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 June 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 77,923,230 Shares of Common Stock, par value $0.01 per share, outstanding as of July 31, 2001.
OGE Energy Corp.
PART I. FINANCIAL INFORMATION
Item 1 FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
3 Months Ended
June 30
--------------------------------
2001 2000
-------------- --------------
(thousands except per share data)
OPERATING REVENUES......................................... $ 747,891 $ 726,904
COST OF GOODS SOLD......................................... 523,507 502,958
-------------- --------------
Gross margin on revenues................................... 224,384 223,946
Other operation and maintenance.......................... 93,442 91,480
Depreciation and amortization............................ 44,923 44,997
Taxes other than income.................................. 16,258 15,723
-------------- --------------
OPERATING INCOME........................................... 69,761 71,746
-------------- --------------
OTHER INCOME (EXPENSES), net............................... (531) 4,855
-------------- --------------
EARNINGS BEFORE INTEREST AND TAXES......................... 69,230 76,601
INTEREST INCOME (EXPENSES):
Interest income.......................................... 1,458 596
Interest on long-term debt............................... (24,931) (25,917)
Interest on trust preferred securities................... (4,317) (4,317)
Allowance for borrowed funds used during construction.... 234 1,582
Other interest charges................................... (3,512) (3,531)
-------------- --------------
Net interest expenses.................................. (31,068) (31,587)
-------------- --------------
INCOME BEFORE TAXES........................................ 38,162 45,014
INCOME TAX EXPENSE......................................... 13,369 13,270
-------------- --------------
NET INCOME................................................. $ 24,793 $ 31,744
============== ==============
AVERAGE COMMON SHARES OUTSTANDING (thousands).............. 77,922 77,863
EARNINGS PER AVERAGE COMMON SHARE.......................... $ 0.32 $ 0.41
============== ==============
AVERAGE COMMON SHARES OUTSTANDING
ASSUMING DILUTION (thousands)............................ 77,922 77,863
EARNINGS PER AVERAGE COMMON SHARE
ASSUMING DILUTION........................................ $ 0.32 $ 0.41
============== ==============
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)
6 Months Ended 6 Months Ended
June 30 June 30
--------------------------------
2001 2000
-------------- --------------
(thousands except per share data)
OPERATING REVENUES......................................... $ 1,811,478 $ 1,308,485
COST OF GOODS SOLD......................................... 1,420,429 903,754
-------------- --------------
Gross margin on revenues................................... 391,049 404,731
Other operation and maintenance.......................... 191,532 179,042
Depreciation and amortization............................ 90,246 89,916
Taxes other than income.................................. 32,910 31,831
-------------- --------------
OPERATING INCOME........................................... 76,361 103,942
-------------- --------------
OTHER INCOME (EXPENSES), net............................... (781) 4,654
-------------- --------------
EARNINGS BEFORE INTEREST AND TAXES......................... 75,580 108,596
INTEREST INCOME (EXPENSES):
Interest income.......................................... 2,327 2,205
Interest on long-term debt............................... (51,372) (51,304)
Interest on trust preferred securities................... (8,634) (8,634)
Allowance for borrowed funds used during construction.... 417 1,730
Other interest charges................................... (7,218) (9,145)
-------------- --------------
Net interest expenses.................................. (64,480) (65,148)
-------------- --------------
INCOME BEFORE TAXES........................................ 11,100 43,448
INCOME TAX EXPENSE......................................... 1,275 10,928
-------------- --------------
NET INCOME................................................. $ 9,825 $ 32,520
============== ==============
AVERAGE COMMON SHARES OUTSTANDING (thousands).............. 77,922 77,863
EARNINGS PER AVERAGE COMMON SHARE.......................... $ 0.13 $ 0.42
============== ==============
AVERAGE COMMON SHARES OUTSTANDING
ASSUMING DILUTION (thousands)............................ 77,922 77,863
EARNINGS PER SVERAGE COMMON SHARE
ASSUMING DILUTION........................................ $ 0.13 $ 0.42
============== ==============
DIVIDENDS DECLARED PER SHARE............................... $ 0.6650 $ 0.6650
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
1
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30 December 31
2001 2000
------------- --------------
(dollars in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents..................................... $ 397 $ 454
Accounts receivable - customers, less reserve of $3,970 and
$4,135, respectively........................................ 282,019 446,185
Accrued unbilled revenues..................................... 61,500 49,000
Accounts receivable - other, less reserve of $0 and
$2,545, respectively........................................ 13,087 24,713
Fuel inventories.............................................. 112,698 200,316
Materials and supplies, at average cost....................... 41,403 41,517
Prepayments and other......................................... 10,116 45,715
Price risk management......................................... 23,404 45,727
Accumulated deferred tax assets............................... 11,255 10,669
------------- --------------
Total current assets........................................ 555,879 864,296
------------- --------------
OTHER PROPERTY AND INVESTMENTS, at cost......................... 38,897 36,980
------------- --------------
PROPERTY, PLANT AND EQUIPMENT:
In service.................................................... 5,402,200 5,323,541
Construction work in progress................................. 75,931 47,016
------------- --------------
Total property, plant and equipment......................... 5,478,131 5,370,557
Less accumulated depreciation............................. 2,222,352 2,151,093
------------- --------------
Net property, plant and equipment........................... 3,255,779 3,219,464
------------- --------------
DEFERRED CHARGES:
Advance payments for gas...................................... 12,500 12,500
Income taxes recoverable through future rates................. 38,134 38,654
Price risk management......................................... 6,034 5,668
Other......................................................... 90,908 142,068
------------- --------------
Total deferred charges...................................... 147,576 198,890
------------- --------------
TOTAL ASSETS.................................................... $ 3,998,131 $ 4,319,630
============= ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt............................................... $ 220,100 $ 284,500
Accounts payable.............................................. 191,912 330,445
Dividends payable............................................. 25,909 25,890
Customers' deposits........................................... 25,590 22,647
Accrued taxes................................................. 24,061 33,067
Accrued interest.............................................. 40,522 40,699
Long-term debt due within one year............................ 32,000 2,000
Price risk management......................................... 9,752 33,709
Other......................................................... 35,683 36,975
------------- --------------
Total current liabilities................................... 605,529 809,932
------------- --------------
LONG-TERM DEBT.................................................. 1,601,871 1,648,523
------------- --------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Accrued pension and benefit obligation........................ 19,664 14,256
Accumulated deferred income taxes............................. 624,486 618,360
Accumulated deferred investment tax credits................... 54,854 57,429
Price risk management......................................... 12,136 3,001
Other......................................................... 59,357 103,821
------------- --------------
Total deferred credits and other liabilities................ 770,497 796,867
------------- --------------
STOCKHOLDERS' EQUITY:
Common stockholders' equity................................... 443,172 443,298
Retained earnings............................................. 578,997 621,010
Accumulated other comprehensive income........................ (1,935) ---
------------- --------------
Total stockholders' equity.................................. 1,020,234 1,064,308
------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 3,998,131 $ 4,319,630
============= ==============
The accompanying Notes to Consolidated Financial Statements are an integral part hereof.
2
CONSOLIDATED STATEMENTS OF
CASH FLOWS
(Unaudited)
6 Months Ended
June 30
2001 2000
-------------- --------------
(dollars in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income......................................................... $ 9,825 $ 32,520
Adjustments to Reconcile Net Income to Net Cash Provided
from Operating Activities:
Depreciation and amortization.................................... 90,246 89,916
Deferred income taxes and investment tax credits, net............ 4,809 15,177
Gain on sale of assets........................................... (127) (4,624)
Change in Certain Current Assets and Liabilities:
Accounts receivable - customers................................ 164,166 23,335
Accrued unbilled revenues...................................... (12,500) (18,100)
Fuel, materials and supplies inventories....................... 87,732 (48,219)
Other current assets........................................... 46,896 (40,893)
Accounts payable............................................... (138,533) 54,200
Accrued taxes.................................................. (9,006) (11,571)
Accrued interest............................................... (177) 8,053
Other current liabilities...................................... 1,670 2,192
Other operating activities....................................... 2,065 12,274
-------------- --------------
Net cash provided from operating activities.................. 247,066 114,260
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures............................................... (126,397) (91,481)
Proceeds from sale of assets....................................... 489 11,119
Other investing activities......................................... (258) 188
-------------- --------------
Net cash used in investing activities........................ (126,166) (80,174)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirement of long-term debt....................................... (5,766) (1,000)
Proceeds from long-term debt....................................... --- 400,000
Decrease in short-term debt, net................................... (64,400) (370,800)
Premium on issuance (retirement) of common stock................... (125) ---
Contribution from minority interest................................ 1,449 ---
Payment of obligation under capital lease.......................... (278) ---
Cash dividends declared on common stock............................ (51,837) (51,780)
-------------- --------------
Net cash used in financing activities........................ (120,957) (23,580)
-------------- --------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. (57) 10,506
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 454 7,271
-------------- --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 397 $ 17,777
============== ==============
- ---------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized)............................. $ 55,327 $ 48,462
Income taxes..................................................... $ 5,700 $ 7,665
- ---------------------------------------------------------------------------------------------------------
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Interest rate swap............................................... $ 11,476 $ ---
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.
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 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 June 30, 2001, and December 31, 2000, and the results of operations and the changes in cash flows for the periods ended June 30, 2001, and June 30, 2000, have been included and are of a normal recurring nature. Certain prior period amounts have been reclassified on the consolidated 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 trades, 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.
4
- 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, 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.
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.
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 is to reduce exposure to short-term interest rate spikes. This interest rate swap qualified as a cash flow hedge under SFAS No. 133.
The Company recorded a loss, related to the ineffective portion of hedge derivatives, for production hedges, of $4.7 million ($2.9 million net of tax) for the six months ended June 30, 2001.
As of June 30, 2001, a deferred loss of $2.6 million ($1.6 million net of tax), related to an effective 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 two quarters of 2001, as the hedged natural gas production is sold.
5
As of June 30, 2001, a deferred loss of $0.5 million ($0.3 million net of tax), related to an effective cash flow hedge of the interest payments on the $140 million of variable rate short-term debt was recorded in Accumulated Other Comprehensive Income. This loss is expected to be reclassified into earnings over the next 12 months.
- In accordance with SFAS No. 130, Reporting Comprehensive Income, the following are components of Other Comprehensive Income:
- 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, 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.
Six Months Ended
June 30
2001 2000
----------------- -----------------
(dollars in thousands)
Net income............................................... $ 9,825 $ 32,520
----------------- -----------------
Other comprehensive income (loss), net of tax:
Transition adjustment.................................. (16,492) ---
Gain on qualifying cash flow hedging instruments....... 16,653 ---
Reclassification adjustments - contract settlements.... (2,096) ---
----------------- -----------------
Total other comprehensive (loss), net of tax............. (1,935) ---
----------------- -----------------
Total comprehensive income............................... $ 7,890 $ 32,520
================= =================
6
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 six months ended June 30, 2001 (respectively, the “current periods”), and the financial position as of June 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. All references to earnings per share are to earnings per share of the Company’s Common Stock. For the three months ended June 30, 2001, the Company’s earnings were $0.32 per share, compared to $0.41 for the same period in 2000. For the six months ended June 30, 2001, earnings were $0.13 per share versus $0.42 for the comparable period in the prior year. For the current periods, the results of OG&E remained strong, contributing $0.36 and $0.35 to earnings per share, which reflects a $0.02 decrease and a $0.01 increase as compared to results in 2000. Results at Enogex for the current periods remained significantly below 2000, with Enogex’s contribution to earnings per share decreasing $0.07 and $0.30 in the current periods to $0.00 and $(0.13). 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 $0.09 for the current periods, the same as in the prior periods.
For the current periods, approximately 52 percent and 62 percent of the Company’s revenues consisted of the non-utility operations of Enogex, while the remaining 48 percent and 38 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 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 Oklahoma, legislation was passed in 1997 to provide for the orderly restructuring of the electric industry with the goal to provide retail customers with the ability to choose their electric suppliers by July 1, 2002. The Oklahoma Legislature passed Senate Bill 440, in May 2001, which delays the start of electric deregulation 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
7
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 $7.0 million or 21.9 percent in the three months ended June 30, 2001. Of the $7.0 million decrease, approximately $5.5 million was attributable to Enogex and the balance was attributable to OG&E. The decrease in Enogex’s earnings for the three months ended June 30, 2001, was due primarily 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). High natural gas prices without corresponding price increases in natural gas liquids resulted in low fractionation spreads in the current period. The impact of lower fractionation spreads was partially offset by lower pipeline system fuel expenses. OG&E’s decrease in earnings for the three months ended June 30, 2001, was primarily attributable to increases in the cost of goods sold which more than offset the increase in revenues.
For the six months ended June 30, 2001, net income decreased $22.7 million or 69.8 percent. Of the $22.7 million decrease, approximately $23.0 million was attributable to Enogex and $0.4 million was attributable to increased expenses at the corporate level, while OG&E’s net income increased by $0.7 million. The decline in earnings at Enogex was attributable primarily to poor fractionation spreads (which were actually negative during parts of the first quarter of 2001). 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 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. The improvement in earnings at OG&E was attributable to increased sales from warmer weather and increased customer demand, which was only partially offset by lower recoveries under certain rate riders and higher expenses. 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.
OUTLOOK
The Company maintains its previous projection of 2001 earnings at $1.70 to $1.80 per share.
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, full recovery of pipeline system fuel expense at Enogex, the addition of new natural gas
8
transportation contracts at Enogex and lower interest expenses, offset by a continuation of the weak natural gas liquids price environment.
REVENUES
Total operating revenues increased $21.0 million or 2.9 percent and $503.0 million or 38.4 percent in the current periods.
OG&E’s revenues increased $23.9 million or 7.1 percent and $105.4 million or 18.1 percent in the current periods. These increases resulted from the recovery of higher fuel costs and increased customer demand due to warmer weather (approximately $2.6 million and $7.0 million). 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 Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the FERC. See “Regulation and Rates.” Partially offsetting the increased recoveries under the fuel adjustment clauses, were decreased recoveries under the Generation Efficiency Performance Rider (“GEP Rider”) of $1.6 million and $2.9 million, and under the Acquisition Premium Credit Rider (“APC Rider”) of $2.8 million and $5.7 million. See “Regulation and Rates” – “Recent Regulatory Matters” for a related discussion. Increases in kilowatt-hour sales of 1.1 percent and 1.2 percent to OG&E customers (“system sales”) in the current periods were primarily attributable to warmer weather in OG&E’s service area, which partially offset the impact of the GEP modifications and the APC Rider. The warmer weather increased revenues by approximately $2.6 million and $7.0 million in the current periods. Kilowatt-hour sales to other utilities and power marketers (“off-system sales”) increased $459,000 (13.8 percent) and $1.2 million (22.1 percent) in the current periods, however, off-system sales are generally at lower prices per kilowatt-hour and have less impact on operating revenues and earnings than system sales.
Enogex revenues decreased $2.9 million or 0.7 percent in the three months ended June 30, 2001. This decrease was primarily attributable to lower volumes of natural gas liquids processed and sold but was partially offset by higher power marketing revenues. The volume of natural gas liquids processed decreased due to poor fractionation spreads. Although natural gas prices were higher, liquids prices and fractionation spreads were lower compared to the year-ago quarter. These factors caused Enogex to periodically reduce its processing activities to the minimal level necessary to fulfill its contractual obligations to third party shippers so as to avoid increased losses in processing and selling natural gas liquids. Power marketing revenues were driven by higher volumes and prices. The increase in volumes was due to additional opportunities in 2001. Enogex revenues increased $397.6 million or 54.7 percent in the six months ended June 30, 2001, driven by higher natural gas prices as volumes were only slightly higher. Although revenues increased across all of Enogex’s lines of business in the six months ended June 30, 2001, the largest increase was recorded in the energy marketing business, where revenues increased $239.3 million. This increase reflects slightly lower volume of natural gas sales at significantly higher prices.
9
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 $20.5 million or 4.1 percent and $516.7 million or 57.2 percent in the current periods. The specific components of cost of goods sold for the reported periods are as follows:
3 Months Ended 6 Months Ended
June 30 June 30
-------------------------- ---------------------------
2001 2000 2001 2000
------------ ------------ ------------ ------------
(dollars in thousands)
Fuel......................... $ 110,356 $ 97,930 $ 228,238 $ 159,930
Purchased power.............. 70,436 62,124 147,405 122,665
Gas and electricity
purchased for resale........ 291,071 315,529 942,600 565,071
Natural gas purchases -
other....................... 51,644 27,375 102,186 56,088
------------ ------------ ------------ ------------
Total cost of goods sold... $ 523,507 $ 502,958 $ 1,420,429 $ 903,754
============ ============ ============ ============
OG&E’s fuel expense increased $12.5 million or 12.7 percent and $68.3 million or 42.7 percent in the current periods primarily due to a significant increase in the average cost of fuel (particularly natural gas).
OG&E increased its purchased power by $8.3 million or 13.4 percent and $24.7 million or 20.2 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 $24.5 million or 7.8 percent in the three months ended June 30, 2001, due primarily to decreased volumes of natural gas purchased for resale to third parties. Volumes of natural gas purchased for resale decreased slightly due to lower sales activity by Enogex’s energy marketing business. For the six months ended June 30, 2001, Enogex’s natural gas and electricity purchased for resale increased $377.5 million or 66.8 percent due to increased volume and prices of natural gas purchased for resale to third parties, primarily attributable to increased sale 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, increased $24.3 million or 88.7 percent and $46.1 million or 82.2 percent in the current periods due to the significantly increased price of natural gas but was partially offset by a slight decrease in gas shrinkage volumes.
The higher cost of goods sold at Enogex more than offset the increase in Enogex’s revenues for the six months ended June 30, 2001.
10
Other operation and maintenance increased $2.0 million or 2.1 percent and $12.5 million or 7.0 percent in the current periods primarily due to higher expenses attributed to storm recovery, increased bad debt expense, employee labor and benefit costs and miscellaneous corporate expenses.
Interest charges decreased $1.0 million or 3.0 percent and $1.9 million or 2.7 percent in the current periods 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 meets its cash needs through a combination of internally generated funds, short-term borrowings and permanent financing.
For the six months ended June 30, 2001, the Company satisfied its capital expenditures of $126.4 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, $200 million expires on January 15, 2002, $100 million expires on January 15, 2004, and $15 million expires on June 28, 2002.
The Company’s capital structure and cash flow remained strong throughout the current periods. The Company’s combined cash and cash equivalents decreased approximately $57,000 during the six months ended June 30, 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. 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 quarter ended March 31, 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.
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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. 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.
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 is to reduce exposure to short-term interest rate spikes. This interest rate swap qualified as a cash flow hedge under SFAS No. 133.
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.
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===================================================================================================
Fair Value
(dollars in millions) 2001 2002 2003 2004 2005 Thereafter Total at 6-30-01
- ---------------------------------------------------------------------------------------------------
Fixed rate debt:
Principal amount....... $ 1.0 $115.0 $ 14.3 $ 57.8 $153.0 $ 861.2 $1,202.3 $ 1,247.0
Weighted-average
interest rate........ 7.15% 7.34% 7.70% 7.20% 7.09% 7.48% 7.33% ---
Variable-rate debt:
Principal amount....... --- --- --- --- --- $ 434.4 $ 434.4 $ 434.4
Weighted-average
interest rate........ --- --- --- --- --- 5.49% 5.49% ---
===================================================================================================
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 June 30, 2001:
Wholesale Non-Trading
- --------------------------------------------------------------------------------
Commodity market risk, net...... $1,072,082 $ 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.
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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
In 1999, the OCC Staff (“Staff”) implemented a review program (“Matrix Review”) to complete an annual assessment of a utility’s 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 on the state’s electric and gas utilities. Prior to the Matrix Review, the OCC conducted rate cases on a periodic basis without any set criteria. 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 expected to be, a flexible document that will continually evolve. Supplements and modifications to the review program may be needed to respond to the changing regulatory environment and to provide added process efficiencies. 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 identified within the Matrix Review are composed of items such as the time from a utility’s last rate review and the existence of complaints related to quality of service issues. Each indicator is considered and rated 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 on OG&E and two other utilities. The review resulted in an aggregate score of 17 for OG&E, with only one rating of a three relating to the indicator of “Time since last formal rate review”. OG&E’s last formal rate review by the Staff occurred in 1995. As part of its written report, the Staff recommended that general rate reviews be performed on OG&E and the other two utilities. However, at the hearing before the OCC, there was no discussion of a need to pursue further rate proceedings. Nevertheless, the Company does realize that there is an ongoing process that could eventually lead to rate action. At the present time, the Company does not believe that a rate proceeding involving OG&E will be initiated within the next 12 months.
On January 12, 2000, 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 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
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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 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 estimated to be $5.1 million for the time period July 1, 2001 through June 30, 2002. 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 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.
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.
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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 Gas Transportation Adjustment Credit Rider (“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 shall 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, the Attorney General, an Oklahoma Corporation Commissioner 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 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.
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The APSC has established a timetable to establish rules implementing the Arkansas restructuring statutes.
National Energy Legislation
The Bush Administration is currently considering supporting National Energy Legislation, which among other things may reform or repeal the Public Utility Holding Company Act of 1935. Various bills are currently being proposed and considered in Congress. At this time we cannot predict whether or in what form this legislation may be enacted. 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.
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 six months ended June 30, 2001 and June 30, 2000.
========================================================================================================
Three Months Ended Electric
June 30, 2001 Utility Non-utility Intersegment Total
- --------------------------------------------------------------------------------------------------------
(dollars in thousands)
Operating revenues................... $ 359,481 $ 398,203 $ (9,793) (A) $ 747,891
Fuel................................. 119,435 --- (9,079) 110,356
Purchased power...................... 70,436 --- --- 70,436
Gas and electricity purchased
for resale......................... --- 291,785 (714) 291,071
Natural gas purchases - other........ --- 51,644 --- 51,644
- --------------------------------------------------------------------------------------------------------
Cost of goods sold................... 189,871 343,429 (9,793) 523,507
- --------------------------------------------------------------------------------------------------------
Gross margin on sales................ 169,610 54,774 --- 224,384
- --------------------------------------------------------------------------------------------------------
Other operation and maintenance...... 71,777 21,665 --- 93,442
Depreciation and amortization........ 30,227 14,696 --- 44,923
Taxes other than income.............. 11,456 4,802 --- 16,258
- --------------------------------------------------------------------------------------------------------
Operating income..................... 56,150 13,611 --- 69,761
- --------------------------------------------------------------------------------------------------------
Other expenses....................... (500) (31) --- (531)
- --------------------------------------------------------------------------------------------------------
Earnings before interest and taxes... $ 55,650 $ 13,580 $ --- $ 69,230
Net income (loss).................... $ 28,025 $ (3,232) $ --- $ 24,793
========================================================================================================
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========================================================================================================
Three Months Ended Electric
June 30, 2000 Utility Non-utility Intersegment Total
- --------------------------------------------------------------------------------------------------------
(dollars in thousands)
Operating revenues................... $ 335,573 $ 465,704 $ (74,373) (A) $ 726,904
Fuel................................. 106,957 --- (9,027) 97,930
Purchased power...................... 62,124 --- --- 62,124
Gas and electricity purchased
for resale......................... --- 380,875 (65,346) 315,529
Natural gas purchases - other........ --- 27,375 --- 27,375
- --------------------------------------------------------------------------------------------------------
Cost of goods sold................... 169,081 408,250 (74,373) 502,958
- --------------------------------------------------------------------------------------------------------
Gross margin on sales................ 166,492 57,454 --- 223,946
- --------------------------------------------------------------------------------------------------------
Other operation and maintenance...... 69,083 22,397 --- 91,480
Depreciation and amortization........ 30,363 14,634 --- 44,997
Taxes other than income.............. 11,365 4,358 --- 15,723
- --------------------------------------------------------------------------------------------------------
Operating income..................... 55,681 16,065 --- 71,746
- --------------------------------------------------------------------------------------------------------
Other income (expenses).............. (767) 5,622 --- 4,855
- --------------------------------------------------------------------------------------------------------
Earnings before interest and taxes... $ 54,914 $ 21,687 $ --- $ 76,601
Net income........................... $ 29,561 $ 2,183 $ --- $ 31,744
========================================================================================================
========================================================================================================
Six Months Ended Electric
June 30, 2001 Utility Non-utility Intersegment Total
- --------------------------------------------------------------------------------------------------------
(dollars in thousands)
Operating revenues................... $ 686,316 $ 1,148,741 $ (23,579) (A) $ 1,811,478
Fuel................................. 246,397 --- (18,159) 228,238
Purchased power...................... 147,405 --- --- 147,405
Gas and electricity purchased
for resale......................... --- 948,020 (5,420) 942,600
Natural gas purchases - other........ --- 102,186 --- 102,186
- --------------------------------------------------------------------------------------------------------
Cost of goods sold................... 393,802 1,050,206 (23,579) 1,420,429
- --------------------------------------------------------------------------------------------------------
Gross margin on sales................ 292,514 98,535 --- 391,049
- --------------------------------------------------------------------------------------------------------
Other operation and maintenance...... 143,498 48,034 --- 191,532
Depreciation and amortization........ 60,523 29,723 --- 90,246
Taxes other than income.............. 23,141 9,769 --- 32,910
- --------------------------------------------------------------------------------------------------------
Operating income..................... 65,352 11,009 --- 76,361
- --------------------------------------------------------------------------------------------------------
Other income (expenses).............. (1,291) 510 --- (781)
- --------------------------------------------------------------------------------------------------------
Earnings before interest and taxes... $ 64,061 $ 11,519 $ --- $ 75,580
Net income (loss).................... $ 27,028 $ (17,203) $ --- $ 9,825
========================================================================================================
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========================================================================================================
Six Months Ended Electric
June 30, 2000 Utility Non-utility Intersegment Total
- --------------------------------------------------------------------------------------------------------
(dollars in thousands)
Operating revenues................... $ 580,905 $ 830,818 $ (103,238) (A) $ 1,308,485
Fuel................................. 179,207 --- (19,277) 159,930
Purchased power...................... 122,665 --- --- 122,665
Gas and electricity purchased
for resale......................... --- 649,032 (83,961) 565,071
Natural gas purchases - other........ --- 56,088 --- 56,088
- --------------------------------------------------------------------------------------------------------
Cost of goods sold................... 301,872 705,120 (103,238) 903,754
- --------------------------------------------------------------------------------------------------------
Gross margin on sales................ 279,033 125,698 --- 404,731
- --------------------------------------------------------------------------------------------------------
Other operation and maintenance...... 134,336 44,706 --- 179,042
Depreciation and amortization........ 60,514 29,402 --- 89,916
Taxes other than income.............. 22,734 9,097 --- 31,831
- --------------------------------------------------------------------------------------------------------
Operating income..................... 61,449 42,493 --- 103,942
- --------------------------------------------------------------------------------------------------------
Other income (expenses).............. (1,401) 6,055 --- 4,654
- --------------------------------------------------------------------------------------------------------
Earnings before interest and taxes... $ 60,048 $ 48,548 $ --- $ 108,596
Net income........................... $ 26,335 $ 6,185 $ --- $ 32,520
========================================================================================================
(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 quarter-ended March 31, 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.
Item 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The Company's Annual Meeting of Shareowners was held on May 24, 2001.
(b) Not applicable.
(c) The matters voted upon and the results of the voting at the Annual Meeting were as follows:
(1) The Shareowners voted to elect the Company's nominees for election to the Board of Directors as follows:
Luke R. Corbett - 67,013,878 votes for election and
1,209,101 votes withheld
Robert Kelley - 66,996,490 votes for election and
1,226,489 votes withheld
J. D. Williams - 66,853,750 votes for election and
1,369,229 votes withheld
Item 6 EXHIBITS AND REPORTS ON FORM 8-K
(a) 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)
August 14, 2001
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