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 June 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 July 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 JUNE 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
11
Item 3. Quantitative and Qualitative Disclosures About Market Risk
24
Part II - OTHER INFORMATION
Item 1. Legal Proceedings
26
Item 4. Submission of Matters To A Vote of Security Holders
27
Item 6. Exhibits and Reports on Form 8-K
27
i
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2002 2001
------------- --------------
(In thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents..................................... $ 274 $ 380
Accounts receivable - customers, less reserve of $4,361 and
$6,174, respectively........................................ 93,801 98,342
Accrued unbilled revenues..................................... 64,200 35,600
Accounts receivable - other................................... 12,792 12,073
Fuel inventories, at LIFO cost................................ 62,821 54,882
Materials and supplies, at average cost....................... 39,727 32,640
Prepayments and other......................................... 3,454 35,480
Accumulated deferred tax assets............................... 6,757 7,493
- ---------------------------------------------------------------- ------------- --------------
Total current assets........................................ 283,826 276,890
- ---------------------------------------------------------------- ------------- --------------
OTHER PROPERTY AND INVESTMENTS, at cost......................... 48,170 15,500
- ---------------------------------------------------------------- ------------- --------------
PROPERTY, PLANT AND EQUIPMENT
In service.................................................... 4,060,487 3,961,652
Construction work in progress................................. 39,307 22,497
- ---------------------------------------------------------------- ------------- --------------
Total property, plant and equipment......................... 4,099,794 3,984,149
Less accumulated depreciation............................. 2,000,986 1,978,872
- ---------------------------------------------------------------- ------------- --------------
Net property, plant and equipment........................... 2,098,808 2,005,277
- ---------------------------------------------------------------- ------------- --------------
DEFERRED CHARGES AND OTHER ASSETS
Advance payments for gas...................................... 32,500 8,500
Income taxes recoverable through future rates................. 37,096 37,615
Intangible asset - unamortized prior service cost............. 42,435 42,435
Prepaid benefit obligation.................................... 787 11,850
Price risk management......................................... 1,032 ---
Other......................................................... 35,032 36,278
- ---------------------------------------------------------------- ------------- --------------
Total deferred charges and other assets..................... 148,882 136,678
- ---------------------------------------------------------------- ------------- --------------
TOTAL ASSETS.................................................... $ 2,579,686 $ 2,434,345
================================================================ ============= ==============
The accompanying Notes to Financial Statements are an integral part hereof.
1
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEETS (Continued)
(Unaudited)
June 30, December 31,
2002 2001
------------- --------------
(In thousands)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - affiliates................................. $ 157,253 $ 25,867
Accounts payable - other...................................... 72,152 63,577
Customers' deposits........................................... 30,386 28,423
Accrued taxes................................................. 19,450 20,255
Accrued interest.............................................. 13,932 14,437
Accrued vacation.............................................. 12,240 11,796
Provision for payments of take or pay gas..................... 425 30,800
Fuel clause over recoveries................................... 8,843 23,358
Capital lease obligation...................................... 3,296 ---
Other......................................................... 7,981 6,338
- ---------------------------------------------------------------- ------------- --------------
Total current liabilities................................... 325,958 224,851
- ---------------------------------------------------------------- ------------- --------------
LONG-TERM DEBT.................................................. 703,928 700,379
- ---------------------------------------------------------------- ------------- --------------
DEFERRED CREDITS AND OTHER LIABILITIES
Capital lease obligation - non-current........................ 30,500 ---
Accrued pension and benefit obligation........................ 81,044 80,850
Accumulated deferred income taxes............................. 452,997 438,972
Accumulated deferred investment tax credits................... 49,704 52,279
Price risk management......................................... --- 2,412
Other......................................................... 32,500 9,000
- ---------------------------------------------------------------- ------------- --------------
Total deferred credits and other liabilities................ 646,745 583,513
- ---------------------------------------------------------------- ------------- --------------
STOCKHOLDERS' EQUITY
Common stockholders' equity................................... 512,446 512,446
Retained earnings............................................. 410,547 433,094
Accumulated other comprehensive income (loss), net of tax..... (19,938) (19,938)
- ---------------------------------------------------------------- ------------- --------------
Total stockholders' equity.................................. 903,055 925,602
- ---------------------------------------------------------------- ------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,579,686 $ 2,434,345
================================================================ ============= ==============
The accompanying Notes to Financial Statements are an integral part hereof.
2
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30 June 30
------------------------------- -----------------------------
2002 2001 2002 2001
-------------- -------------- ------------- -------------
(In thousands, except per share data)
OPERATING REVENUES......................... $ 352,238 $ 359,481 $ 614,321 $ 686,316
COST OF GOODS SOLD......................... 178,032 189,871 326,868 393,802
- ------------------------------------------- -------------- ------------- ------------- -------------
Gross margin on revenues................... 174,206 169,610 287,453 292,514
Other operation and maintenance.......... 75,468 71,777 140,188 143,498
Depreciation and amortization............ 30,293 30,227 61,073 60,523
Taxes other than income.................. 11,604 11,456 23,520 23,141
- ------------------------------------------- -------------- ------------- ------------- -------------
OPERATING INCOME........................... 56,841 56,150 62,672 65,352
- ------------------------------------------- -------------- ------------- ------------- -------------
OTHER EXPENSES, NET........................ (832) (500) (1,240) (1,291)
- ------------------------------------------- -------------- ------------- ------------- -------------
EARNINGS BEFORE INTEREST AND TAXES......... 56,009 55,650 61,432 64,061
INTEREST INCOME (EXPENSES)
Interest income.......................... 367 736 826 1,075
Interest on long-term debt............... (9,572) (10,839) (19,098) (22,075)
Allowance for borrowed funds used
during construction.................... 327 234 705 417
Other interest charges................... (762) (1,643) (1,476) (3,001)
- ------------------------------------------- -------------- ------------- ------------- -------------
Net interest expenses.................. (9,640) (11,512) (19,043) (23,584)
- ------------------------------------------- -------------- ------------- ------------- -------------
INCOME BEFORE TAXES........................ 46,369 44,138 42,389 40,477
INCOME TAX EXPENSE......................... 15,530 16,113 13,068 13,449
- ------------------------------------------- -------------- ------------- ------------- -------------
NET INCOME................................. $ 30,839 $ 28,025 $ 29,321 $ 27,028
=========================================== ============== ============= ============= =============
BASIC AND DILUTED AVERAGE COMMON SHARES
OUTSTANDING.............................. 40,379 40,379 40,379 40,379
BASIC AND DILUTED EARNINGS PER AVERAGE
COMMON SHARE............................. $ 0.76 $ 0.69 $ 0.73 $ 0.67
=========================================== ============== ============= ============= =============
DIVIDENDS PAID PER SHARE................... $ 0.642 $ 0.641 $ 1.284 $ 1.282
=========================================== ============== ============= ============= =============
The accompanying Notes to Financial Statements are an integral part hereof.
3
OKLAHOMA GAS AND ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30
---------------------------------
2002 2001
-------------- --------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income......................................................... $ 29,321 $ 27,028
Adjustments to reconcile net income to net cash provided
from operating activities
Depreciation and amortization.................................... 61,073 60,523
Deferred income taxes and investment tax credits, net............ (6,786) (12,714)
Change in certain assets and liabilities
Accounts receivable - customers................................ 4,541 (6,310)
Accrued unbilled revenues...................................... (28,600) (12,500)
Fuel, materials and supplies inventories....................... (15,026) (30,260)
Accumulated deferred tax assets................................ 736 (255)
Other current assets........................................... 31,307 34,862
Accounts payable............................................... 39,446 (27,483)
Accrued taxes.................................................. (805) (869)
Accrued interest............................................... (505) (9)
Other current liabilities...................................... (40,840) 2,937
Other operating activities....................................... 16,775 2,798
- --------------------------------------------------------------------- -------------- --------------
Net Cash Provided from Operating Activities.................. 90,637 37,748
- --------------------------------------------------------------------- -------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures............................................... (139,391) (68,594)
- --------------------------------------------------------------------- -------------- --------------
Net Cash Used in Investing Activities........................ (139,391) (68,594)
- --------------------------------------------------------------------- -------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES
Net proceeds from issuance of short-term debt...................... 100,515 82,624
Cash dividends declared on common stock............................ (51,867) (51,818)
- --------------------------------------------------------------------- -------------- --------------
Net Cash Provided from Financing Activities.................. 48,648 30,806
- --------------------------------------------------------------------- -------------- --------------
NET DECREASE IN CASH AND CASH EQUIVALENTS............................ (106) (40)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 380 422
- --------------------------------------------------------------------- -------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 274 $ 382
===================================================================== ============== ==============
- ---------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR
Interest (net of amount capitalized $705 and $417)............... $ 16,436 $ 19,617
Income taxes..................................................... $ 600 $ 700
- ---------------------------------------------------------------------------------------------------------
NON-CASH INVESTING AND FINANCING ACTIVITIES
Interest rate swap............................................... $ (3,444) $ 5,405
Change in fair value of long-term debt........................... $ 3,444 $ (5,405)
Assumption of asset and related debt............................. $ 34,747 $ ---
- ---------------------------------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part hereof.
4
OKLAHOMA GAS AND ELECTRIC COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
1. Summary of Significant Accounting Policies
Organization
Oklahoma Gas and Electric Company (the "Company") 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 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 present fairly the financial position of the Company at June 30, 2002 and December 31, 2001, the results of operations for the three and six months ended June 30, 2002 and 2001 and the results of cash flows for the six months ended June 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 six months ended June 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. At June 30, 2002, the Company had 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 through customer rates over a three-year period. See Note 4 for a further discussion. At June 30, 2002, regulatory assets and regulatory liabilities 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.
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.
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"
6
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 Statements of Income. Changes in the fair value of effective fair value hedges are recorded in Price Risk Management in the accompanying 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 occurs.
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 for periods beginning after June 15, 2002. The Company will adopt this new standard effective January 1, 2003. Management has not yet determined what the impact of this new standard will be 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 fair value of the asset. Adoption of SFAS No. 144 is required for financial statements for periods 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 or disposal activities and supersedes Emerging Issues Task Force ("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 or disposal activities initiated after December 31, 2002. The Company will adopt this new standard effective January 1, 2003. Management has not yet determined what the impact of this new standard will be on its financial position or results of operations.
7
3. Comprehensive Income
Accumulated other comprehensive income (loss) at June 30, 2002 and December 31, 2001 included a $19.9 million loss, net of tax, related to a minimum pension liability adjustment. There were no other comprehensive income items for the six months ended June 30, 2002 and 2001.
4. Commitments and Contingencies
In September 2001, the director of the OCC public utility division filed an application with the OCC to review the rates of the Company. The Company's rates had last been formally reviewed in 1996. In the filing, the OCC requested that the Company submit information in accordance with OCC minimum standard filing requirements by January 28, 2002 for a test year ending September 30, 2001. On January 28, 2002, the Company filed its response requesting a $22 million annual rate increase. It has been 16 years since the Company requested a rate increase. Approximately $10.3 million of the requested rate increase relates to enhanced security as a result of the September 11, 2001 terrorist attacks and approximately $11.7 million relates 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 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 million, approximately $86.6 million was related to capital expenditures and $5.4 million was related to 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 pending efforts to seek recovery from federal disaster aid or through rates. The OCC's consideration of recovery of these storm costs has been incorporated into the Company's pending rate review proceeding. 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.
On August 5, 2002, the OCC Staff and all other intervening parties filed responsive testimony regarding the Company's proposal to recover the $5.4 million of deferred operating costs. The OCC Staff's witness and the witness for the Oklahoma Industrial Energy Consumers ("OIEC") did not support the Company's proposal to amortize the deferred operating costs over three years. The witness for the Attorney General's office did accept the Company's proposed three-year recovery of the deferred operating costs. The witness for the OIEC proposed that to the extent the Company is successful in obtaining federal disaster recovery funds, they should be applied first to these deferred costs. Arguments on the recovery of these deferred costs and the remaining issues of this proceeding are scheduled to be heard before an administrative law judge in late September 2002. While the ultimate recovery is subject to the approval of the OCC, management continues to believe that it is probable that these deferred costs will be recovered in rates if not recovered through federal aid. A final order in the Company's rate case is not
8
expected until late in 2002. 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.
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"). Operation of the Storage Facility proved beneficial by allowing the Company to lower fuel costs by base loading coal generation, a less costly fuel supply. During 1996, the Company completed negotiations and contracted with COOG for gas storage service. Pursuant to the contract, COOG reimbursed the Company for all outstanding cash advances and interest amounting to approximately $46.8 million. The Company also entered into a bridge financing agreement as guarantor for COOG. In 1997, COOG obtained permanent financing and issued a note, originally in the amount of $49.5 million. The proceeds from the permanent financing were applied to repay the outstanding bridge financing. In connection with the permanent financing, Energy Corp. entered into a note purchase agreement, where it agreed, upon the occurrence of a monetary default by COOG on its permanent financing, to purchase COOG's 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") also agreed to lease underground gas storage from COOG, with the capacity being developed by COOG. This lease 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 lease, Energy Corp. agreed to make up to a $12 million secured loan to an affiliate of COOG (the "COOG Affiliate Loan"). As of June 30, 2002, the amount outstanding under the COOG Affiliate Loan is approximately $8 million. The COOG Affiliate Loan is repayable in 2003 and 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 borrower is unable to pay the COOG Affiliate Loan, Energy Corp. would be required to write off the portion of such loan that has not been repaid. Disputes arose under the lease agreement between Enogex and COOG. The parties arbitrated these disputes pursuant to the terms of the lease agreement. The arbitration panel rendered a decision on February 8, 2002 ("Arbitration Award"). Pursuant to the Arbitration Award, COOG filed with the arbitration panel a Motion to Reconsider the panel's ruling, which was denied by a majority of the panel. Pursuant to proceedings instituted by Enogex with the District Court of Oklahoma County, the Arbitration Award was confirmed and a judgment in the amount of $23.3 million in favor of Enogex and against COOG (the "Judgment") was entered on July 12, 2002.
By letter dated May 9, 2002, COOG advised the holder of its note that the Arbitration Award was in excess of $10 million and, in the event the Arbitration Award became a final, non-appealable order, it would constitute an event of default under the loan agreement relating to the 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
9
payment of approximately $950,000 and also could be 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. would be a secured creditor, with a first mortgage or comparable security interest on all of COOG's assets. The Company and Enogex have separate rights to purchase the Storage Facility at prices set by their contracts, which, in the case of Enogex, include the right to offset against such purchase price, among other things, the outstanding amount of the COOG Affiliate Loan.
5. Subsequent Events
Commitments and Contingencies
As discussed in Note 4, Enogex was awarded a Judgment against COOG in the amount of $23.3 million on July 12, 2002. On August 9, 2002, COOG appealed this Judgment to the Oklahoma Supreme Court. COOG did not, however, post a bond to stay the execution of the Judgment. Therefore, Enogex exercised its asset option to purchase the Storage Facility under the Option Agreement on July 24, 2002, escrowed the transfer documentation and set closing for July 31, 2002. Enogex offset the $4.5 million purchase price against the Judgment. After exercising the set off against COOG’s obligation to Enogex under the Judgment, there were no funds to reduce the obligation of the affiliate of COOG under the $8 million COOG Affiliate Loan from Energy Corp. 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 is asserting ownership of the Storage Facility, pursuant to the terms of its original exercise of the asset option.
Under the terms of the note purchase agreement described in Note 4, Energy Corp. was required to purchase COOG's note, for approximately $33.8 million in June 2002. Energy Corp. is also pursuing the repayment of the COOG Affiliate Loan. While Energy Corp. fully believes it will collect all amounts receivable under the COOG Affiliate Loan in the event the borrower is unable to pay the COOG Affiliate Loan, Energy Corp. would be required to write off the portion of such loan that has not been repaid.
In further execution on 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 contract with COOG. This garnishment resulted in a collection by Enogex of approximately $983,000 and this amount will be credited as partial satisfaction of the remaining Judgment amount. The Company believes the remaining lease payments under their contract with COOG and now Enogex is still recoverable through rates.
The Company has recently become aware of a legal proceeding that has been filed by COOG and the COOG Affiliate against Energy Corp. and Enogex in Texas. The Company has not been served with the action and therefore, has not yet filed a response to the allegations. The Company asserts that the disputed issues have been properly determined by the Arbitration Panel and that this action is improper.
10
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 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, some 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, including rate recovery for January 2002 storm damages; changes in accounting guidelines; credit worthiness 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
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 results for the three and six months ended June 30, 2002 (the "current periods") are not necessarily indicative of the results that may be expected for the year ending December 31, 2002 or for any future period.
11
Actions of the regulatory commissions that set the Company's electric rates will continue to affect financial results. Reference is made to Note 4 to the condensed financial statements for a discussion of recent actions.
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. Reference is made to Note 4 to the condensed financial statements for a description of the agreement and to Note 5 to the condensed financial statements for a discussion of recent actions related to such agreement.
Results of Operations
The following discussion and analysis presents factors, which affected the Company's results of operations for the current periods as compared to the three and six months ended June 30, 2001, and the financial position as of June 30, 2002. Known trends and contingencies of a material nature are discussed to the extent considered relevant.
The expenditures, of approximately $92 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 pending recovery through regulation or other alternatives. Accordingly, these expenditures did not impact the current periods operating results.
Three Months Ended Six Months Ended
June 30 June 30
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(In thousands, except per share data) 2002 2001 2002 2001
==========================================================================================================
Operating income........................... $ 56,841 $ 56,150 $ 62,672 $ 65,352
Earnings before interest and taxes......... $ 56,009 $ 55,650 $ 61,432 $ 64,061
Average common shares outstanding.......... 40,379 40,379 40,379 40,379
Dividends paid per share................... $ 0.642 $ 0.641 $ 1.284 $ 1.282
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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 Statements of Income. For the three months ended June 30, 2002, operating income was $56.8 million compared to $56.2 million for the same period in 2001 and EBIT was $56.0 million compared to $55.7 for the same period in 2001. For the six months ended June 30, 2002, operating income was $62.7 million compared to $65.4 million for the same period in 2001 and EBIT was $61.4 million compared to $64.1 million for the same period in 2001. The only difference between operating income and EBIT is the inclusion of certain minor non-operating activities in EBIT.
Three Months Ended Six Months Ended
June 30 June 30
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(In thousands) 2002 2001 2002 2001
==========================================================================================================
Operating revenues......................... $ 352,238 $ 359,481 $ 614,321 $ 686,316
Fuel....................................... 112,810 119,435 197,803 246,397
Purchased power............................ 65,222 70,436 129,065 147,405
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Gross margin on revenues................... 174,206 169,610 287,453 292,514
Other operating expenses................... 117,365 113,460 224,781 227,162
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Operating income........................... 56,841 56,150 62,672 65,352
Other expenses, net........................ (832) (500) (1,240) (1,291)
- ----------------------------------------------------------------------------------------------------------
EBIT....................................... $ 56,009 $ 55,650 $ 61,432 $ 64,061
==========================================================================================================
System sales - MWH(a)...................... 5,953 5,952 11,532 11,556
Off-system sales - MWH..................... 42 94 177 161
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Total sales - MWH.......................... 5,995 6,046 11,709 11,717
==========================================================================================================
(a) Megawatt-hour
Quarter ended June 30, 2002 compared to Quarter ended June 30, 2001
The Company's EBIT for the three months ended June 30, 2002 increased approximately $0.3 million or 0.6 percent as compared to the same period in 2001. The increase in EBIT was primarily the result of growth in the Company's service territory, offset by timing differences in the recovery of lower fuel cost expenses from Arkansas customers, milder weather and higher operation and maintenance expenses.
Gross margin on revenues ("gross margin") for the three months ended June 30, 2002 increased approximately $4.6 million or 2.7 percent as compared to the same period in 2001. The gross margin increased by approximately $12.3 million for the three months ended June 30, 2002 as compared to the same period in 2001, due to growth in the Company's service territory. Partially offsetting this increase was a reduction of approximately $4.3 million for the three months ended June 30, 2002 as compared to the same period in 2001, due to lower recoveries of fuel costs from Arkansas customers through that state's automatic fuel adjustment clause. In Arkansas, recovery of fuel costs is subject to a bandwidth mechanism. If fuel costs are
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within the bandwidth range, recoveries are not adjusted on a monthly basis; rather they are reset annually on April 1. Cooling degree days were 14.7 percent lower for the three months ended June 30, 2002 as compared to the same period in 2001, resulting in approximately a $2.4 million reduction to the gross margin. Lower levels of natural gas transportation cost that the Company was allowed to recover from its customers decreased the gross margin by approximately $0.5 million for the three months ended June 30, 2002 as compared to the same period in 2001, as a result of the Acquisition Premium Credit Rider ("APC Rider") and the Gas Transportation Credit Rider ("GTAC Rider"). Lower recoveries under the Generation Efficiency Performance Rider ("GEP Rider") decreased the gross margin by approximately $0.4 million for the three months ended June 30, 2002 as compared to the same period in 2001. Lower kilowatt-hour sales to other utilities and power marketers decreased the gross margin by approximately $0.1 million for the three months ended June 30, 2002 as compared to the same period in 2001.
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 June 30, 2002, fuel expense decreased approximately $6.6 million or 5.5 percent as compared to the same period in 2001, primarily due to a 14.1 percent decrease in the average cost of fuel per kilowatt-hour (particularly the cost of natural gas). Purchased power costs decreased approximately $5.2 million or 7.4 percent for the three months ended June 30, 2002 as compared to the same period in 2001, due to a 17.1 percent decrease in the volume of energy purchased and a 10.0 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 include operating and maintenance expense, depreciation and amortization expense, and taxes other than income. The Company's operating and maintenance expense increased approximately $3.7 million or 5.1 percent for the three months ended June 30, 2002 as compared to the same period in 2001. This increase was primarily due to an increase of approximately $6.5 million in contract labor costs. Partially offsetting this increase were decreases of approximately $1.9 million in bad debt expense and approximately $0.9 million in miscellaneous corporate expenses.
Depreciation and amortization expense increased approximately $0.1 million or 0.2 percent for the three months ended June 30, 2002 as compared to the same period in 2001, due to
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a higher level of depreciable plant. Taxes other than income increased approximately $0.1 million or 1.3 percent for the three months ended June 30, 2002 as compared to the same period in 2001, due to higher ad valorem tax accruals.
Net interest expense includes interest income, interest expense and other interest charges. Net interest expense decreased approximately $1.9 million or 16.3 percent for the three months ended June 30, 2002 as compared to the same period in 2001. This decrease was primarily due to a $1.0 million decrease in interest expense due to Energy Corp. related to lower borrowings during the three months ended June 30, 2002. Also contributing to the decrease was a $0.8 million decrease related to a reduction of interest expense from entering into an interest rate swap agreement in 2001. The remaining $0.1 million decrease is comprised of individually insignificant items.
Income tax expense decreased approximately $0.6 million or 3.6 percent for the three months ended June 30, 2002 as compared to the same period in 2001 primarily as a result of a refund of Oklahoma State income tax related to Oklahoma investment tax credits. This decrease was partially offset by higher pre-tax income for the three months ended June 30, 2002 as compared to the same period in 2001.
Six months ended June 30, 2002 compared to Six months ended June 30, 2001
The Company's EBIT for the six months ended June 30, 2002 decreased approximately $2.6 million or 4.1 percent as compared to the same period in 2001. The decrease in EBIT was primarily the result of timing differences in the recovery of lower fuel cost expenses from Arkansas customers, milder weather and the loss of revenue resulting from the January 2002 ice storm. Partially offsetting this decrease was growth in the Company's service territory and lower operation and maintenance expenses.
Gross margin for the six months ended June 30, 2002 decreased approximately $5.1 million or 1.7 percent as compared to the same period in 2001. Approximately $11.4 million of the decrease for the six months ended June 30, 2002 as compared to the same period in 2001, was due to lower recoveries of fuel costs from Arkansas customers through that state's automatic fuel adjustment clause. Cooling degree days were 11.2 percent lower for the six months ended June 30, 2002 as compared to the same period in 2001, resulting in approximately a $3.2 million reduction to the gross margin. Although total expenditures from the January 2002 ice storm, of approximately $92 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 six months ended June 30, 2002. Lower levels of natural gas transportation cost that the Company was allowed to recover from its customers decreased the gross margin by approximately $1.1 million for the six months ended June 30, 2002 as compared to the same period in 2001, as a result of the APC Rider and the GTAC Rider. Lower recoveries under the GEP Rider decreased the gross margin by approximately $0.8 million for the six months ended June 30, 2002 as compared to the same period in 2001. Lower off-system sales decreased the gross margin by approximately $0.4 million for the six months ended June 30, 2002 as compared to the same period in 2001.
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Partially offsetting these decreases was an increase of approximately $13.3 million for the six months ended June 30, 2002 as compared to the same period in 2001, due to growth in the Company's service territory.
Cost of goods sold for the Company decreased approximately $66.9 million or 17.0 percent for the six months ended June 30, 2002 as compared to the same period in 2001, primarily due to a 26.2 percent decrease in the average cost of fuel per kilowatt-hour (particularly the cost of natural gas). Purchased power costs decreased approximately $18.3 million or 12.4 percent for the six months ended June 30, 2002 as compared to the same period in 2001, due to a 15.0 percent decrease in the volume of energy purchased and a 19.6 percent decrease in the cost of purchased energy.
The Company's operating and maintenance expenses decreased approximately $3.3 million or 2.3 percent for the six months ended June 30, 2002 as compared to the same period in 2001. This decrease was primarily due to a decrease of approximately $6.1 million in bad debt expense, a decrease of approximately $1.2 million in professional services expense, a decrease of approximately $1.0 million in employee pension and benefit costs and a decrease of approximately $8.9 million in miscellaneous corporate expenses. Partially offsetting these decreases were increases of approximately $12.3 million in contract labor costs and approximately $1.6 million in materials and supplies expense.
Depreciation and amortization expense increased approximately $0.1 million or 0.9 percent for the six months ended June 30, 2002 as compared to the same period in 2001, due to a higher level of depreciable plant. Taxes other than income increased approximately $0.3 million or 1.6 percent for the six months ended June 30, 2002 as compared to the same period in 2001, due to higher ad valorem tax accruals.
Net interest expense decreased approximately $4.5 million or 19.3 percent for the six months ended June 30, 2002 as compared to the same period in 2001. This decrease was primarily due to a $2.1 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 $1.8 million decrease in interest expense due to Energy Corp. related to lower borrowings during the six months ended June 30, 2002 and a $1.0 million decrease related to lower variable interest expense due to lower interest rates. The remaining $0.4 million increase is comprised on individually insignificant items.
Income tax expense decreased approximately $0.4 million or 2.8 percent for the six months ended June 30, 2002 as compared to the same period in 2001 primarily as a result of a refund of Oklahoma State income tax related to Oklahoma investment tax credits. This decrease was partially offset by higher pre-tax income for the six months ended June 30, 2002 as compared to the same period in 2001.
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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 million. The Company has requested the OCC to include in its existing rate case relief from the approximately $92 million in damages caused by the ice storm. The Company has requested a $14.5 million annual increase in revenue requirement. The request includes 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. The area of damage is within counties that were declared a federal disaster area. Therefore, the Company is also seeking recovery of a portion of the storm damages from the Federal government with the assistance of the OCC and the Oklahoma Congressional delegation. The expenditures for restoration of the transmission and distribution infrastructure have been capitalized as part of the Company's Property, Plant and Equipment or deferred pending recovery through regulation or other alternatives.
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 financing. Capital expenditures for the six months ended June 30, 2002 were $139.3 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 $100.5 million in short-term debt outstanding at June 30, 2002, which is classified as Accounts payable-affiliates on the accompanying 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 Part II, Item 1 - "Legal Proceedings" of this Form 10-Q, to Part II, Item 1 - "Legal Proceedings" in the Company's Form 10-Q for the quarter ended March 31, 2002 and to "Management's Discussion and Analysis" 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.
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Critical Accounting Policies and Estimates
The 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 contains 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, unbilled revenue, allowance for uncollectible accounts receivable and contingency reserves.
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 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.
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
18
representative of future collections, there could be an effect on the amount of uncollectible expense recognized.
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 generally accepted accounting principles, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company's Financial Statements.
Regulation and Rates
The Company's retail electric tariffs in Oklahoma are regulated by the OCC, and in Arkansas by the APSC. The issuance of certain securities by the Company is also regulated by the OCC and the APSC. The Company's wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of the Company's facilities and operations.
The order of the OCC authorizing the Company to reorganize into a subsidiary of Energy Corp. contains certain provisions which, among other things, ensure the OCC access to the books and records of Energy Corp. and its affiliates relating to transactions with the Company; require the Company to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company's customers; and prohibit the Company from pledging its assets or income for affiliate transactions.
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 in accordance with OCC minimum standard filing requirements by January 28, 2002 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 million annual rate increase. If granted, the increase would be the first for the Company since 1985. Over the past 16 years, the Company has had several rate reductions that have totaled more than $142 million annually.
Attempting to make security investments at the proper level, the Company has developed a set of guidelines aimed at minimizing 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
19
increased security. As described below, the Company subsequently withdrew its request for the $10.3 million related to security. The additional $11.7 million is for investment in increased system reliability and for increased utility costs. The Company has added new generation capacity to meet growing customer demand and has determined a need to increase expenditures for distribution system reliability that has been brought about, in no small part, by 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 has 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 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 energy, then offering that power to customers. The rate would reflect the higher cost of wind-generated power. Also included in the filing was the Company's offer to not seek a rate increase for three years.
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 million. On April 8, 2002, the Company announced it would request the OCC to withdraw the $10.3 million increased security portion of the Company's January request for a $22 million annual rate increase. The Company is working with the OCC Staff under a joint filing to determine the appropriate dollar amount for security upgrades and recovery mechanisms.
On June 11, 2002 the OCC Staff and other intervening parties filed responsive testimony. In their testimony, the OCC Staff proposed adjustments that amounted to a $17.4 million annual rate reduction, Oneok Gas Transmission recommended a $29.4 million annual rate reduction, the Oklahoma Industrial Energy Consumers ("OIEC"), an industry trade group, recommended a $103.8 million annual rate reduction and the Office of the Oklahoma Attorney General ("Attorney General") recommended a $105.8 million annual rate reduction.
On July 1, 2002 the Company filed direct testimony in support of recovery for the approximately $92 million in damages caused by the January 2002 ice storm. The Company has requested a $14.5 million annual increase in revenue requirement. The request includes 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.
On July 15, 2002 the Company and all other parties to the case filed rebuttal testimony. In their testimony the Company cited many erroneous adjustments in the OIEC's and Attorney
20
General's recommendation. After removing what the Company believes are erroneous adjustments, the OIEC's recommendation would be reduced to a $29.3 million annual rate reduction and the Attorney General's recommendation would be reduced to a $33.4 million annual rate reduction. The Company's rebuttal testimony also challenged most of the remaining proposals of the Attorney General and the OIEC. Surrebuttal testimony will be filed on August 15, 2002.
On August 5, 2002 the OCC Staff and all other intervening parties filed responsive testimony regarding return on equity, capital structure, rate design and the cost of the January 2002 ice storm. Each party updated their recommendations that were filed on June 11, 2002. The OCC Staff recommended a $39.1 million rate reduction and proposed an incentive mechanism based on the Company's success at generating electricity with its coal plants. The Attorney General's consultants revised its June 11, 2002 recommendation of a $105.8 million rate reduction to $96.3 million. The OIEC increased its originally proposed $103.8 million rate reduction by recommending a lesser return on equity and lower equity portion of the capital structure. The OIEC's recommendations included only a small portion of the 2002 ice storm damage cost. The OIEC's filed testimony did not calculate a final rate reduction recommendation. The Company has estimated the rate reduction proposed by the OIEC to be approximately $120 million. A final order in the Company's rate case is not expected until late in 2002.
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 is 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 by: (i) allowing the Company to collect one-third of the amount by which its fuel costs were below a specified percentage (96.261 percent) of the average fuel costs of certain other investor-owned utilities in the region; and (ii) disallowing the collection of one-third of the amount by which its fuel costs exceeded a specified percentage (103.739 percent) of the average fuel costs of other investor-owned utilities. The modifications enacted in June 2000 had the effect of reducing the amount the Company could recover under the GEP Rider by: (i) changing the Company's peer group to include utilities with a higher coal-to-gas generation mix; (ii) reducing the amount of fuel costs that can be recovered if the Company's costs exceed the new peer group by changing the percentage above which the Company will not be allowed to recover one-third of the fuel costs from Oklahoma customers from 103.739 percent to 101.0 percent; (iii) reducing the Company's share of cost savings as compared to its new peer group from 33 percent to 30 percent; and (iv) limiting to $10.0 million the amount of any awards paid to the Company or penalties charged to the Company. For the period between July 1, 2001 and June 30, 2002, the Company recovered $5.1
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million under the GEP Rider. The GEP Rider expired in June 2002, however, the OCC could approve a similar reward mechanism requested by the Company in its rate case.
The final action addresses the competitive bid process of the Company's gas transportation needs following which the Company's affiliate, Enogex, contracted to provide gas transportation service to all of the Company's generation plants. In the 1997 Order, the OCC approved a stipulation wherein the Company agreed to initiate a competitive bidding process for gas transportation service to its gas-fired plants, with the competitive services commencing no later than April 30, 2000. The order also set annual compensation for the transportation services provided by Enogex to the Company at $41.3 million annually until March 1, 2000, at which time the rate would drop to $28.5 million (reflecting removal of the APC Rider, upon the completion of the recovery from customers of the amortization premium paid by the Company when it acquired Enogex in 1986) and remain at that level until competitively-bid gas transportation began. In July 1999, the Company filed an application with the OCC requesting approval of a performance-based rate plan for its Oklahoma retail customers from April 2000 until the introduction of customer choice for electric power scheduled for July 2002. As part of this application, the Company stated that Enogex had submitted the only viable bid ($33.4 million per year) for gas transportation to the Company's six gas-fired power plants that were the subject of the competitive bid. As part of its application to the OCC, the Company offered to discount Enogex's bid from $33.4 million annually to $25.2 million annually. The Company executed a gas transportation contract with Enogex under which Enogex continues to serve the needs of the Company's power plants at a price to be paid by the Company of $33.4 million annually and, if the Company's proposal had been approved by the OCC, the Company would have recovered a portion of such amount ($25.2 million) from its customers. The Company negotiated with the OCC Staff, the Office of the Oklahoma Attorney General and a coalition of industrial customers in an effort to settle all issues (including the competitive bid process) associated with its application for a performance-based rate plan. When these negotiations failed, the Company withdrew its application, which withdrawal was approved by the OCC in December 1999.
In July 2000, the Company entered into a stipulation (the "Stipulation") with the OCC Staff, the Office of the Attorney General and a coalition of industrial customers regarding the competitive bid process of the Company's gas transportation service. In June 2001, the OCC approved the Stipulation declaring the Stipulation to be fair, just and reasonable and representing a reasonable settlement of the issues and thereby serving the public interest. The Company had previously collected $28.5 million on an annual basis through its base rate and APC Rider for gas transportation services from Enogex for the power plant requirements covered by the competitive bid. The Stipulation permits the Company to recover $25.2 million annually for the gas transportation services provided by Enogex pursuant to the competitive bid process. The Stipulation directs 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, and will remain in effect until amended by the Company at the direction of the OCC.
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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 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 businesses. A senior 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 Statements of Operations. Changes in the fair value of effective fair value hedges are recorded in Price Risk Management in the accompanying 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 occurs.
During 2001, the Company entered into an interest rate swap agreement, effective March 30, 2001, to convert $110 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 requirements for a determination that there was no ineffective portion as allowed under 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.
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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 June 30, 2002
- --------------------------------------------------------------------------
Fixed rate debt
Principal amount... $ 110.0 $ 350.0 $ 460.0 $ 471.6
Weighted-average
interest rate.... 7.125% 6.55% 6.69% ---
Variable rate debt
Principal amount... --- $ 246.4 $ 246.4 $ 246.4
Weighted-average
interest rate.... --- 2.47% 2.47% ---
===========================================================================
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Reference is made to 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 quarter ended March 31, 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, except as set forth below:
Reference is made to Note 8 of the Company's Financial Statements included in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2001 and Part II, Item 1 of the Company's Form 10-Q for the quarter ended March 31, 2002 for a discussion of the agreements between Central Oklahoma Oil and Gas Corp. ("COOG") and the Company and between COOG and Enogex.
On July 12, 2002, the District Court of Oklahoma County (the "Court") held its hearing on the Motion to Settle and Application to Dissolve Seal. At the hearing, the Court (1) entered its Order Dissolving Seal as to all filed documents except the Storage Lease Agreement; (2) entered an Order Confirming Arbitration Award and directing judgment be entered; and (3) entered its judgment awarding Enogex a judgment against COOG in the amount of $23.3 million. As set forth in Notes 4 and 5, to the condensed financial statements, Enogex has initiated actions to execute on this judgment. The Company has recently become aware of a legal proceeding that has been filed by COOG and the COOG Affiliate against Energy Corp. and Enogex in Texas. The Company has not been served with the action and therefore, has not yet filed a response to the allegations. The Company asserts that the disputed issues have been properly determined by the Arbitration Panel and that this action is improper.
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Item 4. Submission Of Matters To A Vote of Security Holders
(a) The Company's Annual Meeting of Shareowners was held on May 16, 2002.
(b) Not applicable.
(c) The matters voted upon and the results of the voting at the Annual Meeting were
as follows:
(1) The Shareowners voted to elect the Company's nominees for election
to the Board of Directors as follows:
Herbert H. Champlin - 40,378,745 votes for election and
no votes withheld
Martha W. Griffin - 40,378,745 votes for election and
no votes withheld
Ronald H. White, M.D. - 40,378,745 votes for election and
no votes withheld
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
None
(b) Reports on Form 8-K
The Company filed a Current Report on Form 8-K on May 21, 2002 to report
the replacement of the Company's independent public accountants.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
OKLAHOMA GAS AND ELECTRIC COMPANY
(Registrant)
By /s/ Donald R. Rowlett
Donald R. Rowlett
Vice President and Controller
(On behalf of the registrant and in
his capacity as Chief Accounting Officer)
August 14, 2002
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