UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(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, 2003
OR
[ ] TRANSITION REPORT
PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission File Number: 1-1097
Oklahoma Gas and Electric Company meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format permitted by General Instruction H (2).
OKLAHOMA GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Oklahoma
73-0382390
(State or other
jurisdiction
of
(I.R.S.
Employer
incorporation
or organization)
Identification No.)
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
405-553-3000
(Registrant's telephone number, including area
code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes
X No
Indicate by check mark whether the registratrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes No X
As of April 30, 2003, 40,378,745 shares of common stock, par value $2.50 per share, were outstanding.
OKLAHOMA GAS AND ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2003
TABLE OF CONTENTS
PART I - FINANCIAL INFORMATION Page
Item 1. Financial Statements (Unaudited)
Condensed Balance Sheets....................................... 1
Condensed Statements of Operations............................. 3
Condensed Statements of Cash Flows............................. 4
Notes to Condensed Financial Statements........................ 5
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations...................................... 18
Item 3. Quantitative and Qualitative Disclosures About Market Risk....... 31
Item 4. Controls and Procedures.......................................... 31
PART II - OTHER INFORMATION
Item 1. Legal Proceedings................................................ 32 Item 6. Exhibits and Reports on Form 8-K................................. 32 Signature................................................................ 33 Certifications........................................................... 34
i
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
------------- ------------
(In millions)
ASSETS
CURRENT ASSETS
Cash and cash equivalents..................................... $ --- $ 0.3
Accounts receivable - customers, net.......................... 89.4 97.7
Accrued unbilled revenues..................................... 32.5 28.2
Accounts receivable - other, net.............................. 9.1 8.1
Fuel inventories, at LIFO cost................................ 65.4 65.4
Materials and supplies, at average cost....................... 37.3 40.7
Accumulated deferred tax assets............................... 6.8 7.5
Fuel clause under recoveries.................................. 48.8 14.7
Other......................................................... 4.6 5.3
- ---------------------------------------------------------------- ------------- ------------
Total current assets........................................ 293.9 276.9
- ---------------------------------------------------------------- ------------- ------------
OTHER PROPERTY AND INVESTMENTS, at cost......................... 7.2 8.1
- ---------------------------------------------------------------- ------------- ------------
PROPERTY, PLANT AND EQUIPMENT
In service.................................................... 4,141.2 4,099.2
Construction work in progress................................. 27.8 38.7
- ---------------------------------------------------------------- ------------- ------------
Total property, plant and equipment......................... 4,169.0 4,137.9
Less accumulated depreciation............................. 1,952.5 1,931.0
- ---------------------------------------------------------------- ------------- ------------
Net property, plant and equipment........................... 2,216.5 2,206.9
- ---------------------------------------------------------------- ------------- ------------
DEFERRED CHARGES AND OTHER ASSETS
Recoverable take or pay gas charges........................... 32.5 32.5
Income taxes recoverable from customers, net.................. 33.6 34.8
Intangible asset - unamortized prior service cost............. 37.8 37.8
Prepaid benefit obligation.................................... 23.5 29.6
Price risk management......................................... 7.7 7.5
Other......................................................... 32.6 34.8
- ---------------------------------------------------------------- ------------- ------------
Total deferred charges...................................... 167.7 177.0
- ---------------------------------------------------------------- ------------- ------------
TOTAL ASSETS.................................................... $ 2,685.3 $ 2,659.9
================================================================ ============= ============
The accompanying Notes to Condensed Financial Statements are an integral part hereof.,
1
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS (Continued)
(Unaudited)
March 31, December 31,
2003 2002
------------- ------------
(In millions)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates................................. $ 56.7 $ 26.1
Accounts payable - other...................................... 90.3 63.2
Advances from parent.......................................... 99.0 101.1
Customers' deposits........................................... 34.0 33.0
Accrued taxes................................................. 11.2 20.3
Accrued interest.............................................. 15.3 13.9
Tax collections payable....................................... 6.8 6.7
Accrued vacation.............................................. 12.0 11.6
Other......................................................... 12.9 10.4
- ---------------------------------------------------------------- ------------- ------------
Total current liabilities................................... 338.2 286.3
- ---------------------------------------------------------------- ------------- ------------
LONG-TERM DEBT.................................................. 710.7 710.5
- ---------------------------------------------------------------- ------------- ------------
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations....................... 151.0 148.6
Accumulated deferred income taxes............................. 421.4 421.5
Accumulated deferred investment tax credits................... 45.8 47.1
Accrued removal obligations, net.............................. 111.0 109.3
Provision for payments of take or pay gas..................... 32.5 32.5
---------------------------------------------------------------- ------------- ------------
Total deferred credits and other liabilities................ 761.7 759.0
- ---------------------------------------------------------------- ------------- ------------
STOCKHOLDERS' EQUITY
Common stockholders' equity................................... 512.4 512.4
Retained earnings............................................. 425.8 455.2
Accumulated other comprehensive loss, net of tax.............. (63.5) (63.5)
- ---------------------------------------------------------------- ------------- ------------
Total stockholders' equity.................................. 874.7 904.1
- ---------------------------------------------------------------- ------------- ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,685.3 $ 2,659.9
================================================================ ============= ============
The accompanying Notes to Condensed Financial Statements are an integral part hereof.
2
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
March 31
--------------------------------
2003 2002
-------------- --------------
(In millions)
OPERATING REVENUES......................................... $ 332.6 $ 262.1
COST OF GOODS SOLD......................................... 213.9 148.8
- ----------------------------------------------------------- -------------- --------------
Gross margin on revenues................................. 118.7 113.3
Other operation and maintenance.......................... 72.0 64.7
Depreciation............................................. 32.6 30.8
Taxes other than income.................................. 12.0 11.9
- ----------------------------------------------------------- -------------- --------------
OPERATING INCOME........................................... 2.1 5.9
- ----------------------------------------------------------- -------------- --------------
OTHER INCOME (EXPENSE)
Other Income............................................. 0.3 0.2
Other expense............................................ (0.7) (0.7)
- ----------------------------------------------------------- -------------- --------------
Net other expense...................................... (0.4) (0.5)
- ----------------------------------------------------------- -------------- --------------
INTEREST INCOME (EXPENSE)
Interest income.......................................... --- 0.4
Interest on long-term debt............................... (9.3) (9.5)
Allowance for borrowed funds used during construction.... 0.2 0.4
Interest on short-term debt and other interest charges... (0.8) (0.7)
- ----------------------------------------------------------- -------------- --------------
Net interest expense.................................. (9.9) (9.4)
- ----------------------------------------------------------- -------------- --------------
LOSS BEFORE TAXES.......................................... (8.2) (4.0)
INCOME TAX BENEFIT......................................... (4.9) (2.5)
- ----------------------------------------------------------- -------------- --------------
NET LOSS................................................... $ (3.3) $ (1.5)
=========================================================== ============== ==============
The accompanying Notes to Financial Statements are an integral part hereof.
3
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31
---------------------------------
2003 2002
-------------- --------------
(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss........................................................ $ (3.3) $ (1.5)
Adjustments to reconcile net loss to net cash provided
from operating activities
Depreciation.................................................. 32.6 30.8
Deferred income taxes and investment tax credits, net......... 0.7 17.3
Other assets.................................................. 5.1 (2.9)
Other liabilities............................................. 2.3 (0.5)
Change in certain assets and liabilities
Accounts receivable - customers, net........................ 8.3 16.8
Accounts receivable - other, net............................ (1.0) (0.6)
Accrued unbilled revenues................................... (4.3) 4.8
Fuel, materials and supplies inventories.................... 3.5 (19.2)
Fuel clause under recoveries................................ (34.1) ---
Other current assets........................................ 0.5 0.8
Accounts payable............................................ 27.1 28.7
Accounts payable - affiliates............................... 30.4 17.6
Customers' deposits......................................... 1.0 1.2
Accrued taxes............................................... (9.1) (9.3)
Accrued interest............................................ 1.5 1.5
Fuel clause over recoveries................................. --- 5.4
Other current liabilities................................... 3.2 3.4
- ------------------------------------------------------------------ -------------- --------------
Net Cash Provided from Operating Activities............... 64.4 94.3
- ------------------------------------------------------------------ -------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures............................................ (36.6) (75.6)
- ------------------------------------------------------------------ -------------- --------------
Net Cash Used in Investing Activities..................... (36.6) (75.6)
- ------------------------------------------------------------------ -------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES
(Decrease) increase in short-term debt, net..................... (2.0) 7.0
Dividends paid on common stock.................................. (26.1) (25.9)
- ------------------------------------------------------------------ -------------- --------------
Net Cash Used in Financing Activities..................... (28.1) (18.9)
- ------------------------------------------------------------------ -------------- --------------
NET DECREASE IN CASH AND CASH EQUIVALENTS......................... (0.3) (0.2)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.................. 0.3 0.4
- ------------------------------------------------------------------ -------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................ $ --- $ 0.2
================================================================== ============== ==============
The accompanying Notes to Financial Statements are an integral part hereof.
4
OKLAHOMA GAS AND ELECTRIC COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
1. Summary of Significant Accounting Policies
Organization
Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas and its operations are subject to regulation by the Oklahoma Corporation Commission ("OCC"), the Arkansas Public Service Commission ("APSC") and the Federal Energy Regulatory Commission ("FERC"). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“Energy Corp.”) which is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company was incorporated in 1902 under the laws of the Oklahoma Territory and is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.
Basis of Presentation
The condensed financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.
In the opinion of management, all adjustments necessary to fairly present the financial position of the Company at March 31, 2003 and December 31, 2002, and the results of its operations and cash flows for the three months ended March 31, 2003 and 2002, have been included and are of a normal recurring nature.
Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 2003 are not necessarily indicative of the results that may be expected for the year ending December 31, 2003 or for any future period. The accompanying condensed financial statements and notes thereto should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2002.
Accounting Records
The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, the Company, as a regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board (“FASB”) Statement of Financial
5
Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 provides that certain costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. At March 31, 2003 and December 31, 2002, regulatory assets of approximately $60.4 million and approximately $63.9 million, respectively, are being amortized and reflected in rates charged to customers over periods of up to 20 years. At March 31, 2003 and December 31, 2002, regulatory liabilities of approximately $111.0 million and approximately $109.3 million, respectively, have been reclassified from Accumulated Depreciation in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.”
The Company initially records costs: (i) that are probable of future recovery as a deferred charge until such time as the cost is approved by a regulatory authority, then the cost is reclassified as a regulatory asset; and (ii) that are probable of future liability as a deferred credit until such time as the amount is approved by a regulatory authority, then the amount is reclassified as a regulatory liability.
The following table is a summary of the Company’s regulatory assets and liabilities at:
March 31, December 31,
(In millions) 2003 2002
- ------------------------------------------------------------------------------------------------
Regulatory Assets
Income taxes recoverable from customers, net............. $ 33.6 $ 34.8
Unamortized loss on reacquired debt...................... 23.0 23.3
January 2002 ice storm................................... 3.6 5.4
Miscellaneous............................................ 0.2 0.4
- -------------------------------------------------------------- ----------- --------------
Total Regulatory Assets.............................. $ 60.4 $ 63.9
- -------------------------------------------------------------- ----------- --------------
Regulatory Liabilities
Accrued removal obligations, net......................... $ 111.0 $ 109.3
- -------------------------------------------------------------- ----------- --------------
Total Regulatory Liabilities......................... $ 111.0 $ 109.3
- ------------------------------------------------------------------------------------------------
Income taxes recoverable from customers represent income tax benefits previously used to reduce the Company’s revenues. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The provisions of SFAS No. 71 allowed the Company to treat these amounts as regulatory assets and liabilities and they are being amortized over the estimated remaining life of the assets to which they relate. The regulatory assets and liabilities are netted on the Company’s Condensed Balance Sheets in the line item, “Income Taxes Recoverable from Customers, Net.”
Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations. In accordance with SFAS No. 143, the Company was
6
required to reclassify the accrued removal obligations, which had previously been recorded as a liability in Accumulated Depreciation, to a regulatory liability. See Note 2 for a further discussion.
Management continuously monitors the future recoverability of regulatory assets. When in management’s judgment future recovery becomes impaired, the amount of the regulatory asset is reduced or written off, as appropriate.
If the Company were required to discontinue the application of SFAS No. 71 for some or all of its operations, it could result in writing off the related regulatory assets and liabilities; the financial effects of which could be significant.
Use of Estimates
In preparing the condensed financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed financial statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s condensed financial statements. In management’s opinion, the areas of the Company where the most significant judgment is exercised are in the valuation of pension plan assumptions, contingency reserves, unbilled revenue and the allowance for uncollectible accounts receivable.
Allowance for Uncollectible Accounts Receivable
All customer balances are written off if not collected within six months after the account is finalized. The allowance for uncollectible accounts receivable is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. The allowance for uncollectible accounts receivable was approximately $2.8 million and $4.7 million at March 31, 2003 and December 31, 2002, respectively.
Income Taxes
The Company is a member of an affiliated group that files consolidated income tax returns. Income taxes are allocated to each company in the affiliated group based on its separate taxable income or loss. Investment tax credits on electric utility property have been deferred and are being amortized to income over the life of the related property. Amortization of the investment tax credits was approximately $1.3 million for the three months ended March 31, 2003 and 2002 and is recorded as an income tax benefit in the accompanying Condensed Statements of Operations.
7
The Company follows the provisions of SFAS No. 109, “Accounting for Income Taxes”, which uses an asset and liability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted marginal tax rate. Deferred income tax expenses or benefits are based on the changes in the asset or liability from period to period.
Fair Value of Financial Instruments
The carrying value of the financial instruments on the Condensed Balance Sheets not otherwise discussed in these notes approximates market value.
Cash and Cash Equivalents
For purposes of the condensed financial statements, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.
Revenue Recognition
The Company reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. An amount is accrued as a receivable for this unbilled revenue based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
Automatic Fuel Adjustment Clauses
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component in the cost-of-service for ratemaking, are passed through to the Company’s customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC.
Fuel Inventories
Fuel inventories for the generation of electricity consist of coal, natural gas and oil. These inventories are accounted for under the last-in, first-out (“LIFO”) cost method. The estimated replacement cost of fuel inventories was higher than the stated LIFO cost by approximately $36.0 million and $7.0 million at March 31, 2003 and December 31, 2002, respectively, based on the average cost of fuel purchased.
Related Party Transactions
Energy Corp. allocated operating costs to the Company of approximately $21.0 million and $24.8 million during the three months ended March 31, 2003 and 2002, respectively. Energy
8
Corp. allocates operating costs to its affiliates based on several factors. Operating costs directly related to specific affiliates are assigned to those affiliates. Where more than one affiliate benefits from certain expenditures, the costs are shared between those affiliates receiving the benefits. Operating costs incurred for the benefit of all affiliates are allocated among the affiliates, based primarily upon head-count, occupancy, usage or the “Distragas” method. The Distragas method is a three-factor formula that uses an equal weighting of payroll, operating income and assets. The Company believes this method provides a reasonable basis for allocating common expenses.
During the three months ended March 31, 2003 and 2002, the Company paid its affiliate Enogex Inc. and subsidiaries (“Enogex”) approximately $10.0 million and $9.1 million, respectively, for transporting gas to the Company’s natural gas generating stations. These purchases are priced based on a market basket of posted prices within the region and are priced similar to purchases, which had previously been made directly from unaffiliated sources. Approximately $7.5 million and $1.7 million were recorded at March 31, 2003 and December 31, 2002, respectively, and are included in Accounts Payable - - Affiliates in the accompanying Balance Sheets for these activities.
During the three months ended March 31, 2002, the Company recorded interest income of approximately $0.2 million from Energy Corp. for advances made by the Company to Energy Corp. The Company made no advances to Energy Corp. during the three months ended March 31, 2003. During the three months ended March 31, 2003, the Company recorded interest expense of approximately $0.3 million to Energy Corp. for advances made by Energy Corp. to the Company. Energy Corp. made no advances to the Company for the three months ended March 31, 2002. The interest rate charged on advances to the Company from Energy Corp. approximates Energy Corp.’s commercial paper rate.
The Company paid approximately $26.1 million and $25.9 million in dividends to Energy Corp. during the three months ended March 31, 2003 and 2002, respectively.
Reclassifications
Certain prior year amounts have been reclassified on the condensed consolidated financial statements to conform to the 2003 presentation.
2. Accounting Pronouncements
In June 2001, the FASB issued SFAS No. 143, which applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 affects the Company’s accrued plant removal costs for generation, transmission, distribution and processing facilities and requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. If a reasonable estimate of the fair
9
value cannot be made in the period the asset retirement obligation is incurred, the liability shall be recognized when a reasonable estimate of the fair value can be made. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The recognition of an asset retirement obligation is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations represent future liabilities and, as a result, accretion expense is accrued on this liability until such time as the obligation is satisfied. Adoption of SFAS No. 143 is required for financial statements issued for fiscal years beginning after June 15, 2002. The Company adopted this new standard effective January 1, 2003 and the adoption of this new standard did not have a material impact on its financial position or results of operations. In connection with the adoption of SFAS No. 143, the Company assessed whether it had a legal obligation within the scope of SFAS No. 143. The Company determined that it had a legal obligation to retire certain assets. As the Company currently has no plans to retire any of these assets and the remaining life is indeterminable, an asset retirement obligation was not recognized; however, the Company will monitor these assets and record a liability when a reasonable estimate of the fair value can be made. As described below, amounts recovered from ratepayers related to estimated asset retirement obligations recorded as a liability in Accumulated Depreciation were reclassified as a regulatory liability in the first quarter of 2003.
SFAS No. 143 also requires that, if the conditions of SFAS No. 71 are met, a regulatory asset or liability should be recorded to recognize differences between asset retirement costs recorded under SFAS No. 143 and legal or other asset retirement costs recognized for ratemaking purposes. Upon adoption of SFAS No. 143, the Company was required to quantify the amount of asset retirement costs previously recovered from ratepayers for other than legal obligations and reclassify those differences as regulatory assets or liabilities. At December 31, 2002, approximately $109.3 million had been previously recovered from ratepayers and recorded as a liability in Accumulated Depreciation related to estimated asset retirement obligations. This balance was reclassified as a regulatory liability on the December 31, 2002 Condensed Balance Sheet.
3. Price Risk Management Assets and Liabilities
The Company periodically utilizes derivative contracts to reduce exposure to adverse interest rate fluctuations. During the three months ended March 31, 2003 and 2002, the Company’s use of price risk management instruments primarily involved the use of interest rate swap agreements to hedge the Company’s exposure to interest rate risk by converting a portion of the Company’s fixed rate debt to a floating rate. These agreements involve the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an exchange of the underlying principal amount.
In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” the Company recognizes all of its derivative instruments as Price Risk Management assets or liabilities in the Balance Sheet at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the
10
derivative instrument as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized in the same line item associated with the hedged item in current earnings during the period of the change in fair values. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, any gain or loss deferred in Accumulated Other Comprehensive Income is recognized currently in earnings. The Company’s interest rate swap agreements have been designated as fair value hedges and qualified for the shortcut method prescribed by SFAS No. 133. Under the shortcut method, the Company assumes that the hedged item’s change in fair value is exactly as much as the derivative’s change in fair value.
4. Comprehensive Loss
Accumulated other comprehensive loss at both March 31, 2003 and December 31, 2002 included approximately a $63.5 million after tax loss ($103.5 million pre-tax) related to a minimum pension liability adjustment.
5. Supplemental Cash Flow Information
Non-cash financing activities for the three months ended March 31, 2003 and 2002 included approximately $0.2 million and $0.1 million, respectively, related to the change in fair value of the interest rate swap agreement and the corresponding change in long-term debt.
Cash payments for interest, net of interest capitalized of approximately $0.2 million and $0.4 million, respectively, were approximately $8.8 million and $8.5 million for the three months ended March 31, 2003 and 2002, respectively. Cash refunds related to income taxes, net of income tax payments, were approximately $3.2 million and $18.1 million for the three months ended March 31, 2003 and 2002, respectively. Substantially all of the income tax payments and refunds are between the Company and Energy Corp.
6. Long-Term Debt
Interest Rate Swap Agreement
At March 31, 2003 and December 31, 2002, the Company had one outstanding interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate. This interest rate swap qualified as a fair value hedge under SFAS No. 133 and met all requirements for a determination that there was no in effective portion as allowed by the
11
shortcut method under SFAS No. 133. The objective of this interest rate swap was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards.
At March 31, 2003 and December 31, 2002, the fair value pursuant to the interest rate swap was approximately $7.7 million and $7.5 million, respectively, and is included in non-current Price Risk Management assets in the accompanying Condensed Balance Sheets. A corresponding net increase of approximately $7.7 million and $7.5 million is reflected in Long-Term Debt at March 31, 2003 and December 31, 2002, respectively, as this fair value hedge was effective at March 31, 2003 and December 31, 2002.
Security Ratings
On January 15, 2003, Standard & Poor’s Ratings Services (“Standard & Poor’s”) lowered the credit ratings of the Company’s senior unsecured debt from A- to BBB+. The Company may experience somewhat higher borrowing costs but does not expect the actions by Standard & Poor’s to have a significant impact on the Company’s financial position or results of operations.
On February 5, 2003, Moody’s Investors Service (“Moody’s”) lowered the credit ratings of the Company’s senior unsecured debt to A2 from A1. The Company may experience somewhat higher borrowing costs but does not expect the actions by Moody’s to have a significant impact on the Company’s financial position or results of operations.
A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
7. Short-Term Debt
The Company had short-term debt from Energy Corp. of approximately $99.0 million and $101.1 million, respectively, outstanding at March 31, 2003 and December 31, 2002. The Company uses short-term borrowings from Energy Corp. to meet working capital requirements. The following table shows Energy Corp.’s lines of credit in place at March 31, 2003. Energy Corp.’s short-term borrowings will consist of a combination of bank borrowings and commercial paper.
Lines of Credit (In millions)
-----------------------------------------------------------------------------------------------
Entity Amount Maturity
-----------------------------------------------------------------------------------------------
Energy Corp. (A) $ 200.0 January 8, 2004
100.0 January 15, 2004
15.0 April 6, 2004
The Company 100.0 June 26, 2003
-----------------------------------------------------------------------------------------------
Total $ 415.0
===============================================================================================
(A) The lines of credit at Energy Corp. are used to back up its commercial paper borrowings,
which were approximately $139.2 million at March 31, 2003. No borrowings were outstanding
at March 31, 2003 under any of the lines of credit shown above.
12
Energy Corp.’s ability to access the commercial paper market could be adversely impacted by a commercial paper ratings downgrade. The lines of credit contain ratings triggers that require annual fees and borrowing rates to increase if Energy Corp. suffers an adverse ratings impact. The impact of additional downgrades of Energy Corp.’s rating would result in an increase in the cost of short-term borrowings of approximately five to 20 basis points, but would not result in any defaults or accelerations as a result of the ratings triggers.
Unlike Energy Corp. and Enogex, the Company must obtain regulatory approval from the FERC in order to borrow on a short-term basis. The Company has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time.
8. Commitments and Contingencies
The circumstances set forth in Note 9 to the Company’s financial statements included in the Company’s Form 10-K for the year ended December 31, 2002, appropriately represent, in all material respects, the current status of any material commitments and contingent liabilities.
In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. Management consults with counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s condensed consolidated financial statements. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.
9. Rate Matters and Regulation
Regulation and Rates
The Company’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by the Company is also regulated by the OCC and the APSC. The Company’s wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of the Company’s facilities and operations.
The order of the OCC authorizing the Company to reorganize into a subsidiary of Energy Corp. contains certain provisions which, among other things, ensure the OCC access to the books and records of Energy Corp. and its affiliates relating to transactions with the Company; require the Company to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company’s customers; and prohibit the Company from pledging its assets or income for affiliate transactions.
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On October 11, 2002, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of the Company’s rate case. The administrative law judge subsequently recommended approval of the Settlement Agreement and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of the Company’s Oklahoma customers which went into effect January 6, 2003; (ii) recovery by the Company, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) recovery by the Company, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through the Company’s rider for sales to other utilities and power marketers; (iv) the Company to acquire electric generating capacity of not less than 400 megawatts to be integrated into the Company’s generation system. Key portions of the Settlement Agreement are described in detail in Note 10 to the Company’s Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2002.
As part of the Settlement Agreement, the Company also agreed to consider competitive bidding for gas transportation service to its natural gas fired generation facilities pursuant to the terms set forth in the Settlement Agreement. On April 29, 2003, the Company filed an application with the OCC in which the Company advised the OCC that after careful consideration competitive bidding for gas transportation was rejected in favor of a new intrastate firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of the Company's natural gas fired generation plants. An OCC order in the case is expected during 2003.
Security Enhancements
On August 14, 2002, the Company filed a report with the OCC outlining proposed expenditures and related actions for security enhancement. Attempting to make security investments at the proper level, the Company has developed a set of guidelines intended to minimize long-term or widespread outages, minimize the impact on critical national defense and related customers, maximize the ability to respond to and recover from an attack, minimize the financial impact on the Company that might be caused by an attack and accomplish these efforts with minimal impact on ratepayers. The OCC Staff has retained a security expert to review the report filed by the Company, and a hearing is expected to be held in July 2003.
Other Regulatory Actions
The Settlement Agreement, when it became effective, provided for the termination of the Acquisition Premium Credit Rider ("APC Rider") and the Gas Transportation Adjustment Credit Rider ("GTAC Rider").
The APC Rider was approved by the OCC in March 2000 and was implemented by the Company to reflect the completion of the recovery of the amortization premium paid by the Company when it acquired Enogex in 1986. The effect of the APC Rider was to remove
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approximately $10.7 million annually from the amount being recovered by the Company from its Oklahoma customers in current rates.
In June 2001, the OCC approved a stipulation (the “Stipulation”) to the competitive bid process of the Company’s gas transportation service from Enogex. The Stipulation directed the Company to reduce its rates to its Oklahoma retail customers by approximately $2.7 million per year through the implementation of the GTAC Rider. The GTAC Rider was a credit for gas transportation cost recovery and was applicable to and became part of each Oklahoma retail rate schedule to which the Company’s automatic fuel adjustment clause applies. As discussed above, the Settlement Agreement terminated the GTAC Rider. Consequently, these charges for gas transportation provided by Enogex are now included in base rates.
The Company’s Generation Efficiency Performance Rider (“GEP Rider”) expired in June 2002. The GEP Rider was established initially in 1997 in connection with the Company’s 1996 general rate review and was intended to encourage the Company to lower its fuel costs by: (i) allowing the Company to collect one-third of the amount by which its fuel costs were below a specified percentage (96.261 percent) of the average fuel costs of certain other investor-owned utilities in the region; and (ii) disallowing the collection of one-third of the amount by which its fuel costs exceeded a specified percentage (103.739 percent) of the average fuel costs of other investor-owned utilities. In June 2000 the OCC made modifications to the GEP Rider which had the effect of reducing the amount the Company could recover under the GEP Rider by: (i) changing the Company’s peer group to include utilities with a higher coal-to-gas generation mix; (ii) reducing the amount of fuel costs that can be recovered if the Company’s costs exceed the new peer group by changing the percentage above which the Company will not be allowed to recover one-third of the fuel costs from Oklahoma customers from 103.739 percent to 101.0 percent; (iii) reducing the Company’s share of cost savings as compared to its new peer group from 33 percent to 30 percent; and (iv) limiting to $10.0 million the amount of any awards paid to the Company or penalties charged to the Company.
State Restructuring Initiatives
Oklahoma
As previously reported, the Electric Restructuring Act of 1997 (the “1997 Act”) was designed to provide retail customers in Oklahoma a choice of their electric supplier by July 1, 2002. Additional implementing legislation was to be adopted by the Oklahoma Legislature to address many specific issues associated with the 1997 Act and with deregulation. In May 2000, a bill addressing the specific issues of deregulation was passed in the Oklahoma State Senate and then was defeated in the Oklahoma House of Representatives. In May 2001, the Oklahoma Legislature passed Senate Bill 440 (“SB 440”), which postponed the scheduled start date for customer choice from July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, SB 440 calls for a nine-member task force to further study the issues surrounding deregulation. The task force includes the Governor or his designee, the Oklahoma Attorney General, the OCC Chair and several legislative leaders, among others. In the current legislative session, Senate Bill 383 has been recently introduced to repeal the 1997 Act. It is
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unknown at this time whether the bill will be passed into law. The Company will continue to actively participate in the legislative process and expects to remain a competitive supplier of electricity. As a result of the failures of California’s attempt to deregulate its electricity markets, the Enron bankruptcy, and associated impacts on the industry, efforts to restructure the electricity market in Oklahoma appear at this time to be delayed indefinitely.
Arkansas
In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the Restructuring Law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. In March 2003, the Restructuring Law was repealed. As part of the repeal legislation, electric public utilities are permitted to recover transition costs. The Company incurred approximately $2.4 million in transition costs necessary to carry out the Company’s responsibilities associated with efforts to implement retail open access. The Company will be filing an application with the APSC in the next several months to recover these costs. The APSC will most likely schedule a hearing later in 2003.
10. Subsequent Events
Liquidity
On April 6, 2003, Energy Corp. renewed its $15.0 million line of credit facility for an additional one-year term expiring April 6, 2004.
S-3 Filing
On April 17, 2003, the Company filed a Form S-3 Registration Statement pursuant to which it may offer from time to time up to $200.0 million aggregate principal amount of the Company’s unsecured senior notes.
Storm Damage
On May 8 and May 9, 2003, the Oklahoma City area was hit by a series of tornadoes that inflicted damage to the Company's transmission and distribution system. The estimated storm damage costs are not expected to have a material effect on the Company's financial position or results of operations.
Regulatory Matters
On May 12, 2003, the Company filed with the OCC a notice of intent to seek an annual increase in its rates to its Oklahoma customers of more than one percent. The notice lists the following, among others, as major issues to be addressed in its application: (i) the acquisition of a
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generation facility in accordance with the Settlement Agreement; (ii) increased capital expenditures for efficiency improvements and reliability enhancements to ensure fuel costs are minimized, and (iii) increased pension, medical and insurance costs. The Company expects to file its application for this rate increase on or before June 27, 2003, which filing will disclose the precise amount of the rate increase being sought.
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Item 2. Management's Discussion and Analysis of Financial Condition
and
Results of Operations
Introduction
Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas and is subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“Energy Corp.”) which is an energy and energy services provider offering physical delivery and management of both electricity and natural gas in the south central United States. The Company was incorporated in 1902 under the laws of the Oklahoma Territory and is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business.
Company Strategy
In early 2002, Energy Corp. completed a review of its business strategy that was largely driven by the anticipated deregulation of the retail electric markets in Oklahoma and Arkansas. Due to a variety of factors, including the current efforts to repeal the Oklahoma Electric Restructuring Act of 1997 and the recent repeal of the Restructuring Law in Arkansas, Energy Corp. does not anticipate that deregulation of the electricity markets in Oklahoma or Arkansas will occur in the foreseeable future. The strategic direction of Energy Corp. has been revised to reflect these developments. As a result, Energy Corp. expects potentially slower earnings growth than associated with deregulation but with less variability of those earnings.
Energy Corp.’s business strategy will utilize the diversified asset position of the Company and Enogex Inc. and subsidiaries (“Enogex”) to provide energy products and services to customers primarily in the south central United States. Energy Corp. will focus on those products and services with limited or manageable commodity exposure. Energy Corp. intends for the Company to continue as an integrated utility engaged in the generation and the distribution of electricity and to represent over time approximately 70 percent of Energy Corp.’s consolidated assets. The remainder of Energy Corp.’s assets will be in Enogex’s pipeline businesses. In addition to the incremental growth opportunities that Enogex provides, Energy Corp. believes that Enogex’s risk management capabilities, commercial skills and market information provide value to all of its businesses. Federal regulation in regard to the operations of the wholesale power market may change with the proposed Standard Market Design initiative at the FERC. In addition, Oklahoma and Arkansas legislatures and utility commissions may propose changes from time to time that could subject the utilities to market risk. Accordingly, Energy Corp. is applying risk management practices to all of its operations in an effort to mitigate the potential adverse effect of any future regulatory changes.
In the near term, the Company plans on increasing its investment and growing earnings largely through the acquisition of a merchant power plant. As part of the OCC’s rate order on
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November 20, 2002, the Company is seeking to purchase an electric power plant with at least 400 megawatts (“MW”) of generating capacity and to include the cost of such plant in its rate base. Given the surplus power in the region, the Company believes there is a continuing opportunity to purchase existing power plants at prices below the cost to build. This should enable the Company to generate electricity for its customers at prices below those being paid by the Company under existing qualified cogeneration and small power production producers’ contracts (“QF contracts”). Unless extended by the Company, many of these QF contracts will expire over the next one to five years. Accordingly, the Company will continue to explore opportunities to purchase power plants in order to serve its native load. The Company anticipates filing with appropriate regulatory agencies to increase base rates to recover its investment in any power plant acquired and expects that customers should realize overall lower rates through fuel savings due to the increased efficiency of these new plants and lower capital costs than those associated with the expiring QF contracts.
Forward-Looking Statements
Except for the historical statements contained herein, the matters discussed in the following discussion and analysis, including the discussion in “2003 Outlook”, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “estimate”, “expect”, “objective”, “possible”, “potential” and similar expressions. 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; prices of electricity, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other; business conditions in the energy industry; competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; unusual weather; state and federal legislative and regulatory decisions and initiatives; changes in accounting standards, rules or guidelines; creditworthiness of suppliers, customers, and other contractual parties; actions by ratings agencies; and the other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission, including Exhibit 99.01 to the Company’s Form 10-K for the year ended December 31, 2002.
Overview
General
The following discussion and analysis presents factors which affected the Company’s results of operations for the three months ended March 31, 2003 as compared to the same period in 2002 and the Company’s financial position at March 31, 2003. The following information should be read in conjunction with the Condensed Financial Statements and Notes thereto and the Company’s Form 10-K for the year ended December 31, 2002. Known trends and contingencies of a material nature are discussed to the extent considered relevant.
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Operating Results
The Company posted a loss of $0.08 per share for the three months ended March 31, 2003 compared to a loss of $0.04 per share for the same period in 2002. The Company’s decrease was primarily attributable to lower electric rates and higher operating and maintenance expenses partially offset by increased revenue from customer growth and colder weather.
Regulatory Considerations
On October 11, 2002, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of the Company’s rate case. The administrative law judge subsequently recommended approval of the Settlement Agreement and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of the Company’s Oklahoma customers which went into effect January 6, 2003; (ii) recovery by the Company, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) recovery by the Company, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through the Company’s rider for sales to other utilities and power marketers (“off-system sales”); (iv) the Company to acquire electric generating capacity (“New Generation”) of not less than 400 MW’s to be integrated into the Company’s generation system.
The Company expects that the New Generation will provide savings, over a three-year period, in excess of $75 million. If the Company is unable to demonstrate at least $75 million in savings, the Company will be required to credit to its Oklahoma customers any unrealized savings below $75 million. In the event the Company does not acquire the New Generation by December 31, 2003, the Company will be required to credit $25.0 million annually (at a rate of 1/12 of $25.0 million per month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1, 2004 and continuing through December 31, 2006. However, if the Company purchases the New Generation subsequent to January 2004, the credit to Oklahoma customers will terminate in the first month that the New Generation begins initial operations and any credited amount to Oklahoma customers will be included in the determination of the $75.0 million targeted savings. Reference is made to Note 9 of Notes to Condensed Financial Statements in this report and to Note 10 to the Company’s Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2002 for a further discussion of the Settlement Agreement and of other recent actions relating to the Company’s rates.
On May 12, 2003, the Company filed with the OCC a notice of intent to seek an annual increase in its rates to its Oklahoma customers of more than one percent. The notice lists the following, among others, as major issues to be addressed in its application: (i) the acquisition of a generation facility in accordance with the Settlement Agreement; (ii) increased capital expenditures for efficiency improvements and reliability enhancements to ensure fuel costs are minimized, and (iii) increased pension, medical and issuance costs. The Company expects to file
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its application for this rate increase on or before June 27, 2003, which filing will disclose the precise amount of the rate increase being sought.
The Company has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred and additional changes are being proposed to the wholesale electric market. Although it appears unlikely in the near future that changes will occur to retail regulation in the states served by the Company due to the significant problems faced by California in its electric deregulation efforts and other factors, significant changes are possible, which could significantly change the manner in which the Company conducts its business. These developments at the federal and state levels are described in more detail below under “Electric Competition; Regulation.”
2003 Outlook
Energy Corp. currently expects that earnings in 2003 will be between $1.35 and $1.45 per share, assuming, among other things, normal weather and continued customer growth in the electric utility service area and improved performance at Enogex. Energy Corp. anticipates a contribution of approximately $112 to $118 million from the Company.
Energy Corp. plans to issue a combination of equity and debt in 2003 to support the capital structure at the Company for its purchase of generation and for other corporate purposes including the repayment of short-term debt. During April 2003, Energy Corp. filed two registration statements to register shares of Energy Corp.’s common stock pursuant to Energy Corp.’s Automatic Dividend Reinvestment and Stock Purchase Plan and to offer from time to time up to $130.0 million of unsecured debt securities or shares of Energy Corp.’s common stock. Also, during April 2003, the Company filed a registration statement to offer from time to time up to $200.0 million aggregate principal amount of the Company’s unsecured senior notes.
Results of Operations
Three Months Ended
March 31,
----------------------------
(In millions, except per share data) 2003 2002
- -----------------------------------------------------------------------------------
Operating income..................................... $ 2.1 $ 5.9
Net loss............................................. $ (3.3) $ (1.5)
Average common shares outstanding.................... 40.4 40.4
Dividends declared per share......................... $ 0.648 $ 0.642
- -----------------------------------------------------------------------------------
In reviewing its operating results, the Company believes that it is appropriate to focus on operating income as reported in its Condensed Statements of Operations. Operating income was approximately $2.1 million and $5.9 million for the three months ended March 31, 2003 and 2002, respectively.
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Three Months Ended
March 31,
------------------------------
(In millions) 2003 2002
- --------------------------------------------------------------------------
Operating revenues...................... $ 332.6 $ 262.1
Fuel.................................... 141.2 85.0
Purchased power......................... 72.7 63.8
- --------------------------------------------------------------------------
Gross margin on revenues................ 118.7 113.3
Other operating expenses................ 116.6 107.4
- --------------------------------------------------------------------------
Operating income........................ $ 2.1 $ 5.9
- --------------------------------------------------------------------------
System sales - MWH (A).................. 5.9 5.6
Off-system sales - MWH.................. --- 0.1
- --------------------------------------------------------------------------
Total sales - MWH....................... 5.9 5.7
- --------------------------------------------------------------------------
(A) Megawatt-hour
The Company’s operating income for the three months ended March 31, 2003 decreased approximately $3.8 million or 64.4 percent as compared to the same period in 2002. The decrease in operating income was primarily attributable to lower electric rates and higher operating and maintenance expenses partially offset by increased revenue from customer growth and colder weather.
The gross margin was approximately $118.7 million for the three months ended March 31, 2003 as compared to approximately $113.3 million during the same period in 2002, an increase of approximately $5.4 million or 4.8 percent. Growth in the Company’s service territory increased the gross margin by approximately $5.2 million due to approximately a four percent increase in sales to its customers. Higher recoveries of fuel costs from Arkansas customers through that state’s automatic fuel adjustment clause increased the gross margin by approximately $2.9 million. In Arkansas, recovery of fuel costs is subject to a bandwidth mechanism. If fuel costs are within the bandwidth range, recoveries are not adjusted on a monthly basis; rather they are reset annually on April 1. The gross margin increased approximately $1.5 million for the three months ended March 31, 2003 as compared to 2002 due to a loss of revenue in January 2002, associated with the interruption of service to our customers as a result of the severe January 2002 ice storm. The gross margin was also increased by approximately $1.0 million as a result of colder weather in 2003 in the Company’s service territory. Partially offsetting the increase in gross margin was a decrease of approximately $4.2 million due to lower electric rates resulting from the Company’s rate reduction, which went into effect on January 6, 2003. The loss of revenue associated with various rate riders also decreased gross margin by approximately $1.0 million.
Cost of goods sold for the Company consists of fuel used in electric generation and purchased power. Fuel expense was approximately $141.2 million for the three months ended March 31, 2003 as compared to approximately $85.0 million during the same period in 2002, an increase of approximately $56.2 million or 66.1 percent. The increase was due primarily to an increase in the average cost of fuel per kilowatt-hour due to higher natural gas prices in the first quarter of 2003. Purchased power costs were approximately $72.7 million for the three months ended March 31, 2003 as compared to approximately $63.8 million during the same period in
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2002, an increase of approximately $8.9 million or 13.9 percent. The increase was primarily due to a 19.2 percent increase in the volume of energy purchased in the first quarter of 2003.
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component included in the cost-of-service for ratemaking, are passed through to the Company’s customers through automatic fuel adjustment clauses. While the regulatory mechanisms for recovering fuel costs differ in Oklahoma and Arkansas, in both states the costs are passed through to customers and are intended to provide neither an ultimate benefit nor detriment to the Company. The automatic fuel adjustment clauses are subject to periodic review by the OCC, the APSC and the FERC. The OCC, the APSC and the FERC have authority to review the appropriateness of gas transportation charges or other fees the Company pays to Enogex.
Other operating expenses, consisting of operating and maintenance expense, depreciation expense and taxes other than income, were approximately $116.6 million for the three months ended March 31, 2003 as compared to approximately $107.4 million during the same period in 2002, an increase of approximately $9.2 million or 8.6 percent. The Company’s operating and maintenance expenses were approximately $72.0 million for the three months ended March 31, 2003 as compared to approximately $64.7 million during the same period in 2002, an increase of approximately $7.3 million or 11.3 percent. This increase was primarily due to approximately $5.4 million of operating and maintenance costs incurred during the first quarter of 2002 in connection with the severe January 2002 ice storm being reported as a regulatory asset. These 2002 expenditures, incurred by field service personnel, would normally have been charged to maintenance expenses. Also contributing to the increase in operating and maintenance expenses was an increase of approximately $2.3 million in contract labor, primarily related to the overhaul of one of the Company’s turbines. Pension and benefit expenses increased approximately $2.0 million for the three months ended March 31, 2003 as compared to the same period in 2002 due to the general upward trend in these costs. These increases were partially offset by lower levels of uncollectibles expense of approximately $1.2 million and lower levels of overtime of approximately $1.1 million for the three months ended March 31, 2003 as compared to the same period in 2002.
Depreciation expense was approximately $32.6 million for the three months ended March 31, 2003 as compared to approximately $30.8 million during the same period in 2002, an increase of approximately $1.8 million or 5.8 percent. The increase was due to the amortization of the regulatory asset associated with the January 2002 ice storm as set forth in the Settlement Agreement. See Note 9 of Notes to Condensed Financial Statements. Taxes other than income were approximately $12.0 million for the three months ended March 31, 2003 as compared to approximately $11.9 million during the same period in 2002, an increase of approximately $0.1 million or 0.8 percent. This increase was due to higher ad valorem tax accruals.
Net Interest Expense
Net interest expense includes interest income, interest expense and other interest charges. Net interest expense was approximately $9.9 million for the three months ended March 31, 2003
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as compared to approximately $9.4 million during the same period in 2002, an increase of approximately $0.5 million or 5.3 percent. This increase was primarily due to a decrease in interest income of approximately $0.4 million of which approximately $0.2 million related to the sale of the Company’s heat pump loans during December 2002 and a decrease of approximately $0.2 million related to intercompany interest income with Energy Corp.
Income Tax Benefit
Income tax benefit was approximately $4.9 million for the three months ended March 31, 2003 as compared to approximately $2.5 million during the same period in 2002, an increase of approximately $2.4 million or 96.0 percent. The increase was primarily from a higher pre-tax loss at the Company during the first quarter of 2003. Amortization of the investment tax credits was approximately $1.3 million for the three months ended March 31, 2003 and 2002 and is recorded as an income tax benefit in the Company's Condensed Statements of Operations.
Financial Condition
The balance of Fuel Clause Under Recoveries was approximately $48.8 million and $14.7 million at March 31, 2003 and December 31, 2002, respectively, an increase of approximately $34.1 million or 232.0 percent. This increase was due to under recoveries from the Company’s customers as the Company’s cost of fuel exceeded the amount billed during the first quarter of 2003. The cost of fuel subject to recovery through the fuel clause mechanism was approximately $1.54 per million British thermal unit ("MMBtu") in December 2002, and was approximately $2.28 per MMBtu for the quarter ended March 31, 2003. The Company's fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers' bills. As a result the Company under recovers fuel cost in periods of rising prices and over recovers fuel cost when prices decline. Provision in the fuel clauses allow the Company to amortize under or over recovery. The Company began amortizing the under collected amounts beginning with the April 2003 customers bills.
The balance of Accounts Payable – Other was approximately $90.3 million and $63.2 million at March 31, 2003 and December 31, 2002, respectively, an increase of approximately $27.1 million or 42.9 percent. The increase was due to a $26.2 million increase in the cost of fuel under recovered in March 2003.
Liquidity and Capital Requirements
General
The Company’s primary needs for capital are related to replacing or expanding existing facilities in its electric utility business. Other capital requirements are primarily related to maturing debt, operating lease obligations, hedging activities and delays in recovering unconditional purchase obligations. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings from Energy Corp. and permanent financings.
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Interest Rate Swap Agreement
At March 31, 2003 and December 31, 2002, the Company had one outstanding interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed debt due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate. This interest rate swap qualified as a fair value hedge under SFAS No. 133 and met all requirements for a determination that there was no in effective portion as allowed by the shortcut method under SFAS No. 133. The objective of this interest rate swap was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards.
At March 31, 2003 and December 31, 2002, the fair value pursuant to the interest rate swap was approximately $7.7 million and $7.5 million, respectively, and is included in non-current Price Risk Management assets in the accompanying Condensed Balance Sheets. A corresponding net increase of approximately $7.7 million and $7.5 million is reflected in Long-Term Debt at March 31, 2003 and December 31, 2002, respectively, as this fair value hedge was effective at March 31, 2003 and December 31, 2002.
Future Capital Requirements
The Company’s 2003 to 2005 construction program does not include the building of any additional generating units. Instead, in accordance with the Settlement Agreement approved by the OCC on November 20, 2002, the Company intends to purchase an electric generating plant with at least 400 MW’s of generating capacity. The Company believes that an efficient combined cycle plant can be purchased for a price less than the cost to build a new facility. To reliably meet the increased electricity needs of the Company’s customers during the foreseeable future, the Company will continue to invest to maintain the integrity of the delivery system. Approximately $4.9 million of the Company’s capital expenditures budgeted for 2003 are to comply with environmental laws and regulations.
Future financing requirements may be dependent, to varying degrees, upon numerous factors such as general economic conditions, abnormal weather, load growth, acquisitions of other businesses, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new legislation and market entry of competing electric power generators.
Future Sources of Financing
General
Apart from the funds required to purchase at least 400 MW’s of a power plant pursuant to the Settlement Agreement, management expects that internally generated funds will be adequate over the next three years to meet other anticipated capital expenditures, operating needs, payment of dividends and maturities of long-term debt.
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Short-Term Debt
Short-term borrowings from Energy Corp. are used to meet working capital requirements. The following table shows Energy Corp.’s lines of credit in place at April 30, 2003. Energy Corp.’s short-term borrowings will consist of a combination of bank borrowings and commercial paper.
Lines of Credit (In millions)
------------------------------------------------------------------------------------------------
Entity Amount Maturity
------------------------------------------------------------------------------------------------
Energy Corp. (A) $ 200.0 January 8, 2004
100.0 January 15, 2004
15.0 April 6, 2004
The Company 100.0 June 26, 2003
------------------------------------------------------------------------------------------------
Total $ 415.0
================================================================================================
(A) The lines of credit at Energy Corp. are used to back up its commercial paper borrowings,
which were approximately $202.6 million at April 30, 2003. No borrowings were outstanding at
April 30, 2003 under any of the lines of credit shown above.
Energy Corp.’s ability to access the commercial paper market could be adversely impacted by a commercial paper ratings downgrade. The lines of credit contain ratings triggers that require annual fees and borrowing rates to increase if Energy Corp. suffers an adverse ratings impact. The impact of additional downgrades of Energy Corp.’s rating would result in an increase in the cost of short-term borrowings of approximately five to 20 basis points, but would not result in any defaults or accelerations as a result of the ratings triggers. See “Security Ratings” for potential financing needs upon a downgrade by Moody’s Investors Service (“Moody’s”) of Enogex’s long-term debt rating.
Unlike Energy Corp. and Enogex, the Company must obtain regulatory approval from the FERC in order to borrow on a short-term basis. The Company has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time.
Security Ratings
On January 15, 2003, Standard & Poor’s Ratings Services (“Standard & Poor’s”) lowered the credit ratings of the Company’s senior unsecured debt from A- to BBB+. Standard & Poor’s cited the relatively low-risk low-cost efficient operations of the Company. The Company may experience somewhat higher borrowing costs but does not expect the actions by Standard & Poor’s to have a significant impact on the Company’s financial position or results of operations.
On February 5, 2003, Moody’s lowered the credit ratings of the Company’s senior unsecured debt to A2 from A1. The outlook for the Company is stable. Moody’s cited the diminished credit profile of the Company with it having competitive generation and stable cash flow but with regulatory risk associated with the acquisition of at least 400 MW’s of new generation. The Company may experience somewhat higher borrowing costs but does not expect the actions by Moody’s to have a significant impact on the Company’s financial position or results of operations.
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A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Critical Accounting Policies and Estimates
The Condensed Financial Statements and Notes to Condensed Financial Statements included in this Form 10-Q and in the Company’s Form 10-K for the year ended December 31, 2002 contain information that is pertinent to Management’s Discussion and Analysis. In preparing these condensed financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed financial statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s condensed financial statements. However, the Company has taken conservative positions, where assumptions and estimates are used, in order to minimize the negative financial impact to the Company that could result if actual results vary from the assumptions and estimates. In management’s opinion, the areas of the Company where the most significant judgment is exercised are in the valuation of pension plan assumptions, contingency reserves, unbilled revenue and the allowance for uncollectible accounts receivable. The selection, application and disclosure of the following critical accounting estimates have been discussed with the Company’s audit committee.
Pension and other postretirement plan expenses and liabilities are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets and assumed discount rates. Actual changes in the fair market value of plan assets and differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension expense ultimately recognized. For a discussion of the pension plan rate assumptions, reference is made to Note 8 of the Notes to Financial Statements in the Company’s Form 10-K for the year ended December 31, 2002.
In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. Management consults with counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s condensed financial statements.
The Company reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. Unbilled revenue is presented in Accrued Unbilled Revenues on the Condensed Balance Sheets and in Operating Revenues on the Condensed Statements of Operations based on estimates of usage and prices during the period. At March 31, 2003 and December 31, 2002, Accrued Unbilled Revenues were approximately $32.5
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million and $28.2 million, respectively. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
All customer balances are written off if not collected within six months after the account is finalized. The allowance for uncollectible accounts receivable is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. The allowance for uncollectible accounts receivable is a reduction to Accounts Receivable on the Condensed Balance Sheets and is included in Other Operation and Maintenance Expense on the Condensed Statements of Operations. The allowance for uncollectible accounts receivable was approximately $2.8 million and $4.7 million at March 31, 2003 and December 31, 2002, respectively.
Accounting Pronouncements
In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 affects the Company’s accrued plant removal costs for generation, transmission, distribution and processing facilities and requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. If a reasonable estimate of the fair value cannot be made in the period the asset retirement obligation is incurred, the liability shall be recognized when a reasonable estimate of the fair value can be made. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The recognition of an asset retirement obligation is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations represent future liabilities and, as a result, accretion expense is accrued on this liability until such time as the obligation is satisfied. Adoption of SFAS No. 143 is required for financial statements issued for fiscal years beginning after June 15, 2002. The Company adopted this new standard effective January 1, 2003 and the adoption of this new standard did not have a material impact on its financial position or results of operations. In connection with the adoption of SFAS No. 143, the Company assessed whether it had a legal obligation within the scope of SFAS No. 143. The Company determined that it had a legal obligation to retire certain assets. As the Company currently has no plans to retire any of these assets and the remaining life is indeterminable, an asset retirement obligation was not recognized; however, the Company will monitor these assets and record a liability when a reasonable estimate of the fair value can be made. As described below, amounts recovered from ratepayers related to estimated asset retirement obligations recorded as a liability in Accumulated Depreciation were reclassified as a regulatory liability in the first quarter of 2003.
SFAS No. 143 also requires that, if the conditions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” are met, a regulatory asset or liability should be recorded
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to recognize differences between asset retirement costs recorded under SFAS No. 143 and legal or other asset retirement costs recognized for ratemaking purposes. Upon adoption of SFAS No. 143, the Company was required to quantify the amount of asset retirement costs previously recovered from ratepayers for other than legal obligations and reclassify those differences as regulatory assets or liabilities. At December 31, 2002, approximately $109.3 million had been previously recovered from ratepayers and recorded as a liability in Accumulated Depreciation related to estimated asset retirement obligations. This balance was reclassified as a regulatory liability on the December 31, 2002 Condensed Balance Sheet.
Electric Competition; Regulation
Proposed Standard Market Design Rulemaking
In July 2002, the FERC issued a Notice of Proposed Rulemaking on Standard Market Design Rulemaking for regulated utilities. If implemented as proposed, the rulemaking will substantially change how wholesale markets operate throughout the United States. The proposed rulemaking expands the FERC’s intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale markets. The rule contemplates that all wholesale and retail customers will be on a single network transmission service tariff. The rule also contemplates the implementation of a bid-based system for buying and selling energy in wholesale markets. RTOs or Independent Transmission Providers will administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct new transmission, generation or demand side programs to reduce transmission constraints and meet regional energy requirements. Finally, the rule envisions the development of Regional Market Monitors responsible for ensuring the individual participants do not exercise unlawful market power. The FERC recently extended the comment period, with the anticipation that the final rules would be in place in 2003 and the contemplated market changes would take place in 2003 and 2004. On April 28, 2003, the FERC issued a White Paper, “Wholesale Market Platform”, in which the FERC expressed its core mission under the Federal Power Act to achieve wholesale electricity markets that produce just and reasonable prices and work for customers. In the White Paper, the FERC acknowledged numerous concerns raised by approximately 1,000 sets of formal comments. The FERC committed in the White Paper to work with interested parties including state commissions to find solutions that will recognize regional differences within regions subject to the FERC’s jurisdiction. The White Paper discloses that the proposed rule will be changed in several respects as reflected in the White Paper and following additional regional technical conferences. In its Notice of White Paper, the FERC indicated it would be issuing notices of these conferences shortly.
Reference is made to Note 9 and Note 10 of Notes to Condensed Financial Statements included in this report and to "Electric Competetion; Regulation" in Item 7 of the Company's Form 10-K for the year ended December 31, 2002 for a discussion of pending regulatory actions involving the Company and of other initiatives to increase competition in the retail and wholesale sale of electricity.
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Commitments and Contingencies
The circumstances set forth in Note 9 to the Company’s financial statements included in the Company’s Form 10-K for the year ended December 31, 2002, appropriately represent, in all material respects, the current status of any material commitments and contingent liabilities.
In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. Management consults with counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s condensed consolidated financial statements. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently pending or threatened lawsuits and claims will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
Besides the various contingencies described in the Company’s Form 10-K for the year ended December 31, 2002, the Company’s ability to fund its future operational needs and to finance its construction program could be impacted by numerous factors such as general economic conditions, abnormal weather, load growth, acquisitions of other businesses, actions by rating agencies, inflation, changes in environmental laws or regulations, rate increases or decreases allowed by regulatory agencies, new regulation and market entry of competing electric power generators.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Under the reduced disclosure format permitted by General Instruction H(2)(c) of Form 10-Q, the information otherwise required by Item 3 has been omitted.
Item 4. Controls and Procedures
The Company maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Within the 90-day period prior to the filing of this report, an evaluation was carried out under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of the Company’s disclosure controls and procedures. Based on that evaluation, the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.
Subsequent to the date of their evaluation, there have been no significant changes in the Company’s internal controls or in other factors that could significantly affect these controls.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Reference is made to Part I, Item 3 of the Company’s Form 10-K for the year ended December 31, 2002 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 material changes in the previously reported proceedings.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit No. Description
----------- -----------
99.01 Certification Pursuant to 18 U.S.C. Section 1350 As Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K
The Company filed a Current Report on Form 8-K on January 31, 2003 to report its 2002 results of operations and financial condition.
The Company filed a Current Report on Form 8-K on April 30, 2003 to report its results of operations and financial condition for the first quarter of 2003.
The Company filed a Current Report on Form 8-K on May 6, 2003 to report additional financial data discussed in Energy Corp.'s first quarter 2003 earnings conference call.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
OKLAHOMA GAS AND ELECTRIC COMPANY
(Registrant)
By /s/ Donald R. Rowlett
Donald R. Rowlett
Vice President and Controller
(On behalf of the registrant and in
his capacity as Chief Accounting Officer)
May 15, 2003
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CERTIFICATIONS
I, Steven E. Moore, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Oklahoma Gas and Electric Company;
2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: May 15, 2003
/s/ Steven E. Moore
Steven E. Moore
Chairman of the Board, President and
Chief Executive Officer
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CERTIFICATIONS
I, James R. Hatfield, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Oklahoma Gas and Electric Company;
2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: May 15, 2003
/s/ James R. Hatfield
James R. Hatfield
Senior Vice President and
Chief Financial Officer
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Exhibit 99.01
Certification Pursuant to 18 U.S.C. Section 1350
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
In connection with the Quarterly Report of Oklahoma Gas and Electric Company (the "Company") on Form 10-Q for the period ended March 31, 2003, as filed with the Securities and Exchange Commission (the "Report"), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:
1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and
2) The information contained in the Report fairly presents, in all material respects,
the financial condition and results of operations of the Company.
May 15, 2003
/s/ Steven E. Moore
------------------------------------------------------
Steven E. Moore
Chairman of the Board, President
and Chief Executive Officer
/s/ James R. Hatfield
------------------------------------------------------
James R. Hatfield
Senior Vice President and
Chief Financial Officer
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