================================================================================ 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, 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 July 31, 1999. ================================================================================
<TABLE> <CAPTION> OGE ENERGY CORP. PART I. FINANCIAL INFORMATION ITEM 1 FINANCIAL STATEMENTS CONSOLIDATED STATEMENTS OF INCOME (Unaudited) 3 Months Ended 6 Months Ended June 30 June 30 -------------------------------- --------------------------------- 1999 1998 1999 1998 -------------- -------------- -------------- -------------- (THOUSANDS EXCEPT PER SHARE DATA) <S> <C> <C> <C> <C> OPERATING REVENUES: Electric utility......................................... $ 314,102 $ 336,017 $ 564,246 $ 572,662 Non-utility subsidiaries................................. 136,759 76,604 264,820 127,326 -------------- -------------- -------------- -------------- Total operating revenues............................... 450,861 412,621 829,066 699,988 -------------- -------------- -------------- -------------- OPERATING EXPENSES: Fuel..................................................... 75,284 78,555 132,966 138,169 Purchased power.......................................... 62,267 57,757 121,390 114,082 Gas and electricity purchased for resale................. 110,899 55,777 212,356 85,507 Other operation and maintenance.......................... 79,390 79,302 153,734 158,596 Depreciation............................................. 37,323 36,157 75,586 73,207 Taxes other than income.................................. 12,551 12,284 25,812 25,609 -------------- -------------- -------------- -------------- Total operating expenses............................... 377,714 319,832 721,844 595,170 -------------- -------------- -------------- -------------- OPERATING INCOME........................................... 73,147 92,789 107,222 104,818 -------------- -------------- -------------- -------------- OTHER INCOME (EXPENSES): Interest charges......................................... (19,272) (16,035) (37,572) (31,975) Other, net............................................... 1,736 (107) 2,546 1,620 -------------- -------------- -------------- -------------- Net other income (expenses)............................ (17,536) (16,142) (35,026) (30,355) -------------- -------------- -------------- -------------- EARNINGS BEFORE INCOME TAXES............................... 55,611 76,647 72,196 74,463 PROVISION FOR INCOME TAXES................................. 17,867 28,782 23,320 26,938 -------------- -------------- -------------- -------------- NET INCOME................................................. 37,744 47,865 48,876 47,525 PREFERRED DIVIDEND REQUIREMENTS............................ - - - 733 -------------- -------------- -------------- -------------- EARNINGS AVAILABLE FOR COMMON.............................. $ 37,744 $ 47,865 $ 48,876 $ 46,792 ============== ============== ============== ============== AVERAGE COMMON SHARES OUTSTANDING.......................... 77,801 80,772 77,801 80,772 EARNINGS PER AVERAGE COMMON SHARE.......................... $ 0.49 $ 0.59 $ 0.63 $ 0.58 ============== ============== ============== ============== EARNINGS PER AVERAGE COMMON SHARE - ASSUMING DILUTION........................................ $ 0.49 $ 0.59 $ 0.63 $ 0.58 ============== ============== ============== ============== DIVIDENDS DECLARED PER SHARE............................... $ 0.3325 $ 0.3325 $ 0.665 $ 0.665 <FN> THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF. </FN> </TABLE> 1
<TABLE> <CAPTION> CONSOLIDATED BALANCE SHEETS (Unaudited) JUNE 30 DECEMBER 31 1999 1998 ------------- -------------- (DOLLARS IN THOUSANDS) <S> <C> <C> ASSETS CURRENT ASSETS: Cash and cash equivalents..................................... $ 1,962 $ 378 Accounts receivable - customers, less reserve of $3,101 and $3,342, respectively........................................ 144,809 141,235 Accrued unbilled revenues..................................... 59,000 22,500 Accounts receivable - other................................... 13,306 12,902 Fuel inventories, at LIFO cost................................ 85,321 57,288 Materials and supplies, at average cost....................... 36,171 29,734 Prepayments and other......................................... 19,758 31,551 Accumulated deferred tax assets............................... 8,609 7,811 ------------- -------------- Total current assets........................................ 368,936 303,399 ------------- -------------- OTHER PROPERTY AND INVESTMENTS, at cost......................... 61,010 31,682 ------------- -------------- PROPERTY, PLANT AND EQUIPMENT: In service.................................................... 4,479,118 4,391,232 Construction work in progress................................. 36,948 50,039 ------------- -------------- Total property, plant and equipment......................... 4,516,066 4,441,271 Less accumulated depreciation............................. 1,979,001 1,914,721 ------------- -------------- Net property, plant and equipment............................. 2,537,065 2,526,550 ------------- -------------- DEFERRED CHARGES: Advance payments for gas...................................... 14,900 15,000 Income taxes recoverable - future rates....................... 40,211 40,731 Other......................................................... 66,539 66,567 ------------- -------------- Total deferred charges...................................... 121,650 122,298 ------------- -------------- TOTAL ASSETS.................................................... $ 3,088,661 $ 2,983,929 ============= ============== CAPITALIZATION AND LIABILITIES CURRENT LIABILITIES: Short-term debt............................................... $ 298,800 $ 119,100 Accounts payable.............................................. 99,456 96,936 Dividends payable............................................. 25,869 26,865 Customers' deposits........................................... 23,880 23,985 Accrued taxes................................................. 45,132 30,500 Accrued interest.............................................. 21,611 21,081 Long-term debt due within one year............................ 2,000 2,000 Other......................................................... 33,510 50,266 ------------- -------------- Total current liabilities................................... 550,258 370,733 ------------- -------------- LONG-TERM DEBT.................................................. 934,650 935,583 -------------- -------------- DEFERRED CREDITS AND OTHER LIABILITIES: Accrued pension and benefit obligation........................ 21,925 17,952 Accumulated deferred income taxes............................. 523,925 531,940 Accumulated deferred investment tax credits................... 65,153 67,728 Other......................................................... 30,190 16,611 ------------- -------------- Total deferred credits and other liabilities................ 641,193 634,231 ------------- -------------- STOCKHOLDERS' EQUITY: Common stockholders' equity................................... 435,654 513,614 Retained earnings............................................. 526,906 529,768 ------------- -------------- Total stockholders' equity.................................. 962,560 1,043,382 ------------- -------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 3,088,661 $ 2,983,929 ============= ============== <FN> THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF. </FN> </TABLE> 2
<TABLE> <CAPTION> CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) 6 Months Ended June 30 1999 1998 -------------- -------------- (DOLLARS IN THOUSANDS) <S> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES: Net Income......................................................... $ 48,876 $ 47,525 Adjustments to Reconcile Net Income to Net Cash Provided From Operating Activities: Depreciation and amortization.................................... 75,586 73,207 Deferred income taxes and investment tax credits, net............ (9,495) (1,552) Change in Certain Current Assets and Liabilities: Accounts receivable - customers................................ (3,574) (41,474) Accrued unbilled revenues...................................... (36,500) (24,200) Fuel, materials and supplies inventories....................... (34,470) (225) Accumulated deferred tax assets................................ (798) (796) Other current assets........................................... 8,520 (7,149) Accounts payable............................................... 2,520 1,193 Accrued taxes.................................................. 14,632 17,634 Accrued interest............................................... 530 (2,232) Other current liabilities...................................... (17,857) 8,220 Other operating activities....................................... 16,081 2,224 -------------- -------------- Net cash provided from operating activities.................. 64,051 72,375 -------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures............................................... (89,336) (76,886) Other investment activities........................................ (22,132) (1,650) -------------- -------------- Net cash used in investing activities........................ (111,468) (78,536) -------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES: Retirement of long-term debt....................................... (1,000) (112,500) Proceeds from long-term debt....................................... - 105,672 Short-term debt, net............................................... 179,700 114,000 Redemption of common stock......................................... (77,962) - Redemption of preferred stock...................................... - (49,266) Cash dividends declared on preferred stock......................... - (733) Cash dividends declared on common stock............................ (51,737) (53,714) -------------- -------------- Net cash provided from financing activities.................. 49,001 3,459 -------------- -------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. 1,584 (2,702) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 378 4,257 -------------- -------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 1,962 $ 1,555 ============== ============== - -------------------------------------------------------------------------------------------------------------- SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash Paid During the Period for: Interest (net of amount capitalized)............................. $ 29,640 $ 29,025 Income taxes..................................................... $ 17,450 $ 11,696 - -------------------------------------------------------------------------------------------------------------- <FN> 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. </FN> </TABLE> 3
NOTES 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 June 30, 1999, and December 31, 1998, and the results of operations and the changes in cash flows for the periods ended June 30, 1999, and June 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 buys or sells natural gas and electricity futures contracts, swaps or options to hedge the price and basis risk associated with the specifically identified purchase or sales contracts. Additionally, the Company will 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 Company recognizes the gain or loss on enhancement or speculative contracts as market values change in the results of operations. 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 six months ended June 30, 1999 (respectively, the "current periods"), and the financial position as of June 30, 1999, of the Company and its subsidiaries: Oklahoma Gas and Electric Company ("OG&E"), Enogex Inc. ("Enogex") and Origen and its subsidiaries ("Origen"). Unless indicated otherwise, all comparisons are with the corresponding periods of the prior year. For current periods, approximately 70 percent and 68 percent of the Company's revenues consisted of regulated sales of electricity by OG&E, a public utility, while the remaining 30 percent and 32 percent were provided by the non-utility operations of Enogex. Origen's operations to date have been deminimis. 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, 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 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 $701 million, which includes assumption of $173 million of long-term debt". 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 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. 5
EARNINGS Net income decreased $10.1 million or 21.1 percent in the three months ended June 30, 1999. Of the $10.1 million decrease, approximately $12.1 was attributable to OG&E. This decrease was partially offset by a $1.0 million increase attributable to Enogex and gains from other operations of the Company. For the six months ended June 30, 1999, net income increased $1.4 million or 2.8 percent. This $1.4 million was primarily attributable to Enogex, with OG&E having only a minimal increase for the six months ended June 30, 1999. As explained below, OG&E's decrease in earnings for the three months ending June 30, 1999, was primarily attributable to lower revenues due to decreased sales to OG&E customers ("system sales") due to cooler weather in the OG&E electric service area and lower revenues from sales to other utilities and power marketers ("off-system sales"). For the six months ending June 30, 1999, OG&E's increase in earnings reflects lower operating expenses and taxes that offset lower revenues from system sales and off-system sales. The increase in Enogex earnings is attributable to higher volumes in gas processing, revenues from gas storage operations, improved natural gas prices, including the favorable impact of hedging operations and increased activity in energy trading. Earnings per average common share decreased from $0.59 to $0.49 and increased from $0.58 to $0.63 in the current periods. REVENUES Total operating revenues increased $38.2 million or 9.3 percent and $129.1 million or 18.4 percent in the current periods. These increases reflect significantly increased Enogex energy trading revenues, partially offset by decreased electric sales by OG&E. Unfavorable weather in the OG&E electric service area and reduced off-system sales resulted in reduced electric utility revenues of $21.9 million and $8.4 million. Enogex revenues increased $60.4 million or 79.1 percent and $138.0 or 108.9 percent in the current periods largely due to increased sales activity at its OGE Energy Resources trading and energy services unit, but also reflecting revenues from gas storage operations, the new Ozark pipeline project, processing segment volume increases and better natural gas prices including hedging revenues in its Enogex Exploration unit. EXPENSES Total operating expenses increased $57.9 million or 18.1 percent in the three months ended June 30, 1999. This increase was primarily due to increased gas and electricity purchased for resale and purchased power. Enogex's gas and electricity purchased for resale pursuant to its gas and electric marketing operations increased $55.1 million or 98.8 percent in the three months ended June 30, 1999, due to increased volumes of natural gas purchased for resale to third parties and increased volumes of electricity purchased for resale to third parties. OG&E's purchased power costs increased $4.5 million or 7.8 percent primarily due to the availability of electricity at favorable prices. 6
In the six months ended June 30, 1999, total operating expenses were up $126.7 million or 21.3 percent due to increased gas and electricity purchased for resale ($126.8 million or 148.3 percent) and purchased power (7.3 million or 6.4 percent). This increase was due to the same factors as mentioned above for the three months ended June 30, 1999. Fuel expense decreased $3.3 million or 4.2 percent and $5.2 million or 3.8 percent in the current periods primarily due to decreased generation levels, resulting from unfavorable weather in the OG&E electric service area and the significant reduction in off-system sales. 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 other fees OG&E pays Enogex, which OG&E seeks to recover through the fuel adjustment clause or other tariffs. Other operation and maintenance increased $0.1 million or 0.1 percent and decreased $4.9 million or 3.1 percent. The $4.9 million decrease in the six months ended June 30, 1999, was due to reduced miscellaneous corporate expenses. This decrease was partially offset by 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. As previously reported, the Company has estimated a total storm cost of approximately $15 million of which approximately 25 percent will be expensed and the remainder capitalized. Depreciation and amortization increased $1.2 million or 3.2 percent and $2.4 million or 3.2 percent during the current periods due to an increase in depreciable property. Interest charges increased $3.2 million or 20.2 percent and $5.6 million or 17.5 percent primarily due to higher interest charges at Enogex and costs associated with increased short-term debt (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 and to acquire new facilities or replace or expand existing 7
facilities in its non-utility businesses, and to some extent, for satisfying maturing debt. Capital expenditures of $89.3 million for the six months ended June 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 periods. The Company's combined cash and cash equivalents increased approximately $1.6 million during the six months ended June 30, 1999. The increase reflects the Company's cash flow from operations and short-term debt, partially offset by the retirement of long-term debt, construction expenditures, Enogex acquisition, redemption of common stock and dividend payments. As discussed previously, on July 1, 1999, Enogex completed its acquisition of Transok for $701 million, which includes assumption of $173 million of long-term debt. The purchase of Transok was temporarily funded through a new revolving credit agreement with a consortium of banks with the First National Bank of Chicago serving as agent. The Company expects that this financing will be replaced with permanent financing by June 30, 2000. 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. 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, 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 8
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 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. The Company is making significant progress towards the full implementation of the enterprise-wide software system for customer systems. A portion of our customer base began to be phased in to the new system in June of 1999. 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: 9
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 surveys are being sent to vendors that have not responded to our original requests for information (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 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 plans to participate in the September 9, 1999, NERC drill. 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 10
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. 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 by $29 million a year compared to June 1999 rates, resulting in $83 million in savings for customers during the 30-month period ending July 1, 2002. The rates would be fixed and guaranteed. This would be accomplished, in part, through the elimination of OG&E's 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. 11
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. 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 generation efficiency performance 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. 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, 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 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 rulemaking process that will provide for customer choice in Oklahoma by July 1, 2002. 12
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, 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. Origen is engaged in the development of new products. Origen's results to date have not been material to the Company. The following is the Company's business segment results for the current periods. <TABLE> <CAPTION> 3 Months Ended 6 Months Ended June 30 June 30 1999 1998 1999 1998 -------------------------------- --------------------------------- (DOLLARS IN THOUSANDS) - ------------------------------------------------------------------------------------------------------------------------------------ <S> <C> <C> <C> <C> Operating Information: Operating Revenues Electric utility......................................... $ 314,102 $ 336,017 $ 564,246 $ 572,662 Non-utility.............................................. 191,967 123,668 346,317 203,160 Intersegment revenues (A)................................ (55,208) (47,064) (81,497) (75,834) -------------- -------------- -------------- -------------- Total.................................................. $ 450,861 $ 412,621 $ 829,066 $ 699,988 -------------- -------------- -------------- -------------- Net Income Electric utility......................................... $ 33,729 $ 45,879 $ 43,919 $ 43,800 Non-utility.............................................. 4,015 1,986 4,957 3,725 - ------------------------------------------------------------------------------------------------------------------------------------ Total.................................................. $ 37,744 $ 47,865 $ 48,876 $ 47,525 - ------------------------------------------------------------------------------------------------------------------------------------ <FN> (A) Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. </FN> </TABLE> 13
PART II. OTHER INFORMATION ITEM 1 LEGAL PROCEEDINGS Reference is made to Item 3 of the Company's 1998 Form 10-K 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. United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and Oklahoma Gas & Electric Company. In the United States District Court for the Western District of Oklahoma Case No. CIV-97-1010-L. On June 15, 1999, the Company was served with Plaintiff's Complaint. Plaintiff's action is a qui tam action under the False Claims Act. Plaintiff, Jack J. Grynberg, as individual Relator on behalf of the United States Government, alleges: (1) each of the named Defendants have improperly and intentionally mismeasured gas (both volume and BTU content) purchased from federal and Indian lands which have resulted in the under-reporting and underpayment of gas royalties owed to the Federal Government; (2) certain provisions generally found in gas purchase contracts are improper; (3) transactions by affiliated companies are not arms-length; (4) excess processing cost deduction; and (5) failure to account for production separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties which he claims should have been paid to the Federal Government, some percentage of which Grynberg, as Relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring Defendants to measure gas the way Grynberg contends is the better way to do so; and (e) interest costs and attorneys' fees. Plaintiff has filed over 70 other cases naming over 300 other defendants in various Federal Courts across the country containing nearly identical allegations. In qui tam actions, the United States government can intervene and take over such actions from the Relator. The Department of Justice, on behalf of the United States government, has decided not to intervene in this action or any of the other "Grynberg qui tam actions." There are currently pending before the court various motions filed by the parties. At this time, the Company cannot predict the ultimate outcome of this proceeding, but the Company does not believe this matter will have a material adverse impact on the Company's consolidated financial position or results of operations. ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (a) The Company's Annual Meeting of Shareowners was held on May 27, 1999 (b) Not applicable. (c) The matters voted upon and the results of the voting at the Annual Meeting 14
were as follows: (1) The Shareowners voted to elect the Company's nominees for election to the Board of Directors as follows: Herbert H. Champlin - 62,040,414 votes for election and 860,654 votes withheld Martha W. Griffin - 61,971,288 votes for election and 929,780 votes withheld Donald H. White - 61,962,979 votes for election and 938,089 votes withheld ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits 2.01 - Purchase Agreement, dated as of May 14, 1999, by and between Tejas Gas, LLC and Enogex Inc. 27.01 - Financial Data Schedule. (b) Reports on Form 8-K (1) Item 5. Other Events, dated May 20, 1999. 15
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 Chief Accounting Officer) August 13, 1999 16
<TABLE> EXHIBIT INDEX <CAPTION> EXHIBIT INDEX DESCRIPTION - ------------- ----------- <S> <C> 2.01 Purchase Agreement, dated as of May 14, 1999, by and between Tejas Gas, LLC and Enogex Inc. 27.01 Financial Data Schedule </TABLE>