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 September 30, 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 77,923,603 Shares of Common Stock, par value $0.01 per share, outstanding as of October 31, 2001.
Page
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Income:
Three and Nine Months Ended September 30, 2001
2
Consolidated Balance Sheet
3
Consolidated Statements of Cash Flows
4
Notes to Consolidated Financial Statements
5
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
8
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
21
Item 6. Exhibits and Reports on Form 8-K
21
Signature
22
1
OGE Energy Corp.
PART I. FINANCIAL INFORMATION
Item 1 FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
3 Months Ended
September 30
--------------------------------
2001 2000
-------------- --------------
(thousands except per share data)
OPERATING REVENUES......................................... $ 827,766 $ 1,007,966
COST OF GOODS SOLD......................................... 487,842 659,030
-------------- --------------
Gross margin on revenues................................. 339,924 348,936
Other operation and maintenance.......................... 91,237 83,181
Depreciation and amortization............................ 44,935 45,487
Taxes other than income.................................. 16,157 15,208
-------------- --------------
OPERATING INCOME........................................... 187,595 205,060
-------------- --------------
OTHER INCOME (EXPENSES), net............................... (277) (216)
-------------- --------------
EARNINGS BEFORE INTEREST AND TAXES......................... 187,318 204,844
INTEREST INCOME (EXPENSES):
Interest income.......................................... 741 1,039
Interest on long-term debt............................... (24,012) (25,354)
Interest on trust preferred securities................... (4,317) (4,317)
Allowance for borrowed funds used during construction.... 158 259
Other interest charges................................... (3,802) (3,876)
-------------- --------------
Net interest expenses.................................. (31,232) (32,249)
-------------- --------------
INCOME BEFORE TAXES........................................ 156,086 172,595
INCOME TAX EXPENSE......................................... 59,033 65,288
-------------- --------------
NET INCOME................................................. $ 97,053 $ 107,307
============== ==============
AVERAGE COMMON SHARES OUTSTANDING (thousands).............. 77,923 77,863
EARNINGS PER AVERAGE COMMON SHARE.......................... $ 1.25 $ 1.38
============== ==============
AVERAGE COMMON SHARES OUTSTANDING
ASSUMING DILUTION (thousands)............................ 77,824 77,863
EARNINGS PER AVERAGE COMMON SHARE
ASSUMING DILUTION (thousands)............................ $ 1.25 $ 1.38
============== ==============
DIVIDENDS DECLARED PER SHARE............................... $ 0.3325 $ 0.3325
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
9 Months Ended 6 Months Ended
September 30 June 30
--------------------------------
2001 2000
-------------- --------------
(thousands except per share data)
OPERATING REVENUES......................................... $ 2,639,244 $ 2,316,452
COST OF GOODS SOLD......................................... 1,908,271 1,562,784
-------------- --------------
Gross margin on revenues................................. 730,973 753,668
Other operation and maintenance.......................... 282,769 262,224
Depreciation and amortization............................ 135,181 135,403
Taxes other than income.................................. 49,067 47,039
-------------- --------------
OPERATING INCOME........................................... 263,956 309,002
-------------- --------------
OTHER INCOME (EXPENSES), net............................... (1,058) 4,438
-------------- --------------
EARNINGS BEFORE INTEREST AND TAXES......................... 262,898 313,440
INTEREST INCOME (EXPENSES):
Interest income.......................................... 3,068 3,244
Interest on long-term debt............................... (75,384) (76,658)
Interest on trust preferred securities................... (12,951) (12,951)
Allowance for borrowed funds used during construction.... 575 1,989
Other interest charges................................... (11,020) (13,021)
-------------- --------------
Net interest expenses.................................. (95,712) (97,397)
-------------- --------------
INCOME BEFORE TAXES........................................ 167,186 216,043
INCOME TAX EXPENSE......................................... 60,308 76,216
-------------- --------------
NET INCOME................................................. $ 106,878 $ 139,827
============== ==============
AVERAGE COMMON SHARES OUTSTANDING (thousands).............. 77,923 77,863
EARNINGS PER AVERAGE COMMON SHARE.......................... $ 1.37 $ 1.80
============== ==============
AVERAGE COMMON SHARES OUTSTANDING
ASSUMING DILUTION (thousands)............................ 77,845 77,863
EARNINGS PER AVERAGE COMMON SHARE
ASSUMING DILUTION........................................ $ 1.37 $ 1.80
============== ==============
DIVIDENDS DECLARED PER SHARE............................... $ 0.9975 $ 0.9975
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
2
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30 December 31
2001 2000
------------- --------------
(dollars in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 559 $ 454
Accounts receivable - customers, less reserve of $7,184 and
$4,135, respectively........................................ 277,381 446,185
Accrued unbilled revenues..................................... 51,300 49,000
Accounts receivable - other, less reserve of $874 and
$2,545, respectively........................................ 18,684 24,713
Fuel inventories.............................................. 78,257 200,316
Materials and supplies, at average cost....................... 39,618 41,517
Prepayments and other......................................... 7,984 45,715
Price risk management......................................... 25,696 45,727
Accumulated deferred tax assets............................... 10,435 10,669
------------- --------------
Total current assets........................................ 509,914 864,296
------------- --------------
OTHER PROPERTY AND INVESTMENTS, at cost......................... 40,058 36,980
------------- --------------
PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... 5,447,653 5,323,541
Construction work in progress................................. 77,143 47,016
------------- --------------
Total property, plant and equipment......................... 5,524,796 5,370,557
Less accumulated depreciation............................. 2,258,084 2,151,093
------------- --------------
Net property, plant and equipment........................... 3,266,712 3,219,464
------------- --------------
DEFERRED CHARGES:
Advance payments for gas...................................... 12,500 12,500
Income taxes recoverable through future rates................. 37,875 38,654
Price risk management......................................... 21,848 5,668
Other......................................................... 96,648 142,068
------------- --------------
Total deferred charges...................................... 168,871 198,890
------------- --------------
TOTAL ASSETS.................................................... $ 3,985,555 $ 4,319,630
============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt............................................... $ 125,512 $ 284,500
Accounts payable.............................................. 132,844 330,445
Dividends payable............................................. 25,910 25,890
Customers' deposits........................................... 27,017 22,647
Accrued taxes................................................. 78,772 33,067
Accrued interest.............................................. 30,545 40,699
Long-term debt due within one year............................ 115,000 2,000
Price risk management......................................... 12,897 33,709
Other......................................................... 44,342 36,975
------------- --------------
Total current liabilities................................... 592,839 809,932
------------- --------------
LONG-TERM DEBT.................................................. 1,538,139 1,648,523
------------- --------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 6,271 14,256
Accumulated deferred income taxes............................. 641,240 618,360
Accumulated deferred investment tax credits................... 53,566 57,429
Price risk management......................................... 3,080 3,001
Other......................................................... 58,142 103,821
------------- --------------
Total deferred credits and other liabilities................ 762,299 796,867
------------- --------------
STOCKHOLDERS' EQUITY:
Common stockholders' equity................................... 443,202 443,298
Retained earnings............................................. 650,140 621,010
Accumulated other comprehensive income........................ (1,064) -
------------- --------------
Total stockholders' equity.................................. 1,092,278 1,064,308
------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 3,985,555 $ 4,319,630
============= ==============
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
3
CONSOLIDATED STATEMENTS OF
CASH FLOWS
(Unaudited)
9 Months Ended
September 30
2001 2000
-------------- --------------
(dollars in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income......................................................... $ 106,878 $ 139,827
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and amortization.................................... 135,181 135,403
Deferred income taxes and investment tax credits, net............ 21,126 37,086
Gain on sale of assets........................................... (293) (4,850)
Change in Certain Assets and Liabilities:
Accounts receivable - customers................................ 168,804 (103,069)
Accrued unbilled revenues...................................... (2,300) (15,400)
Fuel, materials and supplies inventories....................... 123,958 (40,296)
Other current assets........................................... 44,437 (28,436)
Accounts payable............................................... (197,601) 99,370
Accrued taxes.................................................. 45,705 43,497
Accrued interest............................................... (10,154) 501
Other current liabilities...................................... 11,757 6,118
Other operating activities....................................... (20,705) 3,729
-------------- --------------
Net cash provided from operating activities.................. 426,793 273,480
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (182,177) (137,866)
Proceeds from sale of assets....................................... 1,263 15,859
Other investing activities......................................... 277 402
-------------- --------------
Net cash used in investing activities........................ (180,637) (121,605)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt....................................... (10,390) (58,000)
Proceeds from long-term debt....................................... - 400,000
Decrease in short-term debt, net................................... (158,988) (419,000)
Retirement of common stock......................................... (96) -
Contribution from minority interest................................ 1,449 -
Payment of obligation under capital lease.......................... (279) -
Cash dividends declared on common stock............................ (77,747) (77,667)
-------------- --------------
Net cash used in financing activities........................ (246,051) (154,667)
-------------- --------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. 105 (2,792)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 454 7,271
-------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 559 $ 4,479
============== ==============
- ---------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)............................. $ 95,562 $ 88,441
Income taxes..................................................... $ 5,991 $ 7,680
- ---------------------------------------------------------------------------------------------------------
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Interest rate swap............................................... $ (12,848) $ -
Change in fair value of long-term debt........................... $ 12,848 $ -
Other investing and financing activities......................... $ - $ 2,400
- ---------------------------------------------------------------------------------------------------------
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.
4
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 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 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 September 30, 2001, and December 31, 2000, and the results of operations and the changes in cash flows for the periods ended September 30, 2001, and September 30, 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.
- 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,
Enogex 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, Enogex
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
- 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. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the 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 are deemed to be normal purchases or normal sales are not accounted for as derivatives. However, 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 $26.9 million ($16.5 million net of tax). This unrealized loss is related to the derivative fair value of qualifying cash flow hedges as of the date of adoption and is being amortized to earnings as the related hedged transactions occur.
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. The objective of these interest rate swaps was to raise the percentage of total corporate floating rate debt more in line with industry standard and to achieve a lower cost of debt. These interest rate swaps qualified as fair value hedges under SFAS No. 133 and meet all requirements for a determination that there was no ineffective portion as allowed under the shortcut method under SFAS No. 133.
On April 6, 2001, the Company entered into a one-year interest rate swap agreement to lock in a fixed rate of 4.41 percent, effective April 10, 2001, on $140 million of variable rate short-term debt. The objective of this interest rate swap was to reduce exposure to short-term interest rate volatility associated with the Company’s commercial paper program. This interest rate swap initially qualified for hedge accounting treatment as a cash flow hedge under SFAS No. 133. However, due to unexpected changes in the level of commercial paper issued during the third quarter, hedge accounting treatment under SFAS No. 133 was discontinued as of July 1, 2001, and all subsequent changes in the market value of the swap are being recorded in earnings as required by SFAS No. 133. As of September 30, 2001, a total of approximately $930,000 has been recorded in earnings. This amount represents the change in the market value of the swap since July 1, 2001.
As of September 30, 2001, a deferred loss of approximately $325,000 ($198,000 net of tax), was recorded in Accumulated Other Comprehensive Income which represents the unamortized balance of the effective portion of the interest rate swap as of June 30, 2001. Approximately $161,000 of the unamortized balance was amortized in the third quarter, and6
will continue to be amortized over the remaining life of the original term of the swap, which was set to expire on April 10, 2002.
The Company recorded a gain, related to the ineffective portion of hedge derivatives, for production hedges, of $4.7 million ($2.9 million net of tax) for the nine months ended September 30, 2001.
As of September 30, 2001, a deferred loss of $1.3 million ($0.9 million net of tax), related to an effective cash flow hedge 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 quarter of 2001, as the hedged natural gas production is sold.
- In accordance with SFAS No. 130, Reporting Comprehensive Income, the following are components of Other Comprehensive Income:
9 Months Ended September 30 2001 2000 ----------------- ----------------- (dollars in thousands) Net income.............................................. $ 106,878 $ 139,827 ----------------- ----------------- Other comprehensive income (loss), net of tax: Transition adjustment................................. (16,492) - Gain on qualifying cash flow hedging instruments...... 15,987 - Reclassification adjustments - contract settlements... (559) - ----------------- ----------------- Total other comprehensive (loss), net of tax............ (1,064) - ----------------- ----------------- Total comprehensive income.............................. $ 105,814 $ 139,827 ================= =================- In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143 will affect the Company’s accrued plant removal costs for generation, transmission, distribution and oil and gas production facilities and will require that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement is incurred, the liability shall be recognized when a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Adoption of SFAS No. 143 is required for financial statements for periods beginning after June 15, 2002. The Company will adopt this new standard effective January 1, 2003. Management has not yet determined what the impact of this new standard will be on its consolidated financial position or results of operation.
- In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. SFAS No. 144 requires that an impairment loss be recognized only if the carrying amount of a long-lived asset is not recoverable from its undiscounted cash flows and that the measurement of any impairment loss be the difference
7
between the carrying amount and fair value of the asset. Adoption of SFAS No. 144 is required for financial statements for periods beginning after December 15, 2001. The Company will adopt this new standard effective January 1, 2002, and management believes the adoption of this new standard will not have a material impact on its consolidated financial position or results of operation. - 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. Changes in the fair value of derivatives that are not designated as hedges, as well as the ineffective portion of hedge derivatives, must be recognized as a derivative fair value gain or loss in the 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 are deemed to be normal purchases or normal sales are not accounted for as derivatives. However, 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.
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 and nine months ended September 30, 2001 (respectively, the "current periods"), and the financial position as of September 30, 2001, of the Company and its subsidiaries: OG&E and Enogex. Unless indicated otherwise, all comparisons are with the corresponding periods of the prior year. The table below shows the earnings contributions of OG&E and Enogex for the period indicated. All references to earnings per share are to earnings per share of the Company's Common Stock.
3 Months Ended 9 Months Ended
September 30 September 30
-------------------------- ---------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
(dollars in thousands)
OG&E................................. $ 1.29 $ 1.38 $ 1.63 $ 1.72
Enogex............................... - 0.06 (0.13) 0.23
Holding company (stand-alone basis).. (0.04) (0.06) (0.13) (0.15)
------------ ------------ ------------ ------------
Consolidated Earnings per Share.... $ 1.25 $ 1.38 $ 1.37 $ 1.80
============ ============ ============ ============
The decrease in OG&E's contribution to earnings per share in the current period was primarily attributable to milder weather and increased operation and maintenance expenses. Of the $0.06 and $0.36 decreases in Enogex's contribution to earnings per share for the current periods, approximately $0.10 and $0.46 were attributable to poorer margins in Enogex's gas processing business. The last component of earnings per share are the results on a stand-alone basis of the Company (i.e., a holding company) which has expenses but no revenues, and which posted a loss of $0.04 and $0.13 for the current periods, which reflects an increase of $0.02 each period as compared to results in 2000.
For the current three and nine months periods, approximately 39 percent and 55 percent of the Company's revenues consisted of the non-utility operations of Enogex, while the remaining 61 percent and 45 percent was provided by the regulated sales of electricity by OG&E, a public utility. Revenues from sales of electricity are somewhat seasonal, with a large portion of
8
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. In September 2001, the director of the Oklahoma Corporation Commission's ("OCC") public utility division filed an application with the OCC to review the rates of OG&E. See "Regulation and Rates - Recent Regulatory Matters" for a further discussion of this matter. Deregulation of the electric industry in Oklahoma has been postponed until at least 2003. See "Regulation and Rates - Recent Regulatory Matters" for a related discussion.
Some of the matters discussed in this Form 10-Q, including the discussion in "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
Net income decreased $10.3 million or 9.6 percent in the three months ended September 30, 2001. Of the $10.3 million decrease, approximately $7.2 million was attributable to OG&E and $4.6 million was attributable to Enogex. These decreases were partially offset by decreased losses of approximately $1.5 million at the holding company. OG&E's decrease in earnings for the three months ended September 30, 2001, was primarily attributable to milder weather and increased operation and maintenance expenses. The decrease in earnings at Enogex for the three months ended September 30, 2001, was primarily attributable to poorer margins in the gas processing business, a loss in the energy marketing and trading business and to a one-time cost adjustment stemming from the 1999 Transok acquisition. The decreased losses at the holding company resulted from decreased other operation and maintenance costs.
For the nine months ended September 30, 2001, net income decreased $32.9 million or 23.6 percent. Of the $32.9 million decrease, approximately $27.7 million was attributable to Enogex. The decline in earnings at Enogex was attributable primarily to poor fractionation spreads. Fractionation spreads are the value of liquids after they are processed out of natural gas, compared to the price of the gas itself. During parts of the first quarter of 2001, these spreads were actually negative. Also, in the current periods and, particularly during the first quarter of 2001, 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
9
March 1, 2001, subject to refund. The impact of this filing was minimal during the first quarter of 2001, but enabled Enogex to significantly improve recovery of pipeline system fuel expenses during the second quarter. Enogex earnings also were adversely affected by lower margins in its energy marketing and trading business compared to the prior period. Earnings at OG&E decreased $6.5 million in the nine months ended September 30, 2001, primarily due to milder weather and increased operation and maintenance expenses.
OUTLOOK
The Company has revised its previously projected 2001 earnings to $1.45 to $1.50 a share from $1.70 to $1.80, based on nine-month actual results and expectations for the fourth quarter.
The Company currently expects 2002 earnings to fall within a range of $1.80 to $2.00 per share. Achievement of these earnings goals assumes, among other things, normal weather at the utility, an expected return to a more stable price environment in natural gas processing, the addition of new natural gas transportation contracts at Enogex and lower interest expenses.
REVENUES
Total operating revenues decreased $180.2 million or 17.9 percent in the three months ended September 30, 2001 and increased $322.8 or 13.9 percent in the nine months ended September 30, 2001.
OG&E's revenues decreased $20.9 million or 3.9 percent in the three months ended September 30, 2001, and increased $84.6 million or 7.6 percent in the nine months ended September 30, 2001. The decrease in the three months ended September 30, 2001, was primarily attributable to milder weather (approximately a 6.6 percent decrease in the cooling degree days as compared to the same period in 2000), resulting in a 1.2 percent decrease in electricity sales to Company customers ("system sales"), and a 2.9 percent decrease in electricity sales to other utilities and power marketers ("off-system sales").
The increase in OG&E's operating revenues for the nine months ended September 30, 2001, resulted primarily from the recovery of higher fuel costs. 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 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 OCC, the Arkansas Public Service Commission ("APSC") and the FERC. See "Regulation and Rates." Partially offsetting the increased recoveries under the fuel adjustment clauses in the nine months ended September 30, 2001, were decreased recoveries under the Generation Efficiency Performance Rider ("GEP Rider") of $3.4 million, the Acquisition Premium Credit Rider ("APC Rider") of $2.0 million, and the Gas Transportation Adjustment Credit Rider ("GTAC Rider") of $0.9 million. See "Regulation and Rates - Recent Regulatory Matters" for a related discussion. In the nine months ended September 30, 2001, system sales increased 0.2 percent and off-system sales increased 3.5 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.
10
Enogex revenues, after eliminating intercompany transactions, decreased $159.3 million or 33.3 percent in the three months ended September 30, 2001. Approximately $151.9 million of the decrease was due to lower revenues from natural gas sales. The primary driver of this reduction was a 60.7 percent decline in the price recovered per MMBTU. Approximately $13.5 million of the decrease was attributable to the gas processing business, which experienced a 4.6 percent decrease in the volume of natural gas liquids sold and a 10.9 percent decrease in liquids prices. Partially offsetting these decreases were revenues from gathering and transmitting natural gas which increased $6.5 million or 28.8 percent.
Enogex revenues, after eliminating intercompany transactions, increased $238.2 million or 19.7 percent in the nine months ended September 30, 2001. This increase was primarily attributable to increased natural gas sales of approximately $238.9 million. Revenues from power marketing activities increased approximately $17.3 million or 49.3 percent resulting from a 58.4 percent increase in the number of megawatt hours sold. Revenues for gathering and transmission of natural gas increased $14.7 million or 22.7 percent. This increase was primarily driven by increased volume transported. Gas storage services contributed approximately $2.7 million to the increase in revenues. These revenues resulted from marketing, on a fee basis, a portion of Enogex's storage capacity to its partners in 2001.
Offsetting these increases was a $35.8 million decrease in natural gas liquid sales. This decrease was primarily due to a 13.6 percent decrease in volumes sold.
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, decreased $177.5 million or 26.7 percent in the three months ended September 30, 2001 and increased $339.2 million or 21.6 percent in the nine months ended September 30, 2001. The specific components of cost of goods sold for the reported periods are as follows:
3 Months Ended 9 Months Ended
September 30 September 30
-------------------------- ---------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
(dollars in thousands)
Fuel....................................... $ 145,993 $ 161,713 $ 374,230 $ 321,643
Purchased Power............................ 70,595 68,644 218,000 191,309
Gas and electricity purchased for resale... 244,407 363,377 1,187,008 928,447)
Natural gas purchases - other.............. 26,847 65,296 129,033 121,385
------------ ------------ ------------ ------------
Total cost of goods sold................. $ 487,842 $ 659,030 $ 1,908,271 $ 1,562,784
============ ============ ============ ============
OG&E's fuel expense decreased $15.7 million or 9.7 percent in the three months ended September 30, 2001, primarily due to decreased generation levels associated with milder weather. OG&E's fuel expense increased $52.6 million or 16.3 percent in the nine months ended September 30, 2001, primarily due to a significant increase in the average cost of fuel (particularly natural gas during the first quarter of 2001).
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OG&E increased its purchased power by $2.0 million or 2.8 percent and $26.7 million or 14.0 percent in the current periods. These increases were primarily due to an increase in capacity purchases under a wholesale purchase contract that OG&E maintains with Southwestern Public Service Corp. and the availability of wholesale electricity at favorable prices.
Enogex's natural gas and electricity purchased for resale decreased $119.0 million or 32.7 percent in the three months ended September 30, 2001, due primarily to a decrease in price of natural gas purchased for resale to third parties. For the nine months ended September 30, 2001, Enogex's natural gas and electricity purchased for resale increased $258.6 million or 27.8 percent due to an increase in the volumes of natural gas purchased for resale to third parties, primarily attributable to increased sales activity by Enogex's energy marketing business in the first quarter of 2001.
Enogex's natural gas purchases - other, which consists primarily of natural gas processing shrinkage and, to a lesser extent, pipeline system fuel expenses and pipeline compressor fuel expense, decreased $38.5 million or 58.9 percent in the three months ended September 30, 2001, primarily attributable to lower fuel expense. In the nine months ended September 30, 2001 Enogex's natural gas purchases - other increased $7.6 million or 6.3 percent due to the increased price of natural gas.
Other operation and maintenance increased $8.1 million or 9.7 percent and $20.5 million or 7.8 percent in the current periods primarily due to increased employee pension and benefit costs, outside services and increased bad debt expense.
Interest charges decreased $1.0 million or 3.2 percent in the three months ended September 30, 2001, primarily due to a decrease in long-term debt. In the nine months ended September 30, 2001, interest charges decreased $1.7 million or 1.7 percent primarily due to a decrease in short-term debt and lower interest rates.
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 meets its cash needs through a combination of internally generated funds, short-term borrowings and permanent financing.
For the nine months ended September 30, 2001, the Company satisfied its capital expenditures of $182.1 million through internally generated funds and short-term borrowings. The Company expects that internally generated funds will be adequate during the remainder of 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 lines of credit for up to $315 million, of which $200 million expires on January 15, 2002, $100 million expires on January 15, 2004, and $15 million expires on June 28, 2002. The Company expects to replace these lines of credit on or prior to the expiration.
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The Company's capital structure and cash flow remained strong throughout the current periods. The Company's combined cash and cash equivalents increased approximately $105,000 during the nine months ended September 30, 2001. The increase reflects the Company's cash flow from operations, net of cash used in investing activities, retirement of long-term debt and common stock, payments of short-term debt, capital lease and cash dividends. Variations in accounts receivable and fuel inventories reflect the seasonal nature of the Company's utility business.
Like any business, the Company is subject to numerous contingencies, many of which are beyond its control. For discussion of significant contingencies that could affect the Company, reference is made to Part II, Item 1 - "Legal Proceedings" of this Form 10-Q, to Part II, Item 1 - "Legal Proceedings" in the Company's Form 10-Q for the quarters ended March 31, 2001 and June 30, 2001, 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.
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 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. The objective of these interest rate swaps was to raise the percentage of total
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corporate floating rate debt more in line with industry standard and to achieve a lower cost of debt. These interest rate swaps qualified as fair value hedges under SFAS No. 133 and meet all requirements for a determination that there was no ineffective portion as allowed under the shortcut method under SFAS No. 133.
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 objective of this interest rate swap was to reduce exposure to short-term interest rate volatility associated with the Company's commercial paper program. This interest rate swap initially qualified for hedge accounting treatment as a cash flow hedge under SFAS No. 133. However, due to unexpected changes in the level of commercial paper issued during the third quarter, hedge accounting treatment under SFAS No. 133 was discontinued as of July 1, 2001, and all subsequent changes in the market value of the swap are being recorded through earnings as required by SFAS No. 133. As of September 30, 2001, a total of approximately $930,000 has been recorded in earnings. This amount represents the change in the market value of the swap since July 1, 2001.
As of September 30, 2001, a deferred loss of approximately $325,000 ($198,000 net of tax), was recorded in Accumulated Other Comprehensive Income which represents the unamortized balance of the effective portion of the interest rate swap as of June 30, 2001. Approximately $161,000 of the unamortized balance was amortized in the third quarter, and will continue to be amortized over the remaining life of the original term of the swap, which was set to expire on April 10, 2002.
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 9-30-01
- ---------------------------------------------------------------------------------------------------
Fixed rate debt:
Principal amount....... $ 1.0 $115.0 $ 14.3 $ 53.0 $153.0 $ 861.3 $1,197.6 $ 1,281.0
Weighted-average
interest rate........ 7.15% 7.34% 7.70% 7.22% 7.09% 7.48% 7.33% -
Variable-rate debt:
Principal amount....... - - - - - $ 458.2 $ 458.2 $ 458.2
Weighted-average
interest rate........ - - - - - 4.99% 4.99% -
===================================================================================================
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
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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 September 30, 2001:
Wholesale Non-Trading
- --------------------------------------------------------------------------------
Commodity market risk, net...... $78,957 $ 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 ($16.5 million net of tax). For further discussion regarding the adoption of SFAS No. 133, see Note 4 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.
Recent Regulatory Matters
As previously reported, the OCC Staff ("Staff") annually conducts a review ("Matrix Review") to assess utility operations. The purpose of the Matrix Review is to enable the Staff to specifically identify regulated utilities that have experienced material or significant changes in operating characteristics, or in the underlying cost of service, as a means of evaluating the need to pursue rate hearings. The Staff also uses the Matrix Review to identify regulated utilities that require a Staff review of some specific operational activity conducted by the utility. The Matrix Review is composed of 11 indicators that are the basic guide for the Staff's initial review of a regulated utility. The 11 indicators include such items as the time from a utility's last rate review
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and service quality complaints. Each indicator is given a rating by the Staff from zero to three. A rating of zero is considered not relevant, a rating of one is considered slightly relevant, a rating of two is considered moderately relevant, while a rating of three is considered significantly relevant. The Staff believes that an aggregate rating of less than ten and with no individual indicator receiving a rating of three, should indicate that no further assessment is required. Any rating above these levels could result in a Staff recommendation requesting that a further review should be performed. In July 2001, the OCC held a hearing at which the Staff reported the results of its Matrix Review of OG&E. The review resulted in an aggregate score of 17 for OG&E, with only one indicator "Time since last formal rate review", achieving a rating of three. OG&E's last formal rate review by the Staff occurred in 1995. As part of its written report, the Staff recommended that a general rate review be performed on OG&E.
In September 2001, the director of the OCC public utility division filed an application with the OCC to review the rates of OG&E. In the filing, the Staff requests that OG&E submit information in accordance with OCC standard filing requirements by January 28, 2002, for a test year ending September 30, 2001. At this time, management cannot predict the outcome of this rate review or the impact on its consolidated financial position or results of operation. Hearing's in this case are expected to commence in July 2002.
As previously reported, certain aspects of OG&E's electric rates recently have been addressed by the OCC. In March 2000, the OCC approved, and OG&E implemented, the APC Rider reflecting 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 is to remove $10.7 million annually from the amount being recovered by OG&E from its Oklahoma customers in current rates.
In June 2000, the OCC approved modifications to OG&E's GEP Rider. The GEP Rider was established initially in 1997 in connection with OG&E's last 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 was below a specified percentage (96.261%) 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%) of the average fuel costs of other investor-owned utilities. The modifications enacted in June 2000 had the effect of reducing the amount OG&E could recover under the GEP Rider, and for the period between July 1, 2001 and June 30, 2002, the Company estimates that it will recover $5.1 million under the GEP Rider. The GEP Rider is scheduled to expire in June 2002, however, the OCC could decide to establish a similar reward mechanism in a subsequent action upon proper showing. For a more detailed explanation of the GEP Rider see the Company's 2000 Form 10-K.
The final action addresses the competitive bid process of OG&E's gas transportation needs following which OG&E's affiliate, Enogex, contracted to provide gas transportation service to all of OG&E's generation plants. For a discussion of the background of the competitive bid process, see Note 11 of Notes to Financial Statements in the Company's 2000 Form 10-K.
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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 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.
In June 2001, the Staff approved the Stipulation declaring the Stipulation to be fair, just and reasonable and representing a reasonable settlement of the issues and thereby serving the public interest. OG&E had previously collected $28.5 million on an annual basis through its base rate and APC Rider for gas transportation services from Enogex for the power plant requirements covered by the competitive bid. The Stipulation permits OG&E to recover $25.2 million annually for the gas transportation services provided by Enogex. The Stipulation directs OG&E to reduce rates to its Oklahoma retail customers by approximately $2.7 million per year through the implementation of a GTAC Rider. The GTAC Rider is a credit for gas transportation cost recovery and is applicable to and becomes part of each Oklahoma retail rate schedule to which OG&E's Fuel Cost Adjustment rider applies. The GTAC Rider became effective with the first billing cycle of July 2001, and will remain in effect until amended by OG&E at the direction of the OCC.
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. In May 2001, the Oklahoma Legislature passed Senate Bill 440 ("SB 440"), which postponed the scheduled start date for customer choice of July 1, 2002 until at least 2003. In addition to postponing the date for customer choice, the SB 440 calls for a nine-member task force to further study the issues surrounding deregulation. The task force includes the Governor or his designee, the Attorney General, the Oklahoma Corporation Commission Chair and several legislative leaders, among others. The Company will continue to participate actively in the legislative process and expects to remain a competitive supplier of electricity. The Company cannot predict what, if any, legislation will be adopted at the next legislative session.
Arkansas: In April 1999, Arkansas 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, will 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
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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.
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 for the three and nine months ended September 30, 2001 and September 30, 2000.
========================================================================================================
Three Months Ended Electric
September 30, 2001 Utility Non-utility Intersegment Total
- --------------------------------------------------------------------------------------------------------
(dollars in thousands)
Operating revenues................... $ 508,142 $ 328,933 $ (9,309) (A) $ 827,766
Fuel................................. 155,072 - (9,079) 145,993
Purchased power...................... 70,595 - - 70,595
Gas and electricity purchased
for resale......................... - 244,637 (230) 244,407
Natural gas purchases - other........ - 26,847 - 26,847
- --------------------------------------------------------------------------------------------------------
Cost of goods sold................... 225,667 271,484 (9,309) 487,842
- --------------------------------------------------------------------------------------------------------
Gross margin on sales................ 282,475 57,449 - 339,924
- --------------------------------------------------------------------------------------------------------
Other operation and maintenance...... 69,480 21,757 - 91,237
Depreciation and amortization........ 29,251 15,684 - 44,935
Taxes other than income.............. 11,434 4,723 - 16,157
- --------------------------------------------------------------------------------------------------------
Operating income..................... 172,310 15,285 - 187,595
- --------------------------------------------------------------------------------------------------------
Other expenses....................... (260) (17) - (277)
- --------------------------------------------------------------------------------------------------------
Earnings before interest and taxes... $ 172,050 $ 15,268 $ - $ 187,318
Net income (loss).................... $ 100,117 $ (3,064) $ - $ 97,053
========================================================================================================
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========================================================================================================
Three Months Ended Electric
September 30, 2000 Utility Non-utility Intersegment Total
- --------------------------------------------------------------------------------------------------------
(dollars in thousands)
Operating revenues................... $ 528,993 $ 601,641 $ (122,668) (A) $ 1,007,966
Fuel................................. 170,793 - (9,080) 161,713
Purchased power...................... 68,644 - - 68,644
Gas and electricity purchased
for resale......................... - 476,965 (113,588) 363,377
Natural gas purchases - other........ - 65,296 - 65,296
- --------------------------------------------------------------------------------------------------------
Cost of goods sold................... 239,437 542,261 (122,668) 659,030
- --------------------------------------------------------------------------------------------------------
Gross margin on sales................ 289,556 59,380 - 348,936
- --------------------------------------------------------------------------------------------------------
Other operation and maintenance...... 62,587 20,594 - 83,181
Depreciation and amortization........ 30,841 14,646 - 45,487
Taxes other than income.............. 11,079 4,129 - 15,208
- --------------------------------------------------------------------------------------------------------
Operating income..................... 185,049 20,011 - 205,060
- --------------------------------------------------------------------------------------------------------
Other income expenses................ (14) (202) - (216)
- --------------------------------------------------------------------------------------------------------
Earnings before interest and taxes... $ 185,035 $ 19,809 $ - $ 204,844
Net income (loss).................... $ 107,327 $ (20) $ - $ 107,307
========================================================================================================
========================================================================================================
Nine Months Ended Electric
September 30, 2001 Utility Non-utility Intersegment Total
- --------------------------------------------------------------------------------------------------------
(dollars in thousands)
Operating revenues................... $ 1,194,458 $ 1,477,673 $ (32,887) (A) $ 2,639,244
Fuel................................. 401,469 - (27,239) 374,230
Purchased power...................... 218,000 - - 218,000
Gas and electricity purchased
for resale......................... - 1,192,656 (5,648) 1,187,008
Natural gas purchases - other........ - 129,033 - 129,033
- --------------------------------------------------------------------------------------------------------
Cost of goods sold................... 619,469 1,321,689 (32,887) 1,908,271
- --------------------------------------------------------------------------------------------------------
Gross margin on sales................ 574,989 155,984 - 730,973
- --------------------------------------------------------------------------------------------------------
Other operation and maintenance...... 212,978 69,791 - 282,769
Depreciation and amortization........ 89,774 45,407 - 135,181
Taxes other than income.............. 34,575 14,492 - 49,067
- --------------------------------------------------------------------------------------------------------
Operating income..................... 237,662 26,294 - 263,956
- --------------------------------------------------------------------------------------------------------
Other income (expenses).............. (1,551) 493 - (1,058)
- --------------------------------------------------------------------------------------------------------
Earnings before interest and taxes... $ 236,111 $ 26,787 $ - $ 262,898
Net income (loss).................... $ 127,145 $ (20,267) $ - $ 106,878
========================================================================================================
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========================================================================================================
Nine Months Ended Electric
September 30, 2000 Utility Non-utility Intersegment Total
- --------------------------------------------------------------------------------------------------------
(dollars in thousands)
Operating revenues................... $ 1,109,898 $ 1,432,459 $ (225,905) (A) $ 2,316,452
Fuel................................. 349,999 - (28,356) 321,643
Purchased power...................... 191,309 - - 191,309
Gas and electricity purchased
for resale......................... - 1,125,996 (197,549) 928,447
Natural gas purchases - other........ - 121,385 - 121,385
- --------------------------------------------------------------------------------------------------------
Cost of goods sold................... 541,308 1,247,381 (225,905) 1,562,784
- --------------------------------------------------------------------------------------------------------
Gross margin on sales................ 568,590 185,078 - 753,668
- --------------------------------------------------------------------------------------------------------
Other operation and maintenance...... 196,923 65,301 - 262,224
Depreciation and amortization........ 91,355 44,048 - 135,403
Taxes other than income.............. 33,814 13,225 - 47,039
- --------------------------------------------------------------------------------------------------------
Operating income..................... 246,498 62,504 - 309,002
- --------------------------------------------------------------------------------------------------------
Other income (expenses).............. (1,415) 5,853 - 4,438
- --------------------------------------------------------------------------------------------------------
Earnings before interest and taxes... $ 245,083 $ 68,357 $ - $ 313,440
Net income........................... $ 133,661 $ 6,166 $ - $ 139,827
========================================================================================================
(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 and to Part II, Item 1 of the Company's Form 10-Q for the quarters ended March 31, 2001 and June 30, 2001 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 United States Court of Appeals for the Tenth Circuit issued an order reversing the trial court judgment in favor of Trigen and remanding the case back to the trial court with orders to dismiss the case in its entirety. On October 29, 2001, the United States Supreme Court denied Trigen's petition for certiorari, asking the Supreme Court to review the Court of Appeals decision. As a result of the Supreme Court's denial of Trigen's petition, the Company expects that the trial court will dismiss the charges against OG&E, and the Company considers this matter closed.
As reported in the Company's Form 10-K for the year ended December 31, 2000, Enogex was sued by Melvin Scoggin and Oak Tree Resources, LLC, in February 1998 in the District of Oklahoma County, state of Oklahoma, for alleged breach of contract, fraud, breach of fiduciary duty, misappropriation and unjust enrichment arising from communications that allegedly created agreements regarding oil and gas exploration activities. Plaintiffs' sought damages in excess of $25 million. On October 20, 1999, the trial judge granted Enogex's motions for summary judgment and entered judgment in favor of Enogex on all claims raised by the Plaintiffs. The Plaintiffs appealed the trial court decision and the Court of Appeals upheld the trial court's judgment on all counts. The Plaintiffs requested that the Supreme Court of Oklahoma review the Court of Appeals' decision, which request was recently denied by the Supreme Court. The Company considers this case to be closed.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Reports on Form 8-K
(1) Item 5. Other Events, dated September 11, 2001.
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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)
November 14, 2001
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