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 September 30, 2000, and December 31, 1999, and the results of operations and the changes in cash flows for the periods ended September 30, 2000, and September 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 is currently reviewing various contracts, identifying those which meet the criteria as set forth in SFAS No. 133 and SFAS No. 138. The Company will prospectively adopt these new standards effective January 1, 2001, and management believes, based upon our initial assessment, the adoption of these new standards will not have a material impact on the Company’s financial position or results of operation.

Item 2 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
            CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

OVERVIEW

     The following discussion and analysis presents factors, which affected the results of operations for the three and nine months ended September 30, 2000 (respectively, the "current periods"), and the financial position as of September 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 including the implementation of the restructuring legislation in Oklahoma and Arkansas; 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 increased $19.6 million or 22.3 percent and $2.0 million or 1.5 percent in the current periods. The increase in earnings for the three months ending September 30, 2000, was primarily attributable to higher revenues from sales to customers ("system sales") due to warmer weather in the Company's service area and the recovery of higher fuel costs. This increase was partially offset by reduced sales volume and margin from sales to other utilities and power marketers ("off-system sales"), when compared to 1999 activity. For the nine months ending September 30, 2000, the increase in earnings reflects higher revenues from system sales.

REVENUES

      Operating revenues increased $64.0 million or 13.8 percent and $80.7 million or 7.8 percent in the current periods. These increases were primarily attributable to the warmer weather and the recovery of higher fuel costs. The warmer weather was primarily responsible for increases of 6.2 percent and 5.3 percent in system sales. The increased revenue from system sales was partially offset by a 72.9 percent and 57.5 percent drop in revenue from off-system sales in the current periods. The decline in revenue from off-system sales resulted from a reduction in both volumes and prices. Further, revenue was unfavorably affected in the current periods by approximately $1.9 million and $9.6 million, due to modifications to the Generation Efficiency Performance Rider ("GEP Rider") and by approximately $3.8 million and $7.4 million, due to lower recoveries under the Acquisition Premium Credit Rider ("APC Rider"). See "Regulation and Rates" - "Recent Regulatory Matters" for related discussion.

      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 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."

EXPENSES

      Total operating expenses increased $42.2 million or 14.0 percent and $85.4 million or 11.0 percent in the current periods. For the three months ended September 30, 2000, the increase was primarily due to increased fuel expense. For the nine months ended September 30, 2000, the increase was primarily due to increased fuel expense and other operation and maintenance expenses.

      Fuel expense increased $44.9 million or 35.7 percent and $70.5 million or 25.2 percent in the current periods primarily due to a significant increase in the cost of natural gas and higher generation levels.

      Other operation and maintenance decreased $2.5 million or 3.9 percent in the three months ended September 30, 2000 and increased $11.7 million or 6.3 percent in the nine months ended September 30, 2000. In the nine months ended September 30, 2000, efforts to reduce outside services and contract labor costs were more than offset by increased labor and employee benefit costs.

      Depreciation and amortization increased $0.7 million or 2.4 percent and $2.4 million or 2.7 percent during the current periods due to an increase in depreciable property.

      Interest charges increased $1.4 million or 12.7 percent and $1.1 million or 3.2 percent in the current periods. These increases were primarily due to increased interest on variable rate, long-term debt and an increase in interest expense to Energy Corp.

      Provision for income taxes increased $1.5 million or 2.4 percent in the three months ended September 30, 2000 and decreased $8.5 million or 9.9 percent in the nine months ended September 30, 2000. For the three months ended September 30, 2000, the increase was due primarily to higher earnings and was partially offset by accruals in the prior period. For the nine months ended September 30, 2000 the decrease was primarily due to lower taxable income and reversal of accruals in the prior period.

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. The Company's capital expenditures of $101.3 million for the nine months ended September 30, 2000, were financed with internally generated funds.

      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. A $110 million series of the Company's 6.25 percent Senior Notes matured on October 15, 2000. The Company temporarily funded this transaction through short-term borrowings from Energy Corp. On October 23, 2000, the Company issued $110 million of 7.125 percent Senior Notes, Series due October 15, 2005. Net proceeds from this transaction were used to repay the temporary short-term borrowings from Energy Corp.

      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 $42.5 million and $55.5 million in short-term debt outstanding at September 30, 2000 and December 31, 1999, respectively. These amounts are classified as accounts payable-affiliates on the accompanying balance sheets.

      The Company acquired two gas turbine generators for use at its Horseshoe Lake Generating Station. These two generators were brought on line on June 14 and July 16, 2000 and each can produce approximately 44 megawatts of additional peak-load generating capacity. The total cost of this project was approximately $45 million.

      On July 21, 2000, the Company reactivated two of its generators at the Mustang Generating Station, which had been idle for several years. These two generators together produce approximately 115 megawatts of additional peak-load generating capacity. The total cost of this reactivation project was approximately $5 million. Together, these four generators at Horseshoe Lake and Mustang increased the Company's generating capacity by approximately 4 percent.

      The Company's combined cash and cash equivalents decreased approximately $1.3 million during the nine months ended September 30, 2000. The decrease reflects the Company's cash flow from operations net of short-term debt, 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.

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

      As previously reported, on January 12, 2000, the OCC Staff (the "Staff") filed three applications to address various aspects of the Company's electric rates. The first application related to the completion on March 1, 2000, of the recovery of the amortization premium paid by the Company when it acquired Enogex in 1986 and the resulting removal, pursuant to the APC Rider, of $12.8 million ($10.7 million in the Oklahoma Jurisdiction) from the 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 related 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. The GEP Rider initially 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 April 2000 testimony, the Staff stated that they continued to support incentive programs that reward superior performance, but in their view the existing GEP Rider was not functioning as they had originally envisioned it.

      In June 2000, the OCC approved the collection of $6.6 million through the GEP Rider for the time period July 1, 2000 through June 30, 2001 and approved the following four modifications to the GEP Rider: (i) changing 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.

      The final application, relating to fuel cost recoveries, was used by the Staff to address the competitive bid process of the Company's gas transportation needs. 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 removal of the APC Rider, upon 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 began. 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, was 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 was presented for approval to an Administrative Law Judge ("ALJ") in September 2000, and the ALJ recommended its approval. However, at a hearing on September 28, 2000, the OCC chose to delay the decision of the Stipulation and two of the three commissioners expressed concern over the competitive bid process. The Company cannot predict what further action the OCC may take. The Company believes that the competitive bid process was appropriate and is currently collecting $28.5 million on an annual basis through its base rates for gas transportation services from Enogex.

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 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: The Company's electric service area includes parts of western Arkansas, including Ft. Smith, the second-largest metropolitan market in the State. In April 1999, Arkansas became the 18th state to pass a law ("the restructuring law") calling for restructuring of the electric utility industry at the retail level. The restructuring law will significantly affect the Company's future Arkansas operations. The restructuring law targets customer choice of electricity providers by January 1, 2002, with the APSC having the discretion to delay such date until June 30, 2003. The restructuring law also provides that utilities owning or controlling transmission assets must transfer control of such transmission assets to an independent system operator, independent transmission company or regional transmission group, if any such organization has been approved by the FERC. Other provisions of the restructuring law permit municipal electric systems to opt in or out, permit recovery of stranded costs and transition costs and require filing of unbundled rates for generation, transmission, distribution and customer service. 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. In October 2000, the staff of APSC along with the Company and other electric utilities in Arkansas recommended to the APSC that the start date of customer choice of electric providers in Arkansas be changed from January 1, 2002 until October 1, 2003, with the APSC having the discretion to further delay implementation to October 1, 2005. It is expected that the APSC will accept the recommendations and will suggest to the Arkansas legislature that they be implemented.

National Energy Legislation

     In December 1999, the 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. In October 2000, the Southwest Power Pool ("SPP"), of which the Company is a member, filed its application with the FERC to become an RTO. The Company intends to meet its obligations under FERC Order 2000 by joining the RTO being formed by the SPP.