================================================================================ 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, 1999 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 77,801,317 Shares of Common Stock, par value $0.01 per share, outstanding as of October 31, 1999. ================================================================================
OGE ENERGY CORP. PART I. FINANCIAL INFORMATION ITEM 1 FINANCIAL STATEMENTS CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) 3 MONTHS ENDED 9 MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 -------------------------------- --------------------------------- 1999 1998 1999 1998 -------------- -------------- -------------- -------------- (THOUSANDS EXCEPT PER SHARE DATA) OPERATING REVENUES: Electric utility......................................... $ 464,982 $ 474,209 $ 1,029,228 $ 1,046,871 Non-utility subsidiaries................................. 300,459 81,790 565,279 209,116 -------------- -------------- -------------- -------------- Total operating revenues............................... 765,441 555,999 1,594,507 1,255,987 -------------- -------------- -------------- -------------- OPERATING EXPENSES: Fuel..................................................... 115,360 109,655 248,325 247,824 Purchased power.......................................... 69,117 65,107 190,508 179,189 Gas and electricity purchased for resale................. 233,737 53,380 446,093 138,887 Other operation and maintenance.......................... 108,170 71,305 261,904 229,901 Depreciation............................................. 44,802 40,293 120,388 113,500 Taxes other than income.................................. 15,831 13,316 41,643 38,925 -------------- -------------- -------------- -------------- Total operating expenses............................... 587,017 353,056 1,308,861 948,226 -------------- -------------- -------------- -------------- OPERATING INCOME........................................... 178,424 202,943 285,646 307,761 -------------- -------------- -------------- -------------- OTHER INCOME (EXPENSES): Interest charges......................................... (30,474) (20,213) (68,046) (52,188) Other, net............................................... 2,697 1,290 5,243 2,910 -------------- -------------- -------------- -------------- Total other income (expenses).......................... (27,777) (18,923) (62,803) (49,278) -------------- -------------- -------------- -------------- EARNINGS BEFORE INCOME TAXES............................... 150,647 184,020 222,843 258,483 PROVISION FOR INCOME TAXES................................. 60,443 75,902 83,763 102,840 -------------- -------------- -------------- -------------- NET INCOME................................................. 90,204 108,118 139,080 155,643 PREFERRED DIVIDEND REQUIREMENTS............................ - - - 733 -------------- -------------- -------------- -------------- EARNINGS AVAILABLE FOR COMMON.............................. $ 90,204 $ 108,118 $ 139,080 $ 154,910 ============== ============== ============== ============== AVERAGE COMMON SHARES OUTSTANDING (thousands).............. 77,801 80,772 77,801 80,772 EARNINGS PER AVERAGE COMMON SHARE.......................... $ 1.16 $ 1.34 $ 1.79 $ 1.92 ============== ============== ============== ============== EARNINGS PER AVERAGE COMMON SHARE - ASSUMING DILUTION........................................ $ 1.16 $ 1.34 $ 1.79 $ 1.92 ============== ============== ============== ============== DIVIDENDS DECLARED PER SHARE............................... $ 0.3325 $ 0.3325 $ 0.9975 $ 0.9975
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF. 1CONSOLIDATED BALANCE SHEETS (UNAUDITED) SEPTEMBER 30 DECEMBER 31 1999 1998 ------------- -------------- (DOLLARS IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents..................................... $ 16,711 $ 378 Accounts receivable - customers, less reserve of $4,295 and $3,342, respectively........................................ 313,690 141,235 Accrued unbilled revenues..................................... 47,100 22,500 Accounts receivable - other................................... 11,911 12,902 Fuel inventories, at LIFO cost................................ 123,544 57,288 Materials and supplies, at average cost....................... 39,210 29,734 Prepayments and other......................................... 28,043 31,551 Accumulated deferred tax assets............................... 9,038 7,811 ------------- -------------- Total current assets........................................ 589,247 303,399 ------------- -------------- OTHER PROPERTY AND INVESTMENTS, at cost......................... 37,900 31,682 ------------- -------------- PROPERTY, PLANT AND EQUIPMENT: In service.................................................... 5,201,395 4,391,232 Construction work in progress................................. 49,997 50,039 ------------- -------------- Total property, plant and equipment......................... 5,251,392 4,441,271 Less accumulated depreciation............................. 2,003,389 1,914,721 ------------- -------------- Net property, plant and equipment............................. 3,248,003 2,526,550 ------------- -------------- DEFERRED CHARGES: Advance payments for gas...................................... 14,900 15,000 Income taxes recoverable - future rates....................... 39,952 40,731 Other......................................................... 70,500 66,567 ------------- -------------- Total deferred charges...................................... 125,352 122,298 ------------- -------------- TOTAL ASSETS.................................................... $ 4,000,502 $ 2,983,929 ============= ============== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Short-term debt............................................... $ 792,100 $ 119,100 Accounts payable.............................................. 208,475 96,936 Dividends payable............................................. 25,869 26,865 Customers' deposits........................................... 22,131 23,985 Accrued taxes................................................. 76,407 30,500 Accrued interest.............................................. 21,271 21,081 Long-term debt due within one year............................ 59,000 2,000 Other......................................................... 51,110 50,266 ------------- -------------- Total current liabilities................................... 1,256,363 370,733 ------------- -------------- LONG-TERM DEBT.................................................. 1,051,388 935,583 -------------- -------------- DEFERRED CREDITS AND OTHER LIABILITIES: Accrued pension and benefit obligation........................ 17,344 17,952 Accumulated deferred income taxes............................. 546,901 531,940 Accumulated deferred investment tax credits................... 63,866 67,728 Other......................................................... 32,726 16,611 ------------- -------------- Total deferred credits and other liabilities................ 660,837 634,231 ------------- -------------- STOCKHOLDERS' EQUITY: Common stockholders' equity................................... 440,672 513,614 Retained earnings............................................. 591,242 529,768 ------------- -------------- Total stockholders' equity.................................. 1,031,914 1,043,382 ------------- -------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 4,000,502 $ 2,983,929 ============= ==============
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF. 2CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) 9 MONTHS ENDED SEPTEMBER 30 1999 1998 -------------- -------------- (DOLLARS IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income......................................................... $ 139,080 $ 155,643 Adjustments to Reconcile Net Income to Net Cash: Depreciation and amortization.................................... 120,388 113,500 Deferred income taxes and investment tax credits, net............ 16,640 9,199 Change in Certain Current Assets and Liabilities: Accounts receivable - customers................................ (172,455) (76,100) Accrued unbilled revenues...................................... (24,600) (9,700) Fuel, materials and supplies inventories....................... (30,901) 141 Accumulated deferred tax assets................................ (1,227) 521 Other current assets........................................... 57,209 (16,314) Accounts payable............................................... 56,661 2,877 Accrued taxes.................................................. 45,907 68,507 Accrued interest............................................... 190 (1,503) Other current liabilities...................................... (37,641) 7,470 Other operating activities....................................... 11,967 (22,826) -------------- -------------- Net cash provided by operating activities.................... 181,218 231,415 -------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures............................................. (142,438) (196,769) Investment in Transok............................................ (531,767) - Other investment activities...................................... 2,868 5,106 -------------- -------------- Net cash used in investing activities........................ (671,337) (191,663) -------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES: Retirement of long-term debt..................................... (16,000) (112,500) Proceeds from long-term debt..................................... - 105,671 Short-term debt, net............................................. 673,000 93,700 Redemption of preferred stock.................................... - (49,266) Retirement of common stock....................................... (30) - Premium on retirement of common stock............................ (72,913) - Cash dividends declared on preferred stock....................... - (733) Cash dividends declared on common stock.......................... (77,605) (80,570) -------------- -------------- Net cash provided from (used in) financing activities........ 506,452 (43,698) -------------- -------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. 16,333 (3,946) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 378 4,257 -------------- -------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 16,711 $ 311 ============== ============== - -------------------------------------------------------------------------------------------------------------- SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION CASH PAID DURING THE PERIOD FOR: Interest (net of amount capitalized)............................. $ 51,986 $ 44,363 Income taxes..................................................... $ 37,428 $ 35,316 NON-CASH INVESTING ACTIVITIES DURING THE PERIOD FOR: Capital lease financing.......................................... $ - $ 9,818 Long-term debt assumed in acquisition of Transok................. $ 173,000 $ - Current liabilities assumed in acquisition of Transok............ $ 98,917 $ - - --------------------------------------------------------------------------------------------------------------
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. 3NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. The condensed consolidated financial statements included herein have been prepared by OGE Energy Corp. (the "Company"), without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to make the information presented not misleading. In the opinion of management, all adjustments necessary to present fairly the financial position of the Company and its subsidiaries as of September 30, 1999, and December 31, 1998, and the results of operations and the changes in cash flows for the periods ended September 30, 1999, and September 30, 1998, have been included and are of a normal recurring nature. 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, 1998. 2. In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and for Hedging Activities", with an effective date for periods beginning after June 15, 1999. In July 1999, the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133". Adoption of SFAS No. 133 is now required for financial statements for periods beginning after June 15, 2000. The Company will adopt this new standard effective January 1, 2001, and management believes the adoption of this new standard will not have a material impact on its consolidated financial position or results of operation. 3. Enogex Inc. and its subsidiaries ("Enogex"), in the normal course of business, enters into fixed price contracts for either the purchase or sale of natural gas and electricity at future dates. Due to fluctuations in the natural gas and electricity markets, the Company may buy or sell natural gas and electricity futures contracts, swaps or options to hedge the price and basis risk associated with the specifically identified purchase or sales contracts. Additionally, the Company may use these contracts as an enhancement or speculative trade. For qualifying hedges, the Company accounts for changes in the market value of futures contracts as a deferred gain or loss until the production month for hedged transactions, at which time the gain or loss on the natural gas or electricity futures contract, swap or option is recognized in the results of operations. The results of operations reflect the gain or loss on enhancement or speculative contracts as market values change. 4
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, 1999 (respectively, the "current periods"), and the financial position as of September 30, 1999, of the Company and its subsidiaries: Oklahoma Gas and Electric Company ("OG&E"), Enogex Inc. and its subsidiaries ("Enogex") and Origen and its subsidiaries ("Origen"). Unless indicated otherwise, all comparisons are with the corresponding periods of the prior year. For the current periods, approximately 61 percent and 65 percent of the Company's revenues consisted of regulated sales of electricity by OG&E, a public utility, while the balance of the revenues were provided by the non-utility operations of Enogex. Origen's operations to date have been deminimis and its current operations are in the process of being discontinued. 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. Enogex's primary operations consist of transporting natural gas through its intra-state pipeline to various customers (including OG&E), processing natural gas liquids, marketing electricity, natural gas and natural gas products and investing in the drilling for and production of crude oil and natural gas. On July 1, 1999, Enogex completed its previously announced acquisition of Transok LLC and its subsidiaries ("Transok"), a gatherer, processor and transporter of natural gas in Oklahoma and Texas. Transok's principal assets include approximately 4,900 miles of natural gas pipelines in Oklahoma and Texas with a capacity of approximately 1.2 billion cubic feet per day and 18 billion cubic feet of underground natural gas storage. Transok also owns 9 gas-processing plants, which produced approximately 25,000 barrels per day of natural gas liquids in 1998. Enogex purchased Transok from Tejas Energy LLC of Houston, an affiliate of Shell Oil Company, for $710.3 million, which includes assumption of $173 million of long-term debt (see Part II, Item 5 - "Unaudited Pro Forma Financial Information"). As reported below, Transok operated at a loss of $2.2 million during the three months ended September 30, 1999, as Transok's operations were in the process of being integrated into Enogex. Management currently believes that Transok will report positive results for the six months ended December 31, 1999, which will contribute to the Company's earnings for 1999. Some of the matters discussed in this Form 10-Q may contain forward-looking statements that are subject to certain risks, uncertainties and assumptions. 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; unusual weather; failure of companies that the Company does business with to be Year 2000 ready; regulatory decisions and other risk 5
factors listed in the Company's Form 10-K for the year ended December 31, 1998, 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 $17.9 million or 16.6 percent in the three months ended September 30, 1999. Of the $17.9 million decrease, approximately $18.2 million was attributable to OG&E and approximately $1.4 million was attributable to Enogex. This decrease was partially offset by gains from deferred tax accrual adjustments at the corporate level. For the nine months ended September 30, 1999, net income decreased $16.6 million or 10.6 percent. Of the $16.6 million decrease, approximately $18.1 million was attributable to OG&E. This decrease was partially offset by a $0.5 million increase attributable to Enogex and gains from deferred tax accrual adjustments at the corporate level. As explained below, OG&E's decrease in earnings for the three months ending September 30, 1999, was primarily attributable to lower revenues from sales to OG&E customers ("system sales") due to cooler weather in the OG&E electric service area, lower other electric revenues and lower recoveries under the Generation Efficiency Performance Rider ("GEP Rider"). This decrease was partially offset by higher revenues from sales to other utilities and power marketers ("off-system sales"). For the nine months ending September 30, 1999, OG&E's decrease in earnings reflects lower revenues from both system sales and off-system sales and lower recoveries under the GEP Rider. The decrease in Enogex earnings for the three months ended September 30, 1999, was attributable to higher operating costs, higher interest charges and a loss of $2.2 million at Transok which offset higher volumes in gas processing. For the nine months ended September 30, 1999, Enogex's increase in earnings was due to higher volumes in gas processing, revenues from gas storage operations, improved natural gas prices and increased activity in energy trading. These increases were partially offset by higher operating costs, higher interest charges and Transok's operating results. Earnings per average common share decreased from $1.34 to $1.16 and from $1.92 to $1.79 in the current periods. REVENUES Total operating revenues increased $209.4 million or 37.7 percent and $338.5 million or 27.0 percent in the current periods. These increases reflect the inclusion of Transok revenues for the three months ended September 30, 1999 (approximately $130.4 million) and increased Enogex gas processing revenues, partially offset by decreased electric sales by OG&E. Cooler weather in the OG&E electric service area, lower other electric revenues and lower recoveries under the GEP Rider resulted in reduced revenues of $9.2 million or 2.0 percent for the three months ending September 30, 1999. The cooler weather resulted in a 2.4 percent reduction in kilowatt-hour system sales. OG&E's off-system kilowatt-hour sales also decreased 3.0 percent. However, significantly higher margin sales resulted in increased revenues of $10.3 million which partially offset the other reductions in electric operating revenues. For the nine months ending September 30, 1999, cooler weather, decreased system and off-system sales and lower recoveries under the GEP Rider resulted in reduced OG&E revenues of $17.6 million or 6
1.7 percent. The cooler weather resulted in a 1.5 percent reduction in kilowatt-hour system sales and a 54.4 percent reduction in off-system kilowatt-hour sales. See "Recent Regulatory Matters" for a discussion of the GEP Rider. Enogex revenues increased $218.9 million or 268.4 percent and $356.9 million or 171.3 percent in the current periods largely due to the inclusion of revenues from Transok (approximately $130.4 million), higher volumes in the gas processing segment, increased activity at its OGE Energy Resources trading and energy services unit, improved natural gas prices and revenues from gas storage operations. EXPENSES Total operating expenses increased $234.0 million or 66.3 percent in the three months ended September 30, 1999. This increase was primarily due to the inclusion of Transok's operating expenses ($125.0 million), increased gas and electricity purchased for resale, increased other operation and maintenance and increased depreciation. Enogex's gas and electricity purchased for resale pursuant to its gas and electric marketing operations increased $180.4 million or 337.9 percent in the three months ended September 30, 1999, due to increased volumes of natural gas purchased for resale to third parties, of which $89.5 million was attributable to Transok's operations. Other operation and maintenance increased $36.9 million or 51.7 percent primarily due to increased operating costs at Enogex reflecting the inclusion of Transok's operations; increased costs at OG&E, resulting from expenses associated with tornadoes and severe thunderstorms that inflicted heavy damage to OG&E's power supply, transmission and delivery systems on May 3, 1999; and increased miscellaneous corporate expenses. Depreciation increased $4.5 million or 11.2 percent in the three months ended September 30, 1999, reflecting increased depreciable property, primarily property of Transok. In the nine months ended September 30, 1999, total operating expenses were up $360.6 million or 38.0 percent primarily due to increased gas and electricity purchased for resale ($307.2 million or 221.2 percent) and other operation and maintenance ($32.0 million or 13.9 percent), purchased power ($11.3 million or 6.3 percent) and depreciation ($6.9 million or 6.1 percent). This increase was primarily due to the same factors as mentioned above for the three months ended September 30, 1999. Fuel expense increased $5.7 million or 5.2 percent and $0.5 million or 0.2 percent in the current periods due to higher costs at OG&E associated with the increased use of natural gas in the production of electricity. 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, are passed through to OG&E's electric customers through automatic fuel adjustment clauses. The automatic fuel adjustment clauses are subject to periodic review by the Oklahoma Corporation Commission ("OCC"), the Arkansas Public Service Commission ("APSC") and the Federal Energy Regulatory Commission ("FERC"). Enogex owns and operates a pipeline business that delivers natural gas to the generating stations of OG&E. The OCC, the APSC and the FERC have authority to examine the appropriateness of any gas transportation charges or 7
other fees OG&E pays Enogex, which OG&E seeks to recover through the fuel adjustment clause or other tariffs. See "Recent Regulatory Matters." OG&E's purchased power increased $4.0 million or 6.2 percent and $11.3 million or 6.3 percent primarily due to the availability of electricity at favorable prices. Interest charges increased $10.3 million or 50.8 percent and $15.9 million or 30.4 percent primarily due to higher interest charges at Enogex and costs associated with increased short-term debt incurred to finance the acquisition of Transok (see "Liquidity and Capital Requirements"). LIQUIDITY AND CAPITAL REQUIREMENTS The Company meets its cash needs through internally generated funds, permanent financing and short-term borrowings. Internally generated funds and short-term borrowings are expected to meet virtually all of the Company's capital requirements through the remainder of 1999. Short-term borrowings will continue to be used to meet temporary cash 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, to satisfy maturing debt. Capital expenditures (excluding expenditures to acquire Transok) of $142.4 million for the nine months ended September 30, 1999, were financed with internally generated funds and short-term borrowings. The Company's capital structure and cash flow remained strong throughout the current period. The Company's combined cash and cash equivalents increased approximately $16.3 million during the nine months ended September 30, 1999. The increase reflects the Company's cash flow from operations, other investment activities and short-term debt, partially offset by the construction expenditures, investment in Transok, retirement of long-term debt and common stock, premium on retirement of common stock and dividend payments. As discussed previously, on July 1, 1999, Enogex completed its acquisition of Transok for approximately $710.3 million, which includes assumption of $173 million of long-term debt. The purchase of Transok was temporarily funded through a new $560 million revolving credit agreement with a consortium of banks with the First National Bank of Chicago serving as agent. On October 12, 1999, the Company filed a registration with the Securities and Exchange Commission for up to $200 million of trust preferred securities to be issued by a financing subsidiary trust. On October 21, 1999, the financing trust issued $200 million of 8.375 percent trust preferred securities and all of the proceeds were used to repay a portion of outstanding borrowings under the revolving credit agreement implemented in connection with the acquisition of Transok. The Company expects that the balance of the temporary financing incurred for the purchase of Transok will be replaced with a $400 million note offering by Enogex later this year. 8
Certain security ratings of the Company were lowered by rating agencies primarily due to the debt-incurred to finance the acquisition of Transok. In August 1999, Standard & Poor's ("S&P") downgraded the bank loan rating of the Company and the ratings of OG&E, Enogex and Transok. The Company's bank loan rating changed from "A+" to "A". OG&E's corporate credit rating and senior unsecured debt ratings were changed from "AA-" to "A+". Enogex's corporate credit rating and senior unsecured debt ratings were changed from "A-" to "BBB+". Transok's corporate credit rating and senior unsecured debt ratings were also changed from "A-" to "BBB+". The Company's corporate credit rating and commercial paper rating remained unchanged at "A+/A-1" and "A-1", respectively. Also, in August 1999, Moody's Investors Service ("Moody's") downgraded the commercial paper rating of the Company and the ratings of OG&E and Enogex. The Company's commercial paper rating changed from "P-1" to "P-2". OG&E's senior unsecured debt rating changed from "Aa3" to "A1". Enogex's senior unsecured debt rating changed from "Baa1" to "Baa2". These ratings reflect the views of S&P and Moody's, and an explanation of the significance of these ratings may be obtained from S&P and Moody's. A security rating is not a recommendation to buy, sell or hold securities and is subject to revision or withdrawal at any time by the rating agency. As previously reported, on October 22, 1998, Enogex entered into an option agreement with certain cancellation provisions to purchase two gas turbine generators for use in normal operations. The Company has decided to place these two LM 6000 generators with approximately 50 megawatts of additional peak-load capacity each at Horseshoe Lake power plant with start-up planned for 2000. The total installed cost of this project will be approximately $47.0 million. 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, 1999 and June 30, 1999 and to "Management's Discussion and Analysis" and Notes 10 and 11 of Notes to the Consolidated Financial Statements in the Company's 1998 Form 10-K. THE YEAR 2000 ISSUE There has been a great deal of publicity about the Year 2000 ("Y2K") and the possible problems that information technology systems may suffer as a result. The Y2K problem originated with the early development of computerized business applications. To save then-expensive storage space, reduce the complexity of calculations and yield better system performance, programmers and developers used a two-digit date scheme to represent the year (i.e., "72" for "1972"). This two-digit date scheme was used well into the 1980s and 1990s in traditional computer hardware such as mainframe systems, desktop personal computers and network servers, in customized software systems, off-the-shelf applications and operating systems, as well as in embedded systems ("chips") in everything from elevators to industrial plants to consumer products. As the Year 2000 approaches, date-sensitive systems may recognize the Year 2000 as 1900, or not at all. This inability to recognize or properly treat the 9
Year 2000 may cause systems, including those of the Company, its customers, suppliers, business partners and neighboring utilities to process critical financial and operational information incorrectly, if they are not Year 2000 ready. A failure to identify and correct any such processing problems prior to January 1, 2000 could result in material operational and financial risks if the affected systems either cease to function or produce erroneous data. Such risks are described in more detail below, but could include an inability to operate OG&E's generating plants, disruptions in the operation of its transmission and distribution system and an inability to access interconnections with the systems of neighboring utilities. After the Company's mainframe conversion in 1994, some 300 programs were identified as having date sensitive code. All of these programs have since been corrected or replaced by Y2K ready packaged applications. The Company continues to address the Y2K issues in an aggressive manner. This is reflected by the January 1, 1997 implementation throughout the Company of SAP Enterprise Software, which is Y2K ready, for the financial systems. The SAP installation significantly reduced the potential risks in our older computer systems. In June 1999, the Company also completed the full implementation of the enterprise-wide software system for customer systems. In addition to significantly reducing the potential risks of its current customer systems, the Company is set to streamline work processes in customer service and power delivery by integrating separate systems into a single system using the enterprise-wide software system. This new single system will also provide for a more flexible automated billing system and enhancements in handling customer service orders, energy outage incidents and customer services. In October of 1997, the Company formed a multi-functional Y2K Project Team of experienced and knowledgeable members from each business unit to review and test its operational systems in an effort to further eliminate any potential problems, should they exist. The team provides regular monthly reports on its progress to the Y2K Executive Steering Committee and senior management as well as helping prepare presentations to the Board of Directors. The Company's Year 2000 effort generally follows a three-phase process: Phase I - Inventory and Assess Y2K Issues Phase II - Determine Y2K Readiness of Vendors, Suppliers & Customers Phase III - Correct, Test, Implement Solutions and Contingency Planning STATE OF READINESS The Company has completed the internal inventory and assessment (Phase I) of the Year 2000 plan. Follow-up vendor requests for information on their status has been received, documented and filed (Phase II). Remediation is complete for systems essential to generate and deliver electricity to our customers. Even though contingency planning is a normal part of our 10
business, plans are being updated and finalized to include specific activities with regard to Y2K issues (Phase III). In addition, as a part of the Company's three-year lease agreement for personal computers, all new personal computers are being issued with operating systems and application software that are Y2K ready. All existing personal computers have been upgraded with Y2K ready operating systems. For embedded and plant operational systems, the Company has completed the corrective process. Also, Supervisory Control and Data Acquisition ("SCADA") equipment has been upgraded or replaced in some locations. The Company's Energy Management System ("EMS") that monitors transmission interconnections and automatically signals generation output changes was replaced in 1999. Software has been configured and new equipment is installed and operational. The Company participated in the "Y2K Electric System Readiness Assessment" program, which provides monthly reports to the Southwest Power Pool ("SPP") and the North American Electric Reliability Council ("NERC"). In February 1999, the Company submitted contingency plans to the NERC and the SPP, which will be used along with those of other participating companies to formulate a regional contingency plan. In April 1999, the Company also participated in a nationwide communications drill as a part of the electric utility industry's Y2K readiness preparation. The purpose of the drill was to determine how electric utilities would communicate with one another in the event of an interruption of standard communication systems. The ability to communicate would be important to coordinate the flow of electricity over the nation's electric grid. The drill was successful overall and communications in the SPP went smoothly with only minor problems noted. On June 28, 1999, the Company reported to the NERC that its essential systems used to produce and deliver electricity were ready for the year 2000. The responses from all participating companies are being compiled for an industry-wide status report to the Department of Energy ("DOE"). Also, the Company participated in the NERC tests on September 8, 1999, and September 9, 1999, which simulated the exercise of operating, communications, administrative and contingency plans for the Y2K transition. The drill was successful with respect to the Company's operations. COSTS OF YEAR 2000 ISSUES As described above, with the mainframe conversion, the enterprise software installations and the EMS replacement, a number of Y2K issues were addressed as part of the Company's normal course upgrades to the information technology systems. These upgrades were already contemplated and provided additional benefits or efficiencies beyond the Year 2000 aspect. Since 1995, the Company has spent in excess of $37 million on the mainframe conversion, the initial financial enterprise software systems, the customer care enterprise software installations to-date and the SCADA/EMS replacement. The Company expects to spend slightly less than $5 million in 1999. These costs represent estimates, however, and there can be no assurance that actual costs associated with the Company's Y2K issues will not be higher. 11
RISKS OF YEAR 2000 ISSUES As described above, the Company has made significant progress in the implementation of its Year 2000 plan. Based upon the information currently known regarding its internal operations and assuming successful and timely completion of its remediation plan, the Company does not anticipate significant business disruptions from its internal systems due to the Y2K issue. However, the Company may possibly experience limited interruptions to some aspects of its activities, whether information technology, operational, administrative or otherwise, and the Company is considering such potential occurrences in planning for its most reasonably likely worst case scenarios. Additionally, risk exists regarding the non-readiness of third parties with key business or operational importance to the Company. Year 2000 problems affecting key customers, interconnected utilities, fuel suppliers and transporters, telecommunications providers or financial institutions could result in lost power or gas sales, reductions in power production or transmission or internal functional and administrative difficulties on the part of the Company. Although the Company is not presently aware of any such situations, occurrences of this type, if severe, could have material adverse impacts upon the business, operating results or financial condition of the Company. There can be no assurance that the Company will be able to identify and correct all aspects of the Year 2000 problem that affect it in sufficient time, that it will develop adequate contingency plans or that the costs of achieving Y2K readiness will not be material. RECENT REGULATORY MATTERS On July 15, 1999, OG&E filed with the OCC for approval of a performance-based ratemaking plan that could lower rates for OG&E's Oklahoma customers by $83 million during the transition to deregulated customer choice in mid-2002. OG&E is the first utility in Oklahoma and among the first in the nation to seek approval of such a plan. Under the proposed performance-based ratemaking plan, OG&E's rates would be lowered initially by an estimated $29 million a year compared to June 1999 rates and then would remain fixed at such rate during the 30-month period ending July 1, 2002. This would be accomplished, in part, through the elimination of OG&E's GEP Rider and current fuel adjustment clause through which increases and decreases in fuel costs are passed on to customers. The risk of higher prices for the coal and natural gas used in generating electricity would then shift from the customer to OG&E. Another key component of the proposed performance-based ratemaking plan is a service quality incentive mechanism, pursuant to which OG&E's performance will be measured against its own benchmarks and recognized utility industry standards. These measurements will then be used in a financial reward/penalty program to promote continued reliability in OG&E's electric system, high levels of customer satisfaction and employee safety. 12
OG&E believes that the lower electric rates would be made possible in part, by a reduction in the cost of transporting natural gas to its power plants. Under the proposal, Enogex would remain OG&E's natural gas transporter at an annual rate of $25 million, down from the current $41 million rate. Other provisions of the proposed performance-based ratemaking plan include termination of the GEP Rider and the termination of OG&E's rider for off-system electricity sales. In Oklahoma, profits from off-system sales are shared equally between customers and shareowners. OG&E believes termination of this rider is consistent with providing customers fixed rates and would allow OG&E to benefit from effectively managing its business. On October 13, 1999, the OCC approved a procedural scheduling order for consideration by year-end of OG&E's proposed performance-based ratemaking plan. Under the order approved by the OCC, testimony and discovery deadlines are scheduled to conclude in November, with the case to be submitted to an administrative law judge in early December, followed by a hearing before the OCC on December 17, 1999. If approved by the OCC, the key provisions of the proposed performance-based ratemaking plan will go into effect on January 1, 2000. As previously reported, the OCC's order on February 11, 1997 established the GEP Rider. The GEP Rider is designed so that when OG&E's average annual cost of fuel per kwh is 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 is allowed to collect, through the GEP Rider, one-third of the amount by which OG&E's average annual cost of fuel is less than 96.261 percent of the average of the other specified utilities. If OG&E's fuel cost exceeds 103.739 percent of the stated average, OG&E will not be allowed to recover one-third of the fuel costs above that amount from Oklahoma customers. The GEP Rider is revised effective July 1 of each year to reflect any changes in the relative annual cost of fuel reported for the preceding calendar year. For the twelve months ended June 30, 1999, the GEP Rider positively impacted revenues by $30 million or approximately $0.23 per share. The new GEP Rider which was revised July 1, 1999, is estimated to positively impact revenue by $20 million or approximately $0.15 per share in 1999, which is approximately $10 million or $0.08 per share less than in 1998. As previously reported, on February 13, 1998, the APSC staff filed a motion for a show cause order to review OG&E's electric rates in the State of Arkansas. The Staff recommended a $3.1 million annual rate reduction (based on a test year ended December 31, 1996). The Staff and OG&E have reached a settlement for a $2.3 million annual rate reduction. The settlement was presented to the APSC on May 18, 1999. The APSC issued an order approving the settlement on August 6, 1999. On April 8, 1999, lawmakers in Arkansas reached consensus on deregulation of the state's electric industry. On April 15, 1999, Senate Bill 791 was signed by the governor of Arkansas. Arkansas is the 18th state to pass a law calling for restructuring of the electric utility industry. The new law targets customer choice of electricity providers by January 1, 2002. The new law also provides that utilities owning or controlling transmission assets must transfer control of such 13
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 new law permit municipal electric systems to opt in or out, permit recovery of stranded costs and transition costs and require unbundled rates by July 1, 2000 for generation, transmission, distribution and customer service. If implemented as proposed, the new law will significantly affect OG&E's future Arkansas operations. OG&E's electric service area includes parts of western Arkansas, including Fort Smith, the second-largest metropolitan market in the state. As previously reported, Oklahoma enacted in April 1997 the Electric Restructuring Act of 1997. Various amendments to the Act were enacted in 1998. OG&E remains involved in the legislative and rulemaking process that is scheduled to provide for customer choice in Oklahoma by July 1, 2002. 14
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 and Origen. Enogex is engaged in gathering and processing natural gas, producing natural gas liquids, underground storage of natural gas, transporting natural gas through its pipelines in Oklahoma, Arkansas and Texas 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. Origen is engaged in the development of new products. Origen's results to date have not been material to the Company and its current operations are in the process of being discontinued. The following is the Company's business segment results for the current periods. 3 MONTHS ENDED 9 MONTHS ENDED SEPTEMBER 30 SEPTEMBER 30 1999 1998 1999 1998 =========================== =========================== (DOLLARS IN THOUSANDS) ============================================================================================================= Operating Information: Operating Revenues Electric utility....................... $ 464,982 $ 474,209 $1,029,228 $1,046,871 Non-utility............................ 385,778 154,140 732,094 357,300 Intersegment revenues (A).............. (85,319) (72,350) (166,815) (148,184) - ------------------------------------------------------------------------------------------------------------- Total................................ $ 765,441 $ 555,999 $1,594,507 $1,255,987 ============================================================================================================= Net Income Electric utility....................... $ 87,753 $ 105,931 $ 131,672 $ 149,731 Non-utility............................ 2,451 2,187 7,408 5,912 - ------------------------------------------------------------------------------------------------------------- Total................................ $ 90,204 $ 108,118 $ 139,080 $ 155,643 ============================================================================================================= (A) Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. 15
PART II. OTHER INFORMATION ITEM 1 LEGAL PROCEEDINGS Reference is made to Item 3 of the Company's 1998 Form 10-K and to Part II, Item 1 of the Company's Form 10-Q for the quarters ended March 31, 1999 and June 30, 1999 for a description of certain legal proceedings presently pending. Except as described below, there are no new significant cases to report against the Company or its subsidiaries and there have been no significant changes in the previously reported proceedings. 1. As previously reported in the Company's 1998 Form 10-K, an employee of OG&E filed a lawsuit in the state court on July 8, 1994, against OG&E in connection with OG&E's 1994 voluntary early retirement program. The case was removed to the U.S. District Court in Tulsa, Oklahoma. On August 23, 1994, the trial court granted OG&E's Motion to Dismiss Plaintiff's Complaint in its entirety. On September 12, 1994, Plaintiff, along with two other Plaintiffs, filed an Amended Complaint alleging substantially the same allegations, which were in the original complaint. The action was filed as a class action, but no motion to certify a class was ever filed. Plaintiff's wanted credit, for retirement purposes, for years they worked prior to a pre-ERISA (1974) break in service. They alleged violations of ERISA, the Veterans Reemployment Act, Title VII, and the Age Discrimination in Employment Act. State law claims, including one for intentional infliction of emotional distress, were also alleged. On October 10, 1994, Defendants filed a Motion to Dismiss Counts II, IV, V, VI and VII of Plaintiffs' Amended Complaint. With regard to Counts I and III, Defendants filed a Motion for Summary Judgement on January 18, 1996. On September 8, 1997, the United States Magistrate Judge recommended that the Defendant's motions to dismiss and for summary judgement should be granted and that the case be dismissed in its entirety and judgement entered for OG&E. The United States District Judge accepted the recommendation of the Magistrate and entered judgement for OG&E. Plaintiffs filed an appeal with the Tenth Circuit Court of Appeals. In August 1999, the Tenth Circuit affirmed in all respects the District Courts' decision dismissing Plaintiff's case and entering judgement for OG&E. Since the Plaintiffs have failed to file a timely writ of certiorari to the U.S. Supreme Court, the Company considers this case closed. 2. Also, as previously reported in the Company's 1998 Form 10-K, Enogex was sued by Melvin Scoggin and Oak Tree Resources, LLC in the District Court of Oklahoma County, State of Oklahoma, on February 19, 1998, 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 seek damages in excess of $25 million. Enogex filed an answer denying Plaintiffs' allegations and various motions for summary judgement. On October 20, 1999, and October 25, 1999, the trial judge granted Enogex's motions for summary judgement and entered judgement in favor of Enogex on all claims raised by the Plaintiffs. The time for Plaintiffs to appeal the trial court's decision has not expired as of the date of this report. The Company continues to believe that this case is without merit. 16
3. Reference is made to "Item 1. Legal Proceedings" of Part II of the Company's Form 10-Q for the quarter ended June 30, 1999, for a description of the qui tam cases brought by Jack J. Gynberg against OG&E, Enogex, subsidiaries of Enogex and more than 300 other entities. On October 20, 1999, the Multi District Litigation Panel (MDL Panel) entered its order consolidating all the listed Gynberg qui tam cases in the United States District Court of Wyoming before the Honorable Judge William Downes. On November 4, 1999, the same MDL Panel entered its Order indicating the listed Gynberg qui tam tag-along cases would also be considered in the United States District Court of Wyoming before Judge Downes. On September 23, 1999, Quinque Operating Company, on behalf of itself and others, filed an amended class action petition alleging, among other things, mismeasurement of gas volume and BTU content by approximately 200 defendants, including OG&E, Enogex and two subsidiaries of Enogex, including Transok. Specifically, Plaintiffs are seeking to certify the action as a class action and allege breach of contract, negligent or intentional misrepresentation, civil conspiracy and fraud. Plaintiffs seek actual and treble damages, punitive damages, and an injunction to prevent mismeasurement in the future. Their prayer for actual damages is in excess of $75,000 and includes punitive damages. On October 5, 1999, notice was filed with the MDL Panel that this matter involved the same measurement issues and was a potential tag-along to the Gynberg matter. Plaintiffs opposed the MDL Panel transfer on October 15. The MDL Panel has not yet entered an order concerning whether this will be treated as a tag-along case to the Gynberg lawsuit. Due to early stages of these lawsuits, the Company cannot predict the ultimate outcome of either the Gynberg or Quinque actions, but at the present time, the Company believes that neither lawsuit will have a material adverse impact on the Company's consolidated financial position or results of operations. ITEM 5 OTHER INFORMATION UNAUDITED PRO FORMA FINANCIAL INFORMATION The following unaudited pro forma financial information presents total operating revenues, net income and earnings per average common share of the Company after giving effect to the acquisition of Transok by Enogex. The unaudited pro forma financial information for the nine months ended September 30, 1999 gives effect to the acquisition as if it had occurred at January 1, 1999. The unaudited pro forma financial information for the nine months ended September 30, 1998 gives effect to the acquisition as if it had occurred at January 1, 1998. The following unaudited pro forma financial information has been prepared from, and should be read in conjunction with, the historical consolidated financial statements and related notes thereto of the Company and Transok. The following information is not necessarily indicative of the financial position or operating results that would have occurred had the transaction been consummated on the date, or at the beginning of the periods, for which the 17
transaction is being given effect nor is it necessarily indicative of future operating results or financial position. OGE ENERGY CORP. UNAUDITED PRO FORMA FINANCIAL INFORMATION Pro Forma Pro Forma 9 mo's ended 9 mo's ended September 30, 1999 September 30, 1999 -------------------- -------------------- Total operating revenues.............. $ 1,845,743 $ 1,627,573 Net income............................ 134,812 131,538 Earnings per average common share..... 1.73 1.62 Earnings per average common share - assuming dilution................... 1.73 1.62 18
ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits 27.01 - Financial Data Schedule. (b) Reports on Form 8-K (1) Item 5. Other Events, dated July 8, 1999. (2) Item 2. Acquisition of Assets, dated July 13, 1999. (3) Item 5. Other Events, dated July 16, 1999. (4) Item 7. Financial Statements and Exhibits, dated July 13, 1999 (Form 8-K/A filed on September 13, 1999). (5) Item 7. Financial Statements and Exhibits, dated July 13, 1999 (Form 8-K/A-2 filed on September 14, 1999). 19
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 Controller Corporate Accounting (On behalf of the registrant and in his capacity as Controller Corporate Accounting) November 15, 1999 20
UT 1,000 9-MOS SEP-30-1999 SEP-30-1999 PER-BOOK 3,248,003 37,900 589,247 125,352 0 4,000,502 778 439,894 591,242 1,031,914 0 0 1,051,388 0 0 792,100 59,000 0 9,911 3,148 1,053,041 4,000,502 1,594,507 83,763 1,308,861 1,308,861 285,646 5,243 290,889 68,046 139,080 0 139,080 77,605 45,377 181,218 1.79 1.79