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 September 30, 2002
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
As of October 31, 2002, 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 SEPTEMBER 30, 2002
TABLE OF CONTENTS
PART I - FINANCIAL INFORMATION Page
Item 1. Financial Statements (Unaudited)
Condensed Balance Sheets....................................... 1
Condensed Statements of Income................................. 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...................................... 12
Item 3. Quantitative and Qualitative Disclosures About Market Risk....... 27
Item 4. Controls and Procedures.......................................... 28
PART II - OTHER INFORMATION
Item 1. Legal Proceedings................................................ 29 Item 6. Exhibits and Reports on Form 8-K................................. 29 Signature................................................................ 30 Certifications........................................................... 31
i
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
(In millions)
ASSETS
CURRENT ASSETS
Cash and cash equivalents..................................... $ 0.5 $ 0.4
Accounts receivable - customers, less reserve of $5.3 and
$6.2, respectively.......................................... 147.3 98.3
Accrued unbilled revenues..................................... 53.3 35.6
Accounts receivable - other................................... 16.3 12.1
Fuel inventories, at LIFO cost................................ 61.7 54.9
Materials and supplies, at average cost....................... 37.8 32.6
Accumulated deferred tax assets............................... 7.9 7.5
Prepayments................................................... 0.6 4.7
Fuel clause under recoveries.................................. 17.1 ---
Provision for payments of take or pay gas..................... 0.4 30.8
- ---------------------------------------------------------------- ------------- ------------
Total current assets........................................ 342.9 276.9
- ---------------------------------------------------------------- ------------- ------------
OTHER PROPERTY AND INVESTMENTS, at cost......................... 47.6 15.5
- ---------------------------------------------------------------- ------------- ------------
PROPERTY, PLANT AND EQUIPMENT
In service.................................................... 4,080.6 3,961.6
Construction work in progress................................. 34.8 22.5
- ---------------------------------------------------------------- ------------- ------------
Total property, plant and equipment......................... 4,115.4 3,984.1
Less accumulated depreciation............................. 2,016.3 1,978.8
- ---------------------------------------------------------------- ------------- ------------
Net property, plant and equipment........................... 2,099.1 2,005.3
- ---------------------------------------------------------------- ------------- ------------
DEFERRED CHARGES AND OTHER ASSETS
Provision for payments of take or pay gas..................... 32.5 8.5
Income taxes recoverable through future rates, net............ 36.8 37.6
Intangible asset - unamortized prior service cost............. 42.4 42.4
Prepaid benefit obligation.................................... 34.5 11.9
Price risk management......................................... 6.3 ---
Other......................................................... 37.6 36.2
- ---------------------------------------------------------------- ------------- ------------
Total deferred charges and other assets..................... 190.1 136.6
- ---------------------------------------------------------------- ------------- ------------
TOTAL ASSETS.................................................... $ 2,679.7 $ 2,434.3
================================================================ ============= ============
The accompanying Notes to Condensed Financial Statements are an integral part hereof.
1
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS (Continued)
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
(In millions)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates................................. $ 202.7 $ 25.9
Accounts payable - other...................................... 54.8 58.8
Customers' deposits........................................... 31.0 28.4
Accrued taxes................................................. 30.0 20.3
Accrued interest.............................................. 15.5 14.4
Tax collections payable....................................... 9.3 4.7
Accrued vacation.............................................. 12.1 11.8
Provision for payments of take or pay gas..................... 0.4 30.8
Fuel clause over recoveries................................... --- 23.4
Capital lease obligation...................................... 2.3 ---
Labor accrued but not paid.................................... 2.6 0.4
Other......................................................... 7.2 6.0
- ---------------------------------------------------------------- ------------- ------------
Total current liabilities................................... 367.9 224.9
- ---------------------------------------------------------------- ------------- ------------
LONG-TERM DEBT.................................................. 709.2 700.4
- ---------------------------------------------------------------- ------------- ------------
DEFERRED CREDITS AND OTHER LIABILITIES
Capital lease obligation - non-current........................ 30.5 ---
Accrued pension and benefit obligation........................ 81.3 80.9
Accumulated deferred income taxes............................. 434.4 439.0
Accumulated deferred investment tax credits................... 48.5 52.3
Price risk management......................................... --- 2.4
Provision for payments of take or pay gas..................... 32.5 8.5
Other......................................................... --- 0.3
- ---------------------------------------------------------------- ------------- ------------
Total deferred credits and other liabilities................ 627.2 583.4
- ---------------------------------------------------------------- ------------- ------------
STOCKHOLDERS' EQUITY
Common stockholders' equity................................... 512.4 512.4
Retained earnings............................................. 482.9 433.1
Accumulated other comprehensive loss, net of tax.............. (19.9) (19.9)
- ---------------------------------------------------------------- ------------- ------------
Total stockholders' equity.................................. 975.4 925.6
- ---------------------------------------------------------------- ------------- ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,679.7 $ 2,434.3
================================================================ ============= ============
The accompanying Notes to Condensed Financial Statements are an integral part hereof.
2
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------------- -------------------------
2002 2001 2002 2001
------------ ------------ ----------- -----------
(In millions, except per share data)
OPERATING REVENUES......................... $ 489.9 $ 508.1 $ 1,103.2 $ 1,194.5
COST OF GOODS SOLD......................... 207.3 225.7 534.2 619.5
- ------------------------------------------- ------------ ------------ ----------- -----------
Gross margin on revenues................... 281.6 282.4 569.0 575.0
Other operation and maintenance.......... 68.9 69.5 209.1 213.0
Depreciation and amortization............ 30.9 29.2 91.9 89.8
Taxes other than income.................. 11.6 11.4 35.2 34.5
- ------------------------------------------- ------------ ------------ ----------- -----------
OPERATING INCOME........................... 170.2 172.3 232.8 237.7
- ------------------------------------------- ------------ ------------ ----------- -----------
OTHER INCOME............................... 0.5 0.3 1.2 3.2
OTHER EXPENSES............................. (1.1) (0.6) (3.0) (4.8)
- ------------------------------------------- ------------ ------------ ----------- -----------
EARNINGS BEFORE INTEREST AND TAXES......... 169.6 172.0 231.0 236.1
INTEREST INCOME (EXPENSES)
Interest income.......................... 0.3 0.4 1.2 1.4
Interest on long-term debt............... (9.6) (10.3) (28.7) (32.3)
Allowance for borrowed funds used
during construction.................... 0.1 0.2 0.8 0.6
Other interest charges................... (1.0) (1.0) (2.5) (4.0)
- ------------------------------------------- ------------ ------------ ----------- -----------
Net interest expenses.................. (10.2) (10.7) (29.2) (34.3)
- ------------------------------------------- ------------ ------------ ----------- -----------
INCOME BEFORE TAXES........................ 159.4 161.3 201.8 201.8
INCOME TAX EXPENSE......................... 61.0 61.2 74.1 74.7
- ------------------------------------------- ------------ ------------ ----------- -----------
NET INCOME................................. $ 98.4 $ 100.1 $ 127.7 $ 127.1
=========================================== ============ ============ =========== ===========
AVERAGE COMMON SHARES OUTSTANDING.......... 40.4 40.4 40.4 40.4
EARNINGS PER AVERAGE COMMON SHARE.......... $ 2.44 $ 2.48 $ 3.16 $ 3.15
=========================================== ============ ============ =========== ===========
DIVIDENDS PAID PER SHARE................... $ 0.644 $ 0.642 $ 1.928 $ 1.925
=========================================== ============ ============ =========== ===========
The accompanying Notes to Condensed Financial Statements are an integral part hereof.
3
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
-----------------------------
2002 2001
------------ ------------
(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income......................................................... $ 127.7 $ 127.1
Adjustments to reconcile net income to net cash provided
from operating activities
Depreciation and amortization.................................... 91.9 89.8
Deferred income taxes and investment tax credits, net............ (27.4) (0.7)
Other assets..................................................... (90.9) (14.1)
Other liabilities................................................ 70.2 1.4
Change in certain current assets and liabilities
Accounts receivable - customers................................ (49.0) (49.7)
Accrued unbilled revenues...................................... (17.7) (2.3)
Fuel, materials and supplies inventories....................... (12.0) 7.0
Accumulated deferred tax assets................................ (0.4) 0.9
Other current assets........................................... 13.2 32.0
Accounts payable............................................... 145.3 (2.0)
Accrued taxes.................................................. 9.7 8.9
Accrued interest............................................... 1.0 1.4
Other current liabilities...................................... (47.3) 12.9
- --------------------------------------------------------------------- ------------ ------------
Net Cash Provided from Operating Activities.................. 214.3 212.6
- --------------------------------------------------------------------- ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures............................................... (168.3) (100.1)
- --------------------------------------------------------------------- ------------ ------------
Net Cash Used in Investing Activities........................ (168.3) (100.1)
- --------------------------------------------------------------------- ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase (decrease) in short-term debt, net........................ 32.0 (34.7)
Cash dividends declared on common stock............................ (77.9) (77.7)
- --------------------------------------------------------------------- ------------ ------------
Net Cash Used in Financing Activities........................ (45.9) (112.4)
- --------------------------------------------------------------------- ------------ ------------
NET INCREASE IN CASH AND CASH EQUIVALENTS............................ 0.1 0.1
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 0.4 0.4
- --------------------------------------------------------------------- ------------ ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 0.5 $ 0.5
===================================================================== ============ ============
- -----------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR
Interest (net of amount capitalized $0.8 and $0.6, respectively). $ 25.5 $ 29.1
Income taxes..................................................... $ 0.6 $ 1.0
- -----------------------------------------------------------------------------------------------------
NON-CASH INVESTING AND FINANCING ACTIVITIES
Interest rate swap............................................... $ (8.7) $ (2.6)
Change in fair value of long-term debt........................... $ 8.7 $ 2.6
Assumption of asset and related debt............................. $ 33.8 $ ---
- -----------------------------------------------------------------------------------------------------
The accompanying Notes to Condensed 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") is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity to retail and wholesale customers in Oklahoma and western Arkansas. The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. 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 owns and operates eight generating stations and is the largest electric utility in Oklahoma. The Company's franchised service territory includes the Fort Smith, Arkansas area, which is the second largest market in that state.
Basis of Reporting
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 September 30, 2002 and December 31, 2001, the results of operations for the three and nine months ended September 30, 2002 and 2001, and the results of cash flows for the nine months ended September 30, 2002 and 2001, have been included and are of a normal recurring nature. Certain amounts have been reclassified in the condensed financial statements to conform to the 2002 presentation.
Operating results for the three and nine months ended September 30, 2002 are not necessarily indicative of the results that may be expected for the year ending December 31, 2002 or for any future period. 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. Actual results could differ from those estimates. 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, 2001.
5
Accounting Records
The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission and adopted by the Oklahoma Corporation Commission ("OCC") and the Arkansas Public Service Commission. Additionally, the Company, as a regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board ("FASB") Statement of Financial 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 expected recovery from customers in future rates. Likewise, certain credits that would otherwise reduce expense are deferred as regulatory liabilities based on 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. The Company has deferred approximately $5.4 million of operating costs incurred to restore power to customers subsequent to the January 30, 2002 ice storm. The Company is seeking approval from the OCC to recover these deferred costs over a three-year period. See Notes 5 and 6 and "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations-Regulation and Rates-Recent Regulatory Matters" for a further discussion. At September 30, 2002, regulatory assets of $89.8 million and regulatory liabilities of $28.8 million are being amortized and reflected in rates charged to customers over periods of up to 20 years.
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.
The Company uses a straight-line method to amortize investment tax credit. This can produce an artificially low effective tax rate when net income before taxes is relatively low, which usually occurs in the first quarter of each year. On an annual basis, the impact of the investment tax credit from year to year is relatively stable. Additionally, the Company received a refund of Oklahoma state income tax related to Oklahoma investment tax credits.
Cash and Cash Equivalents
For purposes of these condensed financial statements, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates market value.
6
2. Accounting Pronouncements
Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB 133" and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." SFAS No. 133 requires the Company to record all derivatives on the Balance Sheet at fair value. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the accompanying Condensed Statements of Income. Changes in the fair value of effective fair value hedges are recorded in Price Risk Management in the accompanying Condensed Balance Sheets, with a corresponding net change in the hedged asset or liability. Changes in the fair value of effective cash flow hedges are recorded as a component of Accumulated Other Comprehensive Income, which is later reclassified to earnings when the related hedged transaction is reflected in income.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 will affect the Company's accrued plant removal costs for generation, transmission and distribution facilities and will require 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. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Adoption of SFAS No. 143 is required for financial statements issued for fiscal years beginning after June 15, 2002. The Company will adopt this new standard effective January 1, 2003. Management has not yet determined the impact of this new standard on its financial position or results of operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that an impairment loss be recognized only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and that the measurement of any impairment loss be the difference between the carrying amount and the fair value of the long-lived asset. SFAS No. 144 also required companies to separately report discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. Adoption of SFAS No. 144 is required for financial statements issued for fiscal years beginning after December 15, 2001. The Company adopted SFAS No. 144 effective January 1, 2002 and the adoption of this new standard did not have a material impact on its financial position or results of operations.
In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial accounting and reporting for costs associated with exit and disposal activities and supersedes Emerging Issues Task Force
7
("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires recognition of a liability for a cost associated with an exit or disposal activity when the liability is incurred, as opposed to when the entity commits to an exit plan under EITF 94-3. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Adoption of SFAS No. 146 is required for exit and disposal activities initiated after December 31, 2002. The Company will adopt this new standard effective January 1, 2003. Management has not yet determined the impact of this new standard on its financial position or results of operations.
3. Comprehensive Income
Accumulated other comprehensive loss at both September 30, 2002 and December 31, 2001 included a $19.9 million after-tax loss ($32.5 million pre-tax) related to a minimum pension liability adjustment. There were no other comprehensive income items for the three and nine months ended September 30, 2002 and 2001.
4. Long-Term Debt
During 2001, the Company entered into an interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate 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 of the requirements for a determination that there was no ineffective 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 raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standard.
5. Commitments and Contingencies
Rate Case
In September 2001, the director of the OCC public utility division filed an application with the OCC to review the rates of the Company. On January 28, 2002, the Company filed its response requesting a $22.0 million annual rate increase. Approximately $10.3 million of the requested rate increase related to enhanced security as a result of the September 11, 2001 terrorist attacks and approximately $11.7 million related to increased capacity needs and system reliability.
On January 30, 2002, a significant ice storm hit the Company's service territory and inflicted major damage to the transmission and distribution infrastructure with total expenditures of approximately $92.0 million. The ice storm affected approximately 195,000 of the Company's customers and approximately 15,000 square miles of the Company's service territory. The area of damage was within counties that were declared a federal disaster area. Of the $92.0 million, approximately $86.6 million was related to capital expenditures and $5.4 million was related to
8
operating expenditures. The capital expenditures of approximately $86.6 million have been recorded as part of the Company's Property, Plant and Equipment. The approximately $5.4 million in operating expenditures have been deferred. On July 1, 2002, the Company filed direct testimony in support of recovery for the $5.4 million of deferred operating costs over three years.
In October 2002, the Company settled the rate case, including recovery of the capital expenditures and deferred operating costs associated with the ice storm. See Note 6 for a further discussion.
Natural Gas Storage Facility Agreement with Central Oklahoma Oil and Gas Corp.
The Company entered into an agreement with the parent company of Central Oklahoma Oil and Gas Corp. ("COOG"), an unrelated third-party, to develop a natural gas storage facility (the "Storage Facility"). During 1996, the Company completed negotiations and contracted with COOG for gas storage services from the Storage Facility. Pursuant to the contract, COOG reimbursed the Company for all outstanding cash advances and interest amounting to approximately $46.8 million. In 1997, COOG obtained permanent financing for the Storage Facility and issued a note (the "COOG Note") to an unaffiliated third-party. The original amount of the COOG Note was $49.5 million. As part of the arrangement for the permanent financing, Energy Corp. agreed, upon the occurrence of a monetary default by COOG on the COOG Note, to purchase the COOG Note from the holders at a price equal to the unpaid principal and interest under the COOG Note.
In July 1998, the Company's affiliate Enogex Inc. and subsidiaries ("Enogex") entered into a Storage Lease Agreement with COOG ("Enogex Storage Agreement") whereby Enogex agreed to lease underground gas storage from COOG, with the capacity being developed by COOG. The Enogex Storage Agreement was accounted for as a capital lease, and an asset was recorded for $26.5 million, which is being amortized over 40 years. As part of the Enogex Storage Agreement, Enogex was granted an option to purchase the Storage Facility. Also as part of the Enogex Storage Agreement, Energy Corp. agreed to make up to a $12.0 million secured loan to an affiliate of COOG (the "COOG Affiliate Loan"). At September 30, 2002, the amount outstanding under the COOG Affiliate Loan is $8.0 million. The COOG Affiliate Loan was originally repayable in 2003 and was secured by the assets and stock of COOG. This loan is classified as Other Property and Investments on the books of Energy Corp. While Energy Corp. fully believes it will collect all amounts receivable under the COOG Affiliate Loan in the event the COOG affiliate is unable to pay the COOG Affiliate Loan, Energy Corp. would be required to write off the portion of such loan that is not repaid and which cannot be offset against other COOG liabilities.
In 2001, disputes arose under the Enogex Storage Agreement between Enogex and COOG. The parties arbitrated these disputes pursuant to the terms of the Enogex Storage Agreement. The arbitration panel rendered a decision in favor of Enogex on February 8, 2002 in the amount of $23.3 million ("Arbitration Award").
9
By letter dated May 9, 2002, COOG advised the holder of the COOG Note that the Arbitration Award was in excess of $10.0 million and, in the event the Arbitration Award became a final, non-appealable order, it would constitute an event of default under the COOG Note. COOG also advised the holder of its note that, due to the significant expenses incurred in defending the Arbitration Award, it was unable to make the payment of principal and interest on the note due May 1, 2002. As a result, Energy Corp. made the May 2002 principal and interest payment of approximately $1.0 million and also was required to purchase the note at a price equal to its unpaid principal and interest of approximately $33.8 million. As the holder of the note, Energy Corp. is a secured creditor, with a first mortgage or comparable security interest on the Storage Facility.
On July 12, 2002, the District Court of Oklahoma County confirmed the Arbitration Award and entered a judgment in the amount of $23.3 million in favor of Enogex and against COOG (the "Judgment"). On August 9, 2002, COOG appealed the Judgment to the Oklahoma Supreme Court. COOG did not, however, post a bond to stay the execution of the Judgment. Therefore, on July 24, 2002, Enogex exercised its option to purchase the Storage Facility, escrowed the transfer documentation and set closing for July 31, 2002. Enogex offset the $4.5 million purchase price against the Judgment. After taking into account this set off, there were no funds remaining to reduce the COOG affiliate's obligation to Energy Corp. under the $8.0 million COOG Affiliate Loan. COOG did not execute the transfer documentation by July 31, 2002. On August 7, 2002, COOG agreed to turn over operations of the Storage Facility to Enogex. Enogex took over operation of the Storage Facility on August 9, 2002 and asserted ownership of the Storage Facility, pursuant to the terms of its original exercise of the purchase option.
In order to try and collect the remaining amounts owed under the Judgment, Enogex served a post-judgment garnishment on the Company, as garnishee, on August 1, 2002, for all sums due to COOG under the Company's storage contract with COOG. This garnishment resulted in a collection by Enogex of approximately $1.0 million from the Company and this amount will be credited as partial satisfaction of the remaining Judgment amount. The Company believes the remaining lease payments under its contract with COOG (now Enogex) is still recoverable through rates.
On September 18, 2002, Enogex filed an application seeking to have the Oklahoma Court resolve certain issues relating to the satisfaction of the Judgment. The Company recently became aware of a legal proceeding that has been filed by COOG and the COOG Affiliate against Energy Corp. and Enogex in Texas. Energy Corp. has asserted that it has not been properly served and that the Texas Court does not have proper jurisdiction over Energy Corp. On September 24, 2002, Enogex filed a response to the allegations. It is Energy Corp.'s position, among other things, that the disputed issues have already been properly determined by the arbitration panel and the Oklahoma Court and, therefore, the Texas action is improper. See Note 6 for a further discussion related to this dispute.
10
6. Subsequent Events
Commitments and Contingencies
Rate Case
As discussed in Note 5, in response to a request from the OCC, the Company filed for a rate increase. 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. The Settlement Agreement provides, among other items: (i) a $25.0 million annual reduction in the electric rates of the Company's Oklahoma customers which begins with the first regular billing cycle occurring 41 days after the issuance of the OCC order approving the Settlement Agreement; (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 of electricity to other utilities and power marketers; (iv) the Company to acquire electric generating capacity ("New Generation") of not less than 400 Megawatts to be integrated into the Company's generation system. The Settlement Agreement remains subject to the review and approval of the three commissioners of the OCC. The OCC will meet in November 2002 to review the Settlement Agreement. See "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations-Regulation and Rates-Recent Regulatory Matters" for further discussion of these developments.
Natural Gas Storage Facility Agreement with Central Oklahoma Oil and Gas Corp.
On October 24, 2002, Enogex, Energy Corp., Natural Gas Storage Corporation and COOG entered into a standstill agreement. As part of this agreement, (i) COOG executed the closing documents relating to the Storage Facility and assigned title to the Storage Facility to Enogex; (ii) Energy Corp. agreed to provide information relating to the storage field; (iii) the parties agreed to stay the pending litigation matters for an initial 45 day period to allow the parties the opportunity to draft and execute an escrow agreement whereby COOG would deposit $5.0 million into escrow by the end of the initial 45 day period; (iv) the parties agreed that if COOG deposited the required $5.0 million pursuant to the executed escrow agreement, the litigation would be stayed for a second 45 day period; during which the parties would determine if a mutually agreeable purchase and sale agreement providing for the repurchase of the facility by COOG could be negotiated and executed; (v) if a purchase agreement is executed during the second 45 day period, the parties agreed that the litigation would be stayed for a third 45 day period from the date of the signing of the purchase agreement and if the purchase agreement fully closed prior to the end of the third 45 day period, the $5.0 million escrowed funds would be applied against the purchase price; (vii) the parties agreed that if the purchase agreement was not executed during the second 45 day period or delete extra space if the closing did not occur prior to the end of the third 45 day period, the funds would become the property of Enogex; and (viii) the parties agreed that upon such closing or turnover of the escrowed funds, the parties would exchange mutual full releases of all liabilities.
11
Item 2. Management's Discussion and Analysis of
Financial Condition
and Results of Operations
Introduction
Oklahoma Gas and Electric Company (the "Company") is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity to retail and wholesale customers in Oklahoma and western Arkansas and is subject to the jurisdiction of the Oklahoma Corporation Commission ("OCC"), the Arkansas Public Service Commission ("APSC") and the Federal Energy Regulatory Commission ("FERC"). The Company sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. 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 owns and operates eight generating stations and is the largest electric utility in Oklahoma. The Company's franchised service territory includes the Fort Smith, Arkansas area, which is the second largest market and an area of high growth in that state. The Company is expected to grow moderately, consistent with historic trends. Expansion will primarily result from continued economic growth in its service territory.
Forward-Looking Statements
Except for the historical statements contained herein, the matters discussed in this Form 10-Q, 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", "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; 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 that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the Company's markets, finalization of the Settlement Agreement; changes in accounting guidelines; creditworthiness of suppliers, customers and other contractual parties and other risk factors listed in the Company's Form 10-K for the year ended December 31, 2001, including Exhibit 99.01 thereto and other factors described from time to time in the Company's reports filed with the Securities and Exchange Commission.
Overview
General
Revenues from sales of electricity are somewhat seasonal, with a large portion of the Company's annual electric revenues occurring during the summer months when the electricity needs of its customers increase. Due to seasonal fluctuations and other factors, the operating
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results for the three and nine months ended September 30, 2002 are not necessarily indicative of the results that may be expected for the year ending December 31, 2002 or for any future period.
Regulatory Considerations
Actions of the regulatory commissions that set the Company's electric rates will continue to affect the Company's financial results. Reference is made to "Regulation and Rates-Recent Regulatory Matters" for a discussion of recent actions relating to the Company's rates.
The Company has been and will continue to be affected by competitive changes to the utility industry. Significant changes already have occurred in the wholesale electric markets at the federal level and significant changes are possible at the retail level in the states served by the Company. In Oklahoma, deregulation of the electric industry has been postponed until at least 2003. See "Regulation and Rates-State Restructuring Initiatives" for further discussion of these developments.
Commitments and Contingencies
See Notes 5 and 6 to the Condensed Financial Statements for a description of certain commitments and contingencies, including the dispute with Central Oklahoma Oil and Gas Corp.
Results of Operations
The following discussion and analysis presents factors which affected the Company's results of operations for the three and nine months ended September 30, 2002 as compared to the three and nine months ended September 30, 2001, and the Company's financial position at September 30, 2002. Known trends and contingencies of a material nature are discussed to the extent considered relevant.
The expenditures, of approximately $92.0 million for restoration of the transmission and distribution infrastructure, resulting from the January 2002 ice storm, have been capitalized as part of the Company's Property, Plant and Equipment or deferred. Accordingly, these expenditures did not impact the operating results for the three and nine months ended September 30, 2002.
Three Months Ended Six Months Ended
September 30, September 30,
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(In millions, except per share data) 2002 2001 2002 2001
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Operating income........................... $ 170.2 $ 172.3 $ 232.8 $ 237.7
Earnings before interest and taxes......... $ 169.6 $ 172.0 $ 231.0 $ 236.1
Average common shares outstanding.......... 40.4 40.4 40.4 40.4
Dividends paid per share................... $ 0.644 $ 0.642 $ 1.928 $ 1.925
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In reviewing its operating results, the Company believes that it is appropriate to focus on operating income and earnings before interest and taxes ("EBIT") as reported on its Condensed Statements of Income. For the three months ended September 30, 2002, operating income was $170.2 million compared to $172.3 million for the same period in 2001 and EBIT was $169.6 million compared to $172.0 for the same period in 2001. For the nine months ended September 30, 2002, operating income was $232.8 million compared to $237.7 million for the same period in 2001 and EBIT was $231.0 million compared to $236.1 million for the same period in 2001.
Three Months Ended Nine Months Ended
September 30, September 30,
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(In millions) 2002 2001 2002 2001
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Operating revenues......................... $ 488.9 $ 508.1 $ 1,103.2 $ 1,194.5
Fuel....................................... 140.4 155.1 338.2 401.5
Purchased power............................ 66.9 70.6 196.0 218.0
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Gross margin on revenues................... 281.6 282.4 569.0 575.0
Other operating expenses................... 111.4 110.1 336.2 337.3
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Operating income........................... 170.2 172.3 232.8 237.7
Other income............................... 0.5 0.3 1.2 3.2
Other expenses............................. (1.1) (0.6) (3.0) (4.8)
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EBIT....................................... $ 169.6 $ 172.0 $ 231.0 $ 236.1
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System sales - MWH(a)...................... 7.5 7.7 19.1 19.2
Off-system sales - MWH..................... 0.1 0.1 0.2 0.3
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Total sales - MWH.......................... 7.6 7.8 19.3 19.5
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(a) Megawatt-hour
Quarter ended September 30, 2002 compared to Quarter ended September 30, 2001
The Company's EBIT for the three months ended September 30, 2002 decreased approximately $2.4 million or 1.4 percent as compared to the same period in 2001. The decrease in EBIT was primarily attributable to lower levels of gas transportation cost recovered, lower recoveries of fuel costs from Arkansas customers and lower kilowatt-hour sales to other utilities and power marketers ("off-system sales") partially offset by milder weather and increased growth in the Company's service territory and lower operation and maintenance expenses.
Gross margin on revenues ("gross margin") for the three months ended September 30, 2002 decreased approximately $0.8 million or 0.3 percent as compared to the same period in 2001. Lower levels of natural gas transportation cost that the Company was allowed to recover from its customers decreased the gross margin by approximately $1.6 million for the three months ended September 30, 2002 as a result of the Acquisition Premium Credit Rider ("APC Rider"), the Gas Transportation Credit Rider ("GTAC Rider") and the termination of the Generation Efficiency Performance Rider ("GEP Rider") in June 2002. Lower recoveries
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of fuel costs from Arkansas customers through that state's automatic fuel adjustment clause decreased the gross margin by approximately $0.8 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. Lower kilowatt-hour sales of off-system sales decreased the gross margin by approximately $0.6 million for the three months ended September 30, 2002 as compared to the same period in 2001. Partially offsetting these decreases was an increase of approximately $2.2 million for the three months ended September 30, 2002 as compared to the same period in 2001, due to milder weather and increased growth in the Company's service territory.
Cost of goods sold for the Company consists of fuel used in electric generation and purchased power. The Company's electric generating capability is fairly evenly divided between coal and natural gas and provides for flexibility to use either fuel to the best economic advantage for the Company and its customers. For the three months ended September 30, 2002, fuel expense decreased approximately $14.7 million or 9.5 percent as compared to the same period in 2001 primarily due to an 11.5 percent decrease in the average cost of fuel per kilowatt-hour. Purchased power costs decreased approximately $3.7 million or 5.2 percent for the three months ended September 30, 2002 as compared to the same period in 2001 due to a 9.7 percent decrease in the cost of purchased energy.
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 with no ultimate benefit or 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 its affiliate Enogex Inc. and subsidiaries ("Enogex"). See "Regulation and Rates-Recent Regulatory Matters."
Other operating expenses increased approximately $1.3 million or 1.2 percent for the three months ended September 30, 2002 as compared to the same period in 2001. Other operating expenses include operating and maintenance expense, depreciation and amortization expense and taxes other than income. The Company's operating and maintenance expense decreased approximately $0.6 million or 0.9 percent for the three months ended September 30, 2002 as compared to the same period in 2001. This decrease was primarily due to a decrease of approximately $1.5 million in employee pension and benefit costs, a decrease of approximately $0.6 million in bad debt expense, a decrease of approximately $0.2 million in professional services expense and a decrease of approximately $2.0 million in miscellaneous corporate expenses. Partially offsetting these decreases were increases of approximately $1.8 million in materials and supplies expense, approximately $1.6 million in contract labor costs and approximately $0.3 million in employee labor costs.
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Depreciation and amortization expense increased approximately $1.7 million or 5.8 percent for the three months ended September 30, 2002 as compared to the same period in 2001 due to a higher level of depreciable plant. Taxes other than income increased approximately $0.2 million or 1.8 percent for the three months ended September 30, 2002 as compared to the same period in 2001 due to higher ad valorem tax accruals.
Other income includes revenue from contract work performed by the Company, non-operating rental income and profit on the retirement of fixed assets. The Company's other income increased approximately $0.2 million or 66.7 percent for the three months ended September 30, 2002 as compared to the same period in 2001. This increase was primarily due to a $0.2 million increase in contract work performed by the Company.
Other expense includes expenses associated with contract work performed by the Company, loss on the retirement of fixed assets, charitable donations and expenditures for certain civic, political and related activities. The Company's other expense increased approximately $0.5 million or 83.3 percent for the three months ended September 30, 2002 as compared to the same period in 2001. This increase was primarily due to a $0.2 million increase in expenses associated with contract work performed by the Company and a $0.2 million increase in losses on the retirement of fixed assets.
Net Interest Expense
Net interest expense includes interest income, interest expense and other interest charges. Net interest expense decreased approximately $0.5 million or 4.7 percent for the three months ended September 30, 2002 as compared to the same period in 2001. This decrease was primarily due to a $0.6 million decrease related to a reduction of interest expense from entering into an interest rate swap agreement in 2001. Also contributing to the decrease was a $0.2 million decrease in interest expense due to Energy Corp. related to lower borrowings during the three months ended September 30, 2002. Partially offsetting these decreases was an increase of $0.3 million in higher service fees for commercial paper.
Nine months ended September 30, 2002 compared to Nine months ended September 30, 2001
The Company's EBIT for the nine months ended September 30, 2002 decreased approximately $5.1 million or 2.2 percent as compared to the same period in 2001. The decrease in EBIT was primarily attributable to lower recoveries of fuel costs from Arkansas customers, lower levels of natural gas transportation costs recovered, loss of revenue resulting from the January 2002 ice storm and lower kilowatt-hour sales of off-system sales partially offset by milder weather and increased growth in the Company's service territory and lower operation and maintenance expenses.
Gross margin for the nine months ended September 30, 2002 decreased approximately $6.0 million or 1.0 percent as compared to the same period in 2001. Lower recoveries of fuel costs from Arkansas customers through that state's automatic fuel adjustment clause decreased the gross margin by approximately $9.5 million. Lower levels of natural gas transportation cost
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that the Company was allowed to recover from its customers decreased the gross margin by approximately $3.6 million for the nine months ended September 30, 2002 as compared to the same period in 2001 as a result of the APC Rider, the GTAC Rider and the termination of the GEP Rider in June 2002. Although total expenditures from the January 2002 ice storm, of approximately $92.0 million, which have been capitalized or deferred, did not impact operating results, the related loss of revenue due to interrupted power to our customers resulted in a decrease in the gross margin of approximately $1.5 million for the nine months ended September 30, 2002. Lower kilowatt-hour sales of off-system sales decreased the gross margin by approximately $1.0 million for the nine months ended September 30, 2002 as compared to the same period in 2001. Partially offsetting these decreases was an increase of approximately $9.6 million for the nine months ended September 30, 2002 as compared to the same period in 2001 due to milder weather and increased growth in the Company's service territory.
Cost of goods sold for the Company decreased approximately $85.3 million or 13.8 percent for the nine months ended September 30, 2002 as compared to the same period in 2001. For the nine months ended September 30, 2002, fuel expense decreased $63.3 million or 15.8 percent as compared to the same period in 2001 primarily due to a 20.6 percent decrease in the average cost of fuel per kilowatt-hour. Purchased power costs decreased approximately $22.0 million or 10.1 percent for the nine months ended September 30, 2002 as compared to the same period in 2001 due to a 8.9 percent decrease in the volume of energy purchased and a 16.0 percent decrease in the cost of purchased energy.
Other operating expenses decreased approximately $1.1 million or 0.3 percent for the nine months ended September 30, 2002 as compared to the same period in 2001. The Company's operating and maintenance expense decreased approximately $3.9 million or 1.8 percent for the nine months ended September 30, 2002 as compared to the same period in 2001. This decrease was primarily due to a decrease of approximately $6.8 million in bad debt expense, a decrease of approximately $1.4 million in professional services expense and a decrease of approximately $5.4 million in miscellaneous corporate expenses. Partially offsetting these decreases were increases of approximately $3.8 million in contract labor costs, approximately $3.4 million in materials and supplies expense, approximately $1.6 million in employee labor costs and approximately $0.9 million in employee pensions and benefit costs.
Depreciation and amortization expense increased approximately $2.1 million or 2.3 percent for the nine months ended September 30, 2002 as compared to the same period in 2001 due to a higher level of depreciable plant. Taxes other than income increased approximately $0.7 million or 2.0 percent for the nine months ended September 30, 2002 as compared to the same period in 2001, due to higher ad valorem tax accruals.
The Company's other income decreased approximately $2.0 million or 62.5 percent for the nine months ended September 30, 2002 as compared to the same period in 2001. This decrease was primarily due to a $1.9 million decrease in contract work performed by the Company.
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The Company's other expense decreased approximately $1.8 million or 37.5 percent for the nine months ended September 30, 2002 as compared to the same period in 2001. This decrease was primarily due to a $1.7 million decrease in expenses associated with contract work performed by the Company
Net Interest Expense and Income Tax Expense
Net interest expense decreased approximately $5.1 million or 14.9 percent for the nine months ended September 30, 2002 as compared to the same period in 2001. This decrease was primarily due to a $2.6 million decrease related to a reduction of interest expense from entering into an interest rate swap agreement in 2001. Also contributing to the decrease was a $2.0 million decrease in interest expense due to Energy Corp. related to lower borrowings during the nine months ended September 30, 2002 and a $1.0 million decrease related to lower variable interest expense due to lower interest rates. Partially offsetting these decreases was an increase of $0.4 million in higher service fees for commercial paper. The remaining $0.1 million increase is comprised of insignificant individual items.
Income tax expense decreased approximately $0.6 million or 0.8 percent for the nine months ended September 30, 2002 as compared to the same period in 2001 primarily as a result of a refund of state income tax related to Oklahoma investment tax credits, which was partially offset by an increase in taxes related to higher estimated permanent differences recorded during the nine months ended September 30, 2002.
Liquidity and Capital Requirements
As discussed previously, in January 2002, a significant ice storm hit the Company's service territory and inflicted major damage to the transmission and distribution infrastructure with total expenditures of approximately $92.0 million. The Company requested the OCC to include in its existing rate case relief from the approximately $92.0 million in damages caused by the ice storm.
On October 11, 2002, the Company, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement of the Company's rate case. The settlement stipulates recovery by the Company, through rate base, of the capital expenditures associated with the January 2002 ice storm and 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 off-system sales. In addition, the settlement stipulates that the Company intends to take steps to purchase electric generating facilities of not less than 400 Megawatts ("MW's") to be integrated into the Company's generation system. See "Regulation and Rates-Recent Regulatory Matters" for a further discussion.
The Company's primary needs for capital are related to replacing or expanding existing facilities. The Company generally meets its cash needs through a combination of internally generated funds, short-term borrowings from Energy Corp. and permanent financings. Capital
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expenditures for the nine months ended September 30, 2002 were $168.3 million and were financed with internally generated funds and short-term borrowings.
The Company will continue to use short-term borrowings from Energy Corp. to meet temporary cash requirements. The Company has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time. The Company has in place a line of credit for $100 million expiring on June 26, 2003. Energy Corp. has in place lines of credit in the aggregate for up to $310 million, with $15 million expiring on April 6, 2003, $195 million expiring on January 9, 2003 and $100 million expiring on January 15, 2004. Energy Corp.'s short-term borrowings will consist of a combination of bank borrowings and commercial paper. Energy Corp.'s ability to access the commercial paper market could be adversely impacted by a commercial paper ratings downgrade. The line of credit contains ratings triggers that require annual fees and borrowing rates to increase if Energy Corp. suffers an adverse ratings impact. The impact of a downgrade 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. The Company had $32.0 million in short-term debt outstanding at September 30, 2002, which is classified as Accounts Payable-Affiliates on the accompanying Condensed Balance Sheets.
Like any business, the Company is subject to numerous contingencies, many of which are beyond its control. For a discussion of significant contingencies that could affect the Company, reference is made to Notes 5 and 6 of the Notes to Condensed Financial Statements and to Part II, Item 1 - "Legal Proceedings" of this Form 10-Q, Part II, Item 1 - "Legal Proceedings" in the Company's Form 10-Q for the quarters ended March 31, 2002 and June 30, 2002; and to Part II, Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Notes 8 and 9 of Notes to the Financial Statements in the Company's Form 10-K for the year ended December 31, 2001.
Critical Accounting Policies and Estimates
The Condensed Financial Statements and Notes to Financial Statements included in this Form 10-Q and in the Company's Form 10-K for the year ended December 31, 2001 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. These assumptions and estimates could have a material effect on the Company's 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 is in the valuation of pension plan assumptions, contingency reserves, unbilled revenue and the allowance for uncollectible accounts receivable.
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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 7 of the Notes to Financial Statements in the Company's Form 10-K for the year ended December 31, 2001.
The assumed return on plan assets is based on management's expectation of the long-term return on plan assets portfolio. The discount rate used to compute the present value of plan liabilities is based generally on rates of high grade corporate bonds with maturities similar to the average period over which benefits will be paid.
From time to time, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to claims made by third parties 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 financial statements.
The Company reads its customers' meters and sends its bills 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. This unbilled revenue is estimated by adding the amount of electric power generated and purchased less off-system sales and estimated line losses, which results in net kilowatt-hours available for sale for the current period. From this number, the amount of billed kilowatt-hours are deducted to arrive at an estimate of unbilled kilowatt-hours for the period. These unbilled kilowatt-hours are then multiplied by an estimate of the average price to be paid by customers to arrive at unbilled revenue. The estimates that management uses in this calculation could vary from the actual price to be paid by customers, but when consistently applied from period to period, this method should not result in any material differences.
The allowance for uncollectible accounts receivable is calculated by multiplying the last six months of revenue by the provision rate. The provision rate is based on a 12 month historical average of actual balances written off. To the extent that historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized.
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.
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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.
Recent Regulatory Matters
In September 2001, the director of the OCC public utility division filed an application with the OCC to review the rates of the Company. In the filing, the OCC Staff requested that the Company submit information for a test year ending September 30, 2001. On December 14, 2001, the Company, citing the need for investment in security and system reliability, filed a notice with the OCC of its intent to seek an increase in the Company's electric rates. On January 28, 2002, the Company filed testimony with the OCC supporting the Company's request for a $22.0 million annual rate increase with $10.3 million related to investments for security and $11.7 million attributable to investments in increased system reliability and increased utility costs. Over the past 16 years, the Company has had several rate reductions that have totaled more than $142.0 million annually.
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. Initially, approximately $10.3 million of the January 28, 2002 rate increase requested by the Company was to invest in increased security. As described below, the Company subsequently withdrew its request for the $10.3 million related to security.
The additional $11.7 million of the original $22.0 million request was for investment in increased system reliability and for increased utility costs. The Company had added new generation capacity to meet growing customer demand and had determined that it needed to increase expenditures for distribution system reliability following a series of record-breaking storms, including a 1995 windstorm in the Oklahoma City area affecting 175,000 customers, 1999 tornadoes affecting about 150,000 customers and disrupting service at a power plant, July 2000 thunderstorms affecting 110,000 customers, a Christmas 2000 ice storm affecting 140,000 customers, Memorial Day 2001 storms leaving 143,000 customers without power and at least two other storms affecting at least 100,000 customers each.
Additionally, the Company had experienced an overall increase in operating expenses. As part of it's filing, the Company sought approval to offer several new rate program choices to customers. One such pilot program involves flat billing. This option would set a customer's bill at a fixed dollar amount and would not change throughout the year regardless of the amount of power consumed. The bill amount would then be adjusted in the following year based on the
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previous year's usage and other factors. Another proposed rate program, a Green Power option, would involve the Company contracting with wind generators to purchase a quantity of wind-generated power, then offering that power to customers. The rate would reflect the higher cost of wind-generated power.
As discussed previously, on January 30, 2002, a significant ice storm hit the Company's service territory and inflicted major damage to the transmission and distribution infrastructure with total expenditures of approximately $92.0 million. On April 8, 2002, the Company announced it would withdraw the $10.3 million increased security portion of its January request. Simultaneously with that announcement, the Company filed a Joint Application with the Staff of the OCC for separate consideration of costs related to increased security requirements. Thereafter, on August 15, 2002, the Company filed a report outlining proposed expenditures and related actions for security enhancement. The Company is working with the OCC Staff under this separate filing to determine the appropriate dollar amount for security upgrades and recovery mechanisms. The OCC Staff has indicated its intent to retain a security expert to review the report filed by the Company.
On July 1, 2002 the Company filed direct testimony in support of recovery for the approximately $92.0 million in damages caused by the January 2002 ice storm. The Company requested a $14.5 million annual increase in revenue requirement. The request included recovery of, and return on, $86.6 million of capital expenditures related to the ice storm and recovery, over three years, of $5.4 million of deferred operating costs. Recovery of costs associated with the January 2002 ice storm is included in the Joint Stipulation and Settlement Agreement discussed below.
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. 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 begins with the first regular billing cycle occurring 41 days after the issuance of the OCC order approving the Settlement Agreement; (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 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 Settlement Agreement remains subject to the review and approval of the three commissioners of the OCC. The OCC will meet in November 2002 to review the Settlement Agreement. Key portions of the Settlement Agreement are described below.
I. Rate Reduction to Oklahoma Customers
The Settlement Agreement stipulates that the Company will file tariffs, designed to reflect an annual reduction of $25.0 million in the Company's Oklahoma jurisdictional operating
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revenue. The $25.0 million annual reduction is to begin with the first regular billing cycle which occurs 41 days after the issuance of the OCC order approving the Settlement Agreement.
II. Recovery of Storm Damages
The Settlement Agreement stipulates that the Company will be allowed to earn a return, through base rates, on the capital expenditures related to the January 2002 ice storm. The Settlement Agreement also stipulates that the Company will be allowed recovery of $5.4 million of deferred operating costs related to the January 2002 ice storm. The recovery of the $5.4 million in operating costs will be recovered over a three year period through the Company's rider for off-system sales. Currently, the Company has a 50/50 sharing mechanism in Oklahoma for any off-system sales. The Settlement Agreement, when it becomes effective, will provide that the first $1.8 million in annual net profits from the Company's off-system sales will go to the Company, the next $3.6 million in annual net profits from off-system sales will go to the Company's Oklahoma customers, and any net profits of off-system sales in excess of these amounts will be credited in each sales year with 80 percent to the Company's Oklahoma customers and the remaining 20 percent to the Company. If any of the $5.4 million is not recovered at the end of the three years the OCC will authorize the recovery of any remaining costs.
III. New Generation
In addition to the $25.0 million annual rate reduction to the Company's Oklahoma customers, the Company intends to take steps to purchase electric generating facilities of not less than 400 MW's to be integrated into the Company's generation system. The Company will have the right to accrue a regulatory asset, for a period not to exceed 12 months subsequent to the acquisition and initial operation of the New Generation, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt associated with the capital investment and ad valorem taxes related to the New Generation. In addition to the accrual of the regulatory asset, the Company must file an application with the OCC for the inclusion of the New Generation into the Company's rate base, as part of a general rate review, no later than 12 months following the acquisition and initial operation of the New Generation. Upon approval by the OCC of the application, all prudently incurred costs accrued through the regulatory asset within the 12 month period will be included in the Company's prospective cost of service. The period for recovery of the regulatory asset will be determined by the OCC. The Company expects this New Generation will provide savings, over a three year period, in excess of $75.0 million to the Company's Oklahoma customers. These savings will be derived from: (i) the avoidance of purchase power contracts otherwise needed; (ii) replacing an above market cogeneration contract when it can be terminated at the end of August 2004; and (iii) fuel savings associated with operating efficiencies of a new plant. These savings, while providing real savings to the Company's Oklahoma customers, should have no effect on the profitability of the Company.
As indicated above, the Company's decision with respect to the purchase of the New Generation will be subject to a review by the OCC as part of a general rate case for the purpose of determining the level of just and reasonable costs associated with the New Generation to be
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included in the Company's rate base. The OCC's review is expected to include, but not be limited to, an analysis and review of the alternatives to purchasing the New Generation, the amount paid for such New Generation and the level of capacity purchases. The Company will provide monthly reports, for a period of 36 months, to the OCC Staff, documenting and providing proof of savings experienced by the Company's customers. In determining the 36 month savings the Company will be required to include in its reports: (1) the avoidance of purchased capacity otherwise required to meet Southwest Power Pool capacity margin requirements; (2) credits to customers accruing by virtue of cogeneration contract terminations; and (3) the fuel savings associated with the operating efficiencies of the Company's generating facilities including the New Generation compared to the fuel efficiencies of the Company's generation facilities in operation during the test year related to the Settlement Agreement. The operating costs associated with the New Generation will be deducted from the sum of the three items discussed above to determine the ultimate amount of savings. In determining the 36 month savings, the Company will not include savings to its customers which occur as the result of scheduled reduction in ongoing cogeneration contract payments. In the event the Company is unable to demonstrate at least $75.0 million in savings to its customers during this 36 month period, the Company will have an obligation to credit its customers any unrealized savings below $75.0 million as determined at the end of the 36 month period, which shall be no later than December 31, 2006.
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.
IV. Rate Design
As part of the Settlement Agreement the Company has agreed to withdraw its request for a Coal Utilization Performance Rider ("CUP Rider") and a Transmission Investment Recovery Rider ("TIR Rider"). The Company agreed not to seek implementation of a CUP Rider or a TIR Rider or other similar riders in the Company's next general rate proceeding or during the 36 month benefit period of the New Generation. However, in the event federal regulation of the interstate transmission grid results in a new rate design which increases costs to the Company's Oklahoma customers, the Company will not be precluded from requesting a TIR Rider. Reference is made to "Rate Activities and Proposals" in the Company's Form 10-K for the year ended December 31, 2001.
V. Gas Transportation Service
The Company's current gas transportation service contract with its affiliate Enogex for the Company's current gas-fired generation facilities has a primary term ending in April 2004.
24
Reference is made to Note 9 of Notes to the Financial Statements in the Company's Form 10-K for the year ended December 31, 2001. As part of the Settlement Agreement, the Company agreed to consider competitive bidding as an option when analyzing the extension or renewal of the Company's gas transportation service contract with Enogex prior to April 2004. The Company further agreed to consider competitive bidding as an option for all natural gas transportation services and gas supply acquisition practices to all new generation facilities built, purchased or placed into service after October 9, 2002. If the Company chooses not to utilize competitive bidding to obtain all natural gas transportation services to its current generation facilities, after April 2004, or to any new generation facilities, the Company must then provide the OCC Staff and the office of the Oklahoma Attorney General all data and information upon which the decision was based.
Other Regulatory Actions
As previously reported, certain aspects of the Company's electric rates recently have been addressed by the OCC. In March 2000, the OCC approved, and the Company implemented, the APC Rider reflecting 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 $10.7 million annually from the amount being recovered by the Company from its Oklahoma customers in current rates. In June 2000, the OCC approved modifications to the Company's GEP Rider. The GEP Rider was established initially in 1997 in connection with the Company's last general rate review and was intended to encourage the Company to lower its fuel costs. The GEP Rider expired in June 2002. In June 2001, the OCC approved a stipulation (the "Stipulation") to the competitive bid process of the Company's gas transportation service. 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 a GTAC Rider. The GTAC Rider is a credit for gas transportation cost recovery and is applicable to and becomes part of each Oklahoma retail rate schedule to which the Company's Fuel Cost Adjustment rider applies. The GTAC Rider became effective with the first billing cycle of July 2001. For a further discussion of the APC Rider, GEP Rider and GTAC Rider reference is made to Note 9 of Notes to the Financial Statements in the Company's Form 10-K for the year ended December 31, 2001.
The Settlement Agreement, when it becomes effective, provides for the termination of the APC Rider and the GTAC Rider.
State Restructuring Initiatives
Oklahoma: As previously reported, Oklahoma enacted in April 1997 the Electric Restructuring Act of 1997 (the "Act"), which was designed to provide for choice by retail customers of their electric supplier by July 1, 2002. 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, the 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. The Company will continue to participate
25
actively in the legislative process and expects to remain a competitive supplier of electricity. The Company cannot predict what, if any, legislation will be adopted at the next legislative session.
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, like the Act, will significantly affect the Company's future operations. The Company's electric service area includes parts of western Arkansas, including Fort Smith, the second-largest metropolitan market in the state. 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. The Restructuring Law also provides that utilities owning or controlling transmission assets must transfer control of such transmission assets to an independent system operator, independent transmission company or regional transmission group, if any such organization has been approved by the FERC. The Company filed preliminary business separation plans with the APSC on August 8, 2000. The APSC has established a timetable to establish rules implementing the Restructuring Law.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Market Risk
Risk Management
The risk management process established by the Company is designed to measure both quantitative and qualitative risks in its business. A corporate risk management committee has been established to review these risks on a regular basis. The Company's current market risk exposure relates primarily to changes in interest rates.
Interest Rate Risk
The Company's exposure to changes in interest rates relates primarily to long-term debt obligations. The Company manages its interest rate exposure by limiting its variable rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. The Company may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB 133" and SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." SFAS No. 133 requires the Company to record all derivatives on the Balance Sheet at fair value. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the accompanying Condensed Statements of Income. Changes in the fair value of effective fair value hedges are recorded in Price Risk Management in the accompanying Condensed Balance Sheets, with a corresponding net change in the hedged asset or liability. Changes in the fair value of effective cash flow hedges are recorded as a component of Accumulated Other Comprehensive Income, which is later reclassified to earnings when the hedged transaction is reflected in income.
During 2001, the Company entered into an interest rate swap agreement, effective March 30, 2001, to convert $110.0 million of 7.30 percent fixed rate 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 of the requirements for a determination that there was no ineffective 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 raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standard.
27
The fair value of long-term debt is estimated based on quoted market prices and management's estimate of current rates available for similar issues. The Company has no long-term debt maturing until 2005. The following table shows the Company's long-term debt maturities and the weighted-average interest rates by maturity date.
==============================================================================
Fair Value
(Dollars in millions) 2005 Thereafter Total at September 30, 2002
- ------------------------------------------------------------------------------
Fixed rate debt
Principal amount... $ 110.0 $ 350.0 $ 460.0 $ 492.0
Weighted-average
interest rate.... 7.13% 6.55% 6.69% ---
Variable rate debt
Principal amount... --- $ 251.7 $ 251.7 $ 251.7
Weighted-average
interest rate.... --- 2.37% 2.37% ---
===============================================================================
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 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.
28
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Reference is made to Part I, Item 1 - Notes 5 and 6 to Condensed Financial Statements in this Form 10-Q; Item 3 of the Company's Form 10-K for the year ended December 31, 2001 and to Part II, Item 1 of the Company's Form 10-Q for the quarters ended March 31, 2002 and June 30, 2002 for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Company 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.
99.02 Copy of Settlement Agreement with the Oklahoma Corporation
Commission Staff, the Oklahoma Attorney General and others
relating to the Company's rate case.
(b) Reports on Form 8-K
The Company filed a Current Report on Form 8-K on August 14, 2002 to report the
certification of the Company's financial statements for the quarterly period
ended June 30, 2002 by the Company's Chief Executive Officer and Chief Financial
Officer pursuant to section 906 of the Sarbanes-Oxley Act of 2002.
29
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)
November 14, 2002
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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
31
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: November 14, 2002
/s/ Steven E. Moore
Steven E. Moore
Chairman of the Board, President and
Chief Executive Officer
32
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
33
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: November 14, 2002
/s/ James R. Hatfield
James R. Hatfield
Senior Vice President and
Chief Financial Officer
34
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 September 30, 2002, 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.
November 14, 2002
/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
35
Exhibit 99.02
BEFORE THE CORPORATION COMMISSION
OF THE STATE OF OKLAHOMA
APPLICATION OF ERNEST G. JOHNSON, ) DIRECTOR OF THE PUBLIC UTILITY ) DIVISION, OKLAHOMA CORPORATION ) COMMISSION TO REVIEW THE RATES, ) CHARGES, SERVICES, AND SERVICE TERMS ) CAUSE NO. PUD 200100455 OF OKLAHOMA GAS AND ELECTRIC ) COMPANY AND ALL AFFILIATED ) COMPANIES AND ANY AFFILIATE OR ) NONAFFILIATE TRANSACTION RELEVANT ) TO SUCH INQUIRY )
JOINT STIPULATION AND SETTLEMENT
AGREEMENT
October 11, 2002
36
BEFORE THE CORPORATION COMMISSION
OF THE STATE OF OKLAHOMA
APPLICATION OF ERNEST G. JOHNSON, ) DIRECTOR OF THE PUBLIC UTILITY ) DIVISION, OKLAHOMA CORPORATION ) COMMISSION TO REVIEW THE RATES, ) CHARGES, SERVICES, AND SERVICE TERMS ) CAUSE NO. PUD 200100455 OF OKLAHOMA GAS AND ELECTRIC ) COMPANY AND ALL AFFILIATED ) COMPANIES AND ANY AFFILIATE OR ) NONAFFILIATE TRANSACTION RELEVANT ) TO SUCH INQUIRY )
JOINT STIPULATION AND SETTLEMENT
AGREEMENT
COME NOW the undersigned parties to the above entitled cause and pursuant to 17 O.S.§282 present the following Joint Stipulation and Settlement Agreement ("Joint Stipulation") for the Commission's review and approval as their compromise and settlement of all issues in this proceeding between the parties to this Joint Stipulation ("Stipulating Parties"). The Stipulating Parties represent to the Commission that this Joint Stipulation represents a fair, just and reasonable settlement of these issues, that the terms and conditions of the Joint Stipulation are in the public interest, and the Stipulating Parties urge the Commission to issue an Order in this Cause adopting and approving this Joint Stipulation.
It is hereby stipulated and agreed by and between the Stipulating Parties as follows:
Terms of the Joint Stipulation and Settlement Agreement
This Joint Stipulation represents a comprehensive total settlement benefit package of not less than $50 million consisting of a rate reduction of $25 million to become effective with the first regular billing cycle which occurs 41 days after the Commission order approving this Joint Stipulation is issued; and phased-in customer savings, as specified below, of at least an additional $25 million on an annualized basis for the 36-month period, beginning with the initial operation of new generation facilities or no later than January 1, 2004, ("the 36-month benefit period"), as specified below.
1. Rate Reduction. The Oklahoma Corporation Commission Staff
(“Staff”) initiated this proceeding on September 7, 2001, to
investigate the reasonableness of Oklahoma Gas and Electric
Company’s (“OG&E” or the “Company”)
current rates, charges, services and terms and conditions of service
to the Company’s Oklahoma retail
37
customers. As a result of that review, the Stipulating Parties
represent and agree that OG&E shall file tariffs designed to
produce Oklahoma jurisdictional operating revenues of $1,271,687,611
based upon the test year billing units reflected in Section M of the
Company’s Application Package filed in this proceeding on January
28, 2002, as adjusted by Staff for weather normalization. The Company
shall recover its Oklahoma jurisdictional operating revenue through
tariffs reflecting the rate design set forth in Paragraph 4 of this
Joint Stipulation, and said tariffs shall reflect an annual reduction
from current base rate tariffs in the amount of $25 million beginning
with the first regular billing cycle which occurs 41 days after the
Commission order approving this Joint Stipulation is issued.
Calculation of the rate reduction incorporated in this Joint
Stipulation is set forth on Exhibit “A” to this Joint
Stipulation and Settlement Agreement.
2. Phased-In Customer Savings. In addition to the immediate rate
reduction set forth in Paragraph 1 of this Joint Stipulation, the
Stipulating Parties understand that OG&E intends to take steps to
purchase electric generating facilities of not less than 400 Megawatts
(“New Generation”) to be integrated into the Company’s
generation system. The Company’s decision with respect to the
purchase of the New Generation shall be subject to a prudency review
by the Commission for the purpose of determining the level of just and
reasonable costs associated with the New Generation to be included in
rate base and the remaining Stipulating Parties make no commitment
with respect to acceptance or rejection of the Company’s decision
to acquire the New Generation. The Commission’s prudency review
shall include, but not be limited to, an analysis and review of the
alternatives to purchasing the New Generation, the amount paid for
such Generation and the level of capacity purchased. The Company
agrees that as a part of this provision of the Joint Stipulation,
OG&E shall inform the parties to this Cause of the status of
implementation of this provision of the Joint Stipulation.
Subsequent to the inclusion of the New Generation in OG&E’s
generation assets, OG&E shall provide monthly reports to the Staff
of the Commission, reflecting the savings experienced by the
Company’s Oklahoma jurisdictional retail customers for a period
of 36 months. The Company shall make available to the Staff and AG all
calculations and work papers supporting such savings. Any request to
review said calculations and work papers by any interested party shall
be subject to compliance with Oklahoma law and the Orders of this
Commission.
During said 36-month period, OG&E shall document and provide proof
of savings to said customers of at least $75 million. In determining
the 36-month savings, the Company shall include: (1) the avoidance of
purchased capacity otherwise required to meet Southwest Power Pool
capacity margin requirements; (2) credits to customers accruing by
virtue of cogeneration contract terminations; and (3) the fuel savings
associated with the operating efficiencies of the Company’s
generating facilities including the New Generation compared to the
fuel efficiencies of OG&E’s generation facilities in
operation during the test year in this proceeding. From the
38
sum of these amounts shall be deducted the operating costs associated
with the New Generation, as reflected in Footnote 4 of the Phased-in
Customer Savings Calculation format reflected in Exhibit
“B”. Exhibit “B” to this Joint Stipulation
reflects the formula for the calculation of said savings and the
assumptions related to the variables in the formula. In the event that
OG&E is unable to demonstrate at least $75 million in savings to
its Oklahoma jurisdictional customers during the 36-month period
subsequent to the acquisition and initial operation of the New
Generation, the Company shall have an obligation to credit to said
customers any unrealized savings as determined at the end of said
period: which shall be no later than December 31, 2006. In
determining the 36-month savings, the Company shall not include
savings to customers which occur as the result of scheduled reductions
in cogeneration contract payments. It is the intention of the parties
that to the extent any credit is due to customers at the end of the
36-month period because demonstrated savings are less than $75
million, customers on the OG&E system during any portion of the
36-month period shall be entitled to receive an allocation of such
credit as determined by the Commission. In the event that the Company
does not acquire the New Generation by December 31, 2003, the Company
shall credit its Oklahoma jurisdictional customers the sum of $25
million per year, beginning January 1, 2004 and continuing through
December 31, 2006. Said $25 million per year shall be pro-rated on a
monthly basis. If OG&E purchases New Generation subsequent to
January 2004, the credit terminates the first month that the New
Generation begins initial operations. The credited amount to customers
will be included in the determination of the $75 million targeted
savings. The Phased-in Customer Savings Calculation will be effective
for the remainder of the 36-month benefit period. The Commission shall
conduct a hearing to determine the level of savings and any necessary
credits.
3. Regulatory Asset and New Rate Proceeding. For a period not to
exceed twelve months subsequent to the acquisition and initial
operation of the generation facilities described in Paragraph 2 of
this Joint Stipulation, OG&E shall have the right to accrue a
Regulatory Asset which shall consist of the non-fuel operation and
maintenance expenses, depreciation, debt cost associated with the
capital investment, and ad valorem taxes related to the New
Generation. In addition to the accrual of said Regulatory Asset, the
Company agrees that it shall file an Application with the Commission
pursuant to OAC 165:70, for the inclusion of New Generation in
OG&E’s rate base, as part of a general rate review, no later
than 12 months following the acquisition and initial operation of New
Generation. After the Commission’s review and order regarding
said Application, all prudently incurred costs accrued through the
Regulatory Asset within the 12 month period shall be included in the
Company’s prospective cost of service. The period for recovery of
said Regulatory Asset shall be determined by the Commission at that
time. The Company’s rates will be re-established to reflect
recovery of the regulatory asset in rates. Recovery in rates of the
regulatory asset will be subject to the policy and procedures of the
Commission in effect at that time.
39
4. Rate Design.
a. The Company shall design rates for its major classes of service
and structure the resulting tariffs, which are attached hereto as
Exhibit “C”, such that the classes shall receive the
rate reduction described in Paragraph 1 of this Joint
Stipulation. The spread of this rate reduction among the affected
classes is reflected in Exhibit “D” to this Joint
Stipulation.
b. As a part of the consideration for this Joint Stipulation,
OG&E has agreed to withdraw its request for a Coal
Utilization Performance (“CUP”) Rider, and the
Stipulating parties further agree not to seek implementation of a
CUP Rider or other similar type riders in OG&E’s next
general rate proceeding or during the 36-month benefit period.
c. In addition, OG&E has agreed to withdraw its request for a
Transmission Investment Recovery (“TIR”) Rider from
this cause, and the Stipulating Parties agree not to seek
implementation of a TIR Rider or other similar type riders in its
next general rate proceeding or during the 36-month benefit
period; provided, however, that in the event federal regulation
of the interstate transmission grid results in a new rate design
that increases costs to OG&E’s Oklahoma jurisdictional
customers, OG&E shall not be precluded from requesting a TIR
Rider.
d. The Stipulating Parties further agree that the Company shall file
a Rider for Cogeneration Credit (“CCR”) attached hereto
as Exhibit “E”, as a part of its rate design tariffs to
implement this Joint Stipulation, and said CCR shall be designed
to return purchased capacity cost reductions and any fixed
O&M cost reductions related to cogeneration contracts to
OG&E’s customer classes on the same basis as those
capacity costs were allocated to the Company’s customer
classes on a historical basis. For the year 2005 and subsequent
years in a general rate case or other proceeding, the Commission
shall establish a new rider or change in base rates to return
purchased capacity cost reductions and any change in O&M
costs related to the cogeneration described herein based on
demand allocators.
e. The Stipulating Parties agree that in addition to the
Company’s recovery of capital investment incurred to restore
electric service from the January 2002 ice storm through base
rates, OG&E shall recover its operation and maintenance
expense incurred during that storm in the amount of $5,431,095
through the Company’s Rider for Off-System Sales of
Electricity. The Company shall design its Rider for Off-System
Sales of Electricity to recover the first $1,810,366 in net
profits from such sales per year for a three-year period; after
the Company recovers this amount, said Rider for Off-System Sales
of Electricity shall provide that the next $3,620,732 in net
profits in each sales year shall be credited to OG&E’s
Oklahoma jurisdictional customers. Any net profits in excess of
these amounts shall be
40
credited in each sales year to OG&E’s Oklahoma
jurisdictional customers with customers receiving 80% thereof,
and the Company shall retain 20% of such net profits. If any
amounts remain un-recovered of this $5.4 million at the end of
the three years, then the Commission will authorize the recovery
of the remaining costs. The Stipulating Parties further agree
that no party to this Joint Stipulation will seek to change or
modify the treatment of off-system sales as established herein in
the next general rate case or during the three-year period. At
the end of the three-year recovery period for operation and
maintenance expenses related to the January 2002 ice storm, all
net profits from off-system sales of electricity shall be
credited 80% to Oklahoma jurisdictional customers, with the
Company retaining 20% of such net profits.
f. The Company proposed to implement a Green Power Wind Rider (GPWR)
as a program within Oklahoma, subject to Commission approval as a
matter of policy. OG&E’s proposal contemplated that for
the program to be successful it could require a subsidy to
encourage development of this renewable resource for energy in
Oklahoma. The Stipulating Parties agree that this proposal should
be applicable to all customers, except the Large Power and Light
class customers that affirmatively elect not to participate; that
the costs shall include up to $400,000 annually in educational
advertising for the program; and that any subsidy or benefit
resulting from implementation of the program shall be recovered
from each of OG&E’s customer classes. However, such
costs shall not be recovered from those Large Power and Light
class customers who have affirmatively elected to not participate
in the GPWR. The Company should be directed to proceed with
competitive bidding for the acquisition of a contract for 50
Megawatts of wind energy, and such contract shall be subject to
the approval of the Commission. The final rate design for the
GPWR and the recovery of any benefit or subsidy shall be subject
to final determination at such time as OG&E submits a
contract for wind energy to the Commission.
g. The Stipulating Parties agree that certain rate design
modifications and proposals submitted by the Company were
uncontested by any party to these proceedings. Attached to this
Joint Stipulation and incorporated herein by reference as Exhibit
“F” are tariffs and riders designed to implement
OG&E’s Guaranteed Flat Bill program, to modify
OG&E’s current Load Curtailment Program, establishing
Qualification Rates, and implementing OG&E’s PACE
program, all of which should be approved by the Commission as a
part of the Commission’s Order to be issued in this
proceeding.
h. The Stipulating Parties further agree that certain modifications
to the Company’s Fuel Cost Adjustment tariff are necessary
to accommodate the changes required by this Joint Stipulation and
a modification of the calculation of energy payments to AES Shady
Point, Inc. to remove gas costs on a per unit basis from the Real
Time Pricing incremental sales. The modification to
OG&E’s Fuel Cost Adjustment tariff is reflected in
Exhibit “G” to this Joint Stipulation.
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5. Gas Transportation Service. The current Gas Transportation
Service Agreement pursuant to which Enogex Inc. provides natural gas
transportation services to OG&E's current gas-fired generation
facilities ("Current Generation Facilities") has a primary term ending
April 30, 2004. The Stipulating Parties agree as follows:
a. OG&E agrees to include competitive bidding as an option when
analyzing the extension or renewal of the Enogex Gas
Transportation Service Agreement prior to April 2004. Failure to
utilize competitive bidding to obtain all natural gas
transportation services and gas supply within its current supply
acquisition practices, for the Current Generation Facilities
after April 1, 2004, shall subject such OG&E contract(s) for
the Current Generation Facilities to the requirements of
paragraph (c.) below.
b. OG&E further agrees to include competitive bidding as an
option for all natural gas transportation services and gas supply
within its current supply acquisition practices, to all new
generation facilities built, purchased or placed into service
after October 9, 2002 (collectively, “New Generation
Facilities”). Failure to utilize competitive bidding to
obtain all natural gas transportation services for the New
Generation Facilities shall subject OG&E’s contract(s)
for such services to the requirements of paragraph (c.) below.
c. OG&E will advise the Staff and the other parties to this
cause upon completion of all analyses of competitive bidding for
the Current and New Generation Facilities. If OG&E chooses
not to utilize competitive bidding to obtain all natural gas
transportation services to the Current Generation Facilities
(after April 1, 2004) and the New Generation Facilities, OG&E
will provide Staff and the Attorney General’s office all
data and information upon which those decisions were based, and
the renewed or new contracts for natural gas transportation
services or supply services shall be subject to a prudency review
by the Commission.
d. If a competitive bid package is issued pursuant to the
competitive bidding option as referenced above, such competitive
bid package shall not include the right of any party to match the
lowest bid submitted by any other bidder, and each generation
facility shall be bid separately for the services required. A
competitive bidder may submit a bid for a combination of
generation facilities in response to such competitive bid
package, only if such bidder shall also submit or include a bid
to serve those same plants individually.
6. Discovery. As between and among the Stipulating Parties, all
pending requests for information or discovery and all motions pending
before the Administrative Law Judge are hereby withdrawn.
7. General Reservations. The Stipulating Parties represent and
agree that, except as specifically otherwise provided herein:
42
a. This Joint Stipulation represents a negotiated settlement for the
purpose of compromising and resolving all issues which were
raised relating to this proceeding;
b. Each of the undersigned counsel of record affirmatively
represents to the Commission that he or she has fully advised
their respective client(s) that the execution of this Joint
Stipulation constitutes a resolution of all issues which were
raised in this proceeding; that no promise, inducement or
agreement not herein expressed has been made to any party to this
Joint Stipulation; that this Joint Stipulation constitutes the
entire agreement between and among the Stipulating Parties; and
each of the undersigned counsel of record affirmatively
represents that he or she has full authority to execute this
Joint Stipulation on behalf of his or her client(s);
c. None of the signatories hereto shall be prejudiced or bound by
the terms of this Joint Stipulation in the event the Commission
does not approve this Joint Stipulation; and
d. None of the signatories thereto shall be deemed to have approved
or acquiesced in any ratemaking principle, capital structure,
rate of return, recovery of costs, valuation method, cost of
service determination, depreciation principle or method cost
allocation method or rate design proposal underlying or allegedly
underlying any of the rate schedules to be filed by OG&E upon
approval by the Commission of this Joint Stipulation, and nothing
contained herein shall constitute an admission by any party that
any allegation or contention in these proceedings, or as to any
of the foregoing matters, is true or valid and shall not in any
respect constitute a determination by the Commission as to the
merits of any allegations or contentions made in this rate
proceeding.
e. The Stipulating Parties agree that the provisions of this Joint
Stipulation are the result of extensive negotiations, and the
terms and conditions of this Joint Stipulation are
interdependent. The Stipulating Parties agree that settling the
issues in this Joint Stipulation is in the public interest and,
for that reason, they have entered into this Joint Stipulation to
resolve among themselves the issues in this Joint Stipulation.
This Joint Stipulation shall not constitute nor be cited as
precedent nor deemed an admission by any Stipulating Party in any
other proceeding except as necessary to enforce its terms before
the Commission or any state court of competent jurisdiction. The
Commission’s decision, if it enters an order consistent with
this Joint Stipulation, will be binding as to the matters decided
regarding the issues described in this Joint Stipulation, but the
decision will not be binding with respect to similar issues that
might arise in other proceedings. A Stipulating Party’s
support of this Joint Stipulation may differ from its position or
testimony in other causes. To the extent there is a difference,
the Stipulating Parties are not waiving their positions in other
causes. Because
43
this is a stipulated agreement, the Stipulating Parties are under
no obligation to take the same position as set out in this Joint
Stipulation in other dockets.
8. Non-Severability. The Stipulating Parties stipulate and agree
that the agreements contained in this Joint Stipulation have resulted
from negotiations among the Stipulating Parties and are interrelated
and interdependent. The Stipulating Parties hereto specifically state
and recognize that this Joint Stipulation represents a balancing of
positions of each of the Stipulating Parties in consideration for the
agreements and commitments made by the other Stipulating Parties in
connection therewith. Therefore, in the event that the Commission does
not approve and adopt the terms of this Joint Stipulation in total and
without modification or condition (provided, however, that the
affected party or parties may consent to such modification or
condition), or in the event that the rate schedules proposed herein do
not become effective for bills rendered in accordance with the
provisions contained herein, this Joint Stipulation shall be void and
of no force and effect, and no Stipulating Party shall be bound by the
agreements or provisions contained herein. The Stipulating Parties
agree that neither this Joint Stipulation nor any of the provisions
hereof shall become effective unless and until the Commission shall
have entered an Order approving all of the terms and provisions as
agreed by the parties to this Joint Stipulation.
WHEREFORE, the Stipulating Parties hereby submit this Joint Stipulation and Settlement Agreement to the Commission as their negotiated settlement of this proceeding with respect to all issues which were raised with respect to the Application filed herein by the Director of the Public Utility Division of the Commission, and respectfully request the Commission to issue an Order approving this Joint Stipulation and Settlement Agreement.
44
OKLAHOMA GAS AND ELECTRIC COMPANY
Dated: By:
-------------------- --------------------------------------------------------
Robert D. Stewart, Jr.
William J. Bullard
Rod L. Cook
Rainey, Ross, Rice and Binns
PUBLIC UTILITY DIVISION
OKLAHOMA CORPORATION COMMISSION
Dated: By:
-------------------- --------------------------------------------------------
Maribeth D. Snapp, Deputy General Counsel
Miles Halcomb, Assistant General Counsel
Kelli Leaf, Assistant General Counsel
W. A. DREW EDMONDSON
ATTORNEY GENERAL OF THE
STATE OF OKLAHOMA
Dated: By:
-------------------- --------------------------------------------------------
Cece Coleman, Assistant Attorney General
William L. Humes, Assistant Attorney General
OKLAHOMA INDUSTRIAL ENERGY CONSUMERS
Dated: By:
-------------------- --------------------------------------------------------
J. Fred Gist
Hall, Estill, Hardwick, Gable, Golden & Nelson
James D. Satrom
Thomas P. Schroedter
Hall, Estill, Hardwick, Gable, Golden & Nelson
45
ENERGETIX, L.L.C.
Dated: By:
-------------------- --------------------------------------------------------
Deborah R. Morgan
Energetix, L.L.C.
Cheryl A.Vaught
Vaught & Conner
ONEOK POWER MARKETING COMPANY
Dated: By:
-------------------- --------------------------------------------------------
Donald W. England
ONEOK Power Marketing Company
AES SHADY POINT, INC.
Dated: By:
-------------------- --------------------------------------------------------
Kendall W. Parrish
Ron Comingdeer & Associates
OKLAHOMA RENEWABLE ENERGY
FOUNDATION
Dated: By:
-------------------- --------------------------------------------------------
Cheryl A. Vaught
Scott A. Conner
Vaught & Conner
46
OG&E SHAREHOLDERS ASSOCIATION
Dated: By:
-------------------- --------------------------------------------------------
Ronald E. Stakem
Clark, Stakem, Wood & Patten, P.C.
ONEOK GAS TRANSPORTATION, L.L.C.
Dated: By:
-------------------- --------------------------------------------------------
Rob F. Robertson
John M. Benson
Gable & Gotwals
C. Burnett Dunn
Gable & Gotwals
47