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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, 1997
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.)
101 North Robinson
P. O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
405-553-3000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes x No
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There were 40,373,991 Shares of Common Stock, par value $0.01 per share,
outstanding as of April 30, 1997.
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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
1997 1996
---------- ----------
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C>
OPERATING REVENUES:
Electric utility .............................. $ 227,878 $ 233,826
Non-utility subsidiaries....................... 63,337 44,226
---------- ----------
Total operating revenues .................... 291,215 278,052
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OPERATING EXPENSES:
Fuel .......................................... 56,614 59,580
Purchased power ............................... 58,157 56,649
Gas purchased for resale ...................... 42,958 29,287
Other operation and maintenance................ 71,625 71,033
Depreciation and amortization ................. 35,320 33,470
Current income taxes .......................... (886) 928
Deferred income taxes, net .................... (219) (1,098)
Deferred investment tax credits, net .......... (1,287) (1,287)
Taxes other than income ....................... 12,932 12,273
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Total operating expenses .................... 275,214 260,835
---------- ----------
OPERATING INCOME ................................ 16,001 17,217
---------- ----------
OTHER INCOME (DEDUCTIONS):
Interest Income ............................... 547 511
Other ......................................... (105) (317)
---------- ----------
Net other income (deductions)................ 442 194
---------- ----------
INTEREST CHARGES:
Interest on long-term debt .................... 15,419 15,599
Allowance for borrowed funds used
during construction ......................... (67) (187)
Other ......................................... 1,351 1,461
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Total interest charges, net ................. 16,703 16,873
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NET INCOME (LOSS) ............................... (260) 538
PREFERRED DIVIDEND REQUIREMENTS ................. 571 579
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LOSS AVAILABLE FOR COMMON ....................... $ (831) $ (41)
========== ==========
AVERAGE COMMON SHARES OUTSTANDING (thousands) ... 40,374 40,371
LOSS PER AVERAGE COMMON SHARE ................... $ (0.02) $ 0.00
========== ==========
DIVIDENDS DECLARED PER SHARE .................... $ 0.66 1/2 $ 0.66 1/2
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
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CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31 December 31
1997 1996
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(DOLLARS IN THOUSANDS)
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT:
In service.......................................... $ 4,023,548 $ 4,005,532
Construction work in progress....................... 33,310 27,968
------------ ------------
Total property, plant and equipment............... 4,056,858 4,033,500
Less accumulated depreciation................... 1,721,518 1,687,423
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Net property, plant and equipment................... 2,335,340 2,346,077
------------ ------------
OTHER PROPERTY AND INVESTMENTS, at cost............... 30,337 24,802
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CURRENT ASSETS:
Cash and cash equivalents........................... 6,911 2,523
Accounts receivable - customers, net................ 99,758 128,974
Accrued unbilled revenues........................... 24,900 34,900
Accounts receivable - other......................... 9,878 11,748
Fuel inventories, at LIFO cost...................... 59,774 62,725
Materials and supplies, at average cost............. 26,020 24,827
Prepayments and other............................... 3,142 4,300
Accumulated deferred tax assets..................... 6,214 10,067
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Total current assets.............................. 236,597 280,064
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DEFERRED CHARGES:
Advance payments for gas............................ 9,500 9,500
Income taxes recoverable through future rates....... 43,913 44,368
Other............................................... 53,137 57,544
------------ ------------
Total deferred charges............................ 106,550 111,412
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TOTAL ASSETS.......................................... $ 2,708,824 $ 2,762,355
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CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common stock and retained earnings.................. $ 933,764 $ 961,603
Cumulative preferred stock.......................... 49,329 49,379
Long-term debt...................................... 804,385 829,281
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Total capitalization.............................. 1,787,478 1,840,263
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CURRENT LIABILITIES:
Short-term debt..................................... 65,900 41,400
Accounts payable.................................... 81,104 86,856
Dividends payable................................... 27,420 27,421
Customers' deposits................................. 23,444 23,257
Accrued taxes....................................... 12,447 26,761
Accrued interest.................................... 16,808 19,832
Long-term debt due within one year.................. 25,000 15,000
Other............................................... 36,507 39,188
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Total current liabilities......................... 288,630 279,715
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DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation.............. 62,263 61,335
Accumulated deferred income taxes................... 483,156 488,016
Accumulated deferred investment tax credits......... 76,741 78,028
Other............................................... 10,556 14,998
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Total deferred credits and other liabilities...... 632,716 642,377
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COMMITMENTS AND CONTINGENCIES......................... --- ---
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TOTAL CAPITALIZATION AND LIABILITIES.................. $ 2,708,824 $ 2,762,355
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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
1997 1996
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(DOLLARS IN THOUSANDS)
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CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)........................................... $ (260) $ 538
Adjustments to Reconcile Net Income (Loss) to Net
Cash Provided From Operating Activities:
Depreciation and amortization............................. 35,320 33,470
Deferred income taxes and investment tax credits, net..... (1,506) (2,385)
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers......................... 29,216 14,276
Accrued unbilled revenues............................... 10,000 3,950
Fuel, materials and supplies inventories................ 1,758 2,190
Accumulated deferred tax assets......................... 3,853 1,119
Other current assets.................................... 3,028 (2,883)
Accounts payable........................................ (5,752) 5,028
Accrued taxes........................................... (14,314) (10,553)
Accrued interest........................................ (3,024) (2,554)
Other current liabilities............................... (2,495) (2,974)
Other operating activities................................ (8,461) 4,702
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Net cash provided from operating activities........... 47,363 43,924
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CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures.................................... (25,005) (21,679)
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Net cash used in investing activities................. (25,005) (21,679)
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CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt, net....................... (15,000) ---
Short-term debt, net.................................... 24,500 12,300
Redemption of preferred stock........................... (50) ---
Cash dividends declared on preferred stock.............. (571) (579)
Cash dividends declared on common stock................. (26,849) (26,846)
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Net cash used in financing activities................. (17,970) (15,125)
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NET INCREASE IN CASH AND CASH EQUIVALENTS..................... 4,388 7,120
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.............. 2,523 5,420
CASH AND CASH EQUIVALENTS AT END OF PERIOD.................... $ 6,911 $ 12,540
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash Paid During the Period for:
Interest (net of amount capitalized)...................... $ 18,213 $ 18,253
Income taxes.............................................. $ 5,175 $ 4,613
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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.
The Company became the parent company of Oklahoma Gas and Electric
Company ("OG&E") and its former subsidiary, Enogex Inc. on December
31, 1996. On that date, all outstanding OG&E common stock was
exchanged on a share-for-share basis for common stock of OGE Energy
Corp. and the common stock of Enogex Inc. was distributed to the
Company. The financial information presented represents the
consolidated results of the Company through March 31, 1997. All
significant intercompany transactions have been eliminated in
consolidation.
In the opinion of management, all adjustments necessary to present
fairly the financial position of the Company and its subsidiaries as
of March 31, 1997, and December 31, 1996, and the results of
operations and the changes in cash flows for the periods ended March
31, 1997, and March 31, 1996, have been included and are of a normal
recurring nature (excluding amortization of a regulatory asset
relating to a Voluntary Early Retirement Package ("VERP") and
severance package - See Item 2 "Management's Discussion and Analysis
of Financial Condition and Results of Operations" for related
discussion).
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, 1996.
2. In March 1997, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 128,
"Earnings per Share." Adoption of SFAS No. 128 is required for both
interim and annual periods ending after December 15, 1997. The Company
will adopt this new standard effective December 31, 1997, and
management does not believe the adoption of this standard will have a
material impact on its earnings per share.
3. In March 1997, the FASB issued SFAS No. 129, "Disclosure of
Information about Capital Structure." Adoption of SFAS No. 129 is
required for financial statements for periods ending after December
15, 1997. The Company will adopt this new standard effective December
31, 1997.
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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 months ended March 31, 1997 (the "current
period"), and the financial position as of March 31, 1997, of the Company and
its subsidiaries: OG&E, Enogex Inc. and its subsidiaries ("Enogex") and Origen
and its subsidiaries ("Origen"). For the three months ended March 31, 1997,
approximately 78 percent of the Company's revenues consisted of regulated sales
of electricity by OG&E, a public utility, while the remaining 22 percent was
provided by the non-utility operations of Enogex. Origen recently was formed and
its operations to date have been de minimis. 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.
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, 1996 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 February 11, 1997, the Oklahoma Corporation Commission ("OCC") issued an
order that, among other things, effectively lowered OG&E's rates to its Oklahoma
retail customers by $50 million annually (based on a test year ended December
31, 1995). Of the $50 million rate reduction, approximately $45 million became
effective on March 5, 1997, and the remaining $5 million becomes effective March
1, 1998. This $50 million rate reduction is in addition to the $15 million rate
reduction discussed below that was effective January 1, 1995. The Order also
directed OG&E to transition to competitive bidding of its gas transportation
requirements, currently met by Enogex, no later than April 30, 2000 and set
annual compensation for the transportation services provided by Enogex to OG&E
at $41.3 million until competitively-bid gas transportation begins.
In 1994, OG&E restructured and redesigned its operations to reduce costs
and to more favorably position itself for the competitive electric utility
environment. As part of this process, OG&E implemented a Voluntary Early
Retirement Package ("VERP") and a severance package in 1994. These two packages
reduced OG&E's workforce by approximately 900 employees.
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In response to an application filed by OG&E, the OCC issued an order on
October 26, 1994, that permitted OG&E to: (i) establish a regulatory asset in
connection with the costs associated with the workforce reduction; (ii) amortize
the December 31, 1994, balance of the regulatory asset over 26 months; and (iii)
reduce OG&E's electric rates by approximately $15 million annually, effective
January 1995. In 1996, the labor savings substantially offset the amortization
of the regulatory asset and the annual rate reduction of $15 million. The
regulatory asset was fully amortized at February 28, 1997 and again the labor
savings substantially offset the regulatory asset amortization in 1997 and
therefore, did not significantly impact operating results in the current period.
As previously reported, the Oklahoma House of Representatives was
considering legislation to set the framework for electric industry competition.
In April 1997, this legislation was passed by the Oklahoma House and signed into
law by the Governor. See Part II, Item 5 - "Other Information" for further
discussion of this legislation.
REVENUES
Total operating revenues increased $13.2 million or 4.7 percent. This
increase was attributable to higher Enogex revenues. Electric utility revenues
decreased due to lower sales of electricity attributable primarily to warmer
weather.
The impact of the warmer weather resulted in a 1.1 percent decrease in
kilowatt-hour sales to OG&E customers ("system sales"). Sales to other utilities
decreased 26.3 percent; however, sales to other utilities are at much lower
prices per kilowatt-hour and have less impact on operating revenues and earnings
than system sales.
Enogex revenues increased $19.1 million or 43.2 percent, largely due to
increased revenues from its marketing of natural gas and natural gas liquids.
These increased revenues were attributable primarily to an increase in volumes
sold and significantly higher sales prices for natural gas and natural gas
liquids.
EXPENSES
Total operating expenses increased $14.4 million or 5.5 percent primarily
due to higher volumes purchased and prices paid by Enogex for gas purchased for
resale to third parties.
Fuel expense decreased $ 3.0 million or 5.0 percent in the current period
due to decreased generation at OG&E. 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 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.
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Enogex's gas purchased for resale pursuant to its gas marketing operations
increased $13.7 million or 46.7 percent, due to higher volumes purchased and
significantly higher gas costs.
Depreciation and amortization increased $1.9 million or 5.5 percent due to
an increase in depreciable property and higher oil and gas production volumes
(based on units of production depreciation method).
Other income and deductions increased $248,000 in the current period
primarily due to a gain on the sale of sulfur dioxide allowances by OG&E. Total
interest charges decreased in the current period due to the retirement of $l5
million of 5.125 percent first-mortgage bonds of OG&E in January 1997, and a
lower average daily balance in short-term debt.
EARNINGS
The current period net loss of $260,000 represents a decrease of $798,000
in net income. Enogex's net income decreased $339,000 primarily due to lower
margins on gas purchased for resale. Earnings per share decreased from zero in
the first quarter of 1996 to a two cent loss in the current period, which
reflects the above items and the seasonal nature of the Company's regulated
electric business.
LIQUIDITY AND CAPITAL REQUIREMENTS
The Company meets its cash needs through internally generated funds,
permanent financing and short-term borrowings. Internally generated funds,
short-term borrowings and medium-term notes of Enogex described below are
expected to meet virtually all of the Company's capital requirements through the
remainder of 1997. 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 and sinking fund
obligations. The Company's capital expenditures for the current period of $25
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 $4.4 million during the three months ended March 31, 1997. The
increase reflects the Company's cash flow from operations plus an increase in
short-term borrowings, net of retirement of long-term debt, construction
expenditures and dividend payments.
On April 30, 1997, Enogex acquired an 80 percent interest in the NUSTAR
Joint Venture for approximately $26 million. The assets of the joint venture
include a two-thirds interest in a
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gas processing plant, 100 percent interest in a gas processing bypass plant,
approximately 50 miles of natural gas liquid pipeline and approximately 200
miles of related gas gathering facilities in West Texas. For the year ended
December 31, 1996, the joint venture generated revenues of approximately $36.6
million and partnership net income (before income taxes) of approximately $3.2
million. Enogex financed this acquisition with borrowings from the Company and
expects to issue $30 million of medium-term notes in the second quarter of 1997
and utilize the proceeds to repay the amount borrowed from the Company.
Effective March 31, 1997, Enogex also disposed of its 80 percent interest
in Centoma Gas Systems, Inc. for $3.2 million, which approximated the net book
value of Enogex's share of Centoma's assets at December 31, 1996. Enogex had
purchased its interest in Centoma in 1994 for approximately $6.5 million.
In April 1996, OG&E filed a registration statement for the sale of up to
$300 million of senior notes. In February 1997, OG&E reduced the amount of the
registration statement for senior notes to $250 million and filed a new
registration statement for up to $50 million of grantor trust preferred
securities. Assuming favorable market conditions, OG&E may issue all or part of
these securities to refinance, at lower rates, one or more series of outstanding
first mortgage bonds or preferred stock.
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 9 and 10 of Notes to the
Consolidated Financial Statements in the Company's 1996 Form 10-K.
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PART II. OTHER INFORMATION
Item 1 LEGAL PROCEEDINGS
Reference is made to Item 3 of the Company's 1996 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 5 OTHER INFORMATION
As previously reported, the Oklahoma State Senate passed legislation that
will permit increased competition at the retail level by July 2002. In April
1997, this legislation which is known as the Electric Restructuring Act of 1997
(the "Act") was passed by the Oklahoma House of Representatives and signed into
law by the Governor. If implemented as proposed, the Act will significantly
affect OG&E's operations in the future.
The following summary of the Act does not purport to be complete and is
subject to the specific provisions of the Act, which is codified at Sections
190.2 et. seq. of Title 17 of the Oklahoma Statutes. The Act consists of eight
sections, with Section 1 designating the name of the Act. Section 2 describes
the purposes of the Act, which is generally to restructure the electric industry
to provide for more competition and, in particular, to provide for the orderly
restructuring of the electric utility industry in the State of Oklahoma in order
to allow direct access by retail consumers to the competitive market for the
generation of electricity while maintaining the safety and reliability of the
electric system in the state.
The primary goals of a restructured electric utility industry, as set forth
in Section 2 of the Act, are as follows:
1. To reduce the cost of electricity for as many consumers as possible,
helping industry to be more competitive, to create more jobs in
Oklahoma and help lower the cost of government by reducing the amount
and type of regulation now paid for by taxpayers;
2. To encourage the development of a competitive electricity industry
through the unbundling of prices and services and separation of
generation services from transmission and distribution services;
3. To enable retail electric energy suppliers to engage in fair and
equitable competition through open, equal and comparable access to
transmission and distribution systems and to avoid wasteful
duplication of facilities;
4. To ensure that direct access by retail consumers to the competitive
market for generation be implemented in Oklahoma by July 1, 2002; and
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5. To ensure that proper standards of safety, reliability and service are
maintained in a restructured electric service industry.
Section 3 of the Act sets forth various definitions and exempts in large
part several electric cooperatives and municipalities from the Act unless they
choose to be governed by it.
Sections 4, 5 and 6 of the Act are designed to implement the goals of the
Act and provide for various studies and task forces to assess the issues and
consequences associated with the proposed restructuring of the electric utility
industry. In Section 4, the Oklahoma Corporation Commission (the "Oklahoma
Commission") is directed to undertake a study of all relevant issues relating to
restructuring the electric utility industry in Oklahoma including, but not
limited to, the issues set forth in Section 4, and to develop a proposed
electric utility framework for Oklahoma under the direction of the Joint
Electric Utility Task Force (which task force is described below). However, the
Oklahoma Commission is prohibited from promulgating orders relating to the
restructuring without prior authorization of the Oklahoma Legislature. Also, in
developing a framework for a restructured electric utility industry, the
Oklahoma Commission is to adhere to fourteen principles set forth in Section 4,
including the following:
1. Appropriate rules shall be promulgated, ensuring that reliable and
safe electric service is maintained.
2. Consumers shall be allowed to choose among retail electric energy
suppliers to help ensure competitive and innovative markets. A process
should be established whereby all retail consumers are permitted to
choose their retail electric energy suppliers by July 1, 2002.
3. When consumer choice is introduced, rates shall be unbundled to
provide clear price information on the components of generation,
transmission and distribution and any other ancillary charges. Charges
for public benefit programs currently authorized by statute or the
Oklahoma Commission, or both, shall be unbundled and appear in line
item format on electric bills for all classes of consumers.
4. An entity providing distribution services shall be relieved of its
traditional obligation to provide electric supply but shall have a
continuing obligation to provide distribution service for all
consumers in its service territory.
5. The benefits associated with implementing an independent system
planning committee composed of owners of electric distribution systems
to develop and maintain planning and reliability criteria for
distribution facilities shall be evaluated.
6. A defined period for the transition to a restructured electric utility
industry shall be established. The transition period shall reflect a
suitable time frame for full compliance with the requirements of a
restructured utility industry.
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7. Electric rates for all consumer classes shall not rise above current
levels throughout the transition period. If possible, electric rates
for all consumers shall be lowered when feasible as markets become
more efficient in a restructured industry.
8. The Oklahoma Commission shall consider the establishment of a
distribution access fee to be assessed to all consumers in Oklahoma
connected to electric distribution systems regulated by the Oklahoma
Commission. This fee shall be charged to cover social costs, capital
costs, operating costs, and other appropriate costs associated with
the operation of electric distribution systems and the provision of
electric services to the retail consumer.
9. Electric utilities have traditionally had an obligation to provide
service to consumers within their established service territories and
have entered into contracts, long-term investments and federally
mandated co-generation contracts to meet the needs of consumers. These
investments and contracts have resulted in costs which may not be
recoverable in a competitive restructured market and thus may be
"stranded." Procedures shall be established for identifying and
quantifying stranded investments and for allocating costs and
mechanisms shall be proposed for recovery of an appropriate amount of
prudently incurred, unmitigable and verifiable stranded costs and
investments. As part of this process, each entity shall be required to
propose a recovery plan which establishes its unmitigable and
verifiable stranded costs and investments and a limited recovery
period designed to recover such costs expeditiously, provided that the
recovery period and the amount of qualified transition costs shall
yield a transition charge which shall not cause the total price for
electric power, including transmission and distribution services, for
any consumer to exceed the cost per kilowatt-hour paid on the
effective date of this Act during the transition period. The
transition charge shall be applied to all consumers including direct
access consumers, and shall not disadvantage one class of consumer or
supplier over another, nor impede competition and shall be allocated
over a period of not less than three (3) years nor more than seven (7)
years.
10. It is the intent that all transition costs shall be recovered by
virtue of the savings generated by the increased efficiency in markets
brought about by restructuring of the electric utility industry. All
classes of consumers shall share in the transition costs.
Subject to the principles set forth in Section 4, the Oklahoma Commission
is directed to prepare a four-part study to be delivered to the Joint Electric
Utility Task Force (the "Joint Task Force"). The first part of the study, which
is due February 1, 1998, is to address independent operation issues. The second
part, which is due December 31, 1998, is to address technical issues, such as
reliability, safety, unbundling of generation, transmission and distribution
services, transition issues and market power. The third part of the study is due
December 31, 1999, and is
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to address financial issues, including rates, charges, access fees, transition
costs and stranded costs. The final part of the study is due August 31, 2000 and
is to cover consumer issues, such as the obligation to serve, service
territories, consumer choices, competition and consumer safeguards.
Section 5 of the Act directs the Oklahoma Tax Commission to study and
submit a report to the Joint Task Force by December 31, 1998 on the impact of
the restructuring of the electric utility industry on state tax revenues and all
other facets of the current utility tax structure on the state and all political
subdivisions of the state. The Oklahoma Tax Commission is precluded from issuing
any rules on such matters without the approval of the Oklahoma Legislature or
the Joint Task Force. Also, in the event a uniform tax policy that allows all
competitors to be taxed on a fair and equitable basis is not established on or
before July 1, 2002, then the effective date for implementing customer choice of
retail electric suppliers shall be extended until a uniform tax policy is
established.
Section 6 creates the Joint Task Force, which shall consist of seven
members from the Oklahoma Senate and seven members from the Oklahoma House of
Representatives. The Joint Task Force is to direct and oversee the studies of
the Oklahoma Commission and Oklahoma Tax Commission set forth in Sections 4 and
5 of the Act. The Joint Task Force is permitted to make final recommendations to
the Governor and Oklahoma Legislature. The Joint Task Force is also empowered to
retain consultants to study the creation of an Independent System Operator,
which would coordinate the physical supply of electricity throughout Oklahoma
and maintain reliability, security and stability of the bulk power system. In
addition, such study shall assess the benefits of establishing a power exchange
that would operate as a power pool allowing power producers to compete on common
ground in Oklahoma. In fulfilling its tasks, the Joint Task Force can appoint
advisory councils made up of electric utilities, regulators, residential
customers and other constituencies.
Section 7 provides generally that, with respect to electric distribution
providers, no customer switching will be allowed from the effective date of the
Act until July 1, 2002, except by mutual consent. It also provides that any
municipality that fails to become subject to the Act will be prohibited from
selling power outside its municipal limits except from lines owned on the
effective date of the Act. Section 8 sets forth the effective date of the Act as
April 25, 1997.
The Company intends to actively participate in the restructuring of the
electric utility industry in Oklahoma and to remain a competitive supplier of
electricity. However, due to the early stages of this process, the Company
cannot predict the impact that the restructuring will have on its operations in
the future.
Item 6 EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
27.01 - Financial Data Schedule.
(b) Reports on Form 8-K - None.
12
<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/ A.M. Strecker
-------------------------------------
A.M. Strecker
Senior Vice President
(On behalf of the registrant and in his capacity
as Principal Financial and Accounting Officer)
May 12, 1997
13
<PAGE>
<TABLE>
EXHIBIT INDEX
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<S> <C>
27.01 Financial Data Schedule
</TABLE>
<TABLE> <S> <C>
<PAGE>
<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, 1997 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-31-1997
<PERIOD-END> MAR-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,335,340
<OTHER-PROPERTY-AND-INVEST> 30,337
<TOTAL-CURRENT-ASSETS> 236,597
<TOTAL-DEFERRED-CHARGES> 106,550
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 2,708,824
<COMMON> 465
<CAPITAL-SURPLUS-PAID-IN> 511,781
<RETAINED-EARNINGS> 421,518
<TOTAL-COMMON-STOCKHOLDERS-EQ> 933,764
0
49,329
<LONG-TERM-DEBT-NET> 804,385
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 65,900
<LONG-TERM-DEBT-CURRENT-PORT> 25,000
0
<CAPITAL-LEASE-OBLIGATIONS> 6,802
<LEASES-CURRENT> 3,122
<OTHER-ITEMS-CAPITAL-AND-LIAB> 820,422
<TOT-CAPITALIZATION-AND-LIAB> 2,708,824
<GROSS-OPERATING-REVENUE> 291,215
<INCOME-TAX-EXPENSE> (886)
<OTHER-OPERATING-EXPENSES> 276,100
<TOTAL-OPERATING-EXPENSES> 275,214
<OPERATING-INCOME-LOSS> 16,001
<OTHER-INCOME-NET> 442
<INCOME-BEFORE-INTEREST-EXPEN> 16,443
<TOTAL-INTEREST-EXPENSE> 16,703
<NET-INCOME> (260)
571
<EARNINGS-AVAILABLE-FOR-COMM> (831)
<COMMON-STOCK-DIVIDENDS> 26,849
<TOTAL-INTEREST-ON-BONDS> 15,419
<CASH-FLOW-OPERATIONS> 47,363
<EPS-PRIMARY> (0.02)
<EPS-DILUTED> (0.02)
</TABLE>
