10-Q 1 0001.txt 2ND QUARTER 2000 FORM 10-Q ================================================================================ 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, 2000 OR | | TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-1097 Oklahoma Gas and Electric Company meets the conditions set forth in general instruction H(1) (a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format permitted by general instruction H (2). OKLAHOMA GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) Oklahoma 73-0382390 (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 40,378,745 Shares of Common Stock, par value $2.50 per share, outstanding as of July 31, 2000. ================================================================================
OKLAHOMA GAS AND ELECTRIC COMPANY PART I. FINANCIAL INFORMATION ITEM 1 FINANCIAL STATEMENTS STATEMENTS OF INCOME (Unaudited) 3 Months Ended 6 Months Ended June 30 June 30 -------------------------------- --------------------------------- 2000 1999 2000 1999 -------------- -------------- -------------- -------------- (THOUSANDS EXCEPT PER SHARE DATA) OPERATING REVENUES......................................... $ 335,573 $ 314,102 $ 580,905 $ 564,246 -------------- -------------- -------------- -------------- OPERATING EXPENSES: Fuel..................................................... 106,957 85,698 179,206 153,656 Purchased power.......................................... 62,124 62,267 122,666 121,390 Other operation and maintenance.......................... 69,083 65,012 134,336 120,121 Depreciation and amortization............................ 30,363 29,553 60,514 58,856 Taxes other than income.................................. 11,365 10,875 22,734 22,227 -------------- -------------- -------------- -------------- Total operating expenses............................... 279,892 253,405 519,456 476,250 -------------- -------------- -------------- -------------- OPERATING INCOME........................................... 55,681 60,697 61,449 87,996 -------------- -------------- -------------- -------------- OTHER INCOME (EXPENSES), net............................... (767) 493 (1,401) (34) -------------- -------------- -------------- -------------- EARNINGS BEFORE INTEREST AND TAXES......................... 54,914 61,190 60,048 87,962 INTEREST INCOME (EXPENSES): Interest income.......................................... 144 277 289 500 Interest on long-term debt............................... (11,611) (11,213) (22,870) (22,246) Other interest charges................................... 785 (586) 307 (849) -------------- -------------- -------------- -------------- Net interest income (expenses)......................... (10,682) (11,522) (22,274) (22,595) -------------- -------------- -------------- -------------- EARNINGS BEFORE INCOME TAXES............................... 44,232 49,668 37,774 65,367 PROVISION FOR INCOME TAXES................................. 14,671 15,939 11,439 21,449 -------------- -------------- -------------- -------------- NET INCOME................................................. $ 29,561 $ 33,729 $ 26,335 $ 43,918 ============== ============== ============== ============== AVERAGE COMMON SHARES OUTSTANDING.......................... 40,379 40,379 40,379 40,379 EARNINGS PER AVERAGE COMMON SHARE.......................... $ 0.73 $ 0.84 $ 0.65 $ 1.09 ============== ============== ============== ============== DIVIDENDS DECLARED PER SHARE............................... $ 0.641 $ 0.641 $ 1.282 $ 1.282 THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
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BALANCE SHEETS (UNAUDITED) JUNE 30 DECEMBER 31 2000 1999 ------------- -------------- (DOLLARS IN THOUSANDS) ASSETS CURRENT ASSETS: Cash and cash equivalents..................................... $ 308 $ 1,779 Accounts receivable - customers, less reserve of $5,222 and $3,405, respectively........................................ 102,748 96,212 Accrued unbilled revenues..................................... 58,300 40,200 Accounts receivable - other................................... 6,783 8,074 Fuel inventories, at LIFO cost................................ 82,203 75,465 Materials and supplies, at average cost....................... 31,308 30,311 Prepayments and other......................................... 3,697 3,100 Accumulated deferred tax assets............................... 7,309 7,681 ------------- -------------- Total current assets........................................ 292,656 262,822 ------------- -------------- OTHER PROPERTY AND INVESTMENTS, at cost......................... 15,006 12,731 ------------- -------------- PROPERTY, PLANT AND EQUIPMENT: In service.................................................... 3,770,258 3,747,690 Construction work in progress................................. 66,218 15,575 ------------- -------------- Total property, plant and equipment......................... 3,836,476 3,763,265 Less accumulated depreciation............................. 1,853,648 1,810,898 ------------- -------------- Net property, plant and equipment............................. 1,982,828 1,952,367 ------------- -------------- DEFERRED CHARGES: Advance payments for gas...................................... 11,800 11,800 Income taxes recoverable through future rates................. 39,173 39,692 Other......................................................... 41,329 41,248 ------------- -------------- Total deferred charges...................................... 92,302 92,740 ------------- -------------- TOTAL ASSETS.................................................... $ 2,382,792 $ 2,320,660 ============= ============== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable - affiliates................................. $ 173,197 $ 75,674 Accounts payable - other...................................... 33,427 36,231 Customers' deposits........................................... 22,087 22,137 Accrued taxes................................................. 18,947 19,545 Accrued interest.............................................. 14,472 14,573 Other......................................................... 23,585 20,893 ------------- -------------- Total current liabilities................................... 285,715 189,053 ------------- -------------- LONG-TERM DEBT.................................................. 703,112 703,045 -------------- -------------- DEFERRED CREDITS AND OTHER LIABILITIES: Accrued pension and benefit obligation........................ 16,112 14,886 Accumulated deferred income taxes............................. 442,355 450,028 Accumulated deferred investment tax credits................... 60,004 62,578 Other......................................................... 11,802 11,933 ------------- -------------- Total deferred credits and other liabilities................ 530,273 539,425 ------------- -------------- STOCKHOLDERS' EQUITY: Common stockholders' equity................................... 512,446 512,446 Retained earnings............................................. 351,246 376,691 ------------- -------------- Total stockholders' equity.................................. 863,692 889,137 ------------- -------------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY...................... $ 2,382,792 $ 2,320,660 ============= ============== THE ACCOMPANYING NOTES TO FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
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STATEMENTS OF CASH FLOWS (UNAUDITED) 6 MONTHS ENDED JUNE 30 2000 1999 -------------- -------------- (DOLLARS IN THOUSANDS) CASH FLOWS FROM OPERATING ACTIVITIES: Net Income......................................................... $ 26,335 $ 43,918 Adjustments to Reconcile Net Income to Net Cash: Depreciation and amortization.................................... 60,514 58,856 Deferred income taxes and investment tax credits, net............ (8,949) (12,734) Change in Certain Current Assets and Liabilities: Accounts receivable - customers................................ (6,536) 2,499 Accrued unbilled revenues...................................... (18,100) (36,500) Fuel, materials and supplies inventories....................... (7,735) (21,481) Accumulated deferred tax assets................................ 372 (636) Other current assets........................................... 694 14,325 Accounts payable............................................... 64,438 (3,710) Accrued taxes.................................................. (598) 332 Accrued interest............................................... (101) (485) Other current liabilities...................................... 2,642 (15,495) Other operating activities....................................... (28,083) 19,587 -------------- -------------- Net cash provided from operating activities.................. 84,893 48,476 -------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures............................................... (64,865) (59,683) -------------- -------------- Net cash used in investing activities........................ (64,865) (59,683) -------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES: Short-term debt, net............................................... 30,281 62,810 Cash dividends declared on common stock............................ (51,780) (51,738) -------------- -------------- Net cash provided by (used in) financing activities.......... (21,499) 11,072 -------------- -------------- NET DECREASE IN CASH AND CASH EQUIVALENTS............................ (1,471) (135) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..................... 1,779 312 -------------- -------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD........................... $ 308 $ 177 ============== ============== -------------------------------------------------------------------------------------------------------------- SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION CASH PAID DURING THE PERIOD FOR: Interest (net of amount capitalized)............................. $ 24,760 $ 21,215 Income taxes..................................................... $ 5,115 $ 16,579 -------------------------------------------------------------------------------------------------------------- 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 FINANCIAL STATEMENTS ARE AN INTEGRAL PART HEREOF.
3 NOTES TO FINANCIAL STATEMENTS (Unaudited) 1. The condensed financial statements included herein have been prepared by Oklahoma Gas and Electric Company (the "Company"), without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to make the information presented not misleading. In the opinion of management, all adjustments necessary to present fairly the financial position of the Company as of June 30, 2000, and December 31, 1999, and the results of operations and the changes in cash flows for the periods ended June 30, 2000, and June 30, 1999, have been included and are of a normal recurring nature. Certain amounts have been reclassified on the financial statements to conform with the 2000 presentation. The results of operations for such interim periods are not necessarily indicative of the results for the full year. It is suggested that these condensed financial statements be read in conjunction with the financial statements and the notes thereto included in the Company's Form 10-K for the year ended December 31, 1999. 2. The Company is a regulated public utility engaged in the generation, transmission and distribution of electricity to retail and wholesale customers. The Company is a wholly-owned subsidiary of OGE Energy Corp. ("Energy Corp.") which is a holding company incorporated in the State of Oklahoma and located in Oklahoma City, Oklahoma. 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", 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". As a result of SFAS No. 137, adoption of SFAS No. 133 is now required for financial statements for periods beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities", which amends the accounting and reporting standards of SFAS No. 133 for certain derivative instruments and hedging activities. SFAS No. 133 sweeps in a broad population of transactions and changes the previous accounting definition of a derivative instrument. Under SFAS No. 133, every derivative instrument is recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The Company will prospectively 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 financial position or results of operation. 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, 2000 (respectively, the "current periods"), and the financial position as of June 30, 2000, of the Company. Revenues from sales of electricity are somewhat seasonal, with a large portion of the Company's annual electric revenues occurring during the summer months when the electricity needs of its customers increase. Because of seasonal fluctuations and other factors, the results of one interim period are not necessarily indicative of results to be expected for the year. Actions of the regulatory commissions that set the Company's electric rates will continue to affect financial results. Unless indicated otherwise, all comparisons are with the corresponding periods of the prior year. 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; regulatory decisions and other risk factors listed in the Company's Form 10-K for the year ended December 31, 1999, 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 $4.2 million or 12.4 percent and $17.6 million or 40.0 percent in the current periods. As explained below, the Company's decrease in earnings was primarily attributable to increased operating expenses. Earnings per average common share decreased from $0.84 to $0.73 and from $1.09 to $0.65 in the current periods. REVENUES Operating revenues increased $21.5 million or 6.8 percent and $16.7 million or 3.0 percent in the current periods. These increases resulted primarily from the recovery of higher priced fuel costs. 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 the Company's customers through automatic fuel adjustment clauses. The automatic fuel adjustment clauses are subject to periodic review by the Oklahoma Corporation Commission ("OCC"), the Arkansas Public Service Commission ("APSC") and the Federal Energy Regulatory Commission ("FERC"). Enogex Inc. ("Enogex"), an affiliated company, owns and operates a pipeline business that delivers natural gas to the generating stations of the 5 Company. The OCC, the APSC and the FERC have authority to examine the appropriateness of any gas transportation charges or other fees the Company pays Enogex, which the Company seeks to recover through the fuel adjustment clause or other tariffs. See "Regulation and Rates." Revenue was unfavorably affected in the current periods by approximately $3.6 million and $7.7 million, due to modifications of the Generation Efficiency Performance Rider ("GEP Rider") and by approximately $2.8 million and $3.6 million, due to lower recoveries under the Acquisition Premium Credit Rider ("APC Rider"). See "Regulation and Rates" - "Recent Regulatory Matters." Increases in kilowatt-hour sales of 5.4 percent and 4.8 percent to Company customers ("system sales") in the current periods were primarily attributable to more favorable weather in the Company's service area, which partially offset the impact of the GEP Rider modifications and the APC Rider. Kilowatt-hour sales to other utilities and power marketers ("off-system sales") decreased 44.7 percent in the three months ended June 30, 2000 and increased 5.2 percent in the six-month period ended June 30, 2000. Off-system sales generally occur at much lower prices per kilowatt-hour and have less impact on operating revenues and earnings than system sales. EXPENSES Total operating expenses increased $26.5 million or 10.5 percent and $43.2 million or 9.1 percent in the current periods. These increases were primarily due to increased fuel expense and other operation and maintenance. Fuel expense increased $21.3 million or 24.8 percent and $25.6 million or 16.6 percent in the current periods primarily due to a significant increase in the average cost of fuel (particularly natural gas) and slightly higher generation levels. Purchased power costs remained relatively constant in the three months ended June 30, 2000 and increased $1.3 million or 1.1 percent in the six months ended June 30, 2000, primarily due to an increase in transmission charges associated with off-system purchases. Other operation and maintenance increased $4.1 million or 6.3 percent and $14.2 million or 11.8 percent in the current periods primarily due to increased labor, employee benefit costs and miscellaneous corporate expenses. Depreciation and amortization increased $0.8 million or 2.7 percent and $1.7 million or 2.8 percent during the current periods due to an increase in depreciable property. Other income decreased $1.3 million and $1.4 million in the current periods due to a decrease in margins on contract work. Interest charges decreased $0.8 million or 7.3 percent and $0.3 million or 1.4 percent in the current periods due to an increase in the allowance for borrowed funds used during construction. 6 LIQUIDITY AND CAPITAL REQUIREMENTS The Company's primary needs for capital are related to construction of new facilities to meet anticipated demand for utility service, to replace or expand existing facilities and to some extent, for satisfying maturing debt. Capital expenditures of $64.9 million for the six months ended June 30, 2000, were financed with internally generated funds and short-term borrowings. The Company meets its cash needs through a combination of internally generated funds, permanent financing and short-term borrowings. The Company expects that internally generated funds will be adequate during 2000 to meet anticipated construction expenditures, while maturities of long-term debt will require permanent financings, with the amount and type dependent on market conditions at the time. The Company has long-term debt of $110 million maturing in October 2000, which it expects to refinance and accordingly, this debt is reflected as non-current on the accompanying balance sheets. Short-term borrowings will continue to be used to meet temporary cash requirements. The Company will continue to use short-term borrowings from Energy Corp. to meet its temporary cash requirements. The Company has the necessary regulatory approvals to incur up to $400 million in short-term borrowings at any one time. In January 2000, Energy Corp. increased its line of credit from $200 million to $300 million, with $200 million to expire on January 15, 2001, and $100 million to expire on January 15, 2004. The Company had $85.7 million and $55.5 million in short-term debt outstanding at June 30, 2000 and December 31, 1999, which is classified as accounts payable-affiliates on the accompanying balance sheets. The Company acquired two gas turbine generators for use at the Company's Horseshoe Lake Generating station. These two generators were brought on line on June 14 and July 16, 2000 and will each produce 44 megawatts of additional peak-load generating capacity. The total cost of this project is expected to be $47 million. In August 1999, the Company announced the reactivation of two of its generators at the Mustang Generating Station, which have been idle for several years. These two Mustang Station generators were both brought on line July 21, 2000 and together produce approximately 115 megawatts of additional peak-load generating capacity. The total cost of this reactivation project is expected to be $7 million. Together, these four generators increased the Company's generating capacity by approximately 4 percent. The Company's capital structure and cash flow remained strong throughout the current period. The Company's combined cash and cash equivalents decreased approximately $1.5 million during the six months ended June 30, 2000. The decrease reflects the Company's cash flow from operations and proceeds from short-term debt, net of construction expenditures 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" of this Form 10-Q and to "Management's Discussion and Analysis" and Notes 8 and 9 of Notes to the Financial Statements in the Company's 1999 Form 10-K. 7 REGULATION AND RATES The Company's retail electric tariffs in Oklahoma are regulated by the OCC, and in Arkansas by the APSC. The issuance of certain securities by the Company is also regulated by the OCC and the APSC. The Company's wholesale electric tariffs, short-term borrowing authorization and accounting practices are subject to the jurisdiction of the FERC. The Secretary of the Department of Energy has jurisdiction over some of the Company's facilities and operations. RECENT REGULATORY MATTERS On January 12, 2000, the OCC Staff (the "Staff") filed three applications to address various aspects of the Company's electric rates. Two of the applications were expected, while the third pertains to recoveries under the Company's fuel adjustment clause. The first application relates to the completion on March 1, 2000, of the recovery pursuant to the APC Rider of the amortization premium paid by the Company when it acquired Enogex in 1986 and the resulting removal of this $12.8 million ($10.7 million in the Oklahoma Jurisdiction) from the amounts currently being paid annually by the Company to Enogex and being recovered by the Company from its ratepayers. The Company consented to this action and in March 2000, the OCC approved the APC Rider for $10.7 million annually. The second application relates to a review of the GEP Rider, which, as part of the OCC's 1997 Order, was scheduled for review in March 2000. The Company collected approximately $20.8 million pursuant to the GEP Rider during 1999. On April 4, 2000, the Staff filed testimony proposing an annual GEP Rider incentive of $7.07 million for the Company, compared initially to $13.26 million under the then-current GEP Rider incentive factors. The GEP Rider was designed so that when the Company's average annual cost of fuel per kwh was less than 96.261 percent of the average non-nuclear fuel cost per kwh of certain other investor-owned utilities in the region, the Company was allowed to collect, through the GEP Rider, one-third of the amount by which the Company's average annual cost of fuel was below 96.261 percent of the average of the other specified utilities. If the Company's fuel cost exceeded 103.739 percent of the stated average, the Company was not allowed to recover one-third of the fuel costs above that average from Oklahoma customers. In its April 4, 2000 testimony, the Staff stated that they continued to support incentive programs that reward superior performance, but in their view the existing GEP Rider was not functioning as the Staff had originally envisioned it. In June 2000, the OCC approved the GEP Rider for $6.6 million annually and the following four changes: (i) modifying the Company's peer group to include utilities with a higher coal-to-gas generation mix; (ii) reducing the amount of fuel costs that can be recovered if the Company's costs exceed the new peer group by changing the percentage above which the Company will not be allowed to recover one-third of the fuel costs from Oklahoma customers from 103.739 percent to 101.0 percent; (iii) reducing the Company's share of cost savings as compared to its new peer group from 33 percent to 30 percent; and (iv) limiting to $10.0 million the amount of any awards paid to the Company or penalties charged to the Company. 8 The final application relates to a review of 1999 fuel cost recoveries. The Company assumes that this application also will be used to address the competitive bid process of its gas transportation service. In February 1997, the OCC issued an order (the "1997 Order") that, among other things, directed the Company to commence competitively bid gas transportation service to its gas-fired plants no later than April 30, 2000. The order also set annual compensation for the transportation services provided by Enogex to the Company at $41.3 million annually until March 1, 2000, at which time the rate would drop to $28.5 million (reflecting the completion of the recovery from ratepayers of the amortization premium paid by the Company when it acquired Enogex in 1986) and remain at that level until competitively-bid gas transportation begins. Final firm bids were submitted by Enogex and other pipelines on April 15, 1999. In July 1999, the Company filed an application with the OCC requesting approval of a performance-based rate plan for its Oklahoma retail customers from April 2000 until the introduction of customer choice for electric power in July 2002. As part of this application, the Company stated that Enogex had submitted the only viable bid ($33.4 million per year) for gas transportation to its six gas-fired power plants that were the subject of the competitive bid. As part of its application to the OCC, the Company offered to discount Enogex's bid from $33.4 million annually to $25.2 million annually. The Company has executed a new gas transportation contract with Enogex under which Enogex continues to serve the needs of the Company's power plants at a price to be paid by the Company of $33.4 million annually and, if the Company's proposal had been approved by the OCC, the Company would have recovered a portion of such amount ($25.2 million) from its ratepayers. The Staff, the Office of the Oklahoma Attorney General and a coalition of industrial customers filed testimony questioning various parts of the Company's performance-based rate plan, including the result of the competitive bid process, and suggested, among other things, that the bidding process be repeated or that gas transportation service to five of the Company's gas-fired plants be awarded to parties other than Enogex. The Staff also filed testimony stating in substance that the Company's electric rates as a whole were appropriate and did not warrant a rate review. The Company negotiated with these parties in an effort to settle all issues (including the competitive bid process) associated with its application for a performance-based rate plan. When these negotiations failed, the Company withdrew its application, which withdrawal was approved by the OCC in December 1999. The Company recently entered into a stipulation (the "Stipulation") with the Staff, the Office of the Attorney General and a coalition of industrial customers regarding the competitive bid process of its gas transportation service. The Stipulation (which, with one exception, has been signed by all parties to the proceeding) permits the Company to recover $25.2 million annually for gas transportation services to be provided by Enogex pursuant to the competitive bid process. The Stipulation is scheduled to be presented for approval to an Administrative Law Judge ("ALJ") in September 2000. The decision of the ALJ will then be presented to the OCC for its approval. STATE RESTRUCTURING INITIATIVES OKLAHOMA: As previously reported, Oklahoma enacted in April 1997 the Electric Restructuring Act of 1997 (the "Act"), which is designed to provide for choice by retail customers of their electric supplier by July 1, 2002. Various amendments to the Act were 9 enacted in 1999 and 1998. Additional implementing legislation needs to be adopted by the Oklahoma legislature, to address many specific issues associated with the Act and with deregulation. In May 2000, a bill addressing the specific issues of deregulation was passed in the Oklahoma State Senate and then was defeated in the Oklahoma House of Representatives. The Company cannot predict what, if any, legislation will be adopted at the next legislative session. Nevertheless, the Company expects to remain a competitive supplier of electricity. ARKANSAS: In April 1999, Arkansas became the 18th state to pass a law calling for restructuring of the electric utility industry at the retail level. 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 filing of unbundled rates for generation, transmission, distribution and customer service. The Company filed preliminary business separation plans with the APSC on August 8, 2000. The APSC has established a timetable to establish rules implementing the Arkansas restructuring statutes. The new law will significantly affect the Company's future Arkansas operations. The Company's electric service area includes parts of western Arkansas, including Ft. Smith, the second-largest metropolitan market in the state. NATIONAL ENERGY LEGISLATION In December 1999, FERC issued Order 2000 to advance the formation of Regional Transmission Organizations ("RTO"). The rule requires that each public utility that owns, operates or controls facilities for the transmission of electric energy in interstate commerce file by October 15, 2000, a proposal with respect to forming and participating in an RTO. The FERC also codified minimum characteristics and functions that a transmission entity must satisfy in order to be considered an RTO. The FERC's goal is to promote efficiency in wholesale electricity markets and to ensure that electricity consumers pay the lowest price possible for reliable service. The FERC expects that the RTOs will be operational by December 15, 2001. 10 PART II. OTHER INFORMATION ITEM 1 LEGAL PROCEEDINGS Reference is made to Item 3 of the Company's 1999 Form 10-K and to Part II, Item 1 of the Company's Form 10-Q for the quarter ended March 31, 2000 for a description of certain legal proceedings presently pending. There are no new significant cases to report against the Company and there have been no notable changes in the previously reported proceedings. ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (a) The Company's Annual Meeting of Shareowners was held on May 18, 2000. (b) Not applicable. (c) The matters voted upon and the results of the voting at the Annual Meeting were as follows: (1) The Shareowners voted to elect the Company's nominees for election to the Board of Directors as follows: William E. Durrett - 40,378,745 votes for election and no votes withheld H. L. Hembree, III - 40,378,745 votes for election and no votes withheld Steven E. Moore - 40,378,745 votes for election and no votes withheld ITEM 6 EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits 27.01 - Financial Data Schedule. (b) Reports on Form 8-K None 11 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. OKLAHOMA GAS AND ELECTRIC COMPANY (Registrant) By /s/ Donald R. Rowlett --------------------------------------- Donald R. Rowlett Vice President and Controller (On behalf of the registrant and in his capacity as Chief Accounting Officer) August 11, 2000 12 EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION ----------- ----------- 27.01 Financial Data Schedule