UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT
TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003
OR
[ ] TRANSITION REPORT
PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission File Number: 1-12579
OGE ENERGY CORP.
(Exact name of registrant as specified in its charter)
Oklahoma
73-1481638
(State or other jurisdiction
of
(I.R.S. Employer
incorporation or organization)
Identification No.)
321 North Harvey
P.O. Box 321
Oklahoma City, Oklahoma 73101-0321
(Address of principal executive offices)
(Zip Code)
405-553-3000
(Registrant's telephone number, including area
code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No
Indicate by check mark whether the registratrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes X No
As of April 30, 2003, 79,218,054 shares of common stock, par value $0.01 per share, were outstanding.
OGE ENERGY CORP.
FORM 10-Q
FOR THE QUARTER ENDED MARCH 31, 2003
TABLE OF CONTENTS
Part I - FINANCIAL INFORMATION Page
Item 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets................................. 1
Condensed Consolidated Statements of Operations....................... 3
Condensed Consolidated Statements of Cash Flows....................... 4
Notes to Condensed Consolidated Financial Statements.................. 5
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................... 29
Item 3. Quantitative and Qualitative Disclosures About Market Risk.............. 55
Item 4. Controls and Procedures................................................. 56
Part II - OTHER INFORMATION
Item 1. Legal Proceedings....................................................... 57 Item 6. Exhibits and Reports on Form 8-K........................................ 57 Signature....................................................................... 58 Certifications.................................................................. 59
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, December 31,
2003 2002
------------ ------------
(In millions)
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 20.8 $ 44.4
Accounts receivable, net.................................. 376.8 304.6
Accrued unbilled revenues................................. 32.5 28.2
Fuel inventories.......................................... 67.7 99.7
Materials and supplies, at average cost................... 39.6 42.6
Price risk management..................................... 45.3 17.1
Pipeline imbalance........................................ 6.0 34.3
Accumulated deferred tax assets........................... 10.2 10.9
Fuel clause under recoveries.............................. 48.8 14.7
Other..................................................... 7.1 10.6
Current assets of discontinued operations................. 0.2 4.7
- ------------------------------------------------------------ --------- ---------
Total current assets.................................... 655.0 611.8
- ------------------------------------------------------------ --------- ---------
OTHER PROPERTY AND INVESTMENTS, at cost..................... 28.2 27.2
- ------------------------------------------------------------ --------- ---------
PROPERTY, PLANT AND EQUIPMENT
In service................................................ 5,540.8 5,500.2
Construction work in progress............................. 37.7 44.8
- ------------------------------------------------------------ --------- ---------
Total property, plant and equipment..................... 5,578.5 5,545.0
Less accumulated depreciation......................... 2,265.1 2,231.4
- ------------------------------------------------------------ --------- ---------
Net property, plant and equipment....................... 3,313.4 3,313.6
In service of discontinued operations..................... --- 54.2
Less accumulated depreciation......................... --- 11.4
- ------------------------------------------------------------ --------- ---------
Net property, plant and equipment of discontinued
operations............................................ --- 42.8
- ------------------------------------------------------------ --------- ---------
Net property, plant and equipment....................... 3,313.4 3,356.4
- ------------------------------------------------------------ --------- ---------
DEFERRED CHARGES AND OTHER ASSETS
Recoverable take or pay gas charges....................... 32.5 32.5
Income taxes recoverable from customers, net.............. 33.6 34.8
Intangible asset - unamortized prior service cost......... 42.7 42.7
Prepaid benefit obligation................................ 37.1 44.9
Price risk management..................................... 19.4 20.1
Other..................................................... 78.1 80.8
Deferred charges and other assets of discontinued
operations.............................................. --- 0.2
- ------------------------------------------------------------ --------- ---------
Total deferred charges and other assets................. 243.4 256.0
- ------------------------------------------------------------ --------- ---------
TOTAL ASSETS................................................ $4,240.0 $4,251.4
============================================================ ========= =========
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
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OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
(Unaudited)
March 31, December 31,
2003 2002
------------ ------------
(In millions)
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt............................................ $ 173.0 $ 275.0
Accounts payable .......................................... 387.6 269.0
Dividends payable.......................................... 26.2 26.1
Customers' deposits........................................ 34.0 33.0
Accrued taxes.............................................. 13.7 23.6
Accrued interest........................................... 28.2 35.7
Tax collections payable.................................... 6.8 6.7
Accrued vacation........................................... 17.4 16.9
Long-term debt due within one year......................... 33.0 21.0
Price risk management...................................... 35.9 13.9
Pipeline imbalance......................................... 4.7 9.4
Other...................................................... 22.2 19.4
Current liabilities of discontinued operations............. 0.2 2.0
- ------------------------------------------------------------- --------- ---------
Total current liabilities................................ 782.9 751.7
- ------------------------------------------------------------- --------- ---------
LONG-TERM DEBT............................................... 1,490.1 1,501.9
- ------------------------------------------------------------- --------- ---------
DEFERRED CREDITS AND OTHER LIABILITIES
Accrued pension and benefit obligations.................... 188.3 184.2
Accumulated deferred income taxes.......................... 620.4 627.0
Accumulated deferred investment tax credits................ 45.8 47.1
Accrued removal obligations, net........................... 111.0 109.3
Price risk management...................................... 1.7 0.6
Provision for payments of take or pay gas.................. 32.5 32.5
Other...................................................... 5.5 4.1
Deferred credits and other liabilities of discontinued
operations............................................... --- 9.1
- ------------------------------------------------------------- --------- ---------
Total deferred credits and other liabilities............. 1,005.2 1,013.9
- ------------------------------------------------------------- --------- ---------
STOCKHOLDERS' EQUITY
Common stockholders' equity................................ 457.7 453.5
Retained earnings.......................................... 578.2 604.7
Accumulated other comprehensive loss, net of tax........... (74.1) (74.3)
- ------------------------------------------------------------- --------- ---------
Total stockholders' equity............................... 961.8 983.9
- ------------------------------------------------------------- --------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY................... $4,240.0 $4,251.4
============================================================= ========= =========
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
2
OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
March 31,
--------------------------------
2003 2002
-------------- --------------
(In millions, except per share data)
OPERATING REVENUES.........................................
Electric Utility operating revenues...................... $ 332.6 $ 262.1
Natural Gas Pipeline operating revenues.................. 717.6 313.7
- ----------------------------------------------------------- ----------- -----------
Total operating revenues............................... 1,050.2 575.8
COST OF GOODS SOLD
Electric Utility cost of goods sold...................... 203.9 139.7
Natural Gas Pipeline cost of goods sold.................. 664.5 274.0
- ----------------------------------------------------------- ----------- -----------
Total cost of goods sold............................... 868.4 413.7
- ----------------------------------------------------------- ----------- -----------
Gross margin on revenues................................. 181.8 162.1
Other operation and maintenance.......................... 90.3 85.1
Depreciation............................................. 46.6 45.2
Taxes other than income.................................. 17.2 16.7
- ----------------------------------------------------------- ----------- -----------
OPERATING INCOME........................................... 27.7 15.1
- ----------------------------------------------------------- ----------- -----------
OTHER INCOME (EXPENSE)
Other income............................................. 6.1 0.8
Other expense............................................ (2.9) (1.3)
- ----------------------------------------------------------- ----------- -----------
Net other income (expense)............................. 3.2 (0.5)
- ----------------------------------------------------------- ----------- -----------
INTEREST INCOME (EXPENSE)
Interest income.......................................... 0.2 0.5
Interest on long-term debt............................... (19.0) (22.0)
Interest on trust preferred securities................... (4.3) (4.3)
Allowance for borrowed funds used during construction.... 0.2 0.4
Interest on short-term debt and other interest charges... (1.8) (2.6)
- ----------------------------------------------------------- ----------- -----------
Net interest expense................................... (24.7) (28.0)
- ----------------------------------------------------------- ----------- -----------
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE TAXES...... 6.2 (13.4)
INCOME TAX EXPENSE (BENEFIT)............................... 1.9 (5.1)
- ----------------------------------------------------------- ----------- -----------
INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE...................................... 4.3 (8.3)
DISCONTINUED OPERATIONS
Income from discontinued operations...................... 2.2 1.7
Income tax expense (benefit)............................. 0.9 (0.4)
- ----------------------------------------------------------- ----------- -----------
Income from discontinued operations...................... 1.3 2.1
- ----------------------------------------------------------- ----------- -----------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE................................... 5.6 (6.2)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR
ENERGY TRADING CONTRACTS, NET OF TAX OF $3.7.............. (5.9) ---
- ----------------------------------------------------------- ----------- -----------
NET LOSS................................................... $ (0.3) $ (6.2)
=========================================================== =========== ===========
BASIC AVERAGE COMMON SHARES OUTSTANDING.................... 78.7 78.0
DILUTED AVERAGE COMMON SHARES OUTSTANDING.................. 78.9 78.0
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (loss) from continuing operations................. $ 0.05 $ (0.11)
Income from discontinued operations, net of tax.......... 0.02 0.03
Loss from cumulative effect of accounting change,
net of tax.............................................. (0.07) ---
- ----------------------------------------------------------- ----------- -----------
NET LOSS................................................... $ --- $ (0.08)
=========================================================== =========== ===========
DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (loss) from continuing operations................. $ 0.05 $ (0.11)
Income from discontinued operations, net of tax.......... 0.02 0.03
Loss from cumulative effect of accounting change,
net of tax.............................................. (0.07) ---
- ----------------------------------------------------------- ----------- -----------
NET LOSS................................................... $ --- $ (0.08)
=========================================================== =========== ===========
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
3
OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
---------------------------------
2003 2002
-------------- --------------
(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss........................................................... $ (0.3) $ (6.2)
Adjustments to reconcile net loss to net cash provided from
operating activities
Income from discontinued operations.............................. (1.3) (2.1)
Cumulative effect of change in accounting principle.............. 5.9 ---
Depreciation..................................................... 46.6 45.2
Deferred income taxes and investment tax credits, net............ (0.5) 22.7
Gain on sale of assets........................................... (5.7) (0.5)
Ineffectiveness of interest rate swap............................ --- 0.2
Price risk management assets..................................... (27.2) 13.8
Price risk management liabilities................................ 23.0 0.7
Other assets..................................................... 8.2 (0.9)
Other liabilities................................................ 0.3 1.7
Change in certain current assets and liabilities
Accounts receivable, net....................................... (72.2) (29.2)
Accrued unbilled revenues...................................... (4.3) 4.8
Fuel, materials and supplies inventories....................... 25.5 (3.7)
Pipeline imbalance asset....................................... 28.3 (4.5)
Fuel clause under recoveries................................... (34.1) ---
Other current assets........................................... 3.5 3.8
Accounts payable............................................... 118.5 45.4
Customers' deposits............................................ 1.0 1.2
Accrued taxes.................................................. (6.3) (15.9)
Accrued interest............................................... (7.5) (10.0)
Fuel clause over recoveries.................................... --- 5.4
Pipeline imbalance liability................................... (4.6) 3.2
Other current liabilities...................................... 1.2 4.0
- --------------------------------------------------------------------- -------------- --------------
Net Cash Provided from Operating Activities.................. 98.0 79.1
- --------------------------------------------------------------------- -------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures............................................... (44.9) (84.9)
Proceeds from sale of assets....................................... 9.9 0.5
Other investing activities......................................... (0.4) (0.3)
- --------------------------------------------------------------------- -------------- --------------
Net Cash Used in Investing Activities........................ (35.4) (84.7)
- --------------------------------------------------------------------- -------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES
Decrease in short-term debt, net................................... (102.0) (18.0)
Premium on issuance of common stock................................ 4.2 0.1
Distribution to minority interest.................................. (2.5) ---
Dividends paid on common stock..................................... (23.9) (25.9)
- --------------------------------------------------------------------- -------------- --------------
Net Cash Used in Financing Activities........................ (124.2) (43.8)
- --------------------------------------------------------------------- -------------- --------------
DISCONTINUED OPERATIONS
Net cash (used in) provided from operating activities.............. (0.5) 20.3
Net cash provided from (used in) investing activities.............. 38.5 (2.8)
- --------------------------------------------------------------------- -------------- --------------
Net Cash Provided from Discontinued Operations............... 38.0 17.5
- --------------------------------------------------------------------- -------------- --------------
NET DECREASE IN CASH AND CASH EQUIVALENTS............................ (23.6) (31.9)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 44.4 37.5
- --------------------------------------------------------------------- -------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 20.8 $ 5.6
===================================================================== ============== ==============
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.
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OGE ENERGY CORP.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Summary of Significant Accounting Policies
Organization
OGE Energy Corp. (collectively with its subsidiaries, the “Company”) 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 conducts these activities through two business segments, the Electric Utility and the Natural Gas Pipeline segments. All significant intercompany transactions have been eliminated in consolidation.
The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.
The Natural Gas Pipeline segment is conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consists of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas and (iii) the marketing and trading of natural gas. The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership, Enogex also owns a controlling interest in and operates the Ozark Gas Transmission System (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex’s marketing and trading activities include corporate price risk management and other optimization services. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas, were sold in 2002 and in the first quarter of 2003 and are reported in the condensed consolidated financial statements as discontinued operations.
The Company allocates operating costs to its affiliates based on several factors. Operating costs directly related to specific affiliates are assigned to those affiliates. Where more than one affiliate benefits from certain expenditures, the costs are shared between those affiliates receiving the benefits. Operating costs incurred for the benefit of all affiliates are allocated among the affiliates, based primarily upon head-count, occupancy, usage or the “Distragas” method. The Distragas method is a three-factor formula that uses an equal weighting of payroll, operating income and assets. The Company believes this method provides a reasonable basis for allocating common expenses.
5
Basis of Presentation
The condensed consolidated 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 consolidated financial position of the Company at March 31, 2003 and December 31, 2002, and the results of its operations and cash flows for the three months ended March 31, 2003 and 2002, have been included and are of a normal recurring nature.
Due to seasonal fluctuations and other factors, the operating results for the three months ended March 31, 2003 are not necessarily indicative of the results that may be expected for the year ending December 31, 2003 or for any future period. The accompanying condensed consolidated financial statements and notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2002.
Accounting Records
The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, 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 the expected recovery from customers in future rates. Likewise, certain credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. At March 31, 2003 and December 31, 2002, regulatory assets of approximately $60.4 million and approximately $63.9 million, respectively, are being amortized and reflected in rates charged to customers over periods of up to 20 years. At March 31, 2003 and December 31, 2002, regulatory liabilities of approximately $111.0 million and approximately $109.3 million, respectively, have been reclassified from Accumulated Depreciation in accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations.”
OG&E initially records costs: (i) that are probable of future recovery as a deferred charge until such time as the cost is approved by a regulatory authority, then the cost is reclassified as a regulatory asset; and (ii) that are probable of future liability as a deferred credit until such time as
6
the amount is approved by a regulatory authority, then the amount is reclassified as a regulatory liability.
The following table is a summary of the Company's regulatory assets and liabilities at:
March 31, December 31,
(In millions) 2003 2002
====================================================================================
Regulatory Assets
Income taxes recoverable from customers, net......... $ 33.6 $ 34.8
Unamortized loss on reacquired debt.................. 23.0 23.3
January 2002 ice storm............................... 3.6 5.4
Miscellaneous........................................ 0.2 0.4
- ------------------------------------------------------- --------- ------------
Total Regulatory Assets............................ $ 60.4 $ 63.9
======================================================= ========= ============
Regulatory Liabilities
Accrued removal obligations, net..................... $ 111.0 $ 109.3
- ------------------------------------------------------- --------- ------------
Total Regulatory Liabilities....................... $ 111.0 $ 109.3
====================================================================================
Income taxes recoverable from customers represent income tax benefits previously used to reduce OG&E’s revenues. These amounts are being recovered in rates as the temporary differences that generated the income tax benefit turn around. The provisions of SFAS No. 71 allowed the Company to treat these amounts as regulatory assets and liabilities and they are being amortized over the estimated remaining life of the assets to which they relate. The regulatory assets and liabilities are netted on the Company’s Condensed Consolidated Balance Sheets in the line item, “Income Taxes Recoverable from Customers, Net.”
Accrued removal obligations represent asset retirement costs previously recovered from ratepayers for other than legal obligations. In accordance with SFAS No. 143, the Company was required to reclassify the accrued removal obligations, which had previously been recorded as a liability in Accumulated Depreciation, to a regulatory liability. See Note 2 for a further discussion.
Management continuously monitors the future recoverability of regulatory assets. When in management’s judgment future recovery becomes impaired, the amount of the regulatory asset is reduced or written off, as appropriate.
If the Company were required to discontinue the application of SFAS No. 71 for some or all of its operations, it could result in writing off the related regulatory assets and liabilities; the financial effects of which could be significant.
Use of Estimates
In preparing the condensed consolidated 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 consolidated financial
7
statements and the reported amounts of revenues and expenses during the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s condensed consolidated financial statements. In management’s opinion, the areas of the Company where the most significant judgment is exercised are in the valuation of pension plan assumptions, impairment estimates, contingency reserves, unbilled revenue for OG&E, the allowance for uncollectible accounts receivable, the valuation of energy purchase and sale contracts and gas storage inventory.
Allowance for Uncollectible Accounts Receivable
For OG&E, all customer balances are written off if not collected within six months after the account is finalized. The allowance for uncollectible accounts receivable for OG&E is calculated by multiplying the last six months of electric revenue by the provision rate. The provision rate is based on a 12-month historical average of actual balances written off. To the extent the historical collection rates are not representative of future collections, there could be an effect on the amount of uncollectible expense recognized. For Enogex, customer balances are written off when the Company concludes the required payment of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable for Enogex is established on a case-by-case basis when the Company believes the required payment of specific amounts owed is unlikely to occur. The allowance for uncollectible accounts receivable was approximately $11.7 million and $13.6 million at March 31, 2003 and December 31, 2002, respectively.
Impairment of Assets
The Company assesses potential impairments of assets when there is evidence that events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. An impairment loss is recognized when the sum of the expected future net cash flows is less than the carrying amount of the asset. The amount of any recognized impairment is based on the estimated fair value of the asset subject to impairment compared to the carrying amount of such asset.
Income Taxes
The Company files consolidated income tax returns. Income taxes are allocated to each affiliate 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 follows the provisions of SFAS No. 109, “Accounting for Income Taxes,” which uses an asset and liability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted marginal tax rate. Deferred income tax expenses or benefits are based on the changes in the asset or liability from period to period.
8
Cash and Cash Equivalents
For purposes of the condensed consolidated financial statements, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. These investments are carried at cost, which approximates fair value.
Revenue Recognition
OG&E
OG&E reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of each month. An amount is accrued as a receivable for this unbilled revenue based on estimates of usage and prices during the period. The estimates that management uses in this calculation could vary from the actual amounts to be paid by customers.
Enogex
The Company recognizes revenue from natural gas gathering and processing and transportation and storage services to third parties as services are provided. Revenue associated with natural gas liquids is recognized when the production is processed and sold. Substantially all of OGE Energy Resources, Inc.‘s (“OERI”) natural gas and power marketing contracts qualify as derivatives and, therefore, are accounted for at fair value as prescribed in SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under fair value accounting, fixed-price forwards, swaps, options, futures and other financial instruments with third parties are recorded at estimated fair market values, net of reserves, with the corresponding market changes in fair value recognized in earnings and offsetting amounts recorded as Price Risk Management assets and liabilities in the accompanying Condensed Consolidated Balance Sheets. See Note 2 for a further discussion.
Automatic Fuel Adjustment Clauses
Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to the fuel component in the cost-of-service for ratemaking, are passed through to OG&E’s customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC.
Fuel Inventories
OG&E
Fuel inventories for the generation of electricity consist of coal, natural gas and oil. These inventories are accounted for under the last-in, first-out (“LIFO”) cost method. The estimated replacement cost of fuel inventories was higher than the stated LIFO cost by
9
approximately $36.0 million and $7.0 million at March 31, 2003 and December 31, 2002, respectively, based on the average cost of fuel purchased.
Enogex
Effective January 1, 2003, gas storage inventory used in OERI’s trading activities are accounted for at the lower of cost or market in accordance with the guidance in Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” which resulted in the rescission of EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as amended. Prior to January 1, 2003, this inventory was accounted for on a fair value accounting basis utilizing a gas index that in management’s opinion approximated the current market value of natural gas in that region as of the Balance Sheet date. In order to minimize risk, OERI may enter into contracts or hedging instruments to hedge the fair value of this inventory. If these contracts qualify for hedge accounting under SFAS No. 133, the hedged portion of the inventory is recorded at fair value with an offsetting gain or loss recorded currently in earnings. The fair value of the hedging instrument is also recorded on the books of the Company as a Price Risk Management asset or liability with an offsetting gain or loss recorded in current earnings. At March 31, 2003, the Company had no qualified fair value hedges under SFAS No. 133 for natural gas inventory. Natural gas inventories used in OERI’s trading activities, which are valued at the lower of cost or market, were approximately $2.4 million at March 31, 2003. See Note 2 for a further discussion.
Stock-Based Compensation
Pursuant to the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” the Company has elected to continue using the intrinsic value method of accounting for its stock-based employee compensation plans in accordance with Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” Accordingly, the Company has not recognized compensation expense for its stock-based awards to employees.
10
The following table reflects pro forma net loss and loss per average common share had the Company elected to adopt the fair value based method of SFAS No. 123:
Three Months Ended
March 31,
------------------------------------
2003 2002
--------------- ---------------
(In millions, except per share data)
Net loss, as reported...................................... $ (0.3) $ (6.2)
Add:
Stock-based employee compensation expense included
in reported net loss, net of related tax effects.......... --- ---
Deduct:
Stock-based employee compensation expense determined
under fair value based method for all awards, net of
related tax effects....................................... 0.4 0.3
--------------- ---------------
Pro forma net loss......................................... $ (0.7) $ (6.5)
=============== ===============
Loss per average common share
Basic - as reported...................................... $ --- $ (0.08)
Basic - pro forma........................................ $ (0.01) $ (0.08)
Diluted - as reported.................................... $ --- $ (0.08)
Diluted - pro forma...................................... $ (0.01) $ (0.08)
Reclassifications
Certain prior year amounts have been reclassified on the condensed consolidated financial statements to conform to the 2003 presentation.
2. Accounting Pronouncements
In June 2001, the FASB issued SFAS No. 143, which applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of a long-lived asset. SFAS No. 143 affects the Company’s accrued plant removal costs for generation, transmission, distribution and processing facilities and requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of the fair value can be made. If a reasonable estimate of the fair value cannot be made in the period the asset retirement obligation is incurred, the liability shall be recognized when a reasonable estimate of the fair value can be made. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel. The recognition of an asset retirement obligation is capitalized as part of the carrying amount of
11
the long-lived asset. Asset retirement obligations represent future liabilities and, as a result, accretion expense is accrued on this liability until such time as the obligation is satisfied. Adoption of SFAS No. 143 is required for financial statements issued for fiscal years beginning after June 15, 2002. The Company adopted this new standard effective January 1, 2003 and the adoption of this new standard did not have a material impact on its consolidated financial position or results of operations. In connection with the adoption of SFAS No. 143, the Company assessed whether it had a legal obligation within the scope of SFAS No. 143. The Company determined that it had a legal obligation to retire certain assets. As the Company currently has no plans to retire any of these assets and the remaining life is indeterminable, an asset retirement obligation was not recognized; however, the Company will monitor these assets and record a liability when a reasonable estimate of the fair value can be made. As described below, amounts recovered from ratepayers related to estimated asset retirement obligations recorded as a liability in Accumulated Depreciation were reclassified as a regulatory liability in the first quarter of 2003.
SFAS No. 143 also requires that, if the conditions of SFAS No. 71 are met, a regulatory asset or liability should be recorded to recognize differences between asset retirement costs recorded under SFAS No. 143 and legal or other asset retirement costs recognized for ratemaking purposes. Upon adoption of SFAS No. 143, the Company was required to quantify the amount of asset retirement costs previously recovered from ratepayers for other than legal obligations and reclassify those differences as regulatory assets or liabilities. At December 31, 2002, approximately $109.3 million had been previously recovered from ratepayers and recorded as a liability in Accumulated Depreciation related to estimated asset retirement obligations. This balance was reclassified as a regulatory liability on the December 31, 2002 Condensed Consolidated Balance Sheet.
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 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 adopted this new standard effective January 1, 2003 and the adoption of this new standard did not have a material impact on its consolidated financial position or results of operations.
In October 2002, the EITF reached a consensus on certain issues covered in EITF 02-3. One consensus of EITF 02-3 requires that all mark-to-market gains and losses, whether realized or unrealized, on financial derivative contracts as defined in SFAS No. 133 be shown net in the Income Statement for financial statements issued for periods beginning after December 15, 2002, with reclassification required for prior periods presented. The Company adopted this consensus effective January 1, 2003 and the application of this consensus did not have a material impact on
12
its consolidated financial position or results of operations as this consensus supports the Company's historical presentation of financial derivative contracts.
In October 2002, the EITF reached a consensus to rescind EITF 98-10 effective for fiscal periods beginning after December 15, 2002. Effective October 25, 2002, all new contracts and physical inventories that would have been accounted for under EITF 98-10 are no longer marked to market through earnings unless the contracts meet the definition of a derivative under SFAS No. 133. Application of the consensus for energy contracts and inventory that existed on or before October 25, 2002 that remained in effect at the date this consensus was initially applied was recognized as a cumulative effect of a change in accounting principle in accordance with APB Opinion No. 20, “Accounting Changes.” As a result, only energy contracts that meet the definition of a derivative in SFAS No. 133 will be carried at fair value. The Company adopted this consensus effective January 1, 2003 resulting in an approximate $9.6 million pre-tax loss ($5.9 million after tax). The loss, which was accounted for as a cumulative effect of a change in accounting principle, was primarily related to natural gas held in storage for trading purposes. This natural gas held in storage was sold during the first quarter of 2003 resulting in an increase in gross margin on revenues in excess of the cumulative effect loss described above.
In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123.” SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation which includes the prospective method, modified prospective method and retroactive restatement method. SFAS No. 148 also amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Adoption of the annual disclosure and voluntary transition requirements of SFAS No. 148 is required for annual financial statements issued for fiscal years ending after December 15, 2002. Adoption of the interim disclosure requirements of SFAS No. 148 is required for interim periods beginning after December 15, 2002. Pursuant to the provisions of SFAS No. 123, the Company has elected to continue using the intrinsic value method of accounting for its stock-based employee compensation plans in accordance with APB 25. See “Stock-Based Compensation” in Note 1 for a further discussion.
3. Price Risk Management Assets and Liabilities
Non-Trading Activities
The Company periodically utilizes derivative contracts to manage exposure to unfavorable changes in commodity prices, as well as to reduce exposure to adverse interest rate fluctuations. During the three months ended March 31, 2003 and 2002, the Company’s use of non-trading price risk management instruments primarily involved the use of interest rate swap agreements to hedge the Company’s exposure to interest rate risk by converting a portion of the Company’s fixed rate debt to a floating rate. These agreements involve the receipt of fixed rate amounts in exchange for floating rate interest payments over the life of the agreement without an
13
exchange of the underlying principal amount. In addition, the Company utilized certain fixed price swap instruments to hedge the price to be received for excess fuel recovered from customers as well as to hedge portions of the Company’s exposure to natural gas liquids prices and natural gas storage activities.
In accordance with SFAS No. 133, the Company recognizes all of its derivative instruments as Price Risk Management assets or liabilities in the Balance Sheet at fair value with such amounts classified as current or long-term based on their anticipated settlement. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item attributable to the hedged risk are recognized in the same line item associated with the hedged item in current earnings during the period of the change in fair values. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. Forecasted transactions designated as the hedged item in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, any gain or loss deferred in Accumulated Other Comprehensive Income is recognized currently in earnings. The Company’s interest rate swap agreements have been designated as fair value hedges and qualified for the shortcut method prescribed by SFAS No. 133. Under the shortcut method, the Company assumes that the hedged item’s change in fair value is exactly as much as the derivative’s change in fair value.
At March 31, 2003, the Company had outstanding cash flow hedges and approximately a $0.2 million after tax gain was included in Accumulated Other Comprehensive Loss. At December 31, 2002, the Company had no outstanding cash flow hedges, and no amounts were included in Accumulated Other Comprehensive Loss related to cash flow hedges.
Trading Activities
The Company, through its subsidiary, OERI, engages in energy trading activities primarily related to the purchase and sale of natural gas and electricity as well as certain other commodities. Contracts utilized in these activities generally include forward and swap contracts, over-the-counter and exchange traded options and storage and transportation contracts. Under the guidance provided by SFAS No. 133, financial instruments that qualify as derivatives are reflected at fair value with the resulting unrealized gains and losses recorded as Price Risk Management assets or liabilities in the accompanying Condensed Consolidated Balance Sheets, classified as current or long-term based on their anticipated settlement. Unrealized gains and losses from changes in the market value of open contracts are included in Natural Gas Pipeline operating revenues in the Condensed Consolidated Statements of Operations. Energy trading
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contracts resulting in delivery of a commodity that meet the requirements of EITF Issue No. 99-19, “Reporting Revenues Gross as a Principal or Net as an Agent,” are included as sales or purchases in the accompanying Condensed Consolidated Statements of Operations depending on whether the contract relates to the sale or purchase of the commodity. See Note 2 for a further discussion of the accounting for the Company’s energy trading activities.
4. Comprehensive Loss
The components of total comprehensive loss for the three months ended March 31, 2003 and 2002, respectively, are as follows:
Three Months Ended
March 31,
------------------------------------
(In millions) 2003 2002
=========================================================================================
Net loss ......................................... $ (0.3) $ (6.2)
-----------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax:
Deferred hedging gains (losses)................. 0.2 (0.1)
-----------------------------------------------------------------------------------------
Total comprehensive loss.......................... $ (0.1) $ (6.3)
=========================================================================================
Accumulated other comprehensive loss at both March 31, 2003 and December 31, 2002 included approximately a $74.3 million after tax loss ($121.3 million pre-tax) related to a minimum pension liability adjustment. Also included at March 31, 2003 was approximately a $0.2 million after tax gain related to outstanding cash flow hedges.
5. Discontinued Operations
On March 25, 2002, Enogex entered into an Agreement of Sale and Purchase with West Texas Gas, Inc. to sell all of its interests in Belvan Corp., Belvan Limited Partnership and Todd Ranch Limited Partnership (“Belvan”) for approximately $9.8 million. The effective date of the sale was January 1, 2002 and the closing occurred on March 28, 2002. The Company recognized approximately a $1.6 million after tax gain related to the sale of these assets.
On August 5, 2002, Enogex entered into an Agreement of Sale and Purchase with Chesapeake Exploration Limited Partnership to sell all of its exploration and production assets located in Oklahoma, Texas, Arkansas and Mississippi for approximately $15.0 million. The effective date of the sale was July 1, 2002 and the closing occurred on September 19, 2002. The Company recognized approximately a $2.3 million after tax loss related to the sale of these assets.
On November 14, 2002, Enogex entered into an Agreement of Sale and Purchase with Quicksilver Resources, Inc. to sell all of its exploration and production assets located in Michigan for approximately $32.0 million. The effective date of the sale was July 1, 2002 and the closing occurred on December 2, 2002. The Company recognized approximately a $2.9 million after tax gain related to the sale of these assets.
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During the third quarter of 2002, the Company decided to sell all of its interests in the NuStar Joint Venture (“NuStar”). On January 23, 2003, Enogex entered into an Agreement of Sale and Purchase with Benedum Gas Partners, L.P. to sell all of the interests of its subsidiary, Enogex Products Corporation, in the west Texas properties consisting of NuStar, which has operations consisting of the extraction and sale of natural gas liquids, for approximately $37.0 million. The effective date of the sale was January 1, 2003 and the closing occurred on February 18, 2003. The Company recognized approximately a $1.4 million after tax gain in the first quarter of 2003 related to the sale of these assets, which is recorded in Income from Discontinued Operations in the accompanying Condensed Consolidated Statements of Operations.
The condensed consolidated financial statements of the Company have been restated to reflect Enogex’s exploration and production assets, NuStar and Belvan, all of which were part of the Natural Gas Pipeline segment, as discontinued operations. Accordingly, revenues, costs and expenses, assets, liabilities and cash flows of the exploration and production assets, NuStar and Belvan have been excluded from the respective captions in the condensed consolidated financial statements and have been reported as “Current Assets of Discontinued Operations”, “Net Property, Plant and Equipment of Discontinued Operations”, “Deferred Charges and Other Assets of Discontinued Operations”, “Current Liabilities of Discontinued Operations”, “Deferred Credits and Other Liabilities of Discontinued Operations”, “Income from Discontinued Operations” and “Net Cash Provided from Discontinued Operations.”
Summarized financial information for the discontinued operations is as follows:
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS DATA
Three Months Ended
March 31,
-----------------------
(In millions) 2003 2002
==================================================================================
Operating revenues from discontinued operations......... $ 7.8 $ 19.4
- ----------------------------------------------------------------------------------
Income from discontinued operations before taxes........ $ 2.2 $ 1.7
- ----------------------------------------------------------------------------------
CONDENSED CONSOLIDATED BALANCE SHEET DATA
March 31, December 31,
(In millions) 2003 2002
======================================================================================
Accounts receivable...................................... $ 0.2 $ 4.1
Other current assets..................................... --- 0.6
- --------------------------------------------------------------------------------------
Total current assets of discontinued operations........ $ 0.2 $ 4.7
- --------------------------------------------------------------------------------------
Plant in service of discontinued operations.............. --- 54.2
Less accumulated depreciation........................ --- 11.4
- --------------------------------------------------------------------------------------
Net property, plant and equipment of discontinued
operations............................................ $ --- $ 42.8
- --------------------------------------------------------------------------------------
Total deferred charges and other assets of
discontinued operations................................. $ --- $ 0.2
- --------------------------------------------------------------------------------------
Accounts payable......................................... --- 1.1
Accrued taxes............................................ --- 0.4
Other current liabilities................................ 0.2 0.5
- --------------------------------------------------------------------------------------
Total current liabilities of discontinued operations... $ 0.2 $ 2.0
- --------------------------------------------------------------------------------------
Total deferred credits and other liabilities of
discontinued operations................................. $ --- $ 9.1
- --------------------------------------------------------------------------------------
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6. Asset Disposals
On August 2, 2002, Ozark, in which an Enogex subsidiary owns a 75 percent interest, entered into an Agreement of Sale and Purchase with CenterPoint Energy Gas Transmission Co. to sell approximately 29 miles of transmission lines of the Ozark pipeline located in Pittsburg and Latimer counties in Oklahoma for approximately $10.0 million. On November 18, 2002, the Company received FERC approval for the closing, which occurred on January 6, 2003. The Company recognized approximately a $5.3 million pre-tax gain in the first quarter of 2003 related to the sale of these assets, which is recorded in Other Income in the accompanying Condensed Consolidated Statements of Operations. These assets were part of the Natural Gas Pipeline segment.
7. Supplemental Cash Flow Information
Non-cash financing activities for the three months ended March 31, 2003 and 2002 included approximately $0.2 million and $4.5 million, respectively, related to the change in fair value of the interest rate swap agreements and the corresponding change in long-term debt.
Cash payments for interest, net of interest capitalized of approximately $0.2 million and $0.4 million, respectively, were approximately $32.3 million and $36.6 million for the three months ended March 31, 2003 and 2002, respectively. Cash payments for income taxes, net of income tax refunds, were approximately $2.6 million for the three months ended March 31, 2003. Cash refunds related to income taxes, net of income tax payments, were approximately $26.0 million for the three months ended March 31, 2002.
8. Common Stock
For the three months ended March 31, 2003, the Company issued 242,020 shares of new common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan. For the three months ended March 31, 2002, there were 5,066 shares of new common stock issued pursuant to the Stock Incentive Plan, which related to exercised stock options.
9. Earnings Per Share
For the three months ended March 31, 2003, there were 0.3 million shares of employee stock options, which were included in the computation of diluted earnings per average common share. No employee stock options were included in the computation of diluted earnings per average common share for the three months ended March 31, 2002. For the three months ended March 31, 2003 and 2002, respectively, approximately 2.3 million shares and 2.5 million shares subject to issuance related to employee stock options are not included in the calculation of adjusted average common shares outstanding for diluted earnings per average common share because the effect of including those shares is anti-dilutive.
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10. Long-Term Debt
Interest Rate Swap Agreements
At March 31, 2003 and December 31, 2002, the Company had three outstanding interest rate swap agreements: (i) OG&E 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 ("LIBOR") and (ii) Enogex entered into two separate interest rate swap agreements, effective July 15, 2002 and October 24, 2002, to convert $100.0 million each of 8.125 percent fixed rate debt due January 15, 2010, to a variable rate based on the six month LIBOR.
These interest rate swaps qualified as fair value hedges under SFAS No. 133 and meet 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 these interest rate swaps was to achieve a lower cost of debt and to raise the percentage of total corporate long-term floating rate debt to reflect a level more in line with industry standards.
At March 31, 2003 and December 31, 2002, the fair values pursuant to the interest rate swaps were approximately $16.1 million and $15.9 million, respectively, and are included in non-current Price Risk Management assets in the accompanying Condensed Consolidated Balance Sheets. A corresponding net increase of approximately $16.1 million and $15.9 million is reflected in Long-Term Debt at March 31, 2003 and December 31, 2002, respectively, as these fair value hedges were effective at March 31, 2003 and December 31, 2002.
Security Ratings
On January 15, 2003, Standard & Poor’s Ratings Services (“Standard & Poor’s”) lowered the credit ratings of OGE Energy Corp.‘s, OG&E’s and Enogex’s senior unsecured debt from A- to BBB+. OGE Energy Corp.‘s short-term commercial paper ratings were affirmed at A-2. The Company may experience somewhat higher borrowing costs but does not expect the actions by Standard & Poor’s to have a significant impact on the Company’s consolidated financial position or results of operations.
On February 5, 2003, Moody’s Investors Service (“Moody’s”) lowered the credit ratings of OGE Energy Corp.'s senior unsecured debt to Baa1 from A3, OG&E's senior unsecured debt to A2 from A1 and Enogex's senior unsecured debt to Baa3 from Baa2. OGE Energy Corp.‘s short-term commercial paper rating was unchanged at P-2. The Company may experience somewhat higher borrowing costs but does not expect the actions by Moody’s to have a significant impact on the Company’s consolidated financial position or results of operations. As a result of Enogex’s rating being lowered to Baa3, OGE Energy Corp. was required to issue a $5.0 million guarantee on Enogex’s behalf for a counterparty. At March 31, 2003, there is no outstanding liability balance related to this guarantee.
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A security rating is not a recommendation to buy, sell or hold securities. Such rating may be subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
11. Short-Term Debt
Consolidated short-term debt of approximately $173.0 million and $275.0 million, respectively, was outstanding at March 31, 2003 and December 31, 2002. The following table shows the Company’s lines of credit in place at March 31, 2003. Short-term borrowings will consist of a combination of bank borrowings and commercial paper.
Lines of Credit (In millions)
-------------------------------------------------------------------------------
Entity Amount Maturity
-------------------------------------------------------------------------------
OGE Energy Corp. (A) $ 200.0 January 8, 2004
100.0 January 15, 2004
15.0 April 6, 2004
OG&E 100.0 June 26, 2003
-------------------------------------------------------------------------------
Total $ 415.0
===============================================================================
(A) The lines of credit at OGE Energy Corp. are used to back up the Company's
commercial paper borrowings, which were approximately $139.2 million at
March 31, 2003. No borrowings were outstanding at March 31, 2003 under any of
the lines of credit shown above.
The Company’s ability to access the commercial paper market could be adversely impacted by a commercial paper ratings downgrade. The lines of credit contain ratings triggers that require annual fees and borrowing rates to increase if the Company suffers an adverse ratings impact. The impact of additional downgrades of the Company’s rating would result in an increase in the cost of short-term borrowings of approximately five to 20 basis points, but would not result in any defaults or accelerations as a result of the ratings triggers.
Unlike the Company and Enogex, OG&E must obtain regulatory approval from the FERC in order to borrow on a short-term basis. OG&E has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time.
12. Report of Business Segments
The Company’s Electric Utility operations are conducted through OG&E, a regulated utility engaged in the generation, transmission, distribution and sale of electric energy. The Company’s Natural Gas Pipeline operations are conducted through Enogex. Enogex is engaged in the transportation and storage of natural gas, the gathering and processing of natural gas and the marketing and trading of natural gas. Enogex also has been involved in investing in the development for and production of natural gas and crude oil, which investments Enogex sold during 2002. Other Operations primarily includes unallocated corporate expenses and interest expense on commercial paper and the Trust Originated Preferred Securities. Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by
19
regulatory considerations. The following tables are a summary of the results of the Company’s business segments for the three months ended March 31, 2003 and 2002.
==============================================================================================================
Three Months Ended Electric Natural Gas Other
March 31, 2003 Utility Pipeline (A) Operations Intersegment Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Operating revenues........................ $ 332.6 $ 739.6 $ --- $ (22.0) $ 1,050.2
Fuel ..................................... 141.2 --- --- (10.0) 131.2
Purchased power........................... 72.7 --- --- --- 72.7
Gas and electricity purchased for resale.. --- 657.0 --- (12.0) 645.0
Natural gas purchases - other............. --- 19.5 --- --- 19.5
- --------------------------------------------------------------------------------------------------------------
Cost of goods sold........................ 213.9 676.5 --- (22.0) 868.4
Gross margin on revenues.................. 118.7 63.1 --- --- 181.8
- --------------------------------------------------------------------------------------------------------------
Other operation and maintenance........... 72.0 22.4 (4.1) --- 90.3
Depreciation.............................. 32.6 11.2 2.8 --- 46.6
Taxes other than income................... 12.0 4.3 0.9 --- 17.2
- --------------------------------------------------------------------------------------------------------------
Operating income.......................... 2.1 25.2 0.4 --- 27.7
- --------------------------------------------------------------------------------------------------------------
Other income ............................ 0.3 5.7 0.1 --- 6.1
Other expense............................. (0.7) (1.7) (0.5) --- (2.9)
Interest income........................... --- 0.3 4.8 (4.9) 0.2
Interest expense.......................... (9.9) (10.1) (9.8) 4.9 (24.9)
Income tax expense (benefit).............. (4.9) 9.3 (2.5) --- 1.9
- --------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations.. $ (3.3) $ 10.1 $ (2.5) $ --- $ 4.3
- --------------------------------------------------------------------------------------------------------------
Income from discontinued operations....... --- 1.3 --- --- 1.3
- --------------------------------------------------------------------------------------------------------------
Income (loss) before cumulative effect of
change in accounting principle............ (3.3) 11.4 (2.5) --- 5.6
Cumulative effect of change in accounting
for energy trading contracts, net of tax.. --- (5.9) --- --- (5.9)
- --------------------------------------------------------------------------------------------------------------
Net income (loss)......................... $ (3.3) $ 5.5 $ (2.5) $ --- $ (0.3)
==============================================================================================================
(A) Beginning with the first quarter of 2002, Natural Gas Pipeline's operations consisted of three related businesses: Transportation and Storage, Gathering and Processing and Marketing and Trading. The following table is supplemental Natural Gas Pipeline information.
==============================================================================================================
Transportation Gathering Marketing
Three Months Ended and and and
March 31, 2003 Storage Processing Trading Eliminations Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Operating revenues...................... $ 69.0 $ 141.5 $ 646.6 $ (117.5) $ 739.6
Operating income........................ $ 8.7 $ 6.5 $ 10.0 $ --- $ 25.2
==============================================================================================================
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==============================================================================================================
Three Months Ended Electric Natural Gas Other
March 31, 2002 Utility Pipeline (A) Operations Intersegment Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Operating revenues........................ $ 262.1 $ 323.3 $ --- $ (9.6) $ 575.8
Fuel ..................................... 85.0 --- --- (9.1) 75.9
Purchased power........................... 63.8 --- --- --- 63.8
Gas and electricity purchased for resale.. --- 256.7 --- (0.5) 256.2
Natural gas purchases - other............. --- 17.8 --- --- 17.8
- --------------------------------------------------------------------------------------------------------------
Cost of goods sold........................ 148.8 274.5 --- (9.6) 413.7
Gross margin on revenues.................. 113.3 48.8 --- --- 162.1
- --------------------------------------------------------------------------------------------------------------
Other operation and maintenance........... 64.7 24.0 (3.6) --- 85.1
Depreciation.............................. 30.8 12.0 2.4 --- 45.2
Taxes other than income................... 11.9 4.0 0.8 --- 16.7
- --------------------------------------------------------------------------------------------------------------
Operating income.......................... 5.9 8.8 0.4 --- 15.1
- --------------------------------------------------------------------------------------------------------------
Other income ............................ 0.2 0.5 0.1 --- 0.8
Other expense............................. (0.7) (0.6) --- --- (1.3)
Interest income........................... 0.4 0.4 4.7 (5.0) 0.5
Interest expense.......................... (9.8) (13.1) (10.6) 5.0 (28.5)
Income tax benefit........................ (2.5) (0.6) (2.0) --- (5.1)
- --------------------------------------------------------------------------------------------------------------
Loss from continuing operations........... $ (1.5) $ (3.4) $ (3.4) $ --- $ (8.3)
- --------------------------------------------------------------------------------------------------------------
Income from discontinued operations....... --- 2.1 --- --- 2.1
- --------------------------------------------------------------------------------------------------------------
Net loss.................................. $ (1.5) $ (1.3) $ (3.4) $ --- $ (6.2)
==============================================================================================================
(A) Beginning with the first quarter of 2002, Natural Gas Pipeline's operations consisted of three related businesses: Transportation and Storage, Gathering and Processing and Marketing and Trading. The following table is supplemental Natural Gas Pipeline information.
==============================================================================================================
Transportation Gathering Marketing
Three Months Ended and and and
March 31, 2002 Storage Processing Trading Eliminations Total
- --------------------------------------------------------------------------------------------------------------
(In millions)
Operating revenues...................... $ 117.0 $ 38.8 $ 250.6 $ (83.1) $ 323.3
Operating income (loss)................. $ 10.8 $ (2.1) $ 0.1 $ --- $ 8.8
==============================================================================================================
13. Commitments and Contingencies
Except as set forth below, the circumstances set forth in Note 15 to the Company’s consolidated financial statements included in the Company’s Form 10-K for the year ended December 31, 2002, appropriately represent, in all material respects, the current status of any material commitments and contingent liabilities.
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Farmland Industries
Farmland Industries, Inc. (“Farmland”) voluntarily filed for Chapter 11 bankruptcy protection from creditors on May 31, 2002. Enogex provided gas transportation and supply services to Farmland, and is an unsecured creditor of Farmland. Enogex filed its Proof of Claim on January 7, 2003, for approximately $5.4 million. In April 2003, Enogex negotiated a settlement in which it will receive approximately $1.9 million in May 2003 which is approximately $0.3 million higher than the $1.6 million outstanding balance due (net of the $3.8 million reserve recorded in 2002).
Guarantees
During the normal course of business, Enogex issues guarantees on behalf of its subsidiaries for the purpose of securing credit for certain business activities. These guarantees are for payment when due of amounts payable by its subsidiaries under various agreements with counterparties. At March 31, 2003, accounts payable supported by guarantees was approximately $91.4 million. Since these guarantees by Enogex represent security for payment of payables obtained in the normal course of its subsidiaries business activities, the Company, on a consolidated basis, does not assume any additional liability as a result of this arrangement.
OGE Energy Corp. has issued a $5.0 million guarantee on behalf of OERI and a $15.0 million guarantee on behalf of Enogex Inc. for the purpose of securing credit for certain business activities. These guarantees are for payment when due of amounts payable by OERI and Enogex Inc. under various agreements with counterparties. At March 31, 2003, accounts payable supported by guarantees was approximately $0.1 million. Since these guarantees by OGE Energy Corp. represent security for payment of payables obtained in OERI’s and Enogex Inc.’s business activities, the Company, on a consolidated basis, does not assume any additional liability as a result of this arrangement.
As of December 31, 2002, in the event Moody’s or Standard & Poor’s were to lower Enogex’s senior unsecured debt rating to a below investment grade rating, Enogex would be required to post less than $5.0 million of collateral to satisfy its obligation under its financial and physical contracts.
Other
In the normal course of business, the Company is confronted with issues or events that may result in a contingent liability. These generally relate to lawsuits, claims made by third parties, environmental actions or the action of various regulatory agencies. Management consults with counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company has incurred a probable loss as set forth by accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate accounting entries are reflected in the Company’s condensed consolidated financial statements. Management, after consultation with legal counsel, does not anticipate that liabilities arising out of other currently
22
pending or threatened lawsuits and claims will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flows.
14. Rate Matters and Regulation
Regulation and Rates
OG&E’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in Arkansas. The issuance of certain securities by OG&E is also regulated by the OCC and the APSC. OG&E’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 OG&E’s facilities and operations.
The order of the OCC authorizing OG&E to reorganize into a subsidiary of the Company contains certain provisions which, among other things, ensure the OCC access to the books and records of the Company and its affiliates relating to transactions with OG&E; require the Company to employ accounting and other procedures and controls to protect against subsidization of non-utility activities by OG&E’s customers; and prohibit the Company from pledging OG&E assets or income for affiliate transactions.
On October 11, 2002, OG&E, the OCC Staff, the Oklahoma Attorney General and other interested parties agreed to a settlement (the “Settlement Agreement”) of OG&E’s rate case. The administrative law judge subsequently recommended approval of the Settlement Agreement and on November 22, 2002, the OCC signed a rate order containing the provisions of the Settlement Agreement. The Settlement Agreement provides for, among other items: (i) a $25.0 million annual reduction in the electric rates of OG&E’s Oklahoma customers which went into effect January 6, 2003; (ii) recovery by OG&E, through rate base, of the capital expenditures associated with the January 2002 ice storm; (iii) recovery by OG&E, over three years, of the $5.4 million in deferred operating costs, associated with the January 2002 ice storm, through OG&E’s rider for sales to other utilities and power marketers; (iv) OG&E to acquire electric generating capacity of not less than 400 megawatts to be integrated into OG&E’s generation system. Key portions of the Settlement Agreement are described in detail in Note 16 to the Company’s Consolidated Financial Statements included in the Company’s Form 10-K for the year ended December 31, 2002.
As part of the Settlement Agreement, OG&E also agreed to consider competitive bidding for gas transportation service to its natural gas fired generation facilities pursuant to the terms set forth in the Settlement Agreement. On April 29, 2003, OG&E filed an application with the OCC in which OG&E advised the OCC that after careful consideration competitive bidding for gas transportation was rejected in favor of a new intrastate firm no-notice load following gas transportation and storage services agreement with Enogex. This seven-year agreement provides for gas transportation and storage services for each of OG&E's natural gas fired generation plants. An OCC order in the case is expected during 2003.
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Security Enhancements
On August 14, 2002, OG&E filed a report with the OCC outlining proposed expenditures and related actions for security enhancement. Attempting to make security investments at the proper level, OG&E 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 OG&E that might be caused by an attack and accomplish these efforts with minimal impact on ratepayers. The OCC Staff has retained a security expert to review the report filed by OG&E, and a hearing is expected to be held in July 2003.
Other Regulatory Actions
The Settlement Agreement, when it became effective, provided for the termination of the Acquisition Premium Credit Rider ("APC Rider") and the Gas Transportation Adjustment Credit Rider ("GTAC Rider").
The APC Rider was approved by the OCC in March 2000 and was implemented by OG&E to reflect the completion of the recovery of the amortization premium paid by OG&E when it acquired Enogex in 1986. The effect of the APC Rider was to remove approximately $10.7 million annually from the amount being recovered by OG&E from its Oklahoma customers in current rates.
In June 2001, the OCC approved a stipulation (the “Stipulation”) to the competitive bid process of OG&E’s gas transportation service from Enogex. The Stipulation directed OG&E to reduce its rates to its Oklahoma retail customers by approximately $2.7 million per year through the implementation of the GTAC Rider. The GTAC Rider was a credit for gas transportation cost recovery and was applicable to and became part of each Oklahoma retail rate schedule to which OG&E’s automatic fuel adjustment clause applies. As discussed above, the Settlement Agreement terminated the GTAC Rider. Consequently, these charges for gas transportation provided by Enogex are now included in base rates.
OG&E’s Generation Efficiency Performance Rider (“GEP Rider”) expired in June 2002. The GEP Rider was established initially in 1997 in connection with OG&E’s 1996 general rate review and was intended to encourage OG&E to lower its fuel costs by: (i) allowing OG&E to collect one-third of the amount by which its fuel costs were below a specified percentage (96.261 percent) of the average fuel costs of certain other investor-owned utilities in the region; and (ii) disallowing the collection of one-third of the amount by which its fuel costs exceeded a specified percentage (103.739 percent) of the average fuel costs of other investor-owned utilities. In June 2000 the OCC made modifications to the GEP Rider which had the effect of reducing the amount OG&E could recover under the GEP Rider by: (i) changing OG&E’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 OG&E’s costs exceed the new peer group by changing the percentage above which OG&E 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 OG&E’s share of cost savings as
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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 OG&E or penalties charged to OG&E.
FERC Section 311 Rate Case
In December 2001, Enogex made its filing at the FERC under Section 311 of the Natural Gas Policy Act to establish rates and a treating fee and to address various other issues for the combined Enogex and Transok L.L.C. pipeline systems, effective January 1, 2002, the date that these systems began operating as a single Enogex pipeline system. The FERC Staff, Enogex and the active intervening parties held extensive settlement discussions. Enogex negotiated a settlement of the case with the interveners and, on March 5, 2003, filed a Stipulation and Agreement of Settlement and related documents with the FERC to resolve all issues in dispute in Docket No. PR02-10-000. FERC regulations provide for initial and reply comments. The only initial comments on the settlement, filed March 25, 2003, strongly supported the Stipulation. The proposed settlement includes a fee for processing to bring gas gathered behind processing plants to pipeline gas quality Btu standards (default processing fee) and a monthly low flow meter charge of $200 (offset in any month by the transportation revenues generated by gas through the meter). At December 31, 2002, the Company has fully reserved any treating fees billed through December 31, 2002. During the first quarter of 2003, the Company accrued approximately $1.8 million of treating fees and approximately $0.1 million of low flow meter charges. By Order dated May 9, 2003, the FERC accepted the settlement agreement and entered its order modifying Enogex's Statement of Operating Conditions ("SOC"). The FERC Order requires Enogex to modify its SOC within 15 days to eliminate the priority for scheduling and curtailment purposes for interruptible dedicated gas customers. With the dedicated gas priority eliminated, interruptible capacity will be allocated based on price, consistent with the FERC policy.
State Restructuring Initiatives
Oklahoma
As previously reported, the Electric Restructuring Act of 1997 (the “1997 Act”) was designed to provide retail customers in Oklahoma a choice of their electric supplier by July 1, 2002. Additional implementing legislation was to be adopted by the Oklahoma Legislature to address many specific issues associated with the 1997 Act and with deregulation. In May 2000, a bill addressing the specific issues of deregulation was passed in the Oklahoma State Senate and then was defeated in the Oklahoma House of Representatives. In May 2001, the Oklahoma Legislature passed Senate Bill 440 (“SB 440”), which postponed the scheduled start date for customer choice from July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, SB 440 calls for a nine-member task force to further study the issues surrounding deregulation. The task force includes the Governor or his designee, the Oklahoma Attorney General, the OCC Chair and several legislative leaders, among others. In the current legislative session, Senate Bill 383 has been recently introduced to repeal the 1997 Act. It is unknown at this time whether the bill will be passed into law. The Company will continue to actively participate in the legislative process and expects to remain a competitive supplier of
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electricity. As a result of the failures of California’s attempt to deregulate its electricity markets, the Enron bankruptcy, and associated impacts on the industry, efforts to restructure the electricity market in Oklahoma appear at this time to be delayed indefinitely.
Arkansas
In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric utility industry at the retail level. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the Restructuring Law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. In March 2003, the Restructuring Law was repealed. As part of the repeal legislation, electric public utilities are permitted to recover transition costs. OG&E incurred approximately $2.4 million in transition costs necessary to carry out the Company’s responsibilities associated with efforts to implement retail open access. The Company will be filing an application with the APSC in the next several months to recover these costs. The APSC will most likely schedule a hearing later in 2003.
15. Fair Value of Financial Instruments
The following information is provided regarding the estimated fair value of the Company’s financial instruments, including derivative contracts related to the Company’s price risk management activities that have significantly changed since December 31, 2002:
March 31, December 31,
2003 2002
------------------- --------------------
Carrying Fair Carrying Fair
(In millions) Amount Value Amount Value
============================================================================================
Price Risk Management Assets
Energy Trading Contracts................ $ 48.6 $ 48.6 $ 21.4 $ 21.4
Price Risk Management Liabilities
Energy Trading Contracts................ $ 37.6 $ 37.6 $ 14.6 $ 14.6
============================================================================================
The carrying value of the financial instruments on the accompanying Condensed Consolidated Balance Sheets not otherwise discussed above approximates fair value. The valuation of the Company’s energy trading contracts was determined primarily based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties and the potential impact of liquidating the position in an orderly manner over a reasonable period of time.
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16. Subsequent Events
S-3 Filings
On April 2, 2003, the Company filed a Form S-3 Registration Statement to register 7,000,000 shares of the Company’s common stock pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan. Under the terms of this plan, the Company may accept requests for optional investments in amounts greater than $0.1 million per year and may offer a discount of up to three percent from current market prices. On April 30, 2003, the Company issued 288,133 shares of its common stock at a discount of 1.75 percent pursuant to the Company’s Automatic Dividend Reinvestment and Stock Purchase Plan.
On April 15, 2003, the Company filed a Form S-3 Registration Statement pursuant to which it may offer from time to time up to $130.0 million of unsecured debt securities or shares of the Company’s common stock.
On April 17, 2003, OG&E filed a Form S-3 Registration Statement pursuant to which it may offer from time to time up to $200.0 million aggregate principal amount of OG&E’s unsecured senior notes.
Liquidity
On April 6, 2003, the Company renewed its $15.0 million line of credit facility for an additional one-year term expiring April 6, 2004.
Long-Term Debt
On April 29, 2003, $2.0 million of Enogex’s long-term debt matured. On April 28, 2003, Enogex redeemed $10.0 million principal amount of 7.75 percent medium-term notes due April 24, 2023 and April 26, 2023.
Storm Damage
On May 8 and May 9, 2003, the Oklahoma City area was hit by a series of tornadoes that inflicted damage to OG&E's transmission and distribution system. The estimated storm damage costs are not expected to have a material effect on the Company's consolidated financial position or results of operations.
Regulatory Matters
On May 12, 2003, OG&E filed with the OCC a notice of intent to seek an annual increase in its rates to its Oklahoma customers of more than one percent. The notice lists the following, among others, as major issues to be addressed in its application: (i) the acquisition of a generation facility in accordance with the Settlement Agreement; (ii) increased capital expenditures for efficiency improvements and reliability enhancements to ensure fuel costs are
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minimized, and (iii) increased pension, medical and insurance costs. OG&E expects to file its application for this rate increase on or before June 27, 2003, which filing will disclose the precise amount of the rate increase being sought.
Agreement with Colorado Interstate Gas Company
In December 2002, Enogex entered into an agreement with Colorado Interstate Gas Company ("CIG") regarding reservation of capacity on a proposed interstate gas pipeline (the "Cheyenne Plains Pipeline"). If completed, the Cheyenne Plains Pipeline would provide interstate gas transportation services in the states of Wyoming, Colorado and Kansas. Under the agreement, Enogex bid to reserve 60,000 Decatherms/day of capacity on the proposed pipeline. Such reservation would result in Enogex having access to significant additional natural gas supplies in the areas to be served by the proposed pipeline. CIG has advised that its plan is to request FERC approval for construction of the pipeline in May 2003. Subject to regulatory and other approvals, CIG is proposing an in-service date of August 31, 2005. See a copy of this agreement attached as Exhibit 10.02.
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Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Introduction
OGE Energy Corp. (collectively with its subsidiaries, the “Company”) 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 conducts these activities through two business segments, the Electric Utility and the Natural Gas Pipeline segments.
The Electric Utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E sold its retail gas business in 1928 and is no longer engaged in the gas distribution business. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area.
The Natural Gas Pipeline segment is conducted through Enogex Inc. and its subsidiaries (“Enogex”) and consists of three related businesses: (i) the transportation and storage of natural gas, (ii) the gathering and processing of natural gas and (iii) the marketing and trading of natural gas (collectively, the “pipeline businesses”). The vast majority of Enogex’s natural gas gathering, processing, transportation and storage assets are located in the major gas producing basins of Oklahoma. Through a 75 percent interest in the NOARK Pipeline System Limited Partnership, Enogex also owns a controlling interest in and operates the Ozark Gas Transmission System (“Ozark”), a FERC regulated interstate pipeline that extends from southeast Oklahoma through Arkansas to southeast Missouri. Enogex’s marketing and trading activities include corporate price risk management and other optimization services. Enogex was previously engaged in the exploration and production of natural gas, however, this portion of Enogex’s business, along with interests in certain gas gathering and processing assets in Texas, were sold in 2002 and in the first quarter of 2003 and are reported in the condensed consolidated financial statements as discontinued operations.
Company Strategy
In early 2002, the Company completed a review of its business strategy that was largely driven by the anticipated deregulation of the retail electric markets in Oklahoma and Arkansas. Due to a variety of factors, including the current efforts to repeal the Oklahoma Electric Restructuring Act of 1997 and the recent repeal of the Restructuring Law in Arkansas, the Company does not anticipate that deregulation of the electricity markets in Oklahoma or Arkansas will occur in the foreseeable future. The strategic direction of the Company has been revised to reflect these developments. As a result, the Company expects potentially slower earnings growth than associated with deregulation but with less variability of those earnings.
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The Company’s business strategy will utilize the diversified asset position of OG&E and Enogex to provide energy products and services to customers primarily in the south central United States. The Company will focus on those products and services with limited or manageable commodity exposure. The Company intends for OG&E to continue as an integrated utility engaged in the generation and the distribution of electricity and to represent over time approximately 70 percent of the Company’s consolidated assets. The remainder of the Company’s assets will be in Enogex’s pipeline businesses. In addition to the incremental growth opportunities that Enogex provides, the Company believes that Enogex’s risk management capabilities, commercial skills and market information provide value to all of the Company’s businesses. Federal regulation in regard to the operations of the wholesale power market may change with the proposed Standard Market Design initiative at the FERC. In addition, Oklahoma and Arkansas legislatures and utility commissions may propose changes from time to time that could subject the utilities to market risk. Accordingly, the Company is applying risk management practices to all of its operations in an effort to mitigate the potential adverse effect of any future regulatory changes.
In the near term, OG&E plans on increasing its investment and growing earnings largely through the acquisition of a merchant power plant. As part of the OCC’s rate order on November 20, 2002, OG&E is seeking to purchase an electric power plant with at least 400 megawatts (“MW”) of generating capacity and to include the cost of such plant in its rate base. Given the surplus power in the region, the Company believes there is a continuing opportunity to purchase existing power plants at prices below the cost to build. This should enable OG&E to generate electricity for its customers at prices below those being paid by OG&E under existing qualified cogeneration and small power production producers’ contracts (“QF contracts”). Unless extended by OG&E, many of these QF contracts will expire over the next one to five years. Accordingly, OG&E will continue to explore opportunities to purchase power plants in order to serve its native load. OG&E anticipates filing with appropriate regulatory agencies to increase base rates to recover its investment in any power plant acquired and expects that customers should realize overall lower rates through fuel savings due to the increased efficiency of these new plants and lower capital costs than those associated with the expiring QF contracts.
Enogex initiated a program in 2002 to improve its financial performance. As a part of this performance improvement program, Enogex has received net sales proceeds of approximately $101.3 million from asset sales, reduced debt by 17 percent, reduced its number of employees by 12 percent and reorganized its operations. In addition to improving its earnings, Enogex will continue to take actions to reduce its exposure to commodity prices by, among other things, mitigating its exposure to keep whole processing arrangements and reducing earnings volatility. While the Company be