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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, 1999
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 77,801,317 Shares of Common Stock, par value $0.01 per share,
outstanding as of April 30, 1999.
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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
1999 1998
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(THOUSANDS EXCEPT PER SHARE DATA)
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OPERATING REVENUES:
Electric utility......................................... $ 250,144 $ 236,645
Non-utility subsidiaries................................. 128,061 50,722
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Total operating revenues............................... 378,205 287,367
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OPERATING EXPENSES:
Fuel..................................................... 57,681 59,614
Purchased power.......................................... 59,124 56,325
Gas and electricity purchased for resale................. 101,457 29,730
Other operation and maintenance.......................... 74,344 79,294
Depreciation............................................. 38,263 37,050
Taxes other than income.................................. 13,261 13,325
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Total operating expenses............................... 344,130 275,338
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OPERATING INCOME........................................... 34,075 12,029
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OTHER INCOME (EXPENSES):
Interest charges......................................... (18,300) (15,940)
Other, net............................................... 810 1,727
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Total other income (expenses).......................... (17,490) (14,213)
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EARNINGS BEFORE INCOME TAXES............................... 16,585 (2,184)
PROVISION FOR INCOME TAXES................................. 5,453 (1,844)
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NET INCOME (LOSS).......................................... 11,132 (340)
PREFERRED DIVIDEND REQUIREMENTS............................ --- 733
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EARNINGS (LOSS) AVAILABLE FOR COMMON....................... $ 11,132 $ (1,073)
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AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS).............. 78,267 80,772
EARNINGS (LOSS) PER AVERAGE COMMON SHARE................... $ 0.14 $ (0.01)
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EARNINGS PER AVERAGE COMMON SHARE - ASSUMING DILUTION...... $ 0.14 $ (0.01)
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DIVIDENDS DECLARED PER SHARE............................... $ 0.3325 $ 0.3325
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THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
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CONSOLIDATED BALANCE SHEETS
(Unaudited)
MARCH 31 DECEMBER 31
1999 1998
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(DOLLARS IN THOUSANDS)
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ASSETS
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 2,782 $ 378
Accounts receivable - customers, less reserve of $2,736 and
$3,342, respectively........................................ 134,956 141,235
Accrued unbilled revenues..................................... 22,600 22,500
Accounts receivable - other................................... 9,342 12,902
Fuel inventories, at LIFO cost................................ 63,714 57,288
Materials and supplies, at average cost....................... 30,888 29,734
Prepayments and other......................................... 22,518 31,551
Accumulated deferred tax assets............................... 7,755 7,811
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Total current assets........................................ 294,555 303,399
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OTHER PROPERTY AND INVESTMENTS, at cost......................... 34,284 31,682
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PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... 4,413,235 4,391,232
Construction work in progress................................. 64,582 50,039
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Total property, plant and equipment......................... 4,477,817 4,441,271
Less accumulated depreciation............................. 1,950,510 1,914,721
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Net property, plant and equipment............................. 2,527,307 2,526,550
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DEFERRED CHARGES:
Advance payments for gas...................................... 14,900 15,000
Income taxes recoverable future rates......................... 40,471 40,731
Other......................................................... 67,277 66,567
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Total deferred charges...................................... 122,648 122,298
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TOTAL ASSETS.................................................... $ 2,978,794 $ 2,983,929
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CAPITALIZATION AND LIABILITIES
CURRENT LIABILITIES:
Short-term debt............................................... $ 226,800 $ 119,100
Accounts payable.............................................. 94,802 96,936
Dividends payable............................................. 25,869 26,865
Customers' deposits........................................... 24,127 23,985
Accrued taxes................................................. 27,282 30,500
Accrued interest.............................................. 21,226 21,081
Long-term debt due within one year............................ 2,000 2,000
Other......................................................... 29,411 50,266
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Total current liabilities................................... 451,517 370,733
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LONG-TERM DEBT.................................................. 935,616 935,583
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DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 19,745 17,952
Accumulated deferred income taxes............................. 527,744 531,940
Accumulated deferred investment tax credits................... 66,441 67,728
Other......................................................... 29,414 16,611
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Total deferred credits and other liabilities................ 643,344 634,231
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STOCKHOLDERS' EQUITY:
Common stockholders' equity................................... 433,286 513,614
Retained earnings............................................. 515,031 529,768
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Total stockholders' equity.................................. 948,317 1,043,382
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TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,978,794 $ 2,983,929
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THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
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CONSOLIDATED STATEMENTS OF
CASH FLOWS
(Unaudited)
3 MONTHS ENDED
MARCH 31
1999 1998
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(DOLLARS IN THOUSANDS)
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CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss).................................................. $ 11,132 $ (340)
Adjustments to Reconcile Net Income (Loss) to Net Cash:
Depreciation..................................................... 38,263 37,050
Deferred income taxes and investment tax credits, net............ (4,884) (379)
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers................................ 6,279 20,111
Accrued unbilled revenues...................................... (100) 7,700
Fuel, materials and supplies inventories....................... (7,580) (12)
Accumulated deferred tax assets................................ 56 1,128
Other current assets........................................... 12,593 247
Accounts payable............................................... (2,134) (6,948)
Accrued taxes.................................................. (3,218) (18,078)
Accrued interest............................................... 145 (4,547)
Other current liabilities...................................... (21,709) (2,670)
Other operating activities....................................... 12,897 3,262
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Net cash provided from operating activities.................. 41,740 36,524
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CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (40,838) (28,132)
Other investment activities........................................ --- (58,343)
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Net cash used in investing activities........................ (40,838) (86,475)
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CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt....................................... --- (25,000)
Proceeds from long-term debt....................................... --- 5,690
Short-term debt, net............................................... 107,700 142,100
Redemption of common stock......................................... (80,330) ---
Redemption of preferred stock...................................... --- (49,266)
Cash dividends declared on preferred stock......................... --- (733)
Cash dividends declared on common stock............................ (25,868) (26,857)
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Net cash provided by financing activities.................... 1,502 45,934
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NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. 2,404 (4,017)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 378 4,257
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CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 2,782 $ 240
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)............................. $ 15,385 $ 18,721
Income taxes..................................................... $ 4,150 $ 7,180
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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.
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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,
1999, and December 31, 1998, and the results of operations and the changes
in cash flows for the periods ended March 31, 1999, and March 31, 1998,
have been included and are of a normal recurring nature.
The results of operations for such interim periods are not necessarily
indicative of the results for the full year. It is suggested that these
condensed 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, 1998.
2. In March 1998, the American Institute of Certified Public Accountants
("AICPA") issued Statement of Position ("SOP") 98-1, "Accounting for the
Costs of Computer Software Developed or Obtained for Internal Use".
Adoption of SOP 98-1 is required for fiscal years beginning after December
15, 1998. The Company adopted this new standard effective January 1, 1999.
Adoption of this new standard did not have a material impact on
consolidated financial position or results of operations.
3. In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting
for Derivative Instruments and for Hedging Activities". Adoption of SFAS
No. 133 is required for financial statements for periods beginning after
June 15, 1999. The Company will adopt this new standard effective January
1, 2000, and management believes the adoption of this new standard will not
have a material impact on its consolidated financial position or results of
operation.
4. In December 1998, the FASB Emerging Issues Task Force reached consensus on
Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities ("EITF Issue 98-10"). EITF Issue 98-10 is
effective for fiscal years beginning after December 15, 1998. EITF Issue
98-10 requires energy trading contracts to be recorded at fair value on the
balance sheet, with changes in fair value included in earnings. The Company
adopted this new Issue effective January 1, 1999. Adoption of this new
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Issue did not have a material impact on consolidated financial position or
results of operations.
5. Effective June 15, 1998, the outstanding shares of the Company's common
stock were split on a two-for-one basis. The new shares were issued to
shareowners of record on June 1, 1998. All references in the accompanying
financial statements to the number of common shares and per share amounts
for the three-month period ended March 31, 1998 have been restated to
reflect the stock split.
6. 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 will use these contracts as an enhancement or speculative trade.
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. The Company recognizes the gain or loss on
enhancement or speculative contracts as market values change 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, 1999 (the "current
period"), and the financial position as of March 31, 1999, 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"). For the
three months ended March 31, 1999, approximately 66 percent of the Company's
revenues consisted of regulated sales of electricity by OG&E, a public utility,
while the remaining 34 percent was 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. 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 period of the prior year.
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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, 1998 including Exhibit 99.01 thereto and other factors described from time
to time in the Company's reports to the Securities and Exchange Commission.
On Monday, May 3, 1999, tornadoes and severe thunderstorms inflicted heavy
damage to the power delivery system of OG&E. At the peak of the storms that
started Monday afternoon, 116,000 OG&E customers were estimated to have lost
electricity. Authorities have estimated that as many as 10,000 homes and
businesses were damaged by these storms. Although the Company is still assessing
the damage, current estimates place the storm damage cost at approximately $12
million to $15 million, of which approximately 75 percent will be capitalized
and 25 percent expensed.
The damage sustained by OG&E's power delivery system included numerous
distribution poles and lines. The utility's power transmission system was also
hard-hit. The storms knocked out more than 40 of the towers and high line
systems that transmit electricity from OG&E's power plants to the communities
they serve. Despite this damage, OG&E was quickly able to deliver power to all
of its substations, some of which were also damaged.
EARNINGS
The current period net income of $11.1 million represents an increase of
$11.5 million. Of the $11.5 million increase, approximately $12.3 million was
attributable to OG&E and $0.9 million was attributable to Enogex. These
increases were partially offset by losses from other operations of the Company.
As explained below, OG&E's increase in earnings was primarily attributable to
higher revenues from increased sales to OG&E customers ("system sales") and
lower operating expenses; Enogex's earnings increased due to increased volumes
in all business segments. Earnings per average common share increased to $0.14
from a net loss of $.01 in the prior period.
REVENUES
Total operating revenues increased $90.8 million or 31.6 percent. The
increase was attributable to increased electric sales by OG&E and significantly
increased Enogex revenues. Increased electric sales by OG&E were primarily
attributable to continued growth in the OG&E electric service area. Growth in
the electric service area resulted in increased electric utility revenues of
$13.5 million or 5.7 percent and a 4.0 percent increase in kilowatt-hour system
sales. The increase in system sales was more than offset by a significant
reduction in sales to other utilities and power marketers ("off-system sales").
However, off-system sales are generally
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priced at much lower prices per kilowatt-hour and have less impact on operating
revenues and earnings than system sales.
Enogex revenues increased $77.6 million or 154.0 percent in the current
period, largely due to increased sales activity at its OGE Energy Resources
trading and energy services unit (particularly in the area of power marketing
which OGE Energy Resources expanded into in March, 1998) and due to the
integration of additional pipelines acquired in Arkansas and Texas in 1998.
Increased volumes in all Enogex business segments were partially offset by
depressed commodity prices in the natural gas and natural gas liquids markets.
EXPENSES
Total operating expenses increased $68.8 million or 25.0 percent in the
current period. This increase was primarily due to increased gas and electricity
purchased for resale and purchased power. Enogex's gas and electricity purchased
for resale pursuant to its gas and electricity marketing operations increased
$71.7 million or 241.3 percent in the current period due to increased volumes of
natural gas purchased for resale to third parties and increased volumes and
prices paid by Enogex for energy purchased for resale to third parties. OG&E's
purchased power costs increased $2.8 million or 5.0 percent due to the
availability of electricity at favorable prices.
Depreciation and amortization increased $1.2 million or 3.3 percent due to
an increase in depreciable property and higher oil and gas production volumes
(based on units of production depreciation method).
Fuel expense decreased $1.9 million or 3.2 percent primarily due to the
availability of electricity for purchase at favorable prices and decreased
generation levels, resulting from the significant reduction in off-system sales.
Variances in the actual cost of fuel used in electric generation and certain
purchased power costs, as compared to that component in cost-of-service for
ratemaking, are passed through to 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.
Other operation and maintenance decreased $5.0 million or 6.2 percent,
primarily due to reduced contract labor and miscellaneous corporate expenses.
Interest charges increased $2.4 million or 14.8 percent primarily due to
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.
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LIQUIDITY AND CAPITAL REQUIREMENTS
The Company meets its cash needs through internally generated funds,
permanent financing and short-term borrowings. Internally generated funds and
short-term borrowings are expected to meet virtually all of the Company's
capital requirements through the remainder of 1999. Short-term borrowings will
continue to be used to meet temporary cash requirements.
The Company's primary needs for capital are related to construction of new
facilities to meet anticipated demand for 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 in its non-utility
businesses, and to some extent, for satisfying maturing debt. The Company's
capital expenditures for the current period of $41 million were financed with
internally generated funds and short-term borrowings.
The Company's capital structure and cash flow remained strong throughout
the current period. The Company's combined cash and cash equivalents increased
approximately $2.4 million during the three months ended March 31, 1999. The
increase reflects the Company's cash flow from operations, net of short-term
debt, construction expenditures, redemption of common stock 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" 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 1998 Form 10-K.
THE YEAR 2000 ISSUE
There has been a great deal of publicity about the Year 2000 ("Y2K") and
the possible problems that information technology systems may suffer as a
result. The Y2K problem originated with the early development of computerized
business applications. To save then-expensive storage space, reduce the
complexity of calculations and yield better system performance, programmers and
developers used a two-digit date scheme to represent the year (i.e., "72" for
"1972"). This two-digit date scheme was used well into the 1980s and 1990s in
traditional computer hardware such as mainframe systems, desktop personal
computers and network servers, in customized software systems, off-the-shelf
applications and operating systems, as well as in embedded systems ("chips") in
everything from elevators to industrial plants to consumer products. As the Year
2000 approaches, date-sensitive systems may recognize the Year 2000 as 1900, or
not at all. This inability to recognize or properly treat the Year 2000 may
cause systems, including those of the Company, its customers, suppliers,
business partners and neighboring utilities to process critical financial and
operational
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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
of the enterprise-wide software system for customer systems. In addition to
significantly reducing the potential risks of its current customer systems, the
Company is set to streamline work processes in customer service and power
delivery by integrating separate systems into a single system using the
enterprise-wide software system. This new single system will also provide for a
more flexible automated billing system and enhancements in handling customer
service orders, energy outage incidents and customer services.
In October of 1997, the Company formed a multi-functional Y2K Project Team
of experienced and knowledgeable members from each business unit to review and
test its operational systems in an effort to further eliminate any potential
problems, should they exist. The team provides regular monthly reports on its
progress to the Y2K Executive Steering Committee and senior management as well
as helping prepare presentations to the Board of Directors.
The Company's Year 2000 effort generally follows a three-phase process:
Phase I - Inventory and Assess Y2K Issues
Phase II - Determine Y2K Readiness of Vendors, Suppliers & Customers
Phase III - Correct, Test, Implement Solutions and Contingency Planning
STATE OF READINESS
The Company has substantially completed the internal inventory and
assessment (Phase I) of the Year 2000 plan. Follow-up vendor surveys are being
sent to vendors that have not responded to our original requests for information
(Phase II). Remediation efforts are ongoing and even though contingency planning
is a normal part of our business, plans are being prepared to include specific
activities with regard to Y2K issues (Phase III).
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In addition, as a part of the Company's three-year lease agreement for
personal computers, all new personal computers are being issued with operating
systems and application software that are Y2K ready. All existing personal
computers will be upgraded with Y2K ready operating systems before the turn of
the century. For embedded and plant operational systems, the Company has
generally completed the evaluative process and is commencing corrective 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 is currently
being installed and software is being configured.
The Company is also participating in an "Electric System Readiness
Assessment" program, which provides monthly reports to the Southwest Power Pool
("SPP") and the North American Electric Reliability Council ("NERC"). In April
1999, the Company also participated in a nationwide communications test as a
part of the electric utility industry's Y2K readiness preparation. The purpose
of the test was to determine how electric utilities would communicate with one
another in the event of an interruption of standard communication systems. The
ability to communicate would be important to coordinate the flow of electricity
over the nation's electric grid. The overall success of the test is not yet
known, however, communications in the SPP went smoothly with only minor problems
noted. The responses from all participating companies are being compiled for an
industry-wide status report to the Department of Energy ("DOE"). Also, in
February 1999, the Company submitted contingency plans to the NERC and the SPP
which will be used along with those of other participating companies to
formulate a regional contingency plan.
COSTS OF YEAR 2000 ISSUES
As described above, with the mainframe conversion, the enterprise software
installations and the EMS replacement, a number of Y2K issues were addressed as
part of the Company's normal course upgrades to the information technology
systems. These upgrades were already contemplated and provided additional
benefits or efficiencies beyond the Year 2000 aspect. In addition to the $1
million spent to date for Y2K issues, since 1995 the Company has spent in excess
of $29 million on the mainframe conversion, the enterprise software
installations and the EMS replacement. The Company expects to spend slightly
less than $5 million in 1999. These costs represent estimates, however, and
there can be no assurance that actual costs associated with the Company's Y2K
issues will not be higher.
RISKS OF YEAR 2000 ISSUES
As described above, the Company has made significant progress in the
implementation of its Year 2000 plan. Based upon the information currently known
regarding its internal operations and assuming successful and timely completion
of its remediation plan, the Company does not anticipate significant business
disruptions from its internal systems due to the Y2K issue. However, the Company
may possibly experience limited interruptions to some aspects of its activities,
whether information technology, operational, administrative or otherwise, and
the
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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. Although the Company is not presently aware of any such
situations, occurrences of this type, if severe, could have material adverse
impacts upon the business, operating results or financial condition of the
Company. There can be no assurance that the Company will be able to identify and
correct all aspects of the Year 2000 problem that affect it in sufficient time,
that it will develop adequate contingency plans or that the costs of achieving
Y2K readiness will not be material.
RECENT REGULATORY MATTERS
As previously reported, on February 13, 1998, The APSC Staff filed a motion
for a show cause order to review OG&E's electric rates in the State of Arkansas.
The Staff recommended a $3.1 million annual rate reduction (based on a test year
ended December 31, 1996). The Staff and OG&E have reached a settlement for a
$2.3 million annual rate reduction. The settlement is scheduled to be presented
to the APSC on May 18, 1999. An order is anticipated in the near future.
On April 8, 1999, lawmakers in Arkansas reached consensus on deregulation
of the state's electric industry. On April 15, 1999, Senate Bill 791 was signed
by the governor of Arkansas. Arkansas is the 18th state to pass a law calling
for restructuring of the electric utility industry. The new law targets customer
choice of electricity providers by January 1, 2002. The new law also provides
that utilities owning or controlling transmission assets must transfer control
of such transmission assets to an independent system operator, independent
transmission company or regional transmission group, if any such organization
has been approved by the FERC. Other provisions of the new law permit municipal
electric systems to opt in or out, permit recovery of stranded costs and
transition costs and require unbundled rates by July 1, 2000 for generation,
transmission, distribution and customer service. If implemented as proposed, the
new law will significantly affect OG&E's future Arkansas operations. OG&E's
electric service area includes parts of western Arkansas, including Fort Smith,
the second-largest metropolitan market in the state.
As previously reported, Oklahoma enacted in April 1997 the Electric
Restructuring Act of 1997. Various amendments to the Act were enacted in 1998.
OG&E remains involved in the rulemaking process that will provide for customer
choice in Oklahoma by July 1, 2002.
11
<PAGE>
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 and Origen. 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. Origen is engaged in geothermal
heat pump systems and the development of new products. Origen's results to date
have not been material to the Company. The following is the Company's business
segment results for the current period.
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1999 1998
================================================================================
<S> <C> <C>
Operating Information:
Operating Revenues
Electric utility............................... $ 250,144 $ 236,645
Non-utility.................................... 154,350 79,493
Intersegment revenues (A)...................... (26,289) (28,771)
- --------------------------------------------------------------------------------
Total........................................ $ 378,205 $ 287,367
================================================================================
Net Income
Electric utility............................... $ 10,189 $ (2,079)
Non-utility.................................... 943 1,739
- --------------------------------------------------------------------------------
Total........................................ $ 11,132 $ (340)
================================================================================
(A) Intersegment revenues are recorded at prices comparable to those of
unaffiliated customers and are affected by regulatory considerations.
</TABLE>
12
<PAGE>
PART II. OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
Reference is made to Item 3 of the Company's 1998 Form 10-K for a
description of certain legal proceedings presently pending. There are no new
significant cases to report against the Company or its subsidiaries and there
have been no significant changes in the previously reported proceedings.
ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
27.01 - Financial Data Schedule.
(b) Reports on Form 8-K
None
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
Controller Corporate Accounting
(On behalf of the registrant and in his capacity
as Controller Corporate Accounting)
May 14, 1999
14
<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 March 31, 1999 and is qualified in
its entirety by reference to such Form 10-Q.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> MAR-31-1999
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,527,307
<OTHER-PROPERTY-AND-INVEST> 34,284
<TOTAL-CURRENT-ASSETS> 294,555
<TOTAL-DEFERRED-CHARGES> 122,648
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,978,794
<COMMON> 778
<CAPITAL-SURPLUS-PAID-IN> 432,508
<RETAINED-EARNINGS> 515,031
<TOTAL-COMMON-STOCKHOLDERS-EQ> 948,317
0
0
<LONG-TERM-DEBT-NET> 935,616
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 226,800
<LONG-TERM-DEBT-CURRENT-PORT> 2,000
0
<CAPITAL-LEASE-OBLIGATIONS> 11,202
<LEASES-CURRENT> 2,903
<OTHER-ITEMS-CAPITAL-AND-LIAB> 851,956
<TOT-CAPITALIZATION-AND-LIAB> 2,978,794
<GROSS-OPERATING-REVENUE> 378,205
<INCOME-TAX-EXPENSE> 5,453
<OTHER-OPERATING-EXPENSES> 344,130
<TOTAL-OPERATING-EXPENSES> 344,130
<OPERATING-INCOME-LOSS> 34,075
<OTHER-INCOME-NET> 810
<INCOME-BEFORE-INTEREST-EXPEN> 34,885
<TOTAL-INTEREST-EXPENSE> 18,300
<NET-INCOME> 11,132
0
<EARNINGS-AVAILABLE-FOR-COMM> 11,132
<COMMON-STOCK-DIVIDENDS> 25,868
<TOTAL-INTEREST-ON-BONDS> 15,022
<CASH-FLOW-OPERATIONS> 41,740
<EPS-PRIMARY> 0.14
<EPS-DILUTED> 0.14
</TABLE>
