FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2001
OR
| | TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-12579
OGE ENERGY CORP.
(Exact name of registrant as specified in its charter)
Oklahoma
73-1481638
(State or other jurisdiction of
(I.R.S. Employer
incorporation or
organization)
Identification No.)
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
There were 77,921,997 Shares of Common Stock, par value $0.01 per share, outstanding as of April 30, 2001.
OGE Energy Corp.
PART I. FINANCIAL INFORMATION
Item 1 FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
March 31
--------------------------------
2001 2000
-------------- --------------
(thousands except per share data)
OPERATING REVENUES......................................... $ 1,063,587 $ 581,581
COST OF GOODS SOLD......................................... 896,923 400,006
-------------- --------------
Gross margin on revenues................................. 116,664 181,575
-------------- --------------
Other operation and maintenance.......................... 98,090 88,352
Depreciation and amortization............................ 45,324 44,919
Taxes other than income.................................. 16,650 16,108
-------------- --------------
OPERATING INCOME........................................... 6,600 32,196
-------------- --------------
OTHER EXPENSES, NET........................................ (250) (201)
-------------- --------------
EARNINGS BEFORE INTEREST AND TAXES......................... 6,350 31,995
INTEREST INCOME (EXPENSES):
Interest income.......................................... 869 1,609
Interest on long-term debt............................... (26,441) (25,387)
Interest on trust preferred securities................... (4,317) (4,317)
Allowance for borrowed funds used during construction.... 183 148
Other interest charges................................... (3,706) (5,614)
-------------- --------------
Net interest income (expenses)......................... (33,412) (33,561)
-------------- --------------
LOSS BEFORE TAXES.......................................... (27,062) (1,566)
INCOME TAX BENEFIT......................................... (12,093) (2,342)
-------------- --------------
NET INCOME (LOSS).......................................... $ (14,969) $ 776
============== ==============
AVERAGE COMMON SHARES OUTSTANDING (thousands).............. 77,922 77,863
EARNINGS (LOSS) PER AVERAGE COMMON SHARE................... $ (0.19) $ 0.01
============== ==============
AVERAGE COMMON SHARES OUTSTANDING
ASSUMING DILUTION (thousands)............................ 77,922 77,863
EARNINGS (LOSS) PER AVERAGE COMMON SHARE
ASSUMING DILUTION........................................ $ (0.19) $ 0.01
============== ==============
DIVIDENDS DECLARED PER SHARE............................... $ 0.3325 $ 0.3325
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
1
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31 December 31
2001 2000
------------- --------------
(dollars in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 332 $ 454
Accounts receivable - customers, less reserve of $3,483 and
$4,135, respectively........................................ 316,402 446,185
Accrued unbilled revenues..................................... 42,300 49,000
Accounts receivable - other................................... 14,282 24,713
Fuel inventories.............................................. 90,867 200,316
Materials and supplies, at average cost....................... 41,505 41,517
Prepayments and other......................................... 36,125 45,715
Price risk management......................................... 11,226 45,727
Accumulated deferred tax assets............................... 10,776 10,669
------------- --------------
Total current assets........................................ 563,815 864,296
------------- --------------
OTHER PROPERTY AND INVESTMENTS, at cost......................... 37,872 36,980
------------- --------------
PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... 5,350,814 5,323,541
Construction work in progress................................. 71,953 47,016
------------- --------------
Total property, plant and equipment......................... 5,422,767 5,370,557
Less accumulated depreciation............................. 2,189,561 2,151,093
------------- --------------
Net property, plant and equipment............................. 3,233,206 3,219,464
------------- --------------
DEFERRED CHARGES:
Advance payments for gas...................................... 12,500 12,500
Income taxes recoverable through future rates................. 38,394 38,654
Other......................................................... 117,117 147,736
------------- --------------
Total deferred charges...................................... 168,011 198,890
------------- --------------
TOTAL ASSETS.................................................... $ 4,002,904 $ 4,319,630
============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt............................................... $ 164,300 $ 284,500
Accounts payable.............................................. 286,370 330,445
Dividends payable............................................. 25,909 25,890
Customers' deposits........................................... 23,395 22,647
Accrued taxes................................................. 3,717 33,067
Accrued interest.............................................. 29,884 40,699
Long-term debt due within one year............................ 2,000 2,000
Price risk management......................................... 4,895 33,709
Other......................................................... 36,005 36,975
------------- --------------
Total current liabilities................................... 576,475 809,932
------------- --------------
LONG-TERM DEBT.................................................. 1,643,693 1,648,523
------------- --------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 14,535 14,256
Accumulated deferred income taxes............................. 621,936 618,360
Accumulated deferred investment tax credits................... 56,141 57,429
Other......................................................... 68,900 106,822
------------- --------------
Total deferred credits and other liabilities................ 761,512 796,867
------------- --------------
STOCKHOLDERS' EQUITY:
Common stockholders' equity................................... 443,172 443,298
Retained earnings............................................. 580,114 621,010
Accumulated other comprehensive income........................ (2,062) ---
------------- --------------
Total stockholders' equity.................................. 1,021,224 1,064,308
------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 4,002,904 $ 4,319,630
============= ==============
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
2
CONSOLIDATED STATEMENTS OF
CASH FLOWS
(Unaudited)
Three Months Ended
March 31
2001 2000
-------------- --------------
(dollars in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss).................................................. $ (14,969) $ 776
Adjustments to Reconcile Net Income (Loss) to Net Cash
Provided from Operating Activities:
Depreciation and amortization.................................... 45,324 44,919
Deferred income taxes and investment tax credits, net............ 3,947 8,197
Gain on sale of assets........................................... (53) ---
Change in Certain Assets and Liabilities:
Accounts receivable - customers................................ 129,783 57,714
Accrued unbilled revenues...................................... 6,700 2,600
Fuel, materials and supplies inventories....................... 109,461 (13,959)
Other current assets........................................... 19,916 (25 640)
Accounts payable............................................... (44,075) 26,604
Accrued taxes.................................................. (29,350) (25,677)
Accrued interest............................................... (10,815 2,852
Other current liabilities...................................... (203) 16,502
Other operating activities....................................... (4,575) 5,860
-------------- --------------
Net cash provided from operating activities.................. 211,091 100,748
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (59,540) (43,422)
Proceeds from sale of assets....................................... 72 ---
Other investing activities......................................... (425) 166
-------------- --------------
Net cash used in investing activities........................ (59,893) (43,256)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt....................................... (4,883) ---
Proceeds from long-term debt....................................... --- 400,000
Decrease in short-term debt, net................................... (120,200) (435,400)
Retirement of common stock......................................... (125) ---
Payment of obligation under capital lease.......................... (184) ---
Cash dividends declared on common stock............................ (25,928) (25,889)
-------------- --------------
Net cash used in financing activities........................ (151,320) (61,289)
-------------- --------------
NET DECREASE IN CASH AND CASH EQUIVALENTS............................ (122) (3,797)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 454 7,271
-------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 332 $ 3,474
============== ==============
- --------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)............................. $ 41,578 $ 29,904
Income taxes..................................................... $ 1,800 $ 4,900
- --------------------------------------------------------------------------------------------------------------
DISCLOSURE OF ACCOUNTING POLICY:
For purposes of these statements, the Company considers all highly liquid debt
instruments purchased with a maturity of three months or less to be cash
equivalents. These investments are carried at cost, which approximates market.
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
3
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
- The condensed consolidated financial statements included herein have been
prepared by OGE Energy Corp. (the “Company”), without audit,
pursuant to the rules and regulations of the Securities and Exchange
Commission. Certain information and footnote disclosures normally included
in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such rules
and regulations; however, the Company believes that the disclosures are
adequate to make the information presented not misleading.
In the opinion of management, all adjustments necessary to present fairly the financial position of the Company and its subsidiaries as of March 31, 2001, and December 31, 2000, and the results of operations and the changes in cash flows for the periods ended March 31, 2001, and March 31, 2000, have been included and are of a normal recurring nature. Certain amounts have been reclassified on the financial statements to conform with the 2001 presentation.
The results of operations for such interim periods are not necessarily indicative of the results for the full year. It is suggested that these condensed consolidated financial statements be read in conjunction with the consolidated financial statements and the notes thereto included in the Company’s Form 10-K for the year ended December 31, 2000.
- The Company is a holding company, which was incorporated in August 1995 in
the State of Oklahoma. The Company is not engaged in any business
independent of that conducted through its two primary subsidiaries,
Oklahoma Gas and Electric Company ("OG&E") and Enogex Inc. ("Enogex").
OG&E is a regulated public utility that owns and operates an interconnected electric production, transmission and distribution system.
Enogex is an Oklahoma intrastate natural gas pipeline company that also conducts related operations, through its subsidiaries, in interstate and intrastate gas transmission, natural gas gathering, natural gas processing, natural gas and electricity marketing, and oil and gas development and production.
- Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS Nos. 137 and 138. SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Change in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the income statement. Changes in fair value of effective cash flow hedges are recorded as a component of Accumulated Other Comprehensive Income, which is later transferred to earnings when the hedged transaction occurs. Physical delivery contracts which cannot be net cash settled are deemed to be normal sales and therefore are not accounted for as derivatives. However,
4
- In accordance with SFAS No. 130, Reporting Comprehensive Income, the
following are components of Other Comprehensive Income:
physical delivery contracts that have a price not clearly and closely associated with the asset sold are not a normal sale and must be accounted for as a non-hedge derivative.
The Company accounted for adoption of SFAS No. 133 on January 1, 2001, by recording a cumulative effect transition adjustment debit to Accumulated Other Comprehensive Income of approximately $16.5 million.
The Company recorded a derivative fair value loss, related to the ineffective portion of hedge derivatives, of $2.9 million during the three months ended March 31, 2001.
As of March 31, 2001, an unrealized derivative fair value loss of $2.1 million, related to cash flow hedges of commodity risk associated with the value of future natural gas production for the remainder of 2001 was recorded in Accumulated Other Comprehensive Income. This loss is expected to be reclassified into earnings over the last three quarters of 2001, as the hedged natural gas production is sold.
Three Months Ended
March 31
2001 2000
---------- ----------
(dollars in thousands)
Net income (loss)...................................... $ (14,969) $ 776
---------- ----------
Other comprehensive income (loss), net of tax:
Transition adjustment................................ (16,492) ---
Change in derivative fair value...................... 15,733 ---
Reclassification adjustments - contract settlements.. (1,303) ---
---------- ----------
Total other comprehensive income (loss), net of tax.... (2,062) ---
---------- ----------
Total comprehensive income (loss)...................... $ (17,031) $ 776
========== ==========
- Enogex, in the normal course of business, enters into fixed price contracts for either the purchase or sale of natural gas and electricity at future dates. Due to fluctuations in the natural gas and electricity markets, the Company buys or sells natural gas and electricity futures contracts, swaps or options to hedge the price and basis risk associated with the specifically identified purchase or sales contracts. Additionally, the Company may use these contracts as an enhancement or speculative trade, subject to the Company’s policies on risk management. As market values change, the Company recognizes the gain or loss on enhancement or speculative contracts in the results of operations.
5
Item 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
OVERVIEW
The following discussion and analysis presents factors which affected the results of operations for the three months ended March 31, 2001 (the "current period"), and the financial position as of March 31, 2001, of the Company and its subsidiaries: OG&E and Enogex. Unless indicated otherwise, all comparisons are with the corresponding period of the prior year. For the three months ended March 31, 2001, approximately 69 percent of the Company's revenues consisted of the non-utility operations of Enogex, while the remaining 31 percent was provided by the regulated sales of electricity by OG&E, a public utility. The Company's earnings, however, have been predominantly from OG&E. Revenues from sales of electricity are somewhat seasonal, with a large portion of OG&E's annual electric revenues occurring during the summer months when the electricity needs of its customers increase. Actions of the regulatory commissions that set OG&E's electric rates will continue to affect the Company's financial results.
Some of the matters discussed in this Form 10-Q, including the discussion in "2001 Outlook", may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words "anticipate", "estimate", "objective", "possible", "potential" and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including their impact on capital expenditures; business conditions in the energy industry; competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company; unusual weather; state and federal legislative and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the Company's markets; and other risk factors listed in the Company's Form 10-K for the year ended December 31, 2000, including Exhibit 99.01 thereto and other factors described from time to time in the Company's reports to the Securities and Exchange Commission.
EARNINGS
The current period net loss of $14.9 million represents a decrease of $15.7 million. OG&E's earnings increased approximately $2.2 million while Enogex's earnings decreased approximately $17.6 million. A decrease of $0.3 million was attributable to increased expenses at the corporate level. As explained below, OG&E's increase in earnings was primarily attributable to increased revenues due to increased customer demand. Enogex's decrease in earnings was due in part to the depressed operating environment for the processing and sale of natural gas liquids due to lower fractionation spreads (the value of liquids after they are processed out of natural gas, compared to the price of the gas itself). Unprecedented high natural gas prices, without corresponding price increases in natural gas liquids resulted in negative
6
fractionation spreads in the current period. Other significant factors that reduced earnings at Enogex were higher fuel expenses in the natural gas gathering and transmission segment and reduced margins in energy marketing.
Also in the current period, Enogex continued to resolve the under-recovery of pipeline system fuel expenses, reported with fourth-quarter 2000 results. Enogex filed for fuel-recovery rate adjustments with the Federal Energy Regulatory Commission ("FERC") and the new rates became effective on March 1, 2001, subject to refund. The impact of this filing was minimal in the current period.
Loss per average common share was $0.19 in the current period compared to earnings per average common share of $0.01 in the prior period.
Reference is made to "Report of Business Segments" below for a detailed breakdown of OG&E's and Enogex's results of operations for the reported periods.
2001 OUTLOOK
The Company previously projected 2001 earnings at $2 to $2.10 per share. Due to narrower fractionation spreads in natural gas liquids and expectations that this trend will continue, the Company has revised its 2001 earnings estimate to $1.70 to $1.80 per share.
REVENUES
Total operating revenues increased $482 million or 82.9 percent. The increase was attributable to significantly increased revenues at both Enogex and OG&E. Enogex revenues increased $400.5 million or 119.1 percent primarily due to higher natural gas prices. Although revenues increased across all of Enogex's lines of business, the largest increase was recorded in the energy marketing business, where revenues increased $377.1 million in the current period. As explained above, the increase in revenue from natural gas liquids was more than offset by increases in prices in natural gas used to produce the liquids, which resulted in negative fractionation spreads and contributed to the loss for the current period.
OG&E's revenues increased $81.5 million or 33.2 percent primarily due to the recovery of higher fuel costs and increased customer demand. OG&E recovered higher fuel costs due to variances in the actual cost of fuel used in electric generation and certain purchased power costs, as compared to that component in the cost-of-service for ratemaking, which are passed through to OG&E's customers through automatic fuel adjustment clauses. The automatic fuel adjustment clauses are subject to periodic review by the Oklahoma Corporation Commission ("OCC"), the Arkansas Public Service Commission ("APSC") and the Federal Energy Regulatory Commission ("FERC"). See "Regulation and Rates". Partially offsetting the increased revenues under the fuel adjustment clauses, modifications to the Generation Efficiency Performance Rider ("GEP Rider") and lower recoveries under the Acquisition Premium Credit Rider ("APC Rider") unfavorably affected revenue by approximately $1.4 million and $2.9 million, respectively, in the current period. See "Regulation and Rates" - "Recent Regulatory Matters" for a related discussion. Kilowatt-hour sales to OG&E customers ("system sales") increased 1.3 percent in the current period due to favorable weather. Kilowatt-hour sales to other utilities and power marketers ("off-
7
system sales") decreased 15.9 percent; however, off-system sales are generally at lower prices per kilowatt-hour and have less impact on operating revenues and earnings than system sales.
EXPENSES
Cost of goods sold, which consists of fuel expense for electric generation, purchased power, gas and electricity purchased for resale and natural gas purchases - other, increased $496.9 million or 124.2 percent in the current period. The specific components of cost of goods sold for the reported periods are as follows:
Three Months Ended
March 31
2001 2000
---------- ----------
(dollars in thousands)
Fuel....................................... $ 117,883 $ 62,000
Purchased power............................ 76,969 60,542
Gas and electricity purchased for resale... 651,529 249,541
Natural gas purchases - other.............. 50,542 27,923
---------- ----------
Total cost of goods sold................. $ 896,923 $ 400,006
========== ==========
Enogex's natural gas and electricity purchased for resale increased $402.0 million or 161.1 percent in the current period due to increased volume and prices of natural gas purchased for resale to third parties.
Enogex's natural gas purchases - other, which consists primarily of natural gas processing shrinkage, pipeline system fuel expenses and pipeline compressor fuel, increased $22.6 million or 81.0 percent in the current period due to the increased price of natural gas and the increases in pipeline system fuel volume. As indicated above, Enogex filed with FERC to increase its fuel recoveries. The impact of this filing was minimal during the current period.
The higher cost of goods sold at Enogex more than offset the increase in Enogex's revenues for the current period.
OG&E increased its purchased power by $16.4 million or 27.1 percent in the current period primarily due to the availability of wholesale electricity at favorable prices. Kilowatt hours of energy purchased increased 40.9 percent, but the cost of purchased energy per kwh decreased 9.0 percent in the current period resulting in the 27.1 percent overall increase in purchased power costs.
OG&E's fuel expense increased $55.9 million or 90.1 percent in the current period primarily due to a significant increase in the average cost of fuel (particularly natural gas).
Other operation and maintenance increased $9.7 million or 11.0 percent, primarily due to increased bad debt expense ($4.3 million), employee labor and benefit costs ($2.5 million), contract labor ($1.0 million) and miscellaneous corporate expenses ($1.9 million).
8
The increases in these expenses reduced operating income by $25.6 million or 79.5 percent in the current period.
Interest charges decreased $0.9 million or 2.4 percent in the current period primarily due to a decrease in short-term debt.
LIQUIDITY AND CAPITAL REQUIREMENTS
The Company's primary needs for capital are related to construction of new facilities to meet anticipated demand for OG&E's utility service, to replace or expand existing facilities in OG&E's electric utility business, to replace or expand existing facilities in its non-utility businesses, to acquire new non-utility facilities or businesses and to some extent, for satisfying maturing debt. The Company's capital expenditures for the current period of $59.5 million were financed with internally generated funds and short-term borrowings.
The Company meets its cash needs through a combination of internally generated funds, short-term borrowings and permanent financing. The Company expects that internally generated funds will be adequate during 2001 to meet anticipated construction expenditures and maturities of long-term debt. Short-term borrowings will continue to be used to meet temporary cash requirements. The Company has in place a line of credit for up to $300 million, with $200 million to expire on January 15, 2002, and the remaining $100 million to expire on January 15, 2004.
The Company's capital structure and cash flow remained strong throughout the current period. The Company's combined cash and cash equivalents decreased approximately $122,000 during the three months ended March 31, 2001. The decrease reflects the Company's cash flow from operations, net of cash used in investing activities, retirement of long-term debt, payments of short-term debt, capital lease and cash dividends.
On January 10, 2001, Enogex retired $5.0 million of 7.750 percent senior notes due April 24, 2023. This debt had been assumed as part of the Tejas Transok Holding, L.L.C. acquisition in 1999.
Like any business, the Company is subject to numerous contingencies, many of which are beyond its control. For a discussion of significant contingencies that could affect the Company, reference is made to Part II, Item 1 - "Legal Proceedings" of this Form 10-Q and to "Management's Discussion and Analysis" and Notes 10 and 11 of Notes to the Consolidated Financial Statements in the Company's 2000 Form 10-K.
9
MARKET RISK
RISK MANAGEMENT
The risk management process established by the Company is designed to measure both quantitative and qualitative risks in its businesses. A senior risk management committee has been established to review these risks on a regular basis. The Company is exposed to market risk, including changes in certain commodity prices and interest rates.
To manage the volatility relating to these exposures, the Company enters into various derivative transactions pursuant to the Company's policies on hedging practices. Derivative positions are monitored using techniques such as mark-to-market valuation, value-at-risk and sensitivity analysis.
INTEREST RATE RISK
The Company's exposure to changes in interest rates relates primarily to long-term debt obligations and commercial paper. The Company manages its interest rate exposure by limiting its variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. The Company may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
During March 2001, the Company entered into two separate interest rate swap agreements; (i) OG&E entered into an interest rate swap agreement to convert $110 million of 7.30 percent fixed rate debt, due October 15, 2025, to a variable rate based on the three month London InterBank Offering Rate ("LIBOR") and (ii) effective July 15, 2001, Enogex entered into an interest rate swap agreement to convert $200 million of 8.125 percent fixed rate debt due, January 15, 2010, to a variable rate based on LIBOR. Subsequently, on April 6, 2001, the Company entered into a one-year interest rate swap agreement to convert $140 million of variable rate short-term debt, to a fixed rate of 4.41 percent effective April 10, 2001.
The fair value of long-term debt is estimated based on quoted market prices and management's estimate of current rates available for similar issues. The following table itemizes the Company's long-term debt maturities and the weighted-average interest rates by maturity date.
=========================================================================================================
Fair Value
(dollars in millions) 2001 2002 2003 2004 2005 Thereafter Total at 3-31-01
- ---------------------------------------------------------------------------------------------------------
Fixed rate debt:
Principal amount....... $ 2.0 $ 115.0 $ 14.3 $ 57.8 $ 152.9 $ 1,170.9 $ 1,512.9 $ 1,563.6
Weighted-average
interest rate........ 7.15% 7.34% 7.70% 7.20% 7.09% 7.57% 7.34% ---
Variable-rate debt:
Principal amount....... --- --- --- --- --- $ 135.4 $ 135.4 $ 135.4
Weighted-average
interest rate........ --- --- --- --- --- 4.25% 4.25% ---
=========================================================================================================
10
COMMODITY PRICE EXPOSURE
The market risk inherent in the Company's market risk sensitive instruments and positions are the potential loss in value arising from adverse changes in the Company's commodity prices.
The prices of natural gas, natural gas liquids and electricity are subject to fluctuations resulting from changes in supply and demand. To partially reduce price risk caused by these market fluctuations, the Company may hedge (through the utilization of derivatives) a portion of the Company's supply and related purchase and sale contracts, as well as any anticipated transactions (purchases and sales). Because the commodities covered by these derivatives are substantially the same commodities that the Company buys and sells in the physical market, no special studies other than monitoring the degree of correlation between the derivative and cash markets are deemed necessary.
A sensitivity analysis has been prepared to estimate the price exposure to the market risk of the Company's natural gas, natural gas liquids and electricity commodity positions. The Company's daily net commodity position consists of natural gas inventories, purchased electric capacity, commodity purchase and sales contracts, and derivative financial and commodity instruments. The fair value of such position is a summation of the fair values calculated for each commodity by valuing each net position at quoted market prices. Market risk is estimated as the potential loss in fair value resulting from a hypothetical 10 percent adverse change in such prices over the next 12 months. The results of this analysis, which may differ from actual results, are as follows at March 31, 2001:
Wholesale Non-Trading
=======================================================================
Commodity market risk, net........ $ 656,000 $ 0
=======================================================================
ACCOUNTING CHANGES
The adoption of SFAS No. 133 on January 1, 2001 resulted in a cumulative effect transition adjustment debit to Accumulated Other Comprehensive Income of approximately $26.9 million. For further discussion regarding the adoption of SFAS No. 133, see Note 3 of Notes to Consolidated Financial Statements.
REGULATION AND RATES
OG&E's retail electric tariffs in Oklahoma are regulated by the OCC, and in Arkansas by the APSC. 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.
11
Recent Regulatory Matters
On January 12, 2000, the OCC Staff (the "Staff") filed three applications to address various aspects of OG&E's electric rates. The first application related to the completion on March 1, 2000, of the recovery of the amortization premium paid by OG&E when it acquired Enogex in 1986 and the resulting removal, pursuant to the Acquisition Premium Credit Rider ("APC Rider"), of $12.8 million ($10.7 million in the Oklahoma Jurisdiction) from the amount being recovered by OG&E from its customers through currently authorized electric rates. OG&E consented to this action and in March 2000, the OCC approved the APC Rider for $10.7 million annually.
The second application related to a review of the Generation Efficiency Performance Rider ("GEP Rider"), which, as part of the OCC's order issued in 1997 in connection with OG&E's last general rate review (the "1997 Order"), was scheduled for review in March 2000. OG&E collected approximately $9.9 million pursuant to the GEP Rider during 2000. The GEP Rider initially was designed so that when OG&E's average annual cost of fuel per kwh was less than 96.261 percent of the average non-nuclear fuel cost per kwh of certain other investor-owned utilities in the region, OG&E was allowed to collect, through the GEP Rider, one-third of the amount by which OG&E's average annual cost of fuel was below 96.261 percent of the average of the other specified utilities. If OG&E's fuel cost exceeded 103.739 percent of the stated average, OG&E was not allowed to recover one-third of the fuel costs above that average from Oklahoma customers. In April 2000 testimony, the Staff stated that they continued to support incentive programs that reward superior performance, but in their view the existing GEP Rider was not functioning as they had originally envisioned it.
In June 2000, the OCC approved the collection of $6.6 million through the GEP Rider for the time period July 1, 2000 through June 30, 2001 and approved the following four modifications to the GEP Rider: (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 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. The GEP Rider is to terminate in June 2002. However, the OCC may establish a similar reward mechanism in a subsequent action upon proper showing.
The final application, relating to fuel cost recoveries, was used by the Staff to address the competitive bid process of OG&E's gas transportation needs following which Enogex contracted to provide gas transportation service to all OG&E generating plants. For a discussion of the background of the competitive bid process, see Note 11 of Notes to Consolidated Financial Statements in the Company's 2000 Form 10-K.
In July 2000, OG&E entered into a stipulation (the "Stipulation") with the Staff, the Office of the Attorney General and a coalition of industrial customers regarding the competitive bid process of OG&E's gas transportation service. The Stipulation (which, with one exception, was signed by all parties to the proceeding) would permit OG&E to recover $25.2 million annually for gas transportation services to be provided by Enogex pursuant to the competitive bid
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process. The Stipulation was presented for approval to an Administrative Law Judge ("ALJ") in September 2000, and the ALJ recommended its approval. However, at a hearing on September 28, 2000, the OCC chose to delay the decision concerning the Stipulation and two of the three commissioners expressed concern over the competitive bid process. OG&E cannot predict what further action the OCC may take. OG&E continues to believe that the competitive bid process was appropriate and is currently collecting $28.5 million on an annual basis through its base rates and APC Rider for gas transportation services from Enogex for the power plant requirements covered by the competitive bid.
State Restructuring Initiatives
Oklahoma: As previously reported, Oklahoma enacted in April 1997 the Electric Restructuring Act of 1997 (the "Act"), which is designed to provide for choice by retail customers of their electric supplier by July 1, 2002. Additional implementing legislation needs to be adopted by the Oklahoma Legislature to address many specific issues associated with the 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. The Company cannot predict what, if any, legislation will be adopted during the current legislative session, which ends May 25, 2001. The Company is participating actively in the legislative process and, at a minimum, expects the scheduled start date for customer choice of July 1, 2002 to be postponed.
Arkansas: In April 1999, Arkansas became the 18th state to pass a law ("the Restructuring Law") calling for restructuring of the electric utility industry at the retail level. The Restructuring Law, like the Oklahoma law, would significantly affect OG&E's future operations. OG&E's electric service area includes parts of western Arkansas, including Fort Smith, the second-largest metropolitan market in the state. The Restructuring Law initially targeted customer choice of electricity providers by January 1, 2002. In February 2001, the law was amended to delay the start date of customer choice of electric providers in Arkansas until October 1, 2003, with the APSC having discretion to further delay implementation to October 1, 2005. The Restructuring Law also provides that utilities owning or controlling transmission assets must transfer control of such transmission assets to an independent system operator, independent transmission company or regional transmission group, if any such organization has been approved by the FERC. Other provisions of the Restructuring Law permit municipal electric systems to opt in or out, permit recovery of stranded costs and transition costs and require filing of unbundled rates for generation, transmission, distribution and customer service. OG&E filed preliminary business separation plans with the APSC on August 8, 2000. The APSC has established a timetable to establish rules implementing the Arkansas restructuring statutes.
National Energy Legislation
The Bush Administration is currently considering proposing National Energy Legislation, which among other things may reform or repeal the Public Utility Holding Company Act of 1935. At this time we cannot predict whether or in what form this legislation may take place. Except as set forth above, there are no changes in the discussion of National Energy Legislation as contained in the Company's 2000 Form 10-K.
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REPORT OF BUSINESS SEGMENTS
The Company's electric utility operations are conducted through OG&E, an operating public utility engaged in the generation, transmission, distribution and sale of electric energy. The non-utility operations are conducted through Enogex. Enogex is engaged in gathering and processing natural gas, producing natural gas liquids, transporting natural gas through its pipelines in Oklahoma and Arkansas for various customers (including OG&E), marketing electricity, natural gas and natural gas liquids and investing in the drilling for and production of crude oil and natural gas. The following is the Company's business segment results.
========================================================================================================
Three Months Ended Electric
March 31, 2001 Utility Non-utility Intersegment Total
- --------------------------------------------------------------------------------------------------------
(dollars in thousands)
Operating revenues................... $ 326,835 $ 750,537 $ (13,785) (A) $ 1,063,587
Fuel................................. 126,962 --- (9,079) 117,883
Purchased power...................... 76,969 --- --- 76,969
Gas and electricity purchased
for resale......................... --- 656,235 (4,706) 651,529
Natural gas purchases - other........ --- 50,542 --- 50,542
- --------------------------------------------------------------------------------------------------------
Cost of goods sold................... 203,931 706,777 (13,785) 896,923
- --------------------------------------------------------------------------------------------------------
Gross margin on sales................ 122,904 43,760 --- 166,664
- --------------------------------------------------------------------------------------------------------
Other operation and maintenance...... 71,721 26,369 --- 98,090
Depreciation and amortization........ 30,296 15,028 --- 45,324
Taxes other than income.............. 11,685 4,965 --- 16,650
- --------------------------------------------------------------------------------------------------------
Operating income (expenses).......... 9,202 (2,602) --- 6,600
- --------------------------------------------------------------------------------------------------------
Other income (expenses).............. (791) 541 --- (250)
- --------------------------------------------------------------------------------------------------------
Earnings before interest and taxes... $ 8,411 $ (2,061) $ --- $ 6,350
Net loss............................. $ (997) $ (13,972) $ --- $ (14,969)
========================================================================================================
(A) Intersegment revenues are recorded at prices comparable to those of
unaffiliated customers and are affected by regulatory considerations.
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========================================================================================================
Three Months Ended Electric
March 31, 2000 Utility Non-utility Intersegment Total
- --------------------------------------------------------------------------------------------------------
(dollars in thousands)
Operating revenues................... $ 245,332 $ 365,114 $ (28,865) (A) $ 581,581
Fuel................................. 72,249 --- (10,249) 62,000
Purchased power...................... 60,542 --- --- 60,542
Gas and electricity purchased
for resale......................... --- 268,157 (18,616) 249,541
Natural gas purchases - other........ --- 27,923 --- 27,923
- --------------------------------------------------------------------------------------------------------
Cost of goods sold................... 132,791 296,080 (28,865) 400,006
- --------------------------------------------------------------------------------------------------------
Gross margin on sales................ 112,541 69,034 --- 181,575
- --------------------------------------------------------------------------------------------------------
Other operation and maintenance...... 65,253 23,099 --- 88,352
Depreciation and amortization........ 30,151 14,768 --- 44,919
Taxes other than income.............. 11,369 4,739 --- 16,108
- --------------------------------------------------------------------------------------------------------
Operating income..................... 5,768 26,428 --- 32,196
- --------------------------------------------------------------------------------------------------------
Other income (expenses).............. (634) 433 --- (201)
- --------------------------------------------------------------------------------------------------------
Earnings before interest and taxes... $ 5,134 $ 26,861 $ --- $ 31,995
Net income (loss).................... $ (3,226) $ 4,002 $ --- $ 776
========================================================================================================
(A) Intersegment revenues are recorded at prices comparable to those of
unaffiliated customers and are affected by regulatory considerations.
Item 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT
MARKET RISK
See Item 2, "Management Discussion and Analysis of Financial Condition and Results of Operations - Market Risk".
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PART II. OTHER INFORMATION
Item 1 LEGAL PROCEEDINGS
Reference is made to Item 3 of the Company's 2000 Form 10-K for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Company or its subsidiaries and there have been no notable changes in the previously reported proceedings, except as set forth below:
As reported in the Company's Form 10-K for the year ended December 31, 2000, Trigen-Oklahoma City Energy Corporation ("Trigen") sued OG&E in the United States District Court, Western District of Oklahoma, Case No. CIV-96-1595-M. On April 3, 2001 the U.S. Court of Appeals for the Tenth Circuit issued an order reversing the trial court's judgment in favor of Trigen and remanding the case to the U.S. District Court with orders to dismiss the case in its entirety. Trigen's request for rehearing before the Tenth Circuit was denied. In light of the amounts involved, Trigen may seek review by the U.S. Supreme Court.
Item 6 EXHIBITS AND REPORTS ON FORM 8-K
(a)
Exhibits
None
(b)
Reports on Form 8-K
None
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
OGE ENERGY CORP.
(Registrant)
By /s/ Donald R. Rowlett
Donald R. Rowlett
Vice President and Controller
(On behalf of the registrant and in
his capacity as Chief Accounting Officer)
May 15, 2001
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