================================================================================ FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 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 April 30, 1999. ================================================================================
OGE ENERGY CORP. PART I. FINANCIAL INFORMATION ITEM 1 FINANCIAL STATEMENTS CONSOLIDATED STATEMENTS OF INCOME (Unaudited) 3 MONTHS ENDED MARCH 31 1999 1998 -------------- -------------- (THOUSANDS EXCEPT PER SHARE DATA) OPERATING REVENUES: Electric utility......................................... $ 250,144 $ 236,645 Non-utility subsidiaries................................. 128,061 50,722 -------------- -------------- Total operating revenues............................... 378,205 287,367 -------------- -------------- OPERATING EXPENSES: Fuel..................................................... 57,681 59,614 Purchased power.......................................... 59,124 56,325 Gas and electricity purchased for resale................. 101,457 29,730 Other operation and maintenance.......................... 74,344 79,294 Depreciation............................................. 38,263 37,050 Taxes other than income.................................. 13,261 13,325 -------------- -------------- Total operating expenses............................... 344,130 275,338 -------------- -------------- OPERATING INCOME........................................... 34,075 12,029 -------------- -------------- OTHER INCOME (EXPENSES): Interest charges......................................... (18,300) (15,940) Other, net............................................... 810 1,727 -------------- -------------- Total other income (expenses).......................... (17,490) (14,213) -------------- -------------- EARNINGS BEFORE INCOME TAXES............................... 16,585 (2,184) PROVISION FOR INCOME TAXES................................. 5,453 (1,844) -------------- -------------- NET INCOME (LOSS).......................................... 11,132 (340) PREFERRED DIVIDEND REQUIREMENTS............................ --- 733 -------------- -------------- EARNINGS (LOSS) AVAILABLE FOR COMMON....................... $ 11,132 $ (1,073) ============== ============== AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS).............. 78,267 80,772 EARNINGS (LOSS) PER AVERAGE COMMON SHARE................... $ 0.14 $ (0.01) ============== ============== EARNINGS PER AVERAGE COMMON SHARE - ASSUMING DILUTION...... $ 0.14 $ (0.01) ============== ============== DIVIDENDS DECLARED PER SHARE............................... $ 0.3325 $ 0.3325
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF. 1CONSOLIDATED BALANCE SHEETS (Unaudited) MARCH 31 DECEMBER 31 1999 1998 ------------- -------------- (DOLLARS IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents..................................... $ 2,782 $ 378 Accounts receivable - customers, less reserve of $2,736 and $3,342, respectively........................................ 134,956 141,235 Accrued unbilled revenues..................................... 22,600 22,500 Accounts receivable - other................................... 9,342 12,902 Fuel inventories, at LIFO cost................................ 63,714 57,288 Materials and supplies, at average cost....................... 30,888 29,734 Prepayments and other......................................... 22,518 31,551 Accumulated deferred tax assets............................... 7,755 7,811 ------------- -------------- Total current assets........................................ 294,555 303,399 ------------- -------------- OTHER PROPERTY AND INVESTMENTS, at cost......................... 34,284 31,682 ------------- -------------- PROPERTY, PLANT AND EQUIPMENT: In service.................................................... 4,413,235 4,391,232 Construction work in progress................................. 64,582 50,039 ------------- -------------- Total property, plant and equipment......................... 4,477,817 4,441,271 Less accumulated depreciation............................. 1,950,510 1,914,721 ------------- -------------- Net property, plant and equipment............................. 2,527,307 2,526,550 ------------- -------------- DEFERRED CHARGES: Advance payments for gas...................................... 14,900 15,000 Income taxes recoverable future rates......................... 40,471 40,731 Other......................................................... 67,277 66,567 ------------- -------------- Total deferred charges...................................... 122,648 122,298 ------------- -------------- TOTAL ASSETS.................................................... $ 2,978,794 $ 2,983,929 ============= ============== CAPITALIZATION AND LIABILITIES CURRENT LIABILITIES: Short-term debt............................................... $ 226,800 $ 119,100 Accounts payable.............................................. 94,802 96,936 Dividends payable............................................. 25,869 26,865 Customers' deposits........................................... 24,127 23,985 Accrued taxes................................................. 27,282 30,500 Accrued interest.............................................. 21,226 21,081 Long-term debt due within one year............................ 2,000 2,000 Other......................................................... 29,411 50,266 ------------- -------------- Total current liabilities................................... 451,517 370,733 ------------- -------------- LONG-TERM DEBT.................................................. 935,616 935,583 -------------- -------------- DEFERRED CREDITS AND OTHER LIABILITIES: Accrued pension and benefit obligation........................ 19,745 17,952 Accumulated deferred income taxes............................. 527,744 531,940 Accumulated deferred investment tax credits................... 66,441 67,728 Other......................................................... 29,414 16,611 ------------- -------------- Total deferred credits and other liabilities................ 643,344 634,231 ------------- -------------- STOCKHOLDERS' EQUITY: Common stockholders' equity................................... 433,286 513,614 Retained earnings............................................. 515,031 529,768 ------------- -------------- Total stockholders' equity.................................. 948,317 1,043,382 ------------- -------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,978,794 $ 2,983,929 ============= ==============
THE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF. 2CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) 3 MONTHS ENDED MARCH 31 1999 1998 -------------- -------------- (DOLLARS IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income (Loss).................................................. $ 11,132 $ (340) Adjustments to Reconcile Net Income (Loss) to Net Cash: Depreciation..................................................... 38,263 37,050 Deferred income taxes and investment tax credits, net............ (4,884) (379) Change in Certain Current Assets and Liabilities: Accounts receivable - customers................................ 6,279 20,111 Accrued unbilled revenues...................................... (100) 7,700 Fuel, materials and supplies inventories....................... (7,580) (12) Accumulated deferred tax assets................................ 56 1,128 Other current assets........................................... 12,593 247 Accounts payable............................................... (2,134) (6,948) Accrued taxes.................................................. (3,218) (18,078) Accrued interest............................................... 145 (4,547) Other current liabilities...................................... (21,709) (2,670) Other operating activities....................................... 12,897 3,262 -------------- -------------- Net cash provided from operating activities.................. 41,740 36,524 -------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures............................................... (40,838) (28,132) Other investment activities........................................ --- (58,343) -------------- -------------- Net cash used in investing activities........................ (40,838) (86,475) -------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES: Retirement of long-term debt....................................... --- (25,000) Proceeds from long-term debt....................................... --- 5,690 Short-term debt, net............................................... 107,700 142,100 Redemption of common stock......................................... (80,330) --- Redemption of preferred stock...................................... --- (49,266) Cash dividends declared on preferred stock......................... --- (733) Cash dividends declared on common stock............................ (25,868) (26,857) -------------- -------------- Net cash provided by financing activities.................... 1,502 45,934 -------------- -------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS................. 2,404 (4,017) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 378 4,257 -------------- -------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 2,782 $ 240 ============== ============== - -------------------------------------------------------------------------------------------------------------- SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION CASH PAID DURING THE PERIOD FOR: Interest (net of amount capitalized)............................. $ 15,385 $ 18,721 Income taxes..................................................... $ 4,150 $ 7,180 - --------------------------------------------------------------------------------------------------------------
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 March 31, 1999, and December 31, 1998, and the results of operations and the changes in cash flows for the periods ended March 31, 1999, and March 31, 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 March 1998, the American Institute of Certified Public Accountants ("AICPA") issued Statement of Position ("SOP") 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use". Adoption of SOP 98-1 is required for fiscal years beginning after December 15, 1998. The Company adopted this new standard effective January 1, 1999. Adoption of this new standard did not have a material impact on consolidated financial position or results of operations. 3. 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". Adoption of SFAS No. 133 is required for financial statements for periods beginning after June 15, 1999. The Company will adopt this new standard effective January 1, 2000, and management believes the adoption of this new standard will not have a material impact on its consolidated financial position or results of operation. 4. In December 1998, the FASB Emerging Issues Task Force reached consensus on Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities ("EITF Issue 98-10"). EITF Issue 98-10 is effective for fiscal years beginning after December 15, 1998. EITF Issue 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet, with changes in fair value included in earnings. The Company adopted this new Issue effective January 1, 1999. Adoption of this new 4
Issue did not have a material impact on consolidated financial position or results of operations. 5. Effective June 15, 1998, the outstanding shares of the Company's common stock were split on a two-for-one basis. The new shares were issued to shareowners of record on June 1, 1998. All references in the accompanying financial statements to the number of common shares and per share amounts for the three-month period ended March 31, 1998 have been restated to reflect the stock split. 6. 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. ITEM 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS OVERVIEW The following discussion and analysis presents factors which affected the results of operations for the three months ended March 31, 1999 (the "current period"), and the financial position as of March 31, 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"). For the three months ended March 31, 1999, approximately 66 percent of the Company's revenues consisted of regulated sales of electricity by OG&E, a public utility, while the remaining 34 percent was provided by the non-utility operations of Enogex. Origen recently was formed and its 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. Unless indicated otherwise, all comparisons are with the corresponding period of the prior year. 5
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. On Monday, May 3, 1999, tornadoes and severe thunderstorms inflicted heavy damage to the power delivery system of OG&E. At the peak of the storms that started Monday afternoon, 116,000 OG&E customers were estimated to have lost electricity. Authorities have estimated that as many as 10,000 homes and businesses were damaged by these storms. Although the Company is still assessing the damage, current estimates place the storm damage cost at approximately $12 million to $15 million, of which approximately 75 percent will be capitalized and 25 percent expensed. The damage sustained by OG&E's power delivery system included numerous distribution poles and lines. The utility's power transmission system was also hard-hit. The storms knocked out more than 40 of the towers and high line systems that transmit electricity from OG&E's power plants to the communities they serve. Despite this damage, OG&E was quickly able to deliver power to all of its substations, some of which were also damaged. EARNINGS The current period net income of $11.1 million represents an increase of $11.5 million. Of the $11.5 million increase, approximately $12.3 million was attributable to OG&E and $0.9 million was attributable to Enogex. These increases were partially offset by losses from other operations of the Company. As explained below, OG&E's increase in earnings was primarily attributable to higher revenues from increased sales to OG&E customers ("system sales") and lower operating expenses; Enogex's earnings increased due to increased volumes in all business segments. Earnings per average common share increased to $0.14 from a net loss of $.01 in the prior period. REVENUES Total operating revenues increased $90.8 million or 31.6 percent. The increase was attributable to increased electric sales by OG&E and significantly increased Enogex revenues. Increased electric sales by OG&E were primarily attributable to continued growth in the OG&E electric service area. Growth in the electric service area resulted in increased electric utility revenues of $13.5 million or 5.7 percent and a 4.0 percent increase in kilowatt-hour system sales. The increase in system sales was more than offset by a significant reduction in sales to other utilities and power marketers ("off-system sales"). However, off-system sales are generally 6
priced at much lower prices per kilowatt-hour and have less impact on operating revenues and earnings than system sales. Enogex revenues increased $77.6 million or 154.0 percent in the current period, largely due to increased sales activity at its OGE Energy Resources trading and energy services unit (particularly in the area of power marketing which OGE Energy Resources expanded into in March, 1998) and due to the integration of additional pipelines acquired in Arkansas and Texas in 1998. Increased volumes in all Enogex business segments were partially offset by depressed commodity prices in the natural gas and natural gas liquids markets. EXPENSES Total operating expenses increased $68.8 million or 25.0 percent in the current period. 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 electricity marketing operations increased $71.7 million or 241.3 percent in the current period due to increased volumes of natural gas purchased for resale to third parties and increased volumes and prices paid by Enogex for energy purchased for resale to third parties. OG&E's purchased power costs increased $2.8 million or 5.0 percent due to the availability of electricity at favorable prices. Depreciation and amortization increased $1.2 million or 3.3 percent due to an increase in depreciable property and higher oil and gas production volumes (based on units of production depreciation method). Fuel expense decreased $1.9 million or 3.2 percent primarily due to the availability of electricity for purchase at favorable prices and decreased generation levels, resulting from 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 Inc. 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 decreased $5.0 million or 6.2 percent, primarily due to reduced contract labor and miscellaneous corporate expenses. Interest charges increased $2.4 million or 14.8 percent primarily due to higher interest charges at Enogex and costs associated with increased short-term debt (See "Liquidity and Capital Requirements"). These increases were partially offset by lower interest charges at OG&E. 7
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 facilities in its non-utility businesses, and to some extent, for satisfying maturing debt. The Company's capital expenditures for the current period of $41 million 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 $2.4 million during the three months ended March 31, 1999. The increase reflects the Company's cash flow from operations, net of short-term debt, construction expenditures, redemption of common stock and dividend payments. 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" and Item 5 "Other Information" of this Form 10-Q and to "Management's Discussion and Analysis" and Notes 10 and 11 of Notes to the Consolidated Financial Statements in the Company's 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 Year 2000 may cause systems, including those of the Company, its customers, suppliers, business partners and neighboring utilities to process critical financial and operational 8
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 will be 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 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 substantially 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 efforts are ongoing and even though contingency planning is a normal part of our business, plans are being prepared to include specific activities with regard to Y2K issues (Phase III). 9
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 will be upgraded with Y2K ready operating systems before the turn of the century. For embedded and plant operational systems, the Company has generally completed the evaluative process and is commencing corrective plans. In particular, the Company's Energy Management System ("EMS") that monitors transmission interconnections and automatically signals generation output changes, has been contracted for replacement in 1999. Equipment is currently being installed and software is being configured. The Company is also participating in an "Electric System Readiness Assessment" program, which provides monthly reports to the Southwest Power Pool ("SPP") and the North American Electric Reliability Council ("NERC"). In April 1999, the Company also participated in a nationwide communications test as a part of the electric utility industry's Y2K readiness preparation. The purpose of the test 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 overall success of the test is not yet known, however, communications in the SPP went smoothly with only minor problems noted. The responses from all participating companies are being compiled for an industry-wide status report to the Department of Energy ("DOE"). Also, 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. 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. In addition to the $1 million spent to date for Y2K issues, since 1995 the Company has spent in excess of $29 million on the mainframe conversion, the enterprise software installations and the 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 10
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 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 is scheduled to be presented to the APSC on May 18, 1999. An order is anticipated in the near future. 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. 11
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 geothermal heat pump systems and 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 period. (DOLLARS IN THOUSANDS) 1999 1998 ================================================================================ Operating Information: Operating Revenues Electric utility............................... $ 250,144 $ 236,645 Non-utility.................................... 154,350 79,493 Intersegment revenues (A)...................... (26,289) (28,771) - -------------------------------------------------------------------------------- Total........................................ $ 378,205 $ 287,367 ================================================================================ Net Income Electric utility............................... $ 10,189 $ (2,079) Non-utility.................................... 943 1,739 - -------------------------------------------------------------------------------- Total........................................ $ 11,132 $ (340) ================================================================================ (A) Intersegment revenues are recorded at prices comparable to those of unaffiliated customers and are affected by regulatory considerations. 12
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. 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. ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits 27.01 - Financial Data Schedule. (b) Reports on Form 8-K None 13
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) May 14, 1999 14
EXHIBIT INDEX EXHIBIT INDEX DESCRIPTION - ------------- ----------- 27.01 Financial Data Schedule
UT 1,000 3-MOS MAR-31-1999 MAR-31-1999 PER-BOOK 2,527,307 34,284 294,555 122,648 0 2,978,794 778 432,508 515,031 948,317 0 0 935,616 0 0 226,800 2,000 0 11,202 2,903 851,956 2,978,794 378,205 5,453 344,130 344,130 34,075 810 34,885 18,300 11,132 0 11,132 25,868 15,022 41,740 0.14 0.14