FERC FINANCIAL REPORT by nqj55340

VIEWS: 89 PAGES: 100

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                                   THIS FILING IS                                          1                                    Form 1 Approved
                                                                                                                                OMB NO. 1902-0021
s 1:
m                An Initial (Original)           OR          Resubmission No. -                                                 (Expires 6/30/2007)
                 Submission                                                                                                     Form 1 -F Approved
                                                                                                                                OMB NO. 1902-0029
                                                                                                                                (Expires 6/30/2007)
                                                                                                                                Form 3-Q Approved
                                                                                                                                OMB NO. 1902-0205
                                                                                                                                (Expires 6/30/2007)




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                                FERC FINANCIAL REPORT
                            FERC FORM No. 1: Annual Report of
                             Major Electric Utilities, Licensees
                               and Others and Supplemental
                            Form 3 4 : Quarterly Financial Report


                              These reports are mandatory upder the Federal Power Act, Sections 3, 4(a), 304 and 309, and
                              18 CFR 141.1 and 141.400. Fgilure to report may result in criminal fines, civil penalties and
                              other sanctions as provided by law. The Federal Energy Regulatory Commission does not
                              consider these reports to be of confidential nature




    xact Legal Name o Respondent (Company)
                     f                                                                                                 Yeadperiod of Report
    )klahoma Gas and Electric Company                                                                                  End of      2004/Q4

    :FORM NO.l/3-Q           (REV. 02-04)
                                                                 I Ernst &Young LLP
                                                                  I                                 I   Phone: (405) 278-6800
                                                                    Suite 2500                          Fax:   (405) 278-6823
                                                                    210 Park Avenue                     Fax: (405) 278-6834
                                                                    Oklahoma City, Oklahoma 73102       www.ey.com


                                       Report of Independent Auditors
               Board of Directors
               Oklahoma Gas and Electric Company

               We have audited the accompanying regulatory-lbasis balance sheets of Oklahoma Gas and
               Electric Company as of December 31, 2004 and 2003, and the related regulatory-basis
               statements of income, retained earnings, cash flows and accumulated comprehensive
               income, comprehensive income and hedging activities for the years then ended, included
               on pages 110 through 123.45 of the accompanying Federal Energy Regulatory
               Commission Form No. 1. These financial statements are the responsibility of the
               Company's management. Our responsibility is to express an opinion on these financial
               statements based on our audits.

           We conducted our audits in accordance with auditing standards generally accepted in the
           United States. Those standards require that we plan and perform the audit to obtain
           reasonable assurance about whether the financial statements are free of material
           misstatement. An audit includes examining, on a test basis, evidence supporting the
           amounts and disclosures in the financial statements. An audit also includes assessing the
           accounting principles used and significant estimates made by management, as well as
           evaluating the overall financial statement presentation. We believe that our audits provide
           a reasonable basis for our opinion.

           As described in Note 1, the accompanying fin'ancial statements have been prepared in
           conformity with accounting practices prescribed or permitted by the Federal Energy
           Regulatory Commission, which is a comprehensive basis of accounting other than
           accounting principles generally accepted in the CJnited States.

          In our opinion, the financial statements referred to above present fairly, in all material
          respects, the financial position of Oklahoma Gas and Electric Company at December 3 1,
          2004 and 2003, and the results of its operations and its cash flows for the years then
          ended, in conformity with accounting practices prescribed or permitted by the Federal
          Energy Regulatory Commission.

          This report is intended solely for the information and use of the Company and for filing
          with the Federal Energy Regulatory Commission and is not intended to be and should not
          be used by anyone other than these specified parties. This restriction is not intended to
          limit distribution of this report, which is a matter of public record.




          February 23,2005


0504-0637779
                                          A Member Practice of Ernst 8: Young Global
                                          INSTRUCTIONSFOR FILING FERC FORMS 1 , l - F and 3-Q
                                                                 GENERAL INFORMATION
I     purpose

     Form 1 is an annual regulatory support requirement under 18 CFR 141.1 for Major public utilities, licensees and others. Form 1-F is an annual regulatory
support requirement under 18 CFR 141.2 for Nonrnajor public utilities, licensees and otlhers. Form 3-Q is a quarterly regulatory support requirement which
supplements Forms 1 and I-F under 18 CFR 141.400. The reports are designed to collect financial and operational informationfrom major and nonmajor
electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be a
non-confidential public use forms.

II. Who Must Submit

     Each Major electric utility, licensee, or other, as classified in the Commission's Uniiorm System of Accounts Prescribed for Public Utilitiesand Licensees
Subject To the Provisions of The Federal Power Act (18 CFR 101), must submit Form 1 as prescribed in 18 CFR Part 141.1. Each Nonmajor electric utility,
licensee or other must submit Form 1-F as prescribed in 18 CFR Part 141.2. Each Ma,jor and Nonmajor electric utility licensee or other, must submit Form
3-Q as prescribed in 18 CFR Part 141.400.

      Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
          (1) one million megawatt hours of total annual sales,
          (2) 100 megawatt hours of annual sales for resale,
          (3) 500 megawatt hours of annual power exchanges delivered, or
          (4) 500 megawatt hours of annual wheeling for others (deliveries plus Losses).

Nonmajor means having in each of the three 'previous calendar years, total annual sales of 10,000 megawatt hours or more

111. What and Where to Submit
(a) Submit Forms 1, I-F and 3-0 electronically through the Form 1/34Submission Software. Retain one copy of each report for your files.
(b) Respondents may submit the COrpOfate Officer Certification electronically, or filehail an original signed Corporate Officer Certification to:

             Chief Accountant
             Federal Energy Regulatory Commission
             888 First Street, NE
             Washington, DC 20426
    (c) Submit, immediately upon publication, four (4) copies of the latest annual repclrt to stockholders and any annual financial or statistical report regularly
prepared and distributed to bondholders, security analysts, or industry associations. (110 not include monthly and quarterly reports. Indicate by checking the
appropriate box on Form 1 Page 4, List of Schedules, if the reports to stockholders will be submitted or if no annual report to stockholders is prepared.) Mail
                             .
these reports to the address in Ill(c) above.
    (d) For the Annual CPA certification, submit with the original submission, or within 30 days after the filing date for F o m 1, a letter or report (not
applicable to respondents classified as Class C or Class D prior to January 1, 1984):
(i) Attesting to the conformity, in all material aspects, of the below listed (schedulesand) pages with the Commission's applicable Uniform Systems of
Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and
        (ii) be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority
of a State or other political subdivision of the U. S. (See 18 CFR 158.10-158.12 for specific qualifications.)
        Reference                               Reference
                                                Schedules Pages

          Comparative Balance Sheet      110-113
          Statement of Income               114-117
          Statement of Retained Earnings 118-119
          Statement of Cash Flows           120-121
          Notes to Financial Statements 122-123

     Insert the letter or report immediately following the cover sheet. When submitting after the filing date for this form, send the letter or report to the address
indicated at 111 (b), Use the following form for the lett$r or report Unless UnUSUal CirCUrnStanCeSor conditions, explained in the Letter or report, demand that it
be varied. insert parenthetical phrases only when excleptions are reported.




    FERC FORM NO. 1 (REV. 12-99)                                             Page    I
I                                                       GENERAL INFORMATION (continued)
        In connection with our regular examination of the financial statements of    for the year ended on which we have reported separately under date of
    We have also reviewed schedules of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material
    respects with the requirementsof the Federal Energy RegulatoryCommission as Set forth in its applicable Uniform System of Accounts and published
    accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered
    necessary in the circumstances.

       Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph       (except as noted below) conform in all
    material respects with the accounting requirements of the Federal Energy RegulatoryCommission as set forth in its applicable Uniform System of Accounts
    and published accounting releases.

        State in the letter or report, which, if any, of the pages above do not conform to thle Commission's requirements. Describethe discrepancies that exist

        (d) Federal, State and Local Governments and other authorized users may obtaiin additional blank copies to meet their requirements free of charge from:
    Public Reference and Files Maintenance Branch Federal Energy RegulatoryCommission 888 First Street, NE. Room 2A ED-12.2 Washington, DC 20426
    (202).502-8371

    IV. When to Submit:

    Submit Form 1 according to the filing dates contained in section 18 CFR 141.1 of the Commission's regulations. Submit Form 1-F according to the filing
    dates contained in section 18 CFR 141.2 of the Commission's regulations. Submit Form 3-Q according to the filing dates contained in section 18 CFR
    141.400 of the Commission's regulations.

    V. Where to Send Comments on Public Reporting Burden.

    The public reporting burden for the Form 1 COllectiOn of information is estimated to average 1,144 hours per response, including the time for reviewing
    instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewingthe collection of information.public
    reporting burden for the Form 1-F COlleCtiOn of information is estimated to average 112 hours per response. The public reporting burden for the Form 3-Q
    collection of information is estimated to average 150 hours per response. Send comrnents regarding these burden estimates or any aspect of these
    collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC
    20426 (Attention: Mr. Michael Miller, ED-30); and to the Office of Informationand Reg8ulatory Affairs, Office of Management and Budget, Washington, DC
    20503 (Attention: Desk Officer for the Federal Energy RegulatoryCommission). NO person shall be subject to any penalty if any collection of information
    does not display a valid control number (44 U.S.C. 3512 (a)).




    FERC FORM NO. 1 (REV. 12-99)                                            Page ii
                                                                   GENERAL INSTRUCTIONS
I. Prepare this report in conformity with the Uniform System of Accounts (18 CFFl 101)(U.S. of A.). Interpret all accounting words and phrases in
accordance with the U. S. of A.

11. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important.
The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages
must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for
balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date
amounts.

111 Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely
states the fact.

IV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA," "NONE," or "Not Applicable" in column (d) on the List of
Schedules, pages 2 and 3.

V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed
only for resubmissions (see VII. below).

VI. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a
sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.

VI1 For any resubmissions, submit the electronic filing using the Form 113-Q software and send a letter identifying which pages in the form have been
revised. Send the letter to the Office of the Secretary.

VIII.       Do not make references to reports of previous periodslyears or to other rep3rts in lieu of required entries, except as specifically authorized.

IX. Wherever (schedule) pages refer to figures from a PreViOUS period/year, the figllres reported must be based upon those shown by the report of the
previous peridyear, or an appropriate explanationgiven as to why the different figures were used.

Definitionsfor statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means Service that can nlDt be interrupted for economic reasons and is intended to remain reliable
even under adverse conditions. "Network Service" i Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.
                                                       s
"Self" means the respondent.
        -
FNO Firm Network Service for Others. 'Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under
adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and "firm" means that service cannot be
interrupted for economic reasons and is intended td remain reliable even under advorse conditions. "Point-to-Point Transmission Reservations" are described
in Order No. 888 and the Open Access TransmissionTariff. For all transactions identifiedas LFP, provide in a footnote the termination date of the contract
defined as the earliest date either buyer or seller can unilaterally cancel the contract.
OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access
Transmission Tariff. "Long-Term"means one year or longer and "firm" means that Service cannot be interrupted for economic reasons and is intended to
remain reliable even under adverse conditions. For all transactions identified as OLF', provide in a footnote the termination date of the contract defined as the
earliest date either buyer or seller can unilaterally get out of the contract.
SFP - Short-Term Firm Point-to-PointTransmission Reservations. Use this classificationfor all firm point-to-point transmission reservations, where the
duration of each period of reservation is less than one-year.
NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even
under adverse conditions.
    -
os Other Transmission Service. Use this classification Only for those services which can not be placed in the above-mentionedclassifications, such as ail
other service regardless of the length of the contract and service form. Describe the type of service in a footnote for each entry.
AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an
explanation in a footnote for each adjustment.

DEFINITIONS
1. Commision Authorization (Comm. Auth.) -- The 8uthorization of the Federal Energy Regulatory Commission, or any other Commission. Name the
commission whose authorization was obtained and give date of the authorization

II. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.




FERC FORM NO. 1 (REV. 12-99)                                                  Page iii
I                                                                  EXCERPTS FROM THE LAW
    Federal Power Act, 16 U.S.C. 791a-825r

    Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to wit: ... (3) . corporation' means any corporation,
    joint-stock company, partnership, association, business trust, organized group of persons, whether incorporatedor not, or a receiver or receivers, trustee or
    trustees of any of the foregoing. It shalt not include 'municipalities, as hereinafter defined;
         (4) 'Person' means an individual or a corporation;
                                                                                                         f
         (5) 'Licensee, means any person, State, or municipality Licensed under the provisions o section 4 of this Act, and any assignee or successor in interest
    thereof;
         (7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws
    thereof to carry an the business of developing, transmitting, unitizing, or distributing power; ......
         (11) "project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works
    and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or forebay reservoirs directly connected therewith, the
    primary line or Lines transmitting power therefrom to the point of junction with the distribution system or with the interconnected primary transmission system,
    all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs,
    Lands, or interest in Lands the use and occupancy of which are necessary or appropiriate in the maintenance and operation of such unit;

    "Sec. 4. The Commission is hereby authorized and empowered
        (a) To make investigations and to collect and record data concerning ;he utilization of the water 'resources of any region to be developed, the
    water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development -costs, and
    relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."

    "Sec.304. (a) Every Licensee and every public utility shall file with the Commission such annual and other periodic or special' reports as the Commission
    may be rules and regulations or other prescribe as necessary or appropriate to assist the Cornmission in the -proper administration of this Act. The
    Commission my prescribe the manner and form in which such reports shalt be made, and require from such persons specific answers to all questions upon
    which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets
    and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project
    and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other
    facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to
    make adequate provision for currently determining such costs and other facts. Such r'eportsshall be made under oath unless the Commission otherwise
    specifies'.lO

    "Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it
                                                                   f
    may find necessary or appropriate to carry out the provisions o this Act. Among other things, such rules and regulations may define accounting, technical,
    and trade terms used in this Act; and may prescribe the "form or forms of all statements, declarations, applications, and reports to be filed with the
    Commission, the information which they shall contain, and the time within which they .shall be field..."

    GENERAL PENALTIES
    "Sec. 315. (a) Any licensee or public utility which willfully fails, within the time prescrib'edby the Commission, to comply with any order of the Commission, to
    file any report required under this Act or any rule or regulation of the Commission therleunder, to submit any information of document required by the
    Commission in the course of an investigation conducted under this Act .... shall forfeit to the United States an amount not exceeding $1,000 to be fixed by the
    Commission after notice and opportunity for hearing .... "




FERC FORM NO. 1            (ED.12-91)                                          Page iv
                                                             FERC FORM NO. 1/34:
                                                                                                                  AND OTHER

                                                                                                              02 YearIPeriod of Report
                                                                                                                End of        2004/Q4
03 Previous Name and Date of Change (if name changed duringyetar)
                                                                                                                   / I



05 Name of Contact Person                                                                              06 Title of Contact Person
   Donald R. Rowlett                                                                                   VP, Controller


7 -                                                   I                                                                       I
08 Telephone of Contact Person,/nc/uding 09 This Report Is                                                                        10 Date of Report
Area Code                                                                                                                           (Mo, Da, Yr)
                                          (1)    An Original                            (2)   0   A Resubmission
   (405) 553-3604                                                                                                                    I1
                                                     ANNUAL CORPORATE OFFlCEiR CERTIFICATION
The undersigned officer certifies that:

I have examined this report and to the best of my knowledge, information, and belief (allstatements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.




01 Name                                                   03 Signature                                                            04 Date Signed
 Donald R. Rowlett                                                                                                                 (Mo, Da, Yr)
02 Title
 Vice President and Controller                                     Donald R. Rowlett                                                I /
        Name of Respondent                                     This Re ort Is:          Date of Report              Yeariperid of Report
                                                               (1) d A n Original       (Mo, Da, Yr)                End of         2004lQ4
        Oklahoma Gas and Electric Company                      (2)  n  A Resubmission    I /




    I
    certain pages. Omit pages where the respondents are "none," "not applicabile," or "NA




           1 General Information
                                                      (a)
                                                                                                        Reference



                                                                                                          101
                                                                                                                     1
                                                                                                                     ,      Remarks




          2 Control Over Respondent                                                                       102

          3 CorporationsControlled by Respondent




                                                                                        +
          4 Officers
          5 Directors
          6 Important Changes During the Year                                                            108-109
          7 ComparativeBalance Sheet                                                                     110-113
          8 Statement of Income for the Year                                                             114-117
          9 Statement of Retained Earnings for the Year
         10 Statement of Cash Flows                                                                      120-121
         11 Notes to Financial Statements
         12 Statementof Accum Comp Income, Comp Income, and Hedging Activities
         13 Summary of Utility Plant & Accumulated Provisions for Dep, Amorti3 Dep                      200-201
         14 Nuclear Fuel Materials
I        15 I Electric Plant in Service                                                         I       204-207
~




                                                                                                                     I
         16 Electric Plant Leased to Others
         17 Electric Plant Held for Future Use
         18 Construction Work in Progress-Electric                                                        216
                                                                                            ~       ~




         19 Accumulated Provisionfor Depreciation of Electric Utility Plant
         20 Investment of Subsidiary Companies
                                                                                                          219
                                                                                                        224-225
                                                                                                                     I
I           I
         21 Materials and Supplies                                                              I         227

I    I   22 Allowances                                                                          I       228-229      N/A                     I
I 23 I ExtraordinaryProperty Losses
~
                                                                                                I         230        N/A                     I
         24 UnrecoveredPlant and Regulatory Study Costs
         25 Other RegulatoryAssets
         26 Miscellaneous Deferred Debits
         27 Accumulated Deferred Income Taxes
I           I
         28 Capital Stock                                                                       I       250-251
I        29 I Other Paid-in Capital                                                             I         253
         30 Capital Stock Expense
         31 Long-Term Debit                                                                             256-257
         32 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax
         33 Taxes Accrued, Prepaid and Charged During the Year                                          262-263
         34 Accumulated Deferred Investment Tax Credits                                                 266-267
I        35 I Other Deferred Credits                                                            I         269
        36 Accumulated Deferred Income Taxes-Accelerated Amortization Property                          272-273      N/A                     I
 Name of Respondent                                         This Re rt I :
                                                                        s                           Date of Report             YearIPeriod of Report
                                                            (1) 8 A n Original                      (Mo, Da, Yr)               End of         20041Q4
 Oklahoma Gas and Electric Company                          (2) nA Resubmission                      11
                                                            ..     I                           I                           I
                                                         LIST OF SCHEDULES (Electric Utility) (continued)

 Enter in column (c) the terms "none,"*not applicable,"or "NA,"as appropriate, where no information or amounts have been reported for
 :ertain pages. Omit pages where the respondentsare 'none,* "notapplicable,' or "NA'.

                                         Title of Schedule                                                   Reference                           Remarks
                                                                                                             Page No.
                                                   (a)
      Accumulated Deferred Income Taxes-Other Property                                                        274-275
      Accumulated Deferred Income Taxes-Other                                                                 276-277

      &her Regulatory Liabilities
                        ~~          ~
                                                                                                         I     278             I
      Electric Operating Revenues                                                                             300-301
      Sales of Electricity by Rate Schedules                                                                   304
                                    ~                                                               ~~                         _   _     _   _   _   _     ~




      Sales for Resale                                                                                        310-311
      Electric Operation and Maintenance Expenses                                                             320-323
      Purchased Power                                                                                         326-327
      Transmission of Electricity for Others                                                                  328-330
      Transmission of Electricity by Others                                                                     332
      Miscellaneous General Expenses-Electric                                                                   335
      DeDreciatiOnand Amortization of Electric Plant                                                     I    336-337          I
      Regulatory Commission Expenses
       ~            ~                                                                               ~~
                                                                                                         I    350-351
                                                                                                                 ~~~
                                                                                                                               I
      Research, Development and Demonstration Activities                                                      352-353
      Distributionof Salaries and Wages                                                                       354-355
      Common Utility Plant and Expenses                                                                         356                NIA
      Purchases and Sales of Ancillary Services                                                                 398

      Monthly Transmission System Peak Load                                                              I      400            I
      Electric Energy Account                                                                            I      401    ~
                                                                                                                               I
      Monthly Peaks and Output                                                                                  401
      Steam Electric Generating Plant Statistics (Large Plants)                                               402-403
      Hydroelectric Generating Plant Statistics (Large Plants)                                           I    406-407          I NIA
      Pimped Storage Generating Plant Statistics (Large Plants)                                               408-409              NIA
      Generating Plant Statistics (Small Plants)                                                              410-411              NIA
                                                                                                                                    ~~




      Transmission Line Statistics                                                                       I    422-423          I
      Transmission Lines Added During Year                                                                    424-425
      Substations                                                                                             426-427
      Footnote Data                                                                                             450

       Stockholders' Reports Check appropriate box:
            0    Four copies will be submitted
                 No annual report to stockholders is prepared




FERC FORM NO. 1 (ED. 12-96)                                              Page 3
Name of Respondent                               This Report Is:                  Date of Report         Year/Period of Repori
Oklahoma Gas and Electric Company                (1)     An Original              (Mo, Da, Yr)
                                                 (2)     A Resubmission              / /                 End of       20041Q4


                                                    GENERAL INFORMATION
   1. Provide name and title of officer having custody of the general1 corporate books of account and address of
 office where the general corporate books are kept, and address of office where any other corporate books of account
 are kept, if different from that where the general corporate books are kept.
      Donald R. Rowlett, Vice President and Controller
      321 N. Harvey
      P.O. Box 321
      Oklahcma City, OK       73101-0321

    2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
 If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
 of organization and the date organized.
      State of Oklahoma (Formerly the TerritoIy of Oklahoma)
      February 27, 1902



  3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possessiion, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
      Not Applicable




  4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
      State of Oklahoma   -   Electric Utility Service Only
      State of Arkansas   -   Electric Utility Service Only




  5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?

(1)    0    Yes ...Enter the date when such independent accountant was initially engaged:
(2)    E4   No




FERC FORM No.1 (ED. 12-87)                            PAGE 101
 \lame of Respondent                               This Report Is:                      Date of Report          Year/Period of Report
 3klahoma Gas and Electric Company                 (1) [XI An Original                  (Mo, Da, Yr)
                                                   (2)     A Resubmission                  / I                  End of       2004JQ4


                                                   CONTROL OVER RESPONDENT
  1. If any corporation, business trust, or similar organization or a combination of such organizationsjointly held
 control over the repondent at the end of the year, state name of controlling corporation or organization, manner in
 which control was held, and extent of control. If control was in a holding company organization, show the chain
 of ownership or control to the main parent company or organization. If control was held by a trustee@),state
 name of trusteets), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
 OGE Energy Corp. a registered holding company, owns 100% of respondent's outstanding shares of common stock.




FERC FORM NO. 1 (ED. 12-96)                                  Page 102
     Jameof Respondent                                   This Re ort Is:                     Date of Report           Y earweriw   UI   napi i
                                                         (1) d A n Original                  (Mo, Da, Yr)             End of            2004lQ4
     3klahoma Gas and Electric Company                   (2) n A Resubmission                 t i
                                                       CORPORATIONS CONTROLLED BY RESPONDENT




 lefinitions
 1. See the Uniform System of Accounts for a definition of control.
 2. Direct control is thaf which is exercised without interposition of an intermediary.
 3. Indirect control is that which is exercised by the interposition of an intermediarywhich exercises direct control.
 4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
 doting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
 mutual agreement or understandingbetween two or more parties who together have control within the meaning of the definition of
 control in the Uniform System of Accounts, regardless of the relative voting rights of each party.

 Line                Name of Company Controlled                         Kind of Business             Percent Voting                Footnote
  No.                                                                                                Stock Owned                     Ref.
                                 (a)                                           (b)                        (c)                        (d)
       1 The Arklahoma Corporation                             Owner and Lessor of                       4.8%                       (a)
       2                                                        Transmission facilities.

       3

       4
       5
       6
       7 (a) Held Jointly with Entergy Arkansas Inc.
       6       and AEP-Southwestern Electric Power
      9

     10
     11    I
                                                           I                               3
           -                                                                                                                                      -
     12
     13
     14
     15
     16
                 ~




     17
                                                           I
     18                                                    I                                                             I
     19
     20
-~
     21
     22
     23
     24
     25




FERC FORM NO. 1 (ED. 12-96)                                         Page 103
      ime of Respondent                                        This Re ort I :
                                                                            s                         WULW UI   nqmrvlr    ,   --...   -.         -
                                                               ( 1 ) $An original                     (Mo, Da, Yr)         End of                     2d04JQ4
     tlahoma Gas and Electric Company                          (2) n    A Resubmission                 I1




     le
     IO.
                                                     Title
                                                      (a)
                                                                                             I           Name of Officer
                                                                                                               (b)
                                                                                                                                                   Salary
                                                                                                                                                 for Year
                                                                                                                                                    (c)
       1 Chairman of the Board, President and Chief                                              Steven E. Moore                                            710,000
      2    I    Executive Officer                                                            I                                    I
                                                                                                                                                                      I
      3
      4        Executive Vice President and Chief                                                Peter B. Delaney                                           440,oOo
      5         Operating Officer
      6                                                                                      I                                    I
      7           Fxmtitive Vice    President and Chief                                      IAI M. Strecker                                                191,667
      8               OperaGgWicer                                                           I
      9                                                                                                                           I
     10    Vice President, Business Systems and Services                                         Michael G. Davis                                           190,000
     11
     12    Senior Vice President and Chief Financial Officer
                                                                                         - James R. Hatfield                      I                         310,000)
     13                                                                                  -                                        I         ~~




     14        Corporate Secretary                                                       -       Carla D. Brockrnan
                                                                                                                     ~~
                                                                                                                                                            135,0001
     15                                                                                  -                                        I
     1 Vice President, Electric Services
      6                                                                                  -       Steven R. Gerdes
     17                                                                                  -       Gary D. Huneryager
                                                                                                                                  I
     18 Internal Audit Officer                                                           -
     19                                                                                      I                                    I
     20 I Vice President and Controller                                                      I Donald R. Rowlett                                            190,000
     21
     22 Senior Vice President, Power Supply                                                      Jack T.Coffrnan                                            260,000
     23
     24 Vice President of Transmission                                                           Melvin H. Perkins, Jr.                                     165,589
     25
     26        ** Treasurer                                                                      Deborah S. Fleming                                         173,437
     27
     28
     29
     30
     31           Retired June 1, 2004.
     32
     33        ** Employed as of Janualy 26,2004
     34
     35
     36
     37
     38

 ~
                                                                                                 I                                I
     40
     41
     42

     43
     44




F E W FORM NO. 1 (ED. 12-96)                                              Page 104
    Name of Respondent                                               This Re ort Is:                          Date of Report              YearIPeriod of Report
                                                                     (1) d A n Original                       (Mo, Da, Yr)
                                                                                                                                          End of         2004/Q4
    Oklahoma Gas and Electric Company                                (2) n   A Resubmission


    I. Report below the informationcalled for concerning each director o the respondent who held office at any time during the year. Include in column (a), abbreviated
                                                                       f


    Line                                     Name (and Title) of Director                                                Principal Business Address
     No.                                             (a)                                                                             (b)
          1 Herbert H. Champlin            (A) (B)                                                Post Office Box 1066
         2                                                                                        Enid, Oklahoma 73702
         "
         4 Luke R. Corbett                 (A) (8)                                                Post Office Box 25861
         5                                                                                        Oklahoma City, Oklahoma 73125
         6
         7 William E. Durrett              (A) (C)                                                Post Office Box 25523
         8                                                                                        Oklahoma City, Oklahoma 73125
      9
     10 Martha W. Griffin                  (e) (C)                                                301 West Broadway
     11                                                                                           Muskogee, Oklahoma 74401
I            I                                                                                                                                                            t
     12
     13 John D. Groendyke                  (B) (C)                                                Post Office Box 648
     14                                                                                           Enid, Oklahoma 73702
         15
         16 Robert Kelley                  (A) (B)                                                Post Office Box 1507
     17                                                                                           Ardmore, Oklahoma 73402
     18
     19 Linda Petree Lambert                                                                      3037 NW. 63 Suite 155W
     20                                                                                           Oklahoma City, Oklahoma 73116
     21
             I
     22 Steve E. Moore *                                                                      I Post Office Box 321
     23 II Chairman of the Board. President and
     ~                                                                                        IOklahoma Citv. Oklahoma 73101-0321
     24 I        Chief Executive Officer                                                      I                                                                           I
     25
     26 Ronald H. White, M.D.              (B) (C)                                                1508 W. Wilshire
     27                                                                                           Oklahoma City, Oklahoma 73116
     28
     29 J. D. Williams                     (4(C)                                                  1155 21st Street N.W.
     30                                                                                           Washington D.C. 20036
     31
     32 I
     33 I
     34 I
     35 I
     36      I (A) Member of Audit Committee                                                  I
     37 I (B) Member of Compensation Committee
     38 (C) Member of Nominatingand Corporate Governance
     39                  Committee
     40          *   Mr. Moore is a standing member of all committees
     41
     42
     A3

             I
     44
     45 I
     46      I
                                                                 '                            I
     47 I




FERC FORM NO. 1 (ED. 12-95)                                                   Page   105
BLANK PAGE
  Name of Respondent                                    This Report    s
                                                                      I:   I,z.            Date of Report          Yeadperiod of Report

                                                    I(2)
                                                    I
                                                            a   A Resubmission        I
                                                                                      I
                                                                                            '                  I
                                                 IMPORTANT CHANGES DURIING THE QUARTEWYEAR
 Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
 accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or " N A where applicable. If
 information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
 1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
 franchise rights were acquired. If acquired without the payment of consideration, state that fact.
 2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
 companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
 Commission authorization.
 3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,
 and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
 were submitted to the Commission.
 4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
 effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
 reference to such authorization.
 5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
 began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
 customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
 new continuing sources of gas made available to it from purchases, develoipment, purchase contract or otherwise, giving location and
 approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
 6. Obligations incurred as a result of issuance of securities or assumption (of liabilities or guarantees including issuance of short-term
 debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
 appropriate, and the amount of obligation or guarantee.
 7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
 6. State the estimated annual effect and nature of any important wage scale changes during the year.
 9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
 proceedings culminated during the year.
 10. Describe briefly any materially important transactions of the respondenit not disclosed elsewhere in this report in which an officer,
 director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
 party or in which any such person had a material interest.
 11. (Reserved.)
 12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
 applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
 13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have
 sccurred during the reporting period.
 14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
 sercent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
 Sxtent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
 :ash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.


         PAGE 108 INTENTIONALLY LEFT BLANK
         SEE PAGE 109 FOR REQUIRED INFORMATION.




FERC FORM NO. 1 (ED. 12-96)                                     Page 108
Name of Respondent                                  This Report is:          Date of Report Yeadperiod of Report
                                                    (1) X An Original         (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                  (2) - A Resubmission           / I              2004Q4




1) None

2) None

3) The McClain Plant, located in Newcastle, Oklahoma, is ii 520-megawatt plant of which OG&E owns a 77
   percent interest (400 megawatts). FERC approved OG&;Esacquisition of the plant on July 2,2004. The
   journal entries relating to purchase will be submitted to FERC for approval in the 4th Quarter 2004.

4) None

5) None

6) An Underwriting Agreement was filed with the Securities and Exchange Commission of August 5,2004 for
   $140,000,000 in 6.50% Senior Notes, Series due August 1,2034. The Oklahoma Corporation Commission
   approval for authority to issue $200,000,000 principal amount of its debt securities was issued on May 7,
   2003.

7) None

8) A general salary adjustment of approximately 2 112% was given by respondent to all eligible employees
   effective December 20,2003.




9) PROCEEDINGS CULMINATED DURING 4th QUARTER of 2004:

Application of Joyce Davidson, Acting Director of the Public Utility Division, OCC, and Oklahoma Gas and
Electric Company to Review the Security Related Expenses Incurred and to be Expended by OG&E in the
Aftermath of September 11,2001, Cause No. PUD 200200168, OKLAHOMA CORPORATION
COMMISSION. Originally a part of OG&Es Application filed in response to Cause PUD 200100455,OG&E
withdrew the $10.3 million increased security portion of its irequest for relief, and OG&E and the Acting
Director of the OCC PUD filed this Joint Application for separate consideration of costs related to increased
security requirements. On August l4,2002,OG&E filed its report outlining proposed expenditures and related
actions for security enhancement. In May, 2004,OG&E filed Supplemental Testimony. On July 12, 2004, the
Commission filed its Order on Joint Motion to Establish Pracedural Schedule and Approve Notice of Hearing,
setting hearing on the merits for November 9-11,2004. On October 28,2004, a Joint Stipulation and
Settlement Agreement was presented to the Commission for it's review and approval. The Stipulating Parties
represented to the Commission that the Joint Stipulation was a fair, just and reasonable settlement of the issues,
and that it was in the public interest. The Stipulating Parties agreed, among other issues, that OG&E should
enhance the security of its assets, and agreed to allowable costs for such projects. Further, the Stipulation set
forth that OG&E would make quarterly reports available to the parties, and that the costs would be adjusted
quarterly through the Security Rider, On December 21,2004, the Commission issued its Final Order No.
499043 approving the Joint Stipulation and Settlement Agreement, and further ordering that Staff be directed to
IFERC FORM NO. 1 (ED. 12-96)                         Page 109.1                                                      I
 Name of Respondent                                 This Report is:          Date of Report Year/Period of Report
                                                    (1) X An Original         (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                 (2) - A Resubmission          / I              2004lQ4




perform annual reviews and true-up calculations on a calendlar year basis.

 Oklahoma Gas and Electric Company and NRG McClain, LLC, Docket No. EC03-131-000, FEDERAL
 ENERGY REGULATORY COMMISSION. On August 25,2003,OG&E and NRG McClain, LLC filed with
 the Commission an application pursuant to Section 203 of the Federal Power Act for authorization for NRG
 McClain to sell, and OG&E to acquire, NRG McClain's 77 percent interest in the 520 megawatt McClain
 Energy Generating Facility and associated transmission equipment located near Oklahoma City, Oklahoma.
 Motions were filed by several parties -- some parties requesting intervenor status, some requesting approval of
 the transaction, and some protesting and asking that the application be rejected. On December 18,2003, the
 Commission issued its Order Setting Disposition and Acquiisition of Facilities Application for Hearing. In its
 order, the FERC stated that it would set the application for public hearing to address the appropriate mitigation
 for Applicants' proposed disposition of facilities. The FERC also stated "This order benefits customers by
 ensuring that the Transaction will not adversely affect competition in the marketplace." On January 15,2004,
 the Commission issued a procedural schedule setting dates including hearing date of August 3,2004. On March
 8, 2004,OG&E submitted to the Commission its Offer of Settlement to resolve the mitigation-related issue and
 any proper sub-issues in the evidentiary hearing established by the Commission's Hearing Order of December
 18, 2003. InterGen Services and Redbud Energy (collectively "InterGen") filed a Motion to reject OG&E's
 Offer of Settlement or to Defer Consideration and Request fior Shortened Answer Period and Expedited Ruling.
 On March 26, 2004, the Commission filed its Order denying InterGen's Motion in its entirety. On March 29,
 2004, FERC and various parties filed comments either supporting or opposing OG&Es Offer of Settlement.
During April and May, 2004, reply comments and testimony were filed by various parties and discovery
 requests were exchanged between parties. On April 12,2004, FERC issued its Order rejecting OG&Es Offer of
 Settlement on the ground that OG&E had failed to satisfy requirements of 18 C.F.R. §385.602(h)(2)(i)(2003).
 On April 30,2004, FERC issued its Order rejecting InterGen's March 29,2004 Offer of Settlement on the same
 ground that it rejected OG&Es:       .like OG&Es unilateral offer of settlement, the Intergen Offer of Settlement
                                      'I..


is vigorously contested. It therefore must satisfy 18 C.F.R. fi385.602(h)(2)(i)in order to be certified to the
Commission. Here again, certification requires a presiding officer determination either that: (1) the Offer of
 Settlement presents no genuine issue of material fact; or (2) the record contains substantial evidence from which
the Commission may reach a reasoned decision on the merits of the contested issues. . . . The record remains
insufficient, not yet having been subject to full discovery nor to adequate answering/rebuttal evidence. On
                                                                                                        "

May 3,2004,OG&E filed its Motion for Interlocutory Appeal, stating that "Delaying certification of a contested
settlement until after all testimony is filed under the trial schedule, . . . unnecessarjly prolongs proceedings,
eliminates the primary benefits that the parties achieve by reiaching a settlement, is harmful to administrative
efficiency, and is directly contrary to the Commission's regullations and its policy of fostering settlements." On
May 10,2004, Motions Commissioner Wood determined that OG&E demonstrated extraordinary circumstances
in accordance with the Commissions regulations that would make prompt Commission review of the contested
rulings necessary to prevent detriment to the public interest, and referred to the full Commission the May 3,
2004 interlocutory appeal filed by OG&E. On May 18,20041,Motions Commissioner Wood also referred
InterGen's May 13, 2004 interlocutory appeal to the full Commission. On May 21, 2004, AES Shady Point filed
its Offer of Settlement. On June 15, 2004, FERC issued its Order rejecting AES' Offer of Settlement on the
same ground as the rejection of OG&E and InterGen Offers. On June l6,2004,OG&E, FERC Staff, A E S and
InterGen filed their Unopposed Joint Motion to Extend Certain Procedural Dates and Request for Expedited
Action. On June 18,2004, FERC issued its order rejecting Joint Motion on several grounds,primaily the fact
that FERC regulations state that interlocutory appeals will not suspend a proceeding. On July 2,2004, FERC
rFERC FORM NO. 1 (ED. 12-96]                        Paae 109.2                                                      I
Name of Respondent                                  This Report is:          Date of Report Year/Period of Report
                                                    (1) X An Original         (Mo, Da,Yr)
 Oklahoma Gas and Electric Company                      -
                                                    (2) PI Resubmission            I /              2004/Q4



issued its Order Approving Contested Settlement Offer, Subject to the Commission's Modifications, and
Authorizing Acquisition and Disposition of Jurisdictional Facilities. The Order stated, among other things, . .
                                                                                                              'I.


we approve the OG&E Offer of Settlement, subject to modification, because it will put in place mitigation, both
interim and permanent, to prevent harm to competition in OG&Es market from the Transaction. As stated
above, the OG&E Offer of Settlement includes all of the revisions proposed by Trial Staff. . . . Accordingly,
the Commission approves the Transaction, as modified, asconsistent with the public interest." The Order
approving the OG&E Offer of Settlement also rejected AES's Offer of Settlement and InterGen's Offer of
Settlement in part. The Order also directed OG&E to make appropriate filings under Section 205 of the FPA, as
necessary, to implement the transaction, and ordered OG8z.E to notify the Commission within 10 days of the
date that the acquisition of the jurisdictional facilities were: consummated. On July 9,2004,OG&E filed with
the FERC its Conformed Market Monitoring Plan. On July l9,2004,OG&E filed with the FERC its letter
notifying the Commission that the authorized transfer from NRG McClain LLC to OG&E of a 77 percent
ownership interest in the McClain Generating Facility, including associated jurisdictional transmission facilities,
was consummated on July 9,2004. On August 2,2004, InterGen filed a request for rehearing. On September 1,
FERC issued its Order granting rehearing for further consideration, stating "In order to afford additional time for
consideration of the matters raised or to be raised, rehearing of the Commission's order is hereby granted for the
limited purpose of further consideration, and timely-filed rehearing requests will not be deemed denied by
operation of law. Rehearing requests of the above-cited orlder filed in this proceeding will be addressed in a
future order."

Reporting by Transmission Providers on Vegetation Management Practices Related to Designated Transmission
Facilities, Docket No. ELo4-52-001, FEDERAL ENERGY REGULATORY COMMISSION. On April 19,
2004, the FERC issued its initial Order in this matter. On June 15,2004,OG&E filed its Report on Vegetation
Practices with the FERC and also with the Oklahoma Corporation Commission and Arkansas Public Service
Commission. The FERC submitted its vegetation management report to Congress on September 7,2004.

Oklahoma Gas and Electric Company, Authority to Issue Short-Term Debt Securities in Amounts Not
Exceeding in the Aggregate $400,000,000 Outstanding at Any One Time, Docket No. ES05-9-000, FEDERAL
ENERGY REGULATORY COMMISSION. On October 26,2004,OG&E filed this Application with the
FERC. On November 30,2004, the FERC issued a letter to OG&E authorizing OG&E to issue short-term
promissory notes and other evidences of indebtedness, including guarantees, in an aggregate principal amount
outstanding at any one time not to exceed $400 million, upon the terms and conditions outlined in the remainder
of the letter.




IFERC FORM NO. 1 (ED.12-96)                          Page 109.3                                                     I
Name of Respondent                                        This Report is:             Date of Report Yeadperiod of Report
                                                          (1) 2( An Original           (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                       I(2) - A Flesubmission   I         I!      I      2004/Q4
                                     IMPORTANT CHANGES DURING THE QUARTEWYEAR (Continued)


PENDING AT THE END OF 4th QUARTER OF 2004:
In the Matter of a Rulemalung to Amend Affiliate Transaction Rules-Electric in Compliance with Act 204 of
2003, Docket No. 03-056-R, ARKANSAS PUBLIC SERVICE COMMISSION. On April 1,2003, the
Commission issued orders in this and two other Dockets (03-054-R and 03-055-R) as a part of the process of
implementing Act 204, Section 10 of the Electric Utility Regulatory Reform Act of 2003. The Act provided in
part that "No later than ninety (90) days after the effective date of this subsection, the commission shall
commence a rulemaking proceeding to identify and to repeal or amend all rules and regulations adopted by the
commission to facilitate, or in anticipation of, retail electric competition which are inconsistent with, have been
rendered unnecessary by, or have been superseded by this act of 2003." In this Docket 03-056-R, the Affiliate
Transaction Rules-Electric as adopted by the Commission to facilitate, or in anticipation of, retail electric
competition pursuant to Act 1556 were considered for amendment because they were inconsistent with, were
rendered unnecessary by, or were superseded by Act 204 of 2003. Procedural schedules were established for
comments by Staff and parties. During the month of February 2004, Initial Comments were filed by numerous
parties.

In the Matter of Developing Comprehensive Resource Planning Guidelines for Electric Utilities, Docket No,
03-070-R, ARKANSAS PUBLIC SERVICE COMMISSION. On May 9,2003, the Commission initiated this
generic proceeding for the purpose of developing Comprehensive Resource Planning Guidelines to be followed
by jurisdictional electric utilities. The Commission requested written comments responding to questions and
issues attached to the order. Comments were filed by numerous parties, and on August 7,2003, the
Commission issued its order setting a Collaborative Meeting of the parties on August 19,2003, for the purpose
of discussing the Initial Responses and Comments and develloping draft Comprehensive Resource Planning
Guidelines. On September 4,2003, the Commission issued its order suspending the remaining procedural
schedule pending further order of the Commission.

In the Matter of the Application of Oklahoma Gas and Electric Company for Approval of its Participation in the
Southwest Power Pool Regional Transmission Organization, Docket No. 04-1 11-U, ARKANSAS PUBLIC
SERVICE COMMISSION. On August 5,2004,OG&E filed its Application requesting approval of its
participation in the Southwest Power Pool, Inc. Regional Transmission Organization.

In the Matter of the Application of Oklahoma Gas and Electric Company for a Certificate of Environmental
Compatibility and Public Need to Construct and Operate a 161 KV Transmission Line in Logan County,
Arkansas, Docket No. 04-145-U, ARKANSAS PUBLIC SERVICE COMMISSION. On November 2,2004,
OG&E filed its Application in this docket, along with supporting testimony. On November 11,2004, the
Commission issued Order No. 2 establishing a procedural schedule. Testimony was filed by the Commission
Staff and Comments were filed by the State of Arkansas in late December 2004.

Application of OG&E for a Declaratory Order of the OCC Determining Applicant's Compliance with Order
470044 Issued in Cause PUD 2001010455 with Respect to Competitive Bidding for Natural Gas Transportation
Service, Cause No. PUD 200300226, OKLAHOMA CORPORATION COMMISSION. On April 29,2003,
OG&E filed its Application with supporting testimony in this Cause. Information was exchanged between
parties through data requests, and on December 16,2003, the Commission issued its order suspending
procedural schedule and continuing the hearing date. On January 30,2004, a new procedural schedule was
IFERC FORM NO. 1 (ED. 12-96)                              Page 109.4                                                        I
Name of Respondent                                        Thlis Report is:        Date of Report Yeadperiod of Repor
                                                          (1)l An Original         (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                       I(2) - A Resubmission   I     I !      I      2004lQ4
                                     IMPORTANT CHANGES DURING THE QUAATEWYEAR (Continued)


adopted. During the month of March 2004, direct and supplemental testimony was filed by Applicant and
intervenor Enogex Inc. On June 8,2004, the Commission issued its order modifying procedural schedule to
extend discovery cut-off date, and on June 9,2004, issued its order granting extension of deadlines to file
responsive and rebuttal testimony. On July 12,2004, the OCC Staff, AG's Office and Intervenors filed
testimony and exhibits. During July, 2004, data requests and responses were exchanged by various parties. On
July 26,2004, the Commission issued its order suspenlding current procedural schedule and adopting a new
procedural schedule, setting the hearing on the merits for September 16, 17 and 20,2004. On August 16,2004,
parties filed rebuttal testimony. On September 14, 15 and 16,2004, the Commission issued several Orders
sustaining or settling numerous motions and objections;that had been filed by various parties concerning
discovery requests. Hearings on the merits were held c September 16, 17,20,21 and 22,2004. On October 6 ,
                                                          m
2004, parties filed with the Commission their proposed findings of fact and conclusions of law. On October 22,
2004, the Administrative Law Judge filed her Report. In the Report, Judge Miller recommended, in part: (1)
$41,920,940as the combined cost of service for gas transportation and gas storage service necessary for OG&E
to serve its customers; (2) that the Firm No-Notice, Loa.d Following Transportation and Storage Services
Agreement between OG&E and Enogex, to the extent adopted therein, is fair, just, reasonable, in the public
interest and is not imprudent; (3) that to the extent there have been gas storage charges collected from OG&E
customers in excess of $7,800,000, any such over collections shall be refunded to the customers of OG&E; (4)
that a hearing be set to determine such amounts, if any, within thirty (30) days of a final Commission order in
this Cause; (5) that OG&E's decision not to competitively bid and its evaluation of gas transportation and
storage does not rise to the level of imprudency nor does it violate the Commission's order in Cause No. PUD
200100455, Order No. 470044; (6) that OG&E consider as an option a competitive bidding process for any
transportation and/or storage services required by OG&E in the future, which would allow all bidders to
competitively bid, including Enogex; and (7) that OG&E in collaboration with Commission Staff and the
Attorney General review its Fuel Supply Portfolio and Risk Management Plan. On November 1,2004, some
parties, inclulng OG&E, filed Appeals to the Report of the Administrative Law Judge. On December 7,2004,
these Appeals were heard by the Commission.

Standards of Conduct for Transmission Providers, Docket No. Mol-10-000, FEDERAL ENERGY
REGULATORY COMMISSION. On September 27,2001, the Commission filed its Notice of Proposed
Rulemaking in this proceeding, inviting all interested parties to file written comments to its proposed Standards
of Conduct. On June 28,2002,OG&Efiled Comments stating the proposed revisions to proposed FERC
standards of conduct would have unintended detrimental effects on OG&E and other utilities that operate under
traditional state regulations; that neither Arkansas or Oklahoma is expected to provide retail customers with a
choice of electric energy suppliers in the foreseeable future. Therefore, OG&E has not undertaken any process
to unbundle its transmission function from its distribution and customer service functions, a separation process
the FERC would require under its proposed standards of conduct. On November 25,2003, FERC issued its
Final Rule 2004 adopting standards of conduct that apply iiniformly to interstate natural gas pipelines and public
utilities. The new standards of conduct are designed to eliminate the loophole in the current regulations that do
not cover a Transmission Provider's relationship with Energy Affiliates that are not marketers or merchant
affiliates. The Final Rule will ensure that Transmission Providers cannot extend their market power over
transmission to wholesale energy markets by giving their Energy Affiliates unduly preferential treatment.
Requests for rehearingklarification of the Final Order were filed by various companies. On April 16,2004,
FERC issued its Order No. 2004-A (Final Rule; Order on Rehearing) addressing requests for rehearing and
providing clarification of Order No. 2004. This order clarif3ed the definition of certain terns, including "energy
IFERC FORM NO.1 (ED. 12-96)                           Page 109.5                                                       1
 Name of Respondent                                 This Report is:          Date of Report Yeadperiod of Report
                                                    (1) 21 An Original        (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                    -
                                                    (2) A IResubmission            I 1              2004lQ4




affiliate“ and “marketing affiliate” and clarified certain information-sharing permissions and exceptions.
Requests for rehearing or clarification of Order No. 2004-A. were filed by various parties. On June 14,2004,
FERC issued its Order Granting Rehearing for Further Consideration. On August 2,2004, FERC issued its
Order No. 2004-B, addressing requests for rehearing and/or clarification of Order 2004-A. The FERC granted
rehearing, in part, denied rehearing, in part, and provided clarification of Order No. 2004-A. Among
clarificationswere: (1) local distribution companies (LDCs) may release or acquire capacity in the capacity
release market without becoming Energy Affiliates; (2) the Energy Affiliate exemption for LDCs extends to
LDCs serving state-regulated load at cost-based rates that acquire interstate transmission capacity to purchase
and resell gas only for on-system sales; and (3) all officers of the Transmission Provider as well as its employees
with access to transmission information or information concerning gas or electric purchases, sales or marketing
must be trained concerning the requirements of the Standards of Conduct. On December 21,2004, FERC
issued its Order No. 2004-C, generally reaffirming its determinations in Order Nos. 2004,2004-A and 2004-B
and granting rehearing and clarifying certain provisions. Order Nos. 2004, et seq. require all natural gas and
public utility Transmission Providers to comply with Standards of Conduct that govern the relationship between
the natural gas and public utility Transmission Providers and all of their Energy Affiliates. In Order No.
2004-C, the Commission addressed the requests for rehearing and/or clarification of Order No. 2004-B, and
granted rehearing, in part, denied rehearing, in part, and provided clarification of Order No. 2004-B.

 Standardization of Generator Interconnection Agreements and Procedures, Docket No. RM02- 1-000,
FEDERAL ENERGY REGULATORY COMMISSION. On April 24,2002, the Commission issued its Notice
 of Proposed Rulemaking in this matter advising that the Cormmission is proposing to amend its regulations to
 require public utilities to file the standardized interconnection agreement and procedures the Commission will
adopt in this proceeding and to take and provide interconnection service under them. [Supporters of small
 generators asked the Commission to consider developing streamlined procedures and requirements that would
allow small generators to avoid the unnecessary delay that they claim would occur if they were subjected to the
more extensive interconnection studies and other procedures required for large generators. The Commission
 subsequently severed the subject of interconnection of generators up to and including 20 MW from this
proceeding and initiated another docket, RM02-12-000 (Small Generator Interconnection Rulemaking).] On
July 24,2003, the FERC issued its Final Rule, Order No. 2003, amending its regulations under the Federal
Power Act to require public utilities that own, control, or operate facilities for transmitting electric energy in
interstate commerce to file revised open access transmission tariffs containing standard generator
interconnection procedures and a standard agreement that the Commission is adopting in this order and to
provide interconnection service to devices used for the produlction of electricity having a capacity of more than
20 megawatts, under them. Comments and requests for reheitringklarification were filed by numerous
companies throughout the remainder of 2003. On March 5,2004, the Commission issued its Order No. 2003-A,
Order on Rehearing, reaffirming its dRterminations and clarifying certain provisions in Order No. 2003.
Requests for rehearing or clarification were filed by various parties, and on May 3,2004, FERC issued its Order
Granting Rehearing for Further Consideration. FERC Notices were issued concerning a technical conference to
be held on September 24,2004, to discuss a petition for rulemaking submitted by the American Wind Energy
Association (AWEA) related to the adoption of certain requirements for the interconnection of large wind
generators. On September 24, 2004, the Commission held a technical conference related to the issues raised by
the AWEA. Specifically, the conference focused on the interconnection of wind energy and other alternative
technologies, and considered the technical requirements for the interconnection of large and small wind
generators and other alternative technologies, and the need for creating specific requirements for their
IFERC FORM NO. 1 (ED. 12-96)                        Page 109.6                       I
Name of Respondent                                  This Report is:         Date of Report YearlPeriod of Report
                                                    (1) X An Original        (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                  (2) - A, Resubmission         If               2004lQ4




interconnection to the grid. At the technical conference, FERC Staff stated that the Cornmission would allow
interested parties to file post-technical conference comments, no later than November 1,2004. On December
20,2004, FERC issued its Order No. 2003-B affirming, with certain clarifications, the fundamental
determinations in Order No. 2003-A, and stating that, "At its core, the Commissionk interconnection policy
enunciated in this series of orders ensures that all Generating Facilities are offered Interconnection Service on
comparable terms." Order No. 2003-B reaffirmed the priciing policy and crediting policy for Network Upgrades
discussed in Order No. 2003-A, and also stated that Order No. 2003-A provided no date certain for full
reimbursement of the upfront payment. Order No. 2003-B addressed petitioners' concerns by clarifying that if
the Transmission Provider chooses not to fully reimburse the Interconnection Customer after five years, it must
continue to provide dollar-for-dollar credits to the Interconnection Customer, or develop an alternative schedule
that is mutually agreeable and provides for the return of all amounts advanced for Network Upgrades not
previously repaid. However, full reimbursement shall not extend beyond twenty (20) years from the
Commercial Operation Date.

Oklahoma Gas and Electric Company and OGE Energy Resources, Inc., Docket Nos. ER98-511-002 and
ER97-4345-014, FEDERAL ENERGY REGULATORY COMMISSION. On December 22,2003,OG&E and
OGE Energy jointly filed a triennial market power update in support of their market pricing authority. In
addition, they submitted revised versions of their market based rate tariffs in accordance with the Commission's
Order issued November 17,2003 in Docket Nos. ELO1-118-000 and 001. Motions were filed by several
parties -- some parties requesting intervenor status and some protesting and asking that the application be
rejected. The Commission has not issued an order as of this date. In January of 2004, the Oklahoma
Corporation Commission and PowerSmith Cogeneration filled motions to intervene in this proceeding. On May
13,2004, FERC issued its Order addressing implementation of the new interim generation market power
analysis and mitigation procedures announced in its April 14,2004 Order in AEP Power Marketing, Inc., et al.
This Order "benefits customers by implementing the policies adopted in the SMA Rehearing Order, which
improve the assessment and mitigation of generation market power in wholesale markets, thus better ensuring
[tiat prices charged for jurisdictional sales are just and reasonable." OG&E was directed to submit, within the
time period set forth ("within 270 days of date of this order"), a revised three-year market-based rate review
filing.

10) None

13) A1 M. Strecker retired effective June 1,2004 as Executive Vice President and Chief Operating Officer.
That same day, Peter B. Delaney was named Executive Vice President and Chief Operating Officer. On
September 16,2004, Me1 Perkins, Director Transmission Policy, was named Vice President of Transmission for
OG&E Electric Services. On November 17,2004, Linda Pettree Lambert was elected to serve on the OGE
Energy Board of Directors.

14) NIA




IFERC FORM NO. 1 (ED.12-96]                         Paae 109.7                     I
r
    Name of Respondent                                      s
                                               This Report I :                            Yeadperiod of Report
    Oklahoma Gas and Electric Company          (1)     An Originlal     (Mo, Da, Yr)
                                               (2)     A                                  Endof   *o04/Q4
                                   COMPARATIVE BALANCE SHEET' (ASSETS AND OTHER DEBITS)




       I
    FERC FORM NO. 1 (REV.12-03)                  Page 110
    Name of Respondent                                              s
                                                       This Report I :                Date of Report            Yeadperiod of Report
    Oklahoma Gas and Electric Company
                                                       (1) [24 An Original            (Mo, Da, Yr)
                                                       (2)     A Resubmission            I /                    End of    20041Q4
                                      COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITSiContinuc                                          I
                                                                                                       Current Year
    Line
                                                                                       Ref.         Fnd of QuarterNea    End Balance
    No.
                                           Title of Account                          Page No.            Balance
-                                                  (a)
-
53         ILessl Noncurrent Portion of Allowances
-
54         Stores Expense Undistributed (163)
                                  -
                                                                                       227
-
55         Gas Stored Underwound Current (164.11
-
56         Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
-
57         Prepayments ( 65)
                           1                                                                                5,629.21
-
58         Advances for Gas ( 66-1
                               1     67)                                                                                               0
-
59         Interest and Dividends Receivable 1 7 )
                                                 11                                                         1,029,64           1,246,103
-
60         Rents Receivable ( 72)
                              1                                                                                                        0
-
61         Accrued Utility Revenues (173)                                                                  45.529.00          38.000.000
-
62         Miscellaneous Current and Accrued Assets (174)                                                  80,552,87
-
63         Derivative Instrument Assets (175)
-
64         (Less) Lona-Term Portion of Derivative Instrument Assets ( 75)
                                      -
                                                                     1
-
65         Derivative Instrument Assets Hedges (176)
                                                                -
                                                                                 -                          3,918,86
-
66         (Less) Long-Term Portion of Derivative InstrumentAssets Hedges (176                              3,918.86                   01
-
67         Total Current and Accrued Assets fLines 34 throuah 6 16                                        356,402,31
-
68                                         DEFERRED DEBITS
-
69         Unamortized Debt Expenses (181)
-
70         Extraordinarv ProDertv Losses (1 82.1)                                      230                                             -
-
71         Unrecovered Plant and Regulatory Study Costs ( 82.2)
                                                             1                         230                                            0
-
72         Other Regulatory Assets ( 82.3)
                                      1                                                232                145,002,50          75,337,336
-
73         Prelim. Survev and lnvestiaation Charaes IElectrid I1 83)                                           3734
-
74         Preliminary Natural Gas Survey and Inves$gation Charges 183.1)
-
75         Other Preliminary Survey and Investigation Charges ( 83.2)
                                                                1                                                                      01
-
76         Clearing Accounts (1 84)
-
77         Temmrarv Facilities I1 85)
-
78         Miscellaneous Deferred Debits I1 8 16                                       233                 99,254,83         106,193,324
-
79         Def. Losses from Dispositionof Utility Plt. (187)
-
80         Research, Devel. and Demonstration Expend. ( 88) 1                        352-353                                           0
-
81         Unamortized Loss on Reaquired Debt ( 89)  1                                                     20,958,45
-
                                                                                                ~




82         Accumulated Deferred Income Taxes (1 90)                                    234                 16,465,69
-
83
84
           Unrecovered Purchased Gas Costs I1 9 1
           -     -    -       . -. - -   --.   I
                                                    1
           Total Deferred Debits (lines 69 through 83)
-
i
                                                                                                          287,248,54
:   85                  3
           TOTAL ASS1 S (lines 14-16. 67.and 84)
                                          32.                                                            3,065,277,91




I FERC FORM NO. 1 (REV. 12-03)                                   Page 111
IName of Respondent                                       I
                                              This Report is:                      I
                                                                         Dateof Report    Yeadperiod of Report      I                                      I
    Oklahoma Gas and Electric Company         (1) 0 An Originad
                                              (2) 0 A Rresubmission                       end of      20041Q4

                                COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)                      i
                                                                                                                                    Prior Year

                                           Title of Account

          PROPRIETARY CAPITAL
          Common Stock Issued (201)                                                    250-251                    100.946.863             100.946.863
     3   IPreferred Stock Issued (204)                                         I       250-251     I                           0
                                                                                                                               1                       0
     4   ICaDital Stock Subscribed (202,205)                                   I         252       I                        01                         0
     5    Stock Liability for Conversion (203, 206)                                      252                                0                         0
     6    Premium on Capital Stock (207)                                                 252                      409,501,960             409,504,135
     7       Other Paid-In CaDital (208-211)                                             253                      154.997.342               1.995.167
I    8   I Installments Receivedon Caoital Stock (212)                         I         252       I   ~~~~~~~
                                                                                                                               ol                ~
                                                                                                                                                       01
    9    (Less) Discount on Capital Stock (213)                                          254                                   0                    0
    10   (Less) Capital Stock Expense (214)                                              254                                   0                    0
    11   Retained Earnings (215, 215.1, 216)                                           118-119                     460,893,974            460,757,146
    12   UnaDDroDriated Undistributed Subsidiary Earnings (216.1)                      118-119                         103.352                103.672
    13   (Less) ReaquiredCapital Stock (217)                                           250-251                               0                      0
    14    Noncorporate Proprietorship (Non-majoronly) (218)                                                                  0                      0




I i? 1                                                                         1 1
    15   Accumulated Other Comprehensive Income (219)                                  122(a)(b)                             0            -53,373,645
    16   Total Proprietary Capital (lines 2 through 15)                                                          1,126,443,491            919,933,338
    17   LONG-TERM DEBT
    18   Bonds (221)                                                                   256-257                    135,400,000             135,400,000
    19   (Less) ReaauiredBonds (2221                                                   256-257                                 0                      0
         Advances from Associated Companies (223)                                      256-257                       ~   ~            ~     ~    ~




         Other Long-Term Debt (224)                                                    256-257                    713,918,86              574,022,037
         Unamortized Premium on Long-Term Debt (225)
         (Less) UnamortizedDiscount on Long-Term Debt-Debit (226)                                                   2,159,272               2,190,359
    24   Total Long-Term Debt (lines 18 through 23)                                                               847,159,597             707,231,678
    25   OTHER NONCURRENT LIABILITIES




    37   Notes Payable (231)                                                                                                0              50,000,OO
    38   Accounts Payable (232)                                                                                    93,049,144              57,738,12
    39   Notes Payable to Associated Companies (433)                                                                        0
    40   Accounts Payable to Associated Companies (234)                                                            45,692,417             41,611,05
    41   Customer Deposits (235)                                                                                   45,648,323             35,750,72
    42   Taxes Accrued (236)                                                           262-263                     20,357,279             20,615,50
    43   Interest Accrued (237)                                                                                    16,363,340             12,813,21
    44                          . ,
         Dividends Declared (238)                                                                                            n
    45   Matured Long-Term Debt (239)




1 FERC FORM NO. 1 (rev. 12-03)                                      Page 112
I Name of Respondent                                   I This Report is:                I   Date of Report      I      Yeadperiod of Report
    Oklahoma Gas and Electric Company                      (1)   0   An Original
                                                           (2) 0 A Rresubmission        1   ( m a da, yr)
                                                                                               11               I      endof        2004/Q4


                                                                                                          Current Year         Prior Year
    Line
    No.
                                        Title of Account                                                     Balance
                                                (a)                         ~




    46       Matured Interest (240)
    47       Tax Collections Payable (241)                                                                                           7.874.27d
    48       Miscellaneous Current and Accrued Liabilities (242)                                               46,109,652           59,285,41i
    49     I Obligations Under Capital Leases-Current (243)
                                                                                ~




                                                                                                                         0                    (
    50     I Derivative InstrumentLiabilities (244)                                                               129.075                     (
    51     I (Less) Long-Term Portion of Derivative Instrument Liabilities                            I                   01                  [

    52                                  -
           I Derivative Instrument Liabilities Hedaes (245)                                           I                   d                   (
    53       (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges                     I                   1
                                                                                                                          0
    54       Total Current and Accrued Liabilities (lines 37 through 53)                                      274.479.9901        285.688.301
    55       DEFERRED CREDITS
           1
                                                                       ~~           ~




    56       Customer Advances for Construction (252)                                                                     0          1,550,08!
    57     I Accumulated Deferred Investment Tax Credits (2551                              266-267             36,829,087          41,978,94(
I   58     IDeferred Gains from Dismsition of Utilitv Plant (256)                                                         0                   (
    59       Other Deferred Credits (253)                                                    269                 6,503,562          32,500,00(
    60       Other Regulatory Liabilities (254)                                              278                22,464,982          25,253,98(
    61       Unamortized Gain on Reaquired Debt (257)                                                                     0                   (
    62       Accum. Deferred Income Taxes-Accel. Amort./281)                                272-277                       0                   (
    63       Accum. Deferred Income Taxes-Other Property (282)                                                            0
    64       Accum. Deferred Income Taxes-Other (284)                                                          586.924.994         552.578.581
    65
    66
             Total Deferred Credits (lines 56 through 64)
             TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16.24.35.54 and 65)
                                                                                    -                 I        652,722,625(
                                                                                                             3,065,277,914
                                                                                                                                   653,861,60!
                                                                                                                                 2,701,506,19




    FERC FORM NO. 1 (rev. 12-03)                                     Page 113
 Name of Respondent                                                  This R e rt Is:                                                                    Year/Period of Report
                                                                     (1) 8 A n Original                                                                 End of         2004lQ4
 Oklahoma Gas and Electric Company                                   (2) n Resubmissiori
                                                                               A
                                                                     . .     I                   I                                                 I
                                                                             STATEMENT OF INCOME .
 1. Enter in column (e) operations for the reporting quarter and in column l(f) the operations f o r the same three month period for the prior
 year.
 2. Report in Column (9) year to date amounts for electric utility function; in column (i) year to date amounts for gas utility, and in (k)
                                                                                                 the
 the year to date amounts for the other utility f u n c t i o n f o r the current quartler/year.
 3. Report in Column (h) year to date amounts f o r electric utility function; in column (j) the year to date amounts f o r gas utility, and in (I)
 the year to date amounts for the other utility function f o r the previous quarter/year.
 4. If additional columns are needed place them in a footnote.




 Line                                                                                                      Total                   Total           Current 3 Months   Prior 3 Months
 No.                                                                                                  Current Year to          Prior Year to            Ended             Ended
                                                                                I                 I                       I
        I
        I
                                                                                I
                                                                                      (Ref.)
                                                                                     Page No.
                                                                                        (b)
                                                                                                  I   Date Balance for
                                                                                                       Quartid?
                                                                                                             .,
                                                                                                                          I
                                                                                                                          I
                                                                                                                              Date Balance for
                                                                                                                               QuarterNear
                                                                                                                                     Id\
                                                                                                                                     %   ,
                                                                                                                                                    Quarterly Only
                                                                                                                                                    No 4th Quarter
                                                                                                                                                          le)
                                                                                                                                                                      Quarterly Only
                                                                                                                                                                      No 4th Quarter

     1 UTILITY OPERATING INCOME
     2 Operating Revenues (400)                                                       300-301            1,578,135,5421          1,517,O96,08f
     3 Operating Expenses
     4 Operation Expenses (401)                                                       320-323            1,132,778,244           1,051,966,42E
    5 Maintenance Expenses (402)                                                      320-323               85,533,284              82,040,68!
    6 DepreciationExpense (403)                                                       336-337              120,091,458             119,506,W
    7 Depreciation Expense for Asset RetirementCosts (403.1)                          336-337                  135,622
    8 Amort. & Ded. of Utilitv Plant (404-405)                                        336-337                  617.884                   477.393
    9 Arnort. of Utility Plant Acq. Adj. (406)                                        336-337
   10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
   11 Amort. of Conversion Expenses (407)
   12 Regulatory Debits (407.3)
   13 (Less) RegulatoryCredits (407.4)
   1 4 Taxes Other Than Income Taxes (408.1)                                          262-263
   15 Income Taxes - Federal (409.1)                                                  262-263               13,061,198             -42,001,657
   16          - Other (409.1)                                                        262-263                2,063162               -4,765,012
   17 Provision for Deferred Income Taxes (410.1)                                   234,272-277             85,834396              157,228,254
   18 (Less) Provision for Deferred Income Taxes-Cr. (411.1)                        234,272-277             45,l 34,319             44,442,936
   1 9 Investment Tax Credit Adj. - Net (411.4)                                        266                  -5,149,860              -5,149,86C
   20 (Less) Gains from Disp. of Utility Plant (411.6)
   21 Losses from Disp. of Utility Plant (411.7)
   22 (Less) Gains from Dispositionof Allowances (41 1.8)                                                      297,510                   191,794
   23 Losses from Dispositionof Allowances (41 1.9)
   2 4 Accretion Expense (411.10)                                                                                 9,358
   25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)                                  1,436,527,502           1,361,580,446
   26 Net Uti1Oper Inc (Enter Tot line 2 less 25) Carry to Pgl17,line 27                                   141,608,040            155,515,640




FERC FORM NO. 1/34(REV. 02-04)                                                 Page 114
    Name of Respondent                                  This Re rt Is:                                                           Year/Period of Report
                                                        (1) flAn Original                                                        End of         2004/Q4
    Oklahoma Gas and Electric Company                   (2) n Resubmission
                                                                A
                                                        ..     I                            I                            I
I                                                      -STATEMENTOF INCOME FOR THE YEAR Continuedl




                    ELECTRIC UTILITY                                     GAS UTILITY                                       OTHER UTILITY
     Current Year to Date Previous Year to Date        Current Year to Date Prisvious Year to Date       Current Year to Date  PreviousYear to Date       Line
                                                                                                                                                          No.
          (in dollars)          (in dollars)                (in dollars)            (in dollars)              (in dollars)          (in dollars)
              Ia\                   lh\                                               fil




            .   . .
              85,533,284                  82,040.685                                                                                                         I

             120.091.458                1 19.506.543                                                                                                         6
                         I                                                  I                        I                       I
                                                                                                                                       ~~




                                                                                                                                                      I ;
I                135,622
                 617.884I                  477.3971
                                                   I
                                                                                                                                                      I      r

                                                                                                                                                            1(
                                                                                                                                                            1'
                                                                                                                                                            1:
                                                                                                                             ~    ~~        -
                                                                                                                                                            1:
                46,984,585               46,912,398                                                                                                         Id
                13,061,198              -42,001,657                                                                                                         l!
                 2,063,162               -4,765,012                                                                                                         1t
                a5,834,396              157,228,254                                                                                                         1;
                45,134,319               44,442,936                                                                                                         11
                -5,149,860               -5,149.860                                                                                                         1:
                                                                                                                                                            2(
                                                                                                                                                            2'
                  297,510                  191,794                                                                                                          :
                                                                                                                                                            2
                                                                                                                                                            :
                                                                                                                                                            2
                  9,358                                                                                                                                     r
                                                                                                                                                            2
           1,436,527,502           1,361,580,446                                                                                                            1
                                                                                                                                                            2
            141,608,040              155,515,649                                                                                                            f
                                                                                                                                                            2




FERC FORM NO. 1 (ED.12-96)                                     Page 115
BLANK PAGE
  Name of Respondent                            This Re ort Is:              Date of Report       YearIPeriod of Report
                                                (1)     An Original          (Mo, Yr)
                                                                                 Da,
   Oklahoma Gas and Electric Company
                                                (2) n   A Resubmission




                             Title of Account




     I                                                    I              I     1              I            I
FERC FORM NO. 1 / 3 4 (REV. 02-04)                      Page 117
 Name of Respondent                                   This Re rt Is:                       Date of Report             YearlPeriod of Report
                                                      (1) 8 A n Original                   (Mo, Da, Yr)                              20041Q4
 Oklahoma Gas and Electric Company                    (2)    nA Resubmission                / I
                                                                                                                      End of




2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433,   436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439,Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings, Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439,Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.


                                                                                                                                 Previous
                                                                                                          QuarterNear           QuarterNear
                                                                                                                                Year to Date
Line                                           Item                                Account Affected         Balance               Balance
No.




                                                                               I                      I                     I
  221 TOTAL Aoorooriations of Retained Eaminas IAect. 436)                     I                      I


  25
  26




  36 TOTAL Dividends Declared-Common Stock (Acct. 438)                                                       -107,474,159          ( 109,778,575)
                                                                    -
  37 Transfers from Acct 216.1, Unamrop. Undistrib. Subsidiaw Earninas
                                     .. .
  381 Balance - End of Period (Total 1,9,15,16,22,29,36,37)                                                  460,893,974             460,757,146
       1
FERC FORM NO. 1/34(REV.02-04)                                    Page 118
 Name of Respondent                                        This R e rt Is:                Date of Report                  YearIPeriod of Report
                                                           (1) 8 A n Original             (Mo, Da, Yr)                                   2004/Q4
 Oklahoma Gas and Electric Company                                                                                        End of
                                                       I
                                                               n
                                                           (2) I I A Resubmission     I
                                                                                           I I                      I
                                                             STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 the quarterly version.
                            on
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433,436
- 439 inclusive). Show the contra primary account affected in columrt (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439,Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439,Adjustments to Retained Earnings.
B. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be resewed or appropriated as well as the totals eventually to be accumulated.
3. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.


                                                                                                               Current               Previous
                                                                                                             QuarterNear           QuarterNear
                                                                                        Contra Primary       Year to Date          Year to Date




    40I
    41I




      I                                                                             I                    I                     I

    531 Balance-End of Year (Total lines 49 thru 52)                                I                    I              103,352I             103,67:




FERC FORM NO. 1/34(REV.02-04)                                       m---   ..-
    Name of Respondent                                                  This Re ort Is:                                                                  YearIPeriod of Report
                                                                        (1) d A n Original                                                               End of         2004lQ4
    Oklahoma Gas and Electric Company                                   (2) nA Resubmissioin
                                                                        . .     I                                      I                         I
                                                                              STATEMENT OF CASH FLOWS
    (1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-termdebt; (c) Includecommercial paptr; and (d) Identify separatelysuch items as
    investments,fixed assets, intangibles, etc.
    (2) Informationabout noncash investingand financingactivities must be provided in the Noteslo the Financial statements. Also providea reconciliationbetween "Cash and Cash
    Equivalentsat End of Period"with relatedamounts on the Balance Sheet.
    (3) Operating Activities - Other: Includegains and losses pertaining to operatingactivities only. Gains and losses pertainingto investingand financing activities should be reportec
    in those activities. Show in the Notes to the Financialsthe amounts of interest paid (net of amount capitalized)and income taxes paid.
    (4) InvestingActivities: Includeat Other (line 31) net cash outflow to acquire other companies. Provide a reconciliationof assets acquiredwith liabilitiesassumedin the Notes to
    the Financial Statements. Do not include on this statement the dollar amount of leases capitali;ced per the USofA General Instruction20;insteadprovidea reconciliationof the
    dollar amount of leases capitalized with the plant cost.
                                                                                                                        Current Year to Date               Previous Year to Date
    Line                Description (See Instruction No. 1 for Explanationof codes)
    I .".
     Nn                                                                                                                     Quarterffear                        Quarterffear
                                                          (a)
         1 Net Cash Flow from Operating Activities:
         2                          .,       .
                 Net Income (Line 78(d on Daae 117)
                                                 I




         3       Noncash Charges (Credits) to Income:
         4       Depreciationand Depletion
         5       Amortizationof
         6        Limited-Term Electric Plant                                                                                             617,884                             477,397
         7
         8 Deferred Income Taxes (Net)                                                                                                 40,700,077                        112,785,318
         9 Investment Tax Credit Adjustment (Net)                                                                                      -5,149,860                         -5,149,860
        10 Net (Increase)Decrease in Receivables                                                                                       28,023,990                        -27,140,442
        1 1 Net (Increase) Decrease in Inventory                                                                                       -4,834,542                          4,746,436
        12 Net (Increase) Decrease in Allowances Inventory
        1 Net Increase (Decrease) in Payables and Accrued Expenses
         3                                                                                                                             17,791,682                         49,932,261
        14 Net (Increase) Decrease in Other RegulatoryAssets                                                                           -5,594,753                          8,794,951
         5
        1 Net Increase (Decrease) in Other Regulatory;  Liabilities                                                                    -2,789,004                         -2,995,004
             (Less) Allowance for Other Funds Used During Construction                                             I                     900,995     I
             (Less) UndistributedEarnings from Subsidiary Companies                                                                          320I



E
            IOther (provide details in footnote):
            lNet Increase in Accrued Utility Revenue                                                                                  -7,529,000                          -9,800,000



p
            ,Net Increase in Other Current Assets                                                                                    -48,139,322                          13,837,947
             Net Decrease in Other Operating Activities                                                                              -15,382,041                         -18,159,342
        23 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)                                                     224,651,543                         362,263,795

I 24 (Cash Flows from Investment Activities:                                                                    I                                    I             -1
                 Constructionand Acquisition of Plant (including land):
                 Gross Additions to Utility Plant (less nuclear fuel)                                                               -392,115,675                        -1 48,743,542
                 Gross Additions to Nuclear Fuel
                 Gross Additions to Common Utility Plant
                 Gross Additions to Nonutility Plant                                                                                     - 1 78,935
                 (Less) Allowance for Other Funds Used During Construction                                                               -900,995
                 Other (provide details in footnote):
        32




I 40 IContributionsand Advances from Assoc. and Sbbsidiarv ComDanies                                           I                        . .-I
                                                                                                                                     104.874.037                                       1

                                                                                                               t
L
        4 Dispositionof Investments in (and Advances to)
         1
        42 Associated and Subsidiary Companies                                                                                        73.381.41 I
                                                                                                                                              1

        44 Purchase of Investment Securities (a)
        45 Proceeds from Sales of Investment Securities (a)

L            I                                                                                                 I                                     I                                 1
FERC FORM NO. 1 (ED. 12-96)                                                          Page 120
Name of Respondent                                       This Re rt Is:                                                     YearlPeriod of Report
                                                         (1) &in Original                                                   End of         2004lQ4
Oklahoma Gas and Electric Company                        (2) n Resubmission
                                                                A
                                                         .   I
                                                                  I                      I                          I
                                                                 STATEMENT OF CASH FLOWS




                                                                                             Current Year to Date             Previous Year to Date
Line             Description (SeeInstruction No. 1 for Explanationof Codes)
                                                                                                QuarterNear                       QuarterNear
No.
                                                (a)                                                   (b)                              (c)
  46    Loans Made or Purchased
  47    Collections on Loans
  48
  49    Net (Increase) Decrease in Receivables
  50    Net (Increase ) Decrease in Inventory
  51    Net (Increase) Decrease in Allowances Held for Speculation
  52    Net Increase (Decrease) in Payables and Accrued Expenses
  53    Other (provide details in footnote):
  54
  55
  56    Net Cash Provided by (Used in) InvestingActivities




  62 Preferred Stock
  63 Common Stock
  64 Other (provide details in footnote):
  65
  66 Net Increase in Short-Term Debt (c)
  67 Other (provide details in footnote):
  68
  69
  70 ICash Provided by Outside Sources (Total 61 thru 69)                            I                   138,594,400    I
  7 I
   1                                                                                                                    I
  72 Payments for Retirement of:
  73 Long-term Debt (b)
  74 Prafarred Stock

  75 ICommon Stock                                                                   I                                  I
  76 lother (provide details in footnote):
nl                                                                                   I                                  I
  78 Net Decrease in Short-Term Debt (c)
  79
  80 Dividends on Preferred Stock
  8 Dividends on Common Stock
   1
  82 Net Cash Provided by (Used in) Financing Aotivities
  83 (Total of lines 70 thru 81)
  84 I                                                                               I                                  I
                                                                                                                        I
  85 Net Increase (Decrease) in Cash and Cash Equivalents
                           and
  86 (Total of lines 22,517 83)                                                                                    I
                                                                                                          -3,999,550                        3.735.90!
  8'1

  89
  90 Cash and Cash Equivalents at End of period                                                               15,150                        4,014,70(


FERC FORM NO. 1 (ED. 12-96)                                           Page 121
BLANK PAGE
    Name of Respondent                   This Report Is:          Date of Report   Year/Period of Report
    Oklahoma Gas and Electric Company         /J
                                         (1) X An Original                         End of     20041Q4
                                         (2)     A Resubmission    I /




I        PAGE 122 INTENTIONALLY LEFT BLANK
         SEE PAGE 123 FOR REQUIRED INFORMATION.




FERC FORM NO. 1 (ED.12-96)                        Page 122
Name of Respondent                          This Re ort Is:              Date of Report      YearIPeriod of Report
                                            (1) d A n Original           (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                                                           Endof       ~0O4/Q4
                                            (2) r]A Resubmission          l I
                  STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AhD HEDGING ACTIVITIES




3. For each category of hedges that have been accounted for as “fair value hedges“, report the accounts affected and the related amounts in a footnote.


-                                                  ~~            ~~   ~~~~




                          Item                          Unrealized Gains and        Minimum Pension        Foreign Currency               Other
Line
                                                        Losses on Available-       Liability adjustment        Hedges                  Adjustments
No.
                                                         for-Sale Securities          (net amount)
                                                                 (b)                         (c)
   1 Balance of Account 219 at Beginning of
       Preceding Quarternear
   2 Preceding Quarternear Reclassification
     from Account 219 to Net Income
   3 Preceding QuarterNear Changes in Fair
     Value
   4 Total [lines 2 and 3\
   5 Balance of Account 219 at End of
     Preceding QuarterNear I Beginning of
-
   6 Current Quarternear Reclassificationsfrorr
-    Account 219 to Net Income
   7 Current Quarternear Changes in Fair Valuc
   8 Total (lines 6 and 7)
   9 Balance of Account 219 at End of Current
     DuatterNear




FERC FORM NO. 1 (NEW 06-02)                                                  Page 122a
-
Name of Respondent                            This Re rt Is:                          Date of Report           Year/Period of Report
                                              (1) 8 A n Original
    Oklahoma Gas and Electric Company
                                              (2) n  A Resubmissiori
                                                                                      (Mo, Da, Yr)
                                                                                       I /
                                                                                                               End of      2004JQ4

                   STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AhD HEDGING ACTIVITIES
-




                                                                   'Totats for each                                       Total
                                                                                                Forward from          Comprehensive
                                                                                              Page 117, Line 72)         Income
                                                                       Account 219




FERC FORM NO. 1 (NEW 06-02)                               Page 122b
-
Name of Respondent                                    This Report is:              Date of Report YearIPeriod of Repor
                                                      (1 3 An Original              (Mo, Da, Yr)

                                       NOTES TO FINANCIAL STATEMENTS (Continued)


                         OKLAHOMA GAS AN.D ELECTRIC COMPANY
                           NOTES TO FINANCIAL STATEMENTS
1.      Summary of Significant Accounting Policies

Organization

       Oklahoma Gas and Electric Company (the “Company”) generates, transmits, distributes and sells electric
energy in Oklahoma and western Arkansas and is subject to regulation by the Oklahoma Corporation
                        the
Commission (“OCCY7), Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory
Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“Energy Gorp.")
which is an energy and energy services provider offering physical delivery and management of both electricity
and natural gas primarily in the south central United States. The Company was incorporated in 1902 under the
laws of the Oklahoma Territory and is the largest electric utility in Oklahoma and its franchised service territory
includes the Fort Smith, Arkansas area. The Company sold its retail gas business in 1928 and is no longer
engaged in the gas distribution business.

Accounting Records

         The accounting records of the Company are maintained in accordance with the Uniform System of
Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, the Company, as a
regulated utility, is subject to the accounting principles prescribed by the Financial Accounting Standards Board
(“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of
Certain Types of Regulation.” SFAS No. 71 provides that certain actual or anticipated costs that would
otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from
customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense
can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates.
Management’s expected recovery of deferred costs and flowback of deferred credits generally results from
specific decisions by regulators granting such ratemaking treatment. Excluding recoverable take or pay gas
charges, the McClain Plant operating and maintenance expenses, depreciation, ad valorem taxes and interest on
debt in the table below, regulatory assets are being amortized and reflected in rates charged to customers over
periods of up to 20 years. The accompanying financial statements have been presented in the format prescribed
by FERC. The requirements of FERC related to the grouping of asset, liability, revenue and expense accounts
differ from those under accounting principles generally accepted in the United States.

         The Company records certain actual or anticipated certain costs and obligations as regulatory assets or
liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will
be included in amounts allowable for recovery or refund in future rates,




LFERC FORM NO. 1 (ED. 12-88)                          Page 123.1                          I
Name of Respondent                                 This Report is:                 Date of Report Year/Period of Report
                                                   (1) X An Original                          r
                                                                                    (Mo, Da,Y )
 Oklahoma Gas and Electric Company                 (2) - A Resubmission                  / I             2004lQ4




       The following table is a summary of the Company’s regulatory assets and liabilities at December 31:

 (In millions)                                                        2004             2003
 Regulatory Assets
    Oklahoma Corporation Commission Assessment Fee               !$          0.5   $           0.4
    Deferred Tax Asset SFAS 109                                          66.9             71.3
    PowerSmith capacity payments                                             -c-           ---
    McClain Plant costs                                                  11.0              ---
    January 2002 ice storm                                                1.8              3.6
    Arkansas transition costs                                             0.7              ---
   ~
    Minimum Pension Liability Adiustment                                 64.1                  ---
        Total Regulatory Assets                                  !$     145.0      $     75.3

 Regulatory Liabilities
    Deferred Tax Liability                                              22.5             25.3

         Total Regulatory Liabilities                            !
                                                                 $      22.5       $     25.3

        Deferred tax asset represents income tax benefits previously used to reduce the Company’s revenues.
These amounts are being recovered in rates as the tempolrary differences that generated the income tax benefit
turn around. The provisions of SFAS NO. 71 allowed the Company to treat these amounts as regulatory assets
and liabilities and they are being amortized over the esthated remaining life of the assets to which they relate.

        As a result of the acquisition of a 77 percent interest in the 520 megawatt (“MW”) NRG McClain
Station (the “McClain Plant”) completed on July 9, 2004, and consistent with the 2002 agreed-upon settlement
of the Company’s rate case (the ‘‘Settlement Agreement”) with the OCC, the Company has the right to accrue a
regulatory asset, for a period not to exceed 12 months subsequent to the acquisition and operation of the
McClain Plant, consisting of the non-fuel operation and maintenance expenses, depreciation, cost of debt
associated with the investment and ad valorem taxes. All prudently incurred costs accrued through the
regulatory asset within the 12-month period would be included in the Company’s prospective cost of service and
would be recovered over a period to be determined by the OCC.

        On November 22, 2002, the OCC signed a rate order containing the provisions of a Settlement
Agreement of the Company’s rate case. The Settlement Agreement provides for, among other things, recovery
by the Company, over three years, of the $5.4 million in (deferredoperating costs, associated with the January
2002 ice storm, through the Company’s rider for sales to other utilities and power marketers (“off-system
sales”). Previously, the Company had a 50150 sharing mechanism in Oklahoma for any off-system sales. The
Settlement Agreement provided that the first $1.8 million in annual net profits from the Company’s off-system
sales will go to the Company, the next $3.6 million in annual net profits from off-system sales will go to the
Company’s Oklahoma customers, and any net profits of coff-system sales in excess of these amounts will be
credited in each sales year with 80 percent to the Company’s Oklahoma customers and the remaining 20 percent
to Company. If any of the $5.4 million is not recovered at Ihe end of the three years, the OCC will authorize the
recovery of any remaining costs. During the year ended December 31, 2004, the Company recovered
approximately $1.8 million in annual net profits from off-system sales, gave approximately $3.6 million in
annual net profits from off-system sales to the Company’s Oklahoma customers and the net profits from
IFERC FORM NO. 1 (ED. 12-88)                        Page 123.2                                                            I
 Name of Respondent                                  This Rbport is:           Date of Report Yeadperiod of Report
                                                     (1)   X An Original        (Mo, Yr)
                                                                                     Da,
  Oklahoma Gas and Electric Company                  (2)   - 4 Resubmission         I /               2004IQ4



off-system sales that exceeded the $5.4 million werc shared with 80 percent to the Company’s Oklahom,
customers and the remaining 20 percent to the Company.

         In April 1999, Arkansas passed a law (the “Restructuring Law”) calling for restructuring of the electric
utility industry at the retail level. The Restructuring Law, which had initially targeted customer choice 01
electricity providers by January 1,2002, was repealed in March 2003 before it was implemented. As part of the
repeal legislation, electric public utilities were permitted to recover transition costs. The Company incurred
approximately $2.4 million in transition costs necessary to carry out its responsibilities associated with efforts to
implement retail open access. On January 20, 2004, the APSC issued an order which authorized the Company
to recover approximately $1.9 million in transition costs over an 18-month period beginning February 2004.

         On March 29, 2004, the FERC issued an order relating to the Recognition of a Regulatory Asset for
Minimum Pension Liability. Under this order, FERC is allowing, under the conditions outlined in the order,
companies to classify their minimum pension liability, otherwise recorded in Accumulated Other
Comprehensive Income (AOCI), as a regulatory asset under FERC Accounting. The Company‘s minimum
pension liability of $64.1 million as of December 31, 2004 meets the requirements under SFAS No. 71 to be
classified as a regulatory asset for GAAP. Based on the rule, 2004 is the first reporting year required to
implement the order. This order is not a mandatory rule based on the Company’s communication in the prior
year with FERC. The order was created as an option for consistency purposes between GAAP and the FERC
statements if a company chooses to do so.

        Management continuously monitors the future recoverability of regulatory assets. When in
management’s judgment future recovery becomes impaired, the amount of the regulatory asset is reduced or
written off, as appropriate. If the Company were required to discontinue the application of SFAS No. 71 for
some or all of its operations, it could result in writing off the related regulatory assets; the financial effects of
which could be significant.                                                                                  -
                                                                                                                -

Use of Estimates

        In preparing the Financial Statements, management is required to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of contingent assets and contingent liabilities
at the date of the Financial Statements and the reported amounts of revenues and expenses during the reporting
period. Changes to these assumptions and estimates could have a material affect on the Company’s Financial
Statements particularly as they relate to pension expense. However, the Company believes it has taken
reasonable but conservative positions, where assumptions and estimates are used, in order to minimize the
negative financial impact to the Company that could result if actual results vary from the assumptions and
estimates. In management’s opinion, the areas of the Company where the most significant judgment is
exercised is in the valuation of pension plan assumptions, contingency reserves, accrued removal obligations,
regulatory assets and liabilities, unbilled revenue, the allowance for uncollectible accounts receivable and fair
value hedging policies.




[ F E W FORM NO. 1 (ED.12-88)                        Page 123.3                       I
Name of Respondent                                  This ,Reportis:           Date of Report Yeadperiod of Report
                                                    (1) X An Original          (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                  (2)   - A Resubmission         11                 0a4
                                                                                                     20Q



Cash and Cash Equivalents

        For purposes of the Financial Statements, the Company considers all highly liquid debt instruments
purchased with an original maturity of three months or less to be cash equivalents. These investments are
carried at cost, which approximates fair value.

       The Company’s cash management program utilizes controlled disbursement banking arrangements.
Outstanding checks in excess of cash balances were approximately $21.7 million and $19.0 million at December
31,2004 and 2003, respectively, and are classified as Accounts Payable in the Balance Sheets. Sufficient funds
were available to fund these outstanding checks when they were presented for payment.

Allowance for Uncollectible Accounts Receivable

        Customer balances are generally written off if not collected within six months after the original due date.
 The allowance for uncollectible accounts receivable is calculated by multiplying the last six months of electric
revenue by the provision rate. The provision rate is based on a 1Zmonth historical average of actual balances
written off. To the extent the historical collection rates are not representative of future collections, there could
be an effect on the amount of uncollectible expense recognized. The allowance for uncollectible accounts
receivable was approximately $2.7 million and $2.6 million at December 31,2004 and 2003, respectively.

       New business customers are required to provide a security deposit in the form of a case, bond, or
irrevocable letter of credit which is refunded when the ijccount is closed. New residential customers, whose
outside credit scores indicate risk, are required to provide a security deposit which is refunded after 12 months
of good payment history per the regulatory rules. The payment behavior of all existing customers is monitored
and if the payment behavior indicates sufficient risk per the regulatory rules, customers will be required to
provide a security deposit.

Fuel Inventories

       Fuel inventories for the generation of electricity consist of coal, natural gas and oil. These inventories
are accounted for under the last-in, first-out (“LIFO’) cost method. The estimated replacement cost of fuel
inventories was higher than the stated LIFO cost by approximately $13.7 million and $24.9 million for 2004 and
2003, respectively, based on the average cost of fuel purchased. The amount of fuel inventory was
approximately $42.2 million and $60.0 million at December 31,2004 and 2003, respectively.

       Effective December 31, 2003, approximately $13.7 million of natural gas storage inventory that was
previously classified as Fuel Inventories was reclassified to Property, Plant and Equipment on the Balance Sheet
due to the gas transportation and storage contract between the Company and Enogex requiring a minimum
volume of natural gas be kept in the Enogex system.

Property, Plant and Equipment

       All property, plant and equipment are recorded at cost. Newly constructed plant is added to plant
balances at costs which include contracted services, direct labor, materials, overhead, transportation costs and
IFERC FORM NO. 1 (ED. 12-88)                         Page 123.4                    I
Name of Respondent                                  This Report is:          Date of Report Year/Period of Report
                                                    (1) 3 An Original         (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                 (2) - A Flesubmission          I1               2004lQ4




the allowance for funds used during construction (“AFWDC”). Replacements of major units of property are
capitalized as plant. The replaced plant is removed from plant balances and the cost of such property less
salvage is charged to Accumulated Depreciation. Repair and replacement of minor items of property are
included in the Statements of Income as Other Operation anid Maintenance Expense. Effective January 1,2003,
removal expense has no longer been charged to Accumulated Depreciation but rather has been charged to
regulatory liabilities in accordance with SFAS No. 143.

       The Company’s property, plant and equipment are divided into the following major classes at December
3 1,2004 and 2003, respectively.

 December 31 (In millions)                                  2!004             2003
  Distribution assets                                      $ 1,934.0          $ 1,834.7
  Electric generation assets                                   1,828.3           1,628.1
  Transmission assets                                            552.8             536.9
  Intangible plant                                                 6.3               5.3
  Other DroDertv and eaubment                                    313.0             265.1
       Total property, plant and equipment                 $ 4,634.4          $ 4,270.1

Depreciation

        The provision for depreciation, which was approximately 2.9 percent of the average depreciable utility
plant for 2004 and 2003, is provided on a straight-line method over the estimated service life of the utility
assets. Depreciation is provided at the unit level for production plant and at the account or sub-account level for
all other plant, and is based on the average life group methold.

Allowance for Funds Used During Construction

       AFUDC is calculated according to the FERC pronouncements for the imputed cost of equity and
borrowed funds. AFUDC, a non-cash item, is reflected as i I credit in the Statements of Income and as a charge
to Construction Work in Progress in the Balance Sheets. AECTDC rates, compounded semi-annually, were 4.99
percent, 1.67 percent and 2.40 percent for the years 2004, 2OQ3 and 2002, respectively. The increase in the
AFUDC rates in 2004 was primarily due to a portion of capital expenditures being funded by equity funds,
which have a higher cost rate than short-term borrowings, which were used to fund capital expenditures in 2003
and 2002.

Revenue Recognition

         The Company reads its customers’ meters and sends bills to its customers throughout each month. As a
result, there is a significant amount of customers’ electricity consumption that has not been billed at the end of
each month. An amount is accrued as a receivable for this unbilled revenue based on estimates of usage and
prices during the period. The estimates that management uses in this calculation could vary from the actual
amounts to be paid by customers.



IFERC FORM NO. 1 (ED. 12-88)                        Page 123.5                     I
Name of Respondent                                    This Report is:          Date of Report Year/Period of Report
                                                      (1) An Original           (Mo, Yr)
                                                                                     Da,
 Oklahoma Gas and Electric Company                    (2) - A qesubmission           11               2004lQ4




Automatic Fuel Adjustment Clauses

       Variances in the actual cost of fuel used in electric generation and certain purchased power costs, as
compared to the fuel component in the cost-of-service for ratemaking, are passed through to the Company’s
customers through automatic fuel adjustment clauses, which are subject to periodic review by the OCC, the
APSC and the FERC. See Note 13 of Notes to Financial Statements for a discussion of the proceeding before
the OCC in which the Company is seeking to recover costs billed to it by Enogex for gas transportation and
storage services.

Accrued Vacation

        The Company accrues vacation pay by establishing a liability for vacation earned during the current year,
but not payable until the following year.

Environmental Costs

       Accruals for environmental costs are recognized when it is probable that a liability has been incurred and
the amount of the liability can be reasonably estimated. When a single estimate of the liability cannot be
determined, the low end of the estimated range is recorded. Costs are charged to expense or deferred as a
regulatory asset based on expected recovery from customers in future rates, if they relate to the remediation of
conditions caused by past operations or if they are not expected to mitigate or prevent contamination from future
operations. Where environmental expenditures relate to1 facilities currently in use, such as pollution control
equipment, the costs may be capitalized and depreciated over the future service periods. Estimated remediation
costs are recorded at undiscounted amounts, independent of any insurance or rate recovery, based on prior
experience, assessments and current technology. Accrueld obligations are regularly adjusted as environmental
assessments and estimates are revised, and remediation efforts proceed. For sites where the Company has been
designated as one of several potentially responsible parties, the amount accrued represents the Company’s
estimated share of the cost.

Related Party Transactions

         Energy Cop. allocated operating costs to the Company of approximately $89.6 million, $84.4 million
and $95.2 million during 2004, 2003 and 2002, respectively. Energy Corp. allocates operating costs to its
affiliates based on several factors. Operating costs directly related to specific affiliates are assigned to those
affiliates. Where more than one affiliate benefits from certain expenditures, the costs are shared between those
affiliates receiving the benefits. Operating costs incurred fjor the benefit of all affiliates are allocated among the
affiliates, based primarily upon head-count, occupancy, usage or the “Distragas” method. The Distragas method
is a three-factor formula that uses an equal weighting of payroll, operating income and assets. The Company
believes this method provides a reasonable basis for allocating common expenses.

       In 2004, 2003 and 2002, the Company paid Enogex approximately $34.3 million, $33.5 million and
$33.6 million, respectively, for transporting gas to the Company’s natural gas-fired generating facilities. In
2004,2003 and 2002, the Company paid Enogex approximately $15.3 million, $11.2 million and $3.3 million,
respectively, for natural gas storage services. In 2004, 20013 and 2002, the Company also recorded natural gas
IFERC FORM NO. 1 (ED.12-88)                           Page 123.8                     I
Name of Respondent                                    This Report is:                   Date of Report Year/Period of Report
                                                      (1) & An Original                  (Mo, Da, Yr)
    Oklahoma Gas and Electric Company                 (2)._ 4 Resubmission                   I1               20041Q4
1
                                        NOTES TO FINANCIAL   STATEMENTS   (Continued)


purchases from Enogex of approximately $45.2 millic)n, $20.8 million and $13.9 million, respectively.
Approximately $8.4 million and approximately $3.9 mill\ion were recorded at December 31, 2004 and 2003:
respectively, and are included in Accounts Payable - Affiliates in the Balance Sheet for these activities. There
were no amounts recorded for these activities at December 31, 2003. See Note 13 for a discussion of the gas
transportation and storage contract between the Company and Enogex.

       In 2004, 2003 and 2002, the Company recorded ilnterest income of approximately $0.7 million, $0.1
million and $0.3 million, respectively, from Energy COT. for advances made by the Company to Energy Corp.

       In 2004, 2003 and 2002, the Company recorded interest expense of approximately $0.4 million, $1.1
million and $0.7 million, respectively, to Energy Corp. for advances made by Energy Corp. to the Company.
The interest rate charged on advances to the Company from Energy Corp. approximates Energy Corp.’~
commercial paper rate.

       In 2004, 2003 and 2002, the Company paid approximately $107.4 million, $107.0 million and $103.8
million, respectively, in dividends to Energy Corp.

Reclassifications

       Certain prior year amounts have been reclassified on the Financial Statements to conform to the 2004
presentation.

2.        Accounting Pronouncements

        In June 2001, the FASB issued SFAS No. 143, which applies to legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction, development and/or the normal
operation of a long-lived asset. The scope of SFAS No. 143 includes the Company’s accrued plant removal
costs for generation, transmission and distribution assets. SFAS No. 143 requires that the fair value of a liability
for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of
the fair value can be made. If a seasonable estimate of the fair value cannot be made in the period the asset
retirement obligation is incurred, the liability shall be recognized when a reasonable estimate of the fair value
can be made. Asset retirement obligations associated with long-lived assets included within the scope of SFAS
No. 143 are those for which a legal obligation exists under enacted laws, statutes, written or oral contracts,
including obligations arising under the doctrine of promissory estoppel. The recognition of an asset retirement
obligation is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations
represent future liabilities and, as a result, accretion expense i s accrued on this liability until such time as the
obligation is satisfied. In connectian with the adoption of SFA$ No. 143, the Company assessed whether it had
a legal obligation within the scope Qf SFAS No. 143. The Company determined that it had a legal obligation to
retire certain assets. As the Company currently has no plans b retire any of these assets (except as discussed
                                                                   o
below) and the remaining life is indeterminable, an asset retirement obligation was not recognized; however, the
Company will monitor these assets and record a liability when a reasonable estimate of the fair value can be
made. During the third quarter of 2004, the Company determined the definite life of a legal obligation within
the scope of SFAS No. 143 to retire certain assets related to the expiration of a power supply contract in June
2006. The Company recorded an asset retirement obligation af approximately $1.1 million at September 30,
IFERC FORM NO. 1 (ED. 12-88)                          Page 123.7                                                               1
Name of Respondent                                    This Repbrt is:                 f
                                                                                Date o Report Year/Period of Report
                                                      (1) 3 An original          (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                    (2) - A qesubmission            / I              2004/Q4




2004 and began amortizing this amount over 21 months beginning October 1,2004.
        The Company expects that the FASB will issue an interpretation related to SFAS No. 143 during the
first quarter of 2005 in which an entity would be required to recognize a liability for the fair value of an asset
retirement obligation that is conditional on a future event if ithe liability’s fair value can be reasonably estimated.
 The fair value of a liability for the conditional asset retireqent obligation would be recognized when incurred.
Uncertainty surrounding the timing and method of settleineqt that may be conditional on events occurring in the
future would be factored into the measurement of the lidbility rather than the recognition of the liability.
However, in some cases, there is insufficient information to estimate the fair value of an asset retirement
obligation. In these cases, the liability would be initially recognized in the period in which sufficient
information is available for an entity to make a reasonable estimate of the liability’s fair value. The Company
expects that this interpretation will be effective no later thaq the end of fiscal years ending after December 15,
2005. Additionally, the interpretation is expected to permit, but not require, restatement of interim financial
information during any period of adoption. The FASB also has indicated that it will require both recognition of
a cumulative change in accounting principle and disclosure of the liability on a pro forma basis for transition
purposes. The Company will evaluate the financial impact when a final interpretation is issued.

        In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an Amendment to ARB No. 43,
Chapter 4.” This statement amends the guidance in Accounting Research Bulletin No. 43, Chapter 4 “Inventory
Pricing”, to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and
spoilage. This statement requires these items to be recogniwd as current period charges regardless of whether
the “SO abnormal” criterion is met. Adoption of SFAS No. 151 is required for inventory costs incurred during
fiscal years beginning after June 15, 2005. The Company will adopt this new standard effective
January 1,2006. Management has not yet determined what the impact of this new standard will be on its
financial position or results of operations.

        In December 2004, the FASB issued SFAS No. 123 (Revised), “Share-Based Payment”, which replaces
SFAS No. 123, “Accounting for Stock-Based Compens’atiom,” and supersedes Accounting Principles Board
(“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” This statement applies to all
share-based payment transactions in which an entity acquires goods or services by issuing (or offering to issue)
its shares, share options or other equity instruments (except for equity instruments held by an employee share
ownership plan) or by incurring liabilities to an employee or ather supplier (a) in amounts based, at least in part,
on the price of the entity’s shares or other equity instrument$ or (b) that require or may require settlement by
issuing the entity’s equity shares or other equity instruments. This statement applies to all awards granted after
the required effective date and to awards modified, repurchased or cancelled after that date. The cumulative
effect of initially applying this statement, if any, is recogniize4 as of the required effective date. This statement
requires a public entity to measure and recognize the cost of employee services received in exchange for an
award of equity instruments based on the grant-date fair valle of the award (with limited exceptions). The
grant-date fair value of employee share options and similx irlstruments will be estimated using option-pricing
models adjusted for the unique chmacteristics of those instruments. If an equity award is modified after the grant
date, incremental compensation cost will be recognized in an mount equal to the excess of the fair value of the
modified award over the fair value of the original award imediately before the modification. As of the
required effective date, all public entities that used the fair-value based method for either recognition or
disclosure under SFAS NO. 123 will apply this statement using a modified version of prospective application.
Under that transition method, compensation cost is recognizad on or after the required effective date for the
IFERC FORM NO. 1 (ED.12-88]                            Pam 123.8                      I
 Name of Respondent                                  This Report is:          Date of Report Year/Period of Report
                                                     (1) An Or ginal           (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                  (2) - A Resubmission           / I              2004/Q4




portion of outstanding awards for which the requisite service bas not yet been rendered, based on the grant-date
fair value of those awards calculated under SFAS No. 123 fot either recognition or pro forma disclosures. For
periods prior to the required effective date, those entities nnay elect to apply a modified version of retrospective
                                                               (i
application under which financial statements for prior pei-io s are adjusted on a basis consistent with the pro
forma disclosures required for those periods by SFAS No. 12b. Adoption of SFAS No. 123(R) is required for
public entities as of the beginning of the first interim or anbual period beginning after June 15, 2005. The
Company will adopt this new standard effective July 1,2!00$. Management has not yet determined what the
impact of this new standard will be on its financial position or results of operations.

3.      Price Risk Management Assets and Liabilities


                                                               x
       The Company periodically utilizes derivative contra ts to reduce exposure to adverse interest rate
fluctuations. During 2004 and 2003, the Company’s use of p ce risk management instruments involved the use
of an interest rate swap agreement. This agreement involved the exchange of fixed price or rate payments in
exchange for floating price or rate payments over the life’of the instrument without an exchange of the
underlying principal amount.

        In accordance with SFAS No. 133, the Company recqgnizes all of its derivative instruments as Price
Risk Management assets or liabilities in the Balance Sheets at fair value with such amounts classified as current
or long-term based on their anticipated settlement. The accoupting for changes in the fair value of a derivative
depends on the intended use of the derivative and resulting 4esignation. For derivative instruments that are
designated and qualify as a fair value hedge, the gain or 104s on the derivative instrument is recognized in
current earnings on the same line item as the gain or loss recorbed for the change in the fair value of the hedged
item. For derivatives that are designated and qualify as a cash how hedge, the effective portion of the change in
fair value of the derivative instrument is reported as a componept of Accumulated Other Comprehensive Income
and recognized into earnings in the same period during whidh the hedged transaction affects earnings. The
ineffective portion of a derivative’s change in fair value is racognized currently in earnings. As a matter of
policy, all hedged items and the derivatives used for cash flow hedges must be identical with respect to time and
location and must be in compliance with SFAS No. 133. Foreqasted transactions designated as the hedged item
in a cash flow hedge are regularly evaluated to assess whether they continue to be probable of occurring. If the
forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis
and all future changes in the fair value of the derivative will b~ recognized directly in earnings. Any amounts
recorded in Accumulated Other Comprehensive Income wi I1 rGmain in other comprehensive income until such
time as the forecasted transaction is deemed probable not to occIur.

       The Company’s interest rate swap agreement has been designated as a fair value hedge and qualified for
the shortcut method prescribed by SFAS No. 133. Under the $hortcut method, the Company assumes that the
hedged item’s change in fair value is; exactly as much as the, derivative’s change in fair value. See Note 9 for a
description of the Company’s interest rate swap agreement.

4.      Asset Disposals

        During the second quarter of 2004, the Company sold land and buildings near its principal executive
offices for approximately $0.9 million. The Company recognizled a gain of approximately $0.3 million related
[FERC FORM NO. 1 (ED. 12-88)                    Page 1          2          3         .          9           9
Name of Respondent                                        This R$port is:                          Date of Report Year/Period of Report
                                                          (1) X Ab Original                         (Mo, Yr)
                                                                                                          Da,
 Oklahoma Gas and Electric Company                        (2) 4Resubmission
                                                              ,_                                            I f                     2004/Q4




to the sale of this asset, which is recorded in Other Incoma in the Statements of Income.
        In September 2004, the Company sold its intprests in its natural gas producing properties foi
approximately $3.1 million. These interests had a c w i n g value of approximately $0.1 million and the
Company recognized a gain of approximately $3.0 million1 which is recorded in Other Income in the Statements
of Income. In December 2004, the Company recogriizeld an additional gain of approximately $0.2 million
related to the sale of these interests.

5.      Supplemental Cash Flow Information

        The following table discloses information about investing and financing activities that affect recognized
assets and liabilities but which do not result in cash receipts or payments. Also disclosed in the table is cash
paid for interest, net of interest capitalized, and cash paid far income taxes, net of income tax refunds.

Year ended December 3 1 (In millions)                                                    2004              2003         2002
NON-CASH INVESTING AND FINANCING ACTIVITIES


Power plant long-term service agreement                                             $       6.0        $      ---   $          --
Change in fair value of long-term debt due to interest rate swap                         (.)
                                                                                          01                (3.5)             9.9
Change in property, plant and equipment due to transfer of inventpry                      1.)
                                                                                         (37                  ---             ---
SUPPLEMENTAL CASH FLOW INFORMATION

Cash Paid During the Period for

 Interest (net of interest capitalized of $1.7, $0.5, $0.9)                         $ 3.
                                                                                       36              $ 35.9       $        35.6

 Income taxes (net of income tax refunds)                                                   22.9           (39.8)            61.9

6.      Income Taxes
        The items comprising income tax expense are as follows:

Year ended December 3 1 (In millions)                                       ,   2004                   2003                 2002
Provision (Benefit) for Current Income Taxes
    Federal                                                                     $       13.1       $       (42.0)       $      55.9
    State                                                                                 .
                                                                                         20                 (4.7)              7.7
        Total Provision (Benefit) for Current Income Taxes                               51
                                                                                        1.                 (46.7)             63.6
Provision for Deferred Income Taxes, net
    Federal                                                                             38.5                99.4               11.0
     State                                                                                2.2               13.4               2.6
       Total Provision for Deferred Ipcome Taxes, net                                   4.
                                                                                         07                112.8              13.6
Deferred Investment Tax Credits, net                                                    (5.2)               (5.2)             (54
Income Taxes Relating to Other Income and Deductions                                     2.4                (0.7)             (0.4)
       Total Income Tax Expense                                                 $       5.
                                                                                         30        $        0.2         $      71.6


IFERC FORM NO.1 (ED.12-88)                                    Page 123.10                                    I
Name of Respondent                                      This Report id:              Date of Report Year/Period of Report
                                                        (1 ) X An Orig nal            (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                         -
                                                        (2) A Resuamission                I I              2004lQ4
                                        NOTES TO FINANCIAL STATE:MEFITS(Continued)




tax accounting method change resulted in a one-time catch-up deduction for costs previously capitalized under




        The following schedule reconciles the statutory federal t$x rate to the effective income tax rate:

Year ended December 3 1                                                2004          2003          2002
Statutory federal tax rate                                              35.0%         35.0%         35.0%
State income taxes, net of federal income tax benefit                     .
                                                                         29            3.6           3.4
Tax credits, net                                                       ~ (.)
                                                                          32           (2.9)        (2.6)
Other, net                                                             , 0.4           (1 -4)        0.4
    Effective income tax rate as reported                              ~35.1%          34.3%        36.2%
                                                                       I



         The Company is a member of an affiliated group thaj files consolidated income tax returns. Income
taxes are allocated to each company in the affiliated group base/d on its separate taxable income or loss. Federal
investment tax credits on electric utility property have been Idefhrred and are being amortized to income over the
life of the related property.

         The Company follows the provisions of SFAS No. 109,;“Accounting for Income Taxes,” which uses an
asset and liability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or
                                                                       ~




                                                                       4
liabilities are computed based on the difference between the fi ancial statement and income tax bases of assets
and liabilities using the enacted marginal tax rate. Deferred iqcome tax expenses or benefits are based on the
changes in the asset or liability from period to period.

       The deferred tax provisions, set forth above, are recogpized as costs in the ratemaking process by the
commissions having jurisdiction over the rates charged by the Company. The components of Accumulated
Deferred Taxes at December 3 1,2004 and 2003 respectively, arb as follows:




[FERC FORM NO. 1 (ED. 12-88)                            Paae 123.1‘1
                                                                       I
                                                                                                                            I
Name of Respondent                                                               Date of Report Year/Period of Report
                                                                                  (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                                                      I 1            2004lQ4




(In millions)                                                            2004               2003
Current Accumulated Deferred Tax Assets
   Accrued vacation                                                      $       .
                                                                                38      $       3.9
   Uncollectible accounts                                                       11
                                                                                 .              1. I
   Other                                                                        41
                                                                                 .              1.8
        Total Current Accumulated Deferred Tax Assets                    $      9.0     $       6.8
                                                                     I
Non-Current Accumulated Deferred Tax Liabilities
   Accelerated depreciation and other property related differences       $   564 $
                                                                              3.              501.7
   Allowance for funds used during construction                                11
                                                                              3.               33.1
   Income taxes refundable to customers, net                                  1.
                                                                               20              12.2
   Bond redemption-unamortized costs                                           73               7.7
   Other                                                                       15
                                                                                .              (2.0)
        Total Non-Current Accumulated Deferred Tax Liabilities       ~        8.
                                                                             583              552.7
Non-Current Accumulated Deferred Tax Assets
   Deferred federal investment tax credits                                   (04
                                                                              1.)             (12.1)
   Postretirement medical and life insurance benefits                           (5.9)          (3.8)
   Company pension plan                                                     (.)
                                                                             16    (0.9)
        Total Non-Current Accumulated Deferred Tax Assets                  (79
                                                                            1.)   (16.8)
Non-Current Accumulated Deferred Income Tax Liabilities, net             $ 504
                                                                            7.  $ 535.9

        The Company has an Oklahoma investment tax credit (1‘lTC”) carryover of approximately $3.3 million.
These ITC carryover amounts will begin expiring in the yeaf 2017. The Company believes that, based on
current projections, these ITC carryover amounts will be fully dtilized in 2005.

American Jobs Creation Act o 2004
                            f

         On October 22,2004, President Bush signed into law thp American Jobs Creation Act of 2004 (the “Jobs
Creation Act”). The Jobs Creation Act amended and added ai significant number of provisions to the Internal
Revenue Code and these changes affect virtually all taxpayers. The Jobs Creation Act includes a provision that


                                                                     t
                                                                     ~




entitles all U.S. manufacturers with qualified manufacturing ctivities to a “Deduction Related to Production
Activities” (“DRPA”). Certain activities of the Company, incl ding the generation of electricity, is included in
the list of qualifying manufacturing activities for purposes of t e DRPA. Thus, the Company believes that the
DRPA could impact the Company’s future effective income taxi rate.

        Beginning in 2005, the DRPA equals three percent of the lesser of (a) taxable income derived from a
qualified production activity; or (b) overall taxable income fofl the taxable year. However, the deduction for a
taxable year is limited to 50 percent of the Form W-2 wages pabd by a taxpayer during the taxable year in which
the deduction is claimed. The deduction percentage increases to six percent in 2007. In 2010, when the
deduction is fully phased-in, the deduction rate will be nine perqent.

        Because the Company is an integrated electric utility, it iwill be required to allocate income and expenses
to its “qualified production activity.” The U.S. Treasury 1C)ep;krtmentissued guidance related to the DRPA on
January 19, 2005 and this guidance provides rules for det$&ning taxable income when a portion of a
taxpayer’s income is derived from a qualified production sictiyity. The FASB has determined that the DRPA
IFERC FORM NO. 1 (ED. 12-88)                           page 123.12   ’                      I
 Name of Respondent                                  This Report /is:          Date of Report Yeadperiod of Report
                                                                                (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                                                 I1                2004lQ4




will be classified as a “special deduction” for purposes of computing income tax expense which will have the
effect of reducing the Company’s overall effective tax rate ta the extent the Company can claim a deduction.
The Company is in the process of analyzing these rules to determine the effect of the DRPA on its overall
effective tax rate and income tax expense.

7.      Common Stock and Cumulative Preferred Stock

       There were no new shares of common stock issued during 2004, 2003 or 2002. The Company’s
Restated Certificate of Incorporation permits the issuance oft a new series of preferred stock with dividends
payable other than quarterly.

8.      Stock Incentive Plan



                                                                   1
        On January 21, 1998, Energy Corp. adopted a Stoclk I centive Plan (the “1998 Plan”). Under this Plan,
restricted stock, stock options, stock appreciation rights an performance units may be granted to officers,
directors and other key employees, including officers, direct0 s and employees of the Company. Energy Corp.
had authorized the issuance of up to 4,000,000 shares under thk 1998 Plan.


                                                                   T
       In 2003, Energy Corp. adopted, and its shareowneirs proved, a new Stock Incentive Plan (the “2003
Plan” and together with the 1998 Plan, the “Plans”). The 2 03 Plan replaced the 1998 Plan and no further
awards will be granted under the 1998 Plan. As under the 4998 Plan, under the 2003 Plan, restricted stock,
stock options, stock appreciation rights and performance iinitb may be granted to officers, directors and other
key employees, including officers, directors and employees of the Company. Energy Corp. has authorized the
issuance of up to 2,700,000 shares under the 2003 Plan.

Restricted Stock

        During 2004 and 2003, no restricted stock was distributed under the Plans. The restricted stock
previously distributed vests at the end of three years. Each sh&e of restricted stock is subject to forfeiture if the
recipient ceases to render substantial services to Energy Corpj or a subsidiary for any reason other than death,
disability or retirement. Awards of restricted stock are subject ito an additional condition with all or a portion of
the shares of restricted stock being subject to forfeiture based On Energy Corp.’s return on equity compared to a
peer group of companies during the three-year restriction perio4.

Performance Units

        During 2004 and 2003, respectively, Energy Corp. ayarded 162,591 performance units and 128,469
performance units to certain employees of Energy Corp. and itd subsidiaries. These performance units represent
the value of one share of Energy C a p ’ s common stock. Thesq performance units are contingently awarded and
will be payable in cash or shares of Energy Corp.’s common dtock subject to the condition that the number of
performance units, if any, earned by the employees upon the expiration of a three-year award cycle is dependent
on Energy Corp.’s total shareholder return relative to the total Shareholder return of a peer group of companies.
Each performance unit is subject to forfeiture if the recipient’ceases to render substantial services to Energy
Corp. or a subsidiary for any reason other than death, disability pr retirement.
IFERC FORM NO. 1 (ED. 12-88)                         Page 123.13   1                I
Name of Respondent                                                                                  Date of Report YearlPeriod of Report
                                                                                                          Da,
                                                                                                     (Mo, Yr)
 Oklahoma Gas and Electric Company                                                                        / I                2004lQ4




Stock Options

        Options to purchase shares of Energy C o p . conupon stock may be granted under the Plans. Such
options vest in one-third annual installments beginning on4 year from the date of grant and have a contractual
life of 10 years. To date, no options have expired unexercfsed. Stock option transactions related to the Plans
are summarized in the following table:




                                                   Options          Price             Options        Price   Options        Price
                                        -
 Options Outstanding at beginning of year          430,867         $22.2836            349,800      $23.9551  258,300      $24.5569




       The fair value of each option grant under the Plans for the years ended December 31,2004, 2003 and
2002, are estimated on the date of grant using the BlackSScholes option pricing model with the following
weighted-average assumptions used for grants in 2004,2003 /and 2002:

                                                            2004         ~           2003            2002
 Expected dividend yield                                   6.27 %          6.30%                    6.05%
 Expected price volatility                                 msa %          22.06%                   22.95%
 Risk-free interest rate                                   3.77 %          3.80%                    4.90%
 Expected life of options (in years)                          7               7                        7
 Weighted-average fair value of options granted           $ 2.05         $ 1.85                   $ 3.10

        The following table provides additional information [about stock options outstanding at December 31,
2004:

                                                  Options Outstanding        ,                     Options Exercisable
                    Weighted-Average
   Range of
 Exercise Prices
                       Remaining -
                    Contractual Life
                                             Number
                                            Outstanding
                                                           Weighted-.Avetage                 Number             -
                                                                                                          Weighted-Average
                                                                                                                         "
                4
                                                            Exercise Pride-                 Outstanding    Exercise Price
 $16.69 - $22.50       7.10 years            218,402          $19.8105 \                     127,558         $20.9131
 $23.58 - $28.75       4.96 years            208,300          $26.0892 ,                     151,100            $27.0409




(FERC FORM NO. 1 (ED. 12-88)                                 Page 123.14         '                                                         1
 Name of Respondent                                   This Report ib:                Date of Report Yeadperiod of Report
                                                                                      (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                                                       I l              2004/Q4




9.      Long-Term Debt

         At December 31,2004, the Company is in compliance With all of its debt agreements.

Long-Term Debt with Optional Redemption Provisions

       The Company’s 6.500 percent Senior Notes (“Senior Notes”) series due July 15, 2017, were repayable
on July 15, 2004, at the option of the holders, at 100 percent of the principal amount, together with accrued and
unpaid interest to July 15, 2004. Only holders who submitteb requests for repayment between May 15, 2004
and June 15, 2004 were entitled to such repayments. The Campany and the Senior Note Trustee received no
such requests for repayment of the Senior Notes.

       The Company has three series of variable rate indust~al authority bonds (the “Bonds”) with optional
redemption provisions that allow the holders to request repayment of the Bonds at various dates prior to the
maturity. The Bonds, which are redeemable at the option df the holder during the next 12 months, are as
follows:

     SERIES                      DATE DUE                                    AMOUNT
     Variable %     Garfield Industrial Authority, January 1, 2025       ’    $    47.0
     Variable %     Muskogee Industrial Authority, January 1,2025                  32.4
     Variable % Muskogee Industrial Authority, June 1,2027                         56.0
             Total (redeemableduring next 12 months)                          $   135.4

        All of these Bonds are subject to redemption at the option of the holders, at 100 percent of the principal
amount, together with accrued and unpaid interest to the date /of purchase. The bond holders, on any business
day, can request repayment of the Bond by delivering an i*evocable notice to the tender agent stating the
principal amount of the Bond, payment instructions for the lpur+haseprice and the business day the Bond is to be
purchased. The repayment option may only be exercised by the holder of a Bond for the principal amount. A
third party remarketing agent for the Bonds will attempt to rembket any Bonds tendered for purchase. Since the
original issuance of these series of Bonds in 1995 and 199’7, t$e remarketing agent has successfully remarketed
all tendered bonds. If the remarketing agent is unable to remdket any such Bonds, the Company is obligated to
repurchase such unremarketed Bonds. The Company has suffiqient liquidity to meet these obligations.

Issuance of Long-Term Debt

        In August 2004, the Comppny issued $140.0 millioniof long-term debt. The proceeds were used to
replace a portion of the short-term borrowings initially used tc) fund a portion of the McClain Plant acquisition
in July 2004. This debt has a maturity date of August 1,20:34 qnd an interest rate of 6.50 percent.

Interest Rate Swap Agreement

Fair Value Hedge

        At December 31, 2004 and 2003, the Company had ope outstanding interest rate swap agreement that
                                                                     I


IFERC FORM NO. 1 (ED. 12-88)                          Page 123.15                         I
Name of Respondent                                  This Report is:         Date of Report Year/Period of Report
                                                                             (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                                                11               2004Q4




qualified as a fair value hedge effective March 30, 2001, to aonvert $110.0 million of 7.30 percent fixed rate
debt due October 15, 2025, to a variable rate based on the thee month London InterBank Offering Rate. The
objective of this interest rate swap was to achieve a lower cost of debt and to raise the percentage of total
corporate long-term floating rate debt to reflect a level more ih line with industry standards. This interest rate
swap qualified as a fair value hedge under SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities,” as amended, and met all of the requirements fair a determination that there was no ineffective
portion as allowed by the shortcut method under SFAS No. 133.

       At December 31, 2004 and 2003, the fair values pursyant to the interest rate swap were approximately
$3.9 million and $4.0 million, respectively, and the hedge ’was1classified as Deferred Charges and Other Assets
- Price Risk Management in the Balance Sheets. A corre!spo*ding net increase of approximately $3.9 million
and $4.0 million was reflected in Long-Term Debt at December 31,2004 and 2003, respectively, as this fair
value hedge was effective at December 31,2004 and 2003.

Long-term Debt Maturities

       Maturities of the Company’s long-term debt during the pext five years consist of $1 10.0 million in 2005;
however, in the Statement of Capitalization at December 3 1,2004, no amount is shown as Long-Term Debt Due
Within One Year. The Company plans to refinance this arriourbt and the Company believes they have the ability
to do so as Energy Corp. and the Company entered into new bve-year revolving credit agreements in October
2004 in an amount up to $550 million which could be utilized to temporarily finance these notes when they
mature in October 2005.

      The Company has previously incurred costs related to debt refinancings. Unamortized debt expense and
unamortized loss on reacquired debt are classified as Defferred Charges and Other Assets - Other and
unamortized premium and discount on long-term debt is clapsified as Long-Term Debt, respectively, in the
Balance Sheets and are being amortized over the life of the resdective debt.

10.      Short-Term Debt

        In December 2003, the Company issued commercial pbper in anticipation of the planned acquisition of
the McClain Plant by the end of 2003 and the short-term d&btbalance was approximately $50.0 million at
December 31, 2003. Due to a delay in the completion of the McClain Plant acquisition, the Company
transferred these funds to Energy Corp. for investment and at December 31, 2003, the Company had
approximately $51.8 million in outfitanding advances to Energy Corp. Due to the delay in the completion of the
McClain Plant acquisition, Energy Corp. repaid the outstanding advances and the Company used these funds to
repay the outstanding commercial paper balance during the fitst quarter of 2004. At December 31, 2004, the
Company had approximately $26.5 million in outstanding advmces to Energy Corp. and no commercial paper
outstanding.

       The following table shows Energy Corp.’s and the Clompany’s lines of credit in place and available cash
at December 3 1, 2004. At December 31, 2004, Energy Courp.’$ short-term borrowings consisted of commercial
paper.

( F E W FORM NO.1 (ED.12-88)                        Page 123.16                                                    I
Name of Respondent                                    This Report id:           Date of Report Yeadperiod of Report
                                                      (1) 3 An Clrigihal         (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                        -
                                                      (2) A Resu4mission              I /                  2004lQ4




                              Lines of Credit and Available Cash (In mfZZions)
         Entity                   Amount Available              Amoulnt                     Maturity
                                                              OutstanQling
 Energy Corp.                         $    15.0                  $ -*-                   April 6,2005
 The Company                              100.0                       -*-            October 20,2009 (B)
 Energy Corp. (A)                         450.0                       -*-            October 20,2009 (B)
                                          565.0                      ‘ -
                                                                    -I



 Cash                                     26.4                      NIA                       NIA
   Total                              $ 591.4                    $ --r
 (A) This line of credit is used to back up a maximum of $300.0 nlillibn of Energy Corp.’s commercial
 paper borrowings, which were approximately $125.0million at Dlecebber 3 1, 2004.
 (B) Each of the new credit facilities has a five-year term with two options to extend the term for one
 year.

       On October 20, 2004, Energy Corp. and the Company entered into revolving credit agreements totaling
$550 million. These agreements include two separate credit facilities, one for Energy Corp. in an amount up to
$450 million and one for the Company in an amount up to $ LOO’million. Each of the new credit facilities has a
five-year term with two options to extend the term for one year.

       Energy Corp.’s and the Company’s ability to access the commercial paper market could be adversely
impacted by a credit ratings downgrade. Their respective back-up lines of credit contain rating grids that require
annual fees and borrowing rates to increase if they suffer an adverse ratings impact. The impact of any future
downgrades would result in an increase in the cost of short-term borrowings but would not result in any defaults
or accelerations as a result of the rating changes.

       Unlike Energy Corp. and Enogex, the Company must obtain regulatory approval from the FERC in order
to borrow on a short-term basis. The Company has the necesfjary regulatory approvals to incur up to $400
million in short-term borrowings at any one time. In November $004, the Company received approval from the
FERC to incur up to $400 million in short-term borrowings for ab additional two-year period beginning January
1,2005 through December 3 1,2006.

11.    Retirement Plans and Postretirement Benefit Plans

        In December 2003, the FASB issued SFAS No. 132 (Reqised), “Employer’s Disclosures about Pension
and Postretirement Benefits, an amendment of FASB Statemefits No. 87, 88 and 106,” which revised the
disclosure requirements applicable to employers’ pension plans and other postretirement benefit plans. This
                                                                       I




Statement requires additional disclosures for defined benefit pension plans and other defined benefit
postretirement plans, including disclasures describing the comp0nents of net periodic benefit cost recognized
during interim periods.

Defined Benefit Pension Plan

       All eligible employees of the Company are covered by a non-contributory defined benefit pension plan
sponsored by Energy Corp. In early 2000, the Board of Directors ,of Energy Coy. approved significant changes
(FERC FORM NO. 1 (ED. 12-88)                          Page 123.17
                                                                                                                      1
Name of Respondent                                  This Report ib:                                    f
                                                                             Date of Report Yeadperiod o Report
                                                    (1) X An Ori@nal          (Mol Da, Yr)
 Oklahoma Gas and Electric Company                  (2) - A Fiesqbmission          I l              2004IQ4



to the pension plan. Prior to these changes, benefits were based primarily on years of service and the average of
the five highest consecutive years of compensation during an amployee’s last 10 years prior to retirement, with
reductions in benefits for each year prior to age 62 that an einpbyee retired and additional significant reductions
for retirement prior to age 55. The changes made in 2000 inclbded (i) elimination of the significant reduction
for employees electing to retire before age 55; (ii) the addition of an alternative method of computing the
reduction in benefits (based on years of service and age); and (iii) the ability of an employee at time of
retirement to receive, in lieu of an annuity, a lump sum payment equal to the present value of the annuity. Also,
for employees hired after January 31, 2000, the pension plan will be a cash balance plan, under which Energy
Corp. annually will credit to the employee’s account an amouat equal to five percent of the employee’s annual
compensation plus accrued interest. Employees hired prior to February 1,2000, will receive the greater of the
cash balance benefit or the benefit based on final average compensation as described above.

        It is Energy Corp.’s policy to fund the plan on a current basis based on the net periodic SFAS No. 87
pension expense as determined by the Company’s actuarial congultants. Additional amounts may be contributed
from time to time to increase the funded status of the plan, During 2004 and 2003, Energy Corp. made
contributions of approximately $69.0 million and $50.0 nlilliion, respectively, of which approximately $54.5
million and $38.8 million, respectively, were allocated to the Company, to ensure that the plan maintains an
adequate funded status. Such contributions are intended to pravide not only for benefits attributed to service to
date, but also for those expected to be earned in the future. During 2005, Energy Corp. plans to contribute
approximately $37.4 million to the plan, of which approximately $29.0 million is expected to be allocated to the
Company. The expected contribution to the pension plan, anticipated to be in the form of cash, is a
discretionary contribution and is not required to satisfy the midimum regulatory funding requirements specified
by the Employee Retirement Income Security Act of 1974.

        During 2004 and 2003, Energy Corp. made contributions to the pension plan and the restoration of
retirement income plan that exceeded amounts previous1:y recognized as net periodic pension expense and
recorded a net prepaid benefit obligation at December 31, 2004 and 2003 of approximately $92.0 million and
$55.7 million, respectively, of which approximately $67.0 million and $37.5 million, respectively, were
allocated to the Company. At December 31, 2004 and. 2003, Energy Corp.’s projected pension benefit
obligation exceeded the fair value of pension plan assets and the restoration of retirement income plan assets by
approximately $123.3 million and $131.8 million, respecl.ively, of which approximately $105.9 million and
$117.6 million, respectively, were allocated to the Company. As a result of recording a prepaid benefit
obligation and having a funded status where the projected benefit obligations exceeded the fair value of plan
assets, provisions of SFAS No. 87, “Employers’ Accountin8 for Pensions,” required the recognition of an
additional minimum liability in the amount of approximately $156.6 million and $137.6 million, respectively,
for Energy Corp., of which approximately $136.3 million and $122.8 million, respectively, were allocated to the
Company at December 31, 2004 and 2003. The offset of this entry was an intangible asset and Other
Regulatory Assets, net of a deferred tax asset; therefore, this a4ustment did not impact the results of operations
in 2004 or 2003 and did not require a usage of cash and is therefore excluded from the Statements of Cash
Flows. The amount recorded as an intangible asset equaled the unrecognized prior service cost with the
remainder recorded in Other Regulatory Assets. The arrioufit in Other Regulatory Assets represents a net
periodic pension cost to be recognized in the Statements of lncdme in future periods.



IFERC FORM NO. 1 (ED. 12-88)                        Page 123.1B                     I
 Name of Respondent                                 This Rhport is:            Date of Report Year/Period of Repor
                                                    (1) X An Original           (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                    -
                                                    (2) 4 Resubmission                I /            2004lQ4



       The plan’s assets consist primarily of investments in mutual funds, U.S. Government securities, liste
common stocks and corporate debt. The following table shows, by major category, the percentage of the fa
value of the plan assets held at December 31,2004 and 2003:

                                                            2004        2003
          Equity securities                                  62 %        61 %
          Debt securities                                    36 %        38    %I


          Other securities                                    2%          1%
             Total                                          100 %       100 %

Investment Policies and Strategies

       The plan assets are held in a master trust which follows an investment policy and strategy designed to
maximize the long-tern investment returns of the master tmst at prudent risk levels. Common stocks are used
as a hedge against moderate inflationary conditions, as m l l as for participation in normal economic times.
Fixed income investments are utilized for high current lincdme and as a hedge against deflation. Energy Corp.
has retained an investment consultant responsible for the general investment oversight, analysis, monitoring
investment guideline compliance and providing quarteirly reports to certain of Energy Corp.’s members and
Energy Corp.’s Employees’ Benefit Funds Management Requirements Committee (the “Committee”).

       The various investment managers used by the master trust operate within the general operating
objectives as established in the investment policy and within the specific guidelines established for their
respective portfolio. The table below shows the target asset allocation percentages for each major category of
plan assets:

           Asset Class                Target Allocation      pinimum                Maximum
 Domestic Equity                           30 %                --- %                 60 %
 Domestic Mid-Cap Equity                    10 %               --- %                 10 %
 Domestic Small-Cap Equity                  10 %               --- %                 10 %
 International Equity                       10 %               --- %                 10 %
 Fixed Income Domestic                      38 %               30 %                  70 %
 Cash                                         2%                --- %                 5%

       The portfolio is rebalanced on a periodic basis to bring the asset allocations of various managers in line
with the target asset allocation listed above. More frequent rebalancing may occur if there are dramatic price
movements in the financial markats which may cause the tnist’s exposure to any asset class to exceed or fall
below the established allowable guidelines.

        To evaluate the progress of the portfolio, investment performance is reviewed quarterly. It is, however,
expected that performance goals mill be met over a full miarket cycle, normally defined as a three to five year
period. Analysis of performance is within the context of the prevailing investment environment and the
advisors’ investment style. The goal of the master trust is to orovide a rate of return consistently from three to
five percent over the rate of inflatian (as measured by the natiopal Consumer Price Index) over a typical market
cycle of no less than three years and no more than five years. Each investment manager is expected to
outperform its respective benchmark. Below is a list of each gsset class utilized with appropriate comparative
IFERC FORM NO. 1 (ED.12-88)                          Page 123.19                                                 1
Name of Respondent                                  This Repart is:           Date of Report Year/Period of Report
                                                    (1) g An Ckigirial         (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                     -
                                                    (2) A Resu6mission             l I               2004lQ4




benchmark(s) each manager is evaluated against:

                    Asset Class                  Comparative Bepchmark(s)
               Fixed Income            Lehman Aggregate Inde:x
               Value Equity            Russell lo00 Value Index - Short-term
                                       S&P 500 Index - Long-term
               Growth Equity           Russell lo00 Growth Index - Short-term
                                       S&P 500 Index - Long-term
               Mid-Cap Equity          Russell Midcap Index
               Small-Cap Equity        Russell 2000 Index
               Global Equity           Morgan Stanley Capital International Europe,
                                       Australia and Far East l n d e ~

        The fixed income manager is expected to use discretioQ over the asset mix of the master trust assets in
its efforts to maximize risk-adjusted performance. Exposure to any single issuer, other than the U.S.
government, its agencies, or its instrumentalities (which have no limits) is limited to five percent of the fixed
income portfolio as measured by market value. Exposure to anp single non-government issue is limited to three
percent. At least 80 percent of the invested assets must posses$ an investment grade rating at or above Baa3 or
BBB- by Moody’s Investors Service (“Moody’s”), Standard & Poor’s Ratings Services (“Standard & Poor’s”),
Fitch Ratings (“Fitch”) or Duff & Phelps LLC. The manager may invest up to 10 percent of the portfolio’s
market value in cash equivalents (securities with less than six rponths to maturity). The portfolio may invest up
to 10 percent of the portfolio’s market value in convertible bonds as long as the securities purchased meet the
quality guidelines. No mortgage derivatives or structured riotas are permitted. The purchase of any of Energy
Corp.’s or its subsidiaries equity, debt or other securities is prohibited unless prior approval of the Committee is
received.

       The domestic value equity managers focus on stocks t b t the manager believes are undervalued in price
and earn an average or less than average return on assets, and often pays out higher than average dividend
                                                                         in
payments. The domestic growth equity manager will invest p ~ m a r i l y growth companies which consistently
experience above average growth in earnings and sales, earn a high return on assets, and reinvest cash flow into
existing business. The mid-cap equity portfolio manager foeuses on companies with market capitalizations
lower than the average company traded on the public exchanges with the following characteristics:
price/earnings ratio at or near the Russell Midcap, small dividend yield, return on equity at or near the Russell
Midcap and earnings per share growth rate at or near the Russell Midcap. The small-capitalization equity
manager will purchase shares of companies with market capitalizations lower that the average company traded
on the public exchanges with the following characteristics: pice/earnings ratio at or near the Russell 2000,
small dividend yield, return on equity at or near the Russell 2000 and earnings per share growth rate at or near
the Russell 2000. The global equity manager invests prirnadly in non-dollar denominated equity securities.
Investing internationally diversifies the overall master trust auross the global equity markets. The manager is
required to operate under certain restrictions including: regional constraints, diversification requirements and
percentage of U.S. securities. The Morgan Stanley Capital International Europe, Australia and the Far East
Index (“EAFE”) are the benchmark for comparative performance purposes. The EAFE Index is a market value
weighted index comprised of over 1,000 companies traded an the stock markets of Europe, Australia, New
Zealand and the Far East. All of the equities which are purchased for the fund are thoroughly researched.

IFERC FORM NO. 1 (ED. 12-88)                         Page 123.20                    I
Name of Respondent                                   This Flepdrt is:          Date of Report Year/Period of Report
                                                     (1) & 19n Original         (Mo,Da, Yr)
  Oklahoma Gas and Electric Company                  (2) - ,A Rbsubmission          I /               2004lQ4




        For all equity investment managers, only companiqs with a market capitalization in excess of $100
million are allowable. No more than five percent of the portloolio can be invested in any one stock at the time of
purchase. All securities are freely traded on a recognizedl stock exchange and there are no 144-A securities and
no over-the-counter derivatives. The following investment pategories are excluded: options (other than traded
currency options), commodities, futures (other than currenqy futures or currency hedging), short saledmargin
purchases, private placements, unlisted securities and real edtate (but not real estate shares). A minimum of 95
percent of the total assets of an equity manager’s portfolio must be allocated to the equity markets. Private
placement or venture capital may not be purchased. All iaterest and dividend payments must be swept on a
daily basis into a short-term money market or fund for re-deployment, The purchase of any of Energy Corp.’s or
its subsidiaries equity, debt or other securities is prohibited unless prior approval of the Committee is received.
The purchase of equity or debt issues of the portfolio manager’s organization is also prohibited unless prior
approval of the Committee is received.

Restoration of Retirement Income Plan

       Energy Corp. provides a restoration of retirement inqome plan to those participants in Energy Corp.’s
pension plan whose benefits are subject to certain limitatioqs under the Internal Revenue Code (the “Code”).
The benefits payable under this restoration of retirement inc4me plan are equivalent to the amounts that would
have been payable under the pension plan but for these linnitations. The restoration of retirement income plan is
intended to be an unfunded plan.

Postretirement Benefit Plans

        In addition to providing pension benefits, Energy Oorp. provides certain medical and life insurance
benefits for retired members (“postretirement benefits”). Regular, full-time, active employees hired prior to
February 1, 2000, whose age and years of service total or exjceed 80 or have attained age 55 with 10 years of
service at the time of retirement are entitled to these gostretirement benefits. Employees hired after
January 31, 2000, are not entitled to the postretirement medic41 benefits but are entitled to the postretirement life
insurance benefits. Eligible retirees must contribute such aqount as Energy Corp. specifies from time to time
toward the cost of coverage for postretirement benefits. The benefits are subject to deductibles, co-payment
provisions and other limitations. The Company charges to expense the SFAS No. 106, “Employers’ Accounting
for Postretirement Benefits other than Pensions,” costs and iocludes an annual amount as a component of the
cost-of-service in future ratemaking proceedings.
       The details of the funded status of the pension plan (including the restoration of retirement income plan)
and the postretirement benefit plans and the amounts included in the Balance Sheets are as follows:




IFERC FORM NO. 1 (ED.12-88)                          Paae 123.i!l                                                     I
c

Name of Respondent                                                    This F(/eportis:                   Date of Report Yeadperiod of Repor
                                                                      (1) 3 4n Original                   (Mo, Da, Yr)
    Oklahoma Gas and Electric Company                                 (2) - 4 Resubmission                        I I              2004IQ4
                                                NOTES TO FINANCIAL ST~TEMENTS(Continued)


Projected Benefit Obligations

                                       Pension Plan and
                                   Restoration of Retirement                           Postretirement
                                         Income Plan                                   Benefit Plans
 (In millions)                       2004                2003                  2004                 2003
Beginning obligations               $ (404.0)           $ (373.9)             $ (156.1)             $ (160.9)
Service cost                           (11.3)              (10.3)                 (2.1)                 (2.1)
Interest cost                          (24.4)              (24.6)                  (9.6)                (9.4)
Participants’ contributions                  I--                ---               (2.5)                 (1.8)
Plan changedother                          (1.3                (3.0)                      ---               ---
Actuarial gains (losses)                  (43.5)              (34.3)                 (6-1)                  7.8
Benefits paid                              37.4                42.1                  11.6                  10.3
Ending obligations                     $ (447.1)        $ (404.0)                  (164.8)          $ (156.1)


Fair Value of Plans’ Assets

                                       Pension Plan and
                                   Restoration of Retirement                           Postretirement
                                         Income Plan                                   Benefit Plans
(In millions)                            2004               2003               2b4                  2003
Beginning fair value                    $ 286.4         $    236.1             $ ’ 54.2             §
                                                                                                    !    44.6
Actual return on plans’ assets             37.6               53.6                       9.0              9.5
Employer contributions                     54.6               38.8                       7.8            8.6
Participants’ contributions                  --.                ---                      2.6            1.8
Benefits paid                             (37.4)             (42.1)                ,   (11.6)         (10.3)
Ending fair value                       $ 341.2         $    286.4             $        62.0        $ 54.2

Net Periodic Benefit Cost

                                               Pension Plan and
                                           Restoration of Retirement                                        Postretirement
                                                 Income Plan                                                Benefit Plans
(In millions)                         2004           2003           ;!ooq                         2004            2003             2002
Service cost                        $   11.3      $     10.3     $        ‘9.1                  $      2.1    $
                                                                                                              !        2.1     $          1.9
Interest cost                           24.4            24.6            24.5                           9.6             9.4                8.5
Return on plan assets                  (25.5)          (19.9)          (22.6)                         (5.3)           (5.2)           (5.3)
Amortization of transition
  obligation                                I--
                                                               ---                      ---              2.5             2.5           2.5
Amortization of net loss                    9.6               10.9                      3.7              4.6             3.1           0.5
Amortization of unrecognized
  prior service cost                        5.2                5.0                      4.8              1.5             1.5              1.5
Net periodic benefit cost          $       25.0     $         30.9        $            19.5     $       15.0       $    13.4   $          9.6

       The capitalized portion of the net periodic pension benefit cost was approximately $7.8 million, $5.7
million and $3.9 million at December 31,2004,2003 and 20@, respectively. The capitalized portion of the net
periodic postretirement benefit cost was approximately $4.7 n)lllion, $2.5 million and $1.9 fillion at December
3 1,2004,2003 and 2002,regpectively.


IFERC FORM NO. 1 (ED.12-88)
                                                                       Page 123.,22                               1
 Name of Respondent                                                This Rep04 is:                            Date of Report Yeadperiod of Report
                                                                   (1) 21 An Oliginal                         (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                                (2) - P I R+ubmission                             I /               2004lQ4




Funded Status of Plans

                                              Pension Plan and
                                          Restoration of Retirement                                Postretirement
                                                Income Plan                                         Benefit Plans
 (In millions)                              2004            2003                                2004              2003
Funded status of the plans                $ (105.9) $ (117.6)                                   $ (102.8)        $ (101.9)
Unrecognized net loss                          141.1           119.3                                56.3             58.5
Unrecognized prior service cost                 31.8            35.81                                6.9               8.4
Unrecognized transition obligation                  ---                 ---                         20.3             22.9
Net amount recognized                     !§    67.0         $        37.5        ~             !§ (19.3)        $ (12.1)

Amounts recognized in the Balance Sheets consist of:

                                                                Pension ]Planland
                                                            Restoration of Re#irement

 (In millions)                                               2004                     ~       2003
Prepaid benefit obligation                            !§         67.2         $                   37.5
Accrued pension and benefit obligations                        (136.5)                          (122.8)
Intangible asset - unamortized prior service cost                31.8                             35.7
Accumulated deferred tax asset                                   40.4                             33.7
Accumulated other commehensive loss. net of tax                  64.1                             53.4
Net amount recognized                                 $          67.0         $                   37.5


Rate Assumptions

                                                                                                                      Postretirement
                                                    Pension Plan                                                      Benefit Plans
                                      2004                2003                2@                           2004            2003          2002
Discount rate                         5.75 %               6.25%              6.74%                        5.75 %          6.25%         6.75%
Rate of return on plans’ assets       8.75 %               8.75%              9.4%                         8.75 %          8.75%         9.00%
Compensation increases                4.50%               4.50%               4.50%                        4.50 70         4.50%         4.50%
Assumed health care cost trend:
 Initial trend                          NIA                 NIA                 Y
                                                                               NA                         10.00%           11.00%       12.00%
 Ultimate trend rate                    NIA                 NIA                NP                          4.50 %           4.50%        4.50%
 Ultimate trend year                    NIA                 NIA                NlA                          2010             2010         20 10
N/A - not applicable

          The overall expected rate of return on plan assets asspmption remained 8.75 percent in 2003 and 2004
in determining net periodic pension cost. The rate of return ob plan assets assumption is the average long-term
rate of earnings expected on the fuads currently invested and t4 be invested for the purpose of providing benefits
                                                                                          ,
specified by the pension plan or postretirement benefit plans. This assumption is reexamined at least annually
and updated as necessary. The rqte of return on plan assets1 assumption reflects a combination of historical
return analysis, forward-looking return expectations and the: pldns’ current and expected asset allocation.

       The Company expects to pay benefits related to its pqnsion plan and restoration of retirement income
plan of approximately $49.3 million in 2005, $48.6 million ip 2006, $46.4 million in 2007, $48.2 million in

IFERC FORM NO. 1 (ED. 12-88)                                     Page 123.23                                         I
Name of Respondent                                     This Reportiis:                                          f
                                                                                     Date of Report Year/Period o Report
                                                       (1) X An Original              (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                         -
                                                       (2) A Resubmission                  I1                20WQ4




2008, $49.1 million in 2009 and $227.8 million in years 21010 to 2014. These expected benefits were based on
the same assumptions used to measure the Company’s b’eneifit obligation at the end of the year and include
benefits attributable to estimated future employee service.

          The assumed health care cost trend rates have a significant effect on the amounts reported for
postretirement medical benefit plans. A one-percentage point1 change in the assumed health care cost trend rate
would have the following effects:

                               ONE-PERCENTAGEPOINT INCWASE
 (In millions)                                                            2004         2003       2002

 Effect on aggregate of the service and interest cost components,         $ 1.5        $    1.5   $    1.3
 Effect on accumulated postretirement benefit obligations                     19.9         19.2       19.6

                               ONE-PERCENTAGEPOINT DlECNASE
                                                                     I
 (In millions)                                           2004                          2003       2002

 Effect on aggregate of the service and interest cost components,         $   1.2      $    1.2   §
                                                                                                  !    1.0
 Effect on accumulated postretirement benefit obligations                     16.4         15.7       16.1

Medicare Prescription Drug, Improvement and ModernizatiQnAct of 2003

         On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement
and Modernization Act of 2003 (the “Medicare Act”). The: Medicare Act expanded Medicare to include, for the
first time, coverage for prescription drugs. Due to various uacertainties related to Energy Corp.’~response to
this legislation in relation to its postretirement medical plan and the appropriate accounting methodology for this
event, Energy Corp. elected to defer financial recognition of this legislation until the FASB issued final
accounting guidance. This deferral election was permitteq under FASB Staff Position No. FAS 106-1,
“Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003.” In May 2004, the FASB issued IbASB Staff Position No. FAS 106-2, “Accounting

                                                                     fl
and Disclosure Requirements Related to the Medicare Prelscri tion Drug, Improvement and Modernization Act
of 2003.” FAS 106-2 provides guidance on the accounting r the effects of the Medicare Act for employers
that sponsor postretirement heath care plans that provide pregcription drug benefits. FAS 106-2 also requires
those employers to provide certain disclosures regarding the effect of the federal subsidy provided by the
Medicare Act. For employers who elected to defer financial recognition, FAS 106-2 provides two alternative
methods of adoption which include a retroactive application to the date of the Medicare Act’s enactment or a
prospective application as of the date of adoption. For employers who elected not to defer financial recognition,
FAS 106-2 requires these employers to recognize a cumulative effect of a change in accounting principle in
accordance with APB Opinion No. 20, “Accounting Changes.’’ Adoption of FAS 106-2 is required for financial
statements issued for periods beginning after June 15, 2004. Bnergy Corp. adopted this new standard effective
July 1,2004 with retroactive application to the date of the Pvledicare Act’s enactment. Management expects that
the accumulated plan benefit obligation (“APBO”) for Eneqgy Corp.’s postretirement medical plan will be
reduced by approximately $13.3 million as a result of sairinqsto Energy Corp.’s postretirement medical plan
resulting from the Medicare Act, which will reduce Energy Corp.’s costs for its postretirement medical plan by

IFERC FORM NO. 1 (ED. 12-88)                            Page 12324                                                         I
Name of Respondent                                  This R/?port is:         Date of Report Year/Period of Report
                                                    (1 ) 21 qn Original       (Mo, Da,Yr)
 Oklahoma Gas and Electric Company                     -
                                                    (2) 4 Resubmission             f l              2004lQ4



approximately $2.5 million annually, of which approxiqately $2.1 million is expected to be allocated to thc
Company. The $2.1 million in annual savings is compriskd of a reduction of approximately $1.2 million fron
amortization of the $13.3 million gain due to the reduction of the APBO, a reduction in the interest cost on thc
APBO of approximately $0.7 million and a reduction in the service cost due to the subsidy of approximatel!
$0.2 million.

       The Company expects to pay gross benefits p a p e n t s related to its postretirement benefit plans,
including prescription drug benefits, of approximately $10.4 million in 2005, $10.1 million in 2006, $10.0
million in 2007, $10.6 million in 2008, $11.1 million in q009 and $61.9 million in years 2010 to 2014. The
Company expects to receive subsidy receipts related to it4 postretirement benefit plans of approximately $0.5
million in 2006, $0.5 million in 2007, $0.6 million in 2008, $0.6 million in 2009 and $3.6 million in years 2010
to 2014. The Company does not expect to receive any subsidy receipts in 2005.

Dejined Contribution Plan

         Energy COT. provides a defined contribution savings plan. Each regular full-time employee of Energy
Corp. or an affiliate is eligible to participate in the plan imiediately. All other employees of Energy Corp. or an
affiliate are eligible to become participants in the plan aft6r completing one year of service as defined in the
plan. Participants may contribute each pay period any wholi: percentage between two percent and 19 percent of
their compensation, as defined in the plan, for that pay period. Contributions of the first six percent of
compensation are called “Regular Contributions” and amy Qontributionsover six percent of compensation are
called “Supplemental Contributions.” Energy Corp. contribjutes to the Plan each pay period on behalf of each
participant an amount equal to 50 percent of the participabt’s Regular Contributions for participants whose
employment or re-employment date, as defined in the plan, occurred before February 1,2000 and who have less
than 20 years of service, as defined in the plan, and an amoynt equal to 75 percent of the participant’s Regular
Contributions for participants whose employment or re-ernplbyment date occurred before February 1,2000 and
who have 20 or more years of service. For participants whoqe employment or re-employment date occurred on
or after February 1, 2000, Energy Corp. shall contribute l W percent of the Regular Contributions deposited
during such pay period by such participant. No Energy iCorp. contributions are made with respect to a
participant’s Supplemental Contributions or with respect tc) a participant’s Regular Contributions based on
overtime payments, pay-in-lieu of overtime for exempt persorlnel and special lump-sum recognition awards and
lump-sum merit awards included in compensation for detemining the amount of participant contributions.
Energy Corp.’s contribution which is allocated for investment to the Energy Corp. Common Stock Fund may be
made in shares of Energy C o p ’ s common stock or in cash flhich is used to invest in Energy Corp.’s common
stock. The Company contributed approximately $3.9 million,, $3.6 million and $3.2 million during 2004, 2003
and 2002, respectively, to the defined contribution plan.

Deferred Compensation Plan

          Energy Corp. provides a deferred compensation plap. The plan’s primary purpose is to provide a
tax-deferred capital accumulation vehicle for a select group of anagement, highly compensated employees and
non-employee members of the Board of Directors of Energy           and to supplement such employees’ defined
contribution plan contributions.


IFERC FORM NO.1 (ED. 12-88)                         Page 123.25                    I
Name of Respondent                                  This Report is:          Date of Report Year/Period of Report
                                                    (1) X An Original         (Mol,Da, Yr)
 Oklahoma Gas and Electric Company                  (2) - A Resjlbmission          I t                  2004/Q4



                                                              o
        Eligible employees who enroll in the plan may elect t defer up to a maximum of 70 percent of base
salary and 100 percent of bonus awards; however, the Benefits Committee, appointed by the Benefits Oversight
Committee (which consists of at least two members appointed by the Board of Directors) may, at its discretion,
permit participants to elect a deferral percentage of base slalary and bonus awards based on the deferral
percentage elected for a year under the defined contribution plan, with such deferrals to start when maximum
deferrals to the defined contribution plan have been made because of limitations in that plan. Eligible directors
who enroll in the plan may elect to defer up to a maximum of LOO percent of directors’ meeting fees and annual
retainers. Energy Corp. matches employee (but not non-employee director) deferrals to provide for the match
that would have been made under the defined contribution pl@nhad such deferrals been made under that plan
without regard to the statutory limitations on elective deferrals and matching contributions applicable to the
defined contribution plan. In addition, the Benefits Committee may award discretionary employer contribution
credits to a participant under the plan. Energy Corp. accouqts for the contributions in this plan as Accrued
Pension and Benefit Obligations and Other Deferred Credits and the investment associated with these
contributions is accounted for as Other Property and Investments in its Consolidated Balance Sheets. The
appreciation of these investments is accounted for as Other Ibcome and the increase in the liability under the
plan is accounted for as Other Expense in Energy Corp.’~ Conaolidated Statements of Income.

Supplemental Executive Retirement Plan

       Energy Corp. provides a supplemental executive retirement plan in order to attract and retain lateral hires
or other executives designated by the Compensation Comnlittete of Energy C o p ’ s Board of Directors who may
not otherwise qualify for a sufficient level of benefits under Energy Corp.’~  pension plan. The supplemental
executive retirement plan is intended to be an unfunded plan and not subject to the benefit limits imposed by the
Code.

12.     Commitments and Contingencies

Capital Expenditures

       The Company’s capital expenditures are estimated at approximately: 2005 - $235.7 million, 2006 -
$215.0 million and 2007 - $197.0 million.

Operating Lease Obligations

      The Company has an operating lease expiring Miarch 31, 2006 for railcar leases. Future minimum
payments for this noncancellable operating lease are as followsc

                                                                                             2010 and
 (In millions)                              2005      2006        2007    2008     2009       Beyond


     Railcars (A)                          !$   5.4 !$    5.4 !$, 5.3    !$ 5.4  !$ 5.3   !$ 24.9
 (A) The Company’s current railcar operating lease expires Marchi 31, 2006. The Company expects to
 enter into a similar lease agreement for railcars at the expiratibn of the current lease. Therefore,
 comnarable future minimum Davments have been included in the table above.
                               I     d
                                                                  I

IFERC FORM NO. 1 (ED. 12-88)                        Page 123.26
                                                                                                                    I
 Name of Respondent                                 This Repoh is:           Date of Report Yeadperiod of Report
                                                    (1) 3 An Original         (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                 (2) -E\ Rqsubmission          / I              20041Q4




       Payments for operating lease obligations were approximately $5.4 million, $5.4 million and $5.4 million
in 2004,2003 and 2002, respectively.

Railcar Leases

        At December 31, 2004, the Company has a noncancellable operating lease which has purchase options
covering 1,464 coal hopper railcars to transport coal from Wyoming to the Company’s coal-fired generation
units. Rental payments are charged to Fuel Expense and we recovered through the Company’s tariffs and
automatic fuel adjustment clauses. At the end of the lease tern which is March 31, 2006, the Company has the
option to purchase the railcars at a stipulated fair market value. If the Company chose not to purchase the
railcars and the actual value of the railcars was less than the stipulated fair market value, the Company would be
responsible for the difference in those values up to a maximum of approximately $36 million. The Company
expects to enter into a new lease agreement for railcars effective April 1, 2006, which should negate any
financial exposure under the current lease agreement. The CDmpany is also required to maintain the railcars it
has under lease to transport coal from Wyoming and has entered into agreements with Progress Rail Services
and WATCO, both of which are non-affiliated companies, to ffurnishthis maintenance.

Public Utility Regulatory Policy Act o 1978
                                      f

        The Company has entered into agreements with three qualifying cogeneration facilities having initial
terms of three to 32 years. These contracts were entered into pursuant to the Public Utility Regulatory Policy
Act of 1978 (“PURPA”). Stated generally, PURPA and the regulations thereunder promulgated by the FERC
require the Company to purchase power generated in a manufacturing process from a qualified cogeneration
facility (“QF”). The rate for such power to be paid by the Company was approved by the OCC. The rate
generally consists of two components: one is a rate for actual electricity purchased from the QF by the
Company; the other is a capacity charge, which the Company must pay the QF for having the capacity available.
 However, if no electrical power is made available to the Company for a period of time (generally three months),
the Company’s obligation to pay the capacity charge is suspeaded. The total cost of cogeneration payments is
recoverable in rates from customers.

       During 2004, 2003 and 2002, the Company made total payments to cogenerators of approximately
$203.5 million, $203.0 million and $227.3 million, respectively, of which approximately $155.3 million, $164.7
million and $192.1 million, respectively, represented capacity payments. All payments for purchased power,
including cogeneration, are included in the Statements of Income as Cost of Goods Sold. The future minimum
capacity payments under the contracts are approximately: 2005 - $99.5 million, 2006 - $97.9 million, 2007 -
$96.3 million, 2008 - $86.9 million and 2009 - $85.0 million.

Fuel Minimum Purchase Commitments

        The Company purchased necessary fuel supplies of qoal and natural gas for its generating units of
approximately $166.5 million, $157.3 million and $164.1 nullion for the years ended December 31, 2004,2003
and 2002, respectively. The Company has entered into purchase commitments of necessary fuel supplies of
approximately: 2005 - $170.8 million, 2006 - $160.0 million, 2007 - $159.0 million, 2008 - $164.8 million,
2009 - $86.9 million and 2010 and Beyond - $165.5 million.
IFERC FORM NO.1 (ED. 12-88)                        Page 123.27                    I
Name of Respondent                                              s
                                                   This Report i:           Date of Report Year/Period of Report
                                                   (1) g An Original         (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                 (2) - A qesubmission           I1               200NQ4




        The Company has historically acquired some of its natural gas for boiler fuel under wellhead contracts
that contain provisions allowing the owner to require prepayments for gas if certain minimum quantities are not
taken. At December 3 1,2004, approximately $21.O million has been recorded in the Provision for Payments of
Take or Pay Gas classified as Current Liabilities in the Balance Sheet. At December 31, 2003, approximately
$32.5 million has been recorded in the Provision for Payments of Take or Pay Gas classified as Deferred Credits
and Other Liabilities in the Balance Sheet. These amounts represent the Company’s estimate of the maximum
amount that it could be obligated to pay under certain take-or-pay contracts. The Company believes that it is
entitled to recover any such amounts from its customers through its regulatorily approved automatic fuel
adjustment clauses or other regulatory mechanisms.

Natural Gas Units

        In April 2004, the Company utilized a request for bid (“RFB”) acquire approximately 56 percent and
                                                                    to
26 percent of its projected annual natural gas requirements for 2005 and 2006, respectively. All of these
contracts are tied to various gas price market indices and most will expire in December 2006. Additional
natural gas supply for the summer of 2005 will be secured through a new RFB issued in the first quarter of
2005. The Company will meet additional natural gas requirements with monthly and daily purchases as
required.

Natural Gas Measurement Cases

         United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and the
Company. (United States District Court for the Western District of Oklahoma, Case No. CN-97-1010-L.)
United States of America ex rel., Jack J. Grynberg v. TransDk Inc. et al. (United States District Court for the
Eastern District of Louisiana, Case No. 97-2089; United States District Court for the Western District of
Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with Plaintiff‘s complaint,
which is a qui tam action under the False Claims Act. Plauntiff Jack J. Grynberg, as individual relator on behalf
of the United States Government, alleges: (i) each of the named defendants have improperly or intentionally
mismeasured gas (both volume and British thermal unit ccnteht) purchased from federal and Indian lands which
have resulted in the under-reporting and underpayment of gas royalties owed to the Federal Government;
(ii) certain provisions generally found in gas purchase contracts are improper; (iii) transactions by affiliated
companies are not arms-length; (iv) excess processing cost deduction; and (v) failure to account for production
separated out as a result of gas processing. Grynberg seeks the following damages: (a) additional royalties
which he claims should have been paid to the Federal Government, some percentage of which Grynberg, as
relator, may be entitled to recover; (b) treble damages; (c) civil penalties; (d) an order requiring defendants to
measure the way Grynberg contends is the better way to do so; and (e) interest, costs and attorneys’ fees.

        In qui tam actions, the United States Government can intervene and take over such actions from the
relator. The Department of Justice, on behalf of the United States Government, decided not to intervene in this
action.

       Plaintiff filed over 70 other cases naming over 300 loth$r defendants in various Federal Courts across the
country containing nearly identical allegations. The Multidistaict Litigation Panel entered its order in late 1999
transferring and consolidating for pretrial purposes approximately 76 other sinlilar actions filed in nine other
IFERC FORM NO. 1 (ED. 12-88)                        Paae 123.28                   I
 Name of Respondent                                This Report is:         Date of Report Year/Period of Report
                                                   (1) X An Ori$inal        (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                (2) - A Resybmission          I l             2004IQ4




Federal Courts. The consolidated cases are now before the United States District Court for the District of
Wyoming.

       In October 2002, the Court granted the Department of Justice’s motion to dismiss certain of Plaintiff‘s
claims and issued an order dismissing Plaintiff‘s valuation claims against all defendants. Various procedural
motions have been filed. Discovery is proceeding on limited jurisdictional issues as ordered by the Court. A
hearing on the defendants’ motions to dismiss for lack af subject matter jurisdiction, including public
disclosure, original source and voluntary disclosure requiremeats is set for March 17 - 18,2005.

       The Company intends to vigorously defend this action. Since the case is in the early stages of motions
and discovery, the Company is unable to provide an evaluation1of the likelihood of an unfavorable outcome and
an estimate of the amount or range of potential loss to the Company at this time.

        Will Price (Price I ) - On September 24, 1999, various subsidiaries of Energy C o p . were served with a
class action petition filed in United States District Court, Stata of Kansas by Quinque Operating Company and
other named plaintiffs, alleging mismeasurement of natural1 gas on non-federal lands. On April 10, 2003 the
Court entered an order denying class certification. On Map 12, 2003, Plaintiffs (now Will Price, Stixon
Petroleum, Inc., Thomas F. Boles and the Cooper Clark FounQation, on behalf of themselves and other royalty
interest owners) filed a motion seeking to file an amended petition and the court granted the motion on July 28,
2003. In this amended petition, the Company and Enogex Inc. were omitted from the case. Two subsidiaries of
Enogex remain as defendants. The Plaintiffs’ amended petition alleges that approximately 60 defendants,
including two Enogex subsidiaries, have improperly measured natural gas. The amended petition reduces the
claims to: (1) mismeasurement of volume only; (2) conspiracy, unjust enrichment and accounting; (3) a putative
Plaintiffs’ class of only royalty owners; and (4) gas measurqd in three specific states. Discovery on class
certification is proceeding. A hearing on class certification IISSUESis set for April 1,2005.

       Energy Corp. intends to vigorously defend this action. Since the case is in the early stages of motions
and discovery, Energy Corp. is unable to provide an evaluation of the likelihood of an unfavorable outcome and
an estimate of the amount or range of potential loss to Energ,yCiorp. at this time.

Environmental Laws and Regulations

       Approximately $5.3 million of the Company’s capital expenditures budgeted for 2005 are to comply
with environmental laws and regulations. The Company’s management believes that all of its operations are in
substantial compliance with present federal, state and local erlvironmental standards. It is estimated that the
Company’s total expenditures for capital, operating, maintenhnce and other costs to preserve and enhance
environmental quality will be approximately $54.3 million d u ~ n g 2005, as compared to approximately $52.2
million in 2004. The Company continues to evaluate its $nvironmental management systems to ensure
compliance with existing and proposed environmental legislatidn and regulations and to better position itself in
a competitive market.




IFERC FORM NO. 1 (ED.12-88)                        Page 123.29                    I
Name of Respondent                                  This Report is:          Date of Report Year/Period of Report
                                                    (1) X An Original         (Mo, Yr)
                                                                                   Da,
 Oklahoma Gas and Electric Company                  (2) - A Resqbmission           I1               2004/Q4




Air
        On January 24, 2005, national legislation was introduced in Congress that, if passed, could require a
significant reduction in emissions of sulfur dioxide (“S02’”),   nitrogen oxide (“NOX’) and mercury (Hg) from
the electric utility industry. The legislation, introduced in Senate Bill 131, is commonly referred to as the Clear
Skies Act of 2005.

       While the United States has withdrawn its support of the Kyoto Protocol on global warming, legislation
has been considered that would limit carbon dioxide (“C102”) emissions. In 2004, the McCain-Lieberman
Climate Change Bill addressed the reduction of C 0 2 as a means of addressing global warming; however, the
bill was defeated in the Senate. President Bush supports voluntary reductions by industry. The Company has
joined other utilities in voluntary C 0 2 sequestration pro-jects through reforestation of land in the southern
United States. In addition, the Company has committed to reduce its C 0 2 emission rate (lbs.
C02/megawatt-hour) by up to five percent over the next 10 years. However, if legislation is passed requiring
mandatory reductions, this could have a tremendous impact on the Company’s operations by requiring the
Company to significantly reduce the use of coal as a fuel source.

        Other potential air regulations also have emerged that could impact the Company. On December
15, 2003, the Environmental Protection Agency (“EPA”) proposed regulations to limit mercury emissions from
coal-fired boilers. This rule is expected to be finalized by early 2005. Earliest compliance by the Company
would be 2008. Depending upon the final regulations, this could result in significant capital and operating
expenditures. In addition, on January 30, 2004, the EPA praposed a Clean Air Interstate Rule. This rule is
intended to control SO2 and NOX from utility boilers i n order to minimize the interstate transport of air            -
pollution. The State of Oklahoma, however, is not listed as one of the states affected by the proposed rule.
This, however, could change as the EPA has indicated its intentions to review Oklahoma’s impact on other              -

states. If Oklahoma is included in the final rule reductions;, this could lead to significant capital and operating
expenditures by the Company.

       In 1997, the EPA finalized revisions to the ambient ozone and fine particulate standards. After a court
challenge, which delayed implementation, the EPA has now begun to finalize the implementation process.
Based on the most recent monitoring data, the EPA hais designated Oklahoma “in attainment” with both
standards. However, both Tulsa and Oklahoma City had previously entered into an “Early Action Compact”
with the EPA whereby voluntary measures will be enacted lo raduce ozone. In order to ensure that ozone levels
remain below the standards, both cities intend to comply wiith the compact. Minimal impact on the Company’s
operations is expected.

        In 1999, the EPA first issued regulations concerning regional haze. These regulations are intended to
protect visibility in national parks and wilderness areas throughout the United States. In Oklahoma, the Wichita
Mountains would be the only area covered under the regulation. However, Oklahoma’s impact on parks in
other states must also be evaluated. Sulfates and nitrate aerosols (both emitted from coal-fired boilers) can lead
to the degradation of visibility. The State of Oklahoma has joioed with eight other central states and has begun
the process of determining what, if any, impact emission sources in Oklahoma have on national parks and
wilderness areas. This study will be complete and any compliance strategies adopted by January 2008. If an
impact is determined, then significant capital expenditures could be required for both the Sooner and Muskogee
generating stations.
LFERC FORM NO. 1 (ED. 12-88)                         Page 123.30                    I
 Name of Respondent                                 This Report is:          Date of Report Year/Period of Report
                                                    (1) X An Original         (Ma, Da, Yr)
  Oklahoma Gas and Electric Company                 (2) - A Respbmission           11               2004lQ4




        As required by Title IV of the Clean Air Act Amendments of 1990 (“CAAA”), the Company completed
installation and certification of all required continuous enlissions monitors at its generating stations in 1995.
Since then, the Company has submitted emissions data quwterly to the EPA as required by the CAAA.
Beginning in 2000, the Company became subject to more (strimgentSO2 emission requirements (Phase II of the
CAAA). These lower limits had no significant financial impact due to the Company’s earlier decision to burn
low sulfur coal. In 2004, the Company’s SO2 emissions were well below the allowable limits.

        The 1990 Clean Air Act includes an emission reduction program to reduce SO2 emissions. Reductions
were obtained through a program of emission (release) allowances issued by the EPA to power plants covered
by the acid rain program. Each allowance is worth one toin of SO2 released from the smokestack. Plants may
only release as much SO2 as they have allowances. Allowances may be banked and traded or sold nationwide.
The EPA allocated sulfer dioxide allowances to the Company $tarting in 2000 and the Company started banking
allowances in 2001. At December 31, 2004, the Company h!as banked approximately 31,784 allowances. In
light of emerging regulations with uncertain outcomes, the: Company’s current strategy for management of the
allowances is to bank them for future use.

        With respect to the NOX regulations of Title IV of thle CAAA, the Company committed to meeting a
0.45 lbs/million British thermal unit (“MMBtu”) NOX emission level in 1997 on all coal-fired boilers. As a
result, the Company was eligible to exercise its option to dxtend the effective date of the lower emission
requirements from the year 2000 until 2008. The Company’s average NOX emissions from its coal-fired boilers
for 2004 were 0.337 lbs/MMBtu. The regulations require ithat the Company achieve a NOX emission level of
0.40 lbs/MMBtu for these boilers beginning in 2008. Furthier reductions in NOX emissions could be required if,
among other things, legislation is enacted, a study currently being conducted by the state of Oklahoma
determines that such NOX emissions are contributing to regiodal haze and that the Company’s facilities impact
the air quality of the Tulsa or Oklahoma City metropolitan areas, or if Oklahoma becomes non-attainment with
the fine particulate standard. Any of these scenarios would require significant capital and operating
expenditures.

        The Oklahoma Department of Environmental Quality’$ (“ODEQ”) Clean Air Act Amendment Title V
permitting program was approved by the EPA in March 1996. By March of 1997, the Company had submitted
all required permit applications. As of December 31, 2004, the Company had received Title V permits for all of
its generating stations. Since these permits require renewal eve0 five years the Company has begun the renewal
process for some of its generating stations. Air permit fees for generating stations were approximately $0.6
million in 2004. The fees for 2005 are estimated to be approximately the same as in 2004.

       The ODEQ is expected to adopt a new regulation dealihg with the emission of toxic air contaminants.
While it is unknown at this time what impact, if any, this rule will have on the Company, the rule’s impact could
be significant if the ODEQ identifies high concentrations of any toxic contaminants near Company facilities.

        The EPA continues to investigate and enforce against ,electric utilities around the country for alleged
violation of its New Source Review regulations. While thp Company believes it has complied with all
regulations, it appears that the EPA will begin investigating eledtric utilities in Oklahoma and surrounding states
in 2005.
IFERC FORM NO. 1 (ED. 12-88)                        Page 123.3‘1                                                    I
Name of Respondent                                  This Report i6:                                      f
                                                                             Date of Report Year/Period o Report
                                                    (1) X An Original         (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                  (2) - A Flesqbmission          / I              2004lQ4




Waste

        The Company has sought and will continue to seek, new pollution prevention opportunities and to
evaluate the effectiveness of its waste reduction, reuse and rttcycling efforts. In 2004, the Company obtained
refunds of approximately $0.8 million from its recycling effarts. This figure does not include the adhtional
savings gained through the reduction and/or avoidance of dispwal costs and the reduction in material purchases
due to the reuse of existing materials. Similar savings are anticipated in future years.

Water

       The Company submitted one application during 2004 to renew an Oklahoma Pollutant Discharge
Elimination System (“OPDES”) permit. The Company has raceived three renewed wastewater permits during
2004. All permits received to date have been reasonable in1 their requirements, allow operational flexibility and
provide reductions in operating costs.

         The Company requested, based on the performance of a site-specific study, that the state agency
responsible for the development of water quality standards adjust the in-stream copper criterion at one of our
facilities. The state and the EPA have approved the new in-stream criteria for copper thereby avoiding costly
treatment and/or facility reconfiguration requirements. Balsed on this approval, an OPDES permit was issued
during 2004 for the facility that contains no copper limitations.

        Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of
any cooling water intake structure reflect the “best available teahnology” for minimizing environmental impacts.
 New EPA 316(b) rules for existing facilities became effective July 23, 2004. The Company has acquired the
services of a consultant to assist in the development of “IProposal for Information Collection” documents for
four applicable facilities. These documents will be submitted to the state regulatory agency for review and
approval during the first or second quarters of 2005. Depending on the analysis of these final 316(b) rules,
capital and/or operating costs may increase at some of the Corqpany’s generating facilities.

         The Company has and will continue to evaluate the impact of its operations on the environment. As a
result, contamination on Company property may be discovered from time to time.

Other

        In the normal course of business, the Company is confronted with issues or events that may result in a
contingent liability. These generally relate to lawsuits, clalimg made by third parties, environmental actions or
the action of various regulatory agencies. Management consullts with counsel and other appropriate experts to
assess the claim. If in management’s opinion, the Corripany has incurred a probable loss as set forth by
accounting principles generally accepted in the United States, an estimate is made of the loss and the appropriate
accounting entries are reflected in the Company’s Financial Statements. Management, after consultation with
legal counsel, does not anticipate that liabilities arising out of currently pending or threatened lawsuits, claims
and contingencies will have a material adverse effect on thle Company’s financial position, results of operations
or cash flows. This assessment of currently pending or threatened lawsuits is subject to change.
IFERC FORM NO. 1 (ED. 12-88)                        Page 123.:32                   I
 Name of Respondent
  Oklahoma Gas and Electric Company



13.     Rate Matters and Regulation

Regulation and Rates

        The Company’s retail electric tariffs are regulated by the OCC in Oklahoma and by the APSC in
Arkansas. 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 Departnlent of Energy has jurisdiction over some of the
Company’s facilities and operations. For the year ended Deciember 31, 2004, approximately 87 percent of the
Company’s electric revenue was subject to the jurisdiction @f the OCC, nine percent to the APSC and four
percent to the FERC.

       The OCC issued an order in 1996 authorizing the Company to reorganize into a subsidiary of Energy
Corp. The order required that, among other things, (i) Energp Corp. permit the OCC access to the books and
records of Energy Corp. and its affiliates relating to transactions with the Company; (ii) Energy Corp. employ
accounting and other procedures and controls to protect against subsidization of non-utility activities by the
Company’s customers; and (iii) Energy Corp. refrain from pledging the Company assets or income for affiliate
transactions.

Recent Regulatory Matters

2002 Settlement Agreement

        On November 22, 2002, the OCC signed a rate oader containing the provisions of a Settlement
Agreement of the Company’s rate case. The Settlement Agreeaent provides for, among other items: (i) a $25.0
million annual reduction in the electric rates of the Company’s Oklahoma customers which went into effect
January 6, 2003; (ii) recovery by the Company, through r,ate base, of the capital expenditures associated with
the January 2002 ice storm; (iii) the Company to acquire electric generation of not less than 400 M W s (“New
Generation”) to be integrated into the Company’s generation *stem; and (iv) recovery by the Company, over
three years, of the $5.4 million in deferred operating costs, assbciated with the January 2002 ice storm, through
the Company’s rider for off-system sales. Previously, ithe Company had a 50/50 sharing mechanism in
Oklahoma for any off-system sales. The Settlement Agreemen4 provided that the first $1.8 million in annual net
profits from the Company’s off-system sales will go to the Conhpany, the next $3.6 million in annual net profits
from off-system sales will go to the Company’s Oklahoma customers, and any net profits of off-system sales in
excess of these amounts will be credited in each sales year with 80 percent to the Company’s Oklahoma
customers and the remaining 20 percent to the Company. If aqy of the $5.4 million is not recovered at the end
of the three years, the OCC will authorize the recovery ofiany remaining costs. During the year ended
December 31, 2004, the Company recovered approximately $11.8 million in annual net profits from off-system
sales, gave approximately $3.6 million in annual net profits f r o b off-system sales to the Company’s Oklahoma
customers and the net profits from off-system sales that exceedpd the $5.4 million were shared with 80 percent
to the Company’s Oklahoma customers and the remaining 20 pqrcent to the Company.




(FERC FORM NO. 1 (ED. 12-88)                       Page 123.33                    1
Name of Respondent                                 This Repob is:               Date of Report Yeadperiod of Report
                                                   (1) X A,n qriginal            (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                 (2)-A Rqsubmission                I I              2004IQ4
                                                                  (Continued)
                                     NOTES TO FINANCIAL STATE~J~ENTS                                                  J



OCC Order Confirming Savings

        The Settlement Agreement required that, if the Ccpmpany did not acquire the New Generation by
December 31, 2003, the Company must credit $25.0 milliob annually (at a rate of 1/12 of $25.0 million per
month for each month that the New Generation is not in place) to its Oklahoma customers beginning January 1,
2004 and continuing through December 31, 2006. As disaussed in more detail below, in August 2003 the
Company signed an agreement to purchase a 77 percent inteqest in the McClain Plant, but due to a delay at the
FERC, the acquisition was not completed by December 31, $003. In the interim, the Company entered into a
power purchase agreement with the McClain Plant that delivered the savings guaranteed to the Company’s
customers. The Company requested that the OCC confirm that the steps it had taken, including the power
purchase agreement, were satisfying the customer savings oljligation under the Settlement Agreement and that
the Company would not be required to begin cre&ting its cQstomers. On April 28, 2004, the OCC issued an
order confirming that the Company was delivering savings to its customers as required under the Settlement
Agreement. The order removed any uncertainty over whethe4 the OCC believed the Company had to reduce its
rates, effective January 1, 2004, while it awaited action by tha FERC on its application to purchase the McClain
Plant. A party to the OCC proceeding has appealed the OQC’s order to the Oklahoma Supreme Court. The
Company currently believes that the appeal is without merit.

Recent Acquisition of Power Plant

        On August 18, 2003, the Company signed an asset purjchase agreement to acquire NRG McClain LLC’s
77 percent interest in the McClain Plant. The acquisition of $is 77 percent interest was intended to satisfy the
requirement in the Settlement Agreement to acquire New Cfeneration. The McClain Plant includes natural
gas-fired combined cycle combustion turbine units and is located near Newcastle, Oklahoma in McClain
County, Oklahoma. The McClain Plant began operating in 2001. The owner of the remaining 23 percent
interest in the McClain Plant is the Oklahoma Municipal Powelr Authority (“OMPA”).

        The Company completed the acquisition of the McClqn Plant on July 9, 2004. The purchase price for
the interest in the McClain Plant was approximately $160.01million. The closing was subject to customary
conditions including receipt of certain regulatory approvals. Because NRG McClain LLC had filed for
bankruptcy protection, the acquisition was subject to apprciw~lby the bankruptcy court. As part of the
bankruptcy approval process, NRG McClain LLC’s interest iq the plant was subject to an auction process and
on October 28,2003, the bankruptcy court approved the sale of NRG McClain LLC’s interest in the plant to the
Company.

        The final approval the Company had been waiting for was the approval from the FERC. On July 2,
2004, the FERC authorized the Company to acquire the McClijin Plant. The FERC’s approval was based on an
offer of settlement the Company filed in a proceeding on Maph 8, 2004. Under the offer of settlement, the
Company proposed, among other things, to install certain new transmission facilities and to hire an independent
market monitor to oversee the Company’s activity for a lirnitejd period. Two other parties, InterGen Services,
Inc. and AES Shady Point, opposed the Company’s offer of setgement and filed competing settlement offers. In
the July 2, 2004 order, the FERC: (i) approved the Companyrs offer of settlement subject to conditions; (11)
rejected the competing offers of settlement; and (iii) approvt:d the Company’s acquisition of the McClain Plant.
As part of the July 2,2004 order, the Company agreed to undertpke the following mitigation measures: (i) install
(FERC FORM NO. 1 (ED. 12-88)                        Page 123.34                                                       1
Name of Respondent                                  This Report i$:          Date of Report Yeadperiod of Report
                                                                              (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                                                I I              2004lQ4




a transformer at one of its facilities at a cost of approximately $9.3 million which was completed in the fourth
quarter of 2004; (ii) provide a 600 MW bridge into its contrd area from the Redbud Energy LP (“Redbud’)
plant; and (iii) hire an independent market monitor to oversee the Company’s activity in its control area. The
market monitoring plan is designed to detect any anticompetitive conduct by the Company from operation of its
generation resources or its transmission system. The rn,ark@t       monitoring function is performed daily and
periodic reviews are also performed. To date, the independent market monitor has filed two reports, one on
October 13, 2004 covering the period from July 10,2004 to September 30,2004, and one on January 14,2005
covering the period from October 1, 2004 to December 311 2004. Based on an analysis of transmission
congestion data on the Company’s system, along with data on purchases and sales, generation dispatch data and
power flows on the Company’s tie lines, the market monitor concluded that the Company did not act in an
anticompetitive manner through either dispatch of its genedation or operation of its transmission system.
Additionally, the Company’s operations under the ongoing @tigation measures that require the Company to
make available transmission capability available to the Redbud power plant for access to the Company system
were analyzed. Based on this analysis, the market monitor concluded that the Company has complied with this
requirement. Further, in the review of the disposition of requests for transmission service, the independent
market monitor detected no problems with access to the: Company’s transmission system. The Company
expects to complete the installation and implementation of thege measures by June 2005. One party has filed a
request for rehearing of the FERC’s July 2, 2004 order. The outcome of that request for rehearing cannot be
determined at this time.

        The Company is operating the plant in accordance with a joint ownership and operating agreement with
the OMPA. Under this agreement, the Company operates; the facility, and the Company and the OMPA are
entitled to the net available output of the plant based on thleir respective ownership percentages. All fixed and
variable costs, except fuel and gas transportation costs, are shared in proportion to the respective ownership
interests. Fuel and gas transportation costs are paid in accokdance with each individual owner’s respective
transportation contract and consumption. The Company expeqts to utilize its portion of the output, 400 M W s ,
to serve its native load. As a result, the Company expects to fille with the OCC a request to increase its rates to
its Oklahoma customers to recover, among other things, its iqvestment in, and the operating expenses of, the
McClain Plant no later than July 8, 2005. The Company expeqts to file a rate case during the second quarter of
2005 using 2004 as a test year with new approved rates expected to be in effect by January 2006. As provided
in the Settlement Agreement, until the Company seeks and obt#ns approval of a request to increase base rates to
recover, among other things, the investment in the plant, the Cqmpany will have the right to accrue a regulatory
asset, for a period not to exceed 12 months subsequent to the lacquisition and operation of the McClain Plant,
consisting of the non-fuel operation and maintenance expens@, depreciation, cost of debt associated with the
investment and ad valorem taxes. If the OCC were to appro& the Company’s request, all prudently incurred
costs accrued through the regulatory asset within the 12-rnonrh period would be included in the Company’s
prospective cost of service and would be recovered over a perio/d to be determined by the OCC.

        The Company temporarily funded the McClain F’lant acquisition with short-term borrowings from
Energy Corp. On August 4, 2004, the Company issued        .O million of long-term debt to replace these
short-term borrowings. Also, on August 9, 2004, Energy    made a capital contribution to the Company of
approximately $153.0 million.


IFERC FORM NO. 1 (ED.12-88)                         Paae 123.35                    I
Name of Respondent                                 This Repobt is:                                     f
                                                                           Date of Report Year/Period o Report
                                                   (1) 11 An Original        (Mo, Da,Yr)
 Oklahoma Gas and Electric Company                 (2) - A Rqsubmission          I1              2004lQ4



        The Company expects the acquisition of the McClain Plant, including the effects of an interim power
purchase agreement the Company had with NRG McClain LLC while the Company was awaiting regulatory
approval to complete the acquisition, will provide savings, aver a three-year period, in excess of $75.0 million
to its Oklahoma customers. These savings will be derived fmm: (i) the avoidance of purchase power contracts
otherwise needed; (ii) an above market cogeneration contdact with PowerSmith Cogeneration Project, L.P.
(“PowerSmith”) when it terminated at the end of August 2004; and (iii) fuel savings associated with operating
efficiencies of the new plant. These savings, while providing real savings to Oklahoma customers, are not
expected to affect the Company’s profitability because its rates are not expected to be reduced to accomplish
these savings. In the event the Company is unable to demonstrate at least $75.0 million in savings to its
customers during this 36-month period, the Company will be required to credit its Oklahoma customers any
unrealized savings below $75.0 million as determined at the end of the 36-month period ending December 31,
2006. At this time, the Company believes that it will be able to demonstrate at least $75.0 million in savings
during this period.

Contract with PowerSmith

        In September 2003, PowerSmith filed an application with the OCC seeking to compel the Company to
continue purchasing power from Powersmith’s qualified cogeneration facility under the Public Utility
Regulatory Policy Act of 1978 at a price that would include1 an avoided capacity charge equal to the avoided
cost of the McClain Plant. On June 7, 2004, the Company and PowerSmith signed a 15-year power sales
agreement under which the Company would contract to purchase electric power from PowerSmith. On August
27,2004, the new 15-year power sales agreement was approv$d by the OCC and became effective September 1,
2004. The Company’s ability to meet its guarantee of customer savings of at least $75 million over three years
is not expected to be materially affected by this new agreement to purchase electric power from PowerSmith.

Security Enhancements

         On April 8, 2002, the Company filed a joint applicatiqm with the OCC requesting approval for security
investments and a rider to recover these costs from the ratepayers. On August 14, 2002, the Company filed
testimony with the OCC outlining proposed expenditures and related actions for security enhancement and a
proposed recovery rider. Attempting to make security investments at the proper level, the Company has
developed a set of guidelines intended to minimize long-tem or widespread outages, minimize the impact on
critical national defense and related customers, maximize the ability to respond to and recover from an attack,
minimize the financial impact on the Company that might be caused by an attack and accomplish these efforts
with minimal impact on ratepayers. The OCC Staff retained security expert to review the report filed by the
Company. On July 13, 2004, the security expert filed testiinoqy that recommended: (i) $19.0 million in capital
expenditures and $2.5 million annually in operating and mqintenance expenses are justified to enhance the
security of the Company’s infrastructure; and (ii) a security rider should be authorized to recover costs as these
projects are completed. On August 4, 2004, the Company filed responsive testimony that quantified the
minimal customer impact and revised its request for security inwstments so that it was consistent with the OCC
Staff‘s recommendations. On August 13, 2004, the only intervening party, the Oklahoma Industrial Energy
Consumers (“OIEC”), filed a statement of position which sukported the OCC Staff‘s recommendations. On
October 28, 2004, all parties signed a joint stipulation that contains the OCC Staffs recommendations and
authorizes up to a $5 million annual recovery from the Company’s customers for security enhancement. The
IFERC FORM NO. 1 (ED.    12-88)                     Paae 123.36                    1
    Name of Respondent                                 This Repofl is:              Date of Report Year/Period of Report
                                                       (1) 3 An Original             (Mo, Da, Yr)
    Oklahoma Gas and Electric Company                  (2) - P I Repubmission            / I              2004lQ4

~
                                        NOTES TO FINANCIAL STATEdENTS (Continued)


hearing in this case was held on November 9, 2004, at which time the administrative law judge approved the
stipulation agreement between all parties. On December 21, 2004 the OCC issued an order approving the
security rider.

       On October 17, 2003, the OCC filed a notice of inquiry to consider the issues related to the role of the
OCC and Oklahoma regulated companies in addressing the slecurity of the utility system infrastructure and key
assets. On March 4, 2004, the OCC deliberated the notice of inquiry and directed the OCC Staff to file a
rulemaking proceeding for each utility industry regarding security of the utility system infrastructure and key
assets. On August 27, 2004, the OCC Staff filed a Notice of Proposed Rulemalung. The first technical
conference was held on September 23, 2004 and written comments were filed by all the parties on October 1,
2004. A second technical conference was held on October 21, 2004. The hearing in this case was held on
December 3,2004. On December 10,2004, the OCC subrnitted the amended rules to the Governor’s Office and
Oklahoma Legislature.

Cogeneration Credit Rider

         On September 17, 2004, the Company filed an application and testimony with the OCC requesting a
cogeneration credit rider. The requested rider would reduce charges to customers because of decreasing
cogeneration payments made by the Company beginning January 2005. The cogeneration credit rider is
necessary because amounts currently recovered from customers in base rates include historically higher
cogeneration payments. The Company’s current cogeneratiqn credit rider expired December 3 1, 2004. On
October 29, 2004, the OCC Staff and other parties filed reSpOhSiVe testimony. Hearings in this case were held
on November 15, 2004, at which time the administrative law judge recommended approval of the proposed
cogeneration credit rider. On December 21, 2004 the OCC issued an order approving the new cogeneration
credit rider which will lower electric bills by approximately $80 million annually.

Pending Regulatory Matters

       Currently, the Company has one significant matter pending at the OCC which is a review of the process
completed by the Company in its selection of gas transpoGation and storage services to meet its system
operating needs. This matter, as well as several other matters pmding before the FERC, are discussed below.

Gas Transpodation and Storage Agreement

        As part of the Settlement Agreement, the Company also agreed to consider competitive bidding as a
basis to select its provider for gas transportation service to its natural gas-fired generation facilities pursuant to
the terms set forth in the Settlement Agreement. The prescrfbed bidding process detailed in the Settlement
Agreement provided that each generation facility seek bids segarately for the services required. The Company
believes that in order for it to achieve maximum coal generatipn, which delivers the lowest cost energy to its
customers, and ensure reliable electric service, it must have intqgrated, fr no-notice load following service for
                                                                            im
both gas transportation and gas storage. This type of service is required to satisfy the daily swings in customer
demand placed on the Company’s system and still permit natural gas units to not impede coal energy
production. The Company also believes that gas storage is iin integral part of providing gas supply to the
Company’s generation facilities. Accordingly, the Company evaluated its competitive bid options in light of
[FERC FORM NO. 1 (ED. 12-88)                           Page 123.37                       I
Name of Respondent                                  This Report is:          Date of Report Yeadperiod of Report
                                                    (1) 3 An Original         (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                     -
                                                    (2) A Regubmission             / I              2004lQ4




these circumstances. The Company’s evaluation clearly demonstrates that the Enogex integrated gas system
provides superior integrated, firm no-notice load following service to the Company that is not available from
other companies serving the Company marketplace.

       On April 29,2003, as required by the Settlement Agreement, the Company filed an application with the
OCC in which the Company advised the OCC that, after careful consideration, competitive bidding for gas
transportation was rejected in favor of a new intrastate integrated, firm no-notice load following gas
transportation and storage services agreement with Enogex. This seven-year agreement provides for gas
transportation and storage services for each of the Company’s natural gas-fired generation facilities. The
Company will pay Enogex annual demand fees of approximately $46.8 million for the right to transport
specified maximum daily quantities (“MDQ”) and maximum hourly quantities (“MHQ,) of gas at various
minimum gas delivery pressures depending on the operational needs of the individual generating facility. In
addition, the Company supplies system fuel in-kind for its pro-rata share of actual fuel and loss and unaccounted
for gas on the transportation system. To the extent the Company transports gas in quantities in excess of the
prescribed MDQs or MHQs, it pays an overrun service charge. During the years ended December 31,2004,
2003 and 2002, the Company paid Enogex approximate:ly $49.6 million, $44.7 million and $36.9 million,
respectively, for gas transportation and storage services.

        Based upon requests for information from intervenors, the Company requested from Enogex and Enogex
retained a “cost of service” consultant to assist in the preparation of testimony related to this case. On March
31, 2004, the Company filed testimony and exhibits with the OCC, which completed the initial documentation
required to be filed in this case. On July 12, 2004, severall parties filed responsive testimony reflecting various
positions on the issues related to this case. In particular, the testimony of the OCC Staff recommended that the
Company be entitled to recover the $46.8 million annual demand fee requested, which results in no refund, and
also recommended that the Company provide at its next general rate review the results of an open competitive
bidding process or a comprehensive market study. If thle Company does not provide such open bidding or
market study, the OCC Staff recommendation would cap recovery at approximately $40 million at the
Company’s next general rate review. The recommendatioins in the testimony of the Attorney General’s office
and the OIEC would cap recovery at approximately $35 million and $30 million, respectively, with the
difference between what the Company has been collecting through its automatic fuel adjustment clause and
these recommended amounts being refunded to customers.

        The Company filed rebuttal testimony on August 16, 2004 in this case. Hearings in this case before an
administrative law judge occurred from September 16-22, 2004. On October 22, 2004, the administrative law
judge overseeing the proceeding recommended approximately $41.9 million annual demand fee recovery with
the Company refunding to its customers any demand fees collected in excess of this amount. If this
recommendation is ultimately accepted, the Company believes its refund obligation would be approximately
$6.9 million at December 31, 2004, which the Company does not believe is material in light of previously
established reserves. The Company believes the amount currently paid to Enogex for integrated, firm no-notice
load following transportation and storage services is fair, just and reasonable. The Company and other parties to
the proceeding appealed the administrative law judge’s recomendation on November 1, 2004 and a hearing in
this case was held before the OCC on December 7, 2004. The OCC took the case under advisement and an
OCC order in the case is expected in the first quarter of 2005. There can be no guarantee that the OCC will
 approve the $41.9 million annual demand fee recovery recoinmended by the administrative law judge.
IFERC FORM NO. 1 (ED. 12-88)                        Page 123.38
                                                                                                                   1
Name of Respondent                                  This Report is:          Date of Report Year/Period of Report
                                                    (1) An Original           (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                 (2) - A Resubmission          / I              2004IQ4




Southwest Power Pool

         The Company is a member of the Southwest Power Pool (“SPP’), the regional reliability organization
for all or parts of Oklahoma, Arkansas, Kansas, Louisiana, New Mexico, Mississippi, Missouri and Texas. The
Company participated with the SPP in the development of regional transmission tariffs and executed a
Membership Agreement with the SPP to facilitate interstate transmission operations within this region in 1998.
In October 2003, the SPP filed an application with the FERC seeking authority to form a regional transmission
organization (“RTO”). On February 10, 2004, the FERC conditionally approved the SPP’s application. The
SPP must meet certain conditions before it may commence operations as an RTO. On April 27, 2004, the SPP
Board of Directors took actions to meet the conditions to satisfy the FERC requirement for formal approval of
the RTO. The SPP compliance filing at the FERC was made on May 3, 2004. In response to a subsequent
FERC order on July 2, 2004, the SPP made a compliance filing on August 6, 2004 stating that all requirements
had been met to achieve RTO status. In a FERC order dated October 1, 2004, the FERC accepted the SPP’s
compliance filing and the SPP was granted RTO status, subject to the SPP submitting a further compliance
filing, within 30 days. On November 1,2004, the SPP made a compliance filing as required under the October
1 FERC order. Also, on November 1, the SPP filed a request for rehearing of the FERC’s October 1 order. On
December 1,2004, the FERC granted the request for rehearing. On January 25,2005, the FERC issued an order
on compliance filing stating that the November 1, 2004 SE’P aompliance filing satisfied the October 1 FERC
order. The recent approval of the SPP RTO application is not expected to significantly impact the Company’s
financial results.

        Currently, the regional state committee, which is comprised of commissioners regulating the state
regulatory jurisdictional SPP members, is in the process of formulating a methodology for funding transmission
expansion in the SPP’s control area by allocating costs of transmission expansion to the SPP members who
benefit. The SPP plans to make a filing at the FERC in February 2005 related to this matter. Also, the SPP is in
the process of developing a process, required by the FERC, ta create an imbalance energy market which will
require cash settlements for over or under generation. Each SPP member will be responsible for monitoring its
generation in its control area on an hourly basis and periodically submitting this information to the SPP, who
will then provide settlement statements to each of the SFP members. The imbalance energy market
requirements are planned to be effective October 1,2005.

FERC Standards of Conduct

         On November 25, 2003, the FERC issued new rules regulating the relationships between electric and
natural gas transmission providers, 9s defined in the rules, and those entities’ merchant personnel and energy
affiliates. The new rules will replacer the existing rules governing these relationships. The new rules expand the
definition of “affiliate” and further limit communications between transmission providers and those entities’
merchant personnel and energy affiliates.

        In February 2004, the Company and Enogex submitted plans and schedules to the FERC which detail the
necessary actions to be in compliance with these new rules (andexpected that their initial costs to comply with
the final rules would not exceed $1.6 million in 2004. On April 16, August 2 and December 21, 2004, the
FERC issued orders on rehearing in which the FERC largely rejected requests to revise its November 25, 2003
final rule. However, the FERC did extend the compliance date until September 22, 2004 and did clarify certain
Name of Respondent                                 This Report is:         Date of Report Year/Period of Report
                                                   (1) X An Original        (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                    -
                                                   (2) A Resubmission            I /              2004IQ4




aspects of the rule.

       The Company and Enogex believe that they have taken the necessary actions to comply with the new
rules. The initial cost of compliance incurred in 2004 was less than $0.5 million. Additionally, the Company
and Enogex believe that the recurring cost of compliance in future years will be immaterial to Energy Corp.

Market-Based Rate Authority

        On December 22, 2003, the Company and OGE: Energy Resources, Inc. (“OERI”) filed a triennial
market power update based on the supply margin assessiment test. On April 14, 2004, the FERC issued: (1)
interim requirements for the FERC jurisdictional electric: utilities who have been granted authority to make
wholesale sales at market-based rates; and (2) an order initiating a new rulemaking on future market-based rates
authorizations. The interim method for analyzing generation market power requires two assessments - whether
the utility is a pivotal supplier based on a control area’s annual peak demand and whether the utility exceeds
certain market share thresholds on a seasonal basis. If an applicant fails to pass either assessment, the FERC
will presume that the utility can exercise generation market power and will initiate an investigation into the
scope of the applicant’s market power. The FERC will idlow a utility to rebut that presumption through the
submission of additional information. If an applicant is found to have generation market power, the applicant
must propose a market power mitigation plan. The new interim assessment methods are applicable to all
pending initial market-based rate applications and triennial reviews pending the rulemaking described below.
On May 13, 2004, the FERC directed all utilities with pending three year market-based reviews to revise the
generation market power portion of their three year review to address the two interim tests described above. In
the rulemaking proceeding, the FERC is seeking comments on the adequacy of the FERC’s current analysis of
market-based rate filings, including the adequacy of the new “interim” assessment of generation market power.
The Company and OEM submitted a compliance filing to the FERC on February 7, 2005 which shows the
impact of the new requirements on the Company and OERJ. In the compliance filing, the Company and OEM
passed the pivotal supplier screen but failed to pass the market share screen. The Company and OERI provided
an explanation as to why its failure of the market share screen should not be viewed as an indication that they
can exercise generation market power. The Company and OERI do not know when the FERC will act on the
filing or what action the FERC will take.

Department of Energy Blackout Report

        On April 5, 2004, the U.S. Department of Energy issued its final report regarding the August 14, 2003
electric blackout in the eastern United States, which did not have an adverse affect on the Company’s electric
system. The report recommends a number of specific changes to current statutes, rules or practices in order to
improve the reliability of the infrastructure used to transmit electric power. The recommendations include the
establishment of mandatory reliability standards and financial penalties for noncompliance. On April 14, 2004,
the FERC issued a policy statement requiring electric utihties, including the Company, to submit a report on
vegetation management practices and indicating the FFiRC’s intent to make North American Electric Reliability
Council reliability standards mandatory. On June 17, 2004, the Company filed its report on vegetation
management practices with the FERC. During 2004, the Company spent less than $0.2 million related to the
implementation of blackout report recommendations. Implementation of the blackout report recommendations
and the FERC policy statement could increase future transmission costs, but the extent of the increased costs is
IFERC FORM NO. 1 (ED. 12-88)                       Page 123.40                                                    I
Name of Respondent                                  This Report is:          Date of Report Year/Period of Report
                                                    (1) X An Original         (Mo, Da, Yr)
 Oklahoma Gas and Electric Company                  (2) - A Resubmission           / I              2004lQ4




not known at this time.

Redbud Tariff Filing

        On March 5 , 2004, Redbud filed a rate schedule with the FERC in Docket No. ERO4-622-000
under which Redbud proposed to charge the Company a rate for transmission service Redbud alleges it provides
to the Company over certain facilities that Redbud constructed to connect its generation facility to the Company
transmission grid. Redbud claims that the facilities cost approximately $19.3 million, and seeks to recover this
amount from the Company over a 60-month period. Also on March 5, 2004, Redbud filed an application with
the FERC in Docket No. EG04-38-000 aslung the FERC to rule that Redbud can charge the Company this fee
for transmission service and remain an exempt wholesale generator under Section 32 of the Public Utility
Holding Company Act of 1935. The Company opposed Reldbud’s filings in the two dockets on the grounds that
Redbud is not entitled to impose such a transmission rate, and that the imposition of such a rate is inconsistent
with Redbud’s status as an exempt wholesale generator. On May 4, 2004, the FERC issued an order rejecting
Redbud’s proposed rate schedule. Redbud has since asked the FERC to rehear and reverse its May 4 order
rejecting Redbud’s filing. On November 1, 2004, the FERC issued an order denying Redbud’s request for
rehearing. Redbud had 60 days to file a petition for review with the FERC. Redbud did not file a petition for
review with the FERC and this case is now considered closed.


National Energy Legislation

        In December 2004, the 108th Congress concluded without enactment of a comprehensive energy bill that
had been debated in the Senate and the House of Representatives during 2003 and 2004. While the House had
given strong support to the bill, the Senate failed to overcome a filibuster which blocked final passage. The bill,
as it came out of the House-Senate conference, would have been largely beneficial to the Company. It contained
provisions that would have minimized the risk of future uneconomic purchased power contracts being forced on
the Company under PURPA, and provided tax incentives for investment in the electric transmission and natural
gas pipeline systems. The bill also provided favorable provisions for mandatory reliability regulation by the
North American Electric Reliability Council with oversight by the FERC, and contained improved FERC siting
authority for construction of electric transmission in disputed areas. Also deemed positive by the Company was
the fact that the bill did not contain any provisions for federal mandates of renewable energy which would have
had the effect of raising the Company’s electric rates. Another significant provision of the energy bill was the
repeal of the Public Utility Holding Company Act of 1935 which was of minimal impact to the Company.

         While Congress did not enact the comprehensive energy bill in 2004, Congress was able to pass some
elements of that comprehensive bill as parts of other legislation. In particular, in the Foreign Sales Corporation
- Extra-Territorial Income bill, Congress enacted some provisions relating to the reauthorization of the expired
tax credits for renewable energy projects, including wind turbines, and permitted utilities to deduct a percentage
of their generation revenue as “manufacturers” of energy.

      Looking to the 109th Congress in 2005, the Republican congressional leadership and the Bush
Administration have indicated that enactment of a comprehensive energy biIl remains a priority. While the

IFERC FORM NO. 1 (ED.12-88)                         Paae 123.41                                                     I
Name of Respondent                                   This Report i:
                                                                  s            Date of Report Year/Period of Report
                                                     (1)   X An Original        (Mo, Yr)
                                                                                     Da,
 Oklahoma Gas and Electric Company                   (2)   - A Resubmission          I l              2004m4



precise contours of that legislation to be considered in 2005 remain unknown at this time, many observer
anticipate that a bill basically following the substance of the energy bill that was nearly passed in the 108tl
Congress, with some modifications, will serve as the vehicle.

        Federal law imposes numerous responsibilities and requirements on the Company. PURPA require!
electric utilities, such as the Company, to purchase power generated in a manufacturing process from a QF
Generally stated, electric utilities must purchase electric energy and production capacity made available by QFs
at a rate reflecting the cost that the purchasing utility can avoid as a result of obtaining energy and production
capacity from these sources rather than generating an equivalent amount of energy itself or purchasing the
energy or capacity from other suppliers. The Company has entered into agreements with four such cogenerators.
 Electric utilities also must furnish electric energy on a non-discriminatory basis at a rate that is just, reasonable
and in the public interest and must provide certain types of service which may be requested by QFs to
supplement or back up those facilities’ own generation.

         Although efforts to increase competition at the state level have been stalled, there have been several
initiatives implemented at the federal level to increase competition in the wholesale markets for electricity. The
National Energy Policy Act of 1992 (“Energy Act”), among other things, promoted the development of
independent power producers (“IPP”). The Energy Act was followed by FERC Order 888 and Order 889, which
facilitated third-party utilization of the transmission grid for sales of wholesale power. The Energy Act, Orders
888 and 889, and other FERC policies and initiatives have significantly increased competition in the wholesale
power market. Utilities, including the Company, have increased their own in-house wholesale marketing efforts
and the number of entities with whom they historically traded. While power marketers became an increasingly
important presence in the industry, their importance has declined following the bankruptcy of Enron and the
financial troubles of other significant power marketers. These entities typically arbitrage wholesale price
differentials by buying power produced by others in one market and selling it in another. IPPs also are
becoming a more significant sector of the electric utility industry. In both Oklahoma and Arkansas, significant
additions of new power plants have been announced and, in some cases completed, almost all of it from IPPs.

         Notwithstanding these developments in the wholesale power market, the FERC recognized that
impediments remained to the achievement of fully competitive wholesale markets including: (i) engineering and
economic inefficiencies inherent in the current operation and expansion of the transmission grid; and (ii)
continuing opportunities for transmission owners (primarily electric utilities) to discriminate in the operation of
their transmission facilities in favor of their own or affiliated power marketing activities. In the past, the FERC
only encouraged utilities to join and place their transmission systems under the operational control of
independent system operators. On December 20, 199’9, the FERC issued Order 2000, its final rule on
RTOs. Order 2000 is intended to have the effect OP turning the nation’s transmission facilities into
independently operated “common carriers” that offer comparable service to all would-be-users. Although
adopting a voluntary approach towards RTO formation, the FERC stressed that Order 2000 does not preclude it
from requiring RTO participation. Order 2000 set out a timetable for every jurisdictional utility (including the
Company) to either join in an RTO filing, or, alternatively, to submit a filing describing its efforts to join an
RTO, the reasons for not participating in an RTO proposal and any obstacles to participation, and its plans for
further work toward participation. h October 2004, the FERC gave its approval to the creation of the SPP
RTO, of which the Company is a member.

(FERC FORM NO. 1 (ED. 12-88)                          Page 123.4.2                                                    I
 Name of Respondent                                   This Report is:            Date of Report Year/Period of Report
                                                      (1) An Original             (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                       -
                                                      (2) A Respbmission              I1                20041Q4




        In July 2002, the FERC issued a Notice of Proposed Rulemalung on Standard Market Design
Rulemalung for regulated utilities. If implemented as proposed, the rulemaking will substantially change how
wholesale electric markets operate throughout the United States. The proposed rulemaking expands the FERC’s
intent to unbundle transmission operations from integrated utilities and ensure robust competition in wholesale
markets. The proposed rule contemplates that all wholesale and retail customers will take transmission service
under a single network transmission service tariff. The rule also contemplates the implementation of a bid-based
system for buying and selling energy in wholesale markets. RTOs or Independent Transmission Providers will
administer the market. RTOs will also be responsible for regional plans that identify opportunities to construct
new transmission, generation or demand side programs to reduce transmission constraints and meet regional
energy requirements. Finally, the rule envisions the development of Regional Market Monitors responsible for
ensuring the individual participants do not exercise unlawful market power. On April 28, 2003, the FERC
issued a White Paper, “Wholesale Market Platform”, in which the FERC indicated that it will change the
proposed rule as reflected in the White Paper and following additional regional technical conferences. The
FERC committed in the White Paper to work with interested parties including state commissions to find
solutions that will recognize regional differences within regions subject to the FERC’s jurisdiction. Thus far,
the FERC has held conferences in Boston, Omaha, Wilimington, Tallahassee, Phoenix, New York, Dallas,
Atlanta and San Francisco.

        On April 14, 2004, the FERC initiated Docket No. RM04-7 to review its generation market power
screening processes. The existing four-prong test was developed over 15 years in what the FERC characterizes
as a different marketplace than today. The FERC plans to review the continued appropriateness of the
four-prong test and consider amendments and additions to the required tests. On May 11, 2004, the FERC
opened Docket No. PLO4-6 establishing an investigation of bast practices for competitive solicitation methods
for public utilities, including public utility sales to affiliates;. The purpose of this investigation is to ensure that
transactions filed with the FERC are the result of a fair anid open procedure. On October 6, 2004, the FERC
established Docket No. RM04-14 to set guidelines for events that would trigger a reporting obligation on the
part of any public utility with the authority to engage in sales for resale of electric energy in interstate commerce
at market-based rates and possibly modify the market-based rate authority for public utilities that had a
qualifying change in status that would affect their relevant market power. On February 10, 2005, the FERC
issued Order 652 related to Docket RMO4-14. The Company is currently evaluating Order 652 to determine the
impact on the Company. Although technical conferences have; been held for the first two of these dockets, to
date no definitive rules or guidance have been issued by the FERC. Dockets RM04-7 and PLO4-6 remain open.
Any of these dockets may have a material effect upon the Company’s participation in wholesale energy markets.

        In October 2003, the FERC issued new rules golverning corporate “money pools,” which include
jurisdictional public utility or pipeline subsidiaries of nonregulated parent companies. The rules require
documentation of transactions within such money pools and notification to the FERC if the common equity ratio
of the utility falls below 30 percent.

       The FERC requires all utilities authorized to sell power at market-based rates to file updated market
power analyses every three years. In December 2003, the Company filed its updated market power analysis with
the FERC.

IFERC FORM NO. 1 (ED. 12-88)                          Page 123.43;                                                      I
-
Name of Respondent                                     This Report is:              Date of Report Yeadperiod of Report
                                                       (1) X An Original             (Mo, Da, Yr)
    Oklahoma Gas and Electric Company                  (2) - A Flesubmission             I t              2004lQ4
                                        NOTES TO FINANCIAL STATEMENTS (Continued)


State Legislative Initiatives

Oklahoma

       As previously reported, the Oklahoma legislature originally adopted the Electric Restructuring Act of
1997 (the “1997 Act”) to provide retail customers in Oklahoma with a choice of their electric supplier. The
scheduled start date for customer choice has been indefinitely postponed. In the 2003 legislative session,
attempts to repeal the 1997 Act were initiated, but the se:ssion ended without repeal of the 1997 Act. It is
unknown at this time whether the 1997 Act will be repealed.

       In the 2004 legislative session, legislation was enacted requiring a study to determine the feasibility of
providing investor-owned utilities an incentive to enter into purchase power agreements in Oklahoma by
allowing the utilities to earn a return on purchased power. ‘The study committee held its first meeting in August
and continued holding two meetings a month through November. At the conclusion of the meetings, the study
committee determined that the final report would make no recommendations to the legislature in January 2005.

Arkansas

        In April 1999, Arkansas passed the Restructuring Law calling for restructuring of the electric utility
industry at the retail level. The Restructuring Law, which had initially targeted customer choice of electricity
providers by January 1,2002, was repealed in March 2003 before it was implemented. As part of the repeal
legislation, electric public utilities were permitted to recover transition costs. The Company incurred
approximately $2.4 million in transition costs necessary to carry out its responsibilities associated with efforts to
implement retail open access. On January 20,2004, the APSC issued an order which authorized the Company to
recover approximately $1.9 million in transition costs over ;an 18-month period beginning February 2004.

        In the 2003 legislative session, legislation was enacted requiring a study relating to the restructuring of
the electric utility industry at the industrial level to provide customer choice of electricity providers for large
customers. A roundtable discussion regarding the study was held on July 22,2004 and comments were filed on
August 20, 2004. The APSC released the report on September 30, 2004 and the Insurance and Commerce
Committee heard the issue on October 20, 2004. The commissioners concluded that circumstances in the
current electric generation market have not changed sufficiently since adoption of Act 204 (The Electric Utility
Regulatory Reform Act of 2003) to be able to structure a large user access program that would produce
economic benefits for large users while also ensuring no cost-shifting or net cost increases to remaining
customers. The commissioners also concluded that there: are no clear economic benefits, and more likely
economic harm, that would result from moving forward with the large user access program concept at this time.
The APSC closed the “Feasibility of a Large User Access Program” for electric service choice. The Arkansas
legislature has not proposed legislation to date.

        As discussed above, legislation was enacted in Oiklahoma and Arkansas that was to restructure the
electric utility industry in those states. The Arkansas legislation was repealed and implementation of the
Oklahoma restructuring legislation has been delayed and seems unlikely to proceed during the near future. Yet,
if and when implemented, this legislation could deregulate the Company’s electric generation assets and cause
the Company to discontinue the use of SFAS No. 71 with respect to its related regulatory balances. This may
LFERC FORM NO. 1 (ED. 12-88)                           Page 123.44                                                        I
-Name of Respondent                                  This Report is:                                     f
                                                                              Date of Report Yeadperiod o Report
                                                     (1) 3 An Original         (Mo, Yr)
                                                                                    Da,
  Oklahoma Gas and Electric Company                  (2) - A Resubmission             I I           2M)4/Q4




result in either full recovery of generation-related regulatory assets (net of related regulatory liabilities) or a
non-cash, pre-tax write-off as an extraordinary charge, depending on the transition mechanisms developed by
the legislature for the recovery of all or a portion of these net regulatory assets.

        The previously enacted Oklahoma and Arkansas legislation would not affect the Company’s electric
transmission and distribution assets and the Company believes that the continued use of SFAS No. 71 with
respect to the related regulatory balances is appropriate. However, if utility regulators in Oklahoma and
Arkansas were to adopt regulatory methodologies in the future that are not based on the cost-of-service, the
continued use of SFAS No. 71 with respect to the regulatory balances related to the electric transmission and
distribution assets may no longer be appropriate. Based on a current evaluation of the various factors and
conditions that are expected to impact future cost recovery, management believes that its regulatory assets,
including those related to generation, are probable of future recovery.

Summary

       The Energy Act, the actions of the FERC,the restructuring legislation in Oklahoma and other factors are
intended to increase competition in the electric industry. The Company has taken steps in the past and intends
to take appropriate steps in the future to remain a competitive supplier of electricity. While the Company is
supportive of competition, it believes that all electric suppliers must be required to compete on a fair and
equitable basis and the Company is advocating this position vigorously.

14.      Fair Value of Financial Instruments

       The following information is provided regarding the estimated fair value of the Company’s financial
instruments, including derivative contracts related to the Company’s price risk management activities, as of
December 3 1:

                                                       2004                        2003
                                              Carrying        Fair      Carrying       Fair
 (In millions)                                Amount          Value     Amount        Value
 Price Risk Management Assets
     Interest Rate Swap                          $    39
                                                       .      $     .
                                                                   39    $   4.0      $     4.0

 Long-Tern Debt
    Senior Notes                                 $711.8       $764.2     $571.8       $611.8
      Industrial Authority Bonds                    3.
                                                   154           3.
                                                                154        135.4       135.4

       The carrying value of the financial instruments on the Balance Sheets not otherwise discussed above
approximates fair value except for lang-term debt which is valued at the carrying amount. The valuation of the
Company’s interest rate swap was determined primarily based on quoted market prices. The fair value of the
Company’s long-term debt is based an quoted market prices.




IFERC FORM NO. 1 (ED. 12-88)                         Page 123.45
Name of Respondent                                         This Re ort Is:
                                                           (1) d A n Original                                                      End of      2004/Q4
Oklahoma Gas and Electric Company                          (2)  0  A Resubmission




r
           ~   ~~~




Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (f) common function.


                                                                                                   Total Company for the
                                          Classification                                                                                    Electric
Line                                                                                             Current Year/Quarter Ended
No.




   3 Plant in Service (Classified)                                                                             4,525,462,477                    4,525,462,477
   4 Property Under Capital Leases
   5 Plant Purchasedor Sold
   6 Completed Construction not Classified
   7 Experimental Plant Unclassified
   8 Total (3thru 7)                                                                                           4,525,462,477                    4,525,462,477
   9 Leased to Others




  23 Leased to Others
  24 Depreciation
       I
  25 Amortization and Depletion
       I
  26 Total Leased to Others (24 & 25)                                                        I                                 I
  28 Depreciation
  29 Amortization
  30 Total Held for Future Use (28 & 29)
  31 Abandonment of Leases (Natural Gas)
  32 Amort of Plant Acquisition Adj
  33 Total Accum Prov (equals 14) (22,26,30,31,32)                                                             2,207,927,755                    2,207,927,755




FERC FORM NO. 1 (ED. 12-89)                                           Page 200
                                                                            -
Name of Respondent                              This Re     rt Is:             Date of Report     Yeartperiod of Report
Oklahoma Gas and Electric Company               (1)
                                               (2)
                                                      8~”Original
                                                      A Resubmission
                                                                               (Mo, Da, Yr)
                                                                                I1
                                                                                                  End of      2004lQ4

                                      SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
                                          FOR DEPRECIATION. AMORTI.ZATION AND DEPLETION
         Gas                  Other (Specify)             Other (Specify)       Other (Specify)      Common
                                                                                                                      1   Line
                                                                                                                          NO.




                                                                                                                      I
                                                                                                                      I      !

                                                                                                                      I     1‘


                                                                                                                      I     1:
                                                                                                                      I     14




                                                                                                                      I     1;
                                                                                                                      rii

                                                                                                                      1     2‘
                                                                                                                      I     :
                                                                                                                            2



                                                                                                                      I     2!




                                                                                                                      I     :
                                                                                                                            3




FERC FORM NO. 1 (ED.12-89)                                   Page 201
    Name of Respondent                                     This Re rt Is:                                 Date of Report                  YearJPeriod of Report
                                                           (1) 8 A n Original                             (Mo, Da, Yr)                    End of      2004JQ4
    Oklahoma Gas and Electric Company                      (2) nA Resubmission
                                                           ..                                              I /
t            ~
                                                                    I                             I
                                                ELECTRIC PLANT IN SERVICE (Aocount 101.102.103 and 106)
                                                                                          ~           ~      ~~~
                                                                                                                                 I
                                                                                                                                     ~~         ~   -
                                                                                                                                                                    t
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d). as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
                                                                                                                                                                    I
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
Line
 kl,.
                                            Account
                                                                                              I              Balance
                                                                                                         Beginning of Year                I  Additions



      2 (301) Organization                                                                                                    8wJO
      3 (302) Franchises and Consents                                                                                      2,168,376                           2,993
      4 (303) Miscellaneous Intangible Plant                                                                               3,040,953                       1,008,985
I     5 ITOTAL lntanaible Plant (Enter Total of lines 2.3. and 4)                             I                            5.290.2291                      1.01 1.9781



      8 I(310) Land and Land Rights                                                           I                         10,626,1671
      9 I(311) Structures and Improvements                                                                             219,493,7341                          618.024
     10 (312) Boiler Plant Equipment                                                                                   799,878,061                        24,791,788
     11 (313) Engines and Engine-Driven Generators
     12 (314) Turbogenerator Units                                                                                     320,197,821                         4,905,524
     13 (315) Accessory Electric Equipment                                                                             126,670,219                         1,415,247
     14 (316) Misc. Power Plant Equipment                                                                                  33,969,790                        772,700
     15 (317) Asset Retirement Costs for Steam Production
I    16 ITOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
         TOTAL                                                                                I                       . . .
                                                                                                                     1.510.835.7921
                                                                                                                     1,510,835,7921                       __. .-
                                                                                                                                                             - - - --
                                                                                                                                                          32,503,283
                                                                                                                                                          32.56.2831
     17 B. Nuclear Production Plant
     18 (320) Land and Land Rights                                                                                                        I
     19 (321) Structures and Improvements
     20 (322) Reactor Plant Equipment
     21 (323) Turbogenerator Units
     22 (324) Accessory Electric Equipment
     23 (325) Misc. Power Plant Equipment
     24 (326) Asset Retirement Costs for Nuclear Production
     25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)


     27 (330) Land and Land Rights
     28 (331) Structures and Improvements
     29 (332) Reservoirs, Dams, and Waterways
     30 (333) Water Wheels, Turbines, and Generators
     31 (334) Accessory Electric Equipment
     32 (335) Misc. Power PLant Equipment
     33 (336) Roads, Railroads, and Bridges
     34 (337) Asset Retirement Costs for Hydraulic Production
     35 TOTAL Hvdraulic Production Plant (Enter Total of lines 27 thru 34)


     37 (340) Land and Land Rights
     38 (341) Structures and Improvements                                                                                   3,310.273
     39 (342) Fuel Holders, Products, and Accessories                                                                      12.427.992
     40 (343) Prime Movers                                                                                                  7,805,747                     14,613,519
     41 (344) Generators                                                              -                                    64,633,160                        464,517
     42 (345) Accessory Electric Equipment                                            -                                    13,609,452                        390,528
     43 (346) Misc. Power Plant Equipment                                                                                   1,742,057                        226,573
Name of Respondent                                        This Re rt Is:                              Date of Report              YearIPeriod of Report
                                                          (1) S A n Original                          (Mo, Da, Yr)                End of      2004lQ4
Oklahoma Gas and Electric Company                         (2) n Resubmission
                                                                 A                                     11

distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent’s plant actually in service at end of year.
7. Show in column (9 reclassifications or transfers within utility plant accounts. lncllude also in column (9 the additions of reductionsof primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (9 only the offset to the debits or credits distributed in column (f) to primary
account classifications.


                                                                                  102, state the prope




                           47,894                                                      -        141,535,927                    163,907,299                 40
                          109,654                                                                                                64,988,023                41
                                                                                       -          8,180,597                      22,180,577                42
                                                                                       -          4,457,507                       6,426,137                43

                                                                                       -
    Name of Respondent                                     This Re rt Is:                          Date of Report                YearlPeriod of Report
                                                           (1) 6 A n Original                      (Mo, Da, Yr)                  End of      2004lQ4
    Oklahoma Gas and Electric Company                      (2) n A Resubmission                     I 1

Line                                       Account                                                                                           itions
 No.
                                         (a)
  44 (347) Asset Retirement Costs for Other Production
  45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)                                                  103,528,661
1461TOTALPYod. Plant fEnter Total of lines 16. 25. 35.. and 45)
   - . - .. - .- - - ,- - - -                  . .                                      I                     1.614.364.4731                           49.283.3951
  47 3. TRANSMISSION PLANT
  48 (350) Land and Land RiDhts
     49 (352) Structures and Improvements                                                                             905,719                               2,664
     50 (353) Station Equipment                                                                                 159,934,318                             3,224,538
     51 (354) Towers and Fixtures                                                                                47,699,147                             1,253,048
     52 (355) Poles and Fixtures                                                                                159,507,675                             6,006,208
I                                                                                       1 -
                                                                                                                                                  ~~




     53 I(356) Overhead Conductors and Devices                                                                  143,158,4591                            3,053,9551
     54 (357) Underground Conduit
     55 (358) Underground Conductors and Devices                                                                      110,494
     56 (359) Roads and Trails
        I
     57 (359.1) Asset Retirement Costs for Transmission Plant                           I                                        I
     58 I TOTAL Transmission Plant (Enter Total of lines 48 thru 57)                                            536,873,9881                           14,499,967
     59 4. DISTRIBUTION PLANT
     60 (360) Land and Land Rights                                                                                  5.81 6.6691                          1,152.013
1                                                                                       I
                                                                                              ~~




     61 I(361)Structures and Improvements                                                                            1,438,195)               ~            55,7GI
     62 (362) Station Equipment                                                                                 278,748,896                             19,483,328
     63 (363) Storage Battery Equipment
     64 (364) Poles, Towers, and Fixtures                                                                       328,550,351                             13,582,602
     65 (365) Overhead Conductors and Devices                                                                   264,016,590                             16,171,710
     66 (366) Underground Conduit                                                                                81,339,270                              1,096,312
     67 (367) Underground Conductors and Devices                                                                313,768,126                             30,153,888
     68 I(368) Line Transformers                                                        I                       229,879,1371                            11,731,171
     69 I(369) Services                                                                                         146,512,391 I                            6.986.751
I    70 I(370) Meters                                                                   I                        71,181,0211
I    71 If3711 Installations on Customer Premises                                       I                                        I                                   I
     72 (372) Leased Property on Customer Premises
     73 (373) Street Lighting and Signal Systems                                                                111,505,711                              8,768,899
     74 (374) Asset Retirement Costs for DistributionPlant
     75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)                                             1,834.756.357                           113,495,133

     77 (389) Land and Land Rights                                                                                   3,619,312
     78 (390) Structures and Improvements                                                                           89,856,633                            659,847
     79 (391) Office Furniture and Equipment                                                                        34,852,453                            862,972
     80 (392) Transportation Equipment                                                                              47,851,939                           5.552.647




    FERC FORM NO. 1 (REV. 12-03)                                       Page       206
FERC FORM NO. 1 (REV. 1203)   Page   207
Name of Respondent
Oklahoma Gas and Electric Company
                                                         I Ty
                                                         i
                                                             (2)
                                                                 l 3 ~ ~n Is:
                                                                 n  i
                                                                           -I
                                                                         f Original
                                                                      A Resubmission
                                                                                                i
                                                                                                     Date of Report
                                                                                                     (Mo, Yr)
                                                                                                         Da,
                                                                                                                            i
                                                                                                                                 YearlPeriod of Report
                                                                                                                                 End of         2004lQ4

                                                      ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of propetty held
for future use.
2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other reauired information, the date that utility use of such . . . was discontinued, and the date the original cost was transferred to Account 105.
                                                              property                                     -
                           Description and Location                           Date ri ina y ncu                                             Balance at
 No.
Line                              Of Pro erty
                                       raf                                              Ib)
                                                                                   i?Ais :cdou!!?edJ                                       End of Year


   2 37 Substation Sites                                                                      Various                     Various                    670,422
   3 2 Substation Easements                                                                   Various                     Various                       1,569
    4 3 Transmission Line Easements                                                           Various                     Various                    256,977




   9
  10
   11
   12
   13
   14
   15
   16
   17
   18
  19
  20



  23
  24
  25
  26
  27
  28




  40
  41
  42
  43
  44




FERC FORM NO. 1 (ED. 12-96)                                             Page 214
BLANK PAGE
Name of Respondent                                         This Re rt Is:            Date of Report     YearIPeriod of Report
                                                           (1) 8 A n Original        (Mo. Da, Yr)
Oklahoma Gas and Electric Company                          (2) n  A Resubmission      I1
                                                                                                        End of     2004/Q4




No.                                                                                                   Electric (Account 107)-
                                        (a)                                                                     (4
   1 Discovery, Construct New Substation                                                                                  3,887,437
  2 Oak Park, Construct New Substation                                                                                   3.362.759
  3 Glendale, Construct New Substation                                                                                   3,057,479
  4 Wild Mary, Construct New Substation                                                                                  1,812,960
  5 Lone Oak Substation, Install 3rd 50 MVA Transformer with 3 Feeder Exits                                              1.224.888
       Battlefield, Construct New Substation                                                                             1,167,435
       NE Enid Substation, Install Transformer                                                                             528,342
       Reconfigure Facilities for New Northwest Service Center                                                             430,392
       Underground Feeder Protection                                                                                       425,134
       Van Buren Area, Buy New Substation Site                                                                             410,537
       Razorback, Construct New Substation                                                                                 353,900
       Distribution Voltage Conversion-Coyle. Ok                                                                           349,421
       Midwest City Downtown Service, Town Center Plaza                                                                    348,435
       CHQ Generator & Enclosure Project                                                                                   328,095
       Distribution Voltage Conversion-Woodward, Ok                                                                        445,581
       St. Anthony Hospital Distribution                                                                                   292,829
       Pearson, Rebuild Overhead Distribution                                                                              266,699
       Gerber Road, Construct New Substation                                                                               265,005
       SE 15th Substation, Install 138 Line Terminal                                                                       227,557
       NE Enid Substation, Install RelayIControl                                                                           224,787
       Ft. Smith- Southfield Heights, New Subdivision                                                                      222,855
       Cavanal Mtn Substation, New Breaker                                                                                  186,473
       Update Facilities for Transmission Control Center                                                                    183,103
       Sara Road Replace 2000 Amp Switches                                                                                  180,684
       Yukon Substation, Install Capacitors                                                                                 167,937
       Potawatomi Grand Casino, Construct Overhead Line                                                                     159,693
       38th Street Substation, Install On-Line Monitoring System                                                            157,152
       Graphical Work Order Scheduling System                                                                               147,731
       Ft. Smith-Alma Rural Distribution, Upgrade 6 Miles of Line                                                           146314
       Cleo Comer Substation, Install 138 kV Breaker                                                                        136,546
       New Service for Sterling Canyon Addition                                                                             119,499
       Install New 161 kV Transmission Line                                                                                 117,893
       Westoaks, Construct New Substation                                                                                  113,734
                                                                                   -~~
       Spiro Coal Substation, Change Transformers, Reclosers, & Switches                                                    113,690
       Glen Village 2, New Subdivision                                                                                     110,518
       Nichols Hills Reliability Project                                                                                    110,353
       Villagio at Deer Creek I,New Subdivision                                                                            109,626
       South 4th Street Substation, Replace Relays on NE Enid Line                                                         108,607
       Purchase Three Vanguard Model CT-7500 Channel Breaker Timer Analyizers                                              107,905
       Sahoma Lake, Construct New Substation                                                                               102,519
       MK5 Turbine Efficiency Improvement Project                                                                        7,668,300
       MK6 Turbine Efficiency Improvement Project                                                                        6.379.093

  43    TOTAL                                                                                                           94,407,942

FERC FORM NO. 1 (ED. 12-87)                                          Page 216
                                                                                  -
    Name of Respondent                                    This Re ort Is:               Date of Report                    YearlPeriod of R e v
    Oklahoma Gas and Electric Company                     (1) d A n Original            (Mo, Da, Yr)                      End of     2004lQ4
                                                          (2) nA Resubmission
                                                          . ,                       I
                                                                                         I1                           I
I
                                                                 I
                                                                                   -
                                                 CONSTRUCTION WORK IN PROGRESS - ELECTRIC (Account 107)                                                  t

                                                                                                                                                    1
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development,and Demonstrating(see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100.000, whichever is less) may be grouped.

                                                                                                                      Construction work in progress -


      1 SO2 Controls Upgrade for Boiler
                                         Description of Project
                                                  (al                                                             I     Electric (Account 107)
                                                                                                                                  Ib)
                                                                                                                                            3,530,288
      2 MK4 Turbine Upgrade                                                                                                                  3,501,556
      3 MK6 Superheat and Reheat Surface Addition                                                                                            3,493,911
      4 S02- Generator Stator Rewind                                                                                                         2,655,580
      5 MK4 Superheat & Reheat Surface Addition                                                                                              2,390,246
      6 MK6 FeedwaterHeaters                                                                                                                  973,734
      7 MK6 Install New Toggle Section                                                                                                        857,322
      8 MK6 Fly AsNBottom AsNPyrite Controls                                                                                                   688,337
      g HL7 Replace Bailey Boiler Controls                                                                                                     590,225
          I
     10 Install Genbase & Genportal
                                                                                                                  I                            481,693
     11 I MK6 Condenser Endwall Modification                                                                                                   440,346
     12 MK6 Boiler Elevator Upgrade                                                                                                            426,770
     13 MK4 Reverse Osmosis System                                                                                                             372,193
     14 SM2 Boiler Feed Pump Turbine Controls Upgrade                                                                                          347,610




1
                                                                                                            ~~~                         ~




              MK4 New Rotary Dumper Barrel                                                                                                     341,694
              MK6 Coal Handling Fire Protection Upgrade                                                                                        328,596
              MK4 Dumper Barrel T-Section Upgrade                                                                                              316,487
              SO1 Dumper Deluge & Reclaim Pump                                                                                                 313,723
              SM3 Boiler Feed Pump Turbine Controls                                                                                            311,482
     20 SO Crusher House Fire Protection                                                                                                       283,920
              HL6 Boiler Safety Valves                                                                                                         261,947
     22 SO1 Reactivator Drive System Upgrade                                                                                                  227.674
     23 MK6 Crusher House Fire Protection                                                                                                     210,212
     24 SM1 Main Turbine Supervisory Instrumentation                                                                                          207,592
     25 SM2 Boiler Feed Pump Turbine Supervisory Instrumentation                                                                               189,033
     26 SM1 Nash Pump Motor                                                                                                                    184,041
     27 MK6 Cooling Tower Auxiliary Cooling System                                                                                             159,402
     28 MK3 Burner Management System Controls Upgrade                                                                                          148,217
     29 MK6 Upgrade Cooling Tower Electric Panels, Conduit, etc                                                                                139,720
     30 MK6 Oscullating Retracts                                                                                                               131.988
     31 MK6 Smart Sootblowing System                                                                                                           130,148
     32 MK6 Hydrobin Upgradelcoating                                                                                                           113,400
     33 MK6 Soft Starters for Cooling Tower                                                                                                    113,386
     34 MK4 Dumper Concrete Structure Coating                                                                                                  105,043
     35 Ft Smith, Modify Substation & Add 400 MVA Transformer                                                                                9,299,187
     36 Draper Lake Substation, Add 400 MVA Transformer                                                                                      1,749,403
     37 Imo Substation, Install Bus Tie Transformer and Terminate Lines                                                                      2,310,545
     38 Install 5.5 Miles of 161kV Transmission Line                                                                                         1,334,106
     39 McClain Substation, Replace 2000 Amp Equipment with 3000 Amp                                                                          861,346
     40 Muskogee Substation, Replace Bus Tie Transformer                                                                                      857,060
     41 Purchase ROW for New 161 kV Transmission Line                                                                                         638,394
     42 Penn-Boyd, Replace Underclassed Poles                                                                                                 665,550

     43        TOTAL                                                                                                                        94,407,942
                                                         I
                                                                                                                                                                      II
    Name of Respondent                                             $
                                                                   k
                                                              ?)is R        Is:                      Date of Report            YearIPeriod of Report
                                                                         An Original                 (Mo, Da, Yr)
    Oklahoma Gas and Electric Company                                                                                          End of     2004/Q4
                                                              (2)       nA Resubmission




r
                                                                                                 I                         I
I                                                        1          .    u
                                             CONSTRUCTION WORK IN PROGRESS                - - ELECTRIC (Account 107)                                        ~




1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.

    Line                             Description of Project                                                                Construction work in progress         -
                                                                                                                             Electric (Account 107)
                                             [a)
                                             > ,                                                                                       .,
                                                                                                                                       lb)
       1 Draper Lake, Install 345-138 kV Transformer                                                                                               500,522
       2 Muskogee Substation, Transformer for 161 kV Switch Yard                                                                                    471,412
       3 138 kV Transmission Line- Replace Destroyed Poles                                                                                          448,168
       4 Replace Temporary StructureIPermanent 345 kV Transmission Line                                                                             430,517
       5 Relocate 138 kV Transmission Line                                                                                                          334,892
_______                                                                                                                           ~~           ~    _   _   _    _    _

       6 345 kV Transmission Line, Pole Replacement                                                                                                 332,143
       7 Razorback-ShortMountain, Install 14 Miles of Transmission Line                                                                             330,836
       8 138 KV Transmission Line, Replace Underclassed Poles                                                                                       293,168
       g 138 kV Transmission Line Loop into Wild Mary Substation                                                                                    287,789
      10 138 KV Transmission Line Structure Replacement                                                                                             284,218
      11 Cimarron, Upnrade Power Circuit Breakers                                                                                                   283.593




                                                                                                                                                    236,813


                                                                                                                                                    193.668
           I                                                                                                           I
           I
      17 Seminole Substation, Replace Power Circuit Breaker                                                            I                            188,653
      18 Kinzie Substation, Install Breaker and Meter Equipment                                                                                     168,264
     19 Draper Lake Substation, Install Transformer & Breakers, SP&C                                                                                156,290
     20 Horseshoe Lake, Replace Poles for SE 15th 138kV Transmission Line Restoration                                                               149,486
      21 Imo- Cleo Section, Install 138/69kV Bus Tie                                                                                                139,119
      22 Install 5 Miles of 66 kV Line                                                                                                              138,344
      23 Draper Lake Substation, Upgrade Grounding                                                                                                  131,212
      24 Richards-PiedmontTransmission Line, Obtain ROW                                                                                             130,167
                                                                                                                       I

     25 I Fansteel Tap-Muskogee Transmission Line Relocation                                                           I                            119,756
     26 Pecan Creek Substation, Install On-Line Monitoring System                                                                                   115,897
     27 Muskogee Substation, Install On-Line Monitoring System                                                                                      105,040
     28
     29
     30 Approximately 70 projects covering Additions & Betterments to General Plant Items                                                          1,218,424
     31
     32 Approximately 124 projects covering Additions & Betterments to Generating !Stations                                                     2,782,413
     33
     34 One Franchise covering Additions & Bettermentsto Intangible Plant                                                                                       790
     35
                                                                                                                       I
           I
     36 I Approximately 220 projects covering Transmission Line and Substation Additions 8,                                                                           I
     37 Betterments and Miscellaneous Rebuilds                                                                                                  1,488,779
     38
     39 Approximately 498 projects covering Distribution Lines and Substation
     40 Additions & Betterments, Miscellaneous Rebuilds, Meters and Services                                                                    3,273,641
     41



     43        TOTAL                                                                                                                           94,407,942

FERC FORM NO. 1 (ED. 1287)                                                   Page 216.2
 Name of Respondent                                            This Re ort Is:                        Date of Report               Yeartperiod of Report
                                                               (1) d A n Original                     (Mo, Yr)
                                                                                                           Da,                     End of      2004lQ4
 Oklahoma Gas and Electric Company                             (2) n   A Resubmission                  / /
                                                           I       I   I                       I                              I
                               ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
 1. Explain in a footnote any important adjustments during year.
 2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
 slectric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable properly.
 3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
 such plant is removed from service. Ifthe respondent has a significant amount of plant retired at year end which has not been recorded
 and/or classified to the various reserve functional classifications, make preliiminary closing entries to tentatively functionalize the book
 zost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
 Aassifications.
 4. Show separately interest credits under a sinking fund or similar method i I depreciation accounting.


                                                      Section A. Balances and Chanaes Durina Year
 Line
 No.
                           item
                            [a)
                                                                (CEFA)
                                                                  (b)
                                                                                   tlec ric yiant In
                                                                                        ervice
                                                                                          (C)
                                                                                                                    tiectric riantUse
                                                                                                                       for Future Hela
                                                                                                                             (d)
                                                                                                                                         1   Let3%BT&s
                                                                                                                                                  (e)

    1 Balance Beainnina of Year                                        2.1 19,104,658        2.1 19,104,658




    5 (413) Exp. of Elec. Plt. Leas. to Others
    6 Transportation Expenses-Clearing
   7 Other Clearing Accounts
   8 Other Accounts (Specify, details in footnote):
   4Transportation Expense Capitalized                                         612,0491               612,044


I--- I
   !
  10 TOTAL Deprec. Prov for Year (Enter Total of
     lines 3 thru 9)
                                                                           120,839,129         120,839,12




  12 Book Cost of Plant Retired                                             35,069,078             35,069,078
  13 Cost of Removal                                                        18,219,739             18,219,739
  14 Salvage (Credit)                                                       13,304,196             13,304,196




  171Trans.(net) From Non-Utility or Parent            I                       -94.800 I              -94,8001                           I
  181Book Cost or Asset Retirement Costs Retired       I                                 I                      I                        I
  19 Balance End of Year (Enter Totals of lines 1,                     2,204,070,135         2,204,070,135
     10, 15, 16, and 18)
                                           Section B. Balances at End of Year Accordina to Functional Classification
  20 Steam Production                                                  1,101,376,255         1,101,376,255
  21 Nuclear Production

  221 Hydraulic Production-Conventional                I                                 I                      I                        I
  23 Hydraulic Production-PumpedStorage
  24 Other Production                                                       57,404,945             57,404,945
  25 Transmission                                                          247,240,840        247,240,840
  26 Distribution                                                          717,201,063        717,201,063
  27 General                                                                80.847,Q32             80.847.032

  28 TOTAL (Enter Total of lines 20 thru 27)                           2,204,070,135         2,204,070,135




FERC FORM NO. 1 (REV. 12-03)                                                Page 219
BLANK PAGE
Name of Respondent                                         This Re ort Is:                Date of Report            Yeartperiod of Report
                                                           (1) d A n Original             (Mo, Da, Yr)
Oklahoma Gas and Electric Company                          (2) n Resubmission
                                                                   A                       l I                      End of        2004Q4




Line                                    Description of Investment                    Date Acquired       Date of        Amount of Investmentat
                                                                                                                          Beginning of Year
No.                                            (a)                                        (b)            Ma&'*/                 (4
     1 The Arklahoma Corporation
     2 24 Shares of Common Stock                                                        12/03/47                                        17,000
     3
     4 4.8% of Equity Earnings                                                                                                              888

     6 Subtotal                                                                                                                         17,888
     7I
     81
                                                                                 I

                                                                                 I
                                                                                                     I
                                                                                                     I
                                                                                                                    I

                                                                                                                    I                             I
         I
    11
     0
                                                                                 I
                                                                                 I
                                                                                                     I
                                                                                                     I
                                                                                                                    I
                                                                                                                    I                             I
    11
    12
    13
    14
                                                                                                                             __

    15
    16
-
    17
    18
    19
    20




    36
    37
    38
    39
    40
    41


    42 ITotal Cost of Account 123.1 $                                   17,569                              TOTAL                       17,888
Oklahoma Gas and Electric Company
                                                  I t;",'"
                                                    (2)
                                                            An Original
                                                        R e g " I:
                                                             n
                                                                 s
                                                            A Resubmission   I
                                                                                 Date of Report
                                                                                 (Mo, Da, Yr)
                                                                                  J J
                                                                                                              2004lQ41
                                                                                                  YearIPeriod of Report
                                                                                                  End of




    tquity in Subsidiary              Revenues for Year                                                                   Line
      Eamin s of Year
            Ye)                              (8

                                                                                    17.000

                                                                  I                           I                      1       3
                           -320   I                                                     569   I                      1       4
                                                                                                                             5
                           -320                                                     17,569                                   6




3I                                                                                                                   1
                                                                                                                     I
                                                                                                                             9
                                                                                                                            10




                                                                  I                           1                       1     17
                                  I                                                                                   I     18
                                                                                                                             ~




                                                                                                                            19
                                                                                                                            20
                                                                                                                            21
                                                                                                                            22
                                                                                                                            23
                                                                                                                            24
                                                                                                                            25
                                                                                                                            26
                                                                                                                            27
                                                                                                                            28




FERC FORM NO. 1 (ED. 12-89)                                      Page 225
 Name of Respondent                                         This Re ort Is:                                 Date of Report                 YearIPeriod of Report
                                                            (1) d A n Original                              (Mo, Da, Yr)
  Oklahoma Gas and Electric Company                         (2) n A Resubmission                                                           End of         2004lQ4
                                                                                                             / I
                                                        I       Y                                  I                                   I
                                                             MATERIALS AND SUPPLIES
 1. For Account 154. report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
 estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
 2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
 various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
 clearing, if applicable.
 Line   I                   Account                            I          Balance                      I           Balance                 I       DeDartment or
 No.
                            (a)
    1 Fuel Stock (Account 1511
                                                               II
                                                               I
                                                                      Beginning of Year
                                                                              (b)
                                                                              .   I




                                                                                      59,803.781
                                                                                                       II
                                                                                                       I
                                                                                                                 End of Year
                                                                                                                       (C1
                                                                                                                       ,,
                                                                                                                             42.189.176
                                                                                                                                           I
                                                                                                                                           I

                                                                                                                                           I
                                                                                                                                                 Depahments which
                                                                                                                                                    Use Material
                                                                                                                                                        .,
                                                                                                                                                        (d1


    2 Fuel Stock Expenses Undistributed (Account 152)                                   209,772
    3 Residuals and Extracted Products (Account 153)
    4 Plant Materials and Operating Supplies (Account 154)
    5 Assigned to - Construction (Estimated)                                          27,913,986                             32,674,115 T&D
    6 Assigned to - Operations and Maintenance
    7 Production Plant (Estimated)                                                    10,287,957                             13,929,063 Power Production
                                                                                                                  ~~              ~~                 ~~




    8 Transmission Plant (Estimated)                                                   1,048,427                              1,219,987 T&D
    9 Distribution Plant (Estimated)                                                   2,128,625                              2,476,943        T&D
                    -
   10 Assigned to Other (provide details in footnote)
   11 TOTAL Account 154 (Enter Total of lines 5 thru 10)                              41,378,995                             50,300,108
   12 Merchandise (Account 155)
   13 Other Materials and Sumlies (Account 156)
   14 Nuclear Materials Held for Sale (Account 157) (Not
      applic to Gas Util)
   15 Stores ExDense Undistributed (Account 1631
   16   I
                                                               I
   19
   20 TOTAL Materials and Supplies (Per Balance Sheet)




'ERC FORM NO. 1 (ED. 12-96)                                            Page 227

								
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