUSANDS)
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ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... $ 4,370,375 $ 4,125,858
Construction work in progress................................. 50,352 25,799
-------------- ---------------
Total property, plant and equipment......................... 4,420,727 4,151,657
Less accumulated depreciation............................. 1,893,722 1,797,806
-------------- ---------------
Net property, plant and equipment............................. 2,527,005 2,353,851
-------------- ---------------
OTHER PROPERTY AND INVESTMENTS, at cost......................... 49,361 37,898
-------------- ---------------
CURRENT ASSETS:
Cash and cash equivalents..................................... 311 4,257
Accounts receivable - customers, less reserve of $3,489 and
$4,507 respectively......................................... 193,942 117,842
Accrued unbilled revenues..................................... 46,600 36,900
Accounts receivable - other................................... 11,708 11,470
Fuel inventories, at LIFO cost................................ 48,657 49,369
Materials and supplies, at average cost....................... 29,001 28,430
Prepayments and other......................................... 23,433 4,489
Accumulated deferred tax assets............................... 6,404 6,925
-------------- ---------------
Total current assets........................................ 360,056 259,682
-------------- ---------------
DEFERRED CHARGES:
Advance payments for gas...................................... 10,500 10,500
Income taxes recoverable - future rates....................... 40,592 42,549
Other......................................................... 61,848 61,385
-------------- ---------------
Total deferred charges...................................... 112,940 114,434
-------------- ---------------
TOTAL ASSETS.................................................... $ 3,049,362 $ 2,765,865
============== ===============
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stock and retained earnings............................ $ 1,059,303 $ 984,960
Cumulative preferred stock.................................... - 49,266
Long-term debt................................................ 936,548 841,924
-------------- ---------------
Total capitalization........................................ 1,995,851 1,876,150
-------------- ---------------
CURRENT LIABILITIES:
Short-term debt............................................... 94,700 1,000
Accounts payable.............................................. 80,610 77,733
Dividends payable............................................. 26,857 27,428
Customers' deposits........................................... 24,181 23,847
Accrued taxes................................................. 90,184 21,677
Accrued interest.............................................. 18,538 20,041
Long-term debt due within one year............................ 2,000 25,000
Other......................................................... 46,225 38,518
-------------- ---------------
Total current liabilities................................... 383,295 235,244
-------------- ---------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 55,119 62,023
Accumulated deferred income taxes............................. 515,018 503,952
Accumulated deferred investment tax credits................... 69,016 72,878
Other......................................................... 31,063 15,618
-------------- ---------------
Total deferred credits and other liabilities................ 670,216 654,471
-------------- ---------------
TOTAL CAPITALIZATION AND LIABILITIES............................ $ 3,049,362 $ 2,765,865
============== ===============
<FN>
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
</FN>
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CONSOLIDATED STATEMENTS OF
CASH FLOWS
(Unaudited)
9 Months Ended
September 30
1998 1997
-------------- --------------
(DOLLARS IN THOUSANDS)
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CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income......................................................... $ 155,643 $ 120,344
Adjustments to Reconcile Net Income to Net Cash:
Depreciation and amortization.................................... 113,500 106,100
Deferred income taxes and investment tax credits, net............ 9,199 8,704
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers................................ (76,100) (33,210)
Accrued unbilled revenues...................................... (9,700) (14,400)
Fuel, materials and supplies inventories....................... 141 1,837
Accumulated deferred tax assets................................ 521 4,130
Other current assets........................................... (16,314) 985
Accounts payable............................................... 2,877 (19,224)
Accrued taxes.................................................. 68,507 48,434
Accrued interest............................................... (1,503) (4,015)
Other current liabilities...................................... 7,470 1,832
Other operating activities....................................... (22,826) (6,810)
-------------- --------------
Net cash provided by operating activities.................... 231,415 214,707
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (196,769) (118,983)
Other investment activities........................................ 5,106 -
-------------- --------------
Net cash used in investing activities........................ (191,663) (118,983)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt....................................... (112,500) (265,000)
Proceeds from long-term debt....................................... 105,671 280,000
Short-term debt, net............................................... 93,700 (23,400)
Redemption of preferred stock...................................... (49,266) (113)
Retirement of treasury stock....................................... - 285
Cash dividends declared on preferred stock......................... (733) (1,714)
Cash dividends declared on common stock............................ (80,570) (80,517)
-------------- --------------
Net cash used in financing activities........................ (43,698) (90,459)
-------------- --------------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS................. (3,946) 5,265
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 4,257 2,523
-------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 311 $ 7,788
============== ==============
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)............................. $ 44,363 $ 53,261
Income taxes..................................................... $ 35,316 $ 25,067
NON-CASH INVESTING ACTIVITIES DURING THE PERIOD FOR:
Capital lease financing.......................................... $ 9,818 $ -
- --------------------------------------------------------------------------------------------------------------
<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 September
30, 1998, and December 31, 1997, and the results of operations and the
changes in cash flows for the periods ended September 30, 1998, and
September 30, 1997, 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 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, 1997.
2. In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 131, "Disclosures
About Segments of an Enterprise and Related Information." Adoption of SFAS
No. 131 is required for fiscal years beginning after December 15, 1997. The
Company will adopt this new standard effective December 31, 1998. Adoption
of this new standard will change the presentation of certain financial
information of the Company, but will not affect reported earnings.
3. In February 1998, the FASB issued SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits." Adoption of SFAS No. 132
is required for financial statements for periods beginning after December
15, 1997. The Company will adopt this new standard effective December 31,
1998. Adoption of this new standard will change the presentation of certain
disclosure information of the Company, but will not affect reported
earnings.
4. In March 1998, the American Institute of Certified Public Accountants
("AICPA") issued Statement of Position ("SOP") 98-1, "Accounting for the
Costs of Computer Software Developed or Obtained for Internal Use".
Adoption of SOP 98-1 is required for fiscal years beginning after December
15, 1998. The Company will adopt this new standard effective March 31,
1999, and management believes the adoption of this new standard will not
have a material impact on its consolidated financial position or results of
operation.
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5. In April 1998, the AICPA issued SOP 98-5, "Reporting on the Cost of
Start-Up Activities". Adoption of SOP 98-5 is required in fiscal years
beginning after December 15, 1998. The Company will adopt this new standard
effective March 31, 1999, and management believes the adoption of this new
standard will not have a material impact on its consolidated financial
position or results of operation.
6. In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and for Hedging Activities". Adoption of SFAS No. 133 is
required for financial statements for periods beginning after June 15,
1999. The Company will adopt this new standard effective January 1, 2000,
and management believes the adoption of this new standard will not have a
material impact on its consolidated financial position or results of
operation.
7. In January 1998, the Company awarded approximately 221,900 stock options,
with an exercise price of $51.875, to certain employees, subject to
shareowners' approval of the Company Stock Incentive Plan. The Stock
Incentive Plan was subsequently approved at the 1998 Annual Meeting of
Shareowners - See Item 4 "Submission of Matters to a Vote of Security
Holders" in the Company's Form 10-Q for the quarter ended June 30, 1998.
Consequently, and taking into account the two-for-one stock split
authorized by the Board of Directors on May 21, 1998, the number of stock
options outstanding at September 30, 1998, was approximately 443,800, with
an exercise price of $25.9375. These options were considered in the
calculation of Earnings Per Average Common Share - Assuming Dilution. All
references in the accompanying financial statements to the number of common
shares and per share amounts for the three month and nine month ended
September 30 periods have been restated to reflect the stock split.
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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, 1998
(respectively, the "current periods"), and the financial position as of
September 30, 1998, of the Company and its subsidiaries: Oklahoma Gas and
Electric Company ("OG&E"), Enogex Inc. and its subsidiaries ("Enogex") and
Origen and its subsidiaries ("Origen"). Approximately 77 percent and 76 percent
of the Company's revenues for the current periods consisted of regulated sales
of electricity by OG&E, a public utility, while the balance of the revenues were
provided by the non-utility operations of Enogex. Origen recently was formed and
its operations to date have been deminimis. 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. Enogex's primary operations consist of gathering and processing
natural gas, producing natural gas liquids, transporting natural gas through its
intra-state pipeline for various customers (including OG&E), marketing
electricity, natural gas and natural gas products and investing in the drilling
for and production of crude oil and natural gas. Actions of the regulatory
commissions that set OG&E's electric rates will continue to affect the Company's
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; 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, 1997, 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 increased $18.6 million or 20.8 percent in the three months
ended September 30, 1998. Of the $18.6 million increase, approximately $19.3
million was attributable to OG&E and a decrease of approximately $1.6 million
was attributable to Enogex. For the nine months ended September 30, 1998, net
income increased $35.3 million or 29.3 percent. Of the $35.3 million increase,
approximately $37.9 million was attributable to OG&E and a decrease of
approximately $4.0 million was attributable to Enogex. As explained below,
OG&E's increase in earnings was primarily attributable to higher revenues from
warmer weather and higher margin
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sales to other utilities and power marketers ("off-system sales"). Enogex
earnings in 1997 included a one-time gain of $1.6 million on the sale of certain
surplus assets. Excluding this gain, Enogex's earnings decreased $2.4 million,
in the current period, primarily due to deteriorated gas processing economics
reflecting depressed natural gas liquids prices and lower margins in drilling
and production operations due to lower prices. The Company does not expect
Enogex to meet last year's net income of $16.2 million, but remains confident
that a rebound in commodity prices would substantially improve the outlook for
Enogex. Earnings per average common share increased from $1.10 to $1.34 and from
$1.47 to $1.92 in the current periods.
REVENUES
Total operating revenues increased $142.7 million or 30.1 percent and
$273.3 million or 24.9 percent in the current periods. These increases were
attributable to increased electric sales by OG&E and significantly increased
Enogex revenues.
Increased electric sales by OG&E were primarily attributable to
significantly warmer weather and the impact of the Generation Efficiency
Performance Rider ("GEP Rider") that was authorized by the Oklahoma Corporation
Commission ("OCC") in OG&E's most recent rate order. The significantly warmer
weather resulted in increased electric utility revenue of approximately $24.6
million and $43.9 million for the current periods. The GEP Rider increased
electric utility revenue by approximately $2.1 million and $11.9 million for the
current periods. Together, these increases offset the effects of the annual rate
reduction that became effective March 5, 1997.
Warmer weather in the electric service area resulted in a 11.4 percent and
9.5 percent increase in kilowatt-hour sales to OG&E customers ("system sales").
Kilowatt-hour sales by OG&E to other utilities decreased 63.4 and 32.0 percent;
however, the summer heat drove prices of this off-system electricity to record
levels, increasing operating revenues approximately $6.0 and $16.4 million in
the current periods and at margins significantly higher than had been
experienced in the past. There can be no assurance that such margins on future
off-system sales will continue.
Enogex revenues increased $86.6 million or 128.5 percent and $153.8 million
or 75.9 percent in the current periods, largely due to increased revenues from
its marketing of natural gas and natural gas products (increases of $62.3
million and $115.5 million in the current periods). These increased gas-related
revenues were attributable primarily to significantly higher volumes sold with
little or no increase in sales prices as such commodity prices were depressed.
The recent expansion into the marketing of electricity also increased revenues
$19.0 million and $33.0 million in the current periods.
EXPENSES
Total operating expenses increased $116.7 million or 31.4 percent in the
three months ended September 30, 1998. This increase was primarily due to
increased gas and electricity purchased for resale, current income taxes, fuel
expense and purchased power, partially offset by
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a decrease in other operation and maintenance expense. Enogex's gas and
electricity purchased for resale pursuant to its gas and electricity marketing
operations increased $75.6 million or 194.6 percent in the three months ended
September 30, 1998, due to significantly higher sales volumes resulting from
Enogex's expansion into electricity marketing, expansion of natural gas
marketing and recent expansion and acquisition of natural gas and natural gas
liquids facilities. OG&E's fuel expense increased $14.8 million or 15.6 percent
primarily due to increased generation as a result of significantly warmer
weather.
In the nine months ended September 30, 1998, total operating expenses were
up $232.4 million or 24.9 percent primarily due to increased gas and electricity
purchased for resale ($140.9 million or 123.2 percent), fuel expense ($36.0
million or 17.0 percent), current income taxes and purchased power.
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 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.
OG&E's purchased power costs increased $10.0 million or 18.2 percent and
$13.3 million or 8.0 percent primarily due to increased summer demand for and
the availability of electricity at favorable prices. The start of a power
purchase contract with a cogeneration plant near Pryor, Oklahoma, from which
OG&E was obligated to purchase 110 megawatts of peaking capacity, beginning in
January 1998, also contributed to this increase. See "Liquidity and Capital
Requirements."
Other operation and maintenance expense decreased $10.9 million or 13.7
percent for the three-month period and increased $1.4 million or 0.6 percent for
the nine-month period. The three-month decrease is primarily due to reduced
costs for professional and other outside services and employee benefit costs.
However, the nine-month variance shows expenses only slightly above those of
last year.
Depreciation and amortization increased $4.4 million or 12.3 percent and
$7.4 million or 7.0 percent during the current periods due to an increase in
depreciable property and higher oil and gas production volumes (based on units
of production depreciation method).
Current income taxes increased $22.2 million or 51.3 percent and $31.7
million or 51.8 percent in the current periods primarily due to higher pre-tax
earnings.
Interest charges increased $3.1 million or 18.1 percent for the three
months ended September 30, 1998 and $0.9 million or 1.7 percent for the
nine-month period primarily due to
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higher interest charges at Enogex and costs associated with increased short-term
debt (See "Liquidity and Capital Requirements"). These increases were partially
offset by lower interest charges at OG&E.
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 1998. Short-term borrowings will
continue to be used to meet temporary cash requirements.
The Company's primary needs for capital are related to construction of new
facilities to meet anticipated demand for OG&E's utility service, to replace or
expand existing facilities in OG&E's electric utility business and to acquire
new facilities or replace or expand existing facilities at Enogex and other
non-utility businesses and, to some extent, for satisfying maturing debt and
sinking fund obligations. Capital expenditures of $194.5 million for the nine
months ended September 30, 1998, were financed with internally generated funds
and short-term borrowings.
The Company's capital structure and cash flow remained strong throughout
the current period. The Company's combined cash and cash equivalents decreased
approximately $3.9 million during the nine months ended September 30, 1998. The
decrease reflects the Company's cash flow from operations plus an increase in
short-term borrowings, net of retirement of long-term debt, construction
expenditures, Enogex acquisitions, redemption of preferred stock and dividend
payments.
In January 1998, Enogex, through a newly-formed subsidiary, Enogex Arkansas
Pipeline Corp. ("EAPC") acquired a 40 percent interest in NOARK, a natural gas
pipeline, for approximately $30 million and agreed to acquire Ozark, for
approximately $55 million. The NOARK line is a 302-mile intra-state pipeline
system that extends from near Fort Chaffee, Arkansas to near Paragould,
Arkansas. Current throughput capacity on the NOARK line is approximately 130
million cubic feet per day. The Ozark line is a 437-mile interstate pipeline
system that begins near McAlester, Oklahoma and terminates near Searcy,
Arkansas. Current throughput capacity on the Ozark line is approximately 170
million cubic feet per day.
In July 1998, EAPC acquired Ozark and contributed Ozark to the NOARK
partnership. The two pipelines will be integrated into a single, interstate
transmission system at an estimated additional cost of $15 million. After the
integration, which is to be funded by EAPC, EAPC will own a 75 percent interest
in the NOARK partnership and Southwestern Energy Pipeline Co. will retain its 25
percent interest in the partnership.
In June 1998, NOARK Pipeline Finance, L.L.C., a finance company subsidiary
of NOARK, issued $80.0 million aggregate principal amount of unsecured 7.15
percent Notes due
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2018. These Notes are entitled to the benefits of a guaranty issued by Enogex
pursuant to which Enogex has guaranteed 40 percent (subject to certain
adjustments) of the principal, interest and premium on such Notes. The remaining
60 percent of the principal, interest and premium on such Notes are guaranteed
by Southwestern Energy Company, the parent company of Southwestern Energy
Pipeline Company. The proceeds from the sale of the Notes were loaned by NOARK
Pipeline Finance, L.L.C. to NOARK and utilized by NOARK (i) to repay a bank
revolving line of credit (approximately $29.75 million), (ii) to repay an
outstanding term loan from Enogex (approximately $48.825 million) and (iii) for
general corporate purposes.
In July 1998, Enogex agreed to lease underground gas storage from Central
Oklahoma Oil and Gas Corp. ("COOG"). COOG currently leases gas storage capacity
to OG&E. As part of this lease transaction, the Company made a $12 million
secured loan to an affiliate of COOG. The loan is repayable in 2003 and is
secured by the assets and stock of COOG.
As previously reported, in January 1998, OG&E filed an application with the
OCC seeking approval to revise an existing cogeneration contract with
Mid-Continent Power Company ("MCPC"), a cogeneration plant near Pryor, Oklahoma.
As part of this transaction, the Company agreed to purchase the stock of
Oklahoma Loan Acquisition Corporation ("OLAC"), the company that owns the MCPC
plant, for approximately $25 million. OG&E obtained the required regulatory
approvals from the OCC, APSC and FERC. If the transaction was completed, the
term of the existing cogeneration contract would have been reduced by four and
one-half years, which would have reduced the amounts to be paid by OG&E, and
would have provided savings for its Oklahoma customers, of approximately $46
million as compared to the existing cogeneration contract. Following an
arbitrator's decision that the owner of the stock of OLAC could not sell the
stock of OLAC to the Company until it had offered such stock to a third party on
the same terms as it was offered to the Company, the third party purchased the
stock of OLAC and assumed ownership of the cogeneration plant in October 1998.
The effect of this transaction is that OG&E's original contract with the
cogeneration plant remains in place.
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, 1998 and June 30, 1998 and
to "Management's Discussion and Analysis" and Notes 9 and 10 of Notes to the
Consolidated Financial Statements in the Company's 1997 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
10
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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 will 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 will be replaced by Y2K ready packaged applications.
The Company continues to address the Y2K issues in an aggressive manner.
This is reflected by the January 1, 1997 implementation throughout the Company
of SAP Enterprise Software, which is Y2K ready, for the financial systems. The
SAP installation significantly reduced the potential risks in our older computer
systems. The Company is making significant progress towards the implementation,
in February 1999, of the enterprise-wide software system for customer systems.
In addition to significantly reducing the potential risks of its current
customer systems, the Company is set to streamline work processes in customer
service and power delivery by integrating separate systems into a single system
using the enterprise-wide software system. This new single system will also
provide for a more flexible automated billing system and enhancements in
handling customer service orders, energy outage incidents and customer services.
In October of 1997, the Company formed a multi-functional Y2K Project Team
of experienced and knowledgeable members from each business unit to review and
test its operational systems in an effort to further eliminate any potential
problems, should they exist. The team provides regular monthly reports on its
progress to the Y2K Executive Steering Committee and senior management as well
as helping prepare presentations to the Board of Directors.
The Company's Year 2000 effort generally follows a three-phase process:
Phase I - Inventory and Assess Y2K Issues
Phase II - Determine Y2K Readiness of Vendors, Suppliers & Customers
Phase III - Correct, Test, Implement Solutions and Contingency Planning
11
<PAGE>
STATE OF READINESS
At present, the Company has substantially completed the internal inventory
and assessment (Phase 1) of the Year 2000 plan. Vendor surveys are still being
sent out and their responses are being recorded. Additional notices, however,
will have to be sent to vendors that have not responded to our original requests
for information (Phase II). Remediation efforts are ongoing and even though
contingency planning is a normal part of our business, plans must be prepared to
include specific activities with regard to Y2K issues (Phase III).
In addition, as a part of the Company's three-year lease agreement for
personal computers, all new personal computers are being issued with operating
systems and application software that is Y2K ready. All existing personal
computers will be upgraded with Y2K ready operating systems before the turn of
the century. For embedded and plant operational systems; the Company has
generally completed the evaluative process and is commencing corrective plans.
In particular, the Company's Energy Management System (EMS) that monitors
transmission interconnections and automatically signals generation output
changes, has been contracted for replacement in 1999. Equipment has been ordered
and software is currently being configured.
The Company is also participating in an "Electric System Readiness
Assessment" program, which provides monthly reports to the Southwest Power Pool
(SPP) and the North American Electric Reliability Council (NERC). The responses
from all participating companies are being compiled for an industry-wide status
report to the Department of Energy (DOE).
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. Other than the costs
associated with the mainframe conversion, the enterprise software installations
and the EMS replacement, the Company's costs to date for Y2K issues have been
less than $1 million. The Company expects to spend less than $5 million in 1999.
These costs represent estimates, however, and there can be no assurance that
actual costs associated with the Company's Y2K issues will not be higher.
RISKS OF YEAR 2000 ISSUES
As described above, the Company has made significant progress in the
implementation of its Year 2000 plan. Based upon the information currently known
regarding its internal operations and assuming successful and timely completion
of its remediation plan, the Company does not anticipate significant business
disruptions from its internal systems due to the Y2K issue. However, the Company
may possibly experience limited interruptions to some aspects of its activities,
whether information technology, operational, administrative or otherwise, and
the
12
<PAGE>
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 or gas sales, reductions in power production or
transmission or internal functional and administrative difficulties on the part
of the Company. The Company is not presently aware of any such situations,
however, occurrences of this type, if severe, could have material adverse
impacts upon the business, operating results or financial condition of the
Company and there can be no assurance that the Company will be able to identify
and correct all aspects of the Year 2000 problem that effect it in sufficient
time, that it will develop adequate contingency plans or that the costs of
achieving Y2K readiness will not be material.
The Company plans to develop contingency plans for all material areas of
Year 2000 risk and is in the process of preparing such plans. Among the areas
contingency planning will address include delays in completion in the Company's
remediation plans, failure or incomplete remediation results and failure of key
third party contacts to be Y2K ready.
FORWARD LOOKING STATEMENTS
The foregoing discussion regarding the timing, effectiveness,
implementation, and costs of the Company's Year 2000 efforts, contains
forward-looking statements, which are based on management's best estimates
derived from assumptions. These forward-looking statements involve inherent
risks and uncertainties, and actual results could differ materially from those
contemplated by such statements. Factors that might cause material differences
include, but are not limited to, availability of key Year 2000 personnel, the
Company's ability to locate and correct all relevant computer code, the
readiness of third parties, and the Company's ability to respond to unforeseen
Year 2000 complications.
13
<PAGE>
PART II. OTHER INFORMATION
Item 1 LEGAL PROCEEDINGS
Reference is made to Item 3 of the Company's 1997 Form 10-K and to Part II,
Item 1 of the Company's Form 10-Q for the quarters ended March 31, 1998 and June
30, 1998 for a description of certain legal proceedings presently pending.
Except as described below, there are no new significant cases to report against
the Company or its subsidiaries and there have been no significant changes in
the previously reported proceedings.
As reported in the Company's Form 10-K for the year ended December 31,
1997, Trigen-Oklahoma City Energy Corporation sued OG&E in the United States
District Court, Western District of Oklahoma, Case No. CIV-96-1595-M. In the
third quarter of 1998, OG&E withdrew its counterclaim. The case is currently
scheduled for trial on December 1, 1998. While OG&E cannot predict the outcome
of this proceeding, OG&E believes that it will not have a material adverse
effect on the Company's or OG&E's 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
None
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.
OGE ENERGY CORP.
(Registrant)
By /s/ Donald R. Rowlett
----------------------------------------------
Donald R. Rowlett
Controller Corporate Accounting
(On behalf of the registrant and in
his capacity as Controller Corporate Accounting)
November 13, 1998
15
<PAGE>
<TABLE>
EXHIBIT INDEX
<CAPTION>
EXHIBIT INDEX DESCRIPTION
- ------------- -----------
<S> <C>
27.01 Financial Data Schedule
</TABLE>
<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 September 30, 1998 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-30-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,527,005
<OTHER-PROPERTY-AND-INVEST> 49,361
<TOTAL-CURRENT-ASSETS> 360,056
<TOTAL-DEFERRED-CHARGES> 112,940
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,049,362
<COMMON> 808
<CAPITAL-SURPLUS-PAID-IN> 512,092
<RETAINED-EARNINGS> 546,403
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,059,303
0
0
<LONG-TERM-DEBT-NET> 936,548
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 94,700
<LONG-TERM-DEBT-CURRENT-PORT> 2,000
0
<CAPITAL-LEASE-OBLIGATIONS> 12,487
<LEASES-CURRENT> 2,662
<OTHER-ITEMS-CAPITAL-AND-LIAB> 941,662
<TOT-CAPITALIZATION-AND-LIAB> 3,049,362
<GROSS-OPERATING-REVENUE> 1,372,283
<INCOME-TAX-EXPENSE> 102,095
<OTHER-OPERATING-EXPENSES> 1,062,050
<TOTAL-OPERATING-EXPENSES> 1,164,145
<OPERATING-INCOME-LOSS> 208,138
<OTHER-INCOME-NET> (307)
<INCOME-BEFORE-INTEREST-EXPEN> 207,831
<TOTAL-INTEREST-EXPENSE> 52,188
<NET-INCOME> 155,643
733
<EARNINGS-AVAILABLE-FOR-COMM> 154,910
<COMMON-STOCK-DIVIDENDS> 80,570
<TOTAL-INTEREST-ON-BONDS> 45,672
<CASH-FLOW-OPERATIONS> 229,162
<EPS-PRIMARY> 1.92
<EPS-DILUTED> 1.91
</TABLE>
